Callon Petroleum Company
2006 Annual Report
To Shareholders
THE COMPANY
Callon Petroleum Company is an independent oil and gas company. Since 1950, Callon has
been engaged in the exploration, development and acquisition of crude oil and natural gas properties
in the Gulf Coast region. The majority of Callon’s properties and operations are concentrated in
Louisiana, Alabama and the offshore waters of the Gulf of Mexico.
Callon’s common stock is traded on the New York Stock Exchange under the symbol “CPE.”
HIGHLIGHTS
Financial
(In thousands, except per share amounts)
2006 2005
Revenues ..................................................................................................
Net income before preferred dividends ...................................................
Net income per common share ...............................................................
Cash flow provided by operating activities ..............................................
Total assets ...............................................................................................
Long-term debt .........................................................................................
Stockholders’ equity .................................................................................
$ 182,268 $ 141,290
26,776
1.28
74,010
533,776
188,813
228,048
40,560
1.90
135,484
625,527
225,521
281,363
Year Ended December 31
Operating
Production
Oil (MBbls) ...........................................................................................
Gas (MMcf) ...........................................................................................
Total production (MMcfe) ....................................................................
Average daily (MMcfe) ..........................................................................
1,634
10,977
20,780
56.9
1,837
7,768
18,787
51.5
To Our Shareholders:
I am pleased to report that during 2006 the Company’s average daily
production reached 56.9 million cubic feet of natural gas equivalent (MMcfe)
per day, representing an increase of 11% over 2005. As a result of this
production growth and a strong commodity price environment, Callon
achieved record revenues, net income and cash flow provided by operating
activities in 2006.
Oil and gas sales increased 29% to $182.3 million from $141.3 million
in 2005. Net income increased 51%, from $26.8 million in 2005 to $40.6
million in 2006. Cash flow provided by operating activities for the year 2006
increased 83% to $135.5 million.
Exploration Activity
During 2006 we drilled 17 wells, eight of which were successful. Those
eight wells added a total of 15.8 billion cubic feet of natural gas equivalent
(Bcfe) of proved reserves, and a total of 30.3 Bcfe if probable reserves are
included. Of the unsuccessful wells, three encountered pay but were deemed
non-commercial, and another, Bob North, was temporarily abandoned before
reaching its objective and will be re-drilled in 2007. The discoveries included:
High Island Blocks 165 / 130 - The High Island 165 #1 well reached
total depth of 17,029 feet in January 2006, and began producing in the third
quarter. The well is producing 42.5 million cubic feet of natural gas (MMcf)
and 200 barrels of oil (Bo) per day. We drilled an offset well on High Island
Block 130 which encountered significant additional pay below the initial
discovery sand. It was completed in March 2007 and began producing later
that month. A third well, the High Island 130 #2, is being drilled to develop
the deeper reserves and test an additional section for still deeper pays. Callon
owns a 16.7% working interest in the Gyro K-1, and 11.7% working interest in
the deeper sands. The wells are operated by Hydro GOM.
East Cameron Block 268 #1 (Blondie Prospect) - The initial well was
drilled to a depth of 11,000 feet and encountered 35 feet of net pay. Production
began in late September and the well is producing at a rate of 8 MMcf per day.
Callon has a 50% working interest.
Brazos Block 405 #1 (Pelican Prospect) - The well was drilled to a depth
of 10,667 feet during the first quarter. Production commenced in August and the
well is making 3 MMcf per day. The Company owns a 50% working interest.
East Cameron Block 109 - The discovery well was drilled to a depth of
13,150 feet and encountered 54 feet of net pay. The well is producing at a rate of
9 MMcf and 280 Bo per day. Callon owns a 25% working interest.
Pumpkin Ridge (Cameron Parish, Louisiana) - The discovery well was
drilled to a total depth of 17,250 feet and encountered 109 feet of net pay. The
well is expected to commence production during April 2007 at a rate of 11 MMcf
per day. The Company owns a 10% working interest.
Prairie Beach - Our Prairie Beach discovery in coastal Cameron Parish,
Louisiana, logged 37 feet of net pay. The well commenced production in late
October and is producing at a rate of 8.5 MMcf and 250 Bo per day. The
Company owns a 75% working interest and operates the well.
Producing Properties
Our major producing properties are located in the Outer Continental
Shelf and the Deepwater Regions in the Gulf of Mexico.
Medusa Field (Mississippi Canyon Blocks 538/582) - The Medusa spar
production platform is in approximately 2,200 feet of water and we have six
wells producing a total of 16,000 Bo per day and 16 MMcfe per day. We
anticipate drilling an additional well in 2007 which will increase field
production. Callon owns a 15% working interest in the field.
Habanero Field (Garden Banks Block 341) - We have two
producing wells at Habanero which produce with sub-sea completions
through Shell’s Auger production platform. The combined production
rate is approximately 6,200 Bo and 9.2 MMcf per day. During the
second quarter of 2007, one of the two wells is expected to be
sidetracked to near the structural crest of a strong water-driven oil
reservoir to exploit reserves up-dip of the two producing wells. The
Company owns an 11.25% working interest in the field
West Cameron Block 295 - We now have three wells online
producing a total of 27.5 MMcfe per day and may drill another well on
the block during 2007. We own a 20.5% working interest in the wells
and the block.
North Padre Island Block 913 - This field went online in March
2006 and is producing 13.8 MMcfe per day. Callon owns a 50%
working interest and operates the well.
Oil and Gas Reserves
The Company ended 2006 with estimated net proved reserves
of 66.0 billion cubic feet of natural gas and 13.3 million barrels of oil,
or 145.6 Bcfe, a reduction of 43.0 Bcfe versus 2005 year-end proved
reserves of 188.6 Bcfe. A majority of this reduction is attributable to a
reclassification of reserves related to the Company’s Entrada Field from
‘proved undeveloped’ to ‘probable’ by the Company’s independent
petroleum engineers in their year-end reserve report. The
reclassification was the result of a revision in estimated proved reserves
at Entrada based upon new performance data from analogous
deepwater reservoirs. As of December 31, 2006, the Company had 46.8
Bcfe of probable reserves, or a total of 192.4 Bcfe of 2P (proved plus
probable) reserves.
Completed Credit Facility
During August, the Company announced the completion of a $175
million amended and restated senior secured credit facility with Union Bank
of California, N.A. as the lead arranger and administrative agent. The credit
facility included more favorable borrowing rates and an initial borrowing
base of $75 million, which will be reviewed and re-determined on a semi-
annual basis. There was $35 million of borrowings outstanding under the
facility as of December 31, 2006.
Entrada Acquisition
On March 8, 2007, the Company signed a purchase and sale
agreement with BP Exploration and Production Company (BP) to purchase its
80% interest in the Entrada Field. We will pay BP $150 million initially along
with a $40 million payment once Entrada has produced the equivalent of 12.5
million gross barrels of oil. Upon closing, Callon will own 100% of this
property and become operator.
This is a landmark transaction for the Company which will allow us to
control the development of the Entrada Field and unlock the inherent value
of this important property for our Company. We plan to finance the
acquisition with a new $200 million credit facility, which we will use to pay the
$150 million initial purchase price and the fees and expenses of the financing.
In addition, we intend to initially repay borrowings under the current
revolving credit facility and, eventually, to use a portion of the funds as
development capital for Entrada.
We thank you for your support and confidence as we continue to
strive to build shareholder value.
Fred L. Callon
Chairman
SECURITIES AND EXCHANGE COMMISSION
UNITED STATES
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, 2006
Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
200 North Canal Street
Natchez, Mississippi 39120
(Address of Principal Executive
Offices)(Zip Code)
64-0844345
(I.R.S. Employer
Identification No.)
(601) 442-1601
(Registrant’s telephone number
including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, Par Value $.01 Per Share
Name of exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes__ No
X.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __
No X .
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. [ __ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See
definitions of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ____ Accelerated filer X Non-accelerated filer ___
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ___ No X .
The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the registrant was approximately
$384.5 million as of June 30, 2006 (based on the last reported sale price of such stock on the New York Stock Exchange on such
date of $19.34).
As of March 5, 2007, there were 20,750,449 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, 2007) relating to the Annual Meeting of Stockholders to be held on May 3, 2007, which are
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 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 11 years, we have 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, 2006,
we owned working interests in a total of 112 blocks/leases covering 223,000 net acres. To minimize risk we
join with industry partners 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 Amplitude
versus Offset (“AVO”) technology. We have 8,000 square miles of 3-D seismic data and have invested in
pre-stack time migration in order to apply AVO de-risking to our prospects. In 1998, we began exploration in
the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water) and during 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 2006 with estimated net proved reserves of 145.6 billion cubic feet of natural gas
equivalent (“Bcfe”). This represents a decrease of 23% from 2005 year-end estimated net proved reserves of
188.6 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 Securities and Exchange Commission (“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:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas, and
onshore Louisiana;
aggressively explore our existing prospect inventory;
replenish our prospect inventory with increasing emphasis on prospect generation using AVO
technology to reduce the risks associated with our exploratory drilling; and
acquire producing properties with infrastructure in areas of focus that contain upside potential.
Exploration and Development Activities
In 2006, capital expenditures for exploration and development costs related to oil and gas properties
totaled approximately $167 million. These expenditures included:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
$107 million in the Gulf of Mexico shelf, onshore south Louisiana and Texas State waters areas
which included the drilling of 10 exploratory wells, five of which were unsuccessful, two
development wells and completion costs for our successful wells;
$15 million in our deepwater area, which included four exploratory wells, three of which were
unsuccessful and one temporarily abandoned;
$16 million for leasehold and seismic costs;
$13 million for plugging and abandonment costs; and
$6 million for capitalized interest and $10 million for capitalized general and administration costs
allocable directly to exploration and development projects.
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
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:
the amount of oil and gas that we are economically able to produce;
(cid:120) our revenues, cash flows and earnings;
(cid:120)
(cid:120) 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;
(cid:120)
the value of our oil and gas properties; and
(cid:120)
the profit or loss we incur in exploring for and developing our reserves.
(cid:120)
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.
3
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 the estimates. Any
significant variance could materially affect the estimated quantities and present value of reserves shown
in this report. In addition, estimates of proved reserves may be adjusted to reflect production history,
results of exploration and development, prevailing oil and gas prices and other factors, many of which are
beyond our control.
Also, under Mineral Management Services (“MMS”) rules governing our deepwater Medusa property and
several of our shallow water, deep natural gas properties and prospects, we are eligible for royalty
suspensions depending on the difference between the average monthly New York Mercantile Exchange
(NYMEX) sales price for oil or gas and price thresholds set by the MMS. As a result, our reserve
estimates may increase or decrease depending upon the relation of price thresholds versus the average
NYMEX prices.
Our Entrada field is governed by leases from the MMS. These leases granted royalty suspension without
provisions for pricing thresholds for crude oil and natural gas which would require us to pay royalties to
the MMS if the thresholds were exceeded by the current year average of NYMEX prices. The MMS has
notified us the exclusion of the provisions occurred in error in the lease issuance process and was not the
MMS’s intention. Congress is considering various bills to address this issue and if a bill were to pass to
amend the leases to provide thresholds for crude oil and natural gas prices the reserves for Entrada could
be subject to royalties. However, the MMS stated in their correspondence to us they will continue to
honor the terms of the leases as issued unless notified otherwise. This correspondence applies only to our
20% working interest in the Entrada field.
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.
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 the reserves.
The discounted present value of reserves, therefore, does not necessarily represent the fair market value of
those reserves.
On December 31, 2006, approximately 57% of the discounted present value of our estimated net proved
reserves were proved undeveloped. Proved undeveloped reserves represented 54% of total proved
4
reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties.
Development of these properties is subject to additional risks as described above.
Information about reserves constitutes forward-looking information. See “Forward-Looking
Statements” for information regarding forward-looking information.
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.
Also, because of the aggregate short life of our reserves, our return on the investment we make in our oil
and gas wells and the value of our oil and gas wells will depend significantly on prices prevailing during
relatively short production periods.
A significant part of the value of our production and reserves is concentrated in a small number of
offshore properties, and any production problems or inaccuracies in reserve estimates related to
those properties would adversely impact our business. During 2006, approximately 80% of our daily
production came from eight of our properties in the Gulf of Mexico. Moreover, one property accounted
for 40% of our production during this period. In addition, at December 31, 2006, most of our proved
reserves were located in three fields in the Gulf of Mexico, with approximately 72% 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:
(cid:120) unexpected drilling conditions;
(cid:120) pressure or inequalities in formations;
(cid:120) equipment failures or accidents;
(cid:120) adverse weather conditions;
(cid:120) compliance with governmental requirements; and
(cid:120)
shortages or delays in the availability of drilling rigs and the delivery of equipment.
5
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:
(cid:120)
(cid:120)
(cid:120)
the operator may initiate exploration or development at 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 non-operated 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. Deepwater discoveries require the construction of expensive production
facilities and pipelines prior to 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:
(cid:120) decisions made by the operators of our deepwater wells;
(cid:120)
(cid:120)
(cid:120)
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:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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;
the location of, and our ability to access, platforms, pipelines and other facilities used to produce
and transport oil and gas production;
6
(cid:120)
(cid:120)
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
(cid:127) 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,
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 (cid:127)Liquidity
and Capital Resources” and Note 7 to our Consolidated Financial Statements.
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. 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
7
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;
(cid:120)
(cid:120) material changes in oil or gas prices;
(cid:120)
(cid:120)
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.
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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:
(cid:120) our drilling operations may encounter unexpected formations or pressures, which could cause
damage to equipment or personal injury;
(cid:120) we may experience equipment failures which curtail or stop production;
(cid:120) 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; and
(cid:120) because of these or other events, we could experience environmental hazards, including oil spills,
gas leaks, and ruptures.
In the event of any of the foregoing, we may be subject to interrupted production or substantial
environmental liability due to injury to or loss of life, damage to or destruction of property, natural
resources and equipment, pollution and other environmental damage, investigation and remediation
requirements. 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
8
the difference between the floating price and the fixed price when the floating price exceeds the fixed
price regardless of whether we have sufficient production to cover the quantities specified in the hedge.
Significant reductions in production at times when the floating price exceeds the fixed price could require
us to make payments under the hedge agreements even though such payments are not offset by sales of
production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas
prices above the fixed amount specified in the hedge. 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. Another type of hedging contract we have entered into is a put contract.
Under a put, if the price falls below the set floor price, the counter-party to the contract pays the
difference to us. 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 “Regulations”. These laws and regulations may:
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(cid:120)
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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 measures to remediate or mitigate pollution and environmental impacts from current and
former operations, such as cleaning up spills or 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:
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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.
9
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.
There are inherent limitations in all control systems, and misstatements due to error or fraud that
could seriously harm our business may occur and not be detected. Our management, including our
Chief Executive and Financial Officers, do not expect that our internal controls and disclosure controls
will prevent all possible error and all fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the objectives of the control system
are met. In addition, the design of a control system must reflect the fact that there are resource constraints
and the benefit of controls must be relative to their costs. Because of the inherent limitations in all
control systems, an evaluation of controls can only provide reasonable assurance that all material control
issues and instances of fraud, if any, in our company have been detected. These inherent limitations
include the realities that judgments in decision-making can be faulty and that breakdowns can occur
because of simple error or mistake. Further, controls can be circumvented by the individual acts of some
persons or by collusion of two or more persons. The design of any system of controls is based in part
upon certain assumptions about the likelihood of future events, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future conditions. Because of inherent
limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be
detected. A failure of our controls and procedures to detect error or fraud could seriously harm our
business and results of operations.
10
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:
(cid:120) our oil and gas reserve quantities, and the discounted present value of these reserves;
(cid:120) the amount and nature of our capital expenditures;
(cid:120) drilling of wells;
(cid:120) the timing and amount of future production and operating costs;
(cid:120) business strategies and plans of management; and
(cid:120) 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:
(cid:120) general economic conditions;
(cid:120) the volatility of oil and natural gas prices;
(cid:120) the uncertainty of estimates of oil and natural gas reserves;
(cid:120) the impact of competition;
(cid:120) the availability and cost of seismic, drilling and other equipment;
(cid:120) operating hazards inherent in the exploration for and production of oil and natural gas;
(cid:120) difficulties encountered during the exploration for and production of oil and natural gas;
(cid:120) difficulties encountered in delivering oil and natural gas to commercial markets;
(cid:120) changes in customer demand and producers’ supply;
(cid:120) the uncertainty of our ability to attract capital;
(cid:120) compliance with, or the effect of changes in, the extensive governmental regulations regarding the
oil and natural gas business;
(cid:120) actions of operators of our oil and gas properties; and
(cid:120) weather conditions.
The information contained in this report, including the information set forth under the heading “Risk
Factors,” identifies additional factors that could affect our operating results and performance. We urge
you to carefully consider these factors and the other cautionary statements in this report. Our forward-
looking statements speak only as of the date made, and we have no obligation to update these forward-
looking statements.
Corporate Offices
Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space.
We also maintain a business office in Houston, Texas, and own or lease 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.
11
Employees
We had 86 employees as of December 31, 2006, none of whom are currently represented by a union. We
believe that we have good relations with our employees. We employ six petroleum engineers and eight
petroleum geoscientists.
Regulations
General. The oil and gas industry is subject to regulation at the federal, state and local level, and some of
the laws, rules and regulations that govern our operations carry substantial penalties for non-compliance.
This regulatory burden increases our cost of doing business and, consequently, affects our profitability.
Exploration and Production. Our operations are subject to federal, state and local regulations that
include requirements for permits to drill and to conduct other operations and for provision of financial
assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation
are:
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the location of wells,
the method of drilling and completing wells,
the rate of production,
the surface use and restoration of properties upon which wells are drilled,
the plugging and abandoning of wells,
the disposal of fluids used or other wastes obtained in connection with operations,
the marketing, transportation and reporting of production, and
the valuation and payment of royalties.
For instance, our OCS leases in federal waters are administered by the Minerals Management Service, or
MMS, and require compliance with detailed MMS regulations and orders. Lessees must obtain MMS
approval for exploration plans and exploitation and production plans prior to the commencement of such
operations. The MMS has promulgated regulations requiring offshore production facilities located on the
OCS to meet stringent engineering and construction specifications. The MMS also has regulations
restricting the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil
without prior authorization. MMS policies concerning the volume of production that a lessee must have to
maintain an offshore lease beyond its primary term also are applicable to Callon. Similarly, the MMS has
promulgated other regulations governing the plugging and abandonment of wells located offshore and the
installation and removal of all production facilities. To cover the various obligations of lessees on the
OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other
acceptable assurances that such obligations will be met. The cost of these bonds or other surety can be
substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some
circumstances, the MMS may require any of our operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially adversely affect our financial conditions
and results of operations.
Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation.
The price and terms for access to pipeline transportation remain subject to extensive federal regulation. If
these regulations change, we could face higher transmission costs for our production and, possibly,
reduced access to transmission capacity.
12
We do not currently anticipate that compliance with existing laws and regulations governing exploration
and production will have a significantly adverse effect upon our capital expenditures, earnings or
competitive position.
Various proposals and proceedings that might affect the petroleum industry are pending before Congress,
the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The
industry historically has been heavily regulated and we can offer you no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what
effect such proposals or proceedings may have on our operations.
Environmental Regulation. Various federal, state and local laws and regulations concerning the
discharge of contaminants into the environment, the generation, storage, transportation and disposal of
wastes, and the protection of public health, natural resources, wildlife and the environment affect our
exploration, development and production operations, including processing facilities. We must take into
account the cost of complying with environmental regulations in planning, designing, drilling,
constructing, operating and abandoning wells. In most instances, the regulatory requirements relate to the
handling and disposal of drilling and production waste products, water and air pollution control
procedures, and the remediation of petroleum-product contamination. In addition, our operations may
require us to obtain permits for, among other things,
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air emissions,
discharges into surface waters, and
the construction and operations of underground injection wells or surface pits to dispose of
produced saltwater and other nonhazardous oilfield wastes.
In the event of an unauthorized discharge, emission or activity, we may be liable for penalties, costs and
damages and we could be required to cleanup or mitigate the environmental impacts of unauthorized
discharges. Under state and federal laws, we could be required to remove or remediate previously
disposed wastes and remediate contamination, including contamination in surface water, soil or
groundwater, caused by disposal of that waste. We could be responsible for wastes disposed of or
released by us or prior owners or operators at properties owned or leased by us or at locations where
wastes have been taken for disposal. We could also be required to suspend or cease operations in
contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future
contamination. The Environmental Protection Agency and various state agencies have limited the
disposal options for hazardous and nonhazardous wastes. The owner and operator of a site, and persons
that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be
liable, without regard to fault or the legality of the original conduct, for the release of a hazardous
substance into the environment. The Environmental Protection Agency, state environmental agencies and,
in some cases, third parties are authorized to take actions in response to threats to human health or the
environment and to seek to recover from responsible classes of persons the costs of such action.
Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt
from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore,
be subject to considerably more rigorous and costly operating and disposal requirements.
Federal and state occupational safety and health laws require us to organize information about hazardous
materials used, released or produced in our operations. Certain portions of this information must be
provided to employees, state and local governmental authorities and local citizens. We are also subject to
the requirements and reporting set forth in federal workplace standards.
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We have made and will continue to make expenditures to comply with environmental regulations and
requirements. These are necessary business costs in the oil and gas industry. Although we are not fully
insured against all environmental risks, we maintain insurance coverage which we believe is customary in
the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive
environmental laws and regulations, as well as claims for damages to property or persons resulting from
company operations, could result in substantial costs and liabilities, including civil and criminal penalties,
to Callon. We believe we are in compliance with existing environmental regulations, and that, absent the
occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance will not
have a material adverse effect on our operations or earnings.
Commitments and Contingencies
The Company’s activities are subject to federal, state and local laws and regulations governing environmental
quality and pollution control. Although no assurances can be made, the Company believes that, absent the
occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and
regulations governing the release of materials into 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.
Property Summary
We are engaged in the exploration, development, acquisition and production of oil and gas properties. Our
properties are concentrated offshore in the Gulf of Mexico and onshore, primarily, in Louisiana and Alabama.
We have historically increased our reserves and production by focusing primarily on low to moderate risk
exploration and acquisition opportunities in the Gulf of Mexico shelf area. In 1998, we expanded our area of
exploration to include the Gulf of Mexico deepwater area. As of December 31, 2006, our estimated net
proved reserves totaled 145.6 Bcfe and included 13.3 million barrels of oil (“MMBbl”) and 66.0 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 of $534.7 million. Oil constitutes approximately 55%
on an equivalent basis of our total estimated proved reserves and approximately 46% of our total estimated
proved reserves are proved developed reserves.
Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries
began production in the fourth quarter of 2003. A detailed discussion of each of these properties is
provided in the “Significant Properties” section of this report. These two deepwater discoveries were
responsible for 50% of our total production during 2006.
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Significant Properties
The following table shows discounted cash flows and estimated net proved oil and gas reserves by major field
and for all other properties combined at December 31, 2006.
Estimated Net Proved Reserves
Oil
Operator
(MBbls)
Gas
Pre-tax
Discounted
Present
Value
($000)
(a)(b)(c)
(MMcfe)
(MMcf)
Total
Gulf of Mexico Deepwater:
Garden Banks Block 738/782/826/827
“Entrada”
Mississippi Canyon 538/582
“Medusa”
Garden Banks Block 341
“Habanero”
Gulf of Mexico Shelf and Onshore:
High Island Blocks 165/130
West Cameron 3/LA
High Island Block A-540
West Cameron Block 295
North Padre Island Block 913
East Cameron Block 109
Other
BP
3,824
19,059
42,003
$ 134,977
Murphy
6,030
4,139
40,319
156,542
Shell
2,582
6,252
21,747
121,909
Hydro GOM
Callon
Walter Oil & Gas Corp.
Hydro GOM/Cimarex
Callon
Energy Partners LTD
Various
48
100
104
12
--
48
517
9,594
3,393
3,063
4,679
1,874
1,592
12,392
9,880
3,992
3,686
4,751
1,878
1,879
15,493
37,687
17,919
16,514
15,990
7,834
7,515
17,856
Total Net Proved Reserves
13,265
66,037
145,628 $ 534,743
(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, 2006, 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, 2006, in accordance with Statement of Financial Accounting
Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). See the Oil and
Gas Reserve table for the standardized measure of discounted future net cash flow.
(c) We use the financial measure “present value of estimated future net revenues from proved reserves,
excluding income taxes.” This is a non-GAAP financial measure. We believe that present value of
estimated future net revenues from proved reserves, excluding income taxes, while not a financial
measure in accordance with generally accepted accounting principles, is an important financial measure
used by investors and independent oil and gas producers for evaluating the relative value of oil and
natural gas properties and acquisitions because the tax characteristics of comparable companies can differ
materially. The total standardized measure for our proved reserves as of December 31, 2006 was $470.8
million. The standardized measure gives effect to income taxes, and is calculated in accordance with
Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing
Activities.” The standardized measure of our estimated net proved reserves of $470.8 million equals the
present value of our estimated future net revenue from proved reserves, excluding income taxes, of
$534.7 million, less discounted estimated future income taxes relating to such future net revenues of
$63.9 million.
15
Entrada, Garden Banks Blocks 738/782/826/827
Gulf of Mexico Deepwater
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. The Entrada Area is characterized by a northwest
plunging salt ridge with multiple stacked amplitudes trapped against the salt and various faults. At year
end 2006, we reclassified a portion of Entrada’s estimated net proved reserves to probable, as of
December 31, 2006 due to new performance data from analogous deepwater reservoirs. Please refer to
Note 15 of our Consolidated Financial Statements for further information regarding reserves. On
December 31, 2006, we owned a 20% working interest in this discovery with BP Exploration and
Production Company (“BP”), the operator, holding the remaining working interest.
Subsequent to December 31, 2006, on March 8, 2007 we entered into an agreement with BP to purchase BP’s
80% working interest in the Entrada Field for total cash consideration of $190 million. The purchase price
includes $150 million payable at closing and an additional $40 million payable after the achievement of
certain production milestones. The purchased interests include five federal offshore blocks at Garden Banks
Blocks 738, 782, 785, 826 and 827, subject to certain depth limitations. Upon the completion of the
acquisition, we will own a 100% working interest in the Entrada Field and will become operator. The
acquisition is expected to close within the next 45 days and will add 150 Bcfe to our proved undeveloped
reserves.
The Magnolia field is located on blocks adjacent to Entrada. The field and related production facilities are
owned by Conoco/Phillips, the operator, and Devon Energy Corporation. Work has been substantially
completed on a front-end engineering design study to tie-back Entrada to the Magnolia production
facilities by an integrated project team consisting of a leading engineering firm and personnel from BP
and Callon, along with the Magnolia owners. Negotiations between the Magnolia facility owners and
Entrada owners for a production handling agreement have been ongoing. We expect to complete these
negotiations in the near future once closing of our acquisition of BP’s interest in Entrada is complete.
Development expenditures are expected to commence in the second half of 2007 with the ordering of
long-lead items. The majority of development costs are anticipated to be incurred in 2008 and early 2009.
First production is projected to commence in the first quarter of 2009.
Medusa, Mississippi Canyon Blocks 538/582
Our Medusa deepwater discovery was announced in September 1999, after 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 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 Exploration & Production Company (“Murphy”), the operator,
owns a 60% working interest and ENI Deepwater, LLC, 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 and was
completed in the first half of 2002. The construction of a floating production system, spar, at Medusa was
completed during the second quarter of 2003. The A-1 well was completed and tied into the spar and
commenced production in late November 2003. The remaining five wells were completed and
commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled in 2003 and was
temporarily abandoned after encountering 28 feet of net pay. The well bore was re-entered in the fourth
16
quarter of 2004, sidetracked and reached an objective depth of 9,600 feet in January 2005. The sidetrack
encountered 46 feet of net pay, was completed and commenced initial production in April 2005.
During 2006 the field produced 8.2 Bcfe net to us which accounted for 40% of our total production.
Future plans include five recompletions to produce up-hole sands and two sidetracks to undrained areas of
the field up-dip or fault separated from existing productions.
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 2,015 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 the last of the sidetracks to the Habanero 52 oil and
gas sand and the Habanero 55 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. 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 and from the Habanero 55 gas sand in
January 2004. In July 2004 the #2 well producing the Habanero 52 oil sand developed mechanical
difficulties with a subsurface control valve and was shut-in resulting in a significant loss of production.
Repairs were completed and production was restored in late December 2004. In addition, the #1 well
producing the Habanero 55 gas sand was recompleted to the Habanero 55 oil sand in December 2004.
At the time the field was developed, there was no way to know what the drive mechanism would be, so
the wells were put at a mid-dip position. It is now known the field drive mechanism is water and the
wells need to be at the structural crest for maximum recovery. A sidetrack of the #1 well is planned for
this summer to move that well to an up-dip position.
During 2006 Habanero produced 2.1 Bcfe net to us which accounted for 10% of our total production.
Gulf of Mexico Shelf and Onshore Louisiana
High Island Blocks 165/130
The High Island 165 #1 well was spud in the fourth quarter of 2005, reached total depth of 17,029 feet in
January 2006 and logged 140 feet of net pay. The well commenced production in October 2006 and
during February 2007 was producing at a gross rate of 44 million cubic feet of natural gas per day. We
have two development wells in progress, the High Island Block 130 #1 and #2 wells. The #1 well is being
completed and should commence production at a similar rate late in the first quarter of 2007. In addition
to the productive sands discovered by the High Island 165 #1 well, the High Island 130 #1 well
encountered two deeper productive sands. The High Island 130 #2 well is drilling and if successful should
17
commence production in the second half of 2007. The High Island 165 #1 well produced 0.4 Bcfe net to
our interest in the fourth quarter of 2006. We have a 16.7% working interest in the shallower productive
zones and an 11.7% interest in the deeper discovered by the High Island 130 #1 well and the operator of
the field is Hydro Gulf of Mexico, LLC.
West Cameron 3/LA
We drilled our Prairie Beach prospect during the first half of 2006 which is located onshore in the state
waters of Cameron Parish, Louisiana. The well encountered 37 feet of net pay and began production in
October 2006. During 2006, the field produced 0.3 Bcfe net to us. We operate and own a 75% working
interest.
High Island Block A-540
The #1 well was spud in November 2005 and reached a total depth of 9,450 feet the following month after
logging 32 feet of net pay in the objective section. First production commenced in late September 2006
and during 2006 the field produced 0.3 Bcfe net to us. The company owns a 60% working interest and
Walter Oil and Gas is the operator.
West Cameron Block 295
During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150 feet of
net pay in two zones. Each zone was encountered at the predicted depth and exceeded anticipated
thickness. The #2 well commenced production in the second quarter of 2006 and encountered mechanical
difficulties which were corrected. Sustained production was achieved by the third quarter of 2006. In
2006, we drilled the #4 well, an offset to the #2 well. The #4 well commenced production during
December 2006 in a deeper, secondary zone. After this zone is depleted we expect to recomplete the well
in the main pay zone. Callon holds a 20.5% working interest in the block and Hydro Gulf of Mexico, LLC
is the operator.
A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth of
16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two zones.
The well was completed in a deeper secondary zone and will probably be recompleted to the main pay
zone in early 2008. The well commenced production in August 2006. Callon holds a 20.5% working
interest in the block and Cimarex Energy Company is the operator.
During 2006, the West Cameron 295 field produced 0.8 Bcfe net to us.
North Padre Island Block 913
An exploratory well was drilled to a vertical depth of 8,082 feet in the fourth quarter of 2004 and found
natural gas pay in multiple intervals. The well is tied back to existing infrastructure on a nearby block.
We are the operator and own a 50% working interest. First production commenced in March 2006 and
during 2006 the field produced 1.5 Bcfe net to us.
18
East Cameron 109
During 2006, an exploratory well was drilled to a vertical depth of 13,110 feet and encountered 54 feet of
net pay. The well commenced production during the second half of 2006 and produced 0.1 Bcfe before
encountering mechanical problems. Production was restored in January 2007. Callon owns a 25%
working interest and Energy Partners, LTD is the operator.
Oil and Gas Reserves
The following table sets forth certain information about our estimated proved reserves as reported by
Huddleston & Co., Inc. as of the dates set forth below.
2006
Years Ended December 31,
2005
(In thousands)
2004
Proved developed:
Oil (Bbls)
Gas (Mcf)
Mcfe
Proved undeveloped:
Oil (Bbls)
Gas (Mcf)
Mcfe
Total proved:
Oil (Bbls)
Gas (Mcf)
Mcfe
5,159
36,750
67,704
7,323
30,982
74,921
8,106
29,287
77,924
11,105
47,039
113,667
10,292
33,982
95,735
9,456
38,637
95,373
13,265 18,428
66,037 78,021
145,628 188,588
19,748
72,619
191,108
Estimated pre-tax future net cash flows (a)
$ 775,742 $ 1,487,817
$ 892,145
Pre-tax discounted present value (a) (b)
$ 534,743 $ 1,088,714
$ 612,595
Standardized measure of discounted future
net cash flows(a) (b)
$ 470,791 $ 837,552
$ 515,893
(a)
Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on
our balance sheet at December 31, 2006, in accordance with SFAS 143.
(b) We use the financial measure “present value of estimated future net revenues from proved reserves,
excluding income taxes.” This is a non-GAAP financial measure. We believe that present value of
estimated future net revenues from proved reserves, excluding income taxes, while not a financial
measure in accordance with generally accepted accounting principles, is an important financial
measure used by investors and independent oil and gas producers for evaluating the relative value of
oil and natural gas properties and acquisitions because the tax characteristics of comparable
companies can differ materially. The total standardized measure for our proved reserves as of
December 31, 2006 was $470.8 million. The standardized measure gives effect to income taxes, and
19
is calculated in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures
About Oil and Gas Producing Activities.” The standardized measure of our estimated net proved
reserves of $470.8 million equals the present value of our estimated future net revenue from proved
reserves, excluding income taxes, of $534.7 million, less discounted estimated future income taxes
relating to such future net revenues of $63.9 million.
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 SEC regulations regarding
disclosure of oil and gas reserve information.
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors
beyond our control or the control of the reserve engineers. Reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in an exact manner. 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.
Development:
Oil
Gas
Non-productive
Total
Exploration:
Oil
Gas
Non-productive
Total
Years Ended December 31,
2005
2006
2004
Gross
Net
Gross
Net
Gross
Net
--
2
--
2
--
5
8
13
--
0.37
--
0.37
--
2.05
2.98
5.03
1
--
--
1
0.15
--
--
0.15
--
--
7 2.42
1.25
3.67
4
11
--
2
--
2
--
2
5
7
--
1.22
--
1.22
--
0.72
1.24
1.96
20
The following table sets forth our productive wells as of December 31, 2006:
Oil:
Working interest
Royalty interest
Wells
Gross
Net
40.00
193.00
3.90
3.15
Total
233.00
7.05
Gas:
Working interest
Royalty interest
35.00
211.00
14.40
1.49
Total
246.00
15.89
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, 2006, we had no wells with
multiple completions. At December 31, 2006, 1 gross (0.033 net) exploration oil well, 1 gross (0.255 net)
exploration gas well and 1 gross (0.117 net) development gas well were in progress.
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as
of December 31, 2006.
Location
Louisiana
Texas
Other states
Federal waters
Leasehold Acreage
Developed
Gross
Net
Undeveloped
Gross
Net
6,274
78
--
107,029
4,019
--
--
53,930
10,706
15,150
681
357,270
4,454
7,616
509
152,105
Total
113,381
57,949
383,807
164,684
As of December 31, 2006, we owned various royalty and overriding royalty interests in 553 net developed
and 7,645 net undeveloped acres. In addition, we owned 4,071 developed and 121,929 undeveloped mineral
acres.
21
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:
Shell Trading Company
Louis Dreyfus Energy Services
Plains Marketing, L.P.
Chevron Texaco Natural Gas
December 31
2006
41%
25%
11%
3%
2005
34%
16%
16%
10%
2004
30%
23%
13%
6%
Because alternative purchasers of oil and gas are readily available, we believe that the loss of any of these
purchasers would not result in a material adverse effect on our ability to market future oil and gas production.
Title to Properties
We believe that the title to our oil and gas properties is good and defensible in accordance with standards
generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so
material as to detract substantially from the use or value of such properties. Our properties are typically
subject, in one degree or another, to one or more of the following:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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.
22
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 2006.
23
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
2005:
2006:
First quarter
Second quarter
Third quarter
Fourth quarter
First quarter
Second quarter
Third quarter
Fourth quarter
$ 18.00
16.12
21.25
22.29
$ 13.22
12.42
14.81
16.65
$ 21.25
21.99
19.96
17.44
$ 17.01
15.12
12.54
12.48
As of March 5, 2007 there were approximately 4,057 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.
24
Performance Graph
The following graph compares the yearly percentage change for the five years ended December 31, 2006, in
the cumulative total shareholder return on the Company’s Common Stock against the cumulative total return
for the (i) Hemscott Industry and Market Index of SIC Group 123 (the “Hemscott Group Index”) consisting of
independent oil and gas drilling and exploration companies and (ii) the New York Stock Exchange Market
Index. The comparison of total return on an investment for each of the periods assumes that $100 was
invested on December 31, 2001 in the Company, the Hemscott Group Index and the New York Stock
Exchange Market Index, and that all dividends were reinvested.
COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG CALLON PETROLEUM COMPANY
NYSE MARKET INDEX AND HEMSCOTT GROUP INDEX
400
350
300
250
200
150
100
50
S
R
A
L
L
O
D
0
2001
2002
2003
2004
2005
2006
CALLON PETROLEUM COMPANY
HEMSCOTT GROUP INDEX
NYSE MARKET INDEX
ASSUMES $100 INVESTED ON DEC. 31, 2001
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2006
Callon Petroleum Company
Hemscott Group Index
NYSE Market Index
2001
$ 100
$ 100
$ 100
2002
$ 49
$ 93
$ 82
2003
$ 151
$ 121
$ 106
2004
$ 211
$ 170
$ 119
2005
$ 258
$ 268
$ 129
2006
$ 219
$ 318
$ 152
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, 2006 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.
25
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Statement of Operations Data:
Operating revenues:
Oil and gas sales
Operating expenses:
Lease operating expenses
Depreciation, depletion and amortization
General and administrative
Accretion expense
Derivative expense
Total operating expenses
Years Ended December 31,
2006
2005
2004
2003 2002
$182,268 $ 141,290 $ 119,802 $ 73,697 $ 61,171
28,881
65,283
8,591
4,960
24,377
22,308
11,301
11,030
44,946
47,453
28,253
27,096
8,085
3,549
8,758
3,400
4,713
2,884
4,705
--
150
6,028 1,371 535 708
107,865
86,985 83,290 47,686 43,539
Income from operations 74,403 54,305 36,512 26,011 17,632
Other (income) expenses:
Interest expense
Other (income)
Loss on early extinguishment of debt
Gain on sale of pipeline
16,480
(1,869)
16,660
(998)
20,137
(357)
30,614
(444)
26,140
(1,004)
--
--
--
--
3,004
5,573
--
--
--
--
(2,454)
-- (2,479)
Gain on sale of Enron derivatives --
--
Total other (income) expenses
14,611
15,662 22,784
35,743
20,203
Income (loss) before income taxes
59,792
38,643
13,728
(9,732)
(2,571)
Income tax expense (benefit) 20,707 13,209 (6,697) 8,432
(900)
Income (loss) before equity in earnings of Medusa Spar LLC
and cumulative effect of change in accounting principle
39,085
25,434
20,425
(18,164)
(1,671)
Equity in earnings of Medusa Spar LLC, net of tax
1,475
1,342 1,076 (8)
--
Income (loss) before cumulative effect of change in
in accounting principle
40,560
26,776
21,501
(18,172)
(1,671)
Cumulative effect of change in accounting principle,
net of tax
Net income (loss)
Preferred stock dividends
--
--
-- 181
--
40,560
26,776
21,501
(17,991)
(1,671)
-- 318
1,272
1,277
1,277
Net income (loss) available to common shares
$ 40,560 $ 26,458 $ 20,229 $(19,268) $ (2 ,948)
26
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Years Ended December 31,
2003
2004
2005
2006
2002
Net income (loss) per common share:
Basic:
Net income (loss) available to common before cumulative
effect of change in accounting principle
$ 2.00
$ 1.43 $ 1.28 $ (1.42) $ (.22)
Cumulative effect of change in accounting principle,
net of tax
--
--
-- .01
--
Net income (loss) available to common
$ 2.00
$ 1.43 $ 1.28 $ (1.41) $ (.22)
Diluted:
Net income (loss) available to common before cumulative
effect of change in accounting principle
$ 1.90
$ 1.28 $ 1.22 $ (1.42) $ (.22)
Cumulative effect of change in accounting principle,
net of tax
--
--
--
.01
--
Net income (loss) available to common
$ 1.90
$ 1.28 $ 1.22 $ (1.41) $ (.22)
Shares used in computing net income (loss) per common share:
Basic 20,270
18,453 15,796 13,662 13,387
Diluted 21,363
20,883 17,678 13,662 13,387
Balance Sheet Data (end of period):
Oil and gas properties, net
Total assets
$ 547,027 $ 447,364 $ 406,690 $ 390,163 $377,661
$ 625,527 $ 533,776 $ 457,523 $ 496,032 $410,613
Long-term debt, less current portion
$ 225,521 $ 188,813 $ 192,351 $ 214,885 $248,269
Stockholders' equity
$ 281,363 $ 228,048 $ 198,312 $ 133,261 $140,960
We follow the full-cost method of accounting for oil and gas properties. Under this method of
accounting, our net capitalized costs to acquire, explore and develop oil and gas properties may not
exceed the sum of (1) the estimated future net revenues from proved reserves at current prices discounted
at 10% and (2) the lower of cost or market of unevaluated properties, net of tax (the full-cost ceiling
amount). If these capitalized costs exceed the full-cost ceiling amount, the excess is charged to expense.
27
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 relating to our financial and operating results for the year ended December 31, 2006
included the closing of our four-year amended and restated senior secured credit facility which was
underwritten by Union Bank of California, N.A. The credit facility has an initial borrowing base of $75
million, which will be reviewed and redetermined semi-annually and can be increased to a maximum of
$175 million. We expect planned 2007 capital expenditures of approximately $125 million will be
funded with cash flows from operations and supplemented, if necessary, with our senior secured credit
facility, which had $40 million available at December 31, 2006. For a more detailed discussion of
outstanding debt see Note 7 to our Consolidated Financial Statements.
Our estimated net proved oil and gas reserves decreased at December 31, 2006 to 145.6 Bcfe. This
represents a decrease of 23% from previous year-end 2005 estimated proved reserves of 188.6 Bcfe.
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 the proved reserves, borrowing capacity,
revenues, profitability and cash flows from operations. We use derivative financial instruments (see Note 8 to
our Consolidated Financial Statements 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 these
instruments for trading purposes. On a Mcfe basis, natural gas represents approximately 73% of budgeted
2007 production and 45% of proved reserves at year-end 2006.
Inflation has not had a material impact on us and is not expected to have a material impact on us in the future.
28
Summary of Significant Accounting Policies
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 that could change. These estimates are described below.
Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We calculate depletion by
using the net capitalized costs in our full-cost pool plus future development costs (combined, the depletable
base) and our estimated net proved reserve quantities. Capitalized costs added to the full-cost pool include
the following:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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 classified as unevaluated property
costs and are excluded from the depletable base. These unevaluated property costs are added to the
depletable base 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;
estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool
when the related liabilities are incurred under SFAS 143; and
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.
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 the proved reserves quantities at the beginning of each
accounting period. For each Mcfe 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 rates may change if the estimates and assumptions are not
realized. Such changes may be material.
Ceiling Test. Under the full-cost accounting rules of the SEC, we review the carrying value of our proved oil
and gas properties each quarter. Under these rules, capitalized costs of oil and gas properties, net of
accumulated depreciation, depletion and amortization 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%, plus the lower
of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These
29
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. However, if prices recover
sufficiently subsequent to the balance sheet date before the release of the financial statements then use of the
subsequent pricing is allowed and no write-down would be required if same pricing was used. Given the
volatility of oil and gas prices, it is reasonably possible that our 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 write-downs of oil and gas properties could occur in
the future.
Estimating Reserves and Present Values. The estimates of quantities of proved oil and gas reserves and the
discounted present value of estimated future net cash flows from such reserves at the end of each quarter are
based on numerous assumptions, which are likely to change over time. These assumptions include:
(cid:120)
(cid:120)
(cid:120)
the prices at which we can sell our oil and gas production in the future. Oil and gas prices are volatile,
but we are 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 estimated future net cash flows from 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 of estimated future net cash flows more than the estimated quantities of oil and
gas reserves;
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 estimated oil
and gas quantities and the present value of estimated future net cash flows, while decreases in costs
will increase such amounts. Because our properties have relatively short productive lives, changes in
costs will affect the present value of estimated future net cash flows more than the estimated quantities
of oil and gas reserves; and
the potential royalties payable to the Mineral Management Service. See Note 9 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 depletable base. These unproved properties are included in the line item
“Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the
depletable base 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, include the costs of such
properties in the depletable base. 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.
Asset Retirement Obligations. We account for asset retirement obligations in accordance with Statement of
Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”),
which 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. Interest is accreted on
the present value of the asset retirement obligation and reported as accretion expense within operating
30
expenses in the Consolidated Statements of Operations. See Note 10 to our Consolidated Financial
Statements.
Derivatives. We periodically use derivative financial instruments to manage oil and gas price risk on a
limited amount of our future production and do not use these instruments for trading purposes. Settlement of
derivative contracts are generally based on the difference between the contract price or prices specified in the
derivative instrument and a NYMEX price or other cash or futures index price. Such derivatives are
accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (“SFAS 133”) as amended.
Our derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded at fair
market value and the changes in fair value are recorded through other comprehensive income (loss), net of
tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in
oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as
derivative expense (income). The cash settlement on these contracts is also recorded within derivative
expense (income). The changes in fair value of the our derivative contracts that are not designated as
effective cash flow hedges are recorded through the statement of operations as derivative expense (income).
See Note 8 to our Consolidated Financial Statements.
Income Taxes. We follow the asset and liability method of accounting for deferred income taxes prescribed
by Statement of Financial Accounting Standards No. 109 "Accounting for Income Taxes” ("SFAS 109").
SFAS 109 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.
Share-Based Compensation. Effective January 1, 2006, we adopted Statement of Financial Accounting
Standard No. 123 (revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified prospective
transition method. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance
with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic
value method) and, accordingly, recognized no compensation expense for stock option grants.
Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards as of
January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified,
repurchased or cancelled. Under the modified prospective transition method, compensation cost recognized
in 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of
January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of
Statement of Financial Accounting Standard No. 123 “Accounting for Stock-Based Compensation,” (“SFAS
123”) and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on
the grant-date fair value estimated in accordance with the provisions of SFAS 123R. Prior periods were not
restated to reflect the impact of adopting the new standard.
SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of compensation
cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. The
$1.4 million of excess tax benefits classified as a financing cash inflow for the year ended December 31, 2006
would have been classified as an operating cash flow had we not adopted SFAS 123R. There were no cash
proceeds from the exercise of stock options for the year ended December 31, 2006 due to the fact that all
options were exercised through net-share settlements. As a result of most of our stock-based compensation
being in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes, net
income and basic and diluted earnings per share for the year ended December 31, 2006 was immaterial. See
Note 3 to our Consolidated Financial Statements.
31
New Accounting Standards
In June 2006, the Financial Accounting Standards Board (“FASB”) released interpretation No. 48,
Accounting for Uncertainty in Income Taxes (“FIN 48”). FIN 48 clarifies the accounting for income taxes by
prescribing the minimum recognition threshold a tax position must meet before being recognized in the
financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest
and penalties, accounting in interim periods, disclosure and transition. The effective date for FIN 48 is fiscal
years beginning after December 15, 2006. We are currently reviewing the provisions of FIN 48 and have not
yet determined the impact of adoption.
In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, Fair Value
Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value
and requires enhanced disclosures about fair value measurements. SFAS 157 is effective for fiscal years
beginning after November 15, 2007 and interim periods within those fiscal years. We are still reviewing the
provisions of SFAS 157 and have not yet determined the impact of adoption.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from
financial institutions and the sale of debt and equity securities. Net cash and cash equivalents decreased
by $669,000 during 2006 to $1.9 million. Cash provided from operating activities during 2006 totaled
$135.5 million, an increase of 83% from $74.0 million in 2005.
On August 30, 2006, we closed on a four-year amended and restated senior secured credit facility
underwritten by Union Bank of California, N.A. The credit facility includes an initial borrowing base of
$75 million, which will be reviewed and redetermined semi-annually and can be increased to a maximum
of $175 million. During 2006 we drew $35 million under our facility which was outstanding as of
December 31, 2006 and $40 million was available for future borrowings. In connection with the
anticipated financing of the acquisition of BP’s interest in the Entrada Field, the borrowing base under
this facility would be reduced to $50 million at closing until the next borrowing base redetermination
date. Please refer to “Subsequent Events” below for more discussion on the Entrada acquisition.
In December 2003 and March 2004, we closed on our 9.75% senior notes due 2010 in the aggregate
principal amount of $200 million. The net proceeds from these notes and the public offering of 3,450,000
shares of common stock in the second quarter of 2004 were used to restructure our debt that was maturing
in 2004 and 2005. See Note 7 to the Consolidated Financial Statements for a more detail discussion of
long-term debt.
The indenture governing our 9.75% senior notes due 2010 and our senior secured credit facility contain
various covenants including restrictions on additional indebtedness and payment of cash dividends. In
addition, our senior secured credit facility contains covenants for maintenance of certain financial ratios.
We were in compliance with these covenants at December 31, 2006.
Our oil and gas reserves as estimated by Huddleston & Co., Inc. were 145.6 Bcfe of natural gas
equivalents on December 31, 2006. Our cash flow from operations during 2006 was generated by the
production of 20.8 Bcfe. Production of our reserves during 2007, without weather-related downtime, is
projected to be higher than 2006 due to new discoveries that are projected to commence initial production
during the year, which is expected to offset anticipated declines from our current producing properties.
32
In addition to the acquisition of BP’s interest in the Entrada field, our planned capital expenditures for 2007
total $125 million and include capitalized interest and general and administrative expenses. The current
portion of our asset retirement obligation will require an additional $10 million resulting in total capital
expenditures of $135 million for 2007. Capital expenditure plans for 2007 include:
(cid:120)
(cid:120)
(cid:120)
the discretionary drilling of up to 17 exploratory and development wells;
lease and seismic acquisition; and
capitalized interest and overhead.
We believe that our operating cash flow and our credit facility will be adequate to meet our capital, debt
repayment, and operating requirements for 2007. We fund our day-to-day operating expenses and capital
expenditures from operating cash flows, supplemented as needed by borrowings under our credit facility.
In addition, we have sold debt and equity in both public and private offerings in the past, and we expect
that these sources of capital will continue to be available to us in the future. Because of the liquidity and
capital resources alternatives available to us, including internally generated cash flows, our management
believes that our short-term and long-term liquidity is adequate to fund operations, including our capital
spending program and repayment of maturing debt.
Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas prices,
production levels, industry trends impacting operating expenses and our ability to continue to acquire or
find reserves at competitive prices. Cash flow forecasts for internal use by management are revised
monthly in response to changing market conditions and production projections. We may adjust capital
expenditure budgets within the planned total amount in response to the adjusted cash flow forecasts and
market trends in drilling and acquisitions costs.
The following table describes our outstanding contractual obligations as of December 31, 2006 (in
thousands):
Payments due by Period
More
Total One Year
Contractual Less Than One-Three Three-Five Than-Five
Obligations
$ 35,000
Senior Secured Credit Facility
9.75% Senior Notes 200,000
Capital lease (future minimum payments) 1,270
Throughput Commitments:
Medusa Spar LLC
Medusa Oil Pipeline 400
Years
--
--
446 19
--
101 62
$245,518 $ 3,605 $ 6,285 $235,547 $ 81
$ -- $ -- $ 35,000 $
5,696
105 132
--
348 457
-- 200,000
3,152
Years
8,848
Years
--
Subsequent Events
Subsequent to December 31, 2006, on March 8, 2007, we entered into an agreement with BP to purchase
BP’s 80% working interest in the Entrada Field for total cash consideration of $190 million. The purchase
price includes $150 million payable at closing and an additional $40 million payable after the achievement of
certain production milestones. The purchased interests include five federal offshore blocks at Garden Banks
Blocks 738, 782, 785, 826 and 827, subject to certain depth limitations. Upon the completion of the
acquisition, we will own a 100% working interest in the Entrada Field and will become operator. The
acquisition is expected to close within the next 45 days and will add 150 Bcfe to our proved undeveloped
reserves.
33
To finance the initial $150 million payment of the purchase price, a commitment has been received from
Merrill Lynch Capital Corporation to make available to us a 7-year, $200 million revolving credit facility
secured by a lien on the Entrada properties. We plan to borrow the full commitment amount at closing to
cover the required $150 million payment to BP and, expenses and fees, and the balance of the funds can be
used for Entrada development cost or general corporate purposes.
Off-Balance Sheet Arrangements
We have a 10% ownership interest in Medusa Spar LLC (“LLC”), which is a limited liability company
that 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. The
LLC earns 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 million of non-recourse
financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the spar. On
December 31, 2006, $33.2 million of the financing was outstanding. The balance of Medusa Spar LLC is
owned by Oceaneering International, Inc. and Murphy. We are accounting for its 10% ownership interest
in the LLC under the equity method.
34
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, 2006.
Production:
Oil (MBbls)
Gas (MMcf)
Total production (MMcfe)
Average daily production (MMcfe)
Average sales price:
Oil (per Bbl) (a)
Gas (per Mcf)
Total (per Mcfe)
December 31, .
2006 2005 2004 .
1,634
10,977
20,780
56.9
1,837
7,768
18,787
51.5
1,736
11,387
21,801
59.6
$ 57.33
$ 8.07
$ 8.77
$ 41.61
$ 8.35
$ 7.52
$ 28.71
$ 6.15
$ 5.50
Oil and gas revenues (in thousands):
Oil revenue
$ 49,826
Gas revenue 88,603 64,865 69,976
$119,802
Total
$182,268
$141,290
$ 93,665
$ 76,425
Lease operating expenses (in thousands)
$ 28,881
$ 24,377
$ 22,308
Additional per Mcfe data:
Sales price
$ 5.50
Lease operating expenses 1.39 1.30 1.02
$ 4.48
Operating margin
$ 7.38
$ 7.52
$ 8.77
$ 6.22
Depletion
General and administrative (net of management fees)
$ 3.14
$ .41
$ 2.39
$ .43
$ 2.18
$ .40
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
$ 41.38
Average NYMEX oil price
Basis differential and quality adjustments (7.03) (8.45) (4.60)
Transportation (1.25) (1.26)
(1.27)
Hedging (0.61) (5.25) (6.80)
$ 28.71
Average realized oil price
$ 57.33
$ 56.57
$ 66.22
$ 41.61
35
Comparison of Results of Operations for the Years Ended December 31, 2006 and 2005
Oil and Gas Revenues
Total oil and gas revenues increased 29% from $141.3 million in 2005 to $182.3 million in 2006 primarily
due to higher gas production and oil pricing. Total production for 2006 increased by 11% versus 2005, which
was impacted by downtime for inclement weather.
Gas production during 2006 totaled 11.0 Bcf and generated $88.6 million in revenues compared to 7.8 Bcf
and $64.9 million in revenues during the same period in 2005. Average gas prices realized for 2006 were
$8.07 per Mcf compared to $8.35 per Mcf during the same period in 2005. The increase in production was
primarily due to production from our new wells at East Cameron Block 90, North Padre Island Block 913,
High Island Block 73, Brazos Block 405, West Cameron Block 295, High Island 165 and West Cameron
3/LA and 2005 production being negatively impacted by inclement weather. The increase in production from
new properties was partially offset by normal and expected declines in production from our Habanero, High
Island Block 119 and Mobile Bay area fields and older properties.
Oil production during 2006 totaled 1,634,000 barrels and generated $93.7 million in revenues compared to
1,837,000 barrels and $76.4 million in revenues for the same period in 2005. Average oil prices realized in
2006 were $57.33 per barrel compared to $41.61 per barrel in 2005. Oil production decreased during 2006
primarily due to a normal and expected decline at Habanero. See the Results of Operations table for a
reconciliation of the realized oil prices to average NYMEX.
Lease Operating Expenses
Lease operating expenses for 2006 increased by 18% to $28.9 million compared to $24.4 million for the same
period in 2005. The increase was primarily due to new wells coming on line, higher costs for fuel and marine
transportation and an increase in insurance rates for our policies which were renewed on April 1, 2006. In
addition, we incurred approximately $1.5 million for pipeline repairs at our South Marsh Island Block 261
field and had downhole repairs at our Medusa field.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 2006 and 2005 was $65.3 million and $44.9 million,
respectively. The 45% increase was due to higher production volumes and a higher average depletion rate for
2006 compared to 2005. The higher rate is primarily attributable to an increase in finding costs, estimated
costs of future development and capitalized asset retirement costs.
Accretion Expense
Accretion expense for 2006 and 2005 of $5.0 million and $3.5 million, respectively, represents accretion
of our asset retirement obligations. The increase was due to the addition of plugging and abandonment
obligations associated with new discoveries and an increase in plugging and abandonment cost estimates.
See Note 10 to the Consolidated Financial Statements.
36
General and Administrative
General and administrative expenses for 2006, net of amounts capitalized, were $8.6 million compared to $8.1
million in 2005. The $500,000 (6%) increase in general and administrative expenses was due to increased
overall cost. We recognized non-cash charges of approximately $1.1 million in the third quarter of 2006 for
the vesting of 20% of restricted shares granted in August 2006. General and administrative expenses for 2005
included non-cash charges of $930,000 recognized in the second quarter of 2005 for the accelerated vesting of
performance shares pursuant to the terms of the plan due to deaths or disability for an executive officer and
two directors of the Company. See Note 3 for more details.
Interest Expense
Interest expense was relatively consistent in 2006 in the amount of $16.5 million compared to $16.7
million in 2005.
Income Taxes
For 2006, we had income tax expense of $20.7 million compared to $13.2 million in 2005. The 57%
increase was due to an increase in income before income taxes.
37
Comparison of Results of Operations for the Years Ended December 31, 2005 and 2004
Oil and Gas Revenues
Total oil and gas revenues increased 18% from $119.8 million in 2004 to $141.3 million in 2005 primarily
due to increased pricing. Total production for 2005 decreased by 14% as compared to 2004 as a result of
downtime associated with the tropical storm and hurricane activity in 2005.
Gas production during 2005 totaled 7.8 Bcf and generated $64.9 million in revenues compared to 11.4 Bcf
and $70.0 million in revenues during the same period in 2004. Average gas prices realized for 2005 were
$8.35 per Mcf compared to $6.15 per Mcf during the same period last year. The decrease in production was
primarily due to significant downtime related to tropical storm and hurricane activity and the normal and
expected decline in production from our Mobile area fields and older properties.
Oil production during 2005 totaled 1,837,000 barrels and generated $76.4 million in revenues compared to
1,736,000 barrels and $49.8 million in revenues for the same period in 2004. Average oil prices realized in
2005 were $41.61 per barrel compared to $28.71 per barrel in 2004. Oil production increased during 2005
despite significant downtime resulting from tropical storms and hurricanes. The increase was primarily
attributable to our deepwater property Medusa which began production in 2003 from a single well with five
others being brought online during 2004 and all six producing during 2005. In addition, our North Medusa
discovery was completed and initial production commenced through the field facilities in April 2005. See the
Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.
Lease Operating Expenses
Lease operating expenses for 2005 increased by 9% to $24.4 million compared to $22.3 million for the same
period in 2004. The increase was primarily due to lease operating expenses related to our deepwater
discovery Medusa, which had higher throughput charges as a result of higher production rates and the
addition of our High Island Block 119 field, which began producing late in the third quarter of 2004.
In addition, lease operating expenses for 2005 included the cost of repairs to our properties for damages
caused by tropical storms and hurricanes in the net amount of $1.2 million. This amount includes the
deductibles and an estimate of repairs not expected to be reimbursed by our property insurance carrier.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 2005 and 2004 were $44.9 million and $47.5 million,
respectively. The 5% decrease was primarily due to lower production volumes for 2005 compared to 2004.
The decrease was partially offset by a higher average depletion rate.
Accretion Expense
Accretion expense for 2005 and 2004 of $3.5 million and $3.4 million, respectively, represents accretion
of our asset retirement obligations. See Note 10 to the Consolidated Financial Statements.
38
General and Administrative
General and administrative expenses for 2005, net of amounts capitalized, were $8.1 million compared to $8.8
million in 2004. Expenses for 2004 included a $2.6 million charge that was incurred in the first quarter of
2004 for the early retirement of two executive officers of the Company. Expenses for 2005 included a
$930,000 non-cash charge for the accelerated vesting of performance shares pursuant to the terms of the plan
due to deaths or disability for an executive officer and two directors of the Company. Expenses for 2005 also
increased due to a reduction in the amount of overhead which was capitalized.
Interest Expense
Interest expense decreased by 17% in 2005 to $16.7 million compared to $20.1 million in 2004. This
decrease is primarily attributable to an equity offering completed in the second quarter of 2004 in which a
portion of the proceeds were used to redeem $33 million of 11% Senior Subordinated Notes .
Loss on Early Extinguishment of Debt
A loss on early extinguishment of debt of $3.0 million was recognized in 2004 for the write-off of
deferred financing costs and bond discounts as well as pre-payment premiums associated with the early
extinguishment of debt.
Income Taxes
For 2005, we had an income tax expense of $13.2 million compared to an income tax benefit of $6.7
million in 2004. The income tax benefit for 2004 resulted primarily from the reversal of the valuation
allowance established in 2003 against our deferred tax asset. As a result of production from the
Company’s first two deepwater projects starting in November 2003, as well as refinancing our highest
cost debt in 2004, we achieved profitable operations and had income on an aggregate basis for the three-
year period ended December 31, 2004. As a result, we reversed the valuation allowance as of December
31, 2004. See Note 5 to our Consolidated Financial Statements for a more detailed discussion.
39
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. The prices
for oil and gas remain extremely volatile and sometimes experience large fluctuations as a result of
relatively small changes in supply, weather conditions, economic conditions and government actions.
From time to time, the Company enters into derivative financial instruments to manage oil and gas price
risk.
The Company may utilize fixed price “swaps”, which reduce the Company's exposure to decreases in
commodity prices and limit the benefit the Company might otherwise have received from any increases in
commodity prices.
The Company may utilize price "collars" to reduce the risk of changes in oil and gas prices. Under these
arrangements, no payments are due by either party as long as the market price is above the floor price and
below the ceiling price set in the collar. If the price falls below the floor, the counter-party to the collar
pays the difference to the Company, and if the price rises above the ceiling, the counter-party receives the
difference from the Company.
Callon may purchase “puts” which reduce the Company’s exposure to decreases in oil and gas prices
while allowing realization of the full benefit from any increases in oil and gas prices. If the price falls
below the floor, the counter-party pays the difference to the Company.
The Company enters into these various agreements from time to time to reduce the effects of volatile oil
and gas prices and does not enter into derivative transactions for speculative purposes. However, certain
of the Company’s derivative positions may not be designated as hedges for accounting purposes. See
Note 8 to the Consolidated Financial Statements for a description of the Company’s hedged position at
December 31, 2006. There have been no significant changes in market risks faced by the Company since
the end of 2005.
Based on projected annual sales volumes for 2007 (excluding incremental production from 2007
exploratory drilling), a 10% decline in the prices Callon receives for its crude oil and natural gas
production would have an approximate $12 million impact on our revenues.
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2006
and 2005
Consolidated Statements of Operations for Each of the Three Years
in the Period Ended December 31, 2006
Consolidated Statements of Stockholders' Equity
for Each of the Three Years in the Period Ended December 31, 2006
Consolidated Statements of Cash Flows for Each of the Three Years
in the Period Ended December 31, 2006
Notes to Consolidated Financial Statements
Page
42
43
44
45
46
47
41
Report of Independent Registered Public Accounting Firm
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, 2006 and 2005, and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 2006. 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 the standards of the Public Company Accounting Oversight
Board (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, 2006 and 2005, and the
consolidated results of its operations and its cash flows for each of the three years in the period ended
December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of
accounting for stock-based compensation.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of Callon Petroleum Company’s internal control over financial
reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated March 15, 2007, expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 15, 2007
42
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Deferred tax asset
Restricted investments
Fair market value of derivatives
Other current assets
Total current assets
Oil and gas properties, full-cost accounting method:
Evaluated properties
Less accumulated depreciation, depletion and amortization
Unevaluated properties excluded from amortization
Total oil and gas properties
Other property and equipment, net
Long-term gas balancing receivable
Restricted investments
Investment in Medusa Spar LLC
Other assets, net
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Fair market value of derivatives
Undistributed oil and gas revenues
Asset retirement obligations
Current maturities of long-term debt
Total current liabilities
Long-term debt
Asset retirement obligations
Deferred tax liability
Accrued liabilities to be refinanced
Other long-term liabilities
Total liabilities
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares authorized;
Common Stock, $.01 par value; 30,000,000 shares
authorized; 20,747,773 shares and 19,357,138 shares issued and
outstanding at December 31, 2006 and 2005, respectively
Unearned compensation-restricted stock
Capital in excess of par value
Other comprehensive income (loss)
Retained earnings
Total stockholders' equity
Total liabilities and stockholders' equity
December 31,
2006
2005
$ 1,896
32,166
--
4,306
13,311
5,973
57,652
$ 2,565
33,195
26,770
4,110
889
1,998
69,527
1,096,907
(604,682 )
492,225
937,698
(539,399 )
398,299
54,802
547,027
1,996
714
1,935
12,580
3,623
$ 625,527
$ 43,086
--
3,525
14,355
213
61,179
225,521
26,824
30,054
--
586
344,164
49,065
447,364
1,605
403
1,858
11,389
1,630
$ 533,776
$ 39,323
1,247
721
21,660
263
63,214
188,813
16,613
31,633
5,000
455
305,728
--
--
207
--
220,785
8,652
51,719
281,363
$ 625,527
194
(3,334 )
220,360
(331 )
11,159
228,048
$ 533,776
The accompanying notes are an integral part of these financial statements.
43
Callon Petroleum Company
Consolidated Statements of Operations
For the Years Ended December 31, 2006, 2005 and 2004
(In thousands, except per share amounts)
Operating revenues:
Oil sales
Gas sales
Total operating revenues
Operating expenses:
Lease operating expenses
Depreciation, depletion and amortization
General and administrative
Accretion expense
Derivative expense
Total operating expenses
2006
2005
2004
$ 93,665
88,603
182,268
$ 76,425
64,865
141,290
$ 49,826
69,976
119,802
28,881
65,283
8,591
4,960
150
107,865
24,377
44,946
8,085
3,549
6,028
86,985
22,308
47,453
8,758
3,400
1,371
83,290
Income from operations
74,403
54,305
36,512
Other (income) expenses:
Interest expense
Other (income)
Loss on early extinguishment of debt
Total other (income) expenses
Income before income taxes
Income tax expense (benefit)
16,480
(1,869)
--
14,611
16,660
(998)
--
15,662
20,137
(357)
3,004
22,784
59,792
20,707
38,643
13,209
13,728
(6,697)
Income before equity in earnings of Medusa Spar LLC
Equity in earnings of Medusa Spar LLC, net of tax
39,085
1,475
25,434
1,342
20,425
1,076
Net income
Preferred stock dividends
Net income available to common shares
Net income per common share:
Basic
Diluted
40,560
--
$ 40,560
26,776
318
$ 26,458
21,501
1,272
$ 20,229
$ 2.00
$ 1.90
$ 1.43
$ 1.28
$ 1.28
$ 1.22
Shares used in computing net income per share amounts:
Basic
Diluted
20,270
21,363
18,453
20,883
15,796
17,678
The accompanying notes are an integral part of these financial statements.
44
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Unearned
Restricted
Total
Capital in Other Retained Stock-
Accumulated
Preferred Common
Stock Excess of Comprehensive Earnings holders’
Stock Stock Compensation Par Value Income (Loss) (Deficit) Equity
Balances, December 31, 2003 $ 6
$ 139
$ (372)
$ 169,036
$ (20)
$ (35,528) $ 133,261
Comprehensive income (loss):
Net income --
Other comprehensive (loss) --
Total comprehensive income
Preferred stock dividend --
Sale of common stock --
Shares issued pursuant to employee
benefit and option plan --
Employee stock purchase plan --
Tax benefits related to stock
compensation plans --
Restricted stock --
--
--
--
35
1
1
--
--
--
--
--
--
--
--
--
(1,863)
21,501
--
--
44,012
720
208
--
--
--
--
(1,272)
--
19,638
(1,272)
44,047
--
--
721
209
--
--
--
(4,980)
1,214
5,474
--
--
--
--
1,214
494
Balances, December 31, 2004 6
176 (5,352)
220,664
(1,883)
(15,299) 198,312
--
--
--
--
Comprehensive income:
Net income --
Other comprehensive income --
Total comprehensive income
Preferred stock dividend --
Conversion of preferred shares
to common stock (6)
Shares issued pursuant to employee
benefit and option plan --
Employee stock purchase plan --
Tax benefits related to stock
1,029
--
compensation plans --
Restricted stock -- 2
1,690
Warrants -- 2 -- (2) -- -- --
1,029
(330)
--
--
--
--
--
2,018
28,328
(318)
--
1,552
(324)
(33)
(325)
(33)
26,776
(643)
(318)
(636)
--
--
--
--
--
--
--
--
--
1
--
13
--
--
--
--
--
--
--
Balances, December 31, 2005 --
194 (3,334)
220,360
(331) 11,159 228,048
--
--
Comprehensive income:
Net income --
Other comprehensive income --
Total comprehensive income
Shares issued pursuant to employee
benefit and option plan --
Tax benefits related to stock
--
compensation plans --
Adoption of 123R
3,334
Restricted stock -- 1 --
Warrants --
10 --
--
--
--
--
2
--
--
--
8,983
40,560
--
49,543
(441)
--
--
(439)
1,356
(3,334)
2,854
(10)
--
--
--
--
--
--
--
--
1,356
--
2,855
--
Balances, December 31, 2006 $ --
$ 207 $ --
$ 220,785
$ 8,652 $ 51,719 $ 281,363
The accompanying notes are an integral part of these financial statements.
45
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2006, 2005 and 2004
(In thousands)
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion and amortization
Accretion expense
Amortization of deferred financing costs
Non-cash loss on extinguishment of debt
Equity in earnings of Medusa Spar, LLC
Non-cash derivative expense
Deferred income tax expense (benefit)
Non-cash charge related to compensation plans
Excess tax benefits from share-based payment arrangements
Changes in current assets and liabilities:
Accounts receivable
Other current assets
Current liabilities
Change in gas balancing receivable
Change in gas balancing payable
Change in other long-term liabilities
Change in other assets, net
Cash provided by operating activities
Cash flows from investing activities:
Capital expenditures
Distribution from Medusa Spar, LLC
Cash used by investing activities
Cash flows from financing activities:
Change in accrued liabilities to be refinanced
Increases in debt
Payments on debt
Restricted cash
Debt issuance cost
Issuance of common stock
Buyout of preferred stock
Equity issued related to employee stock plans
Excess tax benefits from share-based payment arrangements
Capital leases
Cash dividends on preferred stock
Cash provided (used) by financing activities
2006
2005
2004
$ 40,560
$ 26,776
$ 21,501
65,929
4,960
2,221
--
(1,475)
150
20,707
1,420
(1,449)
45,657
3,549
2,062
--
(1,342)
1,635
13,209
1,906
--
48,164
3,400
1,929
2,910
(1,076)
(135)
(6,697)
1,225
--
(2,107)
(3,975)
11,311
(311)
133
(2)
(2,588)
135,484
(11,169)
670
(8,666)
322
(289)
(18)
(292)
74,010
(4,495)
971
2,903
376
400
(20)
(448)
70,908
(167,979)
1,078
(166,901)
(73,072)
463
(72,609)
(64,649)
339
(64,310)
(5,000)
88,000
(53,000)
--
--
--
--
(438)
1,449
(263)
--
30,748
5,000
7,000
(12,000)
--
--
2
(637)
(573)
--
(576)
(318)
(2,102)
--
90,000
(205,915)
63,345
(984)
44,047
--
199
--
(1,452)
(1,272)
(12,032)
Net decrease in cash and cash equivalents
(669)
(701)
(5,434)
Cash and cash equivalents:
Balance, beginning of period
Balance, end of period
2,565
3,266
8,700
$ 1 ,896
$ 2,565
$ 3,266
The accompanying notes are an integral part of these financial statements.
46
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 9.
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 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 U.S. 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.
Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with Statement of Financial Accounting
Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which 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. Interest is accreted on the present
value of the asset retirement obligation and reported as accretion expense within operating expenses in the
Consolidated Statements of Operations. See Note 10.
47
Oil and Gas Properties
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. 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 ($9.6 million in 2006, $7.1 million in 2005 and $7.2
million in 2004) 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 oil and gas properties, including future development and future site restoration, dismantlement and
abandonment costs, which have proved reserves and properties 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 discounted at
10% and (2) the lower of cost or market of unevaluated properties, net of tax effects (the full-cost ceiling
amount), then such excess is charged to expense during the period in which the excess occurs. See Note 11.
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. In accordance
with SFAS 143, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In
accordance with Staff Accounting Bulletin No. 106, assets recorded in connection with the recognition of an
asset retirement obligation pursuant to SFAS 143 are included as part of the costs subject to the full-cost
ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations
are excluded from the computation of the present value of estimated future net revenues used in applying the
ceiling test.
Property and Equipment
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. Depreciation expense of $351,000, $355,000 and $346,000 relating
to other property and equipment was included in general and administrative expenses in the Company’s
statements of operations for the years ended December 31, 2006, 2005 and 2004, respectively. The
accumulated depreciation on other property and equipment was $10.8 million and $10.6 million as of
December 31, 2006 and 2005, respectively.
48
Investment in Medusa Spar LLC
The Company has a 10% ownership interest in Medusa Spar, LLC (“LLC”), which is a limited liability
company that owns a 75% undivided ownership interest in the deepwater spar production facilities on
Callon’s Medusa Field in the Gulf of Mexico. The Company 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. The LLC earns a tariff based upon production volume throughput from the
Medusa area. Callon is obligated to process its share of production from the Medusa Field and any future
discoveries in the area through the spar production facilities. This arrangement allows Callon to defer the
cost of the spar production facility over the life of the Medusa Field. The Company’s cash proceeds were
used to reduce the balance outstanding under its senior secured credit facility. The LLC used the cash
proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the LLC owners
to acquire its 75% interest in the spar. On December 31, 2006, $33.2 million of the financing was
outstanding. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII)
and Murphy Oil Corporation (NYSE:MUR). The Company is accounting for its 10% ownership interest
in the LLC under the equity method.
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 recording
a liability to the extent that a well is in an "overtake" position. Gas balancing receivables were $714,000 and
$403,000 as of December 31, 2006 and 2005, respectively. Gas balancing payables were $437,000 and
$304,000 as of December 31, 2006 and 2005, respectively.
Derivatives
The Company periodically uses derivative financial instruments to manage oil and gas price risk on a limited
amount of its future production and does not use these instruments for trading purposes. Settlement of
derivative contracts are generally based on the difference between the contract price or prices specified in the
derivative instrument and a NYMEX price or other cash or futures index price. Such derivatives are
accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (“SFAS 133”) as amended.
The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded
at fair market value and the changes in fair value are recorded through other comprehensive income (loss), net
of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease
in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as
derivative expense (income). The cash settlement on these contracts is also recorded within derivative
expense (income). The changes in fair value of the Company’s derivative contracts that are not designated as
effective cash flow hedges are recorded through the statement of operations as derivative expense (income).
See Note 8.
Income Tax
The Company follows the asset and liability method of accounting for deferred income taxes prescribed by
Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). SFAS
109 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
49
valuation allowance. The valuation allowance is provided for that portion of the asset for which it is deemed
more likely than not will not be realized. See Note 5.
Stock-Based Compensation
Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123
(revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified prospective transition
method. Prior to the adoption of SFAS 123R, the Company accounted for stock option grants in accordance
with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic
value method) and, accordingly, recognized no compensation expense for stock option grants.
Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards as of
January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified,
repurchased or cancelled. Under the modified prospective transition method, compensation cost recognized
in 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of
January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of
Statement of Financial Accounting Standard No. 123 “Accounting for Stock-Based Compensation,” (“SFAS
123”) and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on
the grant-date fair value estimated in accordance with the provisions of SFAS 123R. Prior periods were not
restated to reflect the impact of adopting the new standard.
SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of compensation
cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. The
$1.4 million of excess tax benefits classified as a financing cash inflow for the year ended December 31, 2006
would have been classified as an operating cash flow had the Company not adopted SFAS 123R. There were
no cash proceeds from the exercise of stock options for the year ended December 31, 2006 due to the fact that
all options were exercised through net-share settlements. As a result of most of the Company’s stock-based
compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on income
before taxes, net income and basic and diluted earnings per share for the year ended December 31, 2006 was
not significant. See Note 3.
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 $66,000 at both December 31, 2006
and 2005, respectively. There were no net charge offs recorded against the reserve for doubtful accounts
and no provisions to expense in the three-year period ended December 31, 2006.
Accrued Liabilities to be Refinanced
Amounts included in accrued liabilities to be refinanced at December 31, 2005 represent capital expenditures
that were refinanced with the availability under the Company’s senior secured credit facility subsequent to
December 31, 2005.
50
Major Customers
The Company’s production is generally sold 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 years ended:
Shell Trading Company
Louis Dreyfus Energy Services
Plains Marketing, L.P.
Chevron Texaco Natural Gas
December 31,______
2004
30%
23%
13%
6%
2006
41%
25%
11%
3%
2005
34%
16%
16%
10%
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
with an original maturity of three months or less to be cash equivalents.
The Company paid no federal income taxes for the three years in the period ended December 31, 2006.
During the years ended December 31, 2006, 2005 and 2004, the Company made cash payments for
interest of $20,468,000, $19,854,000 and $23,197,000, respectively.
Fair Value of Financial Instruments
Fair value of cash and cash equivalents, accounts receivable, accounts payable, the capital lease and the senior
secured credit facility approximates book value at December 31, 2006 and 2005. The Company’s 9.75%
Senior Notes due 2010 had an estimated fair value of 101.5% and 103% of face value at December 31, 2006
and 2005, respectively.
Accounting Pronouncements
In June 2006, the Financial Accounting Standards Board (“FASB”) released interpretation No. 48,
Accounting for Uncertainty in Income Taxes, (“FIN 48”). FIN 48 clarifies the accounting for income taxes
by prescribing the minimum recognition threshold a tax position must meet before being recognized in the
financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest
and penalties, accounting in interim periods, disclosure and transition. The effective date for FIN 48 is fiscal
years beginning after December 15, 2006. The Company is currently reviewing the provisions of FIN 48 and
has not yet determined the impact of adoption.
In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, Fair Value
Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value
and requires enhanced disclosures about fair value measurements. SFAS 157 is effective for fiscal years
beginning after November 15, 2007 and interim periods within those fiscal years. The Company is still
reviewing the provisions of SFAS 157 and has not yet determined the impact of adoption.
51
3. STOCK-BASED COMPENSATION
The Company has various stock plans (“Plans”) under which employees of the Company and its subsidiaries
and non-employee members of the Board of Directors of the Company have been or may be granted certain
stock-based compensation. For further discussion of the Plans, refer to Note 12.
For the year ended December 31, 2006, the Company recorded stock-based compensation expense of $3.5
million, of which $1.8 million was included in general and administrative expenses and $1.7 million was
capitalized to oil and gas properties. Shares available for future stock option or restricted stock grants to
employees and directors under existing plans were 490,666 at December 31, 2006.
The following table illustrates the effect on operating results and net income per share had the Company
accounted for stock-based compensation in accordance with SFAS 123 for the years ended December 31,
2005 and 2004:
Net income available to common shares,
as reported
Stock-based compensation expense included
in net income as reported, net of tax
Deduct: Total stock-based
compensation expense under fair
value based method, net of tax
Pro forma net income available to
common shares
Basic net income per share:
As Reported
Pro Forma
Diluted net income per share: As Reported
Pro Forma
Stock Options
2005
2004
(In thousands, except per share data)
$ 26,458
$ 20,229
1,313
348
(1,497) (549)
$ 26,274
$ 20,028
1.43
1.42
1.28
1.27
1.28
1.27
1.22
1.20
The Company uses the Black-Scholes option pricing model to estimate the fair value of stock option awards
with the following weighted-average assumptions for the indicated periods.
2004_
For the Years Ended
December 31,
2005_
--
37.5%
4.3%
5
$ 5.93
--
2006_
--
38.9%
4.6%
5
$ 7.72
7.5%
--
45.1%
3.7%
5
$ 5.48
--
Dividend yield
Expected volatility
Risk-free interest rate
Expected life of option (in years)
Weighted-average grant-date fair value
Forfeiture rate
52
The assumptions above are based on multiple factors, including historical exercise patterns of employees with
respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns
and the historical volatility of the Company’s stock price.
The following table represents stock option activity for the three years ended December 31, 2006:
2006
Wtd Avg
Shares Ex Price
1,205,558 $ 10.11
18.69
15,000
10.66
(480,333)
--
--
--
--
740,225 $ 9.93
695,225 $ 9.44
Outstanding, beginning of year
Granted (at market)
Exercised
Forfeited
Expired
Outstanding, end of year
Exercisable, end of year
Weighted-average remaining
Contract life:
Outstanding options at end of period 4.06 yrs. 3.98 yrs.
Outstanding exercisable at end of period 3.76 yrs.
2005
Wtd Avg
Shares Ex Price
1,512,599 $ 9.93
15.79
65,000
10.34
(329,441)
--
--
10.60
(42,600)
1,205,558 $ 10.11
1,166,558 $ 9.88
2004
Wtd Avg
Ex Price
$ 9.84
12.40
9.74
9.80
--
$ 9.93
$ 10.20
Shares
2,450,867
25,000
(437,918)
(525,350)
--
1,512,599
1,446,486
4.48 yrs.
3.79 yrs. 4.34 yrs.
The aggregate intrinsic value of options outstanding was $3.9 million and the aggregate intrinsic value of
options exercisable was $3.9 million. Total intrinsic value of options exercised was $4.1 million for the year
ended December 31, 2006. At December 31, 2006, there was $231,000 of unrecognized compensation cost
related to nonvested stock options, which is expected to be recognized over a weighted-average period of two
years.
53
Restricted Stock
The Plans allow for the issuance of restricted stock awards. The unearned stock-based compensation related
to these awards is being amortized to compensation expense on a straight-line basis over the requisite service
period for the entire award. The compensation expense for these awards was determined based on the market
price of our stock at the date of grant applied to the total numbers of shares that were anticipated to fully vest.
As of December 31, 2006, there was $9.1 million of unrecognized compensation cost associated with these
awards, which is expected to be recognized over a weighted average period of 3.3 years.
The following table represents unvested restricted stock activity for the year ended December 31, 2006:
Outstanding shares at beginning of period
Granted
Vested
Forfeited
272,000
582,500
(191,500)
(4,200)
Weighted-Average
Number of
Shares
Grant-Date
Fair Value
$ 13.66
15.77
15.02
13.82
Outstanding shares at end of period
658,800
$ 15.13
For the years ended December 31, 2006, 2005 and 2004 the Company recognized non-cash compensation
expense associated with the restricted stock awards of $3.4 million, $2.0 million and $906,000,
respectively. Included in 2005 was $1.0 million of accelerated vesting of performance shares pursuant to
the terms of the plan due to the deaths or disability for an executive officer and two directors of the
Company. There were no restricted stock grants during the year ended December 31, 2005 and the
weighted average grant-date fair value of restricted stock granted during the year ended December 31,
2004 was $13.69.
54
4. NET INCOME PER SHARE
Basic net income per common share was computed by dividing net income by the weighted average number
of shares of common stock outstanding during the year. Diluted net income 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).
A reconciliation of the basic and diluted net income per share computation is as follows (in thousands,
except per share amounts):
2006
2005
2004
(a) Net income available to common shares
Preferred dividends assuming conversion of
preferred stock (if dilutive) -- 318 1,272
(b) Net income available to common shares assum-
ing conversion of preferred stock (if dilutive)
$ 40,560
$ 40,560
$ 26,458
$ 26,776
$ 21,501
$ 20,229
(c) Weighted average shares outstanding
Dilutive impact of stock options
Dilutive impact of restricted stock
Dilutive impact of warrants
Convertible preferred stock (if dilutive)
(d) Weighted average shares outstanding for diluted
20,270
238
78
777
18,453
348
69
1,375
15,796
233
75
894
638 680
--
net income per share
21,363
20,883
17,678
Stock options and warrants excluded due to the
exercise price being greater than the stock price
Basic net income per share (a(cid:121)c)
Diluted net income per share (b(cid:121)d)
28
$ 2.00
$ 1.90
1
$ 1.43
$ 1.28
89
$ 1.28
$ 1.22
55
5. INCOME TAXES
Below is an analysis of the net deferred tax liability as of December 31, 2006 and 2005.
December 31,____
2006
2005
(In thousands)
Deferred Tax Asset:
$ 58,240
Federal net operating loss carryforwards
4,443
Statutory depletion carryforward
547
Alternative minimum tax credit carryforward
Asset retirement obligations 12,228 11,307
1,389
Other
$ 58,051
4,651
332
2,443
Total deferred tax asset 77,705 75,926
Deferred Tax Liability:
(80,565)
Oil and gas properties
Other (5,838) (224)
(80,789)
Total deferred tax liability
(107,759)
(101,921)
Net deferred tax liability
$ (30,054)
$ (4,863)
If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through 2021. The
Company has significant state net operating loss carryforwards that are not included in the deferred tax asset
above, as the Company does not anticipate generating taxable state income in the states in which these loss
carryforwards apply. The Company has very limited state taxable income as primarily all of its revenue is
generated in federal waters not subject to state income taxes.
The Company incurred losses in 2002 and 2003 and had losses on an aggregate basis for the three-year
period ended December 31, 2003. Because of these cumulative losses the Company established a full
valuation allowance of $11.5 million as of December 31, 2003. For the three-year period ended
December 31, 2004, the Company had income on an aggregate basis resulting from the Company
achieving profitable operations in 2004 due to the Company’s first two deepwater projects starting in
November 2003 and the refinancing of the Company’s highest cost debt. As a result, the Company
reversed the valuation allowance, which had a balance of $7.0 million, as of December 31, 2004.
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.
Income tax expense computed at the statutory
federal income tax rate
Change in valuation allowance
Other
Effective income tax rate
Years Ended December 31,_
2004_
2005_
2006_
35%
--
--
35%
35%
--
(1)%
35%
(84)%
--
34%
(49)%
56
6. OTHER COMPREHENSIVE INCOME
The Company’s other comprehensive income (loss) of $9.0 million, $1.6 million and $(1.9) million for the
years ended December 31, 2006, 2005 and 2004 respectively, relates to the change in fair value of its
derivatives. Other comprehensive income (loss) was net of income tax expense (benefit) of $4.7 million,
$835,000 and ($1.0) million for the years ended December 31, 2006, 2005 and 2004, respectively.
7. LONG-TERM DEBT
Long-term debt consisted of the following at:
Senior secured credit facility
9.75% Senior Notes (due 2010) net of discount
Capital lease
Total long-term debt
Less current portion
Long-term portion
December 31,____
2005__
2006 _
(In thousands)
$ 35,000
189,862
872
225,734
213
$225,521
$ --
187,941
1,135
189,076
263
$188,813
Senior Secured Credit Facility. On August 30, 2006, the Company closed on a four-year amended and
restated senior secured credit facility underwritten by Union Bank of California, N.A. The initial
borrowing base is $75 million, which will be reviewed and redetermined semi-annually and can be
increased to a maximum of $175 million. Borrowings under the credit facility are secured by mortgages
covering the Company’s major producing fields. As of December 31, 2006 there was $35 million
outstanding under the facility with a weighted average interest rate of 6.73% and $40 million was
available for future borrowings. In connection with the anticipated financing of the acquisition of BP’s
interest in the Entrada Field, the borrowing base under this facility would be reduced to $50 million at
closing until the next borrowing base redetermination date. See Note 14 for more discussion on the
Entrada acquisition.
The credit facility bears interest at 0% to 0.50% above a defined base rate depending on utilization of the
borrowing base or, at the option of the Company, LIBOR plus 1.375% to 2.0% based on utilization of the
borrowing base. 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. The
range of interest rates on the senior secured credit facility during 2006 was 6.24% to 8.50%.
9.75% Senior Notes (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. In conjunction with the new senior unsecured notes, the Company issued detachable
warrants to purchase 2.775 million shares of its common stock at an exercise price of $10 per share and an
expiration date of December 2010. The warrants were valued at $10.6 million and were treated as a 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 are being amortized over the life of the notes.
57
During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured credit
facility bringing the total outstanding under the facility to $200 million. The net proceeds of
approximately $14 million were primarily used to retire the remaining $10 million of 12% senior loans
due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of these
additional new securities at a fair value of $14 million. Deferred costs of $1 million associated with the
notes are being amortized over the life of the notes.
In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, (“Series A
notes”), issued pursuant to a senior indenture between Callon and American Stock Transfer & Trust
Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to exchange its
9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933, for all
outstanding Series A notes.
As of December 31, 2006, 1.617 million of the 2.775 million detachable warrants issued with the 9.75%
Senior Notes due 2010 were exercised. In addition, 265,210 of the $0.01 warrants associated with the
12% senior loans, which were redeemed in 2004, were exercised in June 2006.
Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million
9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are full
and unconditional and joint and several, the parent company has no independent assets or operations and
any subsidiaries of the parent company other than the subsidiary guarantors are minor.
Loss on Early Extinguishment of Debt. In the first half of 2004, the Company completed several
transactions that restructured certain debt that was maturing through 2005 resulting in a loss on early
extinguishment of debt for the year ended December 31, 2004 of $3.0 million.
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.
Restrictive Covenants. The Indenture governing our 9.75% senior notes due 2010 and our senior secured
credit facility contains various covenants including restrictions on additional indebtedness and payment of
cash dividends. In addition, our senior secured credit facility contains covenants for maintenance of certain
financial ratios. The Company was in compliance with these covenants at December 31, 2006.
Future minimum lease payments and debt maturities are as follows (in thousands):
Capital Lease
Year
Payments
Debt
2007
2008
2009
2010
Thereafter 245 --
$ 348
228
229
220
$ --
--
--
235,000
58
8. DERIVATIVES
The following table summarizes derivative expense for the periods presented (in thousands):
Amortization of derivative contract premiums
Change in fair value and settlements of ineffective
derivative contracts
Change in fair value and settlements of non-designated
derivative contracts
December 31,
2006
2005
2004
$ 150 $ 1,634
$ --
--
--
4,394
1,209
--
162
$ 150 $ 6,028
$ 1,371
The change in fair value and settlements on ineffective derivative contracts in 2005 and 2004 relate to
contracts that were deemed ineffective as a result of a shortfall in production volumes due to downtime
resulting from damages caused by Hurricanes Katrina and Rita in 2005 and tropical storms and Hurricane
Ivan in 2004. Cash settlements on effective cash flow hedges for the year ended December 31, 2006 resulted
in an increase in oil and gas sales of $8.9 million. For the years ended December 31, 2005 and 2004, cash
settlements on effective cash flow hedges resulted in a reduction in oil and gas sales of $10.3 million and
$13.8 million, respectively.
Listed in the table below are the outstanding derivative contracts as of December 31, 2006:
Collars
Average Average
Volumes per Quantity Floor Ceiling
Product
Month Type Price Price Period
Oil 50,000 Bbls $65.00 $88.75 01/07-12/07
Natural Gas 600,000 MMBtu $ 8.00 $12.70 01/07-12/07
59
9. COMMITMENTS AND CONTINGENCIES
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 SEC for sale to the public in firm
commitment public offerings and generally to include shares owned by them, at no cost, in registration
statements filed by the Company. Costs of the offering will not include broker’s discounts and commissions,
which will be paid by the respective sellers of the common stock.
The Company is involved in various claims and lawsuits incidental to its business. In the opinion of
management, the ultimate liability thereunder, if any, will not have a material adverse effect on the financial
position or results of operations of the Company.
The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
Water Royalty Relief Act. In addition, the Company has several shallow water, deep natural gas
properties and prospects that are eligible for royalty suspensions. However, the federal offshore leases
covering these properties contain “price threshold” provisions for oil and gas prices. Under these “price
threshold” provisions, 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 Company was required to make monthly royalty payments for 2006 deepwater oil and gas production
and will be required to make monthly royalty payments for 2007. With regard to the shallow water, deep
natural gas royalty relief, the Company was not required to make royalty payments for 2006 and will not
be required to make royalty payments for 2007.
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, 2006 excluded oil and gas
reserves for Medusa that are subject to MMS royalties as a result of the average 2006 NYMEX prices for
oil and gas exceeding the deepwater price thresholds. With regard to the shallow water, deep natural gas
properties, there was no reduction in reserves for potential future royalties as of December 31, 2006 as a
result of the average 2006 NYMEX price for gas being below the price threshold.
60
The Company’s Entrada Field is governed by leases from the MMS. These leases granted royalty
suspension without provisions for pricing thresholds for crude oil and natural gas which would require us
to pay royalties to the MMS if the thresholds were exceeded by the current year average of NYMEX
prices. The MMS has notified us the exclusion of the provisions occurred in error in the lease issuance
process and was not the MMS’s intention. Congress is considering various bills to address this issue and
if a bill were to pass to amend the leases to provide thresholds for crude oil and natural gas prices the
reserves for Entrada could be subject to such royalties. However, the MMS stated in their
correspondence to the Company that they will continue to honor the terms of the leases as issued unless
notified otherwise. This correspondence applies only to Callon’s 20% working interest in the Entrada
Field.
The Company’s activities are subject to federal, state and local laws and regulations governing environmental
quality and pollution control. Although no assurances can be made, the Company believes that, absent the
occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and
regulations governing the release of materials into 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.
10. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the activity for the Company’s asset retirement obligations:
December 31, 2006 December 31, 2005
Twelve Months Ended
Asset retirement obligations at beginning of period
Accretion expense
Net profits interest accretion
Liabilities incurred
Liabilities settled
Revisions to estimate
Asset retirement obligation at end of period
Less: current retirement obligations
Long-term retirement obligations
$ 38,273
4,960
--
1,440
(16,970)
13,476
41,179
(14,355)
$ 26,824
$ 38,282
3,549
331
2,365
(5,184)
(1,070)
38,273
(21,660)
$ 16,613
Assets, primarily short-term U.S. Government securities, of approximately $6.2 million at December 31,
2006, of which $4.3 million was current, were recorded as restricted investments. These assets are held in
abandonment trusts (“Trusts”) dedicated to pay future abandonment costs for several of the Company’s
oil and gas properties.
61
11. 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.
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance
Property acquisition costs
Exploration costs
Development costs
Sale of mineral interests
End of period balance
Unevaluated Properties (excluded from
amortization) -
Beginning of period balance
Additions
Capitalized interest
Transfers to evaluated
End of period balance
Accumulated depreciation, depletion
and amortization-
Beginning of period balance
Provision charged to expense
End of period balance
Years Ended December 31,
2006 2005 2004
(In thousands)
$ 937,698
4,053
73,659
81,497
--
$ 1,096,907
$ 862,101
6,627
46,379
22,591
--
$ 937,698
$ 802,912
1,355
26,749
31,086
(1)
$ 862,101
$ 49,065
19,103
6,477
(19,843)
$ 54,802
$ 39,042
18,739
5,655
(14,371)
$ 49,065
$ 34,251
16,367
4,577
(16,153)
$ 39,042
$ 539,399
65,283
$ 604,682
$ 494,453
44,946
$ 539,399
$ 447,000
47,453
$ 494,453
Unevaluated property costs, primarily lease acquisition costs incurred at federal and state lease sales,
unevaluated drilling costs, capitalized interest and general and administrative costs being excluded from
the amortizable evaluated property base, consisted of $24.7 million incurred in 2006, $17.8 million
incurred in 2005, $3.5 million incurred in 2004 and $8.8 million incurred in 2003 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 years.
Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $3.14, $2.39 and
$2.18 for the years ended December 31, 2006, 2005, and 2004, 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 oil and gas properties, net of accumulated
depreciation, depletion and amortization 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%, plus the lower of cost or
fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). 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. However, if prices recover
sufficiently subsequent to the balance sheet date before the release of the financial statements then use of the
subsequent pricing is allowed and no write-down would be required if such pricing was used. Given the
62
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 write-downs of oil and gas properties
could occur in the future.
12. 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:
Savings and Protection Plan
The Savings and Protection Plan (“401-K 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 401-K 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 401-K Plan. The total amounts contributed by the Company, including the
value of the common stock contributed, were $615,000, $557,000 and $528,000 in the years
2006, 2005 and 2004, respectively.
1996 Stock Incentive Plan
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 limited to a maximum of 1,200,000 shares (as
amended from the original 900,000 shares) of common stock subject to outstanding awards.
The 1996 Plan was amended again and approved on May 9, 2000 at the Annual Meeting of
Shareholders, increasing the number of shares reserved for issuance under the 1996 plan to
2,200,000 shares. Unvested options are subject to forfeiture upon certain termination of
employment events and expire 10 years from the date of grant.
In August 2006, the Board of Directors approved the award of 520,000 shares of restricted
stock from the 1996 Plan. Of the 520,000 shares, 20,000 shares were granted to non-employee
members of the Board of Directors and vested immediately. The remaining 500,000 shares
were issued to employees of the Company with 20% vesting immediately and the remaining
80% vesting ratably over the next four years. The compensation cost with respect to the 20%
that vested immediately was recognized as an expense on the grant date and the compensation
cost with respect to the remaining 80% is being amortized to expense over the vesting period.
2002 Stock Incentive Plan
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 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
63
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 2006, 17,500 shares were awarded as restricted stock with 20% vesting immediately and the
remaining 80% vesting ratably over the next four years. The compensation cost with respect to
the 20% that vested immediately was recognized as an expense on the grant date and the
compensation cost with respect to the remaining 80% is being amortized to expense over the
vesting period.
2006 Stock Incentive Plan
On March 9, 2006, the Board of Directors of the Company approved the 2006 Stock Incentive
Plan (“2006 Plan”). The 2006 Plan was approved by the shareholders at the May 4, 2006
annual meeting. Pursuant to the 2006 Plan, 500,000 shares of common stock shall be reserved
for issuance upon exercise of stock options, restricted stock or other stock-based awards. In
2006, 45,000 shares were awarded as restricted stock that will vest ratably over the next four
years. The compensation cost with respect to this grant is being amortized to expense over the
vesting period.
13. EQUITY TRANSACTIONS
On June 13, 2005, Callon called for redemption all of the Company’s outstanding shares of $2.125
Convertible Exchange Preferred Stock, Series A. A notice of redemption and letter of transmittal was mailed
to all holders of record as of the close of business on June 10, 2005. Between June 13, 2005 and June 30,
2005, 180,173 shares of preferred stock were converted into 409,496 shares of the Company’s common stock.
Subsequent to June 30, 2005, 392,935 shares of preferred stock were converted into 893,076 shares of the
Company’s common stock. In addition, 23,563 shares of the Company’s preferred stock were redeemed for
$606,000 on July 14, 2005. As a result of the redemption, we will benefit from an annual cash savings of $1.3
million in dividend payments.
On June 22, 2004, Callon closed the public offering of three million shares of common stock priced at
$13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition, the
Company granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to
purchase an additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment
option for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the offering
by approximately $5.7 million, after expenses. The proceeds from the transactions were used to redeem
$33 million of the 11% Senior Subordinated Notes due December 15, 2005 and for general corporate
purposes.
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
64
(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.
14. SUBSEQUENT EVENTS
Subsequent to December 31, 2006, the Company entered into an agreement with BP Exploration and
Production Company (“BP”) to purchase BP’s 80% working interest in the Entrada Field for total cash
consideration of $190 million. The purchase price includes $150 million payable at closing and an additional
$40 million payable after the achievement of certain production milestones. The purchased interests include
five federal offshore blocks at Garden Banks Blocks 738, 782, 785, 826 and 827, subject to certain depth
limitations. Upon the completion of the acquisition, Callon will own a 100% working interest in the Entrada
Field and will become operator. The acquisition is expected to close within the next 45 days and will add 150
Bcfe to Callon’s proved undeveloped reserves.
To finance the initial $150 million payment of the purchase price, a commitment has been received from
Merrill Lynch Capital Corporation to make available to Callon a 7-year, $200 million revolving credit facility
secured by a lien on the Entrada properties. We plan to borrow the full commitment amount at closing to
cover the required $150 million payment to BP and, expenses and fees, and the balance of the funds can be
used for Entrada development costs or general corporate purposes. In connection with the closing of the
financing of the acquisition of BP’s interest in the Entrada Field, the borrowing base of our senior secured
credit facility will be reduced to $50 million.
15. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 2006, 2005 and 2004 have been estimated by
Huddleston & Co., Inc who are the Company’s independent petroleum consultants. The reserves were
prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates
are based upon existing economic and operating conditions.
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
standardized 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. See
Note 9 regarding the provisions for royalty relief and the effect on reserves.
65
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,
2006
2005
2004
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period
Revisions to previous estimates
Purchase of reserves in place
Extensions and discoveries
Production
End of period
Natural Gas (MMcf):
Beginning of period
Revisions to previous estimates
Purchase of reserves in place
Extensions and discoveries
Production
End of period
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period
End of period
Natural Gas (MMcf):
Beginning of period
End of period
(a) Includes Medusa royalty adjustment
18,428
(3,733)
--
204
(1,634)
13,265
78,021
(15,557)
--
14,550
(10,977)
66,037
19,748
316
71
129
(1,836)
18,428
72,619
(4,946)
1,308
16,808
(7,768)
78,021
(a)
23,709
(2,370)
--
145
(1,736)
19,748
74,691
2,138
--
7,177
(11,387)
72,619
7,323
5,159
10,292
7,323
9,919
10,292
30,982
36,750
33,982
30,982
31,415
33,982
66
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 reflect period-end prices (approximately $5.78 per Mcf
for natural gas and $54.07 per Bbl for oil for the 2006 disclosures, $10.13 per Mcf and $55.44 per Bbl for
2005 disclosures, and $6.51 per Mcf and $36.72 per Bbl for 2004 disclosures) at each date presented with
no escalation. Future production and development 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
Future cash inflows
Future costs -
Production
Development and net abandonment
Future net inflows before income taxes
Future income taxes
Future net cash flows
10% discount factor
Standardized measure of discounted
future net cash flows
Years Ended December 31,
2006
2005 2004
$ 1,101,182
(In thousands)
$1,814,208
(243,740)
(81,700)
775,742
(119,685)
656,057
(185,266)
(238,321)
(88,070)
1,487,817
(379,287)
1,108,530
(270,978)
$1,198,096
(231,616)
(74,335)
892,145
(166,284)
725,861
(209,968)
$ 470,791
$ 837,552
$ 515,893
Changes in Standardized Measure
Years Ended December 31,
2006
2005 2004
Standardized measure – beginning of period
Sales and transfers, net of production costs
Net change in sales and transfer prices,
net of production costs
Exchange and sale of in place reserves
Purchases, extensions, discoveries, and improved
recovery, net of future production and
development costs incurred
Revisions of quantity estimates
Accretion of discount
Net change in income taxes
Changes in production rates, timing and other
Standardized measure - end of period
$ 837,552
(153,387)
(347,193)
--
122,862
(155,342)
108,871
187,209
(129,781)
$ 470,791
(In thousands)
$ 515,893
(116,913)
$ 519,026
(97,494)
391,570
--
86,551
--
127,848
(17,241)
61,259
(154,460)
29,596
$ 837,552
77,576
(41,314)
57,046
(45,262)
(40,236)
$ 515,893
At year-end 2006, a downward revision was made by the Company’s independent petroleum engineers to
Entrada’s estimated net proved reserves as of December 31, 2006 due to new performance data from
analogous deepwater reservoirs.
67
16. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
First Second
Fourth
Quarter Quarter Quarter
Third
Quarter
(In thousands, except per share data)
2006
Total revenues
Income from operations
Net income
Net income per common share-basic
Net income per common share-diluted
$45,581
22,605
12,767
$ 0.66
0.60
$47,057
21,616
12,303
$ 0.61
0.57
$44,878
17,815
9,630
$ 0.47
0.45
$44,752
12,367
5,860
$ 0.28
0.27
First Second Third
Fourth
Quarter
Quarter Quarter(a) Quarter(a)
(In thousands, except per share data)
2005
Total revenues
Income from operations
Net income
Net income per common share-basic
Net income per common share-diluted
$43,012
18,134
9,475
$ 0.52
0.46
$41,668
17,696
9,311
$ 0.52
0.46
$31,722
8,692
3,683
$ 0.19
0.17
$24,888
9,783
4,307
$ 0.22
0.20
(a) These quarters were impacted by tropical storm and hurricane activity.
68
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 9.A 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, have 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 have materially affected, or are reasonable likely to materially affect, our internal control over
financial reporting.
Management’s Report On Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the
participation of our management, including our principal executive and financial officers, we conducted
an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2006
based on the frame work in the Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework
in Internal Control-Integrated Framework, our management concluded that our internal control over
financial reporting was effective as of December 31, 2006.
Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation report
on our management’s assessment of the effectiveness of our internal control over financial reporting
which is included herein.
69
Report of Independent Registered Public Accounting Firm
The Stockholders and Board of Directors
Callon Petroleum Company
We have audited management’s assessment, included in the accompanying Management’s Report on
Internal Control over Financial Reporting, that Callon Petroleum Company maintained effective internal
control over financial reporting as of December 31, 2006, based on criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Callon Petroleum Company’s management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express an opinion on management’s assessment and an
opinion on the effectiveness of the Company’s internal control over financial reporting based on our
audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over financial reporting,
evaluating management’s assessment, testing and evaluating the design and operating effectiveness of
internal control, and performing such other procedures as we considered necessary in the circumstances.
We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could
have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the
risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Callon Petroleum Company maintained effective internal
control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on
criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also, in our opinion, Callon Petroleum Company
maintained, in all material respects, effective internal control over financial reporting as of December 31,
2006, based on the COSO criteria.
70
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December 31,
2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and cash flows
for each of the three years in the period ended December 31, 2006 of Callon Petroleum Company and our
report dated March 15, 2007, expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 15, 2007
71
ITEM 9.B OTHER INFORMATION
We have disclosed all information required to be disclosed in a current report on Form 8-K during the
fourth quarter of the year ended December 31, 2006 in previously filed reports on Form 8-K.
72
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 to be held on May 3, 2007 which will be filed with the
Securities and Exchange Commission and is incorporated herein by reference.
The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief
financial officer and chief accounting officer. The full text of such code of ethics has been posted on the
Company’s website at www.callon.com, and is available free of charge in print to any shareholder who
requests it. Request for copies should be addressed to the Secretary at 200 North Canal Street, Natchez,
Mississippi 39120.
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 to be held on May 3, 2007 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
to be held on May 3, 2007 which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
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 to be held on May 3, 2007 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 to be held on May 3, 2007 which will be filed with the
Securities and Exchange Commission and is incorporated herein by reference.
73
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K
PART IV.
(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 42 through 68.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of the Years Ended December 31, 2006 and 2005
Consolidated Statements of Operations for the Three Years in the Period Ended
December 31, 2006
Consolidated Statements of Stockholders' Equity for the Three Years in the Period Ended
December 31, 2006
Consolidated Statements of Cash Flows for the Three Years in the Period Ended
December 31, 2006
Notes to Consolidated Financial Statements
(a) 2. Schedules other than those listed above are omitted because they are not required, not applicable or the
required information is included in the financial statements or notes thereto.
(a) 3. Exhibits:
2. Plan of acquisition, reorganization, arrangement, liquidation or succession*
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended (incorporated by reference to
Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31,
2003, File No. 001-14039)
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 (incorporated by
reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2003, File No. 001-14039)
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)
74
4.2 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)
4.3 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 (incorporated by reference
to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended December
31, 2003, File No. 001-14039)
4.4
Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004 between
Callon Petroleum Company and American Stock Transfer and Trust Company (incorporated
by reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period
ended March 31, 2004, File No. 001-14039)
9. Voting trust agreement
None.
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between the Company and NOCO
Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the Company's
Registration Statement on Form 8-B filed October 3, 1994)
10.2 Counterpart to Registration Rights Agreement by and between the Company, Ganger Rolf
ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2 of the Company’s
Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 001-14039)
10.3 Registration Rights Agreement dated September 16, 1994 between the Company and Callon
Stockholders (incorporated by reference from Exhibit 10.3 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from
Exhibit 10.5 of the Company's Registration Statement on Form 8-B filed October 3, 1994
10.5 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)
10.6 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)
10.7 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)
75
10.8 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)
10.9 Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating
Company, Murphy Exploration & Production Company-USA and Oceaneering International,
Inc. (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form
10-K for the year ended December 31, 2003, File No. 001-14039)
10.10 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. (incorporated by reference to Exhibit 10.20 of the
Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No.
001-14039)
10.11 Amended and Restated Credit Agreement dated as of August 30, 2006 between the Company
and Union Bank of California, N.A., as Administrative Agent (incorporated by reference to
Exhibit 10.11 of the Company’s Current Report on Form 8-K dated August 31, 2006, File No.
001-14039)
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 Executive Officers and Senior Financial Officers (incorporated by
reference to Exhibit 14.1 of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2003, File No. 001-14039)
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
76
23.2 Consent of Huddleston & Co., Inc.
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.
77
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.
SIGNATURES
CALLON PETROLEUM COMPANY
Date: March 16, 2007
/s/Fred L. Callon
Fred L. Callon
(principal executive officer,
director)
Date: March 16, 2007
/s/B. F. Weatherly
B. F. Weatherly
(principal
financial officer,
director)
Date: March 16, 2007
Date: March 16, 2007
Date: March 16, 2007
/s/Rodger W. Smith
Rodger W. Smith (principal accounting officer)
/s/Richard Flury
Richard Flury (director)
/s/John C. Wallace
John C. Wallace (director)
Date: March 16, 2007
/s/Richard O. Wilson
Richard O. Wilson (director)
78
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.
Date: March 16, 2007
CALLON PETROLEUM COMPANY
By: /s/B. F. Weatherly
B. F. Weatherly, Executive Vice-President and
Chief Financial Officer
79
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the following Registration Statements:
Registration Statement (Form S-8 No. 33-90410) of Callon Petroleum Company;
Registration Statement (Form S-8 No. 333-100646) of Callon Petroleum Company;
Registration Statement (Form S-3 No. 333-87945) of Callon Petroleum Company;
Registration Statement (Form S-3 No. 333-60606) of Callon Petroleum Company;
Registration Statement (Form S-8 No. 333-47784) of Callon Petroleum Company;
Registration Statement (Form S-8 No. 333-29537) of Callon Petroleum Company;
Registration Statement (Form S-8 No. 333-29529) of Callon Petroleum Company;
Registration Statement (Form S-8 No. 333-109744) of Callon Petroleum Company;
Registration Statement (Form S-8 No. 333-135703) of Callon Petroleum Company
of our reports dated March 15, 2007, with respect to the consolidated financial statements of
Callon Petroleum Company, Callon Petroleum Company management’s assessment of the
effectiveness of internal control over financial reporting, and the effectiveness of internal
control over financial reporting of Callon Petroleum Company, included in this Annual
Report (Form 10-K) for the year ended December 31, 2006.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 15, 2007
80
EXHIBIT 23.2
CONSENT OF HUDDLESTON & CO., INC.
We hereby consent to the references to us and our reserve reports for the years ended December 31, 2006, 2005
and 2004 in Callon Petroleum Company’s Annual Report on Form 10-K for the year ended December 31, 2006 and
the incorporation by reference in the current and future effective Registration Statements of Callon Petroleum
Company of the reference to us and our reserve reports for the years ended December 31, 2006, 2005 and 2004.
HUDDLESTON & CO., INC.
Peter D. Huddleston, P.E.
President
Houston, Texas
March 7, 2007
81
Exhibit 31.1
CERTIFICATIONS
I, Fred L. Callon, certify that:
1.
2.
I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls
and procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee
of registrant’s board of directors (or persons performing the equivalent function):
82
(a)
All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrant’s internal controls over financial reporting;
Date: March 16, 2007
By: /s/Fred L. Callon
Fred L. Callon, President and Chief Executive Officer
(Principal Executive Officer)
83
CERTIFICATIONS
Exhibit 31.2
I, B. F. Weatherly, certify that:
1.
2.
I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls
and procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee
of registrant’s board of directors (or persons performing the equivalent function):
84
(a)
All significant deficiencies and material weaknesses in the design or operation of
internal control over financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial information; and
(b)
Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrant’s internal controls over financial reporting;
Date: March 16, 2007
By: /s/B. F. Weatherly
B. F. Weatherly, Executive Vice-President and
Chief Financial Officer (Principal Financial Officer)
85
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
In connection with the Annual Report of Callon Petroleum Company (the “Company”) on Form 10-K for the fiscal
year ended December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Fred
L. Callon, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, that to my knowledge:
(1)
1934, as amended; and
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company as of, and for the periods presented in the Report.
Dated: March 16, 2007
/s/Fred L. Callon
Fred L. Callon, Chief Executive Officer (Principal Executive Officer)
The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and
Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States
Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of
1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date
hereof, regardless of any general incorporation language in such filing.
86
EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
In connection with the Annual Report of Callon Petroleum Company (the “Company”) on Form 10-K for the fiscal
year ended December 31, 2006, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, B. F.
Weatherly, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002, that to my knowledge:
(1)
1934, as amended; and
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company as of, and for the periods presented in the Report.
Dated: March 16, 2007
/s/B. F. Weatherly
B. F. Weatherly, Chief Financial Officer (Principal Financial Officer)
The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and
Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States
Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of
1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date
hereof, regardless of any general incorporation language in such filing.
87
CORPORATE DATA
Board of Directors
Legal Counsel
Fred L. Callon
Chairman
and Chief Executive Officer
B.F. Weatherly
Executive Vice President
and Chief Financial Officer
L. Richard Flury
Former Chief Executive
Gas, Power & Renewables (Retired)
British Petroleum plc
John C. Wallace
Chairman, Fred. Olsen Ltd.
London, England
Richard O. Wilson
Offshore Consultant
Houston, Texas
Offi cers of the Company
Fred L. Callon
Chairman
and Chief Executive Officer
B.F. Weatherly
Executive Vice President
and Chief Financial Officer
Robert A. Mayfield
Corporate Secretary
Thomas E. Schwager
Vice President, Engineering
and Operations
H. Clark Smith
Chief Information Officer
Rodger W. Smith
Corporate Controller and Treasurer
Stephen F. Woodcock
Vice President, Exploration
Transfer Agent and Registrar
American Stock Transfer
& Trust Company
59 Maiden Lane, Plaza Level
New York, NY 10273
(718) 921-8200
Haynes and Boone, LLP
Houston, Texas
Simon, Peragine, Smith & Redfearn
New Orleans, Louisiana
Independent Registered
Public Accounting Firm
Ernst & Young LLP
New Orleans, Louisiana
Banks
Union Bank of California N.A.
San Francisco, California
AmSouth Bank
Jackson, Mississippi
Corporate Offi ces
Callon Headquarters Building
200 North Canal Street
Natchez, Mississippi 39120
Callon Petroleum Company
1200 Enclave Parkway, Suite 225
Houston, Texas 77077
2006 Annual Report
This Annual Report and the statements
contained in it are submitted for the general
information of the shareholders of Callon
Petroleum Company. The information is not
presented in connection with the sale or the
solicitation of any offer to buy any securities,
nor is it intended to be a representation by
the Company of the value of its securities. If
you have questions regarding this Annual
Report or the Company, or would like
additional copies of this report, please
contact our Investor Relations Department
at 200 North Canal Street, Natchez, MS
39120 (601) 442-1601.
Security analysts and investment
professionals should direct inquiries
to B. F. Weatherly, Executive Vice President
and Chief Finanical Officer, Callon
Petroleum Company, 200 North Canal
Street, Natchez, MS 39120, (601) 442-1601,
(601) 446-1410 (fax).
Form 10-K
The Company’s annual report on
Form 10-K has been incorporated into this
Annual Report. Extra copies of the Form
10-K, may be obtained upon written request
to Rodger W. Smith at the address above.
Common Stock
Dividend Policy
It is anticipated that all available funds will
be reinvested in the Company’s business
activities. Therefore, the Company does
not anticipate paying cash dividends on its
common stock for the foreseeable future.
Market for Common Stock
Effective April 22, 1998, the Company’s
Common Stock began trading on the New
York Stock Exchange under the symbol
“CPE.”
Notice of Annual
Shareholders’ Meeting
The Annual Meeting of Shareholders
will be held Thursday, May 3, 2007 at
9:00 a.m. in the St. Louis Room of the
Natchez Convention Center, 211 Main
Street, Natchez, MS 39120. Information
with respect to this meeting is contained
in the Proxy Statement sent to shareholders
of record on March 19, 2007. The 2006
Annual Report is not to be considered a
part of the proxy soliciting materials.
Callon Home Page --
www.callon.com
The Company has a homepage on the
internet, www.callon.com. It contains
news releases, corporate governance
materials, the annual report, recent
investor presentations, stock quotes and
links to SEC filings.
CALLON PETROLEUM COMPANY
200 North Canal Street
Natchez, Mississippi 39120
www.callon.com