Corporate Profi le
Callon Petroleum Company is an
independent oil and gas company
focused on building reserves
and production through effi cient
operations and low fi nding and
development costs. Since 1950,
Callon has operated onshore and
offshore in the Gulf Coast region.
The company’s estimated proved
reserves at December 31, 2009 were
58.0 billion cubic feet of natural gas
equivalent (Bcfe).
Midland
Natchez
Houston
2P Reserves by Area
2P Reserves by Oil/Gas
70
60
50
40
30
20
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To Our Shareholders
Throughout its 60-year history, your company has weathered many
storms and adapted to changing conditions in the industry. The year
2009 marks another transition for Callon. This year we announced a
modifi cation to our business strategy, added qualifi ed new people
to our team, acquired new assets and set out to build a bigger and
better company. As a management team, our single focus has been to
position the company to create long-term value for you, the shareholder.
We are excited with the progress we made this year and look forward to
the years ahead.
Callon entered 2009 with a new strategic focus, looking to emphasize
long-term growth through the acquisition and development of
lower-risk, high impact onshore assets and primarily funding the
development of these new assets with the stable cash fl ow from our
quality deepwater Gulf of Mexico properties. One of the key steps in
initiating this new strategy was the hiring of Steven B. Hinchman, our
Executive Vice President and Chief Operating Offi cer, in June 2009.
Steve brings 29 years of ever-increasing experience at Marathon Oil
to our team. His experience has been a signifi cant contribution
toward refi ning our direction and setting measurable strategic
initiatives to lead the company as we move ahead. Our progress will be
measured against these initiatives, which include: 1) growing production
20 percent per year; 2) achieving reserve replacement of 200 percent or
more per year while keeping average fi nding and development costs
under $3.00 per thousand cubic feet of natural gas equivalent (Mcfe);
3) lengthening reserve life to 10 years; and 4) strengthening our balance
sheet while growing reserves to a target of $1.00 of debt per Mcfe of
proved reserves. Our two onshore acquisitions in 2009 are the fi rst
step in achieving these objectives.
Maintaining liquidity during the company’s strategic shift towards
onshore growth was a major focus throughout much of 2009.
In November, we completed a very successful exchange offer which
extended the maturity of 92 percent of our senior notes due December
2010 to September 2016, while also reducing the principal amount
of these notes by $46 million. Additionally, late in the year, as a result
of a ruling by the Supreme Court, we applied for recoupment of
$44.8 million of royalty payments made to the United States Department
of the Interior’s Mineral Management Service on production at our
Medusa Field in the deepwater region of the Gulf of Mexico. In January
2010, we received payment of this amount. This cash, along with the
signifi cant cash fl ow produced by Callon’s offshore deepwater and shelf
assets, will enable us to execute our development plan in 2010 using
only internal funds.
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2009 Highlights
Reserves
(cid:129) Restructured $200.0 million of
senior notes and reduced the
principal from $200.0 million to
$154.0 million, extended debt
maturities of $138.0 million until
September 2016.
(cid:129) Filed for recoupment of
$44.8 million in deepwater
royalty payments (and received
these funds in January 2010).
(cid:129) Initiated a new strategy to reinvest
offshore cash fl ow into lower risk,
longer life onshore plays.
(cid:129) Acquired Permian Basin assets,
providing a multi-year inventory
of drilling locations in the
promising onshore Wolfberry
conventional oil play.
Our estimated net proved reserves at
December 31, 2009 were 58.0 Bcfe, and
our net probable reserves were 66.4 Bcfe.
Our proved reserves grew six percent from
December 31, 2008 despite a reduced 2009
capital budget. Of our 58.0 Bcfe in proved
reserves, 83 percent are associated with our
Gulf of Mexico assets, and the remaining
17 percent are found in the Permian Basin.
Of our 66.4 Bcfe of probable reserves,
21 percent are associated with the
Gulf of Mexico, 50 percent are in the
Permian Basin and 29 percent are
associated with our Haynesville Shale asset.
Our reserves to production ratio at year-end
was 5.1 years, and the PV-10 value of our
proved reserves at December 31, 2009 was
$137.4 million.
These reserves will drive Callon’s production
growth and catalyze our transition from a
Gulf of Mexico producer to a more balanced
(cid:129) Established a position in the
and less concentrated domestic producer both
onshore and offshore.
Haynesville Shale play of northern
Louisiana having the potential
for seven horizontal wells and
the potential to increase proved
reserves by 45 percent with our
fi rst two wells.
(cid:129) Replaced 127 percent of 2009
production with 15.0 billion cubic
feet of natural gas equivalent
(Bcfe) of reserve additions.
Operations and Financial Review
U.S. Gulf of Mexico – Deepwater
Haynesville Shale Natural Gas Play
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Callon made a second acquisition in 2009,
a 70 percent interest in a 577-acre unit in Bossier
Parish, Louisiana, prospective for the Haynesville
Shale. The unit is located in the heart of the play,
with wells in nearby blocks having had initial
production rates in excess of 19.0 million cubic
feet of natural gas (MMcf) per day. By drilling
our fi rst two Haynesville wells in 2010, Callon
has the potential to increase the company’s 2009
proven reserve base by 45 percent. Callon’s
development plan for the unit calls for a total of
seven wells drilled horizontally. The company’s
acreage presents strong economics, with a
20 percent internal rate of return at a natural gas
price of $3.50 per thousand cubic feet (Mcf).
Gulf of Mexico Shelf
Our Gulf of Mexico Shelf properties produced
an average of 14.0 million cubic feet of natural
gas equivalent (MMcfe) per day, net, in 2009.
The West Cameron 295 Field, East Cameron 2
and East Cameron 257 Fields represent
55 percent of the total shelf production.
Production from our Gulf of Mexico assets is anchored
by our two deepwater fi elds, Habanero and Medusa.
In 2009, production from these two fi elds averaged
3,000 net barrels of oil equivalent (BOE) per day.
At the Medusa Field, eight wells produced an average
of 2,000 BOE per day net to Callon in 2009. Callon’s
Medusa reserves are 89 percent oil, and most wells
are in primary completion with signifi cant upside
potential currently behind pipe. The fi eld is operated
by Murphy Exploration & Production Company, and
Callon has a 15 percent working interest.
The Habanero Field has two wells currently producing,
and produced an average of 1,000 BOE per day net
to Callon in 2009. Habanero is operated by Shell
Deepwater Development, Inc., and Callon has an
11.25 percent working interest.
Our two deepwater fi elds are the foundation of our
growth strategy as we move forward. Both Habanero
and Medusa have shallow declines, require minimal
capital reinvestment and have low per unit operating
costs, and we expect them to be stable cash fl ow
producers for at least 10 years.
Permian Basin – Wolfberry Oil Play
In October 2009, we made our fi rst onshore acquisition
since implementing the new strategy. We made our
initial entry into the Permian Basin by purchasing
1.6 million barrels of oil equivalent (MMBoe) proven
reserves and 350 BOE per day production. Our primary
target in the Permian Basin is the Wolfberry trend,
which is a proven, low permeability oil play, and this
acquisition gives us a multi-year inventory of drilling
locations providing us growth visibility in the near
term. The play has solid economics, with a 20 percent
internal rate of return at a $65 per barrel oil price.
Our development program in the basin is fl exible,
should we again witness extreme volatility in
commodity prices.
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Liquidity and Capital Resources
2010 Capital Budget
Total $61.7 million
On January 26, 2010 we received a recoupment of $44.8 million
in deepwater royalties. Also in January, we negotiated a new
$100.0 million credit facility with Regions Bank, with an initial
borrowing base of $20.0 million. While we have made signifi cant
progress towards improving our capital structure with the notes
exchange, royalty recoupment and new credit facility, we will continue
to focus on liquidity as we move forward with our growth plan.
Our 2010 capital budget has been set at $61.7 million, with about
one-third of our budget allocated towards development drilling in the
Permian Basin, one-third towards shale gas and the Gulf of Mexico,
and one-third towards acquiring additional leasehold acreage and
capitalized costs. We expect to be able to fully fund our capital budget
with forecasted operating cash fl ow and available cash.
2010 Outlook
While 2009 was a year of transition for Callon, our outlook for 2010
and beyond is bright. We’ve put together what we believe to be the
right strategy, the right people and the right assets to achieve our
strategic objectives of growing production and reserves, increasing
the life of our proved reserves, managing risk and strengthening the
balance sheet. Now it’s time for us to focus and execute to make our
plan a reality. We have a large inventory of drilling prospects and
strong cash fl ow from our Gulf of Mexico assets to fund the execution
of our strategy, which provides visible growth to you, our shareholder.
Let me express my thanks to our dedicated, hard-working employees,
our board members and our loyal shareholders for their continued
support of Callon Petroleum.
Fred L. Callon
Chairman
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
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)
Title of each class Name of exchange on which registered
Common Stock, Par Value $.01 Per Share
New York Stock Exchange
Securities registered pursuant to Section 12(b) of the Act:
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post such files). 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, a non-accelerated filer, or a smaller
reporting company. See definitions of “Large accelerated filer, accelerated filer and smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer ____ Accelerated filer Non-accelerated filer X Smaller reporting company ____
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
$41 million as of June30, 2009 (based on the last reported sale price of such stock on the New York Stock Exchange on such date of
$1.98).
As of March 8, 2010, there were 28,740,863 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, 2009) relating to the Annual Meeting of Stockholders to be held on May 4, 2010, which are
incorporated into Part III of this Form 10-K.
1
Table of Contents Page
3
17
28
28
28
28
30
33
48
49
Item 6.
Item 7.
Item 1 and 2. Business and Properties
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Risk Factors
Unsolved Staff Comments
Legal Proceedings
[Reserved]
Market for Registrant’s Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and
Results of Operations
Quantitative and Qualitative Disclosures about Market Risks
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9A. (T) Controls and Procedures
Item 9B.
Item 10.
Item 11.
Item 12.
Item 7A.
Item 8.
Item 9.
Other Information
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
88
Certain Relationships and Related Transactions and Director Independence 88
88
Principal Accountant Fees and Services
89
Exhibits, Financial Statement Schedules
Item 13.
Item 14.
Item 15.
84
84
84
87
88
88
2
PART I.
ITEM 1 and 2. BUSINESS and PROPERTIES
Overview
Callon Petroleum Company was 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 partially owned by a member 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.
Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico. Following
the abandonment of our Entrada project in 2008, we took steps to change our operational focus to lower risk,
onshore exploration and development activities. During 2009, we took the following actions:
We exchanged a new series of senior notes due 2016 and common stock for a substantial portion of
our existing $200 million of senior notes due 2010, and reduced principal from $200 million to $154
million.
We filed for recoupment of deepwater royalty payments, and received a payment from the Minerals
Management Service (“MMS”) of $44.8 million in January 2010. We expect to receive an additional
payment from the MMS of approximately $7.7 million during 2010, representing interest.
We began negotiating a new $100 million revolving credit facility, with a borrowing base of $20
million, which we finalized in January 2010.
These activities were undertaken to allow us to shift our operational focus from the offshore Gulf of Mexico
to longer life, lower risk onshore properties. As part of this strategy, we employed Steven B. Hinchman as
our Chief Operating Officer. Mr. Hinchman has substantial experience in onshore oil and gas acquisition,
exploration and development activities. During 2009, we closed two acquisitions as part of this new focus,
including:
In September 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the
Haynesville Shale play in Bossier Parish, Louisiana for $3.0 million. We plan to drill a total of
seven horizontal wells on this property, with the first two wells to be drilled in 2010. We will be the
operator of these wells.
On October 28, 2009, we acquired interests in properties producing from the Wolfberry formation in
Crockett, Ector, Midland and Upton Counties, Texas for total cash consideration of $16.0 million.
The acquisition included year-end proved reserves of 1.6 million barrels of oil equivalent
(“MMBoe”) 22 existing wells producing 350 barrels of oil equivalent (“Boe”) per day and upside
from a multi-year inventory of drilling opportunities. We will operate substantially all of the
production and development of these properties. See Note 13 to our Consolidated Financial
Statements.
3
Our Business Strategy
Our strategy for 2010 and going forward will be,
To increase reserves and production levels by using cash flows from, or monetization of, our Gulf of
Mexico properties to acquire and develop lower risk, longer life onshore oil and gas properties;
To increase our reserve life by focusing on acquisition of long-life onshore properties;
To diversify risk by substantially increasing the number of wells we own; and
To strengthen our balance sheet by focusing on a reduction of our average debt per thousand cubic
feet of natural gas equivalent (“Mcfe”) of proved reserves.
Exploration and Development Activities
In 2009, capital expenditures on an accrual basis for exploration and development costs related to oil and gas
properties totaled approximately $40 million. These expenditures included:
$19 million for on-shore property acquisitions;
$2 million for development costs in the Gulf of Mexico and onshore south Louisiana;
$6 million for plugging and abandonment costs in the Gulf of Mexico; and
$3 million for capitalized interest and $10 million for capitalized general and administration costs
allocable directly to exploration and development projects.
Acquisitions and Divestitures
In September 2009, we acquired a 70% operating interest in a 577-acre Haynesville Shale Unit in Bossier
Parish, Louisiana at a cost of $3.0 million. The Unit is in the core of the play offset by wells having
demonstrated initial production rates of 20 million cubic feet of natural gas (“MMcf”) per day. We plan to drill
and complete two of seven horizontal wells in 2010. We estimate that the typical well in this field will have
gross recoverable reserves of 6.4 billion cubic feet of natural gas (“Bcf”) per well and cost approximately $9.0
million to drill and complete. Callon will be the operator of this project.
On October 28, 2009, we completed the acquisition of proved oil and gas property interests in Wolfberry
play located in Crockett, Ector, Midland and Upton Counties, Texas from Ambrose Energy I, Ltd., a
subsidiary of ExL Petroleum, LP for a total cash consideration of $16.0 million. The acquisition was funded
by our senior secured credit facility in the amount of $10 million, and the remaining $6.0 million with cash
on hand. The acquisition included year-end proved reserves of 1.6 MMBoe, 22 existing wells producing 350
Boe per day and upside from a multi-year inventory of drilling and recompletion opportunities. We will
operate substantially all of the production and development. We accounted for the acquisition in accordance
with the amended guidance issued by the Financial Accounting Standards Board (“FASB”) for business
combinations which was adopted on January 1, 2009, and recorded acquisition expenses in the fourth quarter
of 2009 of $298,000. See Note 13 to our Consolidated Financial Statements.
Oil and Gas Properties Summary
Overview. As of December 31, 2009, our estimated net proved reserves totaled 58.0 billion cubic feet of natural
gas equivalent (“Bcfe”) and included 6.5 million barrels of oil (“MMBbls”) and 19.1 Bcf, with a pre-tax present
value of $137.4 million. Pre-tax present value may be deemed to be a non-U.S. generally accepted accounting
principle (“US GAAP”) financial measure, which we reconcile to standardized measure, the US GAAP
measure, in the table below. Oil constitutes approximately 67% on an equivalent basis of our total estimated net
proved reserves, and approximately 66% of our total estimated proved reserves are proved developed reserves.
4
The following table sets forth certain information about our estimated proved reserves by our independent
petroleum reserve engineers by major field and for all other properties combined at December 31, 2009.
Pre-tax
Estimated Net Proved Reserves Discounted
Present
Value
($000)
(a)(b)(c)
Operator
Total
(MMcfe)
Gas
(MMcf)
Oil
(MBbls)
Gulf of Mexico Deepwater:
Mississippi Canyon 538/582
“Medusa”
Garden Banks Block 341
“Habanero”
Gulf of Mexico Shelf and Onshore:
West Cameron Block 295
East Cameron Block 109
Permian Basin
Other
Murphy
4,412
3,268
29,740 $ 89,795
Shell
725
4,729
9,077
25,084
Mariner Energy
Energy Partners LTD
Callon
Various
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18
1,242
70
1,724
1,224
2,117
6,041
1,798
1,332
9,571
6,457
3,402
4,193
17,873
(2,979)
Total Net Proved Reserves
6,479
19,103
57,975 $ 137,368
(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, 2009, as set forth in
the Company’s reserve reports prepared by its independent petroleum reserve engineers, Huddleston &
Co., Inc.
(b) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our
balance sheet at December 31, 2009, in accordance with accounting for asset retirement obligations
rules. See the Oil and Gas Reserve table for the standardized measure of discounted future net cash flow
in Note 18 of our consolidated financial statements. The negative Pre-Tax Present Value of the Gulf of
Mexico Shelf and Onshore Other reflects plugging and abandonment obligations, of which most are
estimated to occur within the next five years, exceeding the future net cash flows.
(c) We use the financial measure “Pre Tax Present Value” which is a non-US GAAP financial measure. We
believe that Pre Tax Present Value, while not a financial measure in accordance with US GAAP, 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, 2009 was $135.9 million. The standardized measure gives effect to income taxes, and is
calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing
activities.” The $135.9 million of standardized measure of our estimated net proved reserves equals the
present value of our estimated future net revenue from proved reserves of $137.4 million, which excludes
the discounted estimated future income taxes relating to such future net revenues of $1.5 million.
5
Onshore Oil and Gas Properties
Permian Basin
During the fourth quarter of 2009, we acquired 22 producing wells with associated proved reserves of 1.6
MMBoe. Our primary target in the Permian Basin is the Wolfberry trend, which is a proven, low-
permeability oil play. The Wolfberry interval includes the Sprayberry, Dean, and Wolfcamp formations.
We have identified 148 drilling locations based on a 40-acre spacing development. We commenced drilling
in February 2010 and plan to drill up to 16 Wolfberry wells in 2010.
Haynesville Shale
In addition to the significant properties discussed above, we acquired a 70% working interest in a Haynesville
Shale unit located in Southern Bossier Parish, Louisiana in September 2009. We plan to drill two horizontal
wells in 2010.
Gulf of Mexico Deepwater
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. 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. We have participated in additional development of the Medusa field which includes the drilling and
completion of two additional wells, Mississippi Canyon 538 #4, North Medusa, and Mississippi Canyon 538
#5. 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.
During 2009 the field produced 4.5 Bcfe net to us from eight wells which accounted for 38% of our total
production. Inception to date as of December 31, 2009, the Medusa Field had produced 43 Bcfe, net to us.
Most of the wells are still producing from their initial completion and have 14.2 Bcfe of proved developed
non-producing reserves that will be accessed by recompletions in the existing wells. Another 7.1 Bcfe of
proved undeveloped reserves will be developed by side tracking an existing well. These operations will
occur as existing completions reach their economic limit which is estimated as of December 31, 2009 to be
in 2022.
In December 2003, we transferred our undivided 15% working interest in the spar production facilities to
Medusa Spar LLC (“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. 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
6
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. 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 owned by Murphy.
During 2009, Habanero produced 2.2 Bcfe net to us from two wells which accounted for 19% of our total
production. Future plans include sidetracks of both the wells to drain updip and partially fault-separated gas
in the Habanero 52 sand when the existing completions reach their economic limit, which is estimated as of
December 31, 2009 to be in 2014.
Gulf of Mexico Shelf and Onshore Louisiana
We own interests in 18 wells in 12 oil and gas fields in the shelf area of the Gulf of Mexico. These wells
produced 5.0 Bcfe net to our interest in 2009.
Proved Reserves
In December 2008 the Securities and Exchange Commission (“SEC”) approved amendments to its oil and
gas reserves estimation and disclosure requirements. The amendments, among other things:
allow the use of reliable technologies to estimate proved reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve volumes;
require disclosure of oil and gas proved reserves by significant geographic area;
permit the optional disclosure of probable and possible reserves;
modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average
beginning-of-the-month price instead of a period-end price; and
require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the
company make disclosures relating to the independence and qualifications of the third party,
including filing as an exhibit any report received from the third party.
The new requirements are effective for our year-end financial statements and our Annual Report on Form
10-K for the year ended December 31, 2009, and as such the reserves and related information for 2009 are
presented consistent with the requirements of the new rule. The new rule does not require prior-year reserve
information to be restated, so all information related to periods prior to 2009 is presented consistent with the
prior SEC rules for the estimation of proved reserves.
Estimates of volumes of proved reserves, net to our interest, at year end are presented in Mmcf at a pressure
base of 15.025 pounds per square inch for natural gas and in MBbls for oil. Total volumes are presented in
million cubic feet of natural gas equivalent (“MMcfe”). For the computation, one barrel is the equivalent of
6,000 cubic feet of gas.
7
The following table sets forth certain information about our estimated proved reserves. All of our proved
reserves are located in the United States.
Years Ended December 31,
2008_
2009_
2007_
Proved developed:
Oil (MBbls)
Gas (MMcf)
MMcfe
Proved undeveloped:
Oil (MBbls) (c)
Gas (MMcf) (c)
MMcfe (c)
Total proved:
Oil (MBbls) (c)
Gas (MMcf) (c)
MMcfe (c)
4,346
12,301
38,377
4,663
13,463
41,441
2,133
6,802
19,600
1,364
5,189
13,375
6,479 6,027
19,103 18,652
57,977 54,816
4,723
22,340
50,676
19,808
94,114
212,964
24,531
116,454
263,640
Estimated pre-tax future net cash flows (a)
$ 216,702 $ 113,555
$2,317,905
Pre-tax discounted present value (a) (b)
$ 137,368 $ 86,591
$1,591,472
Standardized measure of discounted future
net cash flows(a) (b)
$ 135,921 $ 86,305
$1,133,989
(a) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our
balance sheet at December 31, 2009, in accordance with accounting for asset retirement obligations
rule.
(b) We use the financial measure “Pre Tax Present Value” which is a non-US GAAP financial measure.
We believe that Pre Tax Present Value, while not a financial measure in accordance with US GAAP, 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, 2009 was $135.9 million. The standardized measure gives effect to income taxes, and
is calculated in accordance with guidance issued by the FASB for disclosures about oil and gas
producing activities. The $135.9 million of standardized measure of our estimated net proved reserves
equals the present value of our estimated future net revenue from proved reserves of $137.4 million,
which excludes the discounted estimated future income taxes relating to such future net revenues of
$1.5 million. Year-end average pricing was $4.75 per Mcf for natural gas and $57.40 per Bbl for oil.
(c) The reduction in 2008 reserves as compared to 2007 year-end proved reserves of 263.6 Bcfe was
primarily associated with the sale of a 50% working interest in the Entrada Field and the
abandonment of the Entrada project. See Note 3 to our consolidated financial statements.
8
Our estimates of proved reserves, proved developed reserves (“PDPs”), proved undeveloped reserves
(“PUDs”) at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years
are included in Note 18 of our Consolidated Financial Statements. Also included in Note 18 are our
estimates of future net cash flows and discounted future net cash flows from proved reserves.
Proved Undeveloped Reserves. We annually review our PUDs to ensure an appropriate plan exists for
development. Generally, reserves for our onshore properties are booked as PUDs only if we have plans to
convert the PUDs into PDPs within five years of the date they are first booked as PUDs. We had 19.6 Bcfe
of PUDs at December 31, 2009, compared with 13.4 Bcfe of PUDs at December 31, 2008. Of these 2009
PUDs, 7.1 Bcfe and 6.9 Bcfe were attributable to our offshore properties in the Medusa and Habanero fields
in the Gulf of Mexico, respectively. Our plans are to develop these PUDs by side tracking existing wells
when the zones currently being produced by the wells are depleted. Our current reserve reports forecast that
these producing zones in the Habenero field will be depleted in 2014 and in the Medusa field in 2022, at
which time we plan to develop the PUDs. We did not convert any offshore PUDs to PDPs in 2009.
During 2009, we acquired 711 MBbls and 1.3 Bcf, or 5.6 Bcfe, of PUDs in our ExL acquisition. Our
development plan for these PUDs will begin in 2010 and are anticipated to be completed within five years
allowing the PUDs to be converted to PDPs. The remaining 0.6 Bcfe increase in PUDs from 2008 to 2009 is
associated with our deepwater property, Medusa, and is a result of including reserves related to the
Deepwater Royalty Relief Act. These PUDs were previously excluded due to prices exceeding the MMS
imposed thresholds. As a result of the court decisions, the MMS is no longer enforcing its price thresholds.
At year end 2008, we had no PUDs located onshore. See Note 12 to our Consolidated Financial Statements.
Controls Over Reserve Estimates. Our policies and practices regarding internal controls over the recording
of reserves are structured to objectively and accurately estimate our oil and gas reserves quantities and
present values in compliance with the SEC’s regulations and US GAAP. Compliance in reserves bookings is
the responsibility of our Executive Vice President and Chief Operating Officer, who is our principal
engineer. Our principal engineer has over 30 years of experience in the oil and gas industry, including over
25 years as a manager. Further professional qualifications include a degree in petroleum engineering and
asset evaluation and management. In addition, the principal engineer is an over 30-year member of the
Society of Petroleum Engineers.
Our controls over reserve estimates included retaining Huddleston & Co. as our independent petroleum and
geological firm. We provided information about our oil and gas properties, including production profiles,
prices and costs, to Huddleston and they prepare their own estimates of the reserves attributable to our
properties. All of the information regarding reserves in this annual report is derived from the report of
Huddleston. The report of Huddleston is included as an Exhibit to this annual report. The principal engineer
at Huddleston who is responsible for preparing our reserve estimates has over 29 years of experience in the
oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications
include a degree in petroleum engineering as well as being a member of the Society of Petroleum Engineers.
The Huddleston & Co., Inc. engineer firm is a Texas Registered Engineering Firm.
The Audit Committee of our Board of Directors meets with management, including the Chief Operating
Officer to discuss matters and policies including those related to reserves.
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
9
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.
During our last fiscal year, we have not filed any reports with other federal agencies which contain an estimate
of total proved net oil and gas reserves.
Production Volumes, Average Sales Prices and Average Production Costs
The following table sets forth certain information regarding the production volumes and average sales prices
received for and average production costs associated with the Company’s sale of oil and natural gas for the
periods indicated.
Year ended December 31,
2009
2007
2008
(In thousands, except per unit data)
Production
Natural gas (Mcf)....................................................
Oil (MBbl) ..............................................................
Total (MMcfe) .......................................................
5,740
1,012
11,809
5,839
942
11,494
12,340
1,063
18,718
Revenues
Natural gas sales......................................................
Oil sales .................................................................
Total revenues.......................................................
$ 27,417
73,842
$101,259
$ 58,349
82,963
$141,312
$ 98,877
71,891
$ 170,768
Lease Operating Expenses
Production costs………………………………….
Severance/production taxes ....................................
Gathering ...............................................................
Total lease operating expenses .............................
$ 16,778
528
1,141
$ 18,447
Realized prices
Natural gas ($/Mcf, including realized gains
(losses) on derivatives) ........................................
Natural gas ($/Mcf, excluding realized gains
(losses) on derivatives)………………………… $ 4.45
Oil ($/Bbl, including realized gains (losses) on
derivatives) ..........................................................
Oil ($/Bbl, excluding realized gains (losses) on
derivatives)……………………………………
$ 55.84
$ 73.00
$ 4.78
$ 17,604
626
977
$ 19,208
$ 24,254
1,378
2,162
$ 27,795
$ 9.99
$ 8.01
$ 10.10
$ 7.40
$ 88.07
$ 67.63
$ 97.37
$ 67.10
Operating costs per Mcfe - Total Consolidated
Production costs.....................................................
Severance/production taxes ....................................
Gathering ................................................................
DD&A ....................................................................
Interest ...................................................................
$ 1.42
$ 0.04
$ 0.10
$ 2.83
$ 1.62
$ 1.53
$ 0.05
$ 0.09
$ 5.57
$ 2.09
$ 1.30
$ 0.07
$ 0.12
$ 3.89
$ 1.83
Total operating costs per Mcfe .............................
$ 6.01
$ 9.33
$ 7.21
10
Present Activities and Productive Wells
The following table sets forth the wells we have drilled and completed during the periods indicated. All such
wells were drilled in the continental United States primarily in federal and state waters in the Gulf of Mexico.
Years Ended December 31,_ __________
2007_____
_Net_
Gross
2008 ____
_Net_
Gross
2009_ ___
Gross
_Net_
Development:
Oil
Gas
Non-productive
Total
Exploration:
Oil
Gas
Non-productive
Total
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
--
1
--
1
2
--
--
2
2
0.15
--
0.50
0.65
--
--
0.22
0.22
1
1
--
2
--
2
3
5
0.25
0.12
--
0.37
--
0.63
0.47
1.10
At December 31, 2009 we were not involved in the drilling of any wells.
The following table sets forth our productive wells as of December 31, 2009:
Oil:
Working interest
Royalty interest
Wells ______
Net__
Gross_
32.00
--
19.35
--
Total
32.00
19.35
Gas:
Working interest
Royalty interest
19.00
5.00
5.89
0.13
Total
24.00
6.03
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, 2009, we had no wells with
multiple completions.
11
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of
December 31, 2009.
Location
Louisiana
Texas
Federal waters
Leasehold Acreage__________
Developed____
Undeveloped __
Net__
Gross_
Net__ Gross_
4,320
4,800
53,210
1,964
3,167
18,387
1,522
19,059
157,914
973
9,136
99,841
Total
62,330
23,518
178,495
109,950
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
Plains Marketing, L.P.
Louis Dreyfus Energy Services
StatoilHydro
December 31, __ ___
2007_
2008_
2009_
25%
33%
45%
10%
23%
23%
20%
16%
15%
13%
--
--
Because alternative purchasers of oil and gas are readily available, we believe that the loss of any of these
purchasers would not result in a material adverse effect on our ability to market future oil and gas production.
Title to Properties
We believe that the title to our oil and gas properties is good and defensible in accordance with standards
generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so
material as to detract substantially from the use or value of such properties. Our properties are typically subject,
in one degree or another, to one or more of the following:
royalties and other burdens and obligations, express or implied, under oil and gas leases;
overriding royalties and other burdens created by us or our predecessors in title;
a variety of contractual obligations (including, in some cases, development obligations) arising under
operating agreements, farmout agreements, production sales contracts and other agreements that 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.
12
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.
Corporate Offices
Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We
also maintain a leased 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.
Employees
We had 72 employees as of December 31, 2009, none of whom are currently represented by a union. We believe
that we have good relations with our employees. We employ seven petroleum engineers and four 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 and letters of credit) covering drilling and well operations. Other activities subject to
regulation are:
the location and spacing of wells,
the method of drilling and completing wells,
the rate and method of production,
the surface use and restoration of properties upon which wells are drilled and other exploration
activities,
the plugging and abandoning of wells,
the discharge of contaminants into water and the emission of contaminants into air,
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 outer continental shelf (“OCS”) leases in federal waters are administered by MMS, and
require compliance with detailed MMS regulations and orders. Lessees must obtain MMS approval for
exploration, 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 production
facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees
post bonds, letters of credit, or other acceptable assurances that such obligations will be met. The cost of
13
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.
Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory
restrictions, including various nondiscrimination statues, royalty and related valuation requirements, and
certain of these operations must be conducted pursuant to certain on-site security regulations and other
appropriate permits issued by the MMS or other appropriate federal or state agencies.
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 and state regulation.
If these regulations change, we could face higher transmission costs for our production and, possibly,
reduced access to transmission capacity.
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.
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.
Environmental Regulation. Various federal, state and local laws and regulations concerning the release of
contaminants into the environment, including the discharge of contaminants into water and the emission of
contaminants into the air, the generation, storage, treatment, transportation and disposal of wastes, and the
protection of public health, welfare, and safety, and the environment, including natural resources, affect our
exploration, development and production operations, including operations of our processing facilities. We
must take into account the cost of complying with environmental regulations in planning, designing, drilling,
constructing, operating and abandoning wells. Regulatory requirements relate to, among other things, the
handling and disposal of drilling and production waste products, the control of water and air pollution and
the removal, investigation, and remediation of petroleum-product contamination. In addition, our operations
may require us to obtain permits for, among other things,
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 (e.g., to land or water), emission (e.g., to air) or other activity, we
may be liable for, among other things, penalties, costs and damages, and subject to injunctive relief, and we
could be required to cleanup or mitigate the environmental impacts of those discharges, emissions or
activities. Also, under federal, and certain state, laws, the present and certain past owners and operators 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 hazardous
substances 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 actions. We
therefore 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, irrespective
14
of whether disposal or release were authorized. 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 also irrespective of whether disposal or release were authorized. 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.
Federal, and certain state, laws also impose duties and liabilities on certain “responsible parties” related
specifically to the prevention of oil spills and damages resulting from such spills in or threatening United
States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a
facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge
or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is
located. These laws assign liability, which generally is joint and several, without regard to fault, to each
liable party for oil removal costs and a variety of public and private damages. Although defenses and
limitations exist to the liability imposed under these laws, they are limited. In the event of an oil discharge
or substantial threat of discharge, we could be liable for costs and damages.
The Environmental Protection Agency and various state agencies have limited the disposal options for
hazardous and nonhazardous wastes thereby increasing the costs of disposal. 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.
There are federal and certain state laws that impose restrictions on activities adversely affecting the habitat of
certain plant and animal species. In the event of an unauthorized impact or taking of a protected species or
its habitat, we could be liable for penalties, costs and damages, and subject to injunctive relief, and we could
be required to mitigate those impacts. A critical habitat or suitable habitat designation also could result in
further material restrictions to land use and may materially delay or prohibit land access for oil and natural
gas development.
We have made and will continue to make expenditures to comply with environmental regulations and
requirements. These are necessary costs of doing business within 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. 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.
Greenhouse Gas Legislation (“GHG”). On June 26, 2009, the U.S. House of Representatives passed the
“American Clean Energy and Security Act of 2009” which among other things, would enact a “cap and
trade” system to control GHGs. Under this cap and trade system, a cap on the amount of GHGs would be
established annually, which would be reduced annually. Each covered emission source would be required to
obtain GHG emission allowances corresponding to its annual emissions of GHGs. The Senate has passed
from committee its legislation proposing a similar cap and trade system to regulate GHG emissions, but the
15
Senate legislation has not been voted upon by the full Senate. In the absence of a comprehensive federal
legislation on GHG emission control, the Environmental Protection Agency (“EPA”) has been moving
forward with rulemaking under the Clean Air Act (“CAA”) to regulate GHGs as pollutants under the CAA.
Should EPA regulate GHGs under the CAA, we could incur significant costs to control our emissions and
comply with regulatory requirements. In addition, EPA has adopted a mandatory GHG emissions reporting
program which imposes reporting and monitoring requirements on various industries. We do not believe our
operations will be subject to this program as currently proposed, but there is no guarantee that EPA will not
expand the program to include additional industries. Should we be required to report GHG emissions, it
could require us to incur costs to monitor, keep records of, and report emissions of GHGs.
Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of
uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal
regulation, a number of states, individually and regionally, also are considering or have implemented GHG
regulatory programs. These potential regional and state initiatives may result in so–called cap–and–trade
programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold,
and possibly other regulatory requirements, that could result in our incurring material expenses to comply,
e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The
federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and
natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our
operations to be affected any differently than other similarly situated domestic competitors.
Application of the Safe Drinking Water Act to Hydraulic Fracturing. The Safe Drinking Water Act
regulates, among other things, underground injection operations. Recent legislative activity has occurred
which, if successful, would impose additional regulation under the SDWA upon the use of hydraulic
fracturing fluids. The U.S. Senate and House of Representatives are considering two companion bills
entitled the “Fracturing Responsibility and Chemical Awareness Act of 2009.” If enacted, the legislation
would impose on our hydraulic fracturing operations permit and financial assurance requirements,
requirements that we adhere to construction specifications, fulfill monitoring, reporting and recordkeeping
obligations, and meet plugging and abandonment requirements. In addition to subjecting the injection of
hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would
require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for third
parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific
chemicals used in the process could adversely affect ground water. Neither piece of legislation has been
passed. If this or similar legislation is enacted, we could incur substantial compliance costs, and the
requirements could negatively impact our ability to conduct fracturing activities on our assets.
SDAs. In addition, eleven states have enacted surface damage statutes (“SDAs”). These laws are designed to
compensate for damage caused by mineral development. Most SDAs contain entry notification and
negotiation requirements to facilitate contact between operators and surface owners/users. Most laws also
contain bonding requirements and specific expenses for exploration and operating activities. Costs and
delays associated with SDAs could impair operational effectiveness and increase development costs.
Other Regulations. If we conduct operations on federal, state or Indian oil and natural gas leases, these
operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes,
royalty and related valuation requirements. Certain of these operations must be conducted pursuant to
certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management,
Minerals Management Service or other appropriate federal or state agencies.
16
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.
Availability of Reports
All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and
amendments to such reports as well as other filings we make pursuant to Section 13(a) and 15(d) of the
Securities Exchange Act of 1934 are available free of charge on our Internet website. The address of our
Internet website is www.callon.com. Our SEC filings are available on our website as soon as they are filed with
the SEC.
Item 1A.
Risk Factors
Risk Factors
We may be unable to integrate successfully the operations of recent and future acquisitions with our
operations, and we may not realize all the anticipated benefits of these acquisition. We intend to focus
on producing property acquisitions. Integration of corporate acquisitions with our existing business and
operations will be a complex, time consuming and costly process. We can offer no assurance that we will
achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to
assimilate recent and future acquisitions successfully could adversely affect our financial condition and
results of operations.
Our acquisitions may involve numerous risks, including:
operating a larger combined organization and adding operations;
difficulties in the assimilation of the assets and operations of the acquired business, especially if
the assets acquired are in a new business segment or geographic area;
risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be
developed as anticipated;
loss of significant key employees from the acquired business:
diversion of management’s attention from other business concerns;
failure to realize expected profitability or growth;
failure to realize expected synergies and cost savings;
coordinating geographically disparate organizations, systems and facilities; and
coordinating or consolidating corporate and administrative functions.
17
Further, unexpected costs and challenges may arise whenever businesses with different operations or
management are combined, and we may experience unanticipated delays in realizing the benefits of an
acquisition. If we consummate any future acquisition, our capitalization and results of operation may change
significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant
information that we will consider in evaluating future acquisitions.
We may fail to fully identify problems with any properties we acquire. We acquired a portion of our
acreage position in Louisiana and Texas through acquisitions and acreage trades, and we may acquire
additional acreage in these areas or other regions in the future. Although we conduct a review of properties
we acquire which we believe is consistent with industry practices, we can give no assurance that we have
identified or will identify all existing or potential problems associated with such properties or that we will be
able to mitigate any problems we do identify.
If the United States experiences a sustained economic downturn or recession, oil and natural gas prices
may fall or remain at their current prices for an extended period of time, which may adversely affect
our results of operations. The unprecedented disruption in the United States and international credit
markets in 2008 resulted in a rapid deterioration in the worldwide economy and tightening of the financial
markets. The outlook for the economy in 2010 is uncertain. The current global credit and economic
environment has reduced worldwide demand for energy and resulted in significantly lower oil and natural
gas prices than in earlier periods. A sustained reduction in the prices we receive for our oil and natural gas
production could have a material adverse effect on our results of operations. In addition, any worsening of
domestic and global economic conditions could adversely affect our business and results of operations.
We may not be able to obtain funding on acceptable terms or at all. Global financial markets and
economic conditions have been disrupted and volatile due to a variety of factors. As a result, the cost of
raising money in the debt and equity capital markets and the availability of funds from those markets is
unpredictable. Although we have been able to successfully raise money in the current economic climate and
refinance certain debt instruments, we may not be successful in the future. In addition, lending
counterparties under existing revolving credit facilities and debt instruments may be unwilling or unable to
meet their funding obligations.
Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable
terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable
to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute
our growth strategy, take advantage of other business opportunities or respond to competitive pressures, any
of which could have a negative effect on our revenues and results of operations.
Hedging transactions and receivables expose us to counterparty credit risk. Our hedging transactions
expose us to risk of financial loss if a counterparty fails to perform under a contract. We use master
agreements which allow us, in the event of default, to elect early termination of all contracts with the
defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the
defaulting counterparty would be net settled at the time of election. We also monitor the creditworthiness of
our counterparty on an ongoing basis. However, the current disruptions occurring in the financial markets
could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under
the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s
creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate
the risk may be limited depending upon market conditions.
18
During periods of falling commodity prices, such as in late 2008 and the first half of 2009, our hedge
receivable positions increase, which increases our exposure. If the creditworthiness of our counterparty,
which is a major financial institution, deteriorates and results in its nonperformance, we could incur a
significant loss.
Some of our customers are experiencing, or may experience in the future, severe financial problems that
have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one
or more of our customers will not default on their obligations to us or that such a default or defaults will not
have a material adverse effect on our business, financial position, future results of operations, or future cash
flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or
liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of
amounts owed by the distressed entity or entities. In addition, such events might force such customers to
reduce or curtail their future use of our products and services, which could have a material adverse effect on
our results of operations and financial condition.
The adoption of derivatives legislation or regulations related to derivative contracts could have an
adverse impact on our ability to hedge risks associated with our business. Legislation has been proposed
in Congress and by the Treasury Department to impose restrictions on certain transactions involving
derivatives, which could affect the use of derivatives in hedging transactions. Under proposed legislation,
OTC derivative dealers and other major OTC derivative market participants could be subjected to substantial
supervision and regulation. The legislation generally would expand the power of the Commodity Futures
Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including
oil and natural gas, to mandate clearance of derivative contracts through registered derivative clearing
organizations, and to impose conservative capital and margin requirements and strong business conduct
standards on OTC derivative transactions. The CFTC has proposed regulations that would implement
speculative limits on trading and positions in certain commodities. Although it is not possible at this time to
predict whether or when Congress may act on derivatives legislation or the CFTC may issue new regulations,
any laws or regulations that may be adopted that subject us to additional capital or margin requirements
relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect
on our ability to hedge risks associated with our business or on the cost of our hedging activity.
Depressed 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. Extended periods of
low prices for oil or gas will 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;
our revenues, cash flows and earnings;
our ability to attract capital to finance our operations and the cost of the capital;
the amount we are allowed to borrow under our senior secured credit facility;
the value of our oil and gas properties; and
the profit or loss we incur in exploring for and developing our reserves.
Our reserve information represents estimates that may turn out to be incorrect if the assumptions
upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will materially affect the quantities and present value of our
reserves. The process of estimating oil and gas reserves is complex. It requires interpretations of available
technical data and various assumptions, including assumptions relating to economic factors. Any significant
19
in accuracies 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. We must also analyze available geological, geophysical, production and engineering data, the
extent, completeness, 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.
In addition, the new reserve reporting requirements effective January 1, 2010, represent a significant change
in the types and methods of quantifying reserve, the details of which are still being considered and refined by
the SEC. These changes are the first major modifications to the accounting-based reserve reporting
requirements since 1982. The new SEC rules replace the previous pricing mechanism of using the last day of
the fiscal year by using an average price based on the first day of the last twelve months. In addition, these
new requirements permit oil and gas companies to report not just the proved reserves, but also probable and
possible reserves. While the new rules attempt to provide users of the financial statements with a more
complete picture of the reserves of reporting companies, and recognize new technologies and knowledge
about the geology and extent of oil and natural gas fields, these changes will potentially affect the results of
our reserve estimates. Application of these new, more subjective, reserve reporting rules by competitors may
change our relative positioning in the industry as a whole.
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, 2009, approximately 18% of the discounted present value of our estimated net proved
reserves was PUDs. PUDs represented 34% of total proved reserves. Approximately 71% of the PUDs were
attributable to our deepwater properties.
Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for
information regarding forward-looking information.
Unless we are able to replace reserves that we have produced, our cash flows and production will
decrease over time. Our future success depends upon our ability to acquire, find and develop oil and gas
reserves that are economically recoverable. Without successful exploration or acquisition activities, our
reserves, production and revenues will decline. We cannot assure you that we will be able to find and
develop or acquire additional reserves at an acceptable cost.
20
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 2009, approximately 75% of our daily
production came from four of our properties in the Gulf of Mexico. Moreover, one property accounted for
38% of our production during this period. In addition, at December 31, 2009, most of our proved reserves
were located in two fields in the Gulf of Mexico, with approximately 67% 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 exploration projects increase the risks inherent in our oil and gas activities. Part of our business
strategy is to replace reserves through exploration, where the risks are greater than in acquisitions and
development drilling. Although we have been successful in exploration in the past, we cannot assure you
that we will continue to increase reserves through exploration or at an acceptable cost. Additionally, we are
often uncertain as to the future costs and timing of drilling, completing and producing wells. Our drilling
operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
unexpected drilling conditions;
overpressured formations and resultant blowouts or cratering;
equipment failures or accidents;
adverse weather conditions;
governmental requirements; and
shortages or delays in the availability of drilling rigs and the delivery of equipment.
We do not operate all of our properties, and have limited influence over the operations of some of
these properties, particularly our two deepwater properties. Our lack of control could result in the
following:
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.
Competitive industry conditions may negatively affect our ability to conduct operations. We compete
with numerous other companies in virtually all facets of our business. Our competitors in development,
exploration, acquisitions and production include major integrated oil and gas companies as well as numerous
independents, including many that have significantly greater resources. Therefore, competitors may be able
to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or
prospects than the financial or personnel resources of the Company permit. We also compete for the
materials, equipment and services that are necessary for the exploration, development and operation of our
properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire
suitable prospects for future exploration and development. Factors that affect our ability to compete in the
marketplace include:
21
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;
our ability to procure materials, equipment and services required to explore, develop and operate our
properties; and
our ability to access pipelines, and the location of facilities used to produce and transport oil and
natural gas production.
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.
Further increasing our exposure to this risk, 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 acquire proved producing properties, develop our existing reserves, and to discover
new oil and gas reserves. Historically, we have financed these expenditures primarily with cash from
operations, proceeds from bank borrowings and proceeds from the sale of debt and equity securities. See
“Management’s Discussion and Analysis of Financial Condition and Results of Operations Liquidity and
Capital Resources” for a discussion of our capital budget. We cannot assure you that we will be able to raise
capital in the future. We also make offers to acquire oil and gas properties in the ordinary course of our
business. If these offers are accepted, our capital needs may increase substantially.
Further increasing our exposure to this risk, we expect to continue using our senior secured revolving credit
facility to borrow funds to supplement our available cash. The amount we may borrow under our senior
secured revolving 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 revolving credit facility exceed the borrowing base, the lenders may require that we repay the
excess. If this repayment request were to occur, we might have to sell assets or seek financing from other
sources, which may either be unavailable or available on terms not economically justifiable. 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 revolving 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 revolving credit
facility and its principal terms and conditions, see “Management’s Discussion and Analysis of Financial
Condition and Results of Operations Liquidity and Capital Resources” and Note 7 to our Consolidated
Financial Statements.
22
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 to
drill to a prospect that 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 other geophysical data or the reprocessing of existing data;
material changes in oil or gas prices;
the costs and availability of drilling rigs;
the success or failure of wells drilled in similar formations or which would use the same production
facilities;
availability and cost of capital;
changes in the estimates of the costs to drill or complete wells;
our ability to attract other industry partners to acquire a portion of the working interest to reduce
exposure to costs and drilling risks;
decisions of our joint working interest owners: and
changes to governmental regulations.
We will continue to gather data about our prospects, and it is possible that additional information may cause
us to alter our drilling schedule or determine that a prospect should not be pursued at all. You should
understand that our plans regarding our prospects are subject to change.
Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
impact our ability to conduct business. There are many operating hazards in exploring for and producing
oil and gas, including:
our drilling operations may encounter unexpected formations or pressures, which could cause damage
to equipment or personal injury;
we may experience equipment failures which curtail or stop production;
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;
hurricanes, storms and other weather conditions could cause damages to our production facilities or
wells; and
because of these or other events, we could experience environmental hazards, including release of oil
and gas from 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 persons or loss of life, damage to or destruction of property, natural
resources and equipment, pollution and other environmental damage, investigation and remediation
requirements, and fines and penalties and injunctive relief. 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, which can result in substantial damage to
facilities and interrupt production, as well as 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.
23
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. Additionally, we are required to
pay the difference between the floating price and the fixed price when the floating price exceeds the fixed
price regardless of whether we have sufficient production to cover the quantities specified in the hedge.
Significant reductions in production at times when the floating price exceeds the fixed price could require us
to make payments under the hedge agreements even though such payments are not offset by sales of
production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices
above the fixed amount specified in the hedge.
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:
require that we acquire permits before commencing drilling;
impose operational, emissions control and other conditions on our activities;
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, wilderness areas or coral
reefs; 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 costs of investigation, removal and remediation,
damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property
damages, costs of and increased public services, as well as administrative, civil and criminal fines and
penalties, and injunctive relief. We could also be affected by more stringent laws and regulations adopted in
the future, including any related climate change and greenhouse gases. Under the common law, we could be
liable for injuries to people and property. 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 incidents.
24
Climate Change Legislation or regulations restricting emissions of “greenhouse gasses” could result in
increased operating costs and reduced demand for the oil and gas we produce. On December 15, 2009,
the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon
dioxide, methane and other “greenhouse gases” present an endangerment to public health and the
environment because emissions of such gases are, according to the EPA, contributing to warming of the
earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement
regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean
Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in
emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas
emissions from certain stationary sources.
In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas
emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for
emissions occurring in 2010.
Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security
Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S.
emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17%
reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such
emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of
tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These
reductions would be expected to cause the cost of allowances to escalate significantly over time. The net
effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil,
refined petroleum products, and natural gas.
The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions,
and the Obama Administration has indicated its support for legislation to reduce greenhouse emissions
through an emission allowance system. At the state level, more than one-third of the states, either
individually or through multi-state regional initiatives, already have begun implementing legal measures to
reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing
reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations
could require us to incur costs to accumulate the required data and/or reduce emissions of greenhouse gases
associated with our operations or could adversely affect demand for the oil and natural gas that we produce.
Significant physical effects of climatic change have the potential to damage our facilities, disrupt our
production activities and cause us to incur significant costs in preparing for or responding to those
effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change
could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of
farmland, and water availability and quality. If such effects were to occur, our exploration and production
operations have the potential to be adversely affected. Potential adverse effects could include damages to
our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities
either because of climate-related damages to our facilities in our costs of operation potentially arising from
such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or
increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of
climate change could also have an indirect affect on our financing and operations by disrupting the
transportation or process-related services provided by midstream companies, service companies or suppliers
with whom we have a business relationship. We may not be able to recover through insurance some or any
of the damages, losses or costs that may result from potential physical effects of climate change.
25
Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could
result in increased costs and additional operating restrictions or delays. The U.S. Senate and House of
Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of
Chemicals Act,” or the “FRAC Act,” that would amend the federal Safe Drinking Water Act, or the
“SDWA,” to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would
amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities.
Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance
requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping
obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the
reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for
third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that
specific chemicals used in the fracturing process could adversely affect groundwater. The adoption of any
future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise
limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells and
increase our costs of compliance and doing business.
Factors beyond our control affect our ability to market production and our financial results. The
ability to market oil and gas from our wells depends upon numerous factors beyond our control. These
factors include:
the extent of domestic production and imports of oil and gas;
the proximity of the gas production to gas pipelines;
the availability of pipeline capacity;
the demand for oil and gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of inclement weather;
state and federal regulation of oil and gas marketing; and
federal regulation of gas sold or transported in interstate commerce.
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 or remain depressed for extended periods of time, we may be required to
take additional 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 if we experience 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. See Note 15 to our Consolidated Financial Statements.
26
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 Officer and Chief Financial Officer, 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.
Forward-Looking Statements
In this report, we have made many forward-looking statements. We cannot assure you that the plans,
intentions or expectations upon which our forward-looking statements are based will occur. Our forward-
looking statements are subject to risks, uncertainties and assumptions, including those discussed elsewhere in
this report. Forward-looking statements include statements regarding:
our oil and gas reserve quantities, and the discounted present value of these reserves;
the amount and nature of our capital expenditures;
drilling of wells;
the timing and amount of future production and operating costs;
business strategies and plans of management; and
prospect development and property acquisitions.
Some of the risks, which could affect our future results and could cause results to differ materially from
those expressed in our forward-looking statements, include:
the current global economic downturn;
general economic conditions or including the availability of credit and access to existing lines of
credit
the volatility of oil and natural gas prices;
the uncertainty of estimates of oil and natural gas reserves;
the impact of competition;
the availability and cost of seismic, drilling and other equipment;
operating hazards inherent in the exploration for and production of oil and natural gas;
difficulties encountered during the exploration for and production of oil and natural gas;
difficulties encountered in delivering oil and natural gas to commercial markets;
changes in customer demand and producers’ supply;
the uncertainty of our ability to attract capital and obtain financing on favorable terms;
compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil
and natural gas business including those related to climate change and greenhouse gases;
actions of operators of our oil and gas properties; and
weather conditions.
27
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.
ITEM 1B. Unresolved Staff Comments
None.
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. RESERVED
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
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
2008:
2009:
First quarter
Second quarter
Third quarter
Fourth quarter
First quarter
Second quarter
Third quarter
Fourth quarter
$ 19.22
28.93
28.00
18.06
$ 13.42
17.63
16.18
1.02
$ 3.37
2.93
2.33
2.12
$ 0.94
1.07
1.42
1.42
As of March 8, 2010 there were approximately 3,556 common stockholders of record.
We have never paid dividends on our common stock and intend to retain our cash flow from operations for the
future operation and development of our business. In addition, our primary credit facility and the terms of our
outstanding debt prohibit the payment of cash dividends on our common stock.
During the fourth quarter of 2009, neither we nor any affiliated purchasers made repurchases of our equity
securities.
28
Equity Compensation Plan Information. The following table summarizes information regarding the number
of shares of our common stock that are available for issuance under all of our existing equity compensation
plans as of December 31, 2009.
Plan Category
Equity compensation plans approved by security
holders
Equity compensation for inducement of
employment
Equity compensation plans not approved by
security holders
Total
Number of
securities
to be issued upon
exercise
of outstanding
options
Weighted-average
exercise price of
outstanding
options, warrants
and rights
Number of securities
remaining available
for future issuance
under equity
402,875 $
10.85
1,252,921
500,000
75,483
978,358 $
2.76
6.40
6.37
--
37,466
1,290,387
See Notes 4 and 16 to our Consolidated Financial Statements.
Performance Graph
The following graph compares the yearly percentage change for the five years ended December 31, 2009, 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, 2004 in the Company, the Hemscott Group Index and the New York Stock Exchange Market
Index, and that all dividends were reinvested.
29
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN AMONG CALLON PETROLEUM
COMPANY, NYSE MARKET INDEX AND HEMSCOTT GROUP INDEX
$350.00
$300.00
$250.00
$200.00
$150.00
$100.00
$50.00
S
R
A
L
L
O
D
$0.00
2004
2005
2006
2007
2008
2009
Callon Petroleum Company
NYSE Market Index
Hemscott Group Index
ASSUMES $100 INVESTED ON JAN. 01, 2005
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2009
Company/Index/Market
Callon Petroleum Company
NYSE Market Index
Hemscott Group Index
2004
$100.00
$100.00
$100.00
2005
$122.06
$109.36
$157.64
2006
$103.94
$131.75
$186.69
2007
$113.76
$143.43
$293.61
2008
$ 17.98
$ 87.12
$131.45
2009
$ 10.37
$111.76
$249.89
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, 2009 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.
30
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Years Ended December 31, _
2009
2008
2007
2006 2005
Statement of Operations Data:
Operating revenues:
Oil and gas sales
182,268
170,768
$101,259 $141,312 $170,768 $182,268 $141,290
-- -- -- --
141,290
141,312
18,447
33,443
13,355
3,149
298
19,208
64,054
9,565
4,172
--
-- 498
Medusa MMS royalty recoupment 40,886
Oil and gas sales 142,145
Operating expenses:
24,377
Lease operating expenses
44,946
Depreciation, depletion and amortization
8,085
General and administrative
3,549
Accretion expense
--
Acquisition expense
150 6,028
Derivative expense
Impairment of oil and gas properties
485,498 -- -- --
Total operating expenses
114,418 107,865 86,985
582,995
Income (loss) from operations 73,453 (441,683) 56,350 74,403 54,305
Other (income) expenses:
19,089
Interest expense
7,072
Callon Entrada (non-recourse) interest expense
1,024
9.75% Senior Note restructuring expense
(7,681)
Interest on MMS royalty recoupment
190
Other (income) expense
--
Loss on early extinguishment of debt
Total other (income) expenses 19,694
23,986
2,719
--
--
(1,379)
11,871
37,197
34,329
--
--
--
(1,172)
--
33,157
16,480
--
--
--
(1,869)
--
14,611
16,660
--
--
--
(998)
--
15,662
27,795
72,762
9,876
3,985
--
--
28,881
65,283
8,591
4,960
--
--
68,692
Income (loss) before income taxes
38,643
Income tax expense (benefit) -- (39,725) 8,506 20,707 13,209
53,759
(478,880)
23,193
59,792
Income (loss) before equity in earnings of Medusa Spar LLC
53,759
Equity in earnings of Medusa Spar LLC, net of tax 660
(439,155)
262
14,687
507
39,085
1,475
25,434
1,342
Net income (loss)
(438,893)
Preferred stock dividends -- --
Net income (loss) available to common shares
26,776
318
$ 54,419 $(438,893) $ 15,194 $ 40,560 $ 26,458
15,194
--
40,560
--
54,419
Net income (loss) per common share:
Basic
Diluted
$ 2.47 $ (20.68) $ 0.73 $ 2.00 $ 1.43
$ 2.45 $ (20.68) $ 0.71 $ 1.90 $ 1.28
Shares used in computing net income (loss) per common share:
Basic 22,072 21,222 20,776 20,270 18,453
Diluted 22,200 21,222 21,290 21,363 20,883
31
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Years Ended December 31,
2009
2008
2007
2006
__
2005
Balance Sheet Data (end of period):
Oil and gas properties, net
Total assets
Long-term debt, less current portion
Stockholders' equity (deficit)
$ 130,608 $ 159,252 $ 681,706 $ 547,027 $447,364
$ 227,991 $ 266,090 $ 792,482 $ 625,527 $533,776
$ 179,174 $ 272,855 $ 392,012 $ 225,521 $188,813
$ (80,854) $(129,804) $ 287,075 $ 281,363 $228,048
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. For the year ended December 31,
2008, the Company recorded a $485.5 million impairment of oil and gas properties as a result of the ceiling
test. See Note 15 to the Consolidated Financial Statements.
32
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.”
We have been engaged in the exploration, development, acquisition and production of oil and gas properties
since 1950. Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico.
Following the abandonment of our Entrada project in 2008, we took steps to change our operational focus to
lower risk, onshore exploration and development activities. During 2009, we took the following actions:
We exchanged a new series of senior notes due 2016 and common stock for a substantial portion of
our existing $200 million of senior notes due 2010, and reduced principal from $200 million to $154
million.
We filed for recoupment of deepwater royalty payments, and received a payment from the MMS of
$44.8 million in January 2010. We expect to receive an additional payment from the MMS of
approximately $7.7 million during 2010, representing interest.
We began negotiating a new $100 million revolving credit facility, with a borrowing base of $20
million, which we finalized in January 2010.
These activities were undertaken to allow us to shift our operational focus from the offshore Gulf of Mexico
to longer life, lower risk onshore properties. As part of this strategy, we employed Steven B. Hinchman as
our Chief Operating Officer. Mr. Hinchman has substantial experience in onshore oil and gas acquisition,
exploration and development activities. During 2009, we closed two acquisitions as part of this new focus:
In September 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the
Haynesville Shale play in Bossier Parish, Louisiana for $3.0 million. We plan to drill a total of
seven horizontal wells on this property, with the first two wells to be drilled in 2010. We will be
operator of these wells.
On October 28, 2009, we acquired interests in properties producing from the Wolfberry formation in
Crockett, Ector, Midland and Upton Counties, Texas for total cash consideration of $16.0. The
acquisition included year-end proven reserves of 1.6 MMBoe, 22 existing wells producing 350 Boe
per day and upside from a multi-year inventory of drilling opportunities. We will operate
substantially all of the production and development of these properties.
Deconsolidation of Callon Entrada Company
In June 2009, the FASB issued an accounting standard which amends US GAAP as follows: a) to require an
enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a
controlling financial interest in a variable interest entity (“VIE”), identifying the primary beneficiary of a
VIE, b) to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather
than only when specific events occur, c) to eliminate the quantitative approach previously required for
determining the primary beneficiary of a VIE, d) to amend certain guidance for determining whether an
entity is a VIE, e) to add an additional reconsideration event when changes in facts and circumstances
pertinent to a VIE occur, f) to eliminate the exception for troubled debt restructuring regarding VIE
reconsideration, and g) to require advanced disclosures that will provide users of financial statement with
33
more transparent information about an enterprise’s involvement in a VIE. This pronouncement is effective
for the first annual reporting period that begins after November 15, 2009, with earlier adoption prohibited.
We adopted this pronouncement on January 1, 2010. Upon adoption, we reevaluated our interest in our
subsidiary, Callon Entrada Company (“Callon Entrada”) as a result of the amendments described above.
Based on the evaluation performed applying the new standard, management has concluded that a VIE
reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which
we are not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada will be
deconsolidated from our consolidated financial statements. Deconsolidation will result in the removal of
approximately $1.8 million of current assets, $2.0 million of current liabilities, $30 million of deferred tax
assets, $30 million of valuation allowance and approximately $84.8 million of non-recourse debt and related
obligation for the cumulative amount of interest. Retained earnings will be increased by $85.1 million as a
cumulative effect of change related to this accounting standard. No gain will be reflected in the statement of
operations. See Note 2 to our Consolidated Financial Statements.
2010 OUTLOOK
In 2009, we set our course and began to re-shape our portfolio. We recognized that continuing to solely
focus on the Gulf of Mexico shelf and deep water could not sustain profitable growth at an acceptable level
of risk. We needed to initiate a transition of resources from offshore to a more diverse and lower risk
resource base located both onshore and offshore. We focused our attention on the Permian Basin for oil and
the shale gas plays.
In the Permian Basin we plan to drill and complete 16 wells in 2010. These wells are expected to more than
double our current Permian Basin production of 350 Boe per day by the end of the year.
In the Haynesville Shale gas play, we plan to drill two wells in 2010. We expect to spud the first well by
mid-year and have both wells completed and producing in the fourth quarter of 2010.
We are estimating full year production from our current properties of between 27 and 31 million cubic feet
of natural gas equivalent (“MMcfe”) per day, with an exit rate of approximately 35 MMcfe per day.
Additionally, any acquisition in 2010 would positively contribute to these estimates.
Our lease operating expense, including severance tax, is expected to range between $18 million and $22
million in 2010 with abandonment costs estimated to be $4 million.
Our new onshore properties along with the strong cash flow from our Gulf of Mexico operations have
already begun to re-shape our portfolio and outlook. We are well positioned to continue the pursuit of
diversifying our portfolio by building profitable growth opportunities onshore.
Factors potentially impacting our expected production profile include:
a reduced level of capital expenditures, as discussed below;
allocation of capital expenditures to acquire producing properties;
natural field decline in the deepwater Gulf of Mexico and Gulf Coast areas of our US operations;
timing of well completions in the Permian Basin and Haynesville Shale development programs;
potential hurricane-related downtime and volume curtailments in the Gulf of Mexico and Gulf Coast
areas; and
inflation of capital costs and operating expenses.
2010 Budget—We have designed a flexible capital spending program that can be funded from cash on hand
and cashflows from operations. Our preliminary base capital program includes the development of our
Permian Basin assets as well as exploiting our Haynesville Shale play. Including plugging and
34
abandonment, capitalized interest and general and administrative costs our 2010 capital budget is $61.7
million. We do have a $20 million available borrowing base that could be used for an attractive strategic
opportunity. However, depending on commodity prices and other economic conditions we experience in
2010, this base capital program may be adjusted up or down.
Inflation has not had a material impact on us, nor is it expected to have a material impact on us in the immediate
future.
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 estimated 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:
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;
payroll costs including the 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 guidance for accounting of asset retirement obligations;
and
estimated 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 plus estimated future development costs 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 depletable base, our depletion rates may materially change if actual results differ from these
estimates.
35
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 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, the use of the
subsequent pricing is allowed and no write-down would be required. 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. See Note 15 to our
Consolidated Financial Statements.
Estimating Reserves and Present Value of Estimated Future Net Cash Flows. The estimates of quantities of
proved oil and gas reserves including 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:
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 remain constant. 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 some of 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; and
the costs to develop and produce our reserves and the costs to dismantle our production facilities when
reserves are depleted. These costs are likely to change over time, but we are required to assume that
costs in effect at the end of the quarter will not change. Increases in costs will reduce estimated oil and
gas quantities and the present value of estimated future net cash flows, while decreases in costs will
increase such amounts. Because some of 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.
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.”
Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss
recognized unless the adjustment would significantly alter the relationship between capitalized costs and
proved reserves.
In December 2008 the SEC approved amendments to its oil and gas reserves estimation and disclosure
requirements. The amendments, among other things:
allow the use of reliable technologies to estimate proved reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve volumes;
require disclosure of oil and gas proved reserves by significant geographic area;
permit the optional disclosure of probable and possible reserves;
36
modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average
beginning-of-the-month price instead of a period-end price; and
require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the
company make disclosures relating to the independence and qualifications of the third party,
including filing as an exhibit any report received from the third party.
The new requirements are effective for our year-end financial statements and our Annual Report on Form
10-K for the year ended December 31, 2009. We have adopted the new requirements, which had no material
impact on our financial statements.
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 are required to record our estimate of the fair value of liabilities for
obligations associated with the retirement of tangible long-life 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 11 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.
Our derivative contracts, which are accounted for as cash flow hedges, are recorded at fair market value with
changes in fair value 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). See Note 8 to our
Consolidated Financial Statements.
Our derivative contracts are carried at fair value on our consolidated balance sheet under the caption “Fair
Market Value of Derivatives”. The oil and gas derivative contracts are settled based upon reported prices on
NYMEX. The estimated fair value of these contracts is based upon closing exchange prices on NYMEX and
in the case of collars and floors, the time value of options. See Note 9, “Fair Value Measurements” to our
Consolidated Financial Statements.
In March 2008, the FASB issued guidance for disclosures about derivative instruments and hedging activities.
Under the guidance changes the disclosure requirements for derivative instruments and hedging activities,
entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative
instruments, (b) how derivative instruments and related hedged items are accounted for under GAAP, and (c)
how derivative instruments and related hedged items affect an entity’s financial position, financial performance,
and cash flows. We adopted the guidance on January 1, 2009 and have added certain additional disclosures to
our financial statements.
37
Fair Value Measurements. We adopted guidance issued by the FASB for fair value measurements which
defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair
value measurements. We also adopted guidance issued by the FASB for the fair value option for financial
assets and liabilities, which permits entities to choose to measure various financial instruments and certain
other items at fair value. See Note 9 to our Consolidated Financial Statements.
Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary
differences due to different reporting methods for oil and gas properties for financial reporting purposes and
income tax purposes. GAAP provides for the recognition of a deferred tax asset for net 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 will not
be realized.
Share-Based Compensation. We account for share-based compensation under guidance issued by the FASB.
In June 2008, FASB issued guidance determining whether instruments granted in share-based compensation
transactions are participating securities. The guidance addresses whether instruments granted in share-based
compensation transactions are participating securities prior to vesting and, therefore, need to be included in the
earnings allocation in computing earnings per share under the two-class method described in the FASB issued
guidance for earning per share.” We adopted this guidance on January 1, 2009 with no impact to its financial
statements.
Business Combinations. In December 2007, the FASB issued an accounting standard to improve the
relevance, representational faithfulness, and comparability of the information that a reporting entity provides in
its financial reports about a business combination and its effects. To accomplish that, the standard establishes
principles and requirements for how the acquirer (a) recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (b)
recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase,
and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature
and financial effects of the business combination. The business combination guidance is effective for business
combinations with an acquisition date on or after the beginning of annual reporting period beginning on or after
December 15, 2008. The standard requires an acquirer to recognize 100% of the fair values of acquired assets,
with limited exceptions, even if the acquirer has not acquired 100% of its target. Additionally contingent
consideration arrangements and preacquisition contingencies will be measured at fair value on the acquisition
date and included in the basis of the purchase price. Transaction costs are expensed as incurred and not
considered as part of the fair value of the acquisition; however, acquired research and development are no longer
expensed at acquisition, but instead are capitalized as an indefinite-lived intangible asset. We adopted this
accounting standard on January 1, 2009, and was applied to our ExL acquisition during 2009. See Note 13 for
the impact of the acquisition on our Consolidated Financial Statements.
Subsequent Events. In May 2009, the FASB issued guidance for subsequent events. The objective of this
guidance is to establish general standards of accounting for and disclosures of events that occur after the
balance sheet date but before financial statements are issued or are available to be issued. We adopted the
guidance as of the quarter ended June 30, 2009 with limited impact to its financial statements. See Note 20
to our consolidated financial statements.
Recent Accounting Standards
See Note 2 to our Consolidated Financial Statements.
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 $13.5
38
million during 2009 to $3.6 million. Cash provided from operating activities during 2009 totaled $26.4
million, a decrease of 72% from $93.2 million in 2008. The decrease in liquidity is attributable to the
reduction of accounts payable related to the Entrada project and lower commodity prices.
During 2009, we recorded a receivable attributable to a recoupment of royalty overpayments we previously
made on our deep water properties. Following the decisions in several court cases, it was determined that the
MMS was not entitled to receive these royalty payments, and accordingly refunded the payments previously
made. We received the principal payment of $44.8 million in January 2010, and expect to receive a payment
of approximately $7.7 million representing interest on the amounts previously withheld during 2010. See
Note 12 to our Consolidated Financial Statements.
On September 25, 2008, we closed on a four-year second amended and restated senior secured revolving
credit facility with Union Bank N.A. as administrative agent and issuing lender. The borrowing base was
$16.2 million at December 31, 2009. There was $10 million outstanding under the credit facility at
December 31, 2009.
Subsequent to December 31, 2009, our senior secured credit agreement was amended to include Regions
Bank as the sole arranger and administrative agent. The third amended and restated senior secured credit
agreement, which matures on September 25, 2012, provides for a $100 million facility with an initial
borrowing base of $20 million, which will be reviewed and re-determined on a semi-annual basis. The third
amended and restated credit facility bears interest at 4% above a defined base rate and in no event will the
interest rate be less than 6%. In addition, a commitment fee of 0.5% per annum on the unused portion of the
borrowing base, is payable quarterly. Subsequent to December 31, 2009, simultaneously with the execution
of the third amended and restated senior secured credit agreement, the Company repaid the $10 million
outstanding on the borrowing base under the second amended and restated senior secured credit agreement.
See Notes 7 and 20 to our Consolidated Financial Statements.
During the fourth quarter of 2009, we completed an exchange offer for our outstanding 9.75% Senior Notes
due December 2010 (“Senior Notes”). For each $1,000 principal amount of outstanding Senior Notes tendered
in accordance with the terms and conditions of the exchange offer, each tendering holder of the Senior Notes
received $750 principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of
common stock and 1.6875 shares of Convertible Preferred Stock. Holders of approximately 92% of the Senior
Notes tendered their notes in the exchange offer. On December 31, 2009, each share of the Convertible
Preferred Stock was automatically converted by us into 10 shares of common stock following shareholder
approval of the conversion and the filing of an amendment to our charter increasing the number of authorized
shares of common stock as necessary to accommodate such conversion. We issued 6.9 million shares of
common stock related to the conversion of the Convertible Preferred Stock. In connection with the exchange
offer, holders who tendered Senior Notes consented to amend the indenture governing the Senior Notes,
eliminating substantially all of the indenture’s restrictive covenants. The outstanding principal amount of the
remaining Senior Notes is $16.1 million and the face value of the Exchange Notes is $137.9 million as of
December 31, 2009. In addition, we have reserved $16.1 million from proceeds received from the MMS
recoupment to retire the remaining Senior Notes during 2010.
The Company determined that the note exchange should be accounting for in accordance with guidance
provided by the FASB for accounting for a troubled debt restructuring. Immediately before the issuance of the
Exchange Notes, the total future cash payments on the restructured Senior Notes was less than the remaining
carrying amount of the Senior Notes after the carrying amount was reduced by the fair value of the equity
interests issued of $11.5 million. Therefore, as of November 23, 2009, in accordance with the troubled debt
restructuring accounting standard, the Company reduced the carrying amount of the Senior Notes by the fair
value of the common and preferred stock issued. The difference between the adjusted carrying amount of the
Senior Notes and the face value of the Exchange Notes was recorded as a deferred credit of $31.2 million which
will be amortized as a credit to interest expense at an 8.5% effective interest rate over the life of the Exchange
39
Notes. In addition, the Company incurred $1.0 million of costs associated with the note exchange and expensed
the amount in the fourth quarter of 2009 in accordance with the trouble debt restructuring accounting standard.
See Note 7 to our Consolidated Financial Statements.
The indentures governing our Exchange Notes 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, 2009.
In April 2008, our wholly owned subsidiary, Callon Entrada, entered into a credit agreement with CIECO
Energy (Entrada) LLC (“CIECO Entrada”) pursuant to which Callon Entrada could borrow up to $150
million, plus interest expense incurred of up to $12 million, to finance the development of the Entrada
project. The Callon Entrada credit agreement is a direct obligation of Callon Entrada. The Callon Entrada
credit agreement is secured by a lien on the assets of Callon Entrada, which subsequent to the lease
expiration of the Entrada Field, is comprised solely from the remaining related equipment previously
purchased during the development phase. Neither Callon Petroleum nor any other subsidiary of Callon
Petroleum guaranteed or otherwise agreed to pay the principal or interest payments due on the Callon
Entrada credit agreement, so such facility is effectively non-recourse to Callon Petroleum and its other
subsidiaries.
During 2008, Callon Entrada borrowed $78.4 million under the facility and as of December 31, 2009.
CIECO Entrada had failed to fund $40 million of loan requests which were due in October and November of
2008. We are in discussions with CIECO and CIECO Entrada with regard to these loan requests. No
assurances can be made regarding the outcome of these discussions. We do not believe that we have waived
any of our rights under our agreements with CIECO or CIECO Entrada.
On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that
certain alleged events of default occurred under the credit agreement relating to failure to pay interest when
due and the breach of various other covenants related to the decision to abandon the Entrada project. The
notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon Entrada
credit agreement to accelerate payment of the principal and interest due. The acceleration of payment causes
the principal and interest balances under the Callon Entrada credit agreement to be reclassified as current
liabilities from long-term liabilities under US GAAP. The agreement has not been legally extinguished and
as such under US GAAP, the agreement remains a liability of Callon Entrada. We are currently required to
continue to consolidate the financial statements and results of operations of Callon Entrada which results in
Callon Entrada’s liability being reflected in a separate line item in the consolidated financial statements.
Based on the advice of counsel, we believe that the Callon Entrada credit agreement does not obligate Callon
or any of its subsidiaries (other than Callon Entrada) to pay principal, accrued interest or other amounts
which may be owed under such credit agreement. See Notes 2 and 3 to our Consolidated Financial
Statements.
Operating Activities. During the year ended December 31, 2009, net cash provided by operating activities
was $ 26.4 million, a 72% decrease from $ 93.2 million for the same period in 2008. The decrease in net cash
provided by operating activities was largely attributable to the reduction of accounts payable related to the
Entrada project and lower commodity prices during the year ended December 31, 2009 as compared to the
same period in 2008.
Investing Activities. During the year ended December 31, 2009, net cash used in investing activities was
$49.8 million as compared to $8.7 million for the same period in 2008. The increase in net cash used in
investing activities is the timing of payments associated with capital costs incurred during 2008 for the
Entrada project and paid during 2009.
40
Financing Activities. During the year ended December 31, 2009, net cash provided by financing activities
was $10.0 million as compared to net cash used in financing activities of $120.7 million for the same period
in 2008. The increase in cash provided by net financing activities is primarily attributable to the debt
retirement of the $200 million senior secured revolving credit agreement during 2008 that was used to
purchase BP Exploration and Production Company‘s interest in the Entrada Fields. See Note 3 to our
Consolidated Financial Statements.
Our current planned capital expenditures for 2010 total $58 million and include capitalized interest and general
and administrative expenses. The current portion of our asset retirement obligation will require an additional
$4 million resulting in capital expenditures of $62 million for 2010. The current capital expenditure plans
for 2010 include:
drilling and completing up to 16 wells in the Permian Basin;
drilling two wells in the Haynesville Shale play;
lease and seismic acquisition; and
capitalized interest and overhead.
We believe that our cash on hand and operating cash flow along with our credit facility, if needed, will be
adequate to meet our capital, debt repayment, and operating requirements for 2010. We fund our day-to-day
operating expenses and capital expenditures from operating cash flow, supplemented as needed by
borrowings under our credit facilities.
The following table describes our outstanding contractual obligations as of December 31, 2009 (in
thousands):
Payments due by Period
More
Contractual Less Than One-Three Three-Five Than-Five
Years Years Years__
Total One Year
Obligations
--
$ 10,000
Senior Secured Credit Facility
13% Senior Notes
137,961
137,961
9.75% Senior Notes 16,052
-- --
Throughput Commitments:
27 13
Medusa Oil Pipeline 163
$164,176 $ 16,113 $ 10,062 $ 27 $ 137,974
$ -- $ 10,000
--
--
--
16,052
-- $
--
62
61
$
The Callon Entrada non-recourse credit agreement is not included in the contractual obligations table
because it is a direct obligation of Callon Entrada, an indirect, wholly owned subsidiary of Callon. Neither
Callon nor any other subsidiary of Callon guaranteed or otherwise agreed to pay the principal and interest
payments due on the Callon Entrada non-recourse credit agreement, so this agreement is effectively non-
recourse to Callon and its other subsidiaries. See Notes 2 and 3 to our Consolidated Financial Statements.
41
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 at our Medusa Field in
the Gulf of Mexico. In December 2003, 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 allowed 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. In the
second quarter at 2008, the non-recourse financing was extinguished. The balance of Medusa Spar LLC is
owned by Oceaneering International, Inc. and Murphy. We are accounting for our 10% ownership interest in
the LLC under the equity method.
42
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, 2009.
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, .
2009 2008 2007 .
1,012
5,740
11,809
32.4
942
5,839
11,494
31.4
1,063
12,340
18,718
51.3
$ 73.00
$ 4.78
$ 8.57
$ 88.07
$ 9.99
$ 12.29
$ 67.63
$ 8.01
$ 9.12
Oil and gas revenues (in thousands):
$ 71,891
Oil revenue
Gas revenue 27,417 58,349 98,877
$170,768
Total
$141,312
$101,259
$ 82,963
$ 73,842
Lease operating expenses (in thousands)
$ 18,447
$ 19,208
$ 27,795
Additional per Mcfe data:
Sales price
$ 9.12
Lease operating expenses 1.56 1.67 1.48
$ 7.64
Operating margin
$ 7.01
$ 12.29
$ 10.62
$ 8.57
$ 2.83
Depletion
General and administrative (net of management fees) $ 1.13
$ 5.57
$ .83
$ 3.89
$ .53
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
Average NYMEX oil price
$ 72.33
Basis differential and quality adjustments (4.64) (1.15) (4.08)
Transportation (1.32) (1.15) (1.15)
Hedging 17.16 (9.30) 0.53
$ 88.07 $ 67.63
Average realized oil price
$ 73.00
$ 99.67
$ 61.80
43
Comparison of Results of Operations for the Years Ended December 31, 2009 and 2008
Oil and Gas Revenues
Total oil and gas revenues decreased 28% from $141.3 million in 2008 to $101.3 million in 2009 due to lower
oil and gas pricing. Total production on an equivalent basis for 2009 increased 3% from 2008 production.
Gas production during 2009 totaled 5.7 Bcf and generated $27.4 million in revenues compared to 5.8 Bcf and
$58.3 million in revenues during the same period in 2008. Average gas prices realized for 2009 were $4.78 per
Mcf compared to $9.99 per Mcf during the same period in 2008. The 2% decrease in 2009 production was
primarily normal and expected declines from our legacy properties.
Oil production during 2009 totaled 1,012,000 barrels and generated $73.8 million in revenues compared to
942,000 barrels and $83.0 million in revenues for the same period in 2008. Average oil prices realized in 2009
were $73.00 per barrel compared to $88.07 per barrel in 2008. See the Results of Operations table for a
reconciliation of the realized oil prices to average NYMEX. The 7% increase in 2009 production was primarily
due to the 2009 volumes associated with the MMS royalty recoupment for the Medusa Field. See Note 12 to our
Consolidated Financial Statements.
Lease Operating Expenses
Lease operating expenses for 2009 decreased by 4% to $18.4 million compared to $19.2 million for the same
period in 2008. The decrease was primarily due to a lower number of producing wells in the Gulf of Mexico
Shelf area. Four of our gas wells were shut-in during 2008 due to early water production and are plugged and
abandoned or scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was
shut-in during the second quarter of 2008, due to a plugged flowline, which management determined
uneconomic to repair. This well was plugged in the second half of 2009.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 2009 and 2008 totaled $33.4 million and $64.1 million,
respectively. The 48% decrease was due to a lower depletion rate resulting from the full-cost ceiling writedown,
which was recorded in the fourth quarter of 2008 and the downward revision of plugging and abandonment cost
for the Entrada field during 2009.
Impairment of Oil and Gas Properties
During the fourth quarter of 2008, capitalized costs of oil and gas properties, net of accumulated amortization
and deferred taxes relating to oil and gas properties, exceeded 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. As a result, $485.5 million of excess costs was expensed as an impairment of oil
and gas properties for the year ended December 31, 2008. See Note 15 to the Consolidated Financial
Statements.
Accretion Expense
Accretion expense for 2009 and 2008 of $3.1 million and $4.2 million, respectively, represents accretion of
our asset retirement obligations. See Note 11 to the Consolidated Financial Statements.
44
General and Administrative
General and administrative expenses for 2009, net of amounts capitalized, were $13.4 million compared to $9.6
million in 2008. The 43% increase was primarily due to the $2.2 million of nonrecurring expenses for staffing
reductions and retirements and the result of overhead fees of approximately $2.6 million received during the
second half of 2008 as operator of the Entrada Field, which was recorded as a reduction to general and
administrative expenses in 2008.
Acquisition Expense
As a result of the ExL acquisition, we incurred $298,000 of costs in the fourth quarter of 2009 for consultant and
legal expenses. See Note 13 to our Consolidated Financial Statements.
Interest Expense
Interest expense related to debt obligations decreased to $19.1 million in 2009 compared to $24.0 million in
2008. This 20% decrease was due to the retirement in April 2008 of the $200 million senior revolving credit
facility associated with the Entrada acquisition. See Note 7 to the Consolidated Financial Statement for more
details.
Callon Entrada Non-Recourse Credit Agreement Interest Expense
We incurred interest expense under the Callon Entrada credit agreement for the twelve-month periods ended
December 31, 2009 and 2008 of $7.1 million and $2.7 million, respectively. The increase was due to a
larger outstanding loan balance for the twelve-month period ended December 31, 2009 and an increase in the
interest rate due to the notice of default received from CIECO on April 2, 2009. Principal and related
interest was payable from the assets of Callon Entrada, primarily production from the Entrada Field with no
recourse to the assets of Callon. Accordingly, due to the abandonment of the Entrada project, no cash
payments for principal or interest have been made by Callon Entrada except with proceeds from our 50%
share of the sale of surplus equipment. See Note 3 to the Consolidated Financial Statements for details.
Loss on Early Extinguishment of Debt
Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, we
incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash
charge of $5.6 million related to the amortization expense associated with the deferred financing costs
related to the senior revolving credit facility. See Note 7 to the Consolidated Financial Statements for more
details.
Debt Restructuring Expense
As a result of the 9.75% Senior Note exchange for the 13% Senior Notes we incurred $1.0 million of
financing cost in the fourth quarter of 2009 for consultant and legal expenses. See Note 7 to the Consolidated
Financial Statements for more details.
45
Income Taxes
For 2009, income tax expense was zero compared to an income tax benefit of $39.7 million in 2008. The
income tax benefit in 2008 was primarily the result of expensing the impairment of oil and gas properties in
the amount of $485.5 million. We established a valuation allowance of $128.1 million as of December 31,
2008. We revised the valuation allowance for the twelve-month period ended December 31, 2009 as a result
of current year ordinary income, the impact of which is included in our effective tax rate. See Note 6 to the
Consolidated Financial Statements.
Comparison of Results of Operations for the Years Ended December 31, 2008 and 2007
Oil and Gas Revenues
Total oil and gas revenues decreased 17% from $170.8 million in 2007 to $143.1 million in 2008 primarily due
to lower gas production. Total production on an equivalent basis for 2008 decreased by 39% versus 2007.
Gas production during 2008 totaled 5.8 Bcf and generated $58.3 million in revenues compared to 12.3 Bcf and
$98.9 million in revenues during the same period in 2007. Average gas prices realized for 2008 were $9.99 per
Mcf compared to $8.01 per Mcf during the same period in 2007. The 53% decrease in 2008 production was
primarily due to the sale of our Mobile Bay Field on Blocks 952, 953, and 955, effective May 1, 2007, a lower
number of producing wells, downtime resulting from Hurricanes Gustav and Ike and normal and expected
declines in production from our older properties. Three of our gas wells were shut-in due to early water
production, two of which are now scheduled for plugging and abandonment, and the third was sold for the
plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the
second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to
repair.
Oil production during 2008 totaled 942,000 barrels and generated $83.0 million in revenues compared to
1,063,000 barrels and $71.9 million in revenues for the same period in 2007. Average oil prices realized in 2008
were $88.07 per barrel compared to $67.63 per barrel in 2007. The 11% decrease in 2008 production was
primarily due to downtime resulting from Hurricanes Gustav and Ike and normal and expected declines in
producing wells. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008,
due to a plugged flowline, and management has determined it to be uneconomic to repair. See the Results of
Operations table for a reconciliation of the realized oil prices to average NYMEX.
Lease Operating Expenses
Lease operating expenses for 2008 decreased by 31% to $19.2 million compared to $27.8 million for the same
period in 2007. The decrease was primarily due to the sale of the Mobile Bay Field on Blocks 952, 953 and 955
effective May 1, 2007, a lower number of producing wells and downtime in the third and fourth quarters of 2008
caused by Hurricanes Gustav and Ike resulting in lower throughput charges. Three of our gas wells were shut-in
due to early water production, two of which are now scheduled for plugging and abandonment, and the third was
sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in
during the second quarter of 2008, due to a plugged flowline, and management has determined it to be
uneconomic to repair.
46
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 2008 and 2007 totaled $64.1 million and $72.8 million,
respectively. The 12% decrease was due to lower production volumes which were partially offset by a higher
depletion rate. The 43% increase in the depletion rate from 2007 to 2008 was higher Entrada development costs
in addition to the abandonment of operations.
Impairment of Oil and Gas Properties
During the fourth quarter of 2008, capitalized costs of oil and gas properties, net of accumulated amortization
and deferred taxes relating to oil and gas properties exceeded 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. As a result, $485.5 million of excess costs was expensed as an impairment of oil
and gas properties for the year ended December 31, 2008. See Note 15 to the Consolidated Financial
Statements.
Accretion Expense
Accretion expense for 2008 and 2007 of $4.2 million and $4.0 million, respectively, represents accretion of
our asset retirement obligations. See Note 11 to the Consolidated Financial Statements.
General and Administrative
General and administrative expenses for 2008, net of amounts capitalized, were $9.6 million compared to $9.9
million in 2007, or a 3% decrease.
Interest Expense
Interest expense decreased to $26.7 million in 2008 compared to $34.3 million in 2007. This decrease was
due to the retirement of the $200 million senior revolving credit facility associated with the Entrada
acquisition. See Note 7 to the Consolidated Financial Statement for more details.
Loss on Early Extinguishment of Debt
Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, we
incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash
charge of $5.6 million related to the amortization expense associated with the deferred financing costs
related to the senior revolving credit facility. See Note 7 to the Consolidated Financial Statements for more
details.
Income Taxes
For 2008, we recorded an income tax benefit of $39.7 million compared to an income tax expense of $8.5
million in 2007. The income tax benefit in 2008 was primarily the result of expensing the impairment of oil
and gas properties in the amount of $485.5 million. We evaluated our deferred income tax asset in light of
our reserve quantity estimates, our long-term outlook for oil and gas prices and our expected level of future
revenues and expenses and based upon this evaluation, we believe it is more likely than not, that we will not
realize the recorded deferred income tax asset. As a result, we have established a valuation allowance in the
amount of $128.1 million, as of December 31, 2008, the amount of the deferred income tax asset. See Note 6
to the Consolidated Financial Statements.
47
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Price Risk
Our revenues are derived from the sale of our crude oil and natural gas production. Prices for oil and gas
remain extremely volatile, sometimes experiencing large fluctuations as a result of relatively small changes
in supply, weather conditions, economic conditions and government actions. From time to time, we enter
into derivative financial instruments to manage oil and gas price risk.
We may utilize fixed price “swaps,” which reduce our exposure to decreases in commodity prices and limit
the benefit we might otherwise have received from any increases in commodity prices.
We 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
us, and if the price rises above the ceiling, the counter-party receives the difference from us.
We may purchase “puts” which reduce our 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 us.
We enter into these various agreements from time to time to reduce the effects of volatile oil and gas prices
and do not enter into derivative transactions for speculative purposes. However, certain of our derivative
positions may not be designated as hedges for accounting purposes. See Note 8 to the Consolidated
Financial Statements for a description of our hedged position at December 31, 2009.
Based on projected annual sales volumes for 2010 (excluding production from 2010 exploratory drilling), a
10% decline in the prices we receive for its crude oil and natural gas production would result in an
approximate $9.6 million reduction of our revenues.
48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2009
and 2008
Consolidated Statements of Operations for Each of the Three Years
in the Period Ended December 31, 2009
Consolidated Statements of Stockholders' Equity (Deficit)
for Each of the Three Years in the Period Ended December 31, 2009
Consolidated Statements of Cash Flows for Each of the Three Years
in the Period Ended December 31, 2009
Notes to Consolidated Financial Statements
Page
50
51
52
53
54
55
49
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of
December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders' equity
(deficit) and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the
consolidated results of its operations and its cash flows for each of the three years in the period ended December
31, 2009, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the financial statements, in 2008 the Company changed its method of accounting
for income taxes. In 2009, the Company changed its reserve estimates and related disclosures as a result of
adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), Callon Petroleum Company’s internal control over financial reporting as of December 31,
2009, 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 12, 2010, expressed an
unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 12, 2010
50
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Accounts receivable-MMS royalty recoupment
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
Restricted investments
Investment in Medusa Spar LLC
Other assets, net
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities
Asset retirement obligations
9.75% Senior Notes
Callon Entrada (non-recourse) credit facility (See Note 3)
Total current liabilities
Senior Notes (See Note 7)
Principal outstanding
Deferred credit
Discount
Total Senior Notes
Senior secured revolving credit facility
Callon Entrada (non-recourse) credit facility (See Note 3)
Total long-term debt
Asset retirement obligations
Other long-term liabilities
Total liabilities
Stockholders' equity (deficit):
Preferred Stock, $.01 par value; 2,500,000 shares authorized;
Common Stock, $.01 par value; 60,000,000 shares
authorized; 28,742,926 shares and 21,621,142 shares issued
outstanding at December 31, 2009 and 2008, respectively
Capital in excess of par value
Other comprehensive income (loss)
Retained (deficit) earnings
Total stockholders' equity (deficit) (See Note 2)
Total liabilities and stockholders' equity (deficit)
December 31,
2008
2009
$ 3,635 $ 17,126
44,290
--
21,780
1,103
84,299
20,798
51,534
145
1,572
77,684
1,593,884
(1,488,718 )
105,166
1,581,698
(1,455,275 )
126,423
25,442
130,608
32,829
159,252
2,508
4,065
11,537
1,589
2,536
4,759
12,577
2,667
$ 227,991 $ 266,090
$ 12,887 $ 76,516
9,151
--
4,002
15,820
32,709
84,847
117,556
--
85,667
137,961
31,213
--
169,174
10,000
--
179,174
10,648
1,467
308,845
200,000
--
(5,580)
194,420
81,154
275,574
33,043
1,610
395,894
--
--
287
243,898
(7,478 )
(317,561 )
(80,854 )
216
227,803
14,157
(371,980 )
(129,804 )
$ 227,991 $ 266,090
The accompanying notes are an integral part of these financial statements.
51
Consolidated Statements of Operations
(In thousands, except per share amounts)
Callon Petroleum Company
Year Ended December 31,
2008
2009
2007
Operating revenues:
Oil sales
Gas sales
MMS royalty recoupment (See Note 12)
Total operating revenues
Operating expenses:
Lease operating expenses
Depreciation, depletion and amortization
General and administrative
Accretion expense
Acquisition expenses (See Note 13)
Derivative expense
Impairment of oil and gas properties
Total operating expenses
$ 73,842
27,417
40,886
142,145
$ 82,963
58,349
--
141,312
$ 71,891
98,877
--
170,768
18,447
33,443
13,355
3,149
298
--
--
68,692
19,208
64,054
9,565
4,172
--
498
485,498
582,995
27,795
72,762
9,876
3,985
--
--
--
114,418
Income (loss) from operations
73,453
(441,683)
56,350
Other (income) expenses:
Interest expense
Callon Entrada (non-recourse) credit facility interest expense
(See Note 3)
Loss on early extinguishment of debt
9.75% Senior Notes restructuring expenses (See Note 7)
Interest on MMS royalty recoupment
Other (income) expense
Total other (income) expenses
Income (loss) before income taxes
Income tax (benefit) expense
19,089
23,986
34,329
7,072
--
1,024
(7,681)
190
19,694
2,719
11,871
--
--
(1,379)
37,197
53,759
--
(478,880)
(39,725)
--
--
--
--
(1,172)
33,157
23,193
8,506
14,687
507
Income (loss) before equity in earnings of Medusa Spar LLC
Equity in earnings of Medusa Spar LLC
53,759
660
(439,155)
262
Net income (loss) available to common shares
$ 54,419
$(438,893)
$ 15,194
Net income (loss) per common share:
Basic
Diluted
$ 2.47
$ 2.45
$ (20.68)
$ (20.68)
$ 0.73
$ 0.71
Shares used in computing net income (loss) per share amounts:
Basic
Diluted
22,072
22,200
21,222
21,222
20,776
21,290
The accompanying notes are an integral part of these financial statements.
52
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
(In thousands)
Accumulated Total
Preferred Common Excess of Comprehensive Earnings holders’
Capital in
Other Retained Stock-
Stock Stock Par Value Income (Loss) (Deficit) Equity (Deficit)
Balances, December 31, 2006 $ -- $ 207 $ 220,785
$ 8,652 $ 51,759 $ 281,363
Comprehensive income:
Net income --
Other comprehensive loss --
Total comprehensive income
Tax benefits related to stock
compensation plans --
Restricted stock --
--
--
--
--
-- (12,035)
15,194
--
3,159
--
163
2 2,388
--
--
--
--
163
2,390
Balances, December 31, 2007 --
209 223,336
(3,383) 66,913 287,075
Comprehensive income (loss):
Net loss --
Other comprehensive income --
Total comprehensive loss
Shares issued pursuant to employee
benefit and option plan --
Tax benefits related to stock
compensation plans --
2,050
1 3,575
Restricted stock --
Warrants -- 5 (5)
1 (1,153)
--
--
--
--
--
-- (438,893)
17,540
--
(421,353)
--
-- (1,152)
--
--
-- -- --
-- 3,576
-- 2,050
Balances, December 31, 2008 --
216 227,803
14,157 (371,980) (129,804)
Comprehensive income:
Net income --
Other comprehensive loss --
Total comprehensive income
Shares issued pursuant to employee
205
benefit and option plan --
Restricted stock --
1 4,432
Common stock issued-note exchange -- 69 11,458
--
--
1
--
-- (21,635)
-- 54,419
--
32,784
--
--
-- -- 11,527
-- 4,433
206
--
Balances, December 31, 2009 $ -- $ 287 $ 243,898
$ (7,478) $(317,561) $ (80,854)
The accompanying notes are an integral part of these financial statements.
53
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
2009
2008
2007
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to
cash provided by operating activities:
Depreciation, depletion and amortization
Impairment of oil and gas properties
Accretion expense
Amortization of deferred financing costs
Non-cash interest expense for Callon Entrada credit agreement
Non-cash loss on early extinguishment of debt
Equity in earnings of Medusa Spar, LLC
Deferred income tax (benefit) expense
Valuation allowance
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
ExL acquisition
Entrada acquisition
Proceeds from sale of mineral interests
Distribution from Medusa Spar, LLC
Cash used by investing activities
Cash flows from financing activities:
Increases in debt
Payments on debt
Deferred financing costs
Equity issued related to employee stock plans
Excess tax benefits from share-based payment arrangements
Capital leases
Cash provided by (used in) financing activities
$ 54,419
$ (438,893)
$ 15,194
34,274
--
3,149
2,522
3,693
--
(660)
18,816
(18,816)
2,335
--
(45,573)
(468)
(27,260)
279
(312)
(12)
(31)
26,355
64,862
485,498
4,172
4,185
--
5,598
(262)
(167,848)
128,123
1,550
(2,050)
(22,215)
5,489
22,987
630
156
2,708
(1,458)
93,232
73,677
--
3,985
3,009
--
--
(507)
8,506
--
849
(163)
6,658
(619)
(2,057)
(938)
889
(10)
810
109,283
(35,790)
(15,756)
--
--
1,700
(49,846)
(176,536)
--
--
167,349
498
(8,689)
(127,409)
--
(150,000)
60,931
687
(215,791)
20,337
(10,337)
--
--
--
--
10,000
94,435
(216,000)
--
(1,152)
2,050
--
(120,667)
229,000
(64,000)
(6,429)
--
163
(872)
157,862
Net (decrease) increase in cash and cash equivalents
(13,491)
(36,124)
51,354
Cash and cash equivalents:
Balance, beginning of period
Balance, end of period
17,126
53,250
1,896
$ 3,635
$ 17,126
$ 53,250
The accompanying notes are an integral part of these financial statements.
54
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 14.
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 onshore in
Louisiana and Texas and the offshore waters of the 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., Callon Entrada Company (“Callon Entrada”) 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 United States generally accepted accounting
principles (“US GAAP”) 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 is required to record its estimate of the fair value of liabilities 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 11.
55
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, other
costs related to exploration and development activities, and site restoration, dismantlement and abandonment
costs capitalized in accordance with asset retirement obligation accounting guidance. 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 ($10.1 million in 2009, $12.6 million in 2008 and
$10.8 million in 2007) 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 or management determines that these costs have been impaired.
Costs of oil and gas properties, including future development 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 15.
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 asset retirement obligation guidance issued by the Financial Accounting Standards Board
(“FASB”), such costs are capitalized to the full-cost pool when the related liabilities are incurred. In
accordance with Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin No. 106, assets
recorded in connection with the recognition of an asset retirement obligation 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 determining the full-cost ceiling amount.
Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or
loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs
and proved reserves.
Amendments to Oil and Gas Reserves Estimation and Disclosure Requirements
In December 2008, the SEC approved amendments to its oil and gas reserves estimation and disclosure
requirements. The amendments, among other things:
allow the use of reliable technologies to estimate proved reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve volumes;
require disclosure of oil and gas proved reserves by significant geographic area;
permit the optional disclosure of probable and possible reserves;
modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average
beginning-of-the-month price instead of a period-end price; and
56
require that if a third party is primarily responsible for preparing or auditing the reserve estimates,
the company make disclosures relating to the independence and qualifications of the third party,
including filing as an exhibit any report received from the third party.
Additionally, during January 2010, the FASB issued accounting guidance to align the reserve calculation and
disclosure requirements of US GAPP with the new SEC oil and gas reserve estimation and disclosure rules.
The new requirements are effective for the Company’s year-end financial statements and its Annual
Report on Form 10-K for the year ended December 31, 2009.
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 expense of $423,000, $437,000 and $457,000 relating to other property
and equipment was included in general and administrative expenses in the Company’s consolidated
statements of operations for the years ended December 31, 2009, 2008 and 2007, respectively. The
accumulated depreciation on other property and equipment was $11.8 million and $11.6 million as of
December 31, 2009 and 2008, respectively.
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. In December 2003, 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
allowed 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. During the second quarter
of 2008, the non-recourse financing was extinguished. 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.
Revenue Recognition and Gas Balancing
The Company recognizes revenue under the entitlement method of accounting. Under the method, revenue
is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the
undelivered volumes. Production imbalances are generally recorded at the estimated sale price in effect at
the time of production. Gas balancing receivables were $743,000 and $1.0 million as of December 31, 2009
and 2008, respectively. Gas balancing payables were $1.2 million and $1.5 million as of December 31, 2009
and 2008, respectively.
57
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 is generally based on the difference between the contract price or prices specified in the
derivative instrument and a New York Mercantile Exchange (“NYMEX”) price or other cash or futures index
price.
The Company’s derivative contracts that are accounted for as cash flow hedges 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). See Note 8.
Callon’s derivative contracts are carried at fair value on the Company’s consolidated balance sheet under
the caption “Fair Market Value of Derivatives”. The oil and gas derivative contracts are settled based
upon reported prices on NYMEX. The estimated fair value of these contracts is based upon closing
exchange prices on NYMEX and in the case of collars and floors, the time value of options.
In March 2008, the FASB issued guidance for disclosures about derivative instruments and hedging
activities. Under the guidance for disclosures about derivative instruments and hedging activities, entities are
required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b)
how derivative instruments and related hedged items are accounted for under US GAAP, and (c) how
derivative instruments and related hedged items affect an entity’s financial position, financial performance,
and cash flows. The Company adopted the guidance on January 1, 2009 and has added certain additional
disclosures to its financial statements.
Fair Value Measurements
Effective January 1, 2008, the Company adopted guidance issued by the FASB for fair value measurements.
The guidance for fair value measurements defines fair value, establishes a framework for measuring fair
value and requires enhanced disclosures about fair value measurements. The adoption of the fair value
measurements guidance did not have a significant impact on the Company’s financial statements. The
Company also adopted guidance issued by the FASB for the fair value option for financial assets and
liabilities on January 1, 2008, which permits entities to choose to measure various financial instruments
and certain other items at fair value. The adoption of the fair value option for financial assets and
liabilities guidance did not have an impact on the Company’s financial statements. See Note 9.
Income Taxes
Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to
different reporting methods for oil and gas properties for financial reporting purposes and income tax
purposes. US GAAP requires the recognition of a deferred tax asset for net 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 will not be
realized. See Note 6.
58
Earnings per Share
The Company accounts for earnings per share (“EPS”) in accordance with guidance issued by the FASB.
The guidance on accounting for earnings per share requires all entities with publicly held common stock or
potential common stock must disclose EPS – basic and diluted. Basic EPS is computed by dividing reported
earnings available to common stockholders by weighted average shares outstanding. Diluted EPS reflects the
potential dilution that could occur if securities or other contracts to issue common stock were exercised or
converted into common stock or resulted in the issuance of common stock that then shared in the earnings of
the entity. The earnings component of EPS is limited to earnings applicable to common shares or earnings
after deduction of preferred stock dividends if incurred. If discontinued operations, extraordinary items, and
/or the cumulative effect of a change in accounting principles are reported, EPS information is required for
each of the following: (a) income from continuing operations, (b) income before extraordinary items, (c) the
cumulative effect of the change in accounting principle, net of tax, and (d) net income. See Note 5.
In June 2008, the FASB issued guidance determining whether instruments granted in share-based payment
transactions are participating securities. The guidance addresses whether instruments granted in share-based
payment transactions are participating securities prior to vesting and, therefore, need to be included in the
earnings allocation in computing earnings per share under the two-class method described in the FASB
issued guidance for earning per share”. The Company adopted this guidance on January 1, 2009 with no
impact to its financial statements.
Stock-Based Compensation
Share-based compensation 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 $2.1 million and $163,000 of excess tax benefits classified as a financing cash inflow for the
years ended December 31, 2008 and 2007, respectively would have been classified as an operating cash flow
had the Company not adopted the guidance issued by the FASB for share-based compensation. There were
no stock option exercises in the years ended December 31, 2009 and 2007 and no cash proceeds from the
exercise of stock options for the year ended December 31, 2008 due to the fact that all options were exercised
through net-share settlements. See Note 4.
Accounts Receivable
Accounts receivable consists primarily of accrued oil and gas production receivables. The balance in the
reserve for doubtful accounts netted within accounts receivable was $65,000 at both December 31, 2009
and 2008. There were no provisions to expense in the three-year period ended December 31, 2009.
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
Plains Marketing, L.P.
Louis Dreyfus Energy Services
StatoilHydro
December 31,______
2007
25%
10%
20%
13%
2009
45%
23%
15%
--
2008
33%
23%
16%
--
59
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.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be
cash equivalents.
Statements of Cash Flows
The Company paid no federal income taxes for the three years in the period ended December 31, 2009.
During the years ended December 31, 2009, 2008 and 2007, the Company made cash payments for
interest of $19.8 million, $27.0 million and $37.6 million, respectively.
During the fourth quarter of 2009, the Company commenced an exchange offer for any and all of its
outstanding Senior Notes. For each $1,000 principal amount of outstanding Senior Notes tendered in
accordance with the terms and conditions of the exchange offer, each tendering holder of the Senior Notes
received $750 principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of
common stock and 1.6875 shares of Convertible Preferred Stock. On December 31, 2009, each share of the
Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock
following shareholder approval and the filing of an amendment to the Company’s charter increasing the
number of authorized shares of common stock as necessary to accommodate such conversion. Holders of
approximately 92% of the Senior Notes tender their notes in the exchange offer and 6.9 million shares of
common stock, after the Convertible Preferred Stock was converted into common shares, were issued to the
tendering notes holders. See Note 7.
Fair Value of Financial Instruments
Fair value of cash and cash equivalents, accounts receivable and accounts payable, approximated book value
at December 31, 2009 and 2008. The senior secured revolving credit facility had a balance outstanding of
$10.0 million at December 31, 2009 and the fair value approximated book value at December 31, 2009. The
Company’s 9.75% Senior Notes due 2010 had an estimated fair market value of 95% and 52% of face value
at December 31, 2009 and 2008, respectively. The Company’s 13% Senior Notes due 2016 had an estimated
fair market value of 75% of face value at December 31, 2009. Callon Entrada’s non-recourse credit
agreement had a fair market value of zero at December 31, 2009.
Business Combinations
In December 2007, the FASB issued an accounting standard to improve the relevance, representational
faithfulness, and comparability of the information that a reporting entity provides in its financial reports about
a business combination and its effects. To accomplish that, the standard establishes principles and
requirements for how the acquirer (a) recognizes and measures in its financial statements the identifiable
assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (b) recognizes and
measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (c)
determines what information to disclose to enable users of the financial statements to evaluate the nature and
financial effects of the business combination. The business combination guidance is effective for business
combinations with an acquisition date on or after the beginning of annual reporting period beginning on or
after December 15, 2008. The standard requires an acquirer to recognize 100% of the fair values of acquired
assets, with limited exceptions, even if the acquirer has not acquired 100% of its target. Additionally
contingent consideration arrangements and preacquisition contingencies will be measured at fair value on the
60
acquisition date and included in the basis of the purchase price. Transaction costs are expensed as incurred
and not considered as part of the fair value of the acquisition; however, acquired research and development
are no longer expensed at acquisition, but instead are capitalized as an indefinite-lived intangible asset. The
Company adopted this accounting standard on January 1, 2009, and was applied to the Company’s ExL
acquisition during 2009. See Note 13 for the impact of the acquisition on the financial statements.
Subsequent Events
In May 2009, the FASB issued guidance for subsequent events. The objective of this guidance is to
establish general standards of accounting for and disclosures of events that occur after the balance sheet
date but before financial statements are issued or are available to be issued. The Company adopted the
guidance as of the quarter ended June 30, 2009 with limited impact to its financial statements. See Note
20.
Recent Accounting Pronouncements
Consolidation of Variable Interest Entities (“VIE”). In June 2009, the FASB issued an accounting
standard which amends US GAAP as follows: a) to require an enterprise to perform an analysis to
determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a
VIE, identifying the primary beneficiary of a VIE, b) to require ongoing reassessment of whether an
enterprise is the primary beneficiary of a VIE, rather than only when specific events occur, c) to eliminate
the quantitative approach previously required for determining the primary beneficiary of a VIE. d) to
amend certain guidance for determining whether an entity is a VIE, e) to add an additional reconsideration
event when changes in facts and circumstances pertinent to a VIE occur, f) to eliminate the exception for
troubled debt restructuring regarding VIE reconsideration, and g) to require advanced disclosures that will
provide users of financial statement with more transparent information about an enterprise’s involvement
in a VIE. This pronouncement is effective for the first annual reporting period that begins after November
15, 2009, with earlier adoption prohibited. The Company adopted this pronouncement on January 1,
2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada as a result of
the amendments described above. Based on the evaluation performed, management has concluded that a
VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for
which the Company is not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada
will be deconsolidated from the consolidated financial statements of the Company. Deconsolidation will
result in the removal of approximately $1.8 million of current assets, $2.0 million of current liabilities,
$30.0 million of deferred tax assets, $30.0 million of valuation allowance and approximately $84.8
million of non-recourse debt and related obligation for the cumulative amount of interest. Retained
earnings will be increased by $85.1 million as a cumulative effect of change related to this accounting
standard. The following table shows the impact of deconsolidation as of January 1, 2010.
61
Callon
Entrada
Deconsolidation
Callon
After
Deconsolidation
Balance Sheet (in thousands)
Total current assets
Total oil and gas properties
Other property and equipment
Other assets
Total assets
Callon
Consolidated
as reported
12/31/09
$ 77,684
130,608
2,508
17,191
$227,991
$ (1,767)
--
--
--
$ (1,767)
Other current liabilities
9.75% Senior Notes, due December
2010
Callon Entrada credit agreement
Total current liabilities
Total long-term debt
Total other long-term liabilities
Total stockholders’ equity (deficit)
Total liabilities and stockholders’
equity (deficit)
$ 16,889
$ (2,015)
15,820
84,847
117,556
179,174
12,115
(80,854)
--
(84,847)
(86,862)
--
--
85,095
$227,991
$ (1,767)
$ 75,917
130,608
2,508
17,191
$226,224
$ 14,874
15,820
--
30,694
179,174
12,115
4,241
$226,224
The Company also reevaluated its interest in its equity method investment, Medusa Spar LLC, upon the
adoption of this accounting standard. No changes in the Company’s accounting of Medusa Spar LLC
resulted from the adoption of this accounting standard.
Noncontrolling Interest in Consolidated Financial Statements. In December 2007, the FASB issued an
accounting standard for noncontrolling interest in consolidated financial statements. The objective of this
standard is to improve the relevance, comparability, and transparency of the financial information that a
reporting entity provides in its consolidated financial statements by establishing accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This
standard is effective for first fiscal year and interim periods within the fiscal year, beginning on or after
December 15, 2008. The Company adopted this standard on January 1, 2009 with no impact to its financial
statements.
Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion. Effective
January 1, 2009, the FASB issued an accounting standard for accounting for convertible debt instruments
that may be settled in cash upon conversion (including partial cash settlement). Additionally, this standard
specifies that issuers of such instruments should separately account for the liability and equity components in
a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in
subsequent periods. The Company’s adoption of this standard had no impact to its financial statements.
Business Combinations – Identifiable Assets, Liabilities and Any Noncontrolling Interest. In April
2009, the FASB issued accounting guidance for business combinations that arise from contingencies. The
guidance addresses application issues raised by preparers, auditors, and members of the legal profession
on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets
and liabilities arising from contingencies in a business combination. The Company adopted this guidance
as of the quarter ended June 30, 2009 with no impact to the Company’s financial statements.
62
Fair Value of Financial Instruments for Interim Reporting Periods. The Company adopted the
accounting guidance issued by the FASB for fair value of financial instruments for interim reporting
periods which requires disclosures about fair value of financial instruments for interim reporting periods
of publicly traded companies as well as in annual financial statements. This guidance also amends the
guidance for interim reporting, to require those disclosures in summarized financial information at interim
reporting periods. Accordingly, the Company adopted this guidance as of the quarter ended June 30,
2009 with limited impact to the Company’s financial statements.
Financial Accounting Standards Board Accounting Standards Codification. The FASB voted to
approve the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative
nongovernmental US GAAP as of July 1, 2009. ASC was effective for interim and annual periods ending
after September 15, 2009. ASC reorganizes the many US GAAP pronouncements into approximately 90
accounting topics, with all topics using a consistent structure. It also includes relevant authoritative
content issued by the SEC, as well as selected SEC staff interpretations and administrative guidance. ASC
does not change or alter existing US GAAP and effective July 1, 2009, changes to ASC were
communicated through an Accounting Standards Update (“ASU”). The Company adopted ASC for the
September 30, 2009 reporting period with no impact on the consolidated financial statements.
3. CALLON ENTRADA CREDIT AGREEMENT
In April 2008, Callon completed the sale of a 50% working interest in the Entrada Field to CIECO Energy
(US) Limited (“CIECO”) effective January 1, 2008. At closing, CIECO paid Callon $155 million and
reimbursed the Company $12.6 million for 50% of Entrada capital expenditures incurred prior to the
closing date. In addition, as part of the purchase and sale agreement, CIECO agreed to loan the Company
up to $150 million for its share of the development costs for the Entrada project.
A wholly-owned subsidiary of Callon, Callon Entrada, entered into a credit agreement with CIECO
Energy (Entrada) LLC, (“CIECO Entrada”) pursuant to which Callon Entrada was entitled to borrow up
to $150 million, plus interest expense incurred of up to $12 million, to finance the development of the
Entrada project prior to the abandonment of the project in November 2008. Based on the terms of the
credit agreement, the debt was to be repaid solely from assets, primarily production, from the Entrada
field. As a result of abandoning the project prior to completion and the lease expiring on June 1, 2009,
Callon Entrada’s only source of payment is the proceeds from the sale of equipment purchased but not
used for the Entrada project. The agreement bears interest at six-month LIBOR (as in effect on the first
day of each interest period) plus 375 basis points and is subject to customary representations, warranties,
covenants and events of default. The interest rate increased by 400 basis points as of April 2, 2009 due to
a notice of default received from CIECO Entrada, which is discussed below. As of December 31, 2009,
$78.4 million of principal and $6.4 million of interest were outstanding under this facility.
On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that
certain alleged events of default occurred under the credit agreement relating to failure to pay interest
when due and the breach of various other covenants related to the decision to abandon the Entrada project.
The notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon
Entrada credit agreement to accelerate payment of the principal and interest due. The acceleration of
payment caused the principal and interest balances under the Callon Entrada credit agreement to be
reclassified effective as of the date of notice to current liabilities from long-term liabilities under US
GAAP. The agreement has not been legally extinguished, and as such under US GAAP, the agreement
remains as a liability of Callon Entrada. Until January 1, 2010, the Company is required to continue to
consolidate the financial statements and results of operations of Callon Entrada, and as such, Callon
Entrada’s liability is reflected in a separate line item in Callon’s consolidated financial statements.
63
All assets of Callon Entrada, and its stock, are pledged to CIECO Entrada under the Callon Entrada credit
agreement. Callon and its subsidiaries (other than Callon Entrada) did not guarantee the Callon Enrada
credit facility and, based on the advice of legal counsel, the Company believes that it and its subsidiaries
are not otherwise obligated to repay the principal, accrued interest or any other amount which may
become due under the Callon Entrada credit facility. However, Callon has entered into a customary
indemnification agreement pursuant to which it agrees to indemnify the lenders under the Callon Entrada
credit facility against Callon Entrada’s misappropriation of funds, non-performance of certain covenants,
excluding the events of default discussed above, and similar matters. In addition, Callon also guaranteed
the obligations of Callon Entrada to fund its proportionate share of any operating costs related to the
Entrada project that Callon Entrada may, from time to time, expressly approve under the Entrada joint
operating agreement for which none remain nor are planned. Callon also has guaranteed Callon Entrada’s
payment of all amounts to plug and abandon wells and related facilities and for a breach of law, rule or
regulation (including environmental laws) and for any losses of CIECO Entrada attributable to gross
negligence of Callon Entrada. The well for which Callon Entrada was responsible was plugged and
abandoned in the fourth of quarter of 2008, and the Minerals Management Service (“MMS”) confirmed to
Callon during 2009 that all abandonment obligations in the Entrada field have been satisfied.
Prior to abandonment of the Entrada project, CIECO Entrada failed to fund two loan requests totaling $40
million under the Callon Entrada credit agreement. These loan requests were to cover Callon Entrada’s
share of the costs incurred to develop the Entrada field up to the suspension of the project. Such amounts
were subsequently funded by the Company to Callon Entrada and were included as part of the Company’s
full-cost pool impairment adjustment recorded in the fourth quarter of 2008. The Company continues to
discuss with CIECO Entrada its failure to fund the $40 million in loan requests.
CIECO Entrada also failed to fund its working interest share of a settlement payment in the amount of
$7.3 million to terminate a drilling contract for the Entrada Project. No assurances can be made regarding
the outcome of discussions related to the Company’s ability to recover its funds related to the Entrada
Project. The Company does not believe that we have waived any of our rights under the agreements with
CIECO Entrada or its parent, CIECO.
As of December 31, 2009, the wind down of the Entrada project was complete and all of the costs related
to the Entrada project have been paid. The lease expired June 1, 2009 and reverted to the MMS. In
addition, the sale of equipment purchased for the Entrada project, but not used, is in progress. As of
December 2009, Callon Entrada has collected $3.4 million in sales proceeds from the sale of equipment,
net to its interest, which was applied to unpaid interest expense as required under the Callon Entrada
credit facility. The Company believes that the amount of future operating costs of Callon Entrada, for
which the Company would be responsible for, is not significant and is limited to minimal storage fees for
the surplus equipment, while the equipment is being liquidated.
The Company adopted the pronouncement for consolidation of variable interest entities on January 1,
2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on
the evaluation performed, management has concluded that a VIE reconsideration event had taken place
resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary
beneficiary and Callon Entrada will be deconsolidated from the Company’s consolidated financial
statements as of January 1, 2010. See Note 2 above under “Recent Accounting Pronouncements” for
more details.
64
4. 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 16.
For the year ended December 31, 2009, the Company recorded stock-based compensation expense of $4.8
million, of which $2.3 million was included in general and administrative expenses and $2.5 million was
capitalized to oil and gas properties. For the year ended December 31, 2008, the Company recorded stock-
based compensation expense of $4.5 million, of which $2.5 million was included in general and
administrative expenses and $2.0 million was capitalized to oil and gas properties. For the year ended
December 31, 2007, the Company recorded stock-based compensation expense of $2.9 million, of which
$1.4 million was included in general and administrative expenses and $1.5 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 1,290,387 at December 31, 2009.
Stock Options
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. There were no stock options
issued during 2008.
Dividend yield
Expected volatility
Risk-free interest rate
Expected life of option (in years)
Weighted-average grant-date fair value
Forfeiture rate
Years Ended
December 31,_
2009_
--
136.0%
3.9%
9
$ 1.23
0.0%
2008
--
--
--
--
--
--
2007_
--
36.2%
4.7%
5
$ 5.64
2.0%
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:
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 5.75 yrs. 2.92 yrs. 3.39 yrs.
2.68 yrs. 3.08 yrs.
Outstanding exercisable at end of period 1.78 yrs.
Shares
740,225
30,000
--
--
(15,000)
755,225
710,225
2008
Wtd Avg
Shares Ex Price
755,225 $ 10.00
--
--
9.34
(238,950)
15.97
(3,000)
--
--
513,275 $ 10.27
488,075 $ 9.91
2009
Wtd Avg
Shares Ex Price
513,275 $ 10.27
2.76
500,000
--
--
14.44
(15,000)
(19,917) 9.99
978,358
$ 6.37
464,558 $ 9.93
$ 9.93
14.27
--
--
15.31
$ 10.00
$ 9.57
2007
Wtd Avg
Ex Price
65
As of December 31, 2009 and 2008, the aggregate intrinsic value of options outstanding and options
exercisable was zero. As of December 31, 2007, the aggregate intrinsic value of options outstanding was
$5.0 million and the aggregate intrinsic value of options exercisable was $4.9 million. Total intrinsic value of
options exercised was $4.1 million for the year ended December 31, 2008. At December 31, 2009, there was
$54,000 of unrecognized compensation cost related to nonvested stock options, which is expected to be
recognized over one year.
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, 2009, there was $3.2 million of unrecognized compensation cost associated with these
awards, which is expected to be recognized over a weighted average period of 1.5 years.
The following table represents unvested restricted stock activity for the year ended December 31, 2009:
Weighted-Average
Outstanding shares at beginning of period
Granted
Vested
Forfeited
Number of
Shares
509,300
650,975
(157,750)
(75,100)
Grant-Date
Fair Value
$ 17.43
1.98
15.00
17.36
Outstanding shares at end of period
927,425
$ 7.01
For the years ended December 31, 2009, 2008 and 2007 the Company recognized non-cash compensation
expense associated with the restricted stock awards of $4.6 million, $4.3 million and $2.7 million,
respectively.
As part of the 2009 award, 121,525 shares were issued as stock appreciation rights (“SARs”). The SARs
will vest three years from grant date. At December 31, 2009, the Company had recorded a stock-based
compensation liability of $182,000 for this award.
66
5. 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 and restricted stock considered common stock equivalents computed using the treasury stock
method.
A reconciliation of the basic and diluted net income per share computation is as follows for the years
ended December 31, (in thousands, except per share amounts):
2009
2008
2007
(a) Net income (loss) available to common shares
$ 54,419
$(438,893)
$ 15,194
(b) Weighted average shares outstanding 22,072
Dilutive impact of stock options --
Dilutive impact of restricted stock 128
21,222
--
--
Dilutive impact of warrants --
--
20,776
148
40
326
(c) Weighted average shares outstanding for diluted
net income per share 22,200 21,222
21,290
Stock options excluded due to the exercise
price being greater than the stock price 978
399
75
Basic net income (loss) per share (ab)
Diluted net income (loss) per share (ac)
$ 2.47
$ 2.45
$ (20.68)
$ (20.68)
$ 0.73
$ 0.71
In addition, below are the shares (in thousands) relating to stock option, warrants and restricted stock that
were not included in diluted shares for the year ended December 31, 2008 due to the fact that the Company
had a loss for this period. The Company had net income for the years ended December 31, 2009 and 2007
and all such shares were included as described above.
2008 _
Stock options 161
Warrants 328
Restricted Stock 129
67
6. INCOME TAXES
Below is an analysis of deferred income taxes as of:
December 31,____
2009
2008
(In thousands)
Deferred tax assets:
$ 68,432
Federal net operating loss carryforwards
4,561
Statutory depletion carryforward
Alternative minimum tax credit carryforward
375
Asset retirement obligations 3,704 13,102
Oil and gas properties -- 58,061
Other
34,170 2,241
Valuation allowance (116,676) (128,123)
$ 94,125
4,895
383
Total deferred tax assets 20,601 18,649
Deferred tax liabilities:
Oil and gas properties 9,555 --
Other 11,046 18,649
Total deferred tax liabilities 20,601 18,649
Net deferred tax $ -- $ --
US GAAP provides for the weighing of positive and negative evidence in determining whether it is more
likely than not that a deferred tax asset is recoverable. As a result of the impairment of oil and gas
properties in the fourth quarter of 2008, the Company incurred losses on an aggregate basis for the three-
year period ended December 31, 2008. As a result, the Company has established a full valuation
allowance for its net deferred tax asset which reflects federal net operating loss carryforwards of $268
million as of December 31, 2009.
If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through 2024. The
Company’s state net operating loss carryforwards in the amount of $56.8 million as of December 31, 2009
will expire in 2010 through 2024. The Company has limited state taxable income as primarily all of its
revenue is generated in federal waters and is not subject to state income taxes. Accordingly, the Company
has established a full valuation allowance on the tax benefit associated with these state net operating loss
carryforwards as the Company does not anticipate generating taxable state income in the states in which these
carryforwards apply.
The Company had no significant unrecognized tax benefits at the date of adoption or at December 31,
2009. Accordingly, the Company does not have any interest or penalties related to uncertain tax
positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such
amounts would be recognized in income tax expense. Tax periods for years 2004 through 2008 remain
open to examination by the federal and state taxing jurisdictions to which the Company is subject.
68
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,_
2007_
2009_
2008_
(35)%
34%
1%
(35)%
27%
--
35%
--
2%
0%
(8)%
37%
.
Included in the table below are the components of income tax expense.
Years Ended December 31,
2009
2008
2007
Current income tax expense (benefit)
Deferred income tax (benefit) expense
Valuation allowance
Total income tax expenses
$ --
18,816
(18,816)
$ --
$ --
(167,848)
128,123
$ (39,725)
$ --
8,506
--
$ 8,506
During 2009, the Company reduced the valuation allowance by the income tax expense incurred for the
year.
7. LONG-TERM DEBT
Long-term debt consisted of the following at:
Senior Secured Credit Facility (matures September 25, 2012)
9.75% Senior Notes (due December 2010)
Discount
13% Senior Notes (due September 2016)
Deferred Credit
Callon Entrada (non-recourse) credit agreement
Total long-term debt
Less current portion
Long-term portion
December 31,____
2009 _
2008__
(In Thousands)
$ 10,000
16,052
(232)
137,961
31,213
84,847
279,841
100,667
$ --
200,000
(5,580)
--
--
78,435
272,855
--
$179,174
$272,855
Senior Secured Credit Facility. On September 25, 2008, the Company completed a $250 million second
amended and restated senior secured revolving credit agreement with Union Bank N.A. (“Union Bank”)
as administrative agent and issuing lender. The borrowing base was $16.2 million at December 31, 2009.
Borrowings under the credit agreement are secured by mortgages covering the Company’s major fields.
69
As of December 31, 2009, $10.0 million was outstanding under the agreement. 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 2009 was 1.87% to 3.25%.
Subsequent to December 31, 2009, the Company’s senior secured credit agreement was amended to
include Regions Bank as the sole arranger and administrative agent. The third amended and restated
senior secured credit agreement, which matures on September 25, 2012, provides for a $100 million
facility with an initial borrowing base of $20 million, which will be reviewed and re-determined on a
semi-annual basis. The third amended and restated credit facility bears interest at 4% above a defined
base rate and in no event will the interest rate be less than 6%. In addition, a commitment fee of 0.5% per
annum on the unused portion of the borrowing base, is payable quarterly. Subsequent to December 31,
2009, simultaneously with the execution of the third amended and restated senior secured credit
agreement, the Company repaid the $10 million outstanding on the borrowing base under the second
amended and restated senior secured credit agreement. See Note 20.
9.75% Senior Notes due 2010. In the fourth quarter of 2003, the Company issued $200 million of 9.75%
senior notes (“Senior Notes”), due 2010. In conjunction with the Senior Notes, the Company issued
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. The Senior Notes mature December 8, 2010 and have an effective interest rate of
11.4%. The Company recorded the issuance of the Senior Notes at a fair value of $185 million. Deferred
costs of $15 million associated with the Senior Notes are being amortized over the life of the notes. As of
December 31, 2009, 2.410 million of the 2.775 million warrants issued with the Senior Notes were
exercised.
During the fourth quarter of 2009, Callon commenced an exchange offer for any and all of its outstanding
Senior Notes. For each $1,000 principal amount of outstanding Senior Notes tendered in accordance with the
terms and conditions of the exchange offer, each tendering holder of the Senior Notes received $750 principal
amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of common stock and
1.6875 shares of Convertible Preferred Stock. Holders of approximately 92% of the Senior Notes tendered
their Senior Notes in the exchange offer. On December 31, 2009, each share of the Convertible Preferred
Stock was automatically converted by the Company into 10 shares of common stock following shareholder
approval and the filing of an amendment to the Company’s charter increasing the number of authorized
shares of common stock as necessary to accommodate such conversion. In connection with the exchange
offer, holders who tendered their Senior Notes consented to amend the indenture governing the Senior Notes,
eliminating substantially all of the indenture’s restrictive covenants. The principal amount of the remaining
Senior Notes is $16.1 million at December 31, 2009 and is due in 2010.
13% Senior Notes due 2016 (“Exchange Notes”). As described above, during the fourth quarter of 2009,
the Company exchanged approximately 92% of the principal amount, or $183.9 million, of the Senior Notes
for $137.9 million of Exchange Notes plus 3.8 million shares of common stock and 310,802 shares of
Convertible Preferred Stock which was valued on November 24, 2009 in the amount of $11.5 million and
recorded as an increase to stockholders’ equity. On December 31, 2009, each share of the Convertible
Preferred Stock was automatically converted by the Company into 10 shares of common stock following
shareholder approval and the filing of an amendment to the Company’s charter increasing the number of
authorized shares of common stock as necessary to accommodate such conversion.
70
The Company determined that the note exchange should be accounted for in accordance with guidance
provided by the FASB for accounting for troubled debt restructuring. Immediately before the issuance of the
Exchange Notes, the total future cash payments on the restructured Senior Notes was less than the remaining
carrying amount of the Senior Notes after the carrying amount was reduced by the fair value of the equity
interests issued. Therefore, as of November 23, 2009, in accordance with the troubled debt restructuring
accounting standard, the Company reduced the carrying amount of the Senior Notes by the fair value of the
common and preferred stock issued in the amount of $11.5 million The difference between the adjusted
carrying amount of the Senior Notes and the face value of the Exchange Notes was recorded as a deferred
credit of $31.2 million which will be amortized as a credit to interest expense at an 8.5% effective interest
rate over the life of the Exchange Notes. In addition, the Company incurred $1.0 million of costs associated
with the note exchange and expensed the amount in the fourth quarter of 2009 in accordance with troubled
debt restructuring accounting standard.
Certain of the Company’s subsidiaries guarantee the Company’s obligations under the Exchange Notes.
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.
Restrictive Covenants. The Indenture governing our Exchange Notes and the Company’s senior secured
credit facility contains various covenants including restrictions on additional indebtedness and payment of
cash dividends. In addition, Callon’s senior secured credit facility contains covenants for maintenance of
certain financial ratios. The Company was in compliance with these covenants at December 31, 2009.
Callon Entrada (Non-Recourse) Credit Agreement. A wholly-owned subsidiary of Callon, Callon
Entrada, entered into a credit agreement with CIECO Entrada in April 2008, pursuant to which Callon
Entrada may borrow up to $150 million, plus interest expense incurred of up to $12 million, to finance the
development of the Entrada project. The Callon Entrada credit agreement is a direct obligation of Callon
Entrada. The Callon Entrada credit agreement is secured by a lien on the assets of Callon Entrada, which
generally are comprised of the Entrada Field and related equipment. Neither Callon Petroleum nor any
other subsidiary of Callon Petroleum guaranteed or otherwise agreed to pay the principal or interest
payments due on the Callon Entrada credit agreement. As such, the facility is effectively non-recourse to
Callon Petroleum and its other subsidiaries.
The agreement bears interest at six-month LIBOR (as in effect on the first day of each interest period)
plus 0.375% and is subject to customary representations, warranties, covenants and events of default. The
interest rate increased by 4.0% as of April 2, 2009 due to a notice of default received from CIECO
Entrada. As of December 31, 2009, $78.4 million of principal and $6.4 million of accrued interest was
outstanding under this Callon Entrada credit agreement. See Note 3 for more details.
Senior Revolving Credit Facility (due 2014). On April 18, 2007, Callon closed the Entrada acquisition
contemporaneous with a seven-year $200 million senior revolving credit facility arranged by Merrill
Lynch Capital Corporation, which is secured by a lien on the Entrada properties. On April 8, 2008,
Callon extinguished the $200 million senior revolving credit facility. The retirement was made with cash
on hand, a $16 million draw under the Union Bank credit facility and proceeds from the sale of a 50%
working interest in Callon’s Entrada Field to CIECO. Due to the early extinguishment of this credit
facility, Callon incurred expenses of $11.9 million, consisting of $6.3 million in pre-payment penalties
plus a non-cash charge of $5.6 million related to the amortization expense associated with the deferred
financing costs related to the credit facility. These amounts are included in “Loss on early extinguishment
of debt” in the accompanying Consolidated Statements of Operations.
71
8. DERIVATIVES
During 2008, the change in fair value and settlements of ineffective derivative contracts of $498,000 were
related to contracts that were deemed ineffective as a result of a shortfall in production volumes due to
downtime resulting from damages caused by Hurricanes Gustav and Ike. No contracts were deemed
ineffective during 2009 and 2007. For the years ended December 31, 2009, and 2007 cash settlements on
effective cash flow hedges resulted in an increase in oil and gas sales of $19.2 million and $8.1 million,
respectively. Cash settlements on effective cash flow hedges for the year ended December 31, 2008 resulted
in a reduction in oil and gas sales of $9.4 million.
Listed in the table below are the outstanding derivative contracts, which are collars, as of December 31,
2009:
Average Average
Volumes per Quantity Floor Ceiling
Product Month Type Price Price Period
Natural Gas 75,000 MMBtu $ 5.00 $ 8.30 01/10-12/10
9. FAIR VALUE MEASUREMENTS
US GAAP establishes a fair value hierarchy which consists of three broad levels that prioritize the inputs to
valuation techniques used to measure fair value.
Level 1 valuations consist of unadjusted quoted prices in active markets for identical assets
and liabilities and have the highest priority.
Level 2 valuations rely on quoted market information for the calculation of fair market
value.
Level 3 valuations are internal estimates and have the lowest priority.
The Company has classified its derivatives into these levels depending upon the data relied on to determine
the fair values of the derivative instruments. The fair values of collars and natural gas basis swaps are
estimated using internal discounted cash flow calculations based upon forward commodity price curves or
quotes obtained from counterparties to the agreements and are designated as Level 3. The following table
summarizes the valuation of our assets and liabilities measured at fair value on a recurring basis at December
31, 2009 (in thousands):
Fair Value Measurements Using
Quoted Significant
Prices in Other Significant
Active Observable Unobservable Assets
Markets Inputs Inputs (Liabilities)
(Level 1) (Level 2) (Level 3) At Fair Value
Derivative assets
$ --
$ --
$ 145
$ 145
Derivative liabilities
Total
--
$ --
--
$ --
--
$ 145
--
$ 145
72
The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis
using significant unobservable inputs (Level 3) during the period ended December 31, 2009. The fair values
of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market
observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives
valued using pricing models incorporating assumptions that, in management’s judgment, reflect the
assumptions a marketplace participant would have used at December 31, 2009 (in thousands):
Balance at January 1, 2009
Total gains or losses (realized or unrealized):
Included in earnings
Included in other comprehensive income
Purchases, issuances and settlements
Balance at December 31, 2009
Derivatives
$ 21,780
19,242
(21,635)
(19,242)
$ 145
Change in unrealized gains (losses) included in
earnings relating to derivatives still held as of
December 31, 2009
$ --
10. OTHER COMPREHENSIVE INCOME
A summary of the Company’s comprehensive income (loss) is detailed below (in thousands, net of tax)
for the twelve months ended December 31:
Net income (loss)
Other comprehensive income (loss):
Change in fair value of derivatives
Total comprehensive income (loss)
2009
2008
$ 54,419
$ (438,893)
2007
$ 15,194
(21,635)
$ 32,784
17,540
$ (421,353)
(12,035)
$ 3,159
11. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the activity for the Company’s asset retirement obligations (in
thousands):
Years Ended December 31,
2009 2008 ____
Asset retirement obligations at beginning of period
Accretion expense
Liabilities incurred
Liabilities settled
Revisions to estimate
Asset retirement obligations at end of period
Less: current retirement obligations
Long-term retirement obligations
$ 42,194
3,149
9
(8,194)
(22,508)
14,650
(4,002)
$ 10,648
$ 36,837
4,172
2,851
(6,586)
4,920
42,194
(9,151)
$ 33,043
The revisions to estimate of $22.5 million was primarily due to the MMS approval to abandon in place
the Company’s Entrada #1 and #2 wells in place resulting in a reduction in asset retirement obligation
liabilities of $16.0 million and reduction in estimated costs for other obligations.
73
Assets, primarily short-term U.S. Government securities, of approximately $4.1 million at December 31,
2009, were recorded as restricted investments. These assets are held in abandonment trusts dedicated to
pay future abandonment costs for several of the Company’s oil and gas properties.
12. MMS ROYALTY RECOUPMENT
The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Outer
Continental Shelf Deep Water Royalty Relief Act 1995. From first production during November 2003
and until August 2009, the Company paid $44.8 million of royalties to the MMS based on price
thresholds imposed by the MMS. Kerr-McGee Oil & Gas Corporation sued the MMS on the grounds that
the MMS had no right to impose price thresholds on royalty relief leases located in the Gulf of Mexico
deep water. In October 2009, the Supreme Court refused to review the decision by the Fifth Circuit
Court of Appeals which was in favor of Kerr-McGee. As a result, in November the Company filed for a
recoupment of the royalties paid in the amount of $44.8 million from production at the Company’s
Medusa field. As of December 31, 2009, Callon accrued royalty recoupment of $44.8 million and
estimated interest of $7.7 million. The recoupment of principal was received by the Company in January
2010 with the interest expected to be received in the first quarter of 2010.
Royalty recoupment of $3.0 million related to 2009 production was recorded as oil and gas sales in the
fourth quarter of 2009. Royalty recoupment for years prior to 2009 of $40.9 million was included in
operating revenues as MMS royalty recoupment. Interest income related to the recoupment was recorded
as a component of other income and expense.
13. ACQUISITIONS
In September 2009, the Company acquired for $3.0 million a 70% working interest in a 577-acre unit in
the heart of the Haynesville Shale play in Bossier Parish, Louisiana. The development plan for this
acreage includes drilling a total of seven horizontal wells with the first two wells to be drilled in 2010.
Callon will be the operator of this project.
On October 28, 2009, Callon completed the acquisition of proved oil and gas property interests in
Wolfberry play located in Crockett, Ector, Midland and Upton Counties, Texas from Ambrose Energy I,
Ltd., a subsidiary of ExL Petroleum, LP for a total cash consideration of $16.0 million. The acquisition
was funded by the Company’s senior secured credit facility in the amount of $10 million and the
remaining $6.0 million with cash on hand. The acquisition included year-end proved reserves of 1.6
million barrels of oil equivalent, 22 existing wells producing 350 barrels of oil equivalent per day and
upside from a multi-year inventory of drilling and recompletion opportunities. The Company will operate
substantially all of the production and development. The Company accounted for the acquisition in
accordance with guidance the amended issued by the FASB for business combinations, which was
adopted on January 1, 2009, and recorded acquisition expenses in the fourth quarter of 2009 of $298,000.
74
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at
the acquisition date (In thousands):
Cash paid for acquired assets at closing
Post-closing adjustment
Assumed liabilities
Net assets acquired
$ 15,958
(690)
339
$ 15,607
(a)
(a) Represents net cash flow from the operations of the acquired properties during the period from
September 1, 2008 (effective date) to October 28, 2009 (closing date).
The allocation of the purchase price of the acquired properties at the date of acquisition follows (In
thousands):
Accounts receivable
Oil and gas properties
Other accrued liabilities
Cash paid for acquired assets as closing
$ 690
15,607
(339)
$ 15,958
14. COMMITMENTS AND CONTINGENCIES
From time to time, the Company, as part of the Consolidation and other capital transactions, enters 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 hereunder, if any, will not have a material adverse effect on the financial
position or results of operations of the Company.
The Company’s activities are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. Although no assurances can be made, the Company believes
that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local
laws, rules and 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 hereunder, and claims
for damages to property, employees, other persons and the environment resulting from the Company’s
operations could have on its activities
75
15. 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
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
Sale of mineral interests
End of period balance
Years Ended December 31,
2009 2008 2007
(In thousands)
$ 1,581,698
23,748
--
(11,562)
$ 1,593,884
$ 1,349,904
6,126
2,578
223,090
$ 1,581,698
$1,096,907
154,193
35,959
62,845
$1,349,904
$ 32,829
6,140
3,213
(16,740)
$ 25,442
$ 70,176
6,409
6,496
(50,252)
$ 32,829
$ 54,802
21,525
7,152
(13,303)
$ 70,176
$ 1,455,275
33,443
--
$ 1,488,718
$ 738,374
549,552
167,349
$ 1,455,275
$ 604,682
72,762
60,930
$ 738,374
Unevaluated property costs, primarily including lease acquisition costs incurred at federal and state lease
sales, unevaluated drilling costs, seismic, capitalized interest and general and administrative costs being
excluded from the amortizable evaluated property base, consisted of $8.6 million incurred in 2009, $7.2
million incurred in 2008, and $3.9 million incurred in 2007 and $5.7 million incurred in 2006 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 $2.83, $5.57 and
$3.89 for the years ended December 31, 2009, 2008, and 2007, 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 subsequent pricing is allowed and no write-down would be required if such pricing was used. Given
76
the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate of discounted future
net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline
significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties
could occur in the future. For the year ended December 31, 2008, the Company recorded a $485.5 million
impairment of oil and gas properties as a result of the ceiling test calculation.
16. 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 $640,000, $747,000 and $680,000
in the years 2009, 2008 and 2007, 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.
During 2009, the Company awarded 80,000 shares of restricted stock to non-employee
members of the Board of Directors, which will vest one year from the grant date.
77
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 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.
During 2009, the Company awarded 20,000 share of restricted stock to employees of the
Company, which will vest three years from grant date.
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.
In April 2008, 217,600 shares were awarded as restricted stock with cliff vesting over the next
three years and the compensation cost is being amortized over the vesting period. In addition,
25,000 shares were awarded as restricted stock vesting immediately and the compensation
cost was recognized as an expense on the grant date.
During 2009, the Company awarded 179,150 shares of restricted stock to employees of the
Company, which will vest three years from grant date. In addition, the Company awarded
8,850 of stock appreciation rights, which vest three years from the grant date.
2009 Stock Incentive Plan
On March 5, 2009, the Board of Directors of the Company approved the Callon Petroleum
Company 2009 Stock Incentive Plan (“2009 Plan”), subject to the approval of the
shareholders of the Company. The 2009 Plan was approved by shareholders on April 30,
2009. Pursuant to the 2009 Plan, 1,250,000 shares of common stock shall be reserved for
issuance upon exercise of vested stock options and stock appreciation rights, restricted
stock awards, restricted stock unit awards, and other stock-based awards. During 2009,
171,825 restricted stock units were issued with vesting scheduled for the third anniversary
date following the award. In addition, the Company awarded 112,675 of stock appreciation
rights, which vest three years from the grant date.
78
Stock Incentive Award for Inducement of Employment
On June 1, 2009, the Company awarded 100,000 shares of restricted stock, 100,000 shares
of performance stock and 500,000 options to the Company’s new Executive Vice President
and Chief Operating Officer. These shares were issued from the authorized but unissued
corporate shares under an exception available by the New York Stock Exchange as a
inducement of employment. The restricted stock will vest four years from the grant date,
and the performance shares will vest three years from the grant date based on the
performance of the Company. The options vest over a ten year period based on the
performance of the Company.
17. EQUITY TRANSACTIONS
The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the
Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of the
Company and to guard against partial tender offers, squeeze-outs, open market accumulations, and other
abusive tactics to gain control without paying all stockholders a fair price. The rights plan was not
adopted in response to any specific takeover proposal. Under the rights plan, the Company declared a
dividend of one right (“Right”) on each share of the Company’s Common Stock. Each Right will entitle
the holder to purchase one one-thousandth of a share of a Series B Preferred Stock, par value $0.01 per
share, at an exercise price of $90 per one one-thousandth of a share.
The Rights are not currently exercisable, and will become exercisable only in the event a person or group
acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15 percent or more
(one existing stockholder was granted an exception for up to 21 percent) of the Company’s common
stock. After the Rights become exercisable, each Right will also entitle its holder to purchase a number of
common shares of the Company having a market value of twice the exercise price. The dividend
distribution was made to stockholders of record at the close of business on April 10, 2000. The Rights
will expire on March 30, 2010.
During the fourth quarter of 2009, Callon commenced an exchange offer for any and all of its outstanding
Senior Notes. For each $1,000 principal amount of outstanding Senior Notes tendered in accordance with the
terms and conditions of the exchange offer, each tendering holder of the Senior Notes will receive $750
principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of common
stock and 1.6875 shares of Convertible Preferred Stock. On December 31, 2009, each share of the
Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock
following shareholder approval and the filing of an amendment to the Company’s charter increasing the
number of authorized shares of common stock as necessary to accommodate such conversion. Holders of
approximately 92% of the Senior Notes tender their notes in the exchange offer and 6.9 million shares of
common stock, after the Convertible Preferred Stock was converted into common shares, were issued to the
tendering notes holders.
18. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 2009, 2008 and 2007 have been estimated by
Huddleston & Co., Inc., the Company’s independent petroleum engineers. 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.
79
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.
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,________
__2007_
2009_
2008_
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period
Revisions to previous estimates
Change in ownership
Purchase of reserves in place
Sale of reserves in place
Extensions and discoveries
Production
End of period
Natural Gas (MMcf):
Beginning of period
Revisions to previous estimates
Change in ownership
Purchase of reserves in place
Sale 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
6,027
(356)
563
1,257
--
--
(1,012)
6,479
18,651
3,632
420
2,140
--
--
(5,740)
19,103
24,531
(9,026)
--
--
(8,536)
--
(942)
6,027
116,454
(49,526)
--
--
(42,542)
105
(5,840)
18,651
4,663
4,346
4,723
4,663
13,463
12,301
22,340
13,463
13,265
(1,152)
144
13,658
(356)
35
(1,063)
24,531
66,037
(3,022)
192
68,068
(3,690)
1,209
(12,340)
116,454
5,159
4,723
36,750
22,340
80
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 and gas price structure
utilized to project future net cash flows reflect the average of the preceding 12-month, first of the month
product prices (approximately $4.75 per Mcf for natural gas and $57.40 per Bbl for oil for the 2009
disclosures, $6.36 per Mcf and $36.80 per Bbl for 2008 disclosures, and $7.59 per Mcf and $90.92 per
Bbl for 2007 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.
Gas production from our deepwater and Permian Basin properties has a high BTU content of separator
gas. The natural gas price $4.75 used in the 2009 reserve estimate reflects estimated revenues from our
natural gas and associated natural gas liquids.
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,
2009
2008 2007
$ 462,607
(In thousands)
$ 340,485
(195,735)
( 50,170)
216,702
(2,809)
213,893
(77,972)
(192,819)
(34,111)
113,555
(565)
112,990
(26,685)
$3,113,759
(390,669)
(405,186)
2,317,904
(699,967)
1,617,937
(483,948)
$ 135,921
$ 86,305
$1,133,989
Changes in Standardized Measure
Years Ended December 31,
2009
2008 2007
(In thousands)
Standardized measure – beginning of period
Sales and transfers, net of production costs
Net change in sales and transfer prices,
net of production costs
Net change due to purchases and sales of in
place reserves
Extensions, discoveries, and improved
recovery, net of future production and
development costs incurred
Changes in future development cost
Revisions of quantity estimates
Accretion of discount
Net change in income taxes
Changes in production rates, timing and other
Aggregate change
Standardized measure - end of period
$ 86,305
(82,674)
$1,133,989
(122,104)
$ 470,791
(142,973)
94,435
(111,140)
411,525
45,009
(558,652)
795,595
--
6,194
39,242
5,797
(2,368)
(56,019)
49,616
$ 135,921
81
162,566
33,652
(786,001)
159,147
457,483
(282,635)
(1,047,684)
$ 86,305
(201,750)
--
(66,735)
53,474
(393,530)
207,592
663,198
$1,133,989
At year-end 2008, the Company had a reduction in reserves due to the sale to CIECO of a 50% interest in
the Entrada field and the abandonment of the Entrada project.
The Company ended the year 2009 with estimated net proved reserves of 58.0 billion cubic feet of natural
gas equivalent (“Bcfe”). This increase from 2008 year-end estimated net proved reserves of 54.8 Bcfe is
primarily due to the ExL acquisition which closed October 28, 2009.
The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan
for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs
only if the Company has plans to convert the PUDs into proved developed reserves within five years of
the date they are first booked as PUDs. Callon had 19.6 Bcfe of PUDs at December 31, 2009, compared
with 13.4 Bcfe of PUDs at December 31, 2008. Of these 2009 PUDs, 7.1 Bcfe and 6.9 Bcfe were
attributable to the Company’s offshore properties in the Medusa and Habanero fields in the Gulf of
Mexico, respectively. Callon plans are to develop these PUDs by side tracking existing wells when the
zones currently being produced by the wells are depleted. The Company’s current reserve reports forecast
that these producing zones in the Habenero field will be depleted in 2014 and in the Medusa field in 2022,
at which time Callon plans to develop the PUDs. The Company did not convert any offshore PUDs to
proved developed in 2009.
During 2009, the Company acquired 711 MBbls and 1.3 Bcf, or 5.6 Bcfe, of PUDs in its ExL acquisition.
Callon’s development plan for these PUDs will begin in 2010 with an anticipated completion within five
years, allowing the PUDs to be converted to PDPs. The remaining 0.6 Bcfe increase in PUDs from 2008
to 2009 is associated with the Company’s deepwater property, Medusa, and is a result of including
reserves related to the Deepwater Royalty Relief Act. These PUDs were previously excluded due to
prices exceeding the MMS imposed thresholds. As a result of court decisions, the MMS is no longer
enforcing its price thresholds. At year end 2008, the Company had no PUDs located onshore. See Note
12.
82
19. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
First Second Third Fourth
Quarter
Quarter Quarter Quarter
(In thousands, except per share data)
2009_
Total revenues
Income from operations
Net income
Net income per common share-basic
Net income per common share-diluted
$ 24,815
8,506
2,404
$ 0.11
0.11
$ 25,025 $ 21,320 $ 70,985
53,417
5,799
5,731
(925)
53,895
(955)
$ (0.04) $ (0.04) $ 2.31
2.27
(0.04)
(0.04)
(a)
(a)
(b)
First Second Third Fourth
Quarter
Quarter Quarter Quarter
(In thousands, except per share data)
2008_
Total revenues
Income (loss) from operations
Net income (loss)
Net income (loss) per common share-basic
Net income (loss) per common share-diluted
$ 44,960
21,069
7,632
$ 0.37
0.35
$ 48,029
24,046
5,153
$ 0.25
0.23
$ 32,783 $ 15,540
(500,438)
13,640
5,856
(457,534)
$ 0.27 $ (21.19)
(21.19)
0.27
(c)
(c)
(c)
(c)
(a) Includes Medusa royalty recoupment of $43.9 million, net of override, due from the MMS. See Note 12.
(b) Includes Medusa royalty recoupment of $43.9 million, net of override, and estimated interest in the
amount of $7.7 million due from the MMS.
(c) Loss resulting from impairment of oil and gas properties in the amount of $485.5 million and
establishing a full valuation allowance on the tax benefit in the amount of $128.1 million associated
with net operating loss carryforwards as of December 31, 2009.
20. SUBSEQUENT EVENTS
Subsequent to December 31, 2009, the Company completed a $100 million third amended and restated
senior secured credit agreement with Regions Bank as the sole arranger and administrative agent, which
matures on September 25, 2012. The new senior secured credit agreement provides an initial borrowing
base of $20 million, which will be reviewed and re-determined on a semi-annual basis. See Note 7.
In January 2010, Callon received a royalty refund of $44.8 million from the MMS on the royalties paid
from November 2003 through August 2009 on the Medusa field. See Note 12.
83
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
There have been no disagreements with the independent auditors on any matters of accounting principles
or practices, financial statement disclosure, or auditing scope or procedures.
ITEM 9A. CONTROLS AND PROCEDURES
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the
Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of
a company that are designed to ensure that information required to be disclosed by a company in the
reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified by the Securities and Exchange Commission. Our management,
including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our
disclosure controls and procedures as of the end of the period covered by this annual report. Based upon
that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our
disclosure controls and procedures were effective as of the end of the period covered by this annual
report. There were no changes to our internal control over financial reporting during our last fiscal quarter
that 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, 2009
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, 2009.
Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation report
on the Company’s internal control over financial reporting as of December 31, 2009.
ITEM 9A (T). CONTROLS AND PROCEDURES
See Item 9A.
84
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited Callon Petroleum Company’s internal control over financial reporting as of December
31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (the COSO criteria). 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 included in the
accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is
to express an opinion on 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,
assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, 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, Callon Petroleum Company maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2009, based on the COSO criteria.
85
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,
2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows
for each of the three years in the period ended December 31, 2009 and our report dated March 12, 2010,
expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 12, 2010
86
ITEM 9B. OTHER INFORMATION
SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS
The Company held a special meeting of shareholders on December 31, 2009. At the special meeting, the
shareholders had two proposals to consider for vote.
Proposal I - The shareholders approved an amendment to article four of the Company’s certificate of
incorporation increasing the number of authorized shares of common stock of the Company from 30
million shares to 60 million shares.
Proposal II - The shareholders approved the issuance of common stock upon conversion of convertible
preferred stock.
The votes cast for the amendments proposed in the Company’s definitive proxy statement on Schedule
14A, out of a total of 25,598,743 shares outstanding on the record date for the special meeting was as
follow:
Proposal I
Proposal II
For
18,057,317
Against or Abstained
2,141,666
11,948,390
539,905
There were broker non-votes of 7,710,688 cast for Proposal I.
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, 2009 in previously filed reports on Form 8-K.
87
PART III.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 4, 2010 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 4, 2010 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 4, 2010 which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
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 4, 2010 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 4, 2010 which will be filed with the
Securities and Exchange Commission and is incorporated herein by reference.
88
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV.
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 49 through 83.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of the Years Ended December 31, 2009 and 2008
Consolidated Statements of Operations for the Three Years in the Period Ended
December 31, 2009
Consolidated Statements of Stockholders' Equity for the Three Years in the Period Ended
December 31, 2009
Consolidated Statements of Cash Flows for the Three Years in the Period Ended
December 31, 2009
Notes to Consolidated Financial Statements
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.
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)
3.4 Certificate of Designations, Preferences and Rights of Convertible Preferred Stock of the
Company (incorporated by reference to Appendix A of the Company’s Definitive Proxy
Statement on Schedule 14A, filed December 1, 2009, File No. 001-14039)
3.5 Certificate of Correction to the Certificate of Designations, Preferences and Rights of
Convertible Preferred Stock of the Company (incorporated by reference to Exhibit 3.1 of the
Company’s Current Report on Form 8-K, filed January 4, 2010, File No. 001-14039)
89
4. Instruments defining the rights of security holders, including indentures
4.1 Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the
Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)
4.2 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 & 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)
4.5 Supplemental Indenture for the Company’s 9.75% Senior Notes due 2010, dated April 4,
2008 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-
K, filed April 9, 2008, File No. 001-14039)
4.6 Second Supplemental Indenture for the Company’s 9.75% Senior Notes due 2010, dated
November 24, 2009, between Callon Petroleum Company and American Stock Transfer &
Trust Company
4.7 Indenture for the Company’s 13.00% Senior Notes due 2016, dated November 24, 2009,
between Callon Petroleum Company, the subsidiary guarantors described therein, Regions
Bank and American Stock Transfer & Trust Company (incorporated by reference to Exhibit
T3C to the Company’s Form T-3, filed November 19, 2009, File No. 022-28916)
9. Voting trust agreement
None
10. Material contracts
10.1 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)
10.2 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 on
Schedule 14A, filed March 28, 2000, File No. 001-14039)
90
10.3 Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit
10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31,
2001, File No. 001-14039)
10.4 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)
10.5 Purchase and Sale Agreement between Callon Petroleum Company and Callon Petroleum
Operating Company as Seller, and Indigo Minerals LLC, as Buyer (incorporated by reference
from Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed December 13, 2007,
File No. 001-14039)
10.6 Purchase and Sale Agreement by and between Callon Petroleum Operating Company and
CIECO Energy (US) Limited (incorporated by reference from Exhibit 1.1 of the Company’s
Current Report on Form 8-K, filed February 13, 2008, File No. 001-14039)
10.7 Credit Agreement between Callon Entrada and CIECO Energy (Entrada) LLC dated April 4,
2008 (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-
K, filed April 9, 2008, File No. 001-14039)
10.8
Indemnity Agreement dated April 4, 2008 (incorporated by reference to Exhibit 10.4 of the
Company’s Current Report on Form 8-K, filed April 9, 2008, File No. 001-14039)
10.9 Non-Recourse Guaranty dated April 4, 2008 (incorporated by reference to Exhibit 10.5 of the
Company’s Current Report on Form 8-K, filed April 9, 2008, File No. 001-14039)
10.10 Severance Compensation Agreement dated April 18, 2008 by and between Fred L. Callon
and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K, filed April 23, 2008, File No. 001-14039)
10.11 Form of Severance Compensation Agreement dated April 18, 2008 by and between Callon
Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of
the Company’s Current Report on Form 8-K, filed April 23, 2008, File No. 001-14039)
10.12 Second Amended and Restated Credit Agreement dated as of September 25, 2008, by and
among Callon Petroleum Company, the “Lenders” described therein, Regions Bank, as
Syndication Agent, Capital One, N.A., as Documentation Agent, and Union Bank of
California, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 of the
Company’s Current Report on Form 8-K, filed October 1, 2008, File No. 001-14039)
10.13 Amendment No. 1 to Severance Compensation Agreement executed on December 31, 2008
by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference
from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File
No. 001-14039)
10.14 Form of Amendment No. 1 to Severance Compensation Agreement by and between Callon
Petroleum Company and its executive officers (incorporated by reference from Exhibit 10.2
of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039)
91
10.15 Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K,
filed January 5, 2009, File No. 001-14039)
10.16 Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan
(incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K,
filed January 5, 2009, File No. 001-14039)
10.17 Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated
by reference from Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed January
5, 2009, File No. 001-14039)
10.18 Amendment No. 1 dated as of March 19, 2009 to the Second Amended and Restated Credit
Agreement dated September 25, 2008, among Callon Petroleum Company, the “Lenders”
described therein and Union Bank of California, N.A., as Administrative Agent and as
Issuing Lender (incorporated by reference from Exhibit 10.25 to the Company’s Annual
Report on Form 10-K for the year ended December 31, 2008, File No. 001-14039)
10.19 Callon Petroleum Company 2009 Stock Incentive Plan effective as of April 30, 2009
(incorporated by reference from Exhibit A to the Company’s Definitive Proxy Statement on
Schedule 14A, filed March 30, 2009, File No. 001-14039)
10.20 Callon Petroleum Company Nonqualified Stock Option Award Agreement, dated June 1,
2009, between Callon Petroleum Company and Steven B. Hinchman (incorporated by
reference from Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period
ended June 30, 2009, File No. 001-14039)
10.21 Callon Petroleum Company Performance Share Award Agreement, dated June 1, 2009,
between Callon Petroleum Company and Steven B. Hinchman (incorporated by reference
from Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended
June 30, 2009, File No. 001-14039)
10.22 Amendment to the Callon Petroleum Company 1996 Stock Incentive Plan effective as of
August 7, 2009 (incorporated by reference from Exhibit 10.1 of the Company’s Quarterly
Report on Form 10-Q for the period ended September 30, 2009, File No. 001-14039)
10.23 Purchase and Sale Agreement by and between Callon Petroleum Operating Company and
Ambrose Energy I, Ltd. dated September 9, 2009 (incorporated by reference to Exhibit 2.1 of
the Company’s Current Report on Form 8-K, filed September 11, 2009, File No. 001-14039)
10.24 Amendment No. 3 and Agreement dated as of October 16, 2009 to the Second Amended and
Restated Credit Agreement dated September 25, 2008, among Callon Petroleum Company,
the “Lenders” described therein, and Union Bank, N.A., as Administrative Agent and as
Issuing Lender (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on
Form 8-K, filed October 22, 2010, File No. 001-14039)
10.25 Third Amended and Restated Credit Agreement dated January 29, 2010, by and among
therein, Regions Bank, as
the “Lenders” described
Callon Petroleum Company,
Administrative Agent, Documentation Agent and Syndication Agent (incorporated by
reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed February 3,
2010, File No. 001-14039)
92
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
23.3 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*
99.1 Reserve Report Summary prepared by Huddleston and Co. as of December 31, 2009.
93
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 12, 2010
/s/Fred L. Callon
Fred L. Callon (principal executive officer,
director)
Date: March 12, 2010
/s/B. F. Weatherly
B. F. Weatherly (principal financial officer,
director)
Date: March 12, 2010
Date: March 12, 2010
Date: March 12, 2010
/s/Rodger W. Smith
Rodger W. Smith (principal accounting officer)
/s/L. Richard Flury
L. Richard Flury (director)
/s/John C. Wallace
John C. Wallace (director)
Date: March 12, 2010
/s/Richard O. Wilson
Richard O. Wilson (director)
Date: March 12, 2010
/s/Larry D. McVay
Larry McVay (director)
94
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 12, 2010
CALLON PETROLEUM COMPANY
By: /s/B. F. Weatherly
B. F. Weatherly, Executive Vice-President and
Chief Financial Officer
95
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;
Registration Statement (Form S-3 No. 333-148680) of Callon Petroleum Company;
of our reports dated March 12, 2010, with respect to the consolidated financial statements of
Callon Petroleum Company 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, 2009.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 12, 2010
96
CONSENT OF HUDDLESTON & CO., INC.
EXHIBIT 23.3
As independent oil and gas consultants, we hereby consent to the references to us and our reserve reports for the
years ended December 31, 2009, 2008, and 2007 in Callon Petroleum Company’s Annual Report on Form 10-K for
the year ended December 31, 2009, which is incorporated by reference in this Registration Statement on Form S-3.
We consent to the incorporation by reference in this Registration Statement of the aforementioned report and to the
use of our name as it appears under the caption “Experts.”
HUDDLESTON & CO., INC.
Texas Registered Engineering Firm F-1024
/s/Peter D. Huddleston
Peter D. Huddleston, P.E.
President
Houston, Texas
March 11, 2010
97
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
98
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):
(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 12, 2010
By: /s/Fred L. Callon
Fred L. Callon, President and Chief Executive Officer
(Principal Executive Officer)
99
Exhibit 31.2
CERTIFICATIONS
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
100
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):
(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 12, 2010
By: /s/B. F. Weatherly
B. F. Weatherly, Executive Vice-President and
Chief Financial Officer (Principal Financial Officer)
101
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, 2009, 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 12, 2010
/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.
102
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, 2009, 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 12, 2010
/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.
103
Corporate Data
Board of Directors
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
Larry D. McVay
Former Chief Operating Officer
TNK-BP Holding (Retired)
British Petroleum plc Joint Venture
John C. Wallace
Chairman, Fred. Olsen Ltd.
London, England
Richard O. Wilson
Offshore Consultant
Houston, Texas
Company Officers
Fred L. Callon
Chairman and Chief Executive Officer
B.F. Weatherly
Executive Vice President
and Chief Financial Officer
Steven B. Hinchman
Executive Vice President
and Chief Operating Officer
Mitzi P. Conn
Corporate Controller
Robert A. Mayfield
Corporate Secretary
H. Clark Smith
Chief Information Officer
Rodger W. Smith
Vice President and Treasurer
Stephen F. Woodcock
Vice President, Exploration
Form 10-K
The Company’s annual report on Form 10-K,
excluding exhibits, has been incorporated into
this Annual Report. Extra printed copies of the
Form 10-K, excluding exhibits, may be obtained
upon written request to B.F. Weatherly 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.”
CEO Section 303A.12(a) Certification
In accordance with requirements mandated by the
New York Stock Exchange under Section 303A.12(a)
of the Listed Company Manual, each public company
is required to disclose in its Annual Report to
Shareholders that its CEO certification was filed
and to state any qualifications to such certification.
On behalf of Fred L. Callon, the company filed the
required certification on June 2, 2009
without qualification.
Notice of Annual Shareholders’ Meeting
The Annual Meeting of Shareholders will be held
Tuesday, May 4, 2010 at 9:00 a.m. CDT in the Grand
Ball Room of the Natchez Grand Hotel, 111 Broadway,
Natchez, MS 39120. Information with respect to
this meeting is contained in the Proxy Statement
sent to shareholders of record on March 5, 2010.
In accordance with SEC rules, you may access the
Proxy Statement at www.callon.com, which does
not have “cookies” that identify visitors to the site.
The 2009 Annual Report is not to be considered
a part of the proxy soliciting materials.
Callon Website
The Company has a website on the internet,
www.callon.com. It contains news releases,
corporate governance materials, the annual report,
recent investor presentations, stock quotes and
a link to our SEC filings.
Transfer Agent and Registrar
American Stock Transfer
& Trust Company
59 Maiden Lane, Plaza Level
New York, NY 10273
(718) 921-8200
Legal Counsel
Haynes and Boone, LLP
Houston, Texas
Simon, Peragine, Smith & Redfern
New Orleans, Louisiana
Independent Registered
Public Accounting Firm
Ernst & Young LLP
New Orleans, Louisiana
Bank
Regions Bank
Birmingham, Alabama
Corporate Offices
Callon Headquarters Building
200 North Canal Street
Natchez, Mississippi 39120
Callon Petroleum Company
1200 Enclave Parkway, Suite 225
Houston, Texas 77077
Callon Petroleum Company
200 N. Loraine, Suite 200
Midland, TX 79701
2009 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.
In accordance with SEC rules, you may access the
Annual Report at www.callon.com, which does not
have “cookies” that identify visitors to the site.
Security analysts and investment professionals
should direct inquiries to B.F. Weatherly, Executive
Vice President and CFO, Callon Petroleum Company,
200 North Canal Street, Natchez, MS 39120,
(601) 442-1601, (601) 446-1410 (fax).
CALLON PETROLEUM COMPANY
200 North Canal Street
Natchez, Mississippi 39120
www.callon.com