Callon Petroleum Company
2008 Annual Report to Shareholders
Corporate Profile
Callon Petroleum Company is an independent oil and gas company focused on
building reserves and production through efficient operations and low finding and
development costs. Since 1950, Callon has operated onshore and offshore in the
Gulf Coast region. At December 31, 2008, Callon owned working interests in a total
of 86 blocks covering 193,000 net acres. The Company’s estimated proved reserves at
December 31, 2008 were 54.8 billion cubic feet of natural gas equivalent (Bcfe).
Callon is focused on building value through
low-cost reserve additions in the U.S. Gulf
Coast region.
Letter to Shareholders
To Our Shareholders:
Callon Petroleum has been engaged in the oil
and gas exploration and production business both
onshore and offshore for nearly 60 years. During that
time we have endured and prospered through many
crises and fundamental changes in our industry. From
our headquarters in Natchez, Mississippi, we have
weathered seven recessions, two energy crises and
the resulting collapse of the oil and gas markets and
the “gas bubble” in the 1980’s. We have also seen
more difficult commodity price environments than
the one we are experiencing today, having made it
through oil prices below $10 per barrel in 1986.
Through volatile markets and uncertain times,
one constant has been Callon’s ability to endure.
We have risen to the challenges we faced by making
the difficult decisions necessary to survive and
ultimately prosper. Sometimes we forget that the
energy business is a cyclical one and although we
can’t control the world economic environment,
we can control our reactions and try to make the
right decisions in tough times. Today, we are faced
with yet another challenging business environment
resulting from weak commodity prices, volatile
equity markets and a global recession.
Liquidity and Financial Strength
for Flexibility
Maintaining financial strength has been a key
element of our financial strategy. Our present
liquidity position preserves our ability to respond
and adapt to rapidly changing market and economic
conditions. Beginning in 2007 and continuing
throughout 2008, we carefully managed our liquidity
position with several initiatives. In the summer
of 2008, we established hedges for our legacy oil
production using collars with a floor of $110 to cover
approximately 45% of our expected production for
2009. These hedges provide us significant downside
price protection and have a current combined value
in excess of $17 million. At year end 2008, we also
had $55 million available on our revolving line of
credit. Our highly liquid position, combined with
our expected operating cash flow, provides us the
financial flexibility to fund opportunistic producing
property acquisitions in order to grow the company’s
reserves and production over the next several years.
Our present liquidity position preserves our ability
to respond and adapt to rapidly changing market
and economic conditions.
2008 Annual Report
1
Strategic Focus –
Acquire and Develop
We are modifying our business strategy to emphasize
an “acquire and develop” strategy instead of the
capital-intensive exploration focus we have pursued
over the past few years. Given the current turmoil
in the financial markets and lower commodity
prices, we believe the acquisition prices of quality
producing oil and natural gas properties will decline
to attractive levels. We have been actively evaluating
both asset and corporate acquisition opportunities
since the second half of 2008, and we will continue
this activity in 2009. By prudently using our liquidity
and patiently and opportunistically pursuing
acquisitions in this environment, we plan to add
quality reserves which will serve as catalysts for
growth over the next several years.
Callon is focusing its acquisition strategy in the
offshore and onshore U.S. Gulf Coast region, where
we have successfully operated for many years.
This region is our “home market” where we have
decades of operational experience and a strong
technical staff. We are working diligently to assess
the best opportunities that fit our investment and
operational criteria and provide the potential to
increase long-term shareholder value.
Entrada Field Update
In 2008, we began development of our deepwater
Entrada Field. The first development well was
spud in September after delays brought on by the
failure of the MMS required vertical load anchoring
system for the semisubmersible drilling rig we had
under contract. In addition, before we commenced
drilling operations, we were forced to evacuate
the rig twice due to back-to-back hurricanes. After
finally reaching total depth of 21,100 feet it was
determined that the well needed to be sidetracked.
During the time we were drilling at Entrada, oil
prices fell dramatically, coinciding with the onset of
the global recession. These rapidly declining prices,
combined with delay-related cost overruns, resulted
in a severe degradation of the project’s economic
returns. As a result, the difficult decision was made
to suspend operations at Entrada. To say we were
disappointed by the outcome of our Entrada Field
project would be an understatement. However, in
the end suspending operations was the right thing to
do to preserve shareholder value.
With a final lease expiration anticipated in June
2009, it is unlikely that we will resume commercial
operations at Entrada. As a result, we have
been working to close down the project, finalize
outstanding contractual commitments, and dispose
of the tangible equipment that had been acquired
for the project. These efforts are ongoing and should
be largely resolved in the first half of 2009.
Callon is focusing its acquisition strategy in the
offshore and onshore U.S. Gulf Coast region where
we have successfully operated for many years.
2
Callon Petroleum Company
Operations Overview
Hurricanes Gustav and Ike hit the Gulf of Mexico
and the U.S. Gulf Coast in August and September
2008, which caused us to shut-in production of
approximately 12.8 million cubic feet of natural
gas equivalent per day during the third quarter and
18 million cubic feet of natural gas equivalent per
day during the fourth quarter. By mid-December,
all of our major Gulf of Mexico producing properties
were back online.
Despite the delays, we still averaged 31.4 million
cubic feet of natural gas equivalent per day of
production for 2008 and were within the range of
guidance we provided to the investment community
in the fourth quarter of 2008. Approximately 51%
of 2008 total production volumes were natural gas.
Production volumes in 2008 were 39% lower than
2007 primarily due to the impact of hurricane activity
and reduced capital expenditures.
Our deepwater fi elds and several of our shelf fi elds
were shut-in in August 2008 due to the approach of
Hurricane Gustav, closely followed by Hurricane Ike.
As a result of damage to third-party transmission
lines and downstream facilities, these fields
remained shut-in until late in the fourth quarter of
2008, signifi cantly impacting our operating results
for both the third and fourth quarters.
At the Medusa Field, eight wells are currently
producing 13,200 barrels of oil and 12 million cubic
feet of natural gas per day. A program of workovers
and the drilling of an additional well have
been deferred until 2010 because of current low
commodity prices. We own a 15% working interest
in the Medusa Field; Murphy Exploration
& Production Company is the operator.
The Habanero Field is producing 6,000 barrels of
oil and 9 million cubic feet of natural gas per day
from two wells, both producing from the Hab 52 oil
reservoir. We own an 11.25% working interest in the
number two well and a 25% working interest in the
number one well. Shell Offshore Inc. is the operator.
The West Cameron 295 Field is producing 120 barrels
of oil and 19 million cubic feet of natural gas per
day. The number two and four wells are operated by
Mariner Energy, Inc., while the number three well is
operated by Cimarex Energy Company. Callon owns
a 20.5% working interest in the wells.
First production at our East Cameron 2
(North Pronghorn Field) commenced in October
2008, and the fi eld is currently producing 100 barrels
of oil and 7 million cubic feet of natural gas per day.
The field is operated by Apache Corporation; Callon
owns a 42.5% working interest.
Our East Cameron 257 Field is producing 5 million
cubic feet of natural gas per day, the field is
operated by SPN Resources LLC; we own a 50%
working interest.
The oil and gas business is cyclical and Callon
is well-positioned to endure and capitalize on
opportunities the current cycle brings.
2008 Annual Report
3
Reserves
Our estimated net proved reserves at December
31, 2008 were 54.8 billion cubic feet of natural gas
equivalent. This represents a decline in our reserves
of 208.8 billion cubic feet of natural gas equivalent
as compared to year end 2007 due to a combination
of factors. The sale of a 50% working interest in the
Entrada Field to CIECO Energy in April 2008 accounts
for 45% of the decrease. The previously announced
suspension of operations at the Entrada Field in
November 2008 accounts for 47% of the decrease,
and our 2008 production and other changes account
for the remaining 8%. The PV-10 value of our
reserves at December 31, 2008 was $86.6 million.
Commodity price volatility during 2008 was
extreme and commodity prices at the end of
2008 were sharply lower than at year-end 2007.
At December 31, 2008, we recorded a non-cash
charge of $485.5 million for the impairment of oil
and gas properties under full-cost accounting rules,
which was the result of sharply lower oil and natural
gas prices used at year-end 2008 and the decline in
reserves. The oil and gas prices used in the reserve
report were $36.80 per barrel of oil and $6.36 per
thousand cubic feet of natural gas.
2009 Outlook
As we look forward to 2009, we expect the year
to be a challenging one for the energy industry
and for our company. However, I am confident in
the experience, skills and clear-minded insight of
our team to navigate through these stormy waters
as we have done time after time.
We have limited required capital expenditures
in 2009, including approximately $10 million of
scheduled plugging and abandonment expenditures.
In addition, as long as the current environment of
low commodity prices and relatively high service
costs impairs project economics, we will defer
drilling our high-graded inventory of nine Gulf
of Mexico prospects in favor of focusing on the
acquisition of producing properties.
We are aggressively working to identify attractive
acquisitions which will establish an appropriate
multi-year growth catalyst. Our acquisition screening
efforts are targeting geographic areas where
traditionally we have been successful. Fortunately,
we are well-positioned from a liquidity perspective
as a result of our strong hedges, minimal capital
requirements, and ample borrowing capacity. In
addition, we continue to monitor the commodity and
oil service markets for indications that the economics
of our existing drilling portfolio will improve a
scenario which may serve as a near-term catalyst.
I want to thank our hard-working employees,
bankers, industry partners, board members and loyal
shareholders for their contributions.
Fred L. Callon
Chairman
4
Callon Petroleum Company
SECURITIES AND EXCHANGE COMMISSION
UNITED STATES
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008
Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
200 North Canal Street
Natchez, Mississippi 39120
(Address of Principal Executive
Offices)(Zip Code)
64-0844345
(I.R.S. Employer
Identification No.)
(601) 442-1601
(Registrant’s telephone number
including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, Par Value $.01 Per Share
Name of exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes__ No
X.
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __
No X .
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No .
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will
not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-K or any amendment to this Form 10-K. [ __ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See
definitions of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ____ Accelerated filer X Non-accelerated filer ___
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ___ No X .
The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the registrant was approximately
$557 million as of June 30, 2008 (based on the last reported sale price of such stock on the New York Stock Exchange on such
date of $27.36).
As of March 10, 2009, there were 21,637,470 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, 2008) relating to the Annual Meeting of Stockholders to be held on April 30, 2009,
which are incorporated into Part III of this Form 10-K.
1
Table of Contents
Page
Item 1 and 2. Business and Properties
Item 1A.
Item 1B.
Item 3.
Item 4.
Item 5.
Risk Factors
Unsolved Staff Comments
Legal Proceedings
Submission of Matters to a Vote of Security Holders
Market for Registrant’s Common Equity and Related
Stockholder Matters
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
Controls and Procedures
Other Information
Directors and Executive Officers of the Registrant
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
Certain Relationships and Related Transactions
Principal Accountant Fees and Services
Exhibits, Financial Statement Schedules and Reports on Form 8-K
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
3
16
27
27
27
28
29
32
47
48
79
79
82
83
83
83
83
83
84
2
PART I.
ITEM 1 and 2. BUSINESS and PROPERTIES
Overview
Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of
oil and gas properties since 1950. Our properties are geographically concentrated primarily in the Gulf Coast
Region both onshore and offshore. We were incorporated under the laws of the state of Delaware in 1994 and
succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of
European investors and an independent energy company owned by 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.
In 1989, we began increasing our reserves through the acquisition of producing properties that were
geologically complex, had (or were analogous to fields with) an established production history from stacked
pay zones and were candidates for exploitation. We focused on reducing operating costs and implementing
production enhancements through the application of technologically advanced production and recompletion
techniques.
Over the past 13 years, we have placed emphasis on the acquisition of acreage with exploration and
development drilling opportunities in the Gulf of Mexico shelf and deepwater areas. At December 31, 2008,
we owned working interests in a total of 86 blocks/leases covering 193,000 net acres. To minimize risk we
join with industry partners to explore federal offshore blocks acquired in the Gulf of Mexico. We perform
extensive geological and geophysical studies using computer-aided exploration techniques (CAEX),
including, where appropriate, the acquisition of 3-D seismic or high-resolution 2-D data to facilitate these
efforts. We continue to develop prospects on the shelf through our 3-D seismic partnership using Amplitude
versus Offset (“AVO”) technology. We have approximately 20,000 square miles of 3-D seismic data and
have invested in pre-stack time migration in order to apply AVO de-risking to our prospects. In 1998, we
began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water) and during the
fourth quarter of 2003, our first two deepwater projects, the Medusa and Habanero fields, began production.
Please see “Significant Properties” for a more detailed discussion.
Business Plans for 2009
The economies of the United States and rest of the world are currently in a recession which is expected to
last through 2009, perhaps longer. This recession has caused prices for oil and gas to be significantly
lower than prevailing prices in the first three quarters of 2008. In addition, the capital markets are
experiencing significant disruptions, and many financial institutions have liquidity concerns, prompting
government intervention to mitigate pressure on the credit markets. These disruptions are expected to
make it increasingly difficult for us to access the capital markets to finance growth opportunities.
In response to these developments, and the change in forecasted cash flows as a result of the abandonment
of the Entrada project, we plan to modify our focus in 2009. In particular, we plan to
(cid:2)
(cid:2)
(cid:2)
reduce our focus on exploration drilling in the Gulf of Mexico;
focus on acquisition of domestic, producing properties with development upside and longer
reserve lives; and
partner with financial and industry participants to finance our acquisition activities.
3
Our leases that are in unevaluated oil and gas properties do not expire for a couple of years which allows
us some flexibility. We are constantly monitoring market conditions and when we see project economics
improve as a result of some combination of increasing commodity prices and/or reductions in service
costs in the Gulf, we will revisit our drilling plans.
The Entrada Project
Entrada is an oil and gas field located in approximately 4,500 feet of water in the Gulf of Mexico. In
2000, we acquired a 20% interest in the field and drilled two successful exploration wells. In April 2007,
we acquired the 80% working interest in the field that we did not then own. On April 8, 2008, we sold a
50% working interest in the Entrada field to CIECO Energy (US) Limited (“CIECO”), for a cash payment
of $155 million and an agreement to pay an additional $20 million after the achievement of certain
production milestones. We also contributed our 50% share of the Entrada project to our wholly-owned
subsidiary, Callon Entrada Company (“Callon Entrada”). As part of the purchase, CIECO agreed to loan
Callon Entrada the first $150 million of Callon Entrada’s costs to develop the Entrada project plus up to
$12 million of additional loans to pay accrued interest thereon, which loans were non-recourse to any
entity other than Callon Entrada, were not guaranteed by Callon or any of its other subsidiaries, and were
to be repaid solely out of the proceeds of the sale of production from the Entrada project.
Our order of magnitude estimate of the total costs to develop the Entrada project were to be
approximately $300 million, or $150 million net to Callon Entrada’s 50% interest in the project.
Development of the Entrada project included the drilling of two wells, the #3 and #4 wells, and the
construction of sub-sea tie backs to a production platform owned by another oil and gas company on an
adjacent field in the Gulf of Mexico. Estimated costs to complete the project increased by over 50%
primarily due to damage and down time caused by two hurricanes in the Gulf of Mexico, unanticipated
additional costs imposed by the Minerals Management Service (“MMS”) requiring that we use a mooring
system (vertical load anchors) different from that we intended to use (conventional drag anchors), which
mooring system was ultimately unsuccessful, subsurface mechanical problems and higher fuel costs. In
late November 2008, the #3 well reached its total depth of 21,100 feet. After discussions with CIECO
and a review of the project economics, the decision was made to abandon the project.
Under the terms of its agreements with CIECO, Callon Entrada is responsible for its 50% working interest
share of the costs to plug and abandon the Entrada project, and CIECO is responsible for its 50% working
interest share of plugging and abandonment costs. Total wind down costs to abandon the project are
estimated to be approximately $46 million, or $23 million net to Callon Entrada. The Entrada leases are
scheduled to expire in June 2009 and plugging and abandonment of the original two wells will be done
within 18 month of the lease expiration.
We are in discussions with CIECO with regard to its failure to fund $40 million in loan requests made in
October and November and its share of a settlement payment to terminate a drilling contract. Because
these discussions are in early stages, 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
regarding the loan requests or the drilling contract settlement.
Business Strategy
Our goal is to increase shareholder value by increasing our reserves, production, cash flow and earnings.
We seek to achieve these goals through the following strategies:
(cid:2)
in the current environment, focus on the acquisition of proved developed properties along with
underlying undeveloped properties both onshore and offshore in the Gulf Coast Region;
4
(cid:2)
as commodity prices improve and service costs decline, explore and develop oil and gas
properties; and
(cid:2) maintain efficient low operating costs.
Funding to achieve these goals will come from cash flows from operations, cash on hand and if needed,
borrowings from our senior secured revolving credit facility.
Exploration and Development Activities
In 2008, capital expenditures on an accrual basis for exploration and development costs related to oil and
gas properties totaled approximately $192 million. These expenditures included:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
$144 million for our Entrada project;
$15 million in our deepwater area, which included one development well at our Medusa Field;
$6 million in the Gulf of Mexico shelf and onshore south Louisiana:
$4 million for leasehold and seismic costs;
$4 million for plugging and abandonment costs; and
$7 million for capitalized interest and $12 million for capitalized general and administration costs
allocable directly to exploration and development projects.
Acquisitions and Divestitures
In April 2007, we acquired BP Exploration and Production Company’s (“BP”) 80% working interest in
Entrada Field for a purchase price of $190 million, which included $150 million payable at closing and an
additional $40 million payable after the achievement of certain production milestones. To strengthen our
balance sheet and provide additional liquidity for the development of our Gulf of Mexico deepwater field
Entrada, we completed the sale of certain non-core, non-operated royalty and mineral interests for $61.5
million in December 2007.
On April 8, 2008, we completed the sale of a 50% working interest in the Entrada Field to CIECO for a
purchase price of $175 million with a cash payment of $155 million at closing and the additional $20
million payable after the achievement of certain production milestones. See Note 15 - “Entrada” for more
details.
Property Summary
We are engaged in the exploration, development, acquisition and production of oil and gas properties. Our
properties are concentrated both onshore and offshore in the Gulf Coast Region. We have historically
increased our reserves and production by focusing primarily on low to moderate risk exploration and
acquisition opportunities in the Gulf Coast Region. In 1998, we expanded our area of exploration to include
the Gulf of Mexico deepwater area. As of December 31, 2008, our estimated net proved reserves totaled 54.8
billion cubic feet of natural gas equivalent (“Bcfe”) and included 6.0 million barrels of oil (“MMBbls”) and
18.7 billion cubic feet of natural gas (“Bcf”), with a pre-tax present value, discounted at 10%, of the estimated
future net revenues based on constant prices in effect at year-end of $86.6 million. Oil constitutes
approximately 66% on an equivalent basis of our total estimated proved reserves and approximately 76% of
our total estimated proved reserves are proved developed reserves.
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 as discussed above and
the abandonment of the Entrada project.
5
Significant Properties
The following table shows discounted cash flows and net proved oil and gas reserves estimated by our
independent petroleum reserve engineers by major field and for all other properties combined at December
31, 2008.
Estimated Net Proved Reserves
Oil
Operator
(MBbls)
Gas
Pre-tax
Discounted
Present
Value
($000)
(a)(b)(c)
(MMcfe)
(MMcf)
Total
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 257
East Cameron Block 109
East Cameron 2/LA
Other
Murphy
4,929
3,506
33,078 $ 52,872
Shell
953
5,041
10,758
28,687
Mariner Energy
SPN Resources
Energy Partners LTD
Apache
Various
9
--
37
19
80
2,195
1,401
1,286
977
4,246
2,249
1,401
1,508
1,095
4,727
8,015
5,492
5,491
4,189
(18,155)
Total Net Proved Reserves
6,027
18,652
54,816 $ 86,591
(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, 2008, as set
forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers,
Huddleston & Co., Inc. of Houston, Texas. Year-end average pricing was $6.36 per Mcf for natural
gas and $36.80 per Bbl for oil.
(b) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on
our balance sheet at December 31, 2008, in accordance with Statement of Financial Accounting
Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). See the Oil and
Gas Reserve table for the standardized measure of discounted future net cash flow. 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.” This is a non-GAAP financial measure. We
believe that Pre Tax Present Value, while not a financial measure in accordance with generally accepted
accounting principles, is an important financial measure used by investors and independent oil and gas
producers for evaluating the relative value of oil and natural gas properties and acquisitions because the
tax characteristics of comparable companies can differ materially. The total standardized measure for
our proved reserves as of December 31, 2008 was $86.3 million. The standardized measure gives effect
to income taxes, and is calculated in accordance with Statement of Financial Accounting Standards No.
69, “Disclosures About Oil and Gas Producing Activities.” The standardized measure of our estimated
net proved reserves of $86.3 million equals the present value of our estimated future net revenue from
proved reserves, excluding income taxes, of $86.6 million, less discounted estimated future income taxes
relating to such future net revenues of $0.3 million.
6
Medusa, Mississippi Canyon Blocks 538/582
Gulf of Mexico Deepwater
Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test well
in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in two intervals.
Subsequent sidetrack drilling from the wellbore was used to determine the extent of the discovery, and a
second well was drilled in the first quarter of 2000 to further delineate the extent of the pay intervals. We
own a 15% working interest, Murphy Exploration & Production Company (“Murphy”), the operator,
owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25% working interest.
In 2001, a drilling program began which included four development wells and one sidetrack. The
program included production casing being set on six wells to provide initial production take-points and
was completed in the first half of 2002. The construction of a floating production system, spar, at Medusa
was completed during the second quarter of 2003. The A-1 well was completed and tied into the spar and
commenced production in late November 2003. The remaining five wells were completed and
commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled in 2003 and was
temporarily abandoned after encountering 28 feet of net pay. The well bore was re-entered in the fourth
quarter of 2004, sidetracked and reached an objective depth of 9,600 feet in January 2005. The sidetrack
encountered 46 feet of net pay, was completed and commenced initial production in April 2005. In 2007,
the Mississippi Canyon 538 #5 was drilled into a previously untapped fault- separated reservoir and
commenced initial production in June 2008.
During 2008 the field produced 3.6 Bcfe net to us which accounted for 31% of our total production.
Future plans include five recompletions to produce up-hole sands and a new well to an undrained area of
the field up-dip or fault separated from existing production.
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. We own an 11.25% working interest in the well. The well is operated by Shell Deepwater
Development Inc., which owns a 55% working interest, with the remaining working interest being owned
by Murphy.
A field delineation program began in mid-year 2001, which included three sidetracks of the discovery
well. Production casing was set on this well through the last of the sidetracks to the Habanero 52 oil and
gas sand and the Habanero 55 gas sand. Also, a development well was drilled in the summer of 2003
which provides a take-point for production from the Habanero 52 oil sand. By means of a sub-sea
completion and tie-back to an existing production facility in the area operated by Shell, production from
the Habanero 52 oil sand commenced in late November 2003 and from the Habanero 55 gas sand in
January 2004. In July 2004, the #2 well producing the Habanero 52 oil sand developed mechanical
7
difficulties with a subsurface control valve and was shut-in resulting in a significant loss of production.
Repairs were completed and production was restored in late December 2004. In addition, the #1 well
producing the Habanero 55 gas sand was recompleted to the Habanero 52 oil sand in December 2004.
At the time the field was developed, there was no way to know what the drive mechanism would be in the
Habanero 52 oil sand, so the wells were drilled in a mid-dip position. It is now known that the Habanero
52 oil sand has strong water support requiring a well at structural crest for maximum recovery. A
sidetrack of the #1 well was completed in the third quarter of 2007 at a structurally high position.
Future plans include sidetracks of both the wells to drain updip and partially fault-separated gas in the
Habanero 52 sand.
During 2008, Habanero produced 2.6 Bcfe net to us which accounted for 22% of our total production.
Gulf of Mexico Shelf and Onshore Louisiana
West Cameron Block 295
During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150 feet of
net pay in two zones. Each zone was encountered at the predicted depth and exceeded anticipated
thickness. The #2 well commenced production in the second quarter of 2006 and encountered mechanical
difficulties which were corrected. Sustained production was achieved by the third quarter of 2006. In
2006, we drilled the #4 well, an offset to the #2 well. The #4 well commenced production during
December 2006 in a deeper, secondary zone. After depletion the well was recompleted to the primary
pay zone and commenced production in December 2007. Callon holds a 20.5% working interest in the
block and Mariner is the operator.
A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth of
16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two zones.
The well was completed in a deeper secondary zone and commenced production in August 2006. The
well ceased production in May 2008. Subsequent diagnostic work determined that both the deeper
secondary zone and the shallower primary zone were drained by the initial completion. There are no
additional plans for the well at this time. Callon holds a 20.5% working interest in the block and Cimarex
Energy Company is the operator.
During 2008, the West Cameron 295 field produced 1.0 Bcfe net to us.
East Cameron 257
During 2001, an exploratory well was drilled to a vertical depth of 8,300 feet and was temporarily
abandoned. In 2006, the operator made the decision to complete and produce this well. During 2008, the
East Cameron 257 field produced 0.5 Bcfe net to us.
East Cameron 109
During 2006, an exploratory well was drilled to a vertical depth of 13,110 feet and encountered 54 feet of
net pay. The well produced 0.2 Bcfe net to us in 2008. Callon owns a 25% working interest and Energy
Partners, LTD is the operator.
8
East Cameron 2/LA
The State Lease 18121 #1 well was drilled to a vertical depth of 14,851 feet and encountered 20 feet of net
pay in August, 2007. First production was in the fourth quarter of 2008 and the well produced 0.2 Bcfe net to
us. Callon owns a 42.5% working interest and Apache is the operator.
Oil and Gas Reserves
The following table sets forth certain information about our estimated proved reserves as reported by
Huddleston & Co., Inc. as of the dates set forth below.
2008_
Years Ended December 31,
2007_
(In thousands)
2006_
Proved developed:
Oil (Bbls)
Gas (Mcf)
Mcfe
Proved undeveloped:
Oil (Bbls) (c)
Gas (Mcf) (c)
Mcfe (c)
Total proved:
Oil (Bbls) (c)
Gas (Mcf) (c)
Mcfe (c)
4,663
13,463
41,441
4,723
22,340
50,676
1,364
5,189
13,375
19,808
94,114
212,964
5,159
36,750
67,704
8,106
29,287
77,924
6,027 24,531
18,652 116,454
54,816 263,640
13,265
66,037
145,628
Estimated pre-tax future net cash flows (a)
$ 113,555 $ 2,317,905
$ 775,742
Pre-tax discounted present value (a) (b)
$ 86,591 $ 1,591,472
$ 534,743
Standardized measure of discounted future
net cash flows(a) (b)
$ 86,305 $ 1,133,989
$ 470,791
(a)
Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on
our balance sheet at December 31, 2008, in accordance with SFAS 143.
(b) We use the financial measure “Pre Tax Present Value.” This is a non-GAAP financial measure. We
believe that Pre Tax Present Value, while not a financial measure in accordance with generally
accepted accounting principles, is an important financial measure used by investors and independent
oil and gas producers for evaluating the relative value of oil and natural gas properties and
acquisitions because the tax characteristics of comparable companies can differ materially. The total
standardized measure for our proved reserves as of December 31, 2008 was $86.3 million. The
standardized measure gives effect to income taxes, and is calculated in accordance with Statement of
Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities.” The
standardized measure of our estimated net proved reserves of $86.3 million equals the present value
of our estimated future net revenue from proved reserves, excluding income taxes, of $86.6 million,
9
less discounted estimated future income taxes relating to such future net revenues of $0.3 million.
Year-end average pricing was $6.36 per Mcf for natural gas and $36.80 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.
Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved reserves and
the future net cash flows and present value thereof attributable to such proved reserves. Reserves were
estimated using oil and gas prices and production and development costs in effect on December 31 of each
such year, without escalation, and were otherwise prepared in accordance with SEC regulations regarding
disclosure of oil and gas reserve information.
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors
beyond our control or the control of the reserve engineers. Reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The
accuracy of any reserve or cash flow estimate is a function of the quality of available data and of engineering
and geological interpretation and judgment. Estimates by different engineers often vary, sometimes
significantly. In addition, physical factors, such as the results of drilling, testing and production subsequent to
the date of an estimate, as well as economic factors, such as an increase or decrease in product prices that
renders production of such reserves more or less economic, may justify revision of such estimates.
Accordingly, reserve estimates could be different from the quantities of oil and gas that are ultimately
recovered.
We have not filed any reports with other federal agencies which contain an estimate of total proved net oil and
gas reserves during our last fiscal year.
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,_ __________
2006_____
_Net_
Gross
2007 ____
_Net_
Gross
2008_ ___
_Net_
Gross
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
0.25
0.12
--
0.37
--
--
2 0.63
0.47
1.10
3
5
--
2
--
2
--
5
8
13
--
0.37
--
0.37
--
2.05
2.98
5.03
The following table sets forth our productive wells as of December 31, 2008:
Oil:
Working interest
Royalty interest
Wells ______
Net__
Gross_
10.00
--
1.56
--
Total
10.00
1.56
Gas:
Working interest
Royalty interest
18.00
6.00
7.22
0.18
Total
24.00
7.40
A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas reserves on a
thousand cubic feet of natural gas equivalent (“Mcfe”) basis. However, some of our wells produce both oil
and gas. At December 31, 2008, 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, 2008.
Location
Louisiana
Texas
Federal waters
Leasehold Acreage__________
Undeveloped __
Developed____
Net__
Gross_
Net__ Gross_
5,666
3,520
87,990
2,107
1,760
36,500
4,718
4,800
313,354
1,054
3,240
147,870
Total
97,176
40,367
322,872
152,164
Major Customers
Our production is sold generally on month-to-month contracts at prevailing prices. The following table
identifies customers to whom we sold a significant percentage of our total oil and gas production during
each of the 12-month periods ended:
Shell Trading Company
Louis Dreyfus Energy Services
StatoilHydro
Plains Marketing, L.P.
December 31, __ ___
2006_
2007_
2008_
41%
25%
33%
25%
20%
16%
--
13%
--
11%
10%
23%
Because alternative purchasers of oil and gas are readily available, we believe that the loss of any of these
purchasers would not result in a material adverse effect on our ability to market future oil and gas production.
Title to Properties
We believe that the title to our oil and gas properties is good and defensible in accordance with standards
generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so
material as to detract substantially from the use or value of such properties. Our properties are typically
subject, in one degree or another, to one or more of the following:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
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;
12
(cid:2)
(cid:2)
pooling, unitization and communitization agreements, declarations and orders; and
easements, restrictions, rights-of-way and other matters that commonly affect property.
To the extent that such burdens and obligations affect our rights to production revenues, they have been taken
into account in calculating our net revenue interests and in estimating the size and value of our reserves. We
believe that the burdens and obligations affecting our properties are conventional in the industry for properties
of the kind owned by us.
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 87 employees as of December 31, 2008, none of whom are currently represented by a union. We
believe that we have good relations with our employees. We employ eight petroleum engineers and eight
petroleum geoscientists.
Regulations
General. The oil and gas industry is subject to regulation at the federal, state and local level, and some of
the laws, rules and regulations that govern our operations carry substantial penalties for non-compliance.
This regulatory burden increases our cost of doing business and, consequently, affects our profitability.
Exploration and Production. Our operations are subject to federal, state and local regulations that
include requirements for permits to drill and to conduct other operations and for provision of financial
assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation
are:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
the location of wells,
the method of drilling and completing wells,
the rate of production,
the surface use and restoration of properties upon which wells are drilled,
the plugging and abandoning of wells,
the 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 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 plans and
exploitation and production plans prior to the commencement of such operations. The MMS has
promulgated regulations requiring offshore production facilities located on the OCS to meet stringent
engineering and construction specifications. The MMS also has regulations restricting the flaring or
venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil without prior
13
authorization. MMS policies concerning the volume of production that a lessee must have to maintain an
offshore lease beyond its primary term also are applicable to Callon. Similarly, the MMS has promulgated
other regulations governing the plugging and abandonment of wells located offshore and the installation
and removal of all production facilities. To cover the various obligations of lessees on the OCS, the
MMS generally requires that lessees have substantial net worth or post bonds or other acceptable
assurances that such obligations will be met. The cost of these bonds or other surety can be substantial,
and there is no assurance that bonds or other surety can be obtained in all cases. Under some
circumstances, the MMS may require any of our operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially adversely affect our financial conditions
and results of operations.
Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation.
The price and terms for access to pipeline transportation remain subject to extensive federal regulation. If
these regulations change, we could face higher transmission costs for our production and, possibly,
reduced access to transmission capacity.
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. (cid:3)
Various proposals and proceedings that might affect the petroleum industry are pending before Congress,
the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The
industry historically has been heavily regulated and we can offer you no assurance that the less stringent
regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what
effect such proposals or proceedings may have on our operations.
Environmental Regulation. Various federal, state and local laws and regulations concerning the
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,
(cid:2)
(cid:2)
(cid:2)
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
14
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 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 increasing 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.
More stringent laws and regulations relating to climate change and greenhouse gases (GHGs) may be
adopted in the future and could cause us to incur material expenses in complying with them. The U.S.
Congress last session considered climate change-related legislation to regulate GHG emissions that could
affect our operations and our regulatory costs, as well as the value of oil and natural gas generally.
Although that legislation did not pass, expectations are that Congress will continue to consider some type
of climate change legislation and that EPA may consider climate change-related regulatory initiatives. As
a result, 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 federal 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. These regulatory initiatives also could adversely
affect the marketability of the oil and natural gas we produce.
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
15
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 business costs in the oil and gas industry. Although we are not fully
insured against all environmental risks, we maintain insurance coverage which we believe is customary in
the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive
environmental laws and regulations, as well as claims for damages to property or persons resulting from
company operations, could result in substantial costs and liabilities, to Callon. We believe we are in
compliance with existing environmental regulations, and that, absent the occurrence of an extraordinary
event the effect of which cannot be predicted, any noncompliance will not have a material adverse effect
on our operations or earnings. (cid:3)
(cid:3)(cid:3)
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 Securities and Exchange Commission (“SEC”) filings are available
on our website as soon as they are posted to the EDGAR database on the SEC’s website.
Item 1A.
Risk Factors
Risk Factors
If the United States experiences a sustained economic downturn or recession, oil and natural gas
prices may fall or remain at their current depressed price for an extended period of time, which
may adversely affect our results of operations. The unprecedented disruption in the U.S. and
international credit markets has resulted in a rapid deterioration in the worldwide economy and tightening
of the financial markets in the second half of 2008, and the outlook for the economy in 2009 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. 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.
For example, for the quarter ending December 31, 2008, a 10% reduction in the price we received for oil
and natural gas would have reduced our revenues by approximately $1.6 million. The continuation, or
16
worsening, of domestic and global economic conditions could continue to adversely affect our business
and results of operations.
We may not be able to obtain funding on acceptable terms or at all because of the deterioration of
the credit and capital markets. This may hinder or prevent us from meeting our future capital
needs including the need to refinance $200 million in senior notes in 2010. Global financial markets
and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors.
As a result, the cost of raising money in the debt and equity capital markets has increased substantially
while the availability of funds from those markets has diminished significantly. As a result of concerns
about the stability of financial markets generally and the solvency of lending counterparties specifically,
the cost of obtaining money from the credit markets generally has increased as many lenders and
institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance
existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to
borrowers. In addition, lending counterparties under our existing senior secured revolving credit facility
and $200 million in senior notes 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. Over the next 18 months, we will be required to refinance our $200 million of senior
notes. 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.
We may be unable to integrate successfully the operations of future acquisitions with our
operations and we may not realize all the anticipated benefits of any future 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 cannot assure you
that we will achieve the desired profitability from any acquisitions we may complete in the future. In
addition, failure to assimilate future acquisitions successfully could adversely affect our financial
condition and results of operations.
Our acquisitions may involve numerous risks, including:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
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;
the risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may
not be developed as anticipated;
the loss of significant key employees from the acquired business:
the diversion of management’s attention from other business concerns;
the failure to realize expected profitability or growth;
the failure to realize expected synergies and cost savings;
17
(cid:2)
(cid:2)
coordinating geographically disparate organizations, systems and facilities; and
coordinating or consolidating corporate and administrative functions.
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.
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.
During periods of falling commodity prices, such as in late 2008, 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 financially distressed 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.
Continued 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. Oil
and gas prices are currently lower than in early 2008. Extended 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;
(cid:2) our revenues, cash flows and earnings;
(cid:2)
(cid:2) our ability to attract capital to finance our operations and the cost of the capital;
(cid:2)
the amount we are allowed to borrow under our senior secured credit facility;
(cid:2)
the value of our oil and gas properties; and
(cid:2)
the profit or loss we incur in exploring for and developing our reserves.
18
Our reserve information represents estimates that may turn out to be incorrect if the assumptions
upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will materially affect the quantities and present value of our
reserves. The process of estimating oil and gas reserves is complex. It requires interpretations of
available technical data and various assumptions, including assumptions relating to economic factors.
Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated
quantities and present value of reserves shown in this annual report.
In order to prepare these estimates, we must project production rates and the timing of development
expenditures. The assumptions regarding the timing and costs to commence production from our
deepwater wells used in preparing our reserves are often subject to revisions over time as described under
“Our deepwater operations have special operational risks that may negatively affect the value of those
assets.” We must also analyze available geological, geophysical, production and engineering data, the
extent, quality and reliability of which can vary. The process also requires us to make economic
assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and gas reserves most likely will vary from the estimates. Any
significant variance could materially affect the estimated quantities and present value of reserves shown
in this report. In addition, estimates of proved reserves may be adjusted to reflect production history,
results of exploration and development, prevailing oil and gas prices and other factors, many of which are
beyond our control.
Also, under MMS rules governing our deepwater Medusa property and several of our shallow water, deep
natural gas properties and prospects, we are eligible for royalty suspensions depending on the difference
between the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or gas and
price thresholds set by the MMS. As a result, our reserve estimates may increase or decrease depending
upon the relation of price thresholds versus the average NYMEX prices.
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, 2008, approximately 26% of the discounted present value of our estimated net proved
reserves was proved undeveloped. Proved undeveloped reserves represented 24% of total proved
reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties.
Development of these properties is subject to additional risks as described below.
19
Information about reserves constitutes forward-looking information. See “Forward-Looking
Statements” for information regarding forward-looking information.
Unless we are able to replace reserves which we have produced, our cash flows and production will
decrease over time. Our future success depends upon our ability to acquire, find and develop oil and gas
reserves that are economically recoverable. As is generally the case for Gulf of Mexico properties, our
producing properties usually have high initial production rates, followed by a steep decline in production.
As a result, we must continually locate and develop or acquire new oil and gas reserves to replace those
being depleted by production. We must do this even during periods of low oil and gas prices when it is
difficult to raise the capital necessary to finance these activities. This is particularly so during the present
banking and economic crisis coinciding with periods of high operating costs when it is expensive to
contract for drilling rigs and other equipment and personnel necessary to explore for oil and gas. Without
successful exploration or acquisition activities, our reserves, production and revenues will decline rapidly.
We cannot assure you that we will be able to find and develop or acquire additional reserves at an
acceptable cost.
Also, because of the aggregate short life of our reserves, our return on the investment we make in our oil
and gas wells and the value of our oil and gas wells will depend significantly on prices prevailing during
relatively short production periods.
A significant part of the value of our production and reserves is concentrated in a small number of
offshore properties, and any production problems or inaccuracies in reserve estimates related to
those properties would adversely impact our business. During 2008, approximately 74% of our daily
production came from five of our properties in the Gulf of Mexico. Moreover, one property accounted for
31% of our production during this period. In addition, at December 31, 2008, most of our proved reserves
were located in two fields in the Gulf of Mexico, with approximately 80% 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 increases 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:
(cid:2) unexpected drilling conditions;
(cid:2) pressure or inequalities in formations;
(cid:2) equipment failures or accidents;
(cid:2) adverse weather conditions;
(cid:2) governmental requirements; and
(cid:2)
shortages or delays in the availability of drilling rigs and the delivery of equipment.
20
We do not operate all of our properties and have limited influence over the operations of some of
these properties, particularly two of our deepwater properties. Our lack of control could result in the
following:
(cid:2)
(cid:2)
(cid:2)
the operator may initiate exploration or development at a faster or slower pace than we prefer;
the operator may propose to drill more wells or build more facilities on a project than we have
funds for or that we deem appropriate, which may mean that we are unable to participate in the
project or share in the revenues generated by the project even though we paid our share of
exploration costs; and
if an operator refuses to initiate a project, we may be unable to pursue the project.
Any of these events could materially reduce the value of our non-operated properties.
Our deepwater operations have special operational risks that may negatively affect the value of
those assets. Drilling operations in the deepwater area are by their nature more difficult and costly than
drilling operations in shallow water. Deepwater drilling operations require the application of more
advanced drilling technologies involving a higher risk of technological failure and usually have
significantly higher drilling costs than shallow water drilling operations. Deepwater wells are completed
using sub-sea completion techniques that require substantial time and the use of advanced remote
installation equipment. These operations involve a high risk of mechanical difficulties and equipment
failures that could result in significant cost overruns.
In deepwater, the time required to commence production following a discovery is much longer than in
shallow water and on-shore. Deepwater discoveries require the construction of expensive production
facilities and pipelines prior to production. We cannot estimate the costs and timing of the construction of
these facilities with certainty, and the accuracy of our estimates will be affected by a number of factors
beyond our control, including the following:
(cid:2) decisions made by the operators of our deepwater wells;
(cid:2)
(cid:2)
(cid:2)
(cid:2)
the availability of materials necessary to construct the facilities;
the proximity of our discoveries to pipelines;
the price of oil and natural gas; and
regulatory requirements.
Delays and cost overruns in the commencement of production will affect the value of our deepwater
prospects and the discounted present value of reserves attributable to those prospects.
Competitive industry conditions may negatively affect our ability to conduct operations. We operate
in the highly competitive areas of oil and gas exploration, development and production. We compete for
the purchase of leases in the Gulf of Mexico granted by the U. S. government and from other oil and gas
companies. These leases include exploration prospects as well as properties with proved reserves.
Factors that affect our ability to compete in the marketplace include:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
our access to the capital necessary to drill wells and acquire properties;
our ability to acquire and analyze seismic, geological and other information relating to a property;
our ability to retain the personnel necessary to properly evaluate seismic and other information
relating to a property;
the location of, and our ability to access, platforms, pipelines and other facilities used to produce
and transport oil and gas production;
21
(cid:2)
(cid:2)
the standards we establish for the minimum projected return on an investment of our capital; and
the availability of alternate fuel sources.
Our competitors include major integrated oil companies, substantial independent energy companies, and
affiliates of major interstate and intrastate pipelines and national and local gas gatherers, many of which
possess greater financial, technological and other resources than we do.
Our competitors may use superior technology, which we may be unable to afford or which would
require costly investment by us in order to compete. Our industry is subject to rapid and significant
advancements in technology, including the introduction of new products and services using new
technologies. As our competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new technologies at a substantial
cost. In addition, our competitors may have greater financial, technical and personnel resources that allow
them to enjoy technological advantages and may in the future allow them to implement new technologies
before we can. We cannot be certain that we will be able to implement technologies on a timely basis or
at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may
implement in the future may become obsolete, and we may be adversely affected. For example, marine
seismic acquisition technology has been characterized by rapid technological advancements in recent
years, and further significant technological developments could substantially impair our 3-D seismic
data’s value.
We may not be able to replace our reserves or generate cash flows if we are unable to raise capital.
We will be required to make substantial capital expenditures to 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 (cid:3) Liquidity and Capital Resources” for a discussion of
our capital budget. We cannot assure you that we will be able to raise capital in the future. We also make
offers to acquire oil and gas properties in the ordinary course of our business. If these offers are accepted,
our capital needs may increase substantially.
We expect to continue using our senior secured 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 were to occur,
we might have to sell assets or seek financing from other sources. Sales of assets could further reduce the
amount of our borrowing base. We cannot assure you that we would be successful in selling assets or
arranging substitute financing. If we were not able to repay borrowings under our senior secured
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 (cid:3)Liquidity and Capital Resources” and Notes 7 and 18 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 which will require substantial additional seismic data processing and interpretation.
Whether we ultimately drill a prospect may depend on the following factors:
receipt of additional seismic data or the reprocessing of existing data;
(cid:2)
(cid:2) material changes in oil or gas prices;
(cid:2)
(cid:2)
the costs and availability of drilling rigs;
the success or failure of wells drilled in similar formations or which would use the same
production facilities;
availability and cost of capital;
changes in the estimates of the costs to drill or complete wells;
our ability to attract other industry partners to acquire a portion of the working interest to reduce
exposure to costs and drilling risks; and
decisions of our joint working interest owners.
(cid:2)
(cid:2)
(cid:2)
(cid:2)
We will continue to gather data about our prospects and it is possible that additional information may
cause us to alter our drilling schedule or determine that a prospect should not be pursued at all. You
should understand that our plans regarding our prospects are subject to change.
Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
impact our ability to conduct business. There are many operating hazards in exploring for and
producing oil and gas, including:
(cid:2) our drilling operations may encounter unexpected formations or pressures, which could cause
damage to equipment or personal injury;
(cid:2) we may experience equipment failures which curtail or stop production;
(cid:2) we could experience blowouts or other damages to the productive formations that may require a
well to be re-drilled or other corrective action to be taken; and
(cid:2) 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. 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:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
require that we acquire permits before commencing drilling;
impose operational 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
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:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
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 further 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 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 12 to our Consolidated Financial Statements.
There are inherent limitations in all control systems, and misstatements due to error or fraud that
could seriously harm our business may occur and not be detected. Our management, including our
Chief Executive and Financial Officers, do not expect that our internal controls and disclosure controls
will prevent all possible error and all fraud. A control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the objectives of the control system
are met. In addition, the design of a control system must reflect the fact that there are resource constraints
and the benefit of controls must be relative to their costs. Because of the inherent limitations in all
control systems, an evaluation of controls can only provide reasonable assurance that all material control
issues and instances of fraud, if any, in our company have been detected. These inherent limitations
include the realities that judgments in decision-making can be faulty and that breakdowns can occur
because of simple error or mistake. Further, controls can be circumvented by the individual acts of some
persons or by collusion of two or more persons. The design of any system of controls is based in part
upon certain assumptions about the likelihood of future events, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future conditions. Because of inherent
limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be
detected. A failure of our controls and procedures to detect error or fraud could seriously harm our
business and results of operations.
25
Forward-Looking Statements
In this report, we have made many forward-looking statements. We cannot assure you that the plans,
intentions or expectations upon which our forward-looking statements are based will occur. Our forward-
looking statements are subject to risks, uncertainties and assumptions, including those discussed
elsewhere in this report. Forward-looking statements include statements regarding:
(cid:2) our oil and gas reserve quantities, and the discounted present value of these reserves;
(cid:2) the amount and nature of our capital expenditures;
(cid:2) drilling of wells;
(cid:2) the timing and amount of future production and operating costs;
(cid:2) business strategies and plans of management; and
(cid:2) 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;
(cid:2)
(cid:2) general economic conditions or including the availability of credit and access to existing lines of
credit;
(cid:2) the volatility of oil and natural gas prices;
(cid:2) the uncertainty of estimates of oil and natural gas reserves;
(cid:2) the impact of competition;
(cid:2) the availability and cost of seismic, drilling and other equipment;
(cid:2) operating hazards inherent in the exploration for and production of oil and natural gas;
(cid:2) difficulties encountered during the exploration for and production of oil and natural gas;
(cid:2) difficulties encountered in delivering oil and natural gas to commercial markets;
(cid:2) changes in customer demand and producers’ supply;
(cid:2) the uncertainty of our ability to attract capital and obtain financing on favorable terms;
(cid:2) 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;
(cid:2) actions of operators of our oil and gas properties; and
(cid:2) weather conditions.
26
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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of 2008.
27
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
Our common stock trades on the New York Stock Exchange under the symbol "CPE". The following table
sets forth the high and low sale prices per share as reported for the periods indicated.
Quarter Ended
High
Low
2007:
2008:
First quarter
Second quarter
Third quarter
Fourth quarter
First quarter
Second quarter
Third quarter
Fourth quarter
$ 15.00
15.19
15.68
17.21
$ 12.54
13.26
11.50
13.33
$ 19.22
28.93
28.00
18.06
$ 13.42
17.63
16.18
1.02
As of March 10, 2009 there were approximately 3,560 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 subordinated debt prohibit the payment of cash dividends on our common stock.
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, 2008.
Plan Category
Equity compensation plans approved by
security holders
Equity compensation plans not approved by
security holders
Total
Number of
securities
to be issued upon
exercise
of outstanding
options
(a)
Weighted-
average
exercise price of
outstanding
options, warrants
and rights
(b)
Number of securities
remaining available
for future issuance
under equity
compensation plan
(excluding securities
reflected in column
(a))
(c)
422,792 $
90,483
513,275 $
10.81
7.73
10.27
351,479
42,466
393,945
28
Performance Graph
The following graph compares the yearly percentage change for the five years ended December 31, 2008, 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, 2003 in the Company, the Hemscott Group Index and the New York Stock
Exchange Market Index, and that all dividends were reinvested.
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
AMONG CALLON PETROLEUM COMPANY,
NYSE MARKET INDEX AND HEMSCOTT GROUP INDEX
500
400
300
200
100
S
R
A
L
L
O
D
0
2003
2004
2005
2006
2007
2008
CALLON PETROLEUM COMPANY
NYSE MARKET INDEX
HEMSCOTT GROUP INDEX
ASSUMES $100 INVESTED ON DEC. 31, 2003
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2008
Callon Petroleum Company
Hemscott Group Index
NYSE Market Index
2003_
$ 100
$ 100
$ 100
2004_
$ 139
$ 141
$ 113
2005_
$ 170
$ 222
$ 122
2006_
$ 145
$ 263
$ 143
2007_
$ 159
$ 413
$ 151
2008_
$ 25
$ 185
$ 95
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, 2008 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.
29
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Years Ended December 31,
2008
2007
2006
_
2005 2004
Statement of Operations Data:
Operating revenues:
Oil and gas sales
Operating expenses:
Lease operating expenses
Depreciation, depletion and amortization
General and administrative
Accretion expense
Derivative expense
$141,312 $ 170,768 $ 182,268 $ 141,290 $ 119,802
19,208
64,054
9,565
4,172
27,795
28,881
24,377
22,308
72,762
65,283
44,946
47,453
9,876
3,985
8,591
4,960
8,085
3,549
8,758
3,400
498
--
150 6,028 1,371
Impairment of oil and gas properties
485,498
-- -- -- --
Total operating expenses
582,995
114,418
107,865 86,985 83,290
Income (loss) from operations (441,683) 56,350 74,403 54,305 36,512
Other (income) expenses:
Interest expense
Other (income)
26,705
(1,379)
34,329
(1,172)
16,480
(1,869)
16,660
(998)
20,137
(357)
Loss on early extinguishment of debt
11,871
--
--
--
3,004
Total other (income) expenses
37,197
33,157 14,611
15,662
22,784
Income (loss) before income taxes
(478,880)
23,193
59,792
38,643
13,728
Income tax expense (benefit) (39,725) 8,506 20,707 13,209 (6,697)
Income (loss) before equity in earnings of Medusa Spar LLC
(439,155)
14,687
39,085
25,434
20,425
Equity in earnings of Medusa Spar LLC, net of tax
262
507 1,475 1,342
1,076
Net income (loss)
Preferred stock dividends
(438,893)
15,194
40,560
26,776
21,501
-- --
--
318
1,272
Net income (loss) available to common shares
$(438,893) $ 15,194 $ 40,560 $ 26,458 $ 20,229
Net income (loss) per common share:
Basic
Diluted
$ (20.68)
$ 0.73 $ 2.00 $ 1.43 $ 1.28
$ (20.68)
$ 0.71 $ 1.90 $ 1.28 $ 1.22
Shares used in computing net income (loss) per common share:
Basic 21,222 20,776 20,270 18,453 15,796
Diluted 21,222 21,290 21,363 20,883 17,678
30
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Years Ended December 31,
2008
2007
2006
2005
2004
Balance Sheet Data (end of period):
Oil and gas properties, net
Total assets
$ 159,252 $ 681,706 $ 547,027 $ 447,364 $406,690
$ 266,090 $ 792,482 $ 625,527 $ 533,776 $457,523
Long-term debt, less current portion
$ 272,855 $ 392,012 $ 225,521 $ 188,813 $192,351
Stockholders' equity
$ (129,804) $ 287,075 $ 281,363 $ 228,048 $198,312
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 12 to the Consolidated Financial Statements.
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of our financial condition and results of
operations. Our consolidated financial statements and notes thereto contain detailed information that should
be referred to in conjunction with the following discussion. See Item 8 “Financial Statements and
Supplementary Data.”
General
We have been engaged in the exploration, development, acquisition and production of oil and gas properties
since 1950. In the past several years, our activities have been focused in the shelf and deepwater areas of
the Gulf of Mexico. Production from wells in this area is characterized by high initial production rates
and steep decline curves. Accordingly, we are required to make material expenditures to explore for and
discover reserves to replace those produced.
Disruptions in Capital Markets. The capital markets are experiencing significant disruptions, and many
financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on
the credit markets. Our primary exposure to the current credit market crisis includes our senior secured
revolving credit facility, senior notes and counterparty nonperformance risks.
Our senior secured revolving credit facility was committed in the amount of $70 million as of December
31, 2008. Subsequent to December 31, 2008, our borrowing base redetermination was completed and
reduced to $48 million due to lower commodity prices. In addition, a Monthly Commitment Reduction
(“MCR”) will be implemented commencing June 1, 2009 in the amount of $4.33 million per month. If
not extended, the credit facility matures in September 25, 2012. Should current credit market tightening
be prolonged for several years, future extensions of our credit facility may contain terms that are less
favorable than those of our current credit facility. The amounts which may be outstanding under our
credit facility are limited by a borrowing base, which is established by our lenders and based on the value
of our proved reserves using prices, costs and other assumptions determined by our lenders. Continued
disruptions in the capital markets could cause our lenders to be more restrictive in calculating our
borrowing base. See Note 18 to the Consolidated Financial Statements.
We have outstanding $200 million of senior notes due 2010. Continued disruptions in the capital markets
could make it more difficult or expensive to refinance those notes when they come due.
Current market conditions also elevate the concern over counterparty risks related to our commodity
derivative contracts and trade credit. At December 31, 2008, our open commodity derivative instruments
were in a net receivable position with a fair value of $21.8 million. We have all of our commodity
derivative instruments with a major financial institution. Should the financial counterparty not perform,
we may not realize the benefit of some of our derivative instruments under lower commodity prices and
we could incur a loss.
We sell our production to a variety of purchasers. Some of these parties may experience liquidity
problems. Credit enhancements have been obtained from some parties in the way of parental guarantees
or letters of credit; however, we do not have all of our trade credit enhanced through guarantees or credit
support.
32
Reduced Prices for Oil and Gas Production. The United States and world economies are currently in a
recession which could last through 2009 and perhaps longer. Both oil and gas prices have undergone
significant decline during the second half of 2008 and into 2009 as a result of the reduced economic
activity brought on by the recession. Continued lower commodity prices will reduce our cash flows from
operations. To mitigate the impact of lower commodity prices on our cash flows, we have entered into
crude oil and natural gas commodity contracts for 2009. See Note 8 to our Consolidated Financial
Statements. Depending on the length of the current recession, commodity prices may stay depressed or
decline further, thereby causing a prolonged downturn, which would further reduce our cash flows from
operations. This could cause us to alter our business plans including reducing or delaying our exploration
and development program spending and other cost reduction initiatives.
Abandonment of the Entrada Project
In late November 2008, we and our joint working interest owner, CIECO, decided to abandon the Entrada
project. Under the terms of our agreements with CIECO, Callon Entrada is responsible for its share of the
costs to plug and abandon the Entrada project, which we estimate to be $46 million, $23 million net to
Callon Entrada. In addition, prior to abandonment of the project, CIECO failed to fund two loan requests
totaling $40 million under our non-recourse credit agreement with them. CIECO also failed to fund its
working interest share of a settlement payment to terminate a drilling contract for the Entrada project.
Callon has paid its share of the settlement payment.
We continue to discuss with CIECO its failure to fund $40 million in loan requests and its share of a
settlement payment to terminate a drilling contract. Because these discussions are in the early stages, no
assurances can be made regarding the outcome of these discussions. We do not believe that we have
waived any of our rights under the agreements with CIECO regarding the loan requests or the drilling
contract settlement.
The CIECO Non-Recourse Credit Agreement
Principal and interest outstanding under the credit agreement with CIECO is non-recourse to Callon
Entrada and is not guaranteed by Callon Petroleum or any of its subsidiaries. The principal and interest
under the non-recourse credit agreement is secured by a lien on substantially all of Callon Entrada’s
assets. Included in these assets are the Entrada leases and equipment purchased for the development
project. At December 31, 2008 there was no value included on the balance sheet for these assets.
CIECO has not declared Callon Entrada to be in default under the non-recourse credit agreement. The
lenders under our senior secured revolving credit facility have amended the Second Amended and
Restated Credit Agreement dated September 25, 2008 to state that a default under the Callon Entrada non-
recourse credit facility will not be a default under their facility. In addition, this amendment eliminates a
possible cross default with regard to our $200 million senior notes due 2010. Accordingly, we do not
believe that a default under the CIECO agreement will have a material negative impact on our financial
position, results of operations and cash flows. See Note 18 to the Consolidated Financial Statements.
Other Events in 2008
In addition, the following events impacted our business in 2008:
Asset Impairments– As required under the full-cost accounting rules of the SEC, we assessed the
recoverability of our oil and gas properties. Due to the depressed economic environment, coupled with a
33
severe decrease in commodity prices during the fourth quarter of 2008 and the abandonment of the
Entrada project, we determined that our oil and gas properties were impaired. For 2008, total pre-tax
(non-cash) asset impairment charges were $485.5 million. See Critical Accounting Policies – Impairment
of Proved Oil and Gas Properties and Other Investments, and Impairment of Unproved Oil and Gas
Properties.
Deferred Tax Asset Valuation Allowance – As a result of incurring losses on an aggregate basis for the
three-year period ended December 31, 2008, we established a full valuation allowance in the amount of
$128 million on the tax benefit associated with the federal and state net operating loss carryforwards as of
December 31, 2008. See Critical Accounting Policies – Income Taxes.
Hurricanes Gustav and Ike – In August and September, Hurricanes Gustav and Ike moved through the
Gulf of Mexico. Inspection of our facilities and equipment indicated there was no major damage from the
hurricanes, although damage to third-party processing and pipeline facilities has slowed reinstatement of
production from our Gulf of Mexico assets. Temporary shut-ins of production reduced volumes on
average 12.8 million cubic feet of natural gas equivalent (“MMcfe”) per day during third quarter 2008
and 18.0 MMcfe per day during fourth quarter 2008.
2009 OUTLOOK
We expect the mid-point of our 2009 crude oil and gas production to be slightly above our 2008 results.
The expected year-over-year change in production is impacted by several factors including:
(cid:2)
(cid:2)
(cid:2)
the amount of development capital expenditures;
allocation of capital expenditures to acquire producing properties; and
natural field decline in the deepwater Gulf of Mexico and Gulf Coast areas of our US operations.
Factors potentially impacting our expected production profile include:
(cid:2)
(cid:2)
(cid:2)
our reduced level of capital expenditures, as discussed below;
potential hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast areas as
occurred with Hurricanes Gustav and Ike; and
the timeliness of restoration of pipeline and facilities after an inclement weather event necessary
to increase our Gulf of Mexico production.
2009 Budget—Due to the uncertain economic and commodity price environment, we have designed a
flexible capital spending program that will be responsive to conditions that develop during 2009. Our
preliminary base capital program, including plugging and abandonment, for 2009 is $75 million, which is
relatively flat with 2008 budget, excluding the Entrada project, of $71 million. However, depending on
commodity prices and other economic conditions we experience in 2009, this base capital program may
be adjusted up or down.
We expect that the 2009 budget will be funded primarily from cash flows from operations, cash on hand,
and borrowings under our senior secured revolving credit facility and/or other financing. We will evaluate
the level of capital spending throughout the year based on drilling results, commodity prices, cash flows
from operations and property acquisitions and divestitures.
Inflation has not had a material impact on us and is not expected to have a material impact on us in the future.
34
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:
(cid:2)
(cid:2)
(cid:2)
(cid:2)
(cid:2)
the cost of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with
proved reserves, delay rentals and other costs related to exploration and development of our oil and
gas properties;
our payroll and general and administrative costs and costs related to fringe benefits paid to employees
directly engaged in the acquisition, exploration and/or development of oil and gas properties as well
as other directly identifiable general and administrative costs associated with such activities. Such
capitalized costs do not include any costs related to our production of oil and gas or our general
corporate overhead;
costs associated with properties that do not have proved reserves classified as unevaluated property
costs and are excluded from the depletable base. These unevaluated property costs are added to the
depletable base at such time as wells are completed on the properties, the properties are sold or we
determine these costs have been impaired. Our determination that a property has or has not been
impaired (which is discussed below) requires that we make assumptions about future events;
estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool
when the related liabilities are incurred under SFAS 143; and
our estimates of future costs to develop proved properties are added to the full-cost pool for purposes
of the DD&A computation. We use assumptions based on the latest geologic, engineering, regulatory
and cost data available to us to estimate these amounts. However, the estimates we make are
subjective and may change over time. Our estimates of future development costs are periodically
updated as additional information becomes available.
Capitalized costs included in the full-cost pool 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.
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
35
value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower
of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These
rules generally require pricing future oil and gas production at the unescalated market price for oil and gas at
the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded. However, if prices recover
sufficiently subsequent to the balance sheet date before the release of the financial statements then use of the
subsequent pricing is allowed and no write-down would be required. 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 12
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 and the discounted present value of estimated future net cash flows from such
reserves at the end of each quarter are based on numerous assumptions, which are likely to change over time.
These assumptions include:
(cid:2)
(cid:2)
(cid:2)
the prices at which we can sell our oil and gas production in the future. Oil and gas prices are volatile,
but we are required to assume that they will not change from the prices in effect at the end of the
quarter. In general, higher oil and gas prices will increase quantities of proved reserves and the
present value of estimated future net cash flows from such reserves, while lower prices will decrease
these amounts. Because our properties have relatively short productive lives, changes in prices will
affect the present value of estimated future net cash flows more than the estimated quantities of oil and
gas reserves;
the costs to develop and produce our reserves and the costs to dismantle our production facilities when
reserves are depleted. These costs are likely to change over time, but we are required to assume that
costs in effect at the end of the quarter will not change. Increases in costs will reduce estimated oil
and gas quantities and the present value of estimated future net cash flows, while decreases in costs
will increase such amounts. Because our properties have relatively short productive lives, changes in
costs will affect the present value of estimated future net cash flows more than the estimated quantities
of oil and gas reserves; and
the potential royalties payable to the Mineral Management Service. See Note 10 of our consolidated
financial statements for a more detailed discussion.
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.
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
36
periodically reviewing our exploration program on a property by property basis. This determination may
require the exercise of substantial judgment by our management.
Asset Retirement Obligations. We account for asset retirement obligations in accordance with Statement of
Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”),
which essentially requires entities to record the fair value of a liability for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on
the present value of the asset retirement obligation and reported as accretion expense within operating
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. Such derivatives are
accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative
Instruments and Hedging Activities” (“SFAS 133”), as amended.
Our derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded at fair
market value and the changes in fair value are recorded through other comprehensive income (loss), net of
tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in
oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as
derivative expense (income). The cash settlement on these contracts is also recorded within derivative
expense (income). 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.
Fair Value Measurements. Effective January 1, 2008, we adopted Statement of Financial Accounting
Standard No. 157, (“SFAS 157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a
framework for measuring fair value and requires enhanced disclosures about fair value measurements. We
also adopted Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial
Assets and Liabilities (“SFAS 159”), 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. We account for income taxes in accordance with Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). 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. SFAS 109 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.
We adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for
Uncertainty in Income Taxes” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for
income taxes by prescribing the minimum recognition threshold a tax position is required to meet before
37
being recognized in the financial statements. FIN 48 also provides guidance on derecognition,
measurement, classification, interest and penalties, and disclosure. See Note 5 to our Consolidated
Financial Statements.
Share-Based Compensation. Effective January 1, 2006, we adopted Statement of Financial Accounting
Standard No. 123 (revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified prospective
transition method. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance
with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic
value method) and, accordingly, recognized no compensation expense for stock option grants.
Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards as of
January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified,
repurchased or cancelled. Under the modified prospective transition method, compensation cost recognized
in 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of
January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of
Statement of Financial Accounting Standard No. 123 “Accounting for Stock-Based Compensation,” (“SFAS
123”) and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on
the grant-date fair value estimated in accordance with the provisions of SFAS 123R. Prior periods were not
restated to reflect the impact of adopting the new standard. SFAS 123R also 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. As a result of most of our stock-based
compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on income
before taxes, net income and basic and diluted earnings per share for the year ended December 31, 2006 was
immaterial. See Note 3 to our Consolidated Financial Statements.
New Accounting Standards
In December 2007, the FASB issued Statement of Financial Accounting Standard No. 141 (R) as amended,
“Business Combinations”, (“SFAS 141R”). The objective of SFAS 141R is 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, SFAS 141R 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. SFAS 141R 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. We do not have an acquisition planned at this time and can not evaluate the impact
SFAS 141R will have on future financial statement.
In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 as amended,
“Noncontrolling Interest in Consolidated Financial Statement”, (“SFAS 160”). The objective of SFAS 160 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. SFAS 160 is effective for
first fiscal year and interim periods within the fiscal year, beginning on or after December 15, 2008. We do
not have a noncontrolling interest in a subsidiary at this time and can not evaluate the impact SFAS 160 will
have on future financial statement.
38
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about
Derivative Instruments and Hedging Activities” – an amendment of SFAS Statement No. 133 (“SFAS 161”).
SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Under
SFAS 161, 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
Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items
affect an entity’s financial position, financial performance, and cash flows. The new disclosure standard is
effective for financial statements issued for fiscal years and interim periods beginning after November 15,
2008, with early application encouraged. The Statement encourages, but does not require, comparative
disclosures for earlier periods at initial adoption. We are currently evaluating the impact that SFAS 161 will
have on its financial statements.
In December 2008 the SEC unanimously approved amendments to revise its oil and gas reserves
estimation and disclosure requirements. The amendments, among other things:
allows the use of new technologies to determine proved reserves;
permits the optional disclosure of probable and possible reserves;
(cid:2)
(cid:2)
(cid:2) modifies the prices used to estimate reserves for SEC disclosure purposes to a 12-month average
(cid:2)
price instead of a period-end price; and
requires 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 revised rules are effective January 1, 2010. The new requirements do not have an impact on our
2008 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 $36 million during 2008 to $17 million. Cash provided from operating activities during 2008 totaled
$93 million, a decrease of 15% from $109 million in 2007.
On September 25, 2008, we closed on a four-year second amended and restated senior secured revolving
credit facility with Union Bank of California, N.A. as administrative agent and issuing lender. The
borrowing base which is reviewed and redetermined semi-annually was $70 million at December 31,
2008. There were no borrowings under the credit facility at December 31, 2008; however we had a letter
of credit outstanding in the amount of $15 million to secure payments under a drilling contract for the
Ocean Victory with Diamond Offshore for the development of Entrada.
Subsequent to December 31, 2008, we entered into the first amendment of the Second Amended and
Restated Credit Agreement dated September 25, 2008, which states that a default under the Entrada non-
recourse loan would not constitute a default under our senior secured revolving credit facility. The
amendment set the borrowing base at $48 million and implemented a MCR commencing on June 1, 2009
in the amount of $4.33 million per month. The borrowing base and MCR are both subject to re-
determination August 1, 2009 and quarterly thereafter. The amendment is not expected to have a material
impact on our financial condition, operations or cash flows. See Notes 7, 15 and 18 to our Consolidated
Financial Statements.
39
In April 2008, we entered into a non-recourse credit agreement with CIECO pursuant to which we could
borrow up to $150 million, plus interest expense incurred of up to $12 million, to finance the
development of the Entrada project. This credit facility is secured by the Entrada Field and related assets.
During the year we borrowed $78.4 million under the facility and as of December 31, 2008, CIECO had
failed to fund $40 million of loan request which were due in October and November of 2008. We are in
discussions with CIECO with regard to the loan requests. Because these discussions are in early stages,
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. The Company has not classified any of this
facility as current and has not included any amounts due in the five year maturities as it believes, based on
the advice of counsel, 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.
In December 2003 and March 2004, we closed on our 9.75% senior notes due 2010 in the aggregate
principal amount of $200 million. The net proceeds from these notes and the public offering of 3,450,000
shares of common stock in the second quarter of 2004 were used to restructure our debt that was maturing
in 2004 and 2005. See Note 7 to the Consolidated Financial Statements for a more detailed discussion of
long-term debt.
The indenture governing our 9.75% senior notes due 2010 and our senior secured revolving credit facility
contain various covenants including restrictions on additional indebtedness and payment of cash
dividends. In addition, our senior secured revolving credit facility contains covenants for maintenance of
certain financial ratios. We were in compliance with these covenants at December 31, 2008.
Our current planned capital expenditures for 2009, total $65 million and include capitalized interest and
general and administrative expenses. The current portion of our asset retirement obligation will require an
additional $10 million resulting in capital expenditures of $75 million for 2009. The current capital
expenditure plans for 2009 include:
(cid:2)
(cid:2)
(cid:2)
the acquisition of proved producing properties in the Gulf Coast Region;
lease and seismic acquisition; and
capitalized interest and overhead.
We believe that our operating cash flow and our credit facilities will be adequate to meet our capital, debt
repayment, and operating requirements for 2009. 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, 2008 (in
thousands):
Payments due by Period
More
Contractual Less Than One-Three Three-Five Than-Five
Total
Years Years Years__
Obligations
--
Senior Secured Credit Facility
$ --
--
9.75% Senior Notes 200,000
78,435
78,435
Callon Entrada Credit Facility (1)
Throughput Commitments:
Medusa Oil Pipeline 214
--
--
$ -- $ -- $
-- $
--
200,000
--
One Year
35 27
101
$278,649 $ 51 $200,101 $ 35 $ 78,462
--
51
40
(1)
The Callon Entrada Credit Facility is a direct obligation of Callon Entrada Company, an indirect,
wholly-owned subsidiary of Callon Petroleum. The Callon Entrada Credit Facility 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 Facility, so such facility is
effectively non-recourse to Callon Petroleum and its other subsidiaries.
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.
41
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, 2008.
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, .
2008 2007 2006 .
942
5,839
11,494
31.4
1,063
12,340
18,718
51.3
1,634
10,977
20,780
56.9
$ 88.07
$ 9.99
$ 12.29
$ 67.63
$ 8.01
$ 9.12
$ 57.33
$ 8.07
$ 8.77
Oil and gas revenues (in thousands):
Oil revenue
$ 93,665
Gas revenue 58,349 98,877 88,603
$182,268
Total
$141,312
$170,768
$ 82,963
$ 71,891
Lease operating expenses (in thousands)
$ 19,208
$ 27,795
$ 28,881
Additional per Mcfe data:
Sales price
$ 8.77
Lease operating expenses 1.67 1.48 1.39
$ 7.38
Operating margin
$ 10.62
$ 12.29
$ 9.12
$ 7.64
Depletion
General and administrative (net of management fees)
$ 5.57
$ .83
$ 3.89
$ .53
$ 3.14
$ .41
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
$ 66.22
Average NYMEX oil price
Basis differential and quality adjustments (1.15) (4.08) (7.03)
Transportation (1.15) (1.15)
(1.25)
Hedging (9.30) 0.53 (0.61)
$ 67.63 $ 57.33
Average realized oil price
$ 88.07
$ 72.33
$ 99.67
42
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 $141.3 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.
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.
43
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, the excess in the amount of $485.5 million was expensed as an
impairment of oil and gas properties for the year ended December 31, 2008. See Note 12 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 Notes 7 and 15 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 Notes 7 and 15 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 million, the amount of the deferred income tax asset. See Note 5 to the
Consolidated Financial Statements.
44
Comparison of Results of Operations for the Years Ended December 31, 2007 and 2006
Oil and Gas Revenues
Total oil and gas revenues decreased 6% from $182.3 million in 2006 to $170.8 million in 2007 primarily due
to lower oil production. Total production on an equivalent basis for 2007 decreased by 10% versus 2006.
Gas production during 2007 totaled 12.3 Bcf and generated $98.9 million in revenues compared to 11.0 Bcf
and $88.6 million in revenues during the same period in 2006. Average gas prices realized for 2007 were
$8.01 per Mcf compared to $8.07 per Mcf during the same period in 2006. The 12% increase in 2007
production was primarily attributable to new discoveries brought on line. The increase was partially offset by
the sale of the Mobile Bay 952,953,955 Field in the second quarter of 2007, early water production from East
Cameron Block 90, High Island Block 73 and North Padre Island Block 913 and normal and expected
declines in production from our High Island Block 119 and Mobile Bay area fields and older properties. In
addition, remedial work with wireline and coil tubing was performed to correct mechanical problems on the
A-1 well at Medusa in the fourth quarter of 2006 that resulted in production being restored at a lower rate.
Oil production during 2007 totaled 1,063,000 barrels and generated $71.9 million in revenues compared to
1,634,000 barrels and $93.7 million in revenues for the same period in 2006. Average oil prices realized in
2007 were $67.63 per barrel compared to $57.33 per barrel in 2006. The 35% decrease in production was
primarily due to the A-1 well at Medusa having mechanical problems which required remedial work in the
fourth quarter of 2006 and resulted in production being restored at a lower rate. In addition, the #1 well at
Habanero became uneconomic as expected in the third quarter of 2007 and was sidetracked and completed as
planned in an updip location in the reservoir. Production from the sidetrack well commenced in October
2007. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.
Lease Operating Expenses
Lease operating expenses for 2007 decreased by 4% to $27.8 million compared to $28.9 million for the same
period in 2006. The decrease was primarily due to the sale of the Mobile Bay 952, 953, 955 Field effective
May, 2007, lower throughput charges at Habanero and the shut-in of our South Marsh Island 261 Field, which
is scheduled to be plugged and abandoned. The decrease was partially offset by additional operating costs
associated with or new discoveries.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 2007 and 2006 were $72.8 million and $65.3 million,
respectively. The 11% increase was due to higher depletion rate resulting from higher costs associated with
our exploration and development activities in the Gulf of Mexico.
Accretion Expense
Accretion expense for 2007 and 2006 of $4.0 million and $5.0 million, respectively, represents accretion of
our asset retirement obligations. See Note 11 to the Consolidated Financial Statements.
45
General and Administrative
General and administrative expenses for 2007, net of amounts capitalized, were $9.9 million compared to $8.6
million in 2006. The 15% increase was a result of additions to our technical staff and higher compensation
costs.
Interest Expense
Interest expense increased to $34.3 million in 2007 compared to $16.5 million in 2006. This increase was
due to the new debt associated with the Entrada acquisition. See Notes 7 and 15 to the Consolidated
Financial Statements for more details.
Income Taxes
For 2007, income tax expense was $8.5 million compared to $20.7 million in 2006. The 59% decrease
was primarily due to a decrease in income before income taxes arising mainly out of the reduced oil
production and increased interest expense during the year.
46
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Price Risk
The Company's revenues are derived from the sale of its crude oil and natural gas production. The prices
for oil and gas remain extremely volatile and sometimes experience large fluctuations as a result of
relatively small changes in supply, weather conditions, economic conditions and government actions.
From time to time, the Company enters into derivative financial instruments to manage oil and gas price
risk.
The Company may utilize fixed price “swaps”, which reduce the Company's exposure to decreases in
commodity prices and limit the benefit the Company might otherwise have received from any increases in
commodity prices.
The Company may utilize price "collars" to reduce the risk of changes in oil and gas prices. Under these
arrangements, no payments are due by either party as long as the market price is above the floor price and
below the ceiling price set in the collar. If the price falls below the floor, the counter-party to the collar
pays the difference to the Company, and if the price rises above the ceiling, the counter-party receives the
difference from the Company.
Callon may purchase “puts” which reduce the Company’s exposure to decreases in oil and gas prices
while allowing realization of the full benefit from any increases in oil and gas prices. If the price falls
below the floor, the counter-party pays the difference to the Company.
The Company enters into these various agreements from time to time to reduce the effects of volatile oil
and gas prices and does not enter into derivative transactions for speculative purposes. However, certain
of the Company’s derivative positions may not be designated as hedges for accounting purposes. See
Note 8 to the Consolidated Financial Statements for a description of the Company’s hedged position at
December 31, 2008.
Based on projected annual sales volumes for 2009 (excluding incremental production from 2008
exploratory drilling), a 10% decline in the prices Callon receives for its crude oil and natural gas
production would have an approximate $4.5 million impact on our revenues.
47
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2008
and 2007
Consolidated Statements of Operations for Each of the Three Years
in the Period Ended December 31, 2008
Consolidated Statements of Stockholders' Equity
for Each of the Three Years in the Period Ended December 31, 2008
Consolidated Statements of Cash Flows for Each of the Three Years
in the Period Ended December 31, 2008
Notes to Consolidated Financial Statements
Page
49
50
51
52
53
54
48
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, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the
consolidated results of its operations and its cash flows for each of the three years in the period ended
December 31, 2008, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the financial statements, in 2007 the Company changed its method of
accounting for income taxes.
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, 2008, 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 19,
2009, expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 19, 2009
49
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
December 31,
2008
2007
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable
Restricted investments
Fair market value of derivatives
Other current assets
Total current assets
Oil and gas properties, full-cost accounting method:
Evaluated properties
Less accumulated depreciation, depletion and amortization
Unevaluated properties excluded from amortization
Total oil and gas properties
Other property and equipment, net
Restricted investments
Investment in Medusa Spar LLC
Other assets, net
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities
Asset retirement obligations
Fair market value of derivatives
Total current liabilities
9.75% Senior Notes
Callon Entrada Credit Facility (non-recourse)
Senior Revolving Credit Facility
Total long-term debt
Asset retirement obligations
Deferred tax liability
Other long-term liabilities
Total liabilities
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares authorized;
Common Stock, $.01 par value; 30,000,000 shares
authorized; 21,621,142 shares and 20,891,145 shares issued
outstanding at December 31, 2008 and 2007, respectively
Capital in excess of par value
Other comprehensive income (loss)
Retained (deficit) earnings
Total stockholders' equity
Total liabilities and stockholders' equity
$ 17,126
44,290
--
21,780
1,103
84,299
$ 53,250
22,073
100
--
6,592
82,015
1,581,698
(1,455,275 )
126,423
1,349,904
(738,374 )
611,530
32,829
159,252
2,536
4,759
12,577
2,667
$ 266,090
70,176
681,706
1,986
4,525
12,673
9,577
$ 792,482
$ 76,516
9,151
--
85,667
$ 37,698
9,810
5,205
52,713
194,420
78,435
--
272,855
33,043
--
4,329
395,894
192,012
--
200,000
392,012
27,027
32,190
1,465
505,407
--
--
216
227,803
14,157
(371,980 )
(129,804 )
$ 266,090
209
223,336
(3,383 )
66,913
287,075
$ 792,482
The accompanying notes are an integral part of these financial statements.
50
Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share amounts)
Year Ended December 31,
2007
2008
2006
Operating revenues:
Oil sales
Gas sales
Total operating revenues
Operating expenses:
Lease operating expenses
Depreciation, depletion and amortization
General and administrative
Accretion expense
Derivative expense
Impairment of oil and gas properties
Total operating expenses
$ 82,963
58,349
141,312
$ 71,891
98,877
170,768
$ 93,665
88,603
182,268
19,208
64,054
9,565
4,172
498
485,498
582,995
27,795
72,762
9,876
3,985
--
--
114,418
28,881
65,283
8,591
4,960
150
--
107,865
Income (loss) from operations
(441,683)
56,350
74,403
Other (income) expenses:
Interest expense
Loss on early extinguishment of debt
Other income
Total other (income) expenses
Income (loss) before income taxes
Income tax (benefit) expense
26,705
11,871
(1,379)
37,197
34,329
--
(1,172)
33,157
16,480
--
(1,869)
14,611
(478,880)
(39,725)
23,193
8,506
59,792
20,707
39,085
1,475
Income (loss) before equity in earnings of Medusa Spar LLC
Equity in earnings of Medusa Spar LLC, net of tax
(439,155)
262
14,687
507
Net income (loss) available to common shares
$ (438,893)
$ 15,194
$ 40,560
Net income (loss) per common share:
Basic
Diluted
$ (20.68)
$ (20.68)
$ 0.73
$ 0.71
$ 2.00
$ 1.90
Shares used in computing net income (loss) per share amounts:
Basic
Diluted
21,222
21,222
20,776
21,290
20,270
21,363
The accompanying notes are an integral part of these financial statements.
51
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Unearned
Restricted
Total
Capital in Other Retained Stock-
Accumulated
Preferred Common
Stock Excess of Comprehensive Earnings holders’
Stock Stock Compensation Par Value Income (Loss) (Deficit) Equity
Balances, December 31, 2005 $ --
$ 194 $ (3,334) $ 220,360
$ (331) $ 11,159 $ 228,048
--
--
Comprehensive income:
Net income --
Other comprehensive income --
Total comprehensive income
Shares issued pursuant to employee
benefit and option plan --
Tax benefits related to stock
compensation plans --
Adoption of 123R
Restricted stock -- 1 --
Warrants --
--
2
10 --
--
--
--
--
--
--
8,983
40,560
--
49,543
(441)
--
--
(439)
--
1,356
3,334 (3,334)
2,854
(10)
--
--
--
--
--
--
--
--
1,356
--
2,855
--
Balances, December 31, 2006 --
207 --
220,785
8,652 51,719 281,363
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
--
--
2 --
163
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 --
Restricted stock --
Warrants -- 5
--
--
1
--
--
--
--
-- (438,893)
17,540
--
(421,353)
-- (1,153)
--
-- (1,152)
--
2,050
1 3,575
-- (5)
--
--
--
-- -- --
-- 3,576
-- 2,050
Balances, December 31, 2008 $ --
$ 216 $ --
$ 227,803
$ 14,157 $(371,980) $(129,804)
The accompanying notes are an integral part of these financial statements.
52
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31,
2008
2007
2006
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 loss on early extinguishment of debt
Equity in earnings of Medusa Spar, LLC
Non-cash derivative expense
Deferred income tax (benefit) expense
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
Entrada acquisition
Proceeds from sale of mineral interests
Distribution from Medusa Spar, LLC
Cash used by investing activities
Cash flows from financing activities:
Change in accrued liabilities to be refinanced
Increases in debt
Payments on debt
Deferred financing costs
Equity issued related to employee stock plans
Excess tax benefits from share-based payment arrangements
Capital leases
Cash (used) provided by financing activities
$ (438,893)
$ 15,194
$ 40,560
64,862
485,498
4,172
4,185
5,598
(262)
--
(39,725)
1,550
(2,050)
73,677
--
3,985
3,009
--
(507)
--
8,506
849
(163)
(22,215)
5,489
22,987
630
156
2,708
(1,458)
93,232
6,658
(619)
(2,057)
(938)
889
(10)
810
109,283
65,929
--
4,960
2,221
--
(1,475)
150
20,707
1,420
(1,449)
(2,107)
(3,975)
11,311
(311)
133
(2)
(2,588)
135,484
(176,536)
--
167,349
498
(8,689)
(127,409)
(150,000)
60,931
687
(215,791)
(167,979)
--
--
1,078
(166,901)
--
94,435
(216,000)
--
(1,152)
2,050
--
(120,667)
--
229,000
(64,000)
(6,429)
--
163
(872)
157,862
(5,000)
88,000
(53,000)
--
(438)
1,449
(263)
30,748
Net (decrease) increase in cash and cash equivalents
(36,124)
51,354
(669)
Cash and cash equivalents:
Balance, beginning of period
Balance, end of period
53,250
1,896
2,565
$ 17,126
$ 53,250
$ 1,896
The accompanying notes are an integral part of these financial statements.
53
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 10.
The Company and its predecessors have been engaged in the acquisition, development and exploration of
crude oil and natural gas since 1950. The Company's properties are geographically concentrated in the Gulf
Coast Region.
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 U.S. generally accepted accounting principles
requires management to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual results could differ from
those estimates.
Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with Statement of Financial Accounting
Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which essentially
requires entities to record the fair value of a liability for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present
value of the asset retirement obligation and reported as accretion expense within operating expenses in the
consolidated statements of operations. See Note 11.
54
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 under SFAS 143. General and administrative costs capitalized include salaries and related fringe
benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and gas
properties as well as other directly identifiable general and administrative costs associated with such
activities. Such capitalized costs ($12.6 million in 2008, $10.8 million in 2007 and $9.6 million in 2006) 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 12.
Upon the acquisition or discovery of oil and gas properties, management estimates the future net costs to be
incurred to dismantle, abandon and restore the property using available geological, engineering and regulatory
data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance
with SFAS 143, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In
accordance with SEC Staff Accounting Bulletin No. 106, assets recorded in connection with the recognition
of an asset retirement obligation pursuant to SFAS 143 are included as part of the costs subject to the full-
cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement
obligations are excluded from the computation of the present value of estimated future net revenues used in
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.
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 $437,000, $457,000 and $351,000 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, 2008, 2007 and 2006, respectively. The
accumulated depreciation on other property and equipment was $11.6 million and $11.2 million as of
December 31, 2008 and 2007, respectively.
55
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.
Natural Gas Imbalances
The Company follows the entitlement method of accounting for its proportionate share of gas production on a
well-by-well basis, recording a receivable to the extent that a well is in an "undertake" position and recording
a liability to the extent that a well is in an "overtake" position. Gas balancing receivables were $1.0 million
and $1.7 million as of December 31, 2008 and 2007, respectively. Gas balancing payables were $1.5 million
and $1.3 million as of December 31, 2008 and 2007, respectively.
Derivatives
The Company periodically uses derivative financial instruments to manage oil and gas price risk on a limited
amount of its future production and does not use these instruments for trading purposes. Settlement of
derivative contracts 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. Such derivatives are accounted for under Statement of Financial Accounting Standards No. 133,
“Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.
The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded
at fair market value and the changes in fair value are recorded through other comprehensive income (loss), net
of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease
in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as
derivative expense (income). The cash settlement on these contracts is also recorded within derivative
expense (income). 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. See Note 9,
“Fair Value Measurements.”
56
Income Taxes
The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes" ("SFAS 109"). 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. SFAS 109 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.
Callon adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for
Uncertainty in Income Taxes” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for
income taxes by prescribing the minimum recognition threshold a tax position is required to meet before
being recognized in the financial statements. FIN 48 also provides guidance on derecognition,
measurement, classification, interest and penalties, and disclosure. See Note 5.
Earnings per Share
The Company accounts for earnings per share (“EPS”) in accordance with Statement of Financial Accounting
Standards No. 128, “Earnings Per Share” (“SFAS 128”). SFAS 128 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 4.
Stock-Based Compensation
Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123
(revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified prospective transition
method. Prior to the adoption of SFAS 123R, the Company accounted for stock option grants in accordance
with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic
value method) and, accordingly, recognized no compensation expense for stock option grants.
Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards as of
January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified,
repurchased or cancelled. Under the modified prospective transition method, compensation cost recognized
in 2008, 2007 and 2006 includes compensation cost for all share-based payments granted prior to, but not yet
vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original
provisions of Statement of Financial Accounting Standard No. 123 “Accounting for Stock-Based
Compensation,” (“SFAS 123”) and compensation cost for all share-based payments granted subsequent to
January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS
123R. Prior periods were not restated to reflect the impact of adopting the new standard.
SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of compensation
cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. The
57
$2.1 million, $163,000 and $1.4 million of excess tax benefits classified as a financing cash inflow for the
years ended December 31, 2008, 2007 and 2006, respectively would have been classified as an operating cash
flow had the Company not adopted SFAS 123R. There were no stock option exercises in the year ended
December 31, 2007 and no cash proceeds from the exercise of stock options for the years ended December
31, 2008 and 2006 due to the fact that all options were exercised through net-share settlements. As a result of
most of the Company’s stock-based compensation being in the form of restricted stock, the impact of the
adoption of SFAS 123R on income before taxes, net income and basic and diluted earnings per share for the
year ended December 31, 2006 was not significant. See Note 3.
Accounts Receivable
Accounts receivable consists primarily of accrued oil and gas production receivables. The balance in the
reserve for doubtful accounts netted within accounts receivable was $65,000 at both December 31, 2008
and 2007. There were no provisions to expense in the three-year period ended December 31, 2008.
Major Customers
The Company’s production is generally sold on month-to-month contracts at prevailing prices. The
following table identifies customers to whom it sold a significant percentage of its total oil and gas
production during each of the years ended:
Shell Trading Company
Louis Dreyfus Energy Services
StatoilHydro
Plains Marketing, L.P.
December 31,______
2006
41%
25%
--
11%
2008
33%
16%
--
23%
2007
25%
20%
13%
10%
Because alternative purchasers of oil and gas are readily available, the Company believes that the loss of any
of these purchasers would not result in a material adverse effect on its ability to market future oil and gas
production.
Statements of Cash Flows
The Company considers all highly liquid investments with an original maturity of three months or less to be
cash equivalents.
The Company paid no federal income taxes for the three years in the period ended December 31, 2008.
During the years ended December 31, 2008, 2007 and 2006, the Company made cash payments for
interest of $27.0 million, $37.6 million and $20.5 million, respectively.
Fair Value of Financial Instruments
Fair value of cash and cash equivalents, accounts receivable and accounts payable, approximated book value
at December 31, 2008 and 2007. The fair value of the senior revolving credit facility approximated book
value at December 31, 2008. The senior secured revolving credit facility and capital lease had no balance
outstanding at December 31, 2008 and the fair value approximated book value at December 31, 2008. The
58
Company’s 9.75% Senior Notes due 2010 had an estimated fair market value of 52% and 94% of face value
at December 31, 2008 and 2007, respectively.
Fair Value Measurements
Effective January 1, 2008, the Company adopted Statement of Financial Accounting Standard No. 157,
(“SFAS 157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for
measuring fair value and requires enhanced disclosures about fair value measurements. The adoption of SFAS
157 did not have a significant impact on the Company’s financial statements. The Company also adopted
Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial Assets and
Liabilities (“SFAS 159”) on January 1, 2008, which permits entities to choose to measure various
financial instruments and certain other items at fair value. The Adoption of SFAS 159 did not have an
impact on the Company’s financial statements. See Note 9.
Accounting Pronouncements
In December 2007, the FASB issued Statement of Financial Accounting Standard No. 141 (R) as amended,
“Business Combinations”, (“SFAS 141R”). The objective of SFAS 141R is 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, SFAS 141R 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. SFAS 141R 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 Company does not have an acquisition planned at this time and can not
evaluate the impact SFAS 141R will have on future financial statement.
In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 as amended,
“Noncontrolling Interest in Consolidated Financial Statement”, (“SFAS 160”). The objective of SFAS 160 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. SFAS 160 is effective for
first fiscal year and interim periods within the fiscal year, beginning on or after December 15, 2008. The
Company doe not have a noncontrolling interest in a subsidiary at this time and can not evaluate the impact
SFAS 160 will have on future financial statement.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about
Derivative Instruments and Hedging Activities” – an amendment of SFAS Statement No. 133 (“SFAS 161”).
SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Under
SFAS 161, 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
Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items
affect an entity’s financial position, financial performance, and cash flows. The new disclosure standard is
effective for financial statements issued for fiscal years and interim periods beginning after November 15,
2008, with early application encouraged. The Statement encourages, but does not require, comparative
disclosures for earlier periods at initial adoption. Callon is currently evaluating the impact that SFAS 161 will
have on its financial statements.
59
In December 2008 the SEC unanimously approved amendments to revise its oil and gas reserves
estimation and disclosure requirements. The amendments, among other things:
allows the use of new technologies to determine proved reserves;
permits the optional disclosure of probable and possible reserves;
(cid:2)
(cid:2)
(cid:2) modifies the prices used to estimate reserves for SEC disclosure purposes to a 12-month average
(cid:2)
price instead of a period-end price; and
requires 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 revised rules are effective January 1, 2010. The new requirements do not have an impact on the
Company’s 2008 financial statements.
3. STOCK-BASED COMPENSATION
The Company has various stock plans (“Plans”) under which employees of the Company and its subsidiaries
and non-employee members of the Board of Directors of the Company have been or may be granted certain
stock-based compensation. For further discussion of the Plans, refer to Note 13.
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. For the year ended
December 31, 2006, the Company recorded stock-based compensation expense of $3.5 million, of which $1.8
million was included in general and administrative expenses and $1.7 million was capitalized to oil and gas
properties. Shares available for future stock option or restricted stock grants to employees and directors under
existing plans were 393,945 at December 31, 2008.
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,_
2006_
2007_
--
36.2%
4.7%
5
$ 5.64
2.0%
--
38.9%
4.6%
5
$ 7.72
7.5%
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.
60
The following table represents stock option activity for the three years ended December 31, 2008:
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
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 2.92 yrs. 3.39 yrs.
Outstanding exercisable at end of period 2.68 yrs.
2007
Wtd Avg
Shares Ex Price
740,225 $ 9.93
14.27
30,000
--
--
--
--
(15,000)
15.31
755,225 $ 10.00
710,225 $ 9.57
2006
Wtd Avg
Ex Price
$ 10.11
18.69
10.66
--
--
$ 9.93
$ 9.44
Shares
1,205,558
15,000
(480,333)
--
--
740,225
695,225
4.06 yrs.
3.08 yrs. 3.76 yrs.
As of December 31, 2008, the aggregate intrinsic value of options outstanding and options exercisable was
zero. As of December 31, 2007 and 2006, the aggregate intrinsic value of options outstanding was $5.0
million and $3.9 million and the aggregate intrinsic value of options exercisable was $4.9 million and $3.9
million, respectively. Total intrinsic value of options exercised was $4.1 million for both the years ended
December 31, 2008 and 2006. At December 31, 2008, there was $116,000 of unrecognized compensation
cost related to nonvested stock options, which is expected to be recognized over a weighted-average period of
two years.
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, 2008, there was $6.9 million of unrecognized compensation cost associated with these
awards, which is expected to be recognized over a weighted average period of 1.8 years.
The following table represents unvested restricted stock activity for the year ended December 31, 2008:
Outstanding shares at beginning of period
Granted
Vested
Forfeited
487,450
242,600
(206,950)
(13,800)
Weighted-Average
Number of
Shares
Grant-Date
Fair Value
$ 15.17
20.73
16.05
16.08
Outstanding shares at end of period
509,300
$ 17.43
61
For the years ended December 31, 2008, 2007 and 2006 the Company recognized non-cash compensation
expense associated with the restricted stock awards of $4.3 million, $2.7 million and $3.4 million,
respectively.
4. NET INCOME PER SHARE
Basic net income per common share was computed by dividing net income by the weighted average number
of shares of common stock outstanding during the year. Diluted net income per common share was
determined on a weighted average basis using common shares issued and outstanding adjusted for the effect
of stock options 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 (in thousands,
except per share amounts):
2008
2007
2006
(a) Net income (loss) available to common shares $ (438,893)
$ 15,194
$ 40,560
(b) Weighted average shares outstanding 21,222
Dilutive impact of stock options --
Dilutive impact of restricted stock --
Dilutive impact of warrants --
20,776
148
40
326
20,270
238
78
777
(c) Weighted average shares outstanding for diluted
net income per share 21,222
21,290
21,363
Stock options excluded due to the exercise
price being greater than the stock price 399
Basic net income (loss) per share (a(cid:4)b)
$ (20.68)
Diluted net income (loss) per share (a(cid:4)c)
$ (20.68)
75
$ 0.73
$ 0.71
28
$ 2.00
$ 1.90
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, 2007 and 2006
and all such shares were included as described above.
2008 _
Stock options 161
Warrants 328
Restricted Stock 129
62
5. INCOME TAXES
Below is an analysis of deferred income taxes as of December 31, 2008 and 2007.
December 31,____
2007
2008
(In thousands)
Deferred tax asset:
Federal net operating loss carryforwards
State net operating loss carryforwards
Statutory depletion carryforward
Alternative minimum tax credit carryforward
Asset retirement obligations 13,102 11,274
Oil and gas properties 58,061
--
Other
Valuation allowance (174,062) (36,345)
$ 68,432
45,939
4,561
375
$ 58,397
36,345
4,184
375
2,241 3,572
Total deferred tax asset
18,649 77,802
Deferred tax liability:
Oil and gas properties
Other (18,649) (462)
--
(109,530)
Total deferred tax liability
Net deferred tax liability
(18,649)
(109,992)
$ --
$ (32,190)
SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is more
likely than not that a deferred tax asset is recoverable. 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, the Company established a full valuation allowance in the amount
of $ 128 million on the tax benefit associated with the federal and state net operating loss carryforwards
as of December 31, 2008.
If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through 2023. The
Company’s state net operating loss carryforwards will expire in 2009 through 2023. The Company has very
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.
Callon adopted FIN 48 effective January 1, 2007. The Company had no significant unrecognized tax
benefits at the date of adoption or at December 31, 2008. 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.
63
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
6. OTHER COMPREHENSIVE INCOME
Years Ended December 31,_
2006_
2007_
2008_
(35)%
27%
--
35%
--
2%
35%
--
--
(8)%
37%
35%
The Company’s other comprehensive income (loss) of $18 million, $(12) million and $9 million for the years
ended December 31, 2008, 2007 and 2006, respectively, relates to the change in fair value of its derivatives.
Other comprehensive income (loss) was net of income tax expense (benefit) of $9.4 million, $(6.5) million
and $4.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.
7. LONG-TERM DEBT
Long-term debt consisted of the following at:
December 31,____
2007__
2008 _
(In thousands)
Senior Secured Credit Facility (matures September 25, 2012) $ --
194,420
9.75% Senior Notes (due December 2010) net of discount
Senior Revolving Credit Facility (due 2014)
--
78,435
Callon Entrada Credit Facility - non-recourse
$ --
192,012
200,000
--
Total long-term debt
Less current portion
Long-term portion
272,855
--
$272,855
392,012
--
$392,012
Senior Secured Credit Facility. On September 25, 2008, the Company completed a $250 million second
amended and restated senior secured revolving credit agreement, which matures on September 25, 2012,
with the Union Bank of California (“UBOC”) as administrative agent and issuing lender. The borrowing
base, which will be reviewed and redetermined semi-annually, was $70 million at December 31, 2008.
Borrowings under the credit agreement are secured by mortgages covering the Company’s major fields
excluding Entrada. As of December 31, 2008, there were no borrowings under the agreement; however
Callon had a letter of credit outstanding in the amount of $15 million to secure the drilling rig, Ocean
Victory, for the development of Entrada. As a result, $55 million was available for future borrowings
under the credit agreement as of December 31, 2008. See Note 18.
64
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 revolving 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 interest rate on the senior secured credit facility during 2008 was 5.75%.
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. Borrowings outstanding
under the facility bore interest at a rate of LIBOR plus 7%. The Company borrowed the full commitment
amount under the facility at closing to cover the required $150 million payment to BP Exploration and
Production Company (“BP”) and expenses and fees related to the transaction and the balance was used to
pay down the Company’s UBOC senior secured credit facility. Callon’s UBOC senior secured credit
facility was amended to allow for this transaction.
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 UBOC credit facility and proceeds from the
sale of a 50% working interest in Callon’s Entrada Field to CIECO Energy (US) Limited (“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. See Note 15.
Callon Entrada Credit Agreement (Non-Recourse). A wholly-owned subsidiary of Callon, Callon
Entrada, entered into a credit agreement with CIECO 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 facility is secured by the Entrada Field
and related assets. 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. As of December 31, 2008, $78.4 million of principal and $2.7 million of accrued
interest was outstanding under this facility. See Note 15.
Callon and its subsidiaries (other than Callon Entrada) did not guarantee and are not otherwise obligated
to repay the principal, accrued interest or any other amount which may become outstanding 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 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. Callon also has guaranteed Callon Entrada’s
payment of all amounts to plug and abandon wells and related facilities for a breach of law, rule or
regulation (including environmental laws) and for any losses attributable to gross negligence of Callon
Entrada. The Company has not classified any of this facility as current and has not included any amounts
due in the five year maturities as it believes, based on the advice of counsel, 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.
65
In late November 2008, Callon Entrada and CIECO decided to abandon the Entrada project. Prior to
abandonment of the project, CIECO failed to fund two loan requests totaling $40 million under our non-
recourse credit agreement with them. The Company continues to discuss with CIECO its failure to fund
the $40 million in loan requests. Because these discussions are in early stages, no assurances can be
made regarding the outcome of these discussions. The Company does not believe that we have waived
any of our rights under our agreements with CIECO.
9.75% Senior Notes (due 2010). In December 2003, the Company borrowed $185 million pursuant to a
senior unsecured credit facility. The loans under the credit facility have a stated interest rate of 9.75% and a
seven-year maturity. In conjunction with the senior unsecured notes, the Company issued detachable warrants
to purchase 2.775 million shares of its common stock at an exercise price of $10 per share and an expiration
date of December 2010. The warrants were valued at $10.6 million and were treated as a discount on the debt.
This senior unsecured debt matures December 8, 2010 and has an effective interest rate of 11.4%. The
Company recorded the issuance of these new securities at a fair value of $171 million. Deferred costs of
$14 million associated with the notes are being amortized over the life of the notes.
During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured credit
facility bringing the total outstanding under the facility to $200 million. The net proceeds of
approximately $14 million were primarily used to retire the remaining $10 million of 12% senior loans
due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of these
additional new securities at a fair value of $14 million. Deferred costs of $1 million associated with the
notes are being amortized over the life of the notes. See Note 15.
In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75%
senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, (“Series A
notes”), issued pursuant to a senior indenture between Callon and American Stock Transfer & Trust
Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to exchange its
9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933, for all
outstanding Series A notes.
As of December 31, 2008, 2.410 million of the 2.775 million detachable warrants issued with the 9.75%
Senior Notes due 2010 were exercised.
Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million
9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are full
and unconditional and joint and several, the parent company has no independent assets or operations and
any subsidiaries of the parent company other than the subsidiary guarantors are minor.
Capital Lease. In December 2001, the Company entered into a 10-year gas processing agreement
associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression
Limited Partnership, which was being accounted for as a capital lease. In May 2007, the Company sold
the Mobile Block 952 Field and retired the remainder of the capital lease.
Restrictive Covenants. The Indenture governing our 9.75% senior notes due 2010 and the Company’s senior
secured revolving credit facility contains various covenants including restrictions on additional indebtedness
and payment of cash dividends. In addition, Callon’s senior secured revolving credit facility contains
covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants
at December 31, 2008.
66
8. DERIVATIVES
The following table summarizes derivative expense for the periods presented (in thousands):
Amortization of derivative contract premiums
Change in fair value and settlements of ineffective
derivative contracts
Years Ended December 31,
2008
2007
2006
$ --
$ --
$ 150
498
--
--
$ 498
$ --
$ 150
The change in fair value and settlements of ineffective derivative contracts in 2008 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. For the year ended December 31, 2008, cash
settlements on effective cash flow hedges resulted in a reduction in oil and gas sales of $9.4 million. Cash
settlements on effective cash flow hedges for the years ended December 31, 2007 and 2006 resulted in an
increase in oil and gas sales of $8.1 million and $8.9 million, respectively.
Listed in the table below are the outstanding derivative contracts, which are collars, as of December 31,
2008:
Collars
Average Average
Volumes per Quantity Floor Ceiling
Product
Month Type Price Price Period
Oil 30,000 Bbls $110.00 $175.75 01/09-12/09
Natural Gas 100,000 MMBtu $ 11.00 $ 20.00 01/09-03/09
9. FAIR VALUE MEASUREMENTS
Effective January 1, 2008, the Company adopted (SFAS 157), “Fair Value Measurements.” SFAS 157
defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about
fair value measurements. SFAS 157 establishes a fair value hierarchy which consists of three broad levels
that prioritize the inputs to valuation techniques used to measure fair value.
(cid:2) Level 1 valuations consist of unadjusted quoted prices in active markets for identical assets
and liabilities and have the highest priority.
(cid:2) Level 2 valuations rely on quoted market information for the calculation of fair market
value.
(cid:2) Level 3 valuations are internal estimates and have the lowest priority.
67
Per SFAS 157, 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, 2008 (in thousands):
Quoted Significant
Fair Value Measurements Using
Prices in Other Significant
Active Observable Unobservable Assets
Markets Inputs Inputs (Liabilities)
(Level 1) (Level 2) (Level 3) At Fair Value
Derivative assets
$ --
$ --
$ 21,780
$ 21,780
Derivative liabilities
Total
--
$ --
--
$ --
--
$ 21,780
--
$ 21,780
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, 2008. 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, 2008 (in thousands):
Balance at January 1, 2008
Total gains or losses (realized or unrealized):
Included in earnings
Included in other comprehensive income
Purchases, issuances and settlements
Balance at December 31, 2008
Derivatives
$ (5,205)
--
17,076
9,909
$ 21,780
Change in unrealized gains (losses) included in
earnings relating to derivatives still held as of
December 31, 2008
$ --
The Company also adopted (SFAS 159), “The Fair Value Option for Financial Assets and Financial
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 SFAS 159 did not have an impact on the Company’s
financial statements.
68
10. COMMITMENTS AND CONTINGENCIES
From time to time, the Company, as part of the Consolidation and other capital transactions, entered into
registration rights agreements whereby certain parties to the transactions are entitled to require the Company
to register common stock of the Company owned by them with the SEC for sale to the public in firm
commitment public offerings and generally to include shares owned by them, at no cost, in registration
statements filed by the Company. Costs of the offering will not include broker’s discounts and commissions,
which will be paid by the respective sellers of the common stock.
The Company is involved in various claims and lawsuits incidental to its business. In the opinion of
management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial
position or results of operations of the Company.
In November 2008, the decision was made to abandon the Entrada Project. See Notes 7 and 15 for more
details related to commitments and contingencies.
The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep
Water Royalty Relief Act. In addition, the Company has several shallow water, deep natural gas
properties and prospects that are eligible for royalty suspensions. However, the federal offshore leases
covering these properties contain “price threshold” provisions for oil and gas prices. Under these “price
threshold” provisions, if the average monthly NYMEX sales price for oil or gas during a fiscal year
exceeds the price threshold for oil or gas, respectively, then royalties on the associated production must
be paid to the Minerals Management Service (MMS) at the rate stipulated in the lease. The price
thresholds are adjusted annually by the implicit price deflator for the GDP. The determination of whether
or not royalties are due as a result of the average NYMEX price exceeding the price threshold is made
during the first quarter of the succeeding year. Any royalty payments due must be made shortly after this
determination is made. If a royalty payment is due for all production during a year as a result of
exceeding the price threshold, the lessee is required to make monthly royalty payments during the
succeeding fiscal year for the succeeding year’s production. If at the end of any year the average
NYMEX price is below the price threshold, the lessee can apply for a refund for any associated royalties
paid during that year and the lessee will not be required to pay royalties monthly during the succeeding
year for the succeeding year’s production.
The Company was required to make monthly royalty payments for 2008 deepwater oil and gas production
and will be required to make monthly royalty payments for 2009. With regard to the shallow water, deep
natural gas royalty relief, the Company was not required to make royalty payments for 2008 and will not
be required to make royalty payments for 2009.
In the year succeeding the year in which any of the Company’s properties became subject to royalties as
the result of the average NYMEX price exceeding the price threshold, the portion of reserves attributable
to potential future royalties would not be included in the year-end reserve report. However, if the average
NYMEX prices were below the price thresholds in subsequent years, our reserves would be increased to
reflect reserves previously attributed to future royalties. As a result, reported oil and gas reserves could
materially increase or decrease, depending on the relation of price thresholds versus the average NYMEX
prices. The reduction in revenues resulting from an obligation to pay these royalties and subsequent
reduction of proved reserves could have a material adverse effect on the Company’s results of operations
and financial condition. The Company’s reserve report as of December 31, 2008 excluded oil and gas
reserves for Medusa that are subject to MMS royalties as a result of the average 2008 NYMEX prices for
oil and gas exceeding the deepwater price thresholds. With regard to the shallow water, deep natural gas
69
properties, there was no reduction in reserves for potential future royalties as of December 31, 2008 as a
result of the average 2008 NYMEX price for gas being below the price threshold.
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
11. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the activity for the Company’s asset retirement obligations (in
thousands):
Years Ended December 31,
2008
Asset retirement obligations at beginning of period
Accretion expense
Liabilities incurred
Liabilities settled
Revisions to estimate
Asset retirement obligation at end of period
Less: current retirement obligations
Long-term retirement obligations
$ 36,837
4,172
2,851
(6,586)
4,920
42,194
(9,151)
$ 33,043
2007____
$ 41,179
3,985
6,368
(19,519)
4,824
36,837
(9,810)
$ 27,027
.
Assets, primarily short-term U.S. Government securities, of approximately $4.8 million at December 31,
2008, 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.
70
12. 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
Years Ended December 31,
2008 2007 2006
(In thousands)
$ 1,349,904
6,126
2,578
223,090
$ 1,581,698
$ 1,096,907
154,193
35,959
62,845
$ 1,349,904
$ 937,698
4,053
73,659
81,497
$1,096,907
$ 70,176
6,409
6,496
(50,252)
$ 32,829
$ 54,802
21,525
7,152
(13,303)
$ 70,176
$ 49,065
19,103
6,477
(19,843)
$ 54,802
Accumulated depreciation, depletion
and amortization-
Beginning of period balance
Ceiling test and provision charged to expense
Sale of mineral interests
End of period balance
$ 738,374
549,552
167,349
$ 1,455,275
$ 604,682
72,762
60,930
$ 738,374
$ 539,399
65,283
--
$ 604,682
Unevaluated property costs, primarily 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 $11.3 million incurred in 2008, $10.3
million incurred in 2007, $5.8 million incurred in 2006 and $5.4 million incurred in 2005 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 $5.57, $3.89 and
$3.14 for the years ended December 31, 2008, 2007, and 2006, 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
71
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.
13. 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 $747,000, $680,000 and $615,000 in the years
2008, 2007 and 2006, respectively.
1996 Stock Incentive Plan
On August 23, 1996, the Board of Directors of the Company approved and adopted the Callon
Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996 Plan was
approved by the shareholders in 1997 and limited to a maximum of 1,200,000 shares (as
amended from the original 900,000 shares) of common stock subject to outstanding awards.
The 1996 Plan was amended again and approved on May 9, 2000 at the Annual Meeting of
Shareholders, increasing the number of shares reserved for issuance under the 1996 plan to
2,200,000 shares. Unvested options are subject to forfeiture upon certain termination of
employment events and expire 10 years from the date of grant.
In August 2006, the Board of Directors approved the award of 520,000 shares of restricted
stock from the 1996 Plan. Of the 520,000 shares, 20,000 shares were granted to non-employee
members of the Board of Directors and vested immediately. The remaining 500,000 shares
were issued to employees of the Company with 20% vesting immediately and the remaining
80% vesting ratably over the next four years. The compensation cost with respect to the 20%
that vested immediately was recognized as an expense on the grant date and the compensation
cost with respect to the remaining 80% is being amortized to expense over the vesting period.
2002 Stock Incentive Plan
On February 14, 2002, the Board of Directors of the Company approved and adopted the 2002
Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan, 350,000 shares of common
stock shall be reserved for issuance upon the exercise of options or for grants of stock options,
stock appreciation rights or units, bonus stock, or performance shares or units.
72
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.
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.
14. 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.
73
15. ENTRADA
On April 18, 2007, the Company completed an acquisition of BP’s 80% working interest in the Entrada field
for a purchase price of $190 million. The purchase price included $150 million payable at closing and an
additional $40 million payable after the achievement of certain production milestones. The purchased
interests included five federal offshore blocks at Garden Banks Blocks 738, 782, 785, 826 and 827, subject to
certain depth limitations. The acquisition was recorded at fair value based on the initial purchase price of
$150 million. As a result of the acquisition, Callon owned a 100% working interest in the Entrada field and
became operator.
To finance the initial $150 million payment of the purchase price, Callon closed on a seven-year $200 million
senior revolving credit facility arranged by Merrill Lynch Capital Corporation contemporaneous with the
closing of the acquisition. The facility was secured by a lien on the Entrada properties. The Company
borrowed the full commitment amount under the facility at closing to cover the required $150 million
payment to BP and expenses and fees related to the transaction and the balance was used to pay down our
UBOC senior secured revolving credit facility. The Company’s UBOC senior secured credit facility was
amended to allow for this transaction.
In August 2007, Callon entered into a production handling agreement (“PHA”) with ConocoPhillips and
Devon Energy Corporation. The PHA provides for production from the Entrada field to be processed through
the Magnolia production platform, which is owned by ConocoPhillips and Devon. On February 25, 2009 a
letter was sent to ConocoPhillips to terminate the PHA. There are no costs associated with the termination.
On April 8, 2008, Callon completed the sale of a 50% working interest in the Entrada Field to CIECO
effective January 1, 2008. At closing, CIECO paid Callon $155 million and reimbursed Callon $12.6 million
for 50% of Entrada capital expenditures incurred prior to the closing date. In addition, CIECO agreed to fund
half of a $40 million future contingent payment owed by Callon to BP if the production milestone was
achieved. Callon retained a 50% working interest and is operator of the field. The Company did not
recognize a gain or loss on this transaction.
Simultaneously with the closing of the CIECO transaction, the Company used the proceeds from the sale,
cash on hand and a draw of $16 million from the UBOC credit facility, to extinguish the $200 million senior
revolving credit facility, which was secured by a lien on the Entrada properties. Due to the early
extinguishment of the $200 million senior revolving credit facility on April 8, 2008, Callon 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 credit facility.
As part of the purchase price, CIECO agreed to loan a wholly-owned subsidiary of Callon, Callon
Entrada, the first $150 million of Callon Entrada’s costs to develop the Entrada project plus up to $12
million of additional loans to pay accrued interest thereon, which loans were non-recourse to Callon
Entrada, were not guaranteed by Callon or any of its other subsidiaries, and were to be repaid solely out
of the proceeds of the sale of production from the Entrada project. The Callon Entrada credit facility is
secured by Callon’s remaining 50% interest in the Entrada field, which was conveyed to Callon Entrada
as a capital contribution in connection with the closing of the Callon Entrada credit facility.
74
In late November 2008, Callon Entrada and CIECO decided to abandon the Entrada project. Under the
terms of our agreements with CIECO, Callon Entrada is responsible for its 50% share of the costs to plug
and abandon the Entrada project, which we estimate to be $46 million, $23 million net to Callon Entrada.
In addition, prior to abandonment of the project, CIECO failed to fund two loan requests totaling $40
million under our non-recourse credit agreement with them. CIECO also refused to fund its working
interest share for the settlement payment to terminate a drilling contract. Callon Entrada has paid its
share of the drilling contract. We continue to discuss with CIECO its failure to fund the $40 million in
loan requests and its share of the drilling contract. Because these discussions are in early stages, 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 regarding the loan requests or the drilling
contract settlement.
75
16. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 2008, 2007 and 2006 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.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following
reserve data represents estimates only and should not be construed as being exact. In addition, the
standardized measure of discounted future net cash flows should not be construed as the current market value
of the Company's oil and gas properties or the cost that would be incurred to obtain equivalent reserves. See
Note 10 regarding the provisions for royalty relief and the effect on 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,________
2008_
2007_
__2006_
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
24,531
(9,026)
--
--
(8,536)
--
(942)
6,027
116,454
(49,526)
--
--
(42,542)
105
(5,840)
18,651
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
4,723
4,663
5,159
4,723
22,340
13,463
36,750
22,340
18,428
(3,733)
--
--
--
204
(1,634)
13,265
78,021
(15,557)
--
--
--
14,550
(10,977)
66,037
7,323
5,159
30,982
36,750
76
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 period-end prices (approximately $6.36 per Mcf for natural
gas and $36.80 per Bbl for oil for the 2008 disclosures, $7.59 per Mcf and $90.92 per Bbl for 2007
disclosures, and $5.78 per Mcf and $54.07 per Bbl for 2006 disclosures) at each date presented with no
escalation. Future production and development costs are based on current costs without escalation. The
resulting net future cash flows have been discounted to their present values based on a 10% annual
discount factor.
Standardized Measure
Future cash inflows
Future costs -
Production
Development and net abandonment
Future net inflows before income taxes
Future income taxes
Future net cash flows
10% discount factor
Standardized measure of discounted
future net cash flows
Years Ended December 31,
2008
2007 2006
$ 340,485
(In thousands)
$3,113,759
(192,819)
( 34,111)
113,555
(565)
112,990
(26,685)
(390,669)
(405,186)
2,317,904
(699,967)
1,617,937
(483,948)
$1,101,182
(243,740)
(81,700)
775,742
(119,685)
656,057
(185,266)
$ 86,305
$ 1,133,989
$ 470,791
Changes in Standardized Measure
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
Years Ended December 31,
2008
2007 2006
$1,133,989
(122,104)
(In thousands)
$ 470,791
(142,973)
$ 837,552
(153,387)
(111,140)
411,525
(347,193)
(558,652)
795,595
--
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
122,862
--
(155,342)
108,871
187,209
(129,781)
(366,761)
$ 470,791
77
At year-end 2006, a downward revision was made by the Company’s independent petroleum engineers to
Entrada’s estimated net proved reserves as of December 31, 2006 due to new performance data from
analogous deepwater reservoirs.
The Company ended the year 2008 with estimated net proved reserves of 54.8 billion cubic feet of natural
gas equivalent (“Bcfe”). This reduction from 2007 year-end estimated net proved reserves of 263.6 Bcfe
is primarily due to the sale to CIECO of a 50% interest in the Entrada field and the abandonment of the
Entrada project.
17. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
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
13,640
(500,438)
(457,534)
5,856
$ 0.27 $ (21.19)
(21.19)
0.27
(a)
(a)
(a)
(a)
First Second Third
Quarter
Quarter Quarter Quarter
Fourth
(In thousands, except per share data)
2007_
Total revenues
Income from operations
Net income
Net income per common share-basic
Net income per common share-diluted
$ 45,484
13,705
5,803
$ 0.28
0.27
$ 43,474
12,828
2,581
$ 0.12
0.12
$ 37,869 $ 43,941
16,727
13,090
2,268
4,542
$ 0.11 $ 0.22
0.21
0.11
(a) 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, 2008.
18. SUBSEQUENT EVENTS
Subsequent to December 31, 2008, the Company entered into the first amendment of the Second
Amended and Restated Credit Agreement dated September 25, 2008, which states that a default under the
Entrada non-recourse loan would not constitute a default under the Company’s senior secured revolving
credit facility. The amendment set the borrowing base at $48 million and implemented a Monthly
Commitment Reduction (MCR) commencing on June 1, 2009 in the amount of $4.33 million per month.
78
The borrowing base and MCR are both subject to re-determination August 1, 2009 and quarterly
thereafter.
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, 2008
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, 2008.
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, 2008.
79
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, 2008, 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, 2008, based on the COSO criteria.
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,
80
2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and cash flows
for each of the three years in the period ended December 31, 2008 and our report dated March 19, 2009,
expressed an unqualified opinion thereon.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 19, 2009
81
ITEM 9B. OTHER INFORMATION
We have disclosed all information required to be disclosed in a current report on Form 8-K during the
fourth quarter of the year ended December 31, 2008 in previously filed reports on Form 8-K.
82
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company
relating to the Annual Meeting of Stockholders to be held on April 30, 2009 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 April 30, 2009 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 April 30, 2009 which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company
relating to the Annual Meeting of Stockholders to be held on April 30, 2009 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 April 30, 2009 which will be filed with the
Securities and Exchange Commission and is incorporated herein by reference.
83
PART IV.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K
(a) 1. The following is an index to the financial statements and financial statement schedules that are filed as
part of this Form 10-K on pages 49 through 79.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of the Years Ended December 31, 2008 and 2007
Consolidated Statements of Operations for the Three Years in the Period Ended
December 31, 2008
Consolidated Statements of Stockholders' Equity for the Three Years in the Period Ended
December 31, 2008
Consolidated Statements of Cash Flows for the Three Years in the Period Ended
December 31, 2008
Notes to Consolidated Financial Statements
(a) 2. Schedules other than those listed above are omitted because they are not required, not applicable or the
required information is included in the financial statements or notes thereto.
(a) 3. Exhibits:
2. Plan of acquisition, reorganization, arrangement, liquidation or succession*
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended (incorporated by reference to
Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31,
2003, File No. 001-14039)
3.2 Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company's
Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)
3.3 Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by
reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2003, File No. 001-14039)
4. Instruments defining the rights of security holders, including indentures
4.1 Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the
Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)
84
4.2 Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust
Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1
of the Company’s Registration Statement on Form 8-A, filed April 6, 2000, File No. 001-
14039)
4.3 Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under
the Company’s $185 million amended and restated senior unsecured credit agreement dated
December 23, 2003 to purchase common stock from the Company (incorporated by reference
to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended December
31, 2003, File No. 001-14039)
4.4
Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004 between
Callon Petroleum Company and American Stock Transfer and Trust Company (incorporated
by reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period
ended March 31, 2004, File No. 001-14039)
9. Voting trust agreement
None.
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between the Company and NOCO
Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.2 Counterpart to Registration Rights Agreement by and between the Company, Ganger Rolf
ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2 of the Company’s
Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 001-14039)
10.3 Registration Rights Agreement dated September 16, 1994 between the Company and Callon
Stockholders (incorporated by reference from Exhibit 10.3 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from
Exhibit 10.5 of the Company's Registration Statement on Form 8-B filed October 3, 1994
10.5 Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000
(incorporated by reference from Appendix I of the Company’s Definitive Proxy Statement of
Schedule 14A filed March 28, 2000)
10.6 Conveyance of Overriding Royalty Interest from the Company to Duke Capital Partners,
LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the Company’s
Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039)
10.7 Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit
10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001,
File No. 001-14039)
85
10.8 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)
10.9 Purchase and Sale Agreement executed on March 8, 2007 by and between Callon Petroleum
Operating Company and BP Exploration and Production Company (incorporated by reference
to Exhibit 2.1 of the Company’s Report on Form 8-K filed on March 9, 2007).
10.10 Deepwater Production Handling and Operating Services Agreement for Garden Banks Blocks
738, 782, 785, 826 and 827 Production Handling at the Garden Banks Block 783 Magnolia
TLP, dated as of August 31, 2007, by and between ConocoPhillips Company and Devon
Energy Production Company, L.P. and Callon Petroleum Operating Company (incorporated
by reference from Exhibit 10.1 of the Company’s Report on Form 10-Q filed on November 6,
2007).
10.11 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 Report on Form 8-K filed on December 13, 2007).
10.12 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
Report on Form 8-K filed on February 13, 2008).
10.13 Supplemental Indenture dated April 4, 2008 (incorporated by reference to Exhibit 10.1 of the
Company’s Report on Form 8-K filed on April 9, 2008)
10.14 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 Report on Form 8-K filed
on April 9, 2008)
10.15 Indemnity Agreement dated April 4, 2008 (incorporated by reference to Exhibit 10.4 of the
Company’s Report on Form 8-K filed on April 9, 2008)
10.16 Non-Recourse Guaranty dated April 4, 2008 (incorporated by reference to Exhibit 10.5 of the
Company’s Report on Form 8-K filed on April 9, 2008)
10.17 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
Report on Form 8-K filed on April 23, 2008)
10.18 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 Report on Form 8-K filed on April 23, 2008)
10.19 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
86
California, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 of the
Company’s Report on Form 8-K filed on October 1, 2008)
10.20 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 Report on Form 8-K filed on January 5, 2009).
10.21 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 Report on Form 8-K filed on January 5, 2009).
10.22 Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan (incorporated
by reference from Exhibit 10.1 of the Company’s Report on Form 8-K filed on January 5,
2009).
10.23 Amendment No. 1 to the Callon Petroleum Company 2002
Plan
(incorporated by reference from Exhibit 10.2 of the Company’s Report on Form 8-K filed on
January 5, 2009).
Incentive
Stock
10.24 Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated
by reference from Exhibit 10.3 of the Company’s Report on Form 8-K filed on January 5,
2009).
10.25 Amendment No. 1 dated as of March 19, 2009 to the Second Amended and Restated Credit
Agreement dated September 25, 2008 is among Callon Petroleum, the Lenders and Union
Bank of California, N.A., as Administrative Agent and as Issuing Lender.
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)
87
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*
*Inapplicable to this filing.
88
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 19, 2009
/s/Fred L. Callon
Fred L. Callon (principal executive officer,
director)
Date: March 19, 2009
/s/B. F. Weatherly
B. F. Weatherly (principal financial officer,
director)
Date: March 19, 2009
Date: March 19, 2009
Date: March 19, 2009
/s/Rodger W. Smith
Rodger W. Smith (principal accounting officer)
/s/Richard L. Flury
Richard Flury (director)
/s/John C. Wallace
John C. Wallace (director)
Date: March 19, 2009
/s/Richard O. Wilson
Richard O. Wilson (director)
Date: March 19, 2009
/s/Larry D. McVay
Larry McVay (director)
89
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 19, 2009
CALLON PETROLEUM COMPANY
By: /s/B. F. Weatherly
B. F. Weatherly, Executive Vice-President and
Chief Financial Officer
90
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 19, 2009, 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, 2008.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 19, 2009
91
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, 2008, 2007, and 2006 in Callon Petroleum Company’s Annual Report on Form 10-K for
the year ended December 31, 2008, 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.
/S/ Peter D. Huddleston
Peter D. Huddleston, P.E.
President
Houston, Texas
March 9, 2009
92
CERTIFICATIONS
Exhibit 31.1
I, Fred L. Callon, certify that:
1.
2.
I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls
and procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee
of registrant’s board of directors (or persons performing the equivalent function):
(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
93
(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 19, 2009
By: /s/Fred L. Callon
Fred L. Callon, President and Chief Executive Officer
(Principal Executive Officer)
94
CERTIFICATIONS
Exhibit 31.2
I, B. F. Weatherly, certify that:
1.
2.
I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;
Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a)
Designed such disclosure controls and procedures, or caused such disclosure controls
and procedures to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b)
Designed such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles;
(c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the disclosure controls and
procedures as of the end of the period covered by this report based on such evaluation; and
(d)
Disclosed in this report any change in the registrant’s internal control over financial
reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee
of registrant’s board of directors (or persons performing the equivalent function):
(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
95
(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 19, 2009
By: /s/B. F. Weatherly
B. F. Weatherly, Executive Vice-President and
Chief Financial Officer (Principal Financial Officer)
96
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, 2008, 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 19, 2009
/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.
97
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, 2008, 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 19, 2009
/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.
98
Corporate Data
Board of Directors
Fred L. Callon
Chairman and Chief Executive Officer
Legal Counsel
Haynes and Boone, LLP
Houston, Texas
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
Officers of the Company
Fred L. Callon
Chairman and Chief Executive Officer
B.F. Weatherly
Executive Vice President
and Chief Financial Officer
Mitzi P. Conn
Corporate Controller
Robert A. Mayfield
Corporate Secretary
Thomas E. Schwager
Vice President, Engineering
and Operations
H. Clark Smith
Corporate Information Officer
Rodger W. Smith
Vice President and Treasurer
Stephen F. Woodcock
Vice President, Exploration
Transfer Agent and Registrar
American Stock Transfer
& Trust Company
59 Maiden Lane, Plaza Level
New York, NY 10273
(718) 921-8200
Simon, Peragine, Smith & Redfern
New Orleans, Louisiana
Independent Registered
Public Accounting Firm
Ernst & Young LLP
New Orleans, Louisiana
Banks
Union Bank of California N.A.
San Francisco, California
Capital One, N.A.
McLean, Virginia
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
2008 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).
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 certifi cation on July 23, 2008
without qualification.
Notice of Annual
Shareholders’ Meeting
The Annual Meeting of Shareholders will be
held Thursday, April 30, 2009 at 9:00 a.m. in the
Grand Ball Room of the Country Inn & Suites,
111 Broadway, Natchez, MS 39120. Information
with respect to this meeting is contained in the
Proxy Statement sent to shareholders of record
on March 9, 2009. 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 2008 Annual
Report is not to be considered a part of the proxy
soliciting materials.
Callon Home Page
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.
Callon Petroleum Company 200 North Canal Street
Natchez, Mississippi 39120
www.callon.com