e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008
Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)
|
|
|
Delaware
|
|
64-0844345 |
|
|
|
(State or other jurisdiction of
incorporation or organization)
|
|
(I.R.S. Employer
Identification No.) |
|
|
|
200 North Canal Street
Natchez, Mississippi 39120
|
|
(601) 442-1601 |
|
|
|
(Address of Principal Executive
Offices)(Zip Code)
|
|
(Registrants telephone number
including area code) |
Securities registered pursuant to Section 12(b) of the Act:
|
|
|
Title of each class
|
|
Name of exchange on which registered |
|
|
|
Common Stock, Par Value $.01 Per Share
|
|
New York Stock Exchange |
Securities registered pursuant to Section 12(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 o No þ.
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 o No þ.
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 þ No o.
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 Registrants 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
|
|
|
|
|
|
|
Large accelerated filer o
|
|
Accelerated filer þ
|
|
Non-accelerated filer o
|
|
Smaller reporting company o |
|
|
|
|
(Do not check if a smaller reporting company) |
|
|
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule
12b-2). Yes o No þ.
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 Registrants 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.
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
|
|
|
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 Entradas
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 Entradas 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 months 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:
|
|
|
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; |
|
|
|
|
as commodity prices improve and service costs decline, explore and develop oil and gas
properties; and |
|
|
|
|
maintain efficient low operating costs. |
4
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:
|
|
|
$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 Companys (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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted |
|
|
|
|
|
|
Estimated Net Proved Reserves |
|
Present |
|
|
|
|
|
|
Oil |
|
Gas |
|
Total |
|
Value |
|
|
Operator |
|
(MBbls) |
|
(MMcf) |
|
(MMcfe) |
|
($000) |
|
|
|
|
|
|
|
|
|
|
(a)(b)(c) |
Gulf of Mexico Deepwater: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mississippi Canyon 538/582
Medusa |
|
Murphy |
|
|
4,929 |
|
|
|
3,506 |
|
|
|
33,078 |
|
|
$ |
52,872 |
|
Garden Banks Block 341
Habanero |
|
Shell |
|
|
953 |
|
|
|
5,041 |
|
|
|
10,758 |
|
|
|
28,687 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gulf of Mexico Shelf and Onshore: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Cameron Block 295 |
|
Mariner Energy |
|
|
9 |
|
|
|
2,195 |
|
|
|
2,249 |
|
|
|
8,015 |
|
East Cameron 257 |
|
SPN Resources |
|
|
|
|
|
|
1,401 |
|
|
|
1,401 |
|
|
|
5,492 |
|
East Cameron Block 109 |
|
Energy Partners LTD |
|
|
37 |
|
|
|
1,286 |
|
|
|
1,508 |
|
|
|
5,491 |
|
East Cameron 2/LA |
|
Apache |
|
|
19 |
|
|
|
977 |
|
|
|
1,095 |
|
|
|
4,189 |
|
Other |
|
Various |
|
|
80 |
|
|
|
4,246 |
|
|
|
4,727 |
|
|
|
(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 Companys 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
Gulf of Mexico Deepwater
Medusa, Mississippi Canyon Blocks 538/582
Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test
well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in
two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of
the discovery, and a second well was drilled in the first quarter of 2000 to further delineate the
extent of the pay intervals. 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
Managements Discussion and Analysis of Financial Condition and Results of Operations-Off-Balance
Sheet Arrangements.
Habanero, Garden Banks Block 341
During February 1999, the initial test well on our Habanero deepwater discovery encountered over
200 feet of net pay in two zones. Located in 2,015 feet of water, the well was drilled to a
measured depth of 21,158 feet. We own an 11.25% working interest in the well. The well is operated
by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working
interest being owned by Murphy.
A field delineation program began in mid-year 2001, which included three sidetracks of the
discovery well. Production casing was set on this well through the last of the sidetracks to the
Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in
the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By
means of a sub-sea completion and tie-back to an existing production facility in the area operated
by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the
Habanero 55 gas sand in January 2004. In July 2004, the #2 well producing the Habanero 52 oil sand
developed mechanical difficulties with a subsurface control valve and was shut-in resulting in a
significant loss of production. Repairs were completed and production was restored in late
December 2004. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the
Habanero 52 oil sand in December 2004.
7
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
2006 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Proved developed: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
4,663 |
|
|
|
4,723 |
|
|
|
5,159 |
|
Gas (Mcf) |
|
|
13,463 |
|
|
|
22,340 |
|
|
|
36,750 |
|
Mcfe |
|
|
41,441 |
|
|
|
50,676 |
|
|
|
67,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) (c) |
|
|
1,364 |
|
|
|
19,808 |
|
|
|
8,106 |
|
Gas (Mcf) (c) |
|
|
5,189 |
|
|
|
94,114 |
|
|
|
29,287 |
|
Mcfe (c) |
|
|
13,375 |
|
|
|
212,964 |
|
|
|
77,924 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total proved: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) (c) |
|
|
6,027 |
|
|
|
24,531 |
|
|
|
13,265 |
|
Gas (Mcf) (c) |
|
|
18,652 |
|
|
|
116,454 |
|
|
|
66,037 |
|
Mcfe (c) |
|
|
54,816 |
|
|
|
263,640 |
|
|
|
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, 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. |
9
|
(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.
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, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Development: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
1 |
|
|
|
0.15 |
|
|
|
1 |
|
|
|
0.25 |
|
|
|
|
|
|
|
|
|
Gas |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
0.12 |
|
|
|
2 |
|
|
|
0.37 |
|
Non-productive |
|
|
1 |
|
|
|
0.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2 |
|
|
|
0.65 |
|
|
|
2 |
|
|
|
0.37 |
|
|
|
2 |
|
|
|
0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
0.63 |
|
|
|
5 |
|
|
|
2.05 |
|
Non-productive |
|
|
2 |
|
|
|
0.22 |
|
|
|
3 |
|
|
|
0.47 |
|
|
|
8 |
|
|
|
2.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2 |
|
|
|
0.22 |
|
|
|
5 |
|
|
|
1.10 |
|
|
|
13 |
|
|
|
5.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
The following table sets forth our productive wells as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Wells |
|
|
Gross |
|
Net |
Oil: |
|
|
|
|
|
|
|
|
Working interest |
|
|
10.00 |
|
|
|
1.56 |
|
Royalty interest |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
10.00 |
|
|
|
1.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas: |
|
|
|
|
|
|
|
|
Working interest |
|
|
18.00 |
|
|
|
7.22 |
|
Royalty interest |
|
|
6.00 |
|
|
|
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.
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold
acreage as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold Acreage |
|
|
Developed |
|
Undeveloped |
Location |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Louisiana |
|
|
5,666 |
|
|
|
2,107 |
|
|
|
4,718 |
|
|
|
1,054 |
|
Texas |
|
|
3,520 |
|
|
|
1,760 |
|
|
|
4,800 |
|
|
|
3,240 |
|
Federal waters |
|
|
87,990 |
|
|
|
36,500 |
|
|
|
313,354 |
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
2006 |
Shell Trading Company |
|
|
33 |
% |
|
|
25 |
% |
|
|
41 |
% |
Louis Dreyfus Energy Services |
|
|
16 |
% |
|
|
20 |
% |
|
|
25 |
% |
StatoilHydro |
|
|
|
|
|
|
13 |
% |
|
|
|
|
Plains Marketing, L.P. |
|
|
23 |
% |
|
|
10 |
% |
|
|
11 |
% |
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.
11
Title to Properties
We believe that the title to our oil and gas properties is good and defensible in accordance with
standards generally accepted in the oil and gas industry, subject to such exceptions which, in our
opinion, are not so material as to detract substantially from the use or value of such properties.
Our properties are typically subject, in one degree or another, to one or more of the following:
|
|
|
royalties and other burdens and obligations, express or implied, under oil and gas
leases; |
|
|
|
|
overriding royalties and other burdens created by us or our predecessors in title; |
|
|
|
|
a variety of contractual obligations (including, in some cases, development obligations)
arising under operating agreements, farmout agreements, production sales contracts and
other agreements that may affect the properties or their titles; |
|
|
|
|
back-ins and reversionary interests existing under purchase agreements and leasehold
assignments; |
|
|
|
|
liens that arise in the normal course of operations, such as those for unpaid taxes,
statutory liens securing obligations to unpaid suppliers and contractors and contractual
liens under operating agreements; |
|
|
|
|
pooling, unitization and communitization agreements, declarations and orders; and |
|
|
|
|
easements, restrictions, rights-of-way and other matters that commonly affect property. |
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:
12
|
|
|
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 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.
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,
13
|
|
|
air emissions, |
|
|
|
|
discharges into surface waters, and |
|
|
|
|
the construction and operations of underground injection wells or surface pits to
dispose of produced saltwater and other nonhazardous oilfield wastes. |
In the event of an unauthorized discharge (e.g., to land or water), emission (e.g., to air) or
other activity, we may be liable for, among other things, penalties, costs and damages, and subject
to injunctive relief, and we could be required to cleanup or mitigate the environmental impacts of
those discharges, emissions or activities. Also, under federal, and certain state, laws, the
present and certain past owners and operators of a site, and persons that treated, disposed of or
arranged for the disposal of hazardous substances found at a site, may be liable, without regard to
fault or the legality of the original conduct, for the release of hazardous substances into the
environment. The Environmental Protection Agency, state environmental agencies and, in some cases
third parties are authorized to take actions in response to threats to human health or the
environment and to seek to recover from responsible classes of persons the costs of such actions.
We therefore could be required to remove or remediate previously disposed wastes and remediate
contamination, including contamination in surface water, soil or groundwater, caused by disposal of
that waste, irrespective 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
14
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 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.
Commitments and Contingencies
The Companys 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 Companys 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 SECs website.
15
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 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.
16
Our acquisitions may involve numerous risks, including:
|
|
|
operating a larger combined organization and adding operations; |
|
|
|
|
difficulties in the assimilation of the assets and operations of the acquired business,
especially if the assets acquired are in a new business segment or geographic area; |
|
|
|
|
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 managements attention from other business concerns; |
|
|
|
|
the failure to realize expected profitability or growth; |
|
|
|
|
the failure to realize expected synergies and cost savings; |
|
|
|
|
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 counterpartys liquidity, which could impair their
ability to perform under the terms of the hedging contract. We are unable to predict sudden changes
in a counterpartys 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.
17
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:
|
|
|
our revenues, cash flows and earnings; |
|
|
|
|
the amount of oil and gas that we are economically able to produce; |
|
|
|
|
our ability to attract capital to finance our operations and the cost of the capital; |
|
|
|
|
the amount we are allowed to borrow under our senior secured credit facility; |
|
|
|
|
the value of our oil and gas properties; and |
|
|
|
|
the profit or loss we incur in exploring for and developing our reserves. |
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
18
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.
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
19
producing wells. Our drilling operations may be curtailed, delayed or canceled as a result of
a variety of factors, including:
|
|
|
unexpected drilling conditions; |
|
|
|
|
pressure or inequalities in formations; |
|
|
|
|
equipment failures or accidents; |
|
|
|
|
adverse weather conditions; |
|
|
|
|
governmental requirements; and |
|
|
|
|
shortages or delays in the availability of drilling rigs and the delivery of equipment. |
We do not operate all of our properties and have limited influence over the operations of some of
these properties, particularly two of our deepwater properties. Our lack of control could result
in the following:
|
|
|
the operator may initiate exploration or development at a faster or slower pace than we
prefer; |
|
|
|
|
the operator may propose to drill more wells or build more facilities on a project than
we have funds for or that we deem appropriate, which may mean that we are unable to
participate in the project or share in the revenues generated by the project even though we
paid our share of exploration costs; and |
|
|
|
|
if an operator refuses to initiate a project, we may be unable to pursue the project. |
Any of these events could materially reduce the value of our non-operated properties.
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:
|
|
|
decisions made by the operators of our deepwater wells; |
|
|
|
|
the availability of materials necessary to construct the facilities; |
|
|
|
|
the proximity of our discoveries to pipelines; |
|
|
|
|
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.
20
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:
|
|
|
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; |
|
|
|
|
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 datas 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 Managements Discussion
and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources
for a discussion of our capital budget. We cannot assure you that we will be able to raise capital
in the future. We also make offers to acquire oil and gas properties in the ordinary course of our
business. If these offers are accepted, our capital needs may increase substantially.
We expect
to continue using our senior secured 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.
21
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 Managements Discussion and Analysis of Financial Condition
and Results of Operations Liquidity and Capital Resources and Notes 7 and 18 to our Consolidated
Financial Statements.
Our decision to drill a prospect is subject to a number of factors, and we may decide to alter our
drilling schedule or not drill at all. A prospect is a property on which we have identified what
our geoscientists believe, based on available seismic and geological information, to be indications
of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which
is ready to drill to a prospect which will require substantial additional seismic data processing
and interpretation. Whether we ultimately drill a prospect may depend on the following factors:
|
|
|
receipt of additional seismic data or the reprocessing of existing data; |
|
|
|
|
material changes in oil or gas prices; |
|
|
|
|
the costs and availability of drilling rigs; |
|
|
|
|
the success or failure of wells drilled in similar formations or which would use the
same production facilities; |
|
|
|
|
availability and cost of capital; |
|
|
|
|
changes in the estimates of the costs to drill or complete wells; |
|
|
|
|
our ability to attract other industry partners to acquire a portion of the working
interest to reduce exposure to costs and drilling risks; and |
|
|
|
|
decisions of our joint working interest owners. |
We will continue to gather data about our prospects and it is possible that additional information
may cause us to alter our drilling schedule or determine that a prospect should not be pursued at
all. You should understand that our plans regarding our prospects are subject to change.
Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely
impact our ability to conduct business. There are many operating hazards in exploring for and
producing oil and gas, including:
|
|
|
our drilling operations may encounter unexpected formations or pressures, which could
cause damage to equipment or personal injury; |
|
|
|
|
we may experience equipment failures which curtail or stop production; |
|
|
|
|
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 |
|
|
|
|
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.
22
We cannot assure you that we will be able to maintain adequate insurance at rates we consider
reasonable to cover our possible losses from operating hazards. The occurrence of a significant
event not fully insured or indemnified against could materially and adversely affect our financial
condition and results of operations.
We may not have production to offset hedges; by hedging, we may not benefit from price increases.
Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by
hedging a portion of our production. In a typical hedge transaction, we will have the right to
receive from the other parties to the hedge the excess of the fixed price specified in the hedge
over a floating price based on a market index, multiplied by the quantity hedged. If the floating
price exceeds the fixed price, we are required to pay the other parties this difference multiplied
by the quantity hedged. We are required to pay the difference between the floating price and the
fixed price when the floating price exceeds the fixed price regardless of whether we have
sufficient production to cover the quantities specified in the hedge. Significant reductions in
production at times when the floating price exceeds the fixed price could require us to make
payments under the hedge agreements even though such payments are not offset by sales of
production. Hedging will also prevent us from receiving the full advantage of increases in oil or
gas prices above the fixed amount specified in the hedge. We also enter into price collars to
reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either
party so long as the market price is above a floor set in the collar and below a ceiling. If the
price falls below the floor, the counter-party to the collar pays the difference to us and if the
price is above the ceiling, we pay the counter-party the difference. Another type of hedging
contract we have entered into is a put contract. Under a put, if the price falls below the set
floor price, the counter-party to the contract pays the difference to us. See Quantitative and
Qualitative Disclosures About Market Risks for a discussion of our hedging practices.
Compliance with environmental and other government regulations could be costly and could negatively
impact production. Our operations are subject to numerous laws and regulations governing the
operation and maintenance of our facilities and the discharge of materials into the environment or
otherwise relating to environmental protection. For a discussion of the material regulations
applicable to us, see Regulations. These laws and regulations may:
|
|
|
require that we acquire permits before commencing drilling; |
|
|
|
|
impose operational 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.
23
Factors beyond our control affect our ability to market production and our financial results. The
ability to market oil and gas from our wells depends upon numerous factors beyond our control.
These factors include:
|
|
|
the extent of domestic production and imports of oil and gas; |
|
|
|
|
the proximity of the gas production to gas pipelines; |
|
|
|
|
the availability of pipeline capacity; |
|
|
|
|
the demand for oil and gas by utilities and other end users; |
|
|
|
|
the availability of alternative fuel sources; |
|
|
|
|
the effects of inclement weather; |
|
|
|
|
state and federal regulation of oil and gas marketing; and |
|
|
|
|
federal regulation of gas sold or transported in interstate commerce. |
Because of these factors, we may be unable to market all of the oil or gas we produce. In addition,
we may be unable to obtain favorable prices for the oil and gas we produce.
If oil and gas prices decrease 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 auditors 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.
24
Forward-Looking Statements
In this report, we have made many forward-looking statements. We cannot assure you that the plans,
intentions or expectations upon which our forward-looking statements are based will occur. Our
forward-looking statements are subject to risks, uncertainties and assumptions, including those
discussed elsewhere in this report. Forward-looking statements include statements regarding:
|
|
|
our oil and gas reserve quantities, and the discounted present value of these
reserves; |
|
|
|
|
the amount and nature of our capital expenditures; |
|
|
|
|
drilling of wells; |
|
|
|
|
the timing and amount of future production and operating costs; |
|
|
|
|
business strategies and plans of management; and |
|
|
|
|
prospect development and property acquisitions. |
Some of the risks, which could affect our future results and could cause results to differ
materially from those expressed in our forward-looking statements, include:
|
|
|
the current global economic downturn; |
|
|
|
|
general economic conditions or including the availability of credit and access to
existing lines of credit; |
|
|
|
|
the volatility of oil and natural gas prices; |
|
|
|
|
the uncertainty of estimates of oil and natural gas reserves; |
|
|
|
|
the impact of competition; |
|
|
|
|
the availability and cost of seismic, drilling and other equipment; |
|
|
|
|
operating hazards inherent in the exploration for and production of oil and natural
gas; |
|
|
|
|
difficulties encountered during the exploration for and production of oil and
natural gas; |
|
|
|
|
difficulties encountered in delivering oil and natural gas to commercial markets; |
|
|
|
|
changes in customer demand and producers supply; |
|
|
|
|
the uncertainty of our ability to attract capital and obtain financing on favorable
terms; |
|
|
|
|
compliance with, or the effect of changes in, the extensive governmental
regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases; |
|
|
|
|
actions of operators of our oil and gas properties; and |
|
|
|
|
weather conditions. |
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 1.B. Unresolved Staff Comments
None.
25
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.
26
PART II.
ITEM 5. MARKET FOR REGISTRANTS 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: |
|
|
|
|
|
|
|
|
First quarter |
|
$ |
15.00 |
|
|
$ |
12.54 |
|
Second quarter |
|
|
15.19 |
|
|
|
13.26 |
|
Third quarter |
|
|
15.68 |
|
|
|
11.50 |
|
Fourth quarter |
|
|
17.21 |
|
|
|
13.33 |
|
2008: |
|
|
|
|
|
|
|
|
First quarter |
|
$ |
19.22 |
|
|
$ |
13.42 |
|
Second quarter |
|
|
28.93 |
|
|
|
17.63 |
|
Third quarter |
|
|
28.00 |
|
|
|
16.18 |
|
Fourth quarter |
|
|
18.06 |
|
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of securities |
|
|
|
|
|
|
|
|
|
|
|
remaining available |
|
|
|
Number of |
|
|
Weighted- |
|
|
for future issuance |
|
|
|
securities |
|
|
average |
|
|
under equity |
|
|
|
to be issued upon |
|
|
exercise price of |
|
|
compensation plan |
|
|
|
exercise |
|
|
outstanding |
|
|
(excluding securities |
|
|
|
of outstanding |
|
|
options, warrants |
|
|
reflected in column |
|
|
|
options |
|
|
and rights |
|
|
(a)) |
|
Plan Category |
|
(a) |
|
|
(b) |
|
|
(c) |
|
Equity
compensation plans
approved by
security holders |
|
|
422,792 |
|
|
$ |
10.81 |
|
|
|
351,479 |
|
Equity
compensation plans
not approved by
security holders |
|
|
90,483 |
|
|
|
7.73 |
|
|
|
42,466 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
513,275 |
|
|
$ |
10.27 |
|
|
|
393,945 |
|
|
|
|
|
|
|
|
|
|
|
27
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 Companys 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
ASSUMES $100 INVESTED ON DEC. 31, 2003
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
2004 |
|
|
2005 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
Callon Petroleum Company |
|
|
$ |
100 |
|
|
|
$ |
139 |
|
|
|
$ |
170 |
|
|
|
$ |
145 |
|
|
|
$ |
159 |
|
|
|
$ |
25 |
|
|
|
Hemscott Group Index |
|
|
$ |
100 |
|
|
|
$ |
141 |
|
|
|
$ |
222 |
|
|
|
$ |
263 |
|
|
|
$ |
413 |
|
|
|
$ |
185 |
|
|
|
NYSE Market Index |
|
|
$ |
100 |
|
|
|
$ |
113 |
|
|
|
$ |
122 |
|
|
|
$ |
143 |
|
|
|
$ |
151 |
|
|
|
$ |
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 Managements 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.
28
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 |
|
$ |
141,312 |
|
|
$ |
170,768 |
|
|
$ |
182,268 |
|
|
$ |
141,290 |
|
|
$ |
119,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
19,208 |
|
|
|
27,795 |
|
|
|
28,881 |
|
|
|
24,377 |
|
|
|
22,308 |
|
Depreciation, depletion and
amortization |
|
|
64,054 |
|
|
|
72,762 |
|
|
|
65,283 |
|
|
|
44,946 |
|
|
|
47,453 |
|
General and administrative |
|
|
9,565 |
|
|
|
9,876 |
|
|
|
8,591 |
|
|
|
8,085 |
|
|
|
8,758 |
|
Accretion expense |
|
|
4,172 |
|
|
|
3,985 |
|
|
|
4,960 |
|
|
|
3,549 |
|
|
|
3,400 |
|
Derivative expense |
|
|
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 |
|
|
26,705 |
|
|
|
34,329 |
|
|
|
16,480 |
|
|
|
16,660 |
|
|
|
20,137 |
|
Other (income) |
|
|
(1,379 |
) |
|
|
(1,172 |
) |
|
|
(1,869 |
) |
|
|
(998 |
) |
|
|
(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) |
|
|
(438,893 |
) |
|
|
15,194 |
|
|
|
40,560 |
|
|
|
26,776 |
|
|
|
21,501 |
|
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
$ |
(20.68 |
) |
|
$ |
0.73 |
|
|
$ |
2.00 |
|
|
$ |
1.43 |
|
|
$ |
1.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
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 |
|
$ |
159,252 |
|
|
$ |
681,706 |
|
|
$ |
547,027 |
|
|
$ |
447,364 |
|
|
$ |
406,690 |
|
|
Total assets |
|
$ |
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.
30
|
ITEM 7. MANAGEMENTS 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.
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.
31
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 Entradas 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 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.
32
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:
|
|
|
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:
|
|
|
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 BudgetDue 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.
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:
33
|
|
|
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 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:
34
|
|
|
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 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.
35
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 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.
36
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
statements.
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
statements.
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 entitys 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; |
|
|
|
|
modifies the prices used to estimate reserves for SEC disclosure
purposes to a 12-month average 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
37
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 Monthly Commitment
Reduction (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.
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:
|
|
|
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):
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by Period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
More |
|
Contractual |
|
|
|
|
|
Less Than |
|
|
One-Three |
|
|
Three-Five |
|
|
Than-Five |
|
Obligations |
|
Total |
|
|
One Year |
|
|
Years |
|
|
Years |
|
|
Years |
|
Senior Secured Credit Facility |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
9.75% Senior Notes |
|
|
200,000 |
|
|
|
|
|
|
|
200,000 |
|
|
|
|
|
|
|
|
|
Callon Entrada Credit Facility (1) |
|
|
78,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78,435 |
|
Throughput Commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Medusa Oil Pipeline |
|
|
214 |
|
|
|
51 |
|
|
|
101 |
|
|
|
35 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
278,649 |
|
|
$ |
51 |
|
|
$ |
200,101 |
|
|
$ |
35 |
|
|
$ |
78,462 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
39
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
942 |
|
|
|
1,063 |
|
|
|
1,634 |
|
Gas (MMcf) |
|
|
5,839 |
|
|
|
12,340 |
|
|
|
10,977 |
|
Total production (MMcfe) |
|
|
11,494 |
|
|
|
18,718 |
|
|
|
20,780 |
|
Average daily production (MMcfe) |
|
|
31.4 |
|
|
|
51.3 |
|
|
|
56.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales price: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) (a) |
|
$ |
88.07 |
|
|
$ |
67.63 |
|
|
$ |
57.33 |
|
Gas (per Mcf) |
|
$ |
9.99 |
|
|
$ |
8.01 |
|
|
$ |
8.07 |
|
Total (per Mcfe) |
|
$ |
12.29 |
|
|
$ |
9.12 |
|
|
$ |
8.77 |
|
|
Oil and gas revenues (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
82,963 |
|
|
$ |
71,891 |
|
|
$ |
93,665 |
|
Gas revenue |
|
|
58,349 |
|
|
|
98,877 |
|
|
|
88,603 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
141,312 |
|
|
$ |
170,768 |
|
|
$ |
182,268 |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (in thousands) |
|
$ |
19,208 |
|
|
$ |
27,795 |
|
|
$ |
28,881 |
|
|
Additional per Mcfe data: |
|
|
|
|
|
|
|
|
|
|
|
|
Sales price |
|
$ |
12.29 |
|
|
$ |
9.12 |
|
|
$ |
8.77 |
|
Lease operating expenses |
|
|
1.67 |
|
|
|
1.48 |
|
|
|
1.39 |
|
|
|
|
|
|
|
|
|
|
|
Operating margin |
|
$ |
10.62 |
|
|
$ |
7.64 |
|
|
$ |
7.38 |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion |
|
$ |
5.57 |
|
|
$ |
3.89 |
|
|
$ |
3.14 |
|
General and administrative (net of management fees) |
|
$ |
.83 |
|
|
$ |
.53 |
|
|
$ |
.41 |
|
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per
barrel of oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NYMEX oil price |
|
$ |
99.67 |
|
|
$ |
72.33 |
|
|
$ |
66.22 |
|
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 |
) |
|
|
|
|
|
|
|
|
|
|
Average realized oil price |
|
$ |
88.07 |
|
|
$ |
67.63 |
|
|
$ |
57.33 |
|
|
|
|
|
|
|
|
|
|
|
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.
40
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.
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.
41
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.
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
42
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.
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.
43
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity Price Risk
The Companys 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 Companys 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 Companys 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 Companys derivative positions may not be designated as hedges
for accounting purposes. See Note 8 to the Consolidated Financial Statements for a description of
the Companys 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.
44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
45
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 Companys 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 Companys internal control over financial
reporting as of December 31, 2008, based on criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated March 19, 2009, expressed an unqualified opinion thereon.
New Orleans, Louisiana
March 19, 2009
46
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
December
31, |
|
|
|
2008 |
|
|
2007 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
17,126 |
|
|
$ |
53,250 |
|
Accounts receivable |
|
|
44,290 |
|
|
|
22,073 |
|
Restricted investments |
|
|
|
|
|
|
100 |
|
Fair market value of derivatives |
|
|
21,780 |
|
|
|
|
|
Other current assets |
|
|
1,103 |
|
|
|
6,592 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
84,299 |
|
|
|
82,015 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, full-cost accounting method: |
|
|
|
|
|
|
|
|
Evaluated properties |
|
|
1,581,698 |
|
|
|
1,349,904 |
|
Less accumulated depreciation, depletion and amortization |
|
|
(1,455,275 |
) |
|
|
(738,374 |
) |
|
|
|
|
|
|
|
|
|
|
126,423 |
|
|
|
611,530 |
|
|
|
|
|
|
|
|
|
|
Unevaluated properties excluded from amortization |
|
|
32,829 |
|
|
|
70,176 |
|
|
|
|
|
|
|
|
Total oil and gas properties |
|
|
159,252 |
|
|
|
681,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other property and equipment, net |
|
|
2,536 |
|
|
|
1,986 |
|
Restricted investments |
|
|
4,759 |
|
|
|
4,525 |
|
Investment in Medusa Spar LLC |
|
|
12,577 |
|
|
|
12,673 |
|
Other assets, net |
|
|
2,667 |
|
|
|
9,577 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
266,090 |
|
|
$ |
792,482 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
76,516 |
|
|
$ |
37,698 |
|
Asset retirement obligations |
|
|
9,151 |
|
|
|
9,810 |
|
Fair market value of derivatives |
|
|
|
|
|
|
5,205 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
85,667 |
|
|
|
52,713 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.75% Senior Notes |
|
|
194,420 |
|
|
|
192,012 |
|
Callon Entrada Credit Facility (non-recourse) |
|
|
78,435 |
|
|
|
|
|
Senior Revolving Credit Facility |
|
|
|
|
|
|
200,000 |
|
|
|
|
|
|
|
|
Total long-term debt |
|
|
272,855 |
|
|
|
392,012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
|
33,043 |
|
|
|
27,027 |
|
Deferred tax liability |
|
|
|
|
|
|
32,190 |
|
Other long-term liabilities |
|
|
4,329 |
|
|
|
1,465 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
395,894 |
|
|
|
505,407 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
216 |
|
|
|
209 |
|
Capital in excess of par value |
|
|
227,803 |
|
|
|
223,336 |
|
Other comprehensive income (loss) |
|
|
14,157 |
|
|
|
(3,383 |
) |
Retained (deficit) earnings |
|
|
(371,980 |
) |
|
|
66,913 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
(129,804 |
) |
|
|
287,075 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
266,090 |
|
|
$ |
792,482 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
47
Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Operating revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
82,963 |
|
|
$ |
71,891 |
|
|
$ |
93,665 |
|
Gas sales |
|
|
58,349 |
|
|
|
98,877 |
|
|
|
88,603 |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
141,312 |
|
|
|
170,768 |
|
|
|
182,268 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
19,208 |
|
|
|
27,795 |
|
|
|
28,881 |
|
Depreciation, depletion and amortization |
|
|
64,054 |
|
|
|
72,762 |
|
|
|
65,283 |
|
General and administrative |
|
|
9,565 |
|
|
|
9,876 |
|
|
|
8,591 |
|
Accretion expense |
|
|
4,172 |
|
|
|
3,985 |
|
|
|
4,960 |
|
Derivative expense |
|
|
498 |
|
|
|
|
|
|
|
150 |
|
Impairment of oil and gas properties |
|
|
485,498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
582,995 |
|
|
|
114,418 |
|
|
|
107,865 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations |
|
|
(441,683 |
) |
|
|
56,350 |
|
|
|
74,403 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other (income) expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
26,705 |
|
|
|
34,329 |
|
|
|
16,480 |
|
Loss on early extinguishment of debt |
|
|
11,871 |
|
|
|
|
|
|
|
|
|
Other income |
|
|
(1,379 |
) |
|
|
(1,172 |
) |
|
|
(1,869 |
) |
|
|
|
|
|
|
|
|
|
|
Total other (income) expenses |
|
|
37,197 |
|
|
|
33,157 |
|
|
|
14,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(478,880 |
) |
|
|
23,193 |
|
|
|
59,792 |
|
Income tax (benefit) expense |
|
|
(39,725 |
) |
|
|
8,506 |
|
|
|
20,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before equity in earnings of Medusa Spar LLC |
|
|
(439,155 |
) |
|
|
14,687 |
|
|
|
39,085 |
|
Equity in earnings of Medusa Spar LLC, net of tax |
|
|
262 |
|
|
|
507 |
|
|
|
1,475 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common shares |
|
$ |
(438,893 |
) |
|
$ |
15,194 |
|
|
$ |
40,560 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(20.68 |
) |
|
$ |
0.73 |
|
|
$ |
2.00 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(20.68 |
) |
|
$ |
0.71 |
|
|
$ |
1.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares used in computing net income (loss) per share
amounts: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
21,222 |
|
|
|
20,776 |
|
|
|
20,270 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
21,222 |
|
|
|
21,290 |
|
|
|
21,363 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
48
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unearned |
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
Restricted |
|
|
Capital in |
|
|
Other |
|
|
Retained |
|
|
Stock- |
|
|
|
Preferred |
|
|
Common |
|
|
Stock |
|
|
Excess of |
|
|
Comprehensive |
|
|
Earnings |
|
|
holders |
|
|
|
Stock |
|
|
Stock |
|
|
Compensation |
|
|
Par Value |
|
|
Income (Loss) |
|
|
(Deficit) |
|
|
Equity |
|
Balances, December 31, 2005 |
|
$ |
|
|
|
$ |
194 |
|
|
$ |
(3,334 |
) |
|
$ |
220,360 |
|
|
$ |
(331 |
) |
|
$ |
11,159 |
|
|
$ |
228,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,560 |
|
|
|
|
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,983 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,543 |
|
Shares issued pursuant to employee
benefit and option plan |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
(441 |
) |
|
|
|
|
|
|
|
|
|
|
(439 |
) |
Tax benefits related to stock
compensation plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,356 |
|
|
|
|
|
|
|
|
|
|
|
1,356 |
|
Adoption of 123R |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,334 |
|
|
|
(3,334 |
) |
|
|
|
|
|
|
|
|
Restricted stock |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
2,854 |
|
|
|
|
|
|
|
|
|
|
|
2,855 |
|
Warrants |
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2006 |
|
|
|
|
|
|
207 |
|
|
|
|
|
|
|
220,785 |
|
|
|
8,652 |
|
|
|
51,719 |
|
|
|
281,363 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,194 |
|
|
|
|
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,035 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,159 |
|
Tax benefits related to stock
compensation plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
163 |
|
|
|
|
|
|
|
|
|
|
|
163 |
|
Restricted stock |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2,388 |
|
|
|
|
|
|
|
|
|
|
|
2,390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2007 |
|
|
|
|
|
|
209 |
|
|
|
|
|
|
|
223,336 |
|
|
|
(3,383 |
) |
|
|
66,913 |
|
|
|
287,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(438,893 |
) |
|
|
|
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(421,353 |
) |
Shares issued pursuant to employee
benefit and option plan |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
(1,153 |
) |
|
|
|
|
|
|
|
|
|
|
(1,152 |
) |
Tax benefits related to stock
compensation plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,050 |
|
|
|
|
|
|
|
|
|
|
|
2,050 |
|
Restricted stock |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
3,575 |
|
|
|
|
|
|
|
|
|
|
|
3,576 |
|
Warrants |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2008 |
|
$ |
|
|
|
$ |
216 |
|
|
$ |
|
|
|
$ |
227,803 |
|
|
$ |
14,157 |
|
|
$ |
(371,980 |
) |
|
$ |
(129,804 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
49
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) |
|
$ |
(438,893 |
) |
|
$ |
15,194 |
|
|
$ |
40,560 |
|
Adjustments to reconcile net income (loss) to
cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
64,862 |
|
|
|
73,677 |
|
|
|
65,929 |
|
Impairment of oil and gas properties |
|
|
485,498 |
|
|
|
|
|
|
|
|
|
Accretion expense |
|
|
4,172 |
|
|
|
3,985 |
|
|
|
4,960 |
|
Amortization of deferred financing costs |
|
|
4,185 |
|
|
|
3,009 |
|
|
|
2,221 |
|
Non-cash loss on early extinguishment of debt |
|
|
5,598 |
|
|
|
|
|
|
|
|
|
Equity in earnings of Medusa Spar, LLC |
|
|
(262 |
) |
|
|
(507 |
) |
|
|
(1,475 |
) |
Non-cash derivative expense |
|
|
|
|
|
|
|
|
|
|
150 |
|
Deferred income tax (benefit) expense |
|
|
(39,725 |
) |
|
|
8,506 |
|
|
|
20,707 |
|
Non-cash charge related to compensation plans |
|
|
1,550 |
|
|
|
849 |
|
|
|
1,420 |
|
Excess tax benefits from share-based payment arrangements |
|
|
(2,050 |
) |
|
|
(163 |
) |
|
|
(1,449 |
) |
Changes in current assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(22,215 |
) |
|
|
6,658 |
|
|
|
(2,107 |
) |
Other current assets |
|
|
5,489 |
|
|
|
(619 |
) |
|
|
(3,975 |
) |
Current liabilities |
|
|
22,987 |
|
|
|
(2,057 |
) |
|
|
11,311 |
|
Change in gas balancing receivable |
|
|
630 |
|
|
|
(938 |
) |
|
|
(311 |
) |
Change in gas balancing payable |
|
|
156 |
|
|
|
889 |
|
|
|
133 |
|
Change in other long-term liabilities |
|
|
2,708 |
|
|
|
(10 |
) |
|
|
(2 |
) |
Change in other assets, net |
|
|
(1,458 |
) |
|
|
810 |
|
|
|
(2,588 |
) |
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities |
|
|
93,232 |
|
|
|
109,283 |
|
|
|
135,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(176,536 |
) |
|
|
(127,409 |
) |
|
|
(167,979 |
) |
Entrada acquisition |
|
|
|
|
|
|
(150,000 |
) |
|
|
|
|
Proceeds from sale of mineral interests |
|
|
167,349 |
|
|
|
60,931 |
|
|
|
|
|
Distribution from Medusa Spar, LLC |
|
|
498 |
|
|
|
687 |
|
|
|
1,078 |
|
|
|
|
|
|
|
|
|
|
|
Cash used by investing activities |
|
|
(8,689 |
) |
|
|
(215,791 |
) |
|
|
(166,901 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Change in accrued liabilities to be refinanced |
|
|
|
|
|
|
|
|
|
|
(5,000 |
) |
Increases in debt |
|
|
94,435 |
|
|
|
229,000 |
|
|
|
88,000 |
|
Payments on debt |
|
|
(216,000 |
) |
|
|
(64,000 |
) |
|
|
(53,000 |
) |
Deferred financing costs |
|
|
|
|
|
|
(6,429 |
) |
|
|
|
|
Equity issued related to employee stock plans |
|
|
(1,152 |
) |
|
|
|
|
|
|
(438 |
) |
Excess tax benefits from share-based payment arrangements |
|
|
2,050 |
|
|
|
163 |
|
|
|
1,449 |
|
Capital leases |
|
|
|
|
|
|
(872 |
) |
|
|
(263 |
) |
|
|
|
|
|
|
|
|
|
|
Cash (used) provided by financing activities |
|
|
(120,667 |
) |
|
|
157,862 |
|
|
|
30,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents |
|
|
(36,124 |
) |
|
|
51,354 |
|
|
|
(669 |
) |
|
Cash and cash equivalents: |
|
|
|
|
|
|
|
|
|
|
|
|
Balance, beginning of period |
|
|
53,250 |
|
|
|
1,896 |
|
|
|
2,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of period |
|
$ |
17,126 |
|
|
$ |
53,250 |
|
|
$ |
1,896 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these financial statements.
50
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 Companys 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.
51
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
Companys 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.
52
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
Callons 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 Companys 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 Companys 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.
Callons derivative contracts are carried at fair value on the Companys 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.
53
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
$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
54
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 Companys 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 Companys 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2008 |
|
2007 |
|
2006 |
Shell Trading Company |
|
|
33 |
% |
|
|
25 |
% |
|
|
41 |
% |
Louis Dreyfus Energy Services |
|
|
16 |
% |
|
|
20 |
% |
|
|
25 |
% |
StatoilHydro |
|
|
|
|
|
|
13 |
% |
|
|
|
|
Plains Marketing, L.P. |
|
|
23 |
% |
|
|
10 |
% |
|
|
11 |
% |
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 Companys 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.
55
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 Companys 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 Companys 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 statements.
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 entitiy 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
statements.
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 entitys 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.
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; |
|
|
|
|
modifies the prices used to estimate reserves for SEC disclosure
purposes to a 12-month average 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 Companys 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.
56
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.
|
|
|
|
|
|
|
|
|
|
|
Years Ended |
|
|
December 31, |
|
|
2007 |
|
2006 |
Dividend yield |
|
|
|
|
|
|
|
|
Expected volatility |
|
|
36.2 |
% |
|
|
38.9 |
% |
Risk-free interest rate |
|
|
4.7 |
% |
|
|
4.6 |
% |
Expected life of option (in years) |
|
|
5 |
|
|
|
5 |
|
Weighted-average grant-date fair value |
|
$ |
5.64 |
|
|
$ |
7.72 |
|
Forfeiture rate |
|
|
2.0 |
% |
|
|
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 Companys stock price.
The following table represents stock option activity for the three years ended December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
Wtd Avg |
|
|
|
|
|
|
Wtd Avg |
|
|
|
|
|
|
Wtd Avg |
|
|
|
Shares |
|
|
Ex Price |
|
|
Shares |
|
|
Ex Price |
|
|
Shares |
|
|
Ex Price |
|
Outstanding, beginning of year |
|
|
755,225 |
|
|
$ |
10.00 |
|
|
|
740,225 |
|
|
$ |
9.93 |
|
|
|
1,205,558 |
|
|
$ |
10.11 |
|
Granted (at market) |
|
|
|
|
|
|
|
|
|
|
30,000 |
|
|
|
14.27 |
|
|
|
15,000 |
|
|
|
18.69 |
|
Exercised |
|
|
(238,950 |
) |
|
|
9.34 |
|
|
|
|
|
|
|
|
|
|
|
(480,333 |
) |
|
|
10.66 |
|
Forfeited |
|
|
(3,000 |
) |
|
|
15.97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expired |
|
|
|
|
|
|
|
|
|
|
(15,000 |
) |
|
|
15.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding, end of year |
|
|
513,275 |
|
|
$ |
10.27 |
|
|
|
755,225 |
|
|
$ |
10.00 |
|
|
|
740,225 |
|
|
$ |
9.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, end of year |
|
|
488,075 |
|
|
$ |
9.91 |
|
|
|
710,225 |
|
|
$ |
9.57 |
|
|
|
695,225 |
|
|
$ |
9.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average remaining |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract life: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding options at
end of period |
|
2.92 yrs. |
|
|
|
|
|
3.39 yrs. |
|
|
|
|
|
4.06 yrs. |
|
|
|
|
Outstanding
exercisable at
end of period |
|
2.68 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 unvested stock options, which is expected to be recognized over a weighted-average period of
two years.
57
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average |
|
|
Number of |
|
Grant-Date |
|
|
Shares |
|
Fair Value |
|
|
|
Outstanding shares at beginning of period |
|
|
487,450 |
|
|
$ |
15.17 |
|
Granted |
|
|
242,600 |
|
|
|
20.73 |
|
Vested |
|
|
(206,950 |
) |
|
|
16.05 |
|
Forfeited |
|
|
(13,800 |
) |
|
|
16.08 |
|
|
|
|
|
Outstanding shares at end of period |
|
|
509,300 |
|
|
$ |
17.43 |
|
|
|
|
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.
58
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 |
|
|
|
20,776 |
|
|
|
20,270 |
|
Dilutive impact of stock options |
|
|
|
|
|
|
148 |
|
|
|
238 |
|
Dilutive impact of restricted stock |
|
|
|
|
|
|
40 |
|
|
|
78 |
|
Dilutive impact of warrants |
|
|
|
|
|
|
326 |
|
|
|
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 |
|
|
|
75 |
|
|
|
28 |
|
Basic net income (loss) per share (a¸b) |
|
$ |
(20.68 |
) |
|
$ |
0.73 |
|
|
$ |
2.00 |
|
Diluted net income (loss) per share (a¸c) |
|
$ |
(20.68 |
) |
|
$ |
0.71 |
|
|
$ |
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 |
|
59
5. INCOME TAXES
Below is an analysis of deferred income taxes as of December 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Deferred tax asset: |
|
|
|
|
|
|
|
|
Federal net operating loss carryforwards |
|
$ |
68,432 |
|
|
$ |
58,397 |
|
State net operating loss carryforwards |
|
|
45,939 |
|
|
|
36,345 |
|
Statutory depletion carryforward |
|
|
4,561 |
|
|
|
4,184 |
|
Alternative minimum tax credit carryforward |
|
|
375 |
|
|
|
375 |
|
Asset retirement obligations |
|
|
13,102 |
|
|
|
11,274 |
|
Oil and gas properties |
|
|
58,061 |
|
|
|
|
|
Other |
|
|
2,241 |
|
|
|
3,572 |
|
Valuation allowance |
|
|
(174,062 |
) |
|
|
(36,345 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax asset |
|
|
18,649 |
|
|
|
77,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liability: |
|
|
|
|
|
|
|
|
Oil and gas properties |
|
|
|
|
|
|
(109,530 |
) |
Other |
|
|
(18,649 |
) |
|
|
(462 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liability |
|
|
(18,649 |
) |
|
|
(109,992 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
|
|
|
$ |
(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 Companys federal net operating loss carryforwards will expire in 2013 through
2023. The Companys 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.
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.
60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Income tax expense computed at the statutory
federal income tax rate |
|
|
(35 |
)% |
|
|
35 |
% |
|
|
35 |
% |
Change in valuation allowance |
|
|
27 |
% |
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate |
|
|
(8 |
)% |
|
|
37 |
% |
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
6. OTHER COMPREHENSIVE INCOME
The Companys 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, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands) |
|
Senior Secured Credit Facility (matures
September 25, 2012) |
|
$ |
|
|
|
$ |
|
|
9.75% Senior Notes (due December 2010) net of discount |
|
|
194,420 |
|
|
|
192,012 |
|
Senior Revolving Credit Facility (due 2014) |
|
|
|
|
|
|
200,000 |
|
Callon Entrada Credit Facility non-recourse |
|
|
78,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
|
272,855 |
|
|
|
392,012 |
|
|
Less current portion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion |
|
$ |
272,855 |
|
|
$ |
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 Companys
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.
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 Companys UBOC senior secured credit facility. Callons UBOC senior secured credit facility
was amended to allow for this transaction.
61
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 Callons 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 Entradas 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 Entradas 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.
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.
62
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 Companys subsidiaries guarantee the Companys 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 Callons 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 Companys
senior secured revolving credit facility contains various covenants including restrictions on
additional indebtedness and payment of cash dividends. In addition, Callons 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.
8. DERIVATIVES
The following table summarizes derivative expense for the periods presented (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Amortization of derivative contract premiums |
|
$ |
|
|
|
$ |
|
|
|
$ |
150 |
|
Change in fair value and settlements of ineffective
derivative contracts |
|
|
498 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
498 |
|
|
$ |
|
|
|
$ |
150 |
|
|
|
|
|
|
|
|
|
|
|
63
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.
|
|
|
Level 1 valuations consist of unadjusted quoted prices in active markets for
identical assets and liabilities and have the highest priority. |
|
|
|
|
Level 2 valuations rely on quoted market information for the calculation of
fair market value. |
|
|
|
|
Level 3 valuations are internal estimates and have the lowest priority. |
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):
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
Quoted |
|
|
Significant |
|
|
|
|
|
|
|
|
|
Prices in |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
Active |
|
|
Observable |
|
|
Unobservable |
|
|
Assets |
|
|
|
Markets |
|
|
Inputs |
|
|
Inputs |
|
|
(Liabilities) |
|
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
At Fair Value |
|
Derivative assets |
|
$ |
|
|
|
$ |
|
|
|
$ |
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 managements judgment, reflect the assumptions a marketplace
participant would have used at December 31, 2008 (in thousands):
|
|
|
|
|
|
|
Derivatives |
|
Balance at January 1, 2008 |
|
$ |
(5,205 |
) |
Total gains or losses (realized or unrealized): |
|
|
|
|
Included in earnings |
|
|
|
|
Included in other comprehensive income |
|
|
17,076 |
|
Purchases, issuances and settlements |
|
|
9,909 |
|
|
|
|
|
Balance at December 31, 2008 |
|
$ |
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 Companys financial statements.
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 brokers 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.
65
The Companys 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 years 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 years 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 Companys 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 Companys results of operations and financial condition. The
Companys 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 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 Companys 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 Companys
operations could have on its activities.
66
11. ASSET RETIREMENT OBLIGATIONS
The
following table summarizes the activity for the Companys asset
retirement obligations (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
Asset retirement obligations at beginning of period |
|
$ |
36,837 |
|
|
$ |
41,179 |
|
Accretion expense |
|
|
4,172 |
|
|
|
3,985 |
|
Liabilities incurred |
|
|
2,851 |
|
|
|
6,368 |
|
Liabilities settled |
|
|
(6,586 |
) |
|
|
(19,519 |
) |
Revisions to estimate |
|
|
4,920 |
|
|
|
4,824 |
|
|
|
|
|
|
|
|
Asset retirement obligation at end of period |
|
|
42,194 |
|
|
|
36,837 |
|
Less: current retirement obligations |
|
|
(9,151 |
) |
|
|
(9,810 |
) |
|
|
|
|
|
|
|
Long-term retirement obligations |
|
$ |
33,043 |
|
|
$ |
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 Companys oil and gas properties.
67
12. OIL AND GAS PROPERTIES
The following table discloses certain financial data relating to the Companys oil and gas
activities, all of which are located in the United States.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Capitalized costs incurred: |
|
|
|
|
|
|
|
|
|
|
|
|
Evaluated Properties- |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period balance |
|
$ |
1,349,904 |
|
|
$ |
1,096,907 |
|
|
$ |
937,698 |
|
Property acquisition costs |
|
|
6,126 |
|
|
|
154,193 |
|
|
|
4,053 |
|
Exploration costs |
|
|
2,578 |
|
|
|
35,959 |
|
|
|
73,659 |
|
Development costs |
|
|
223,090 |
|
|
|
62,845 |
|
|
|
81,497 |
|
|
|
|
|
|
|
|
|
|
|
End of period balance |
|
$ |
1,581,698 |
|
|
$ |
1,349,904 |
|
|
$ |
1,096,907 |
|
|
|
|
|
|
|
|
|
|
|
|
Unevaluated Properties (excluded from
amortization)-
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period balance |
|
$ |
70,176 |
|
|
$ |
54,802 |
|
|
$ |
49,065 |
|
Additions |
|
|
6,409 |
|
|
|
21,525 |
|
|
|
19,103 |
|
Capitalized interest |
|
|
6,496 |
|
|
|
7,152 |
|
|
|
6,477 |
|
Transfers to evaluated |
|
|
(50,252 |
) |
|
|
(13,303 |
) |
|
|
(19,843 |
) |
|
|
|
|
|
|
|
|
|
|
End of period balance |
|
$ |
32,829 |
|
|
$ |
70,176 |
|
|
$ |
54,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated depreciation, depletion
and amortization-
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period balance |
|
$ |
738,374 |
|
|
$ |
604,682 |
|
|
$ |
539,399 |
|
Ceiling test and provision charged to expense |
|
|
549,552 |
|
|
|
72,762 |
|
|
|
65,283 |
|
Sale of mineral interests |
|
|
167,349 |
|
|
|
60,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period balance |
|
$ |
1,455,275 |
|
|
$ |
738,374 |
|
|
$ |
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 the volatility of oil and gas prices, it is reasonably possible that the Companys
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 employees 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
68
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. This Plan qualified as a broadly based plan under the
provisions of the New York Stock Exchanges 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
69
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
Companys 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 Companys 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
Companys 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.
15. ENTRADA
On April 18, 2007, the Company completed an acquisition of BPs 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 Companys UBOC
senior secured credit facility was amended to allow for this transaction.
70
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 Entradas 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 Callons 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.
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.
71
16. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Companys proved oil and gas reserves at December 31, 2008, 2007 and 2006 have been estimated
by Huddleston & Co., Inc., the Companys 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 Companys 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:
72
Reserve Quantities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
Proved developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (MBbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
24,531 |
|
|
|
13,265 |
|
|
|
18,428 |
|
Revisions to previous estimates |
|
|
(9,026 |
) |
|
|
(1,152 |
) |
|
|
(3,733 |
) |
Change in ownership |
|
|
|
|
|
|
144 |
|
|
|
|
|
Purchase of reserves in place |
|
|
|
|
|
|
13,658 |
|
|
|
|
|
Sale of reserves in place |
|
|
(8,536 |
) |
|
|
(356 |
) |
|
|
|
|
Extensions and discoveries |
|
|
|
|
|
|
35 |
|
|
|
204 |
|
Production |
|
|
(942 |
) |
|
|
(1,063 |
) |
|
|
(1,634 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
|
6,027 |
|
|
|
24,531 |
|
|
|
13,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf): |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
116,454 |
|
|
|
66,037 |
|
|
|
78,021 |
|
Revisions to previous estimates |
|
|
(49,526 |
) |
|
|
(3,022 |
) |
|
|
(15,557 |
) |
Change in ownership |
|
|
|
|
|
|
192 |
|
|
|
|
|
Purchase of reserves in place |
|
|
|
|
|
|
68,068 |
|
|
|
|
|
Sale of reserves in place |
|
|
(42,542 |
) |
|
|
(3,690 |
) |
|
|
|
|
Extensions and discoveries |
|
|
105 |
|
|
|
1,209 |
|
|
|
14,550 |
|
Production |
|
|
(5,840 |
) |
|
|
(12,340 |
) |
|
|
(10,977 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
|
18,651 |
|
|
|
116,454 |
|
|
|
66,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (MBbls): |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
4,723 |
|
|
|
5,159 |
|
|
|
7,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
|
4,663 |
|
|
|
4,723 |
|
|
|
5,159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MMcf): |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of period |
|
|
22,340 |
|
|
|
36,750 |
|
|
|
30,982 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
|
13,463 |
|
|
|
22,340 |
|
|
|
36,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
Standardized Measure
The following tables present the Companys 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
Future cash inflows |
|
$ |
340,485 |
|
|
$ |
3,113,759 |
|
|
$ |
1,101,182 |
|
Future costs -
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(192,819 |
) |
|
|
(390,669 |
) |
|
|
(243,740 |
) |
Development and net abandonment |
|
|
(34,111 |
) |
|
|
(405,186 |
) |
|
|
(81,700 |
) |
|
|
|
|
|
|
|
|
|
|
Future net inflows before income taxes |
|
|
113,555 |
|
|
|
2,317,904 |
|
|
|
775,742 |
|
Future income taxes |
|
|
(565 |
) |
|
|
(699,967 |
) |
|
|
(119,685 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
112,990 |
|
|
|
1,617,937 |
|
|
|
656,057 |
|
10% discount factor |
|
|
(26,685 |
) |
|
|
(483,948 |
) |
|
|
(185,266 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows |
|
$ |
86,305 |
|
|
$ |
1,133,989 |
|
|
$ |
470,791 |
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(In thousands) |
|
Standardized measure beginning of period |
|
$ |
1,133,989 |
|
|
$ |
470,791 |
|
|
$ |
837,552 |
|
Sales and transfers, net of production costs |
|
|
(122,104 |
) |
|
|
(142,973 |
) |
|
|
(153,387 |
) |
Net change in sales and transfer prices,
net of production costs |
|
|
(111,140 |
) |
|
|
411,525 |
|
|
|
(347,193 |
) |
Net change due to purchases and sales of in
place reserves |
|
|
(558,652 |
) |
|
|
795,595 |
|
|
|
|
|
Extensions, discoveries, and improved
recovery, net of future production and
development costs incurred |
|
|
162,566 |
|
|
|
(201,750 |
) |
|
|
122,862 |
|
Changes in future development cost |
|
|
33,652 |
|
|
|
|
|
|
|
|
|
Revisions of quantity estimates |
|
|
(786,001 |
) |
|
|
(66,735 |
) |
|
|
(155,342 |
) |
Accretion of discount |
|
|
159,147 |
|
|
|
53,474 |
|
|
|
108,871 |
|
Net change in income taxes |
|
|
457,483 |
|
|
|
(393,530 |
) |
|
|
187,209 |
|
Changes in production rates, timing and other |
|
|
(282,635 |
) |
|
|
207,592 |
|
|
|
(129,781 |
) |
|
|
|
|
|
|
|
|
|
|
Aggregate change |
|
|
(1,047,684 |
) |
|
|
663,198 |
|
|
|
(366,761 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure end of period |
|
$ |
86,305 |
|
|
$ |
1,133,989 |
|
|
$ |
470,791 |
|
|
|
|
|
|
|
|
|
|
|
At year-end 2006, a downward revision was made by the Companys independent petroleum engineers to
Entradas 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.
74
17. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
(In thousands, except per share data) |
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
44,960 |
|
|
$ |
48,029 |
|
|
$ |
32,783 |
|
|
$ |
15,540 |
|
Income (loss) from operations |
|
|
21,069 |
|
|
|
24,046 |
|
|
|
13,640 |
|
|
|
(500,438 |
) (a) |
Net income (loss) |
|
|
7,632 |
|
|
|
5,153 |
|
|
|
5,856 |
|
|
|
(457,534 |
) (a) |
Net income (loss) per common share-basic |
|
$ |
0.37 |
|
|
$ |
0.25 |
|
|
$ |
0.27 |
|
|
$ |
(21.19 |
) (a) |
Net income (loss) per common share-diluted |
|
|
0.35 |
|
|
|
0.23 |
|
|
|
0.27 |
|
|
|
(21.19 |
) (a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
(In thousands, except per share data) |
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
45,484 |
|
|
$ |
43,474 |
|
|
$ |
37,869 |
|
|
$ |
43,941 |
|
Income from operations |
|
|
13,705 |
|
|
|
12,828 |
|
|
|
13,090 |
|
|
|
16,727 |
|
Net income |
|
|
5,803 |
|
|
|
2,581 |
|
|
|
2,268 |
|
|
|
4,542 |
|
Net income per common share-basic |
|
$ |
0.28 |
|
|
$ |
0.12 |
|
|
$ |
0.11 |
|
|
$ |
0.22 |
|
Net income per common share-diluted |
|
|
0.27 |
|
|
|
0.12 |
|
|
|
0.11 |
|
|
|
0.21 |
|
|
|
|
(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 Companys 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. 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 9.A CONTROLS AND PROCEDURES
The term disclosure controls and procedures is defined in Rules 13a-15(e) and 15d-15(e) of the
Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and
procedures of a company that are designed to ensure that information required to be disclosed by a
company in the reports that it files or submits under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified by the Securities and Exchange
Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, 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.
75
Managements 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 Companys internal control over financial reporting as of December 31, 2008.
76
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
Callon Petroleum Company
We have audited Callon Petroleum Companys 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 Companys 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 Managements Report on Internal Control over Financial
Reporting. Our responsibility is to express an opinion on the Companys 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 companys 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
companys 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 companys 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, 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 |
|
|
77
ITEM 9.B OTHER INFORMATION
We have disclosed all information required to be disclosed in a current report on Form 8-K during
the fourth quarter of the year ended December 31, 2008 in previously filed reports on Form 8-K.
78
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 Companys chief executive officer,
chief financial officer and chief accounting officer. The full text of such code of ethics has
been posted on the Companys 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.
79
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.
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 47 through 76.
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.
80
(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 Companys 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
Companys 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 Companys 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 Companys Registration Statement on Form S-4, filed August 4, 1994, Reg.
No. 33-82408) |
|
|
4.2 |
|
Rights Agreement between Callon Petroleum Company and American Stock Transfer
& Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from
Exhibit 99.1 of the Companys 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 Companys $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 Companys Annual Report on Form 10-K for the year ended
December 31, 2003, File No. 001-14039) |
|
|
4.4 |
|
Indenture for the Companys 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 Companys 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 Companys
Registration Statement on Form 8-B filed October 3, 1994) |
81
|
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
Companys 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 Companys
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 Companys 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 Companys 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
Companys 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 Companys Annual Report on Form 10-K for the year ended
December 31, 2001, File No. 001-14039) |
|
|
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 Companys
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 Companys 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 Companys 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 Companys 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
Companys 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 Companys Report on Form 8-K filed on April 9, 2008) |
82
|
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 Companys 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 Companys 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 Companys 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
Companys 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 Companys 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
California, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1
of the Companys 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 Companys 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 Companys
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
Companys Report on Form 8-K filed on January 5, 2009). |
|
|
10.23 |
|
Amendment No. 1 to the Callon Petroleum Company 2002 Stock
Incentive Plan (incorporated by reference from Exhibit 10.2 of the
Companys Report on Form 8-K filed on January 5, 2009). |
|
|
10.24 |
|
Callon Petroleum Company Amended and Restated 2006 Stock Incentive
Plan (incorporated by reference from Exhibit 10.3 of the Companys
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 Companys 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 Companys Registration Statement on Form 8-B filed October 3, 1994) |
|
22. |
|
Published report regarding matters submitted to vote of security holders* |
|
|
23. |
|
Consents of experts and counsel |
83
|
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) |
|
|
|
|
* |
|
Inapplicable to this filing. |
84
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.
CALLON PETROLEUM COMPANY
|
|
|
|
|
Date: March 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
|
|
/s/Rodger W. Smith
Rodger W. Smith (principal accounting officer)
|
|
|
|
|
|
|
|
Date: March 19, 2009
|
|
/s/Richard L. Flury
Richard Flury (director)
|
|
|
|
|
|
|
|
Date: March 19, 2009
|
|
/s/John C. Wallace
John C. Wallace (director)
|
|
|
85
|
|
|
|
|
|
|
|
|
|
Date: March 19, 2009
|
|
/s/Richard O. Wilson
Richard O. Wilson (director)
|
|
|
|
|
|
|
|
Date: March 19, 2009
|
|
/s/Larry D. McVay
Larry McVay (director)
|
|
|
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
|
CALLON PETROLEUM COMPANY |
|
|
|
|
|
|
|
Date: March 19, 2009
|
|
By: /s/B. F. Weatherly
B. F. Weatherly, Executive Vice-President and
|
|
|
|
|
Chief Financial Officer |
|
|
86