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| CPE > SEC Filings for CPE > Form 10-K on 20-Mar-2009 | All Recent SEC Filings |
20-Mar-2009
Annual Report
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.
Abandonment of the Entrada Project
In late November 2008, we and our joint working interest owner, CIECO, decided
to abandon the Entrada project. Under the terms of our agreements with CIECO,
Callon Entrada is responsible for its share of the costs to plug and abandon the
Entrada project, which we estimate to be $46 million, $23 million net to Callon
Entrada. In addition, prior to abandonment of the project, CIECO failed to fund
two loan requests totaling $40 million under our non-recourse credit agreement
with them. CIECO also failed to fund its working interest share of a settlement
payment to terminate a drilling contract for the Entrada project. Callon has
paid its share of the settlement payment.
We continue to discuss with CIECO its failure to fund $40 million in loan
requests and its share of a settlement payment to terminate a drilling contract.
Because these discussions are in the early stages, no assurances can be made
regarding the outcome of these discussions. We do not believe that we have
waived any of our rights under the agreements with CIECO regarding the loan
requests or the drilling contract settlement.
The CIECO Non-Recourse Credit Agreement
Principal and interest outstanding under the credit agreement with CIECO is
non-recourse to Callon Entrada and is not guaranteed by Callon Petroleum or any
of its subsidiaries. The principal and interest under the non-recourse credit
agreement is secured by a lien on substantially all of Callon Entrada's assets.
Included in these assets are the Entrada leases and equipment purchased for the
development project. At December 31, 2008 there was no value included on the
balance sheet for these assets.
CIECO has not declared Callon Entrada to be in default under the non-recourse
credit agreement. The lenders under our senior secured revolving credit facility
have amended the Second Amended and Restated Credit Agreement dated September
25, 2008 to state that a default under the Callon Entrada non-recourse credit
facility will not be a default under their facility. In addition, this amendment
eliminates a possible cross default with regard to our $200 million senior notes
due 2010. Accordingly, we do not believe that a default under the CIECO
agreement will have a material negative impact on our financial position,
results of operations and cash flows. See Note 18 to the Consolidated Financial
Statements.
Other Events in 2008
In addition, the following events impacted our business in 2008:
Asset Impairments- As required under the full-cost accounting rules of the SEC,
we assessed the recoverability of our oil and gas properties. Due to the
depressed economic environment, coupled with a severe decrease in commodity
prices during the fourth quarter of 2008 and the abandonment of the Entrada
project, we determined that our oil and gas properties were impaired. For 2008,
total pre-tax (non-cash) asset impairment charges were $485.5 million. See
Critical Accounting Policies - Impairment of Proved Oil and Gas Properties and
Other Investments, and Impairment of Unproved Oil and Gas Properties.
Deferred Tax Asset Valuation Allowance - As a result of incurring losses on an
aggregate basis for the three-year period ended December 31, 2008, we
established a full valuation allowance in the amount of $128 million on the tax
benefit associated with the federal and state net operating loss carryforwards
as of December 31, 2008. See Critical Accounting Policies - Income Taxes.
Hurricanes Gustav and Ike - In August and September, Hurricanes Gustav and Ike
moved through the Gulf of Mexico. Inspection of our facilities and equipment
indicated there was no major damage from the hurricanes, although damage to
third-party processing and pipeline facilities has slowed reinstatement of
production from our Gulf of Mexico assets. Temporary shut-ins of production
reduced volumes on average 12.8 million cubic feet of natural gas equivalent
("MMcfe") per day during third quarter 2008 and 18.0 MMcfe per day during fourth
quarter 2008.
2009 OUTLOOK
We expect the mid-point of our 2009 crude oil and gas production to be slightly
above our 2008 results. The expected year-over-year change in production is
impacted by several factors including:
• 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 Budget-Due to the uncertain economic and commodity price environment, we
have designed a flexible capital spending program that will be responsive to
conditions that develop during 2009. Our preliminary base capital program,
including plugging and abandonment, for 2009 is $75 million, which is relatively
flat with 2008 budget, excluding the Entrada project, of $71 million. However,
depending on commodity prices and other economic conditions we experience in
2009, this base capital program may be adjusted up or down.
We expect that the 2009 budget will be funded primarily from cash flows from
operations, cash on hand, and borrowings under our senior secured revolving
credit facility and/or other financing. We will evaluate the level of capital
spending throughout the year based on drilling results, commodity prices, cash
flows from operations and property acquisitions and divestitures.
Inflation has not had a material impact on us and is not expected to have a
material impact on us in the future.
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:
• 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:
• 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.
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.
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 entity's financial position, financial performance, and cash flows.
The new disclosure standard is effective for financial statements issued for
fiscal years and interim periods beginning after November 15, 2008, with early
application encouraged. The Statement encourages, but does not require,
comparative disclosures for earlier periods at initial adoption. We are
currently evaluating the impact that SFAS 161 will have on its financial
statements.
In December 2008 the SEC unanimously approved amendments to revise its oil and
. . .
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