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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
Commission File Number 0-25192
CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)
Delaware 64-0844345
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
200 North Canal Street (601) 442-1601
Natchez, Mississippi 39120 (Registrant's telephone number
(Address of Principal Executive including area code)
Offices)(Zip Code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Common Stock, Par Value $.01 Per Share
Convertible Exchangeable Preferred Stock,
Series A, Par Value $.01 Per Share
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [ X ]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was approximately $76,254,647, as of March 10, 1998 (based on the
last reported sale price of such stock on the Nasdaq National Market System).
As of March 10, 1998, there were 8,022,784 shares of the Registrant's Common
Stock, par value $.01 per share, outstanding.
Document incorporated by reference: Proxy Statement of Callon Petroleum
Company relating to the Annual Meeting of Stockholders to be held on May 28,
1998, which is incorporated into Part III of this Form 10-K.
This report includes "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934. All statements other than state-
ments of historical fact included in this report regarding the Company's
financial position, estimated quantities and net present values of reserves,
business strategy, plans and objectives for future operations and covenant
compliance, are forward-looking statements. Although the Company believes that
the assumptions upon which such forward-looking statements are based are
reasonable, it can give no assurances that such assumptions will prove to have
been correct. Important factors that could cause actual results to differ
materially from the Company's expectations ("Cautionary Statements") are
disclosed below and elsewhere in this report. All subsequent written and oral
forward-looking statements attributable to the Company or persons acting on
its behalf are expressly qualified by the Cautionary Statements.
PART I.
BUSINESS OF THE COMPANY
ITEM 1. BUSINESS
Overview
Callon Petroleum Company (the "Company") has been engaged in the acquisition,
development and exploration of oil and gas properties since 1950. The
Company's properties are geographically concentrated offshore in the Gulf of
Mexico and onshore in Louisiana and Alabama. The Company was formed under the
laws of the state of Delaware in 1994 through the consolidation of a publicly
traded limited partnership, a joint venture with a consortium of European
institutional investors and an independent energy company owned by certain
members of current management (the "Consolidation"). As used herein, the
"Company" refers to Callon Petroleum Company and its predecessors and
subsidiaries unless the context requires otherwise.
Over the past eight years, the Company has increased its reserves through the
acquisition of producing properties that are geologically complex, have (or are
analogous to fields with) an established production history from stacked pay
zones and are candidates for exploitation. The Company focuses on reducing
operating costs and implementing production enhancements through the applica-
tion of technologically advanced production and recompletion techniques.
Over the past three years, the Company has also placed emphasis on the
acquisition of acreage with exploration and development drilling opportunities.
The Company acquired an extensive infrastructure of production platforms,
gathering systems and pipelines to minimize development expenditures of these
drilling opportunities. The Company also joined with Murphy Exploration and
Production, Inc., ("Murphy") to explore 32 federal offshore blocks acquired in
the Gulf of Mexico. The Company owns either a 20% or 25% working interest in
each of the blocks. The major focus of the Company's operations over the next
two years is expected to be the exploration for and development of oil and gas
properties, primarily in the Gulf of Mexico.
Business Strategy
The Company's objective is to enhance shareholder value through sustained
growth in its reserve base, production levels, and resulting cash flow from
operations. In furtherance of this strategy, the Company (i) acquires
properties with exploration and development potential; (ii) utilizes advanced
technology including proprietary high resolution, shallow focus seismic
technology and the latest available 3-D seismic surveys; (iii) balances lower
risk, shallow target exploration in the Shallow Miocene Trend and similar
geologic areas with higher risk, large target exploration; and (iv) acquires
properties which provide it with the ability to control or significantly
influence operations.
Exploration and Development Activities
The Company currently conducts its exploration and development activities in
three areas, the Shallow Miocene Trend, the Main Pass Block 32/35 Area and in
the Gulf of Mexico in a joint venture with Murphy Oil Corporation ("Murphy").
The Shallow Miocene Trend. The Company conducts exploration and development
activities in the Shallow Miocene Trend in the Gulf of Mexico, where it seeks
oil and gas deposits located near existing production facilities at true
vertical depths of between 1,800 and 6,000 feet. Relatively low exploration
and development costs and high initial production rates characterize successful
wells in this area. The Company has successfully used high resolution, shallow
focused seismic techniques to explore for and develop these shallow gas
deposits. This seismic technique utilizes high-definition two dimensional
seismic lines shot in a tight grid, with spacing as close as 50 meters. The
Company has developed a proprietary method of processing and interpreting this
data which the Company believes gives it a competitive advantage over other
companies exploring in the Shallow Miocene Trend. During 1996, the Company
completed four proprietary high-resolution seismic surveys over an eight block
area contiguous to Chandeleur Block 40 ("CB 40"). Based on these surveys,
between October 1996 and July 1997, the Company drilled 2 gross (1.5 net)
successful development wells and 2 gross (2.0 net) successful exploratory wells
and one unsuccessful (0.7 net) development well in this area for a drilling
success rate of 80%. Primarily as a result of these wells, the Company's
average daily production for 1997 increased to 43.5 MMcfe/d, a 63% increase
over the same period in 1996. The Company intends to use this high-resolution
seismic technique to confirm 3-D seismic surveys of shallow gas prospects on
its Brazos Blocks 582 and 610 in the Gulf of Mexico. For 1998, the Company's
budget includes drilling 2 gross (1.4 net) exploration wells in the Shallow
Miocene Trend and the Brazos Blocks 582 and 610, for a total net dry hole cost
of $3.9 million, excluding completion and development costs.
Main Pass 32/35 Area. In the Main Pass Block 32/35 Area, the Company owns and
operates 14 wells in a field located in shallow Louisiana-state waters which
produce from true vertical depths of between 6,000 and 9,000 feet. In November
1996, the Company completed a 36 square-mile 3-D seismic survey covering its
Main Pass Block 35 field and adjoining acreage. Based upon this data, the
Company farmed-in and successfully drilled a development well to a total depth
of 10,900 feet in August 1997, which added net proved reserves of 7.9 Bcfe as
of December 31, 1997. The Company also acquired additional acreage in this
area and entered into a joint venture agreement with Burlington Resources Oil &
Gas Company to drill eight prospects identified by the 3-D seismic survey at
true vertical depths of between 13,000 and 15,000 feet. The first of these
prospects drilled was Parodi. The initial well, the S/L 15543#1, on the Parodi
prospect was drilled to a total depth of 15,305 and encountered 35 feet of net
gas pay in the Lower Big Hum sand between 13,920 feet and 13,970 feet measured
depth. Additional zones will be tested when the well is completed in late
March 1998. Initial production is currently scheduled for June 1998 after
flowlines are laid to the nearby Company operated production facilities located
on Main Pass Block 32. Reserves for the Parodi discovery were not included in
the Company's proved reserves as of December 31, 1997. The Company will operate
and has retained an approximate 42.4% working interest in the eight prospects.
For 1998, the Company's budget includes drilling 2 gross (1.4 net) exploration
wells and 1 gross (0.4 net) development wells in the Main Pass 32/35 Area for
a total net dry hole cost of $5.0 million, excluding completion and development
costs.
The Murphy Joint Venture. The Company has also entered into an agreement
with Murphy to jointly explore 32 blocks which were acquired in the Gulf of
Mexico, primarily in shallow waters seeking deposits as deep as a true vertical
depth of 17,500 feet. In September 1997, the Company and Murphy drilled a
successful exploration well, the #A-1 well, on Eugene Island Block 335 to a
vertical depth of 6,094 feet which encountered 300 feet of net oil and gas pay
in three intervals. Two delineation wells were also drilled. The three wells
encountered a total of six pay sands which, with fault separations, form eight
potentially productive reservoirs. Initial production is not expected until
the first quarter of 1999 and the Company's year-end reserve report did not
include reserves for the discoveries, pending production tests.
The Company and Murphy have generated an additional 15 prospects in the shallow
waters of the Gulf of Mexico, to explore for oil and gas deposits at true
vertical depths of between 8,000 and 17,500 feet. The Company owns either
a 20% or 25% working interest in each of these prospects. The Company's budget
for 1998 includes the drilling of 7 gross (1.6 net) exploration wells on seven
of these prospects, for a total net dry hole cost of $12 million, excluding
completion and development costs.
The Company and Murphy have also acquired acreage and generated five prospects
in the deep waters of the Gulf of Mexico. The Company plans to drill an
exploration well with Murphy in 900 feet of water during the third quarter of
1998. Estimated dry hole costs to drill this well are $2.2 million, net to
Callon's 25% working interest (the Company may sell down its interest in this
prospect). The Company's 1998 budget also includes the drilling of a second
deep water exploratory well with estimated dry hole costs of $2.5 million, net
to the Company's 10% working interest.
In total, the Company's current capital budget through fiscal 1998 of $75
million contemplates the drilling of 1 gross (0.4 net) development well and 13
gross (4.8 net) exploratory wells, at an estimated net cost to the Company to
drill of $25.6 million and $34.0 million in completion and development costs.
These drilling operations will be financed through cash flows from operations,
the net proceeds of the November 1997 public stock offering, the proceeds of
property sales and borrowings under the Company's credit facility with a
commercial bank ("Credit Facility"). The Company's Credit Facility has an
available borrowing base of $35 million as of December 31, 1997.
Recent Developments
During 1997, the Company focused its acquisition efforts in the Shallow
Miocene Trend in the Mobile Block 864 Area located offshore Alabama. During
the first nine months of 1997, Callon consummated three acquisitions in this
area and in October 1997 agreed to acquire properties from Chevron U.S.A. Inc.
In October 1997, the Company also entered into a letter of intent to sell
properties in its Black Bay Complex.
Recent Acquisitions. In June 1997, the Company closed an $11.8 million acquisi-
tion from Elf Exploration, Inc. (the "Elf Acquisition") for their interest in
three adjoining blocks located in the Shallow Miocene Trend in federal waters
in Mobile Block 864 Area and in August 1997, for $7.5 million Callon acquired
from Koch Exploration Company (the "Koch Acquisition") an interest in two wells
producing from the Shallow Miocene Trend adjoining the blocks acquired in the
Elf Acquisition. Additionally, in September 1997, at a purchase price of $10.6
million the Company acquired from Santa Fe Energy Resources, Inc. additional
interests in the properties acquired in the Koch Acquisition, along with an
interest in a well in a nearby block. In October 1997, the Company agreed to
purchase 61% of Chevron U.S.A. Inc.'s interest in the Mobile Block 864 Area for
$18.8 million, effective July 1, 1997. As a result of these acquisitions, the
Company acquired an average 55.4% working interest in seven blocks, a 53.3%
working interest in the Mobile Block 864 Area unit and the unit production
facilities, a 66.7% working interest in two producing wells and a 50% working
interest in another well. The Company became the operator of the unit and
related production facilities. In total, the Company spent $48.7 million to
acquire properties in the Mobile Block 864 Area which as of December 31, 1997,
had estimated net proved reserves of 50.8 Bcfe. The Company's average net daily
production during December 1997 from this area was 17.6 MMcf per day.
The Company has identified two development and one exploration prospects in
this area. The Company plans to conduct an extensive shallow focus, high-
resolution seismic survey over the area to refine its development plans and
to explore for additional prospects. Production from the area is currently
limited by the capacity of the production facilities, which the Company intends
to increase during 1998.
Sale of Black Bay Complex. The Company has entered into a letter of intent to
sell its interest in the Black Bay Complex. The Company is currently negotiat-
ing with the buyer to finalize the transaction.
Risk Management
Volatility of Oil and Gas Prices; Marketability of Production. The Company's
revenues, profitability and future growth and the carrying value of its oil and
gas properties are substantially dependent on prevailing prices of oil and gas.
The Company's ability to maintain or increase its borrowing capacity and to
obtain additional capital on attractive terms is also substantially dependent
upon oil and gas prices. Prices for oil and gas are subject to large
fluctuations in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
beyond the control of the Company. These factors include weather conditions
in the United States, the condition of the United States economy, the action
of the Organization of Petroleum Exporting Countries, governmental regulation,
political stability in the Middle East and elsewhere, the foreign supply of
oil and gas, the price of foreign imports and the availability of alternate
fuel sources. Any substantial and extended decline in the price of oil or gas
would have an adverse effect on the Company's carrying value of its proved
reserves, borrowing capacity, revenues, profitability and cash flows from
operations.
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the
market for oil and gas producing properties, as buyers and sellers have
difficulty agreeing on such value. Price volatility also makes it difficult
to budget for and project the return on acquisitions and development and
exploitation projects.
In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand
all could adversely affect the Company's ability to produce and market its oil
and natural gas. If market factors were to change dramatically, the financial
impact on the Company could be substantial. The availability of markets and
the volatility of product prices are beyond the control of the Company and
represent a significant risk.
Risks of Exploration and Development
The major focus of the Company's operations over the next two years is expected
to be the exploration for and development of oil and gas properties, primarily
in federal and state waters in the Gulf of Mexico. Exploration and drilling
activities are generally considered to be of a higher risk than acquisitions
of producing oil and gas properties. Additionally, certain of the Company's
wells seek to discover deposits of gas at deep formations and have more risk
than wells seeking to develop hydrocarbons from shallow formations. No
assurances can be made that the Company will discover oil and gas in
commercial quantities in its exploration and development operations.
Expenditure of a material amount of funds in exploration for oil and gas
without discovery of commercial quantities of reserves will have a material
adverse effect upon the Company.
Operating Hazards, Offshore Operations and Uninsured Risks. Callon's
operations are subject to risks inherent in the oil and gas industry, such as
blowouts, cratering, explosions, uncontrollable flows of oil, gas or well
fluids, fires, pollution and other environmental risks. These risks could
result in substantial losses to the Company due to injury and loss of life,
severe damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. Moreover, a sub-
stantial portion of the Company's operations are offshore and therefore are
subject to a variety of operating risks peculiar to the marine environment,
such as hurricanes or other adverse weather conditions, to more extensive
governmental regulation, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to
interruption or termination of operations by governmental authorities based
on environmental or other considerations.
The Company maintains insurance of various types to cover its operations,
including maritime employer's liability and comprehensive general liability.
Amounts in excess of base coverages are provided by primary and excess
umbrella liability policies with maximum limits of $50 million. In addition,
the Company maintains operator's extra expense coverage, which provides
coverage for the control of wells drilled and/or producing and redrilling
expenses and pollution coverage for wells out of control.
No assurances can be given that Callon will be able to maintain adequate
insurance in the future at rates the Company considers reasonable. The
occurrence of a significant event not fully insured or indemnified against
could materially and adversely affect the Company's financial condition and
results of operations.
Estimates of Oil and Gas Reserves
This document contains estimates of oil and gas reserves, and the future net
cash flows attributable to those reserves, prepared by Huddleston & Co., Inc.,
independent petroleum and geological engineers (the "Reserve Engineers").
There are numerous uncertainties inherent in estimating quantities of proved
reserves and cash flows attributable to such reserves, including factors beyond
the control of the Company and 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 an estimate of
quantities of reserves, or of cash flows attributable to such reserves, is a
function of the available data, assumptions regarding future oil and gas prices
and expenditures for future development and exploitation activities, and of
engineering and geological interpretation and judgment. Additionally, reserves
and future cash flows may be subject to material downward or upward revisions,
based upon production history, development and exploitation activities and
prices of oil and gas. Actual future production, revenue, taxes, development
expenditures, operating expenses, quantities of recoverable reserves and the
value of cash flows from such reserves may vary significantly from the
assumptions and estimates set forth herein. In addition, reserve engineers
may make different estimates of reserves and cash flows based on the same
available data. In calculating reserves on a Mcfe basis, oil was converted to
gas equivalent at the ratio of six Mcf of gas to one Bbl of oil. While this
ratio approximates the energy equivalency of gas to oil on a Btu basis, it may
not represent the relative prices received by the Company on the sale of its
oil and gas production.
The estimated quantities of proved reserves and the discounted present value of
future net cash flows attributable to estimated proved reserves set forth in
this document were prepared by the Reserve Engineers in accordance with the
rules of the Securities and Exchange Commission (the "Commission"), and are not
intended to represent the fair market value of such reserves.
Ability to Replace Reserves
The Company's future success depends upon its ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable.
As is generally the case in the Gulf Coast region, many of the Company's
producing properties are characterized by a high initial production rate,
followed by a steep decline in production. As a result, the Company must
locate and develop or acquire new oil and gas reserves to replace those
being depleted by production. Without successful exploration or acquisition
activities, the Company's reserves and revenues will decline rapidly. No
assurances can be given that the Company will be able to find and develop or
acquire additional reserves at an acceptable cost.
The exploration for oil and gas requires the expenditure of substantial amounts
of capital, and there can be no assurances that commercial quantities of oil
or gas will be discovered as a result of such activities. The Company's
current capital budget includes drilling 1 gross (0.4 net) development wells
and 13 gross (4.8 net) exploratory wells through fiscal 1998. The estimated
cost, net to the Company, to drill and complete these wells is approximately
$59.6 million with dry hole costs of approximately $25.6 million. The drilling
of several unsuccessful wells could have a material adverse effect on the
Company. In addition, the successful acquisition of producing properties
requires an assessment of recoverable reserves, future oil and gas prices and
operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact and their accuracy
inherently uncertain. In addition, no assurances can be given that the
Company's exploitation and development activities will result in any increases
in reserves. The Company's operations may be curtailed, delayed or canceled
as a result of lack of adequate capital and other factors, such as title
problems, weather, compliance with governmental regulations or price controls,
mechanical difficulties or shortages or delays in the delivery of equipment.
In addition, the costs of exploration and development may materially exceed
initial estimates.
Shortages of Rigs, Equipment, Supplies and Personnel
There is a general shortage of drilling rigs, equipment and supplies which the
Company believes may intensify. The costs and delivery times of rigs, equipment
and supplies are substantially greater than in prior periods and are currently
escalating. Shortages of drilling rigs, equipment or supplies could delay and
adversely affect the Company's exploration and development operations, which
could have a material adverse effect on its financial condition and results of
operation.
The demand for, and wage rates of, qualified rig crews have begun to rise in
the drilling industry in response to the increasing number of active rigs in
service. Such shortages have in the past occurred in the industry in times of
increasing demand for drilling services. If the number of active drilling rigs
continues to increase, the oil and gas industry may experience shortages of
qualified personnel to operate drilling rigs, which could delay the Company's
drilling operations and adversely effect the Company's financial condition and
results of operations.
Substantial Capital Requirements
The Company makes, and will continue to make, substantial capital expenditures
for the exploitation, exploration, acquisition and production of oil and gas
reserves. Historically, the Company has financed these expenditures primarily
with cash generated by operations, proceeds from bank borrowings and issuance
of debt and equity securities. The Company's total capital expenditure budget
for 1998 is approximately $75 million, and could be reduced depending on the
success of the Company's drilling activities. The Company makes unsolicited
offers for the acquisition of oil and gas properties in the normal course of
business. In the event that any such offers are accepted, the amount or
composition of the Company's capital expenditure budget could be revised
significantly.
If revenues or the Company's borrowing base decrease as a result of lower oil
and gas prices, operating difficulties or declines in reserves, the Company
may have limited ability to expend the capital necessary to undertake or
complete future drilling programs. There can be no assurance that additional
debt or equity financing or cash generated by operations will be available to
meet these requirements.
Hedging of Production
Part of the Company's business strategy is to reduce its exposure to the
volatility of oil and gas prices by hedging a portion of its production. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations ? Liquidity and Capital Resources." In a typical hedge transaction,
the Company will have the right to receive from the counterparts 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, the Company is required to pay the counterparts
this difference multiplied by the quantity hedged. The Company is required to
pay the difference between the floating price and the fixed price (when the
floating price exceeds the fixed price) regardless of whether the Company has
sufficient production to cover the quantities specified in the hedge. Signifi-
cant reductions in production at times when the floating price exceeds the
fixed price could require the Company to make payments under the hedge agree-
ments even though such payments are not offset by sales of production.
Hedging will also prevent the Company from receiving the full advantage of
increases in oil or gas prices above the fixed amount specified in the hedge.
As of December 31, 1997, the Company has hedged approximately 24% of its
estimated natural gas production from January 1998 through September 1998 at
an average floor price of $2.24 per MMBtu (NYMEX) and an average ceiling price
of $2.89 per MMBtu (NYMEX).
Competition
The Company operates in the highly competitive areas of oil and gas explora-
tion, development and production. The availability of funds and information
relating to a property, the standards established by the Company for the
minimum projected return on investment, the availability of alternate fuel
sources and the intermediate transportation of gas are factors which affect
the Company's ability to compete in the marketplace. The Company's competitors
include major integrated oil companies, substantial independent energy
companies, affiliates of major interstate and intrastate pipelines and national
and local gas gatherers, many of which possess greater financial and other
resources than the Company.
Environmental and Other Regulations
The Company's operations are subject to numerous laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the types,
quantities and concentration of various substances that can be released into
the environment in connection with drilling and production activities, limit
or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, require remedial measures to mitigate
pollution from former operations, such as plugging abandoned wells, and impose
substantial liabilities for pollution resulting from the Company's operations.
Moreover, the recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. The enactment of stricter
legislation or the adoption of stricter regulation could have a significant
impact on the operating costs of the Company, as well as on the oil and gas
industry in general.
The Company's operations could result in liability for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation
and clean-up costs and other environmental damages. Moreover, the Company
could be liable for environmental damages caused by previous property owners.
As a result, substantial liabilities to third parties or governmental entities
may be incurred; the payment of which could have a material adverse effect on
the Company's financial condition and results of operations. The Company main-
tains insurance coverage for its operations, including limited coverage for
sudden and accidental environmental damages, but does not believe that
insurance coverage for environmental damages that occur over time is
available at a reasonable cost. Moreover, the Company does 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, the Company may be subject to liability or may lose the privilege
to continue exploration or production activities upon substantial portions
of its properties in the event of certain environmental damages.
The Oil Pollution Act of 1990 imposes a variety of regulations on "responsible
parties" related to the prevention of oil spills. The implementation of new,
or the modification of existing, environmental laws or regulations, including
regulations promulgated pursuant to the Oil Pollution Act of 1990, could have
a material adverse impact on the Company.
Markets
Callon's ability to market oil and gas from the Company's wells depends upon
numerous factors beyond the Company's control, including the extent of domestic
production and imports of oil and gas, the proximity of the gas production to
gas pipelines, the availability of capacity in such pipelines, the demand for
oil and gas by utilities and other end users, the availability of alternative
fuel sources, the effects of inclement weather, and state and federal regula-
tion of oil and gas production and federal regulation of gas sold or trans-
ported in interstate commerce. No assurance can be given that Callon will be
able to market all of the oil or gas produced by the Company or that favorable
prices can be obtained for the oil and gas Callon produces.
In view of the many uncertainties affecting the supply and demand for oil, gas
and refined petroleum products, the Company is unable to predict future oil
and gas prices and demand or the overall effect such prices and demand will
have on the Company. Callon does not believe that the loss of any of the
Company's oil purchasers would have a material adverse effect on the Company's
operations. Additionally, since substantially all of the Company's gas sales
are on the spot market, the loss of one or more gas purchasers should not
materially and adversely affect the Company's financial condition. The market-
ing of oil and gas by Callon can be affected by a number of factors which are
beyond the Company's control, the exact effects of which cannot be accurately
predicted.
Corporate Offices
The Company's headquarters are located in Natchez, Mississippi, in approximate-
ly 51,500 square feet of owned space. The Company also maintains owned or
leased field offices in the area of the major fields in which it operates
properties or has a significant interest. Replacement of any of the Company's
leased offices would not result in material expenditures by the Company as
alternative locations to its leased space are anticipated to be readily
available.
Employees
The Company had 143 employees as of December 31, 1997, none of whom are
currently represented by a union. The Company considers itself to have
good relations with its employees. The Company employs eight petroleum
engineers and four petroleum geoscientists.
Litigation
The Company is a defendant in various legal proceedings and claims which arise
in the ordinary course of Callon's business. Callon does not believe the
ultimate resolution of any such actions will have a material effect on the
Company's financial position or results of operations.
Federal Regulations
Sales of Natural Gas. Effective January 1, 1993, the Natural Gas Wellhead
Decontrol Act deregulated prices for all "first sales" of natural gas. Thus,
all sales of gas by the Company may be made at market prices, subject to
applicable contract provisions.
Transportation of Natural Gas. The rates, terms and conditions applicable to
the interstate transportation of natural gas by pipelines are regulated by the
Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act
("NGA"), as well as under section 311 of the Natural Gas Policy Act ("NGPA").
Since 1985, the FERC has implemented regulations intended to make natural gas
transportation more accessible to gas buyers and sellers on an open-access,
non-discriminatory basis.
Most recently, in Order No. 636, et seq., the FERC promulgated an extensive set
of new regulations requiring all interstate pipelines to "restructure" their
services. The most significant provisions of Order No. 636 (i) require that
interstate pipelines provide firm and interruptible transportation solely on
an "unbundled" basis, separate from their sales service, and convert each pipe-
line's bundled firm city-gate sales service into unbundled firm transportation
service; (ii) issue blanket certificates to pipelines to provide unbundled
sales service; (iii) require that pipelines provide firm and interruptible
transportation service on a basis that is equal in quality for all natural
gas supplies, whether purchased from the pipeline or elsewhere; (iv) require
that pipelines provide a new non-discriminatory "no-notice" transportation
service; (v) establish two new, generic programs for the reallocation of firm
pipeline capacity; (vi) require that all pipelines offer access to their storage
facilities on a firm and interruptible, open access, contract basis; (vii)
provide pregranted abandonment of unbundled sales and interruptible and short-
term firm transportation service and conditional pregranted abandonment of
long-term transportation service; (viii) modify transportation rate design
by requiring all fixed costs related to transportation to be recovered
through the reservation charge under the straight fixed variable ("SFV")
method. The order also recognized that the elimination of city-gate sales
service and the implementation of unbundled transportation service would
result in considerable costs being incurred by the pipelines. Therefore,
Order No. 636 provided mechanisms for the recovery by pipelines from present,
former and future customers of certain types of "transition" costs likely to
occur due to these new regulations.
In subsequent orders, the FERC substantially upheld in the requirements imposed
by Order No. 636. Pursuant to Order No. 636, pipelines and their customers
engaged in extensive negotiations in order to develop and implement new service
relationships under Order No. 636. Tariffs instituting these new restructured
services were placed into effect on all pipelines on or before November 1, 1993.
Numerous petitions for judicial review of Order No. 636 have been filed and
consolidated for review in the United States Court of Appeals for the D. C.
Circuit. In addition, numerous parties have sought review of separate FERC
orders implementing Order No. 636 on individual pipeline systems. Since the
restructuring requirements that emerge from this lengthy administrative and
judicial review process may be materially different from those of Order No.
636 as originally adopted, it is not possible to predict what effect, if any,
the final rule resulting from Order No. 636 will have on the Company.
Sales and Transportation of Crude Oil. Sales of crude oil and condensate can
be made by the Company at market prices not subject at this time to price
controls. The price that the Company receives from the sale of these products
will be affected by the cost of transporting the products to market. As
required by the Energy Policy Act of 1992, the FERC has revised its regulations
governing the rates that may be charged by oil pipelines. The new rules, which
were effective January 1, 1995, provide a simplified, generally applicable
method of regulating such rates by use of an index for setting rate ceilings.
In certain circumstances, the new rules permit oil pipelines to establish rates
using traditional cost of service and other methods of ratemaking. The effect
that these new rules may have on moving the Company's products to market cannot
yet be determined. In addition, at the same time as it issued the new rules,
the FERC also issued notices of inquiry regarding market-based pricing for oil
pipeline rates and the information required to be filed for ratemaking and
reporting purposes. It is not possible to predict what rules, if any, the FERC
will ultimately adopt as a result of these inquiry proceedings or the effect
that any rules that are adopted might have on the cost of moving the Company's
products to market.
Legislative Proposals. In the past, Congress has been very active in the area
of natural gas regulation. There are legislative proposals pending in various
state legislatures which, if enacted, could significantly affect the petroleum
industry. At the present time it is impossible to predict what proposals, if
any, might actually be enacted by Congress or the various state legislatures
and what effect, if any, such proposals might have on the Company's operations.
Federal, State or Indian Leases. In the event the Company conducts operations
on federal, state or Indian oil and gas leases, such operations must comply
with numerous regulatory restrictions, including various nondiscrimination
statutes, and certain of such operations must be conducted pursuant to certain
on-site security regulations and other appropriate permits issued by the Bureau
of Land Management ("BLM") or Minerals Management Service or other appropriate
federal or state agencies.
The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect
ownership of any interest in federal onshore oil and gas leases by a foreign
citizen of a country that denies "similar or like privileges" to citizens of
the United States. Such restrictions on citizens of a "non-reciprocal"
country include ownership or holding or controlling stock in a corporation
that holds a federal onshore oil and gas lease. If this restriction is
violated, the corporation's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of non-
reciprocal countries, there are presently no such designations in effect.
The Company owns interests in numerous federal onshore oil and gas leases.
It is possible that holders of equity interests in the Company may be
citizens of foreign countries, which at some time in the future might be
determined to be non-reciprocal under the Mineral Act.
State Regulations
Most states regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. The rate of production may be regulated and the maximum
daily production allowable from both oil and gas wells may be established on a
market demand or conservation basis or both.
The Company may enter into agreements relating to the construction or operation
of a pipeline system for the transportation of natural gas. To the extent that
such gas is produced, transported and consumed wholly within one state, such
operations may, in certain instances, be subject to the jurisdiction of such
state's administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates which the Company could charge
for gas, the transportation of gas, and the construction and operation of such
pipeline would be subject to the rules and regulations governing such matters,
if any, of such administrative authority.
Environmental Regulations
General. The Company's activities are subject to existing 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 regulating the release
of materials in 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 exist-
ing assets and operations. The Company cannot predict what effect additional
regulation or legislation, enforcement policies thereunder, and claims for
damages to property, employees, other persons and the environment resulting
from the Company's operations could have on its activities.
Activities of the Company with respect to natural gas facilities, including the
operation and construction of pipelines, plants and other facilities for trans-
porting, processing, treating or storing natural gas and other products, are
subject to stringent environmental regulation by state and federal authorities
including the United States Environmental Protection Agency ("EPA"). Such
regulation can increase the cost of planning, designing, installation and
operation of such facilities. In most instances, the regulatory requirements
relate to water and air pollution control measures. Although the Company
believes that compliance with environmental regulations will not have a
material adverse effect on it, risks of substantial costs and liabilities are
inherent in oil and gas production operations, and there can be no assurance
that significant costs and liabilities will not be incurred. Moreover, it is
possible that other developments, such as stricter environmental laws and
regulations, and claims for damages to property or persons resulting from oil
and gas production, would result in substantial costs and liabilities to the
Company.
Solid and Hazardous Waste. The Company owns or leases numerous properties that
have been used for production of oil and gas for many years. Although the
Company has utilized operating and disposal practices standard in the industry
at the time, hydrocarbons or other solid wastes may have been disposed or
released on or under these properties. In addition, many of these properties
have been operated by third parties. The Company had no control over such
entities' treatment of hydrocarbons or other solid wastes and the manner in
which such substances may have been disposed or released. State and federal
laws applicable to oil and gas wastes and properties have gradually become
stricter over time. Under these new laws, the Company could be required to
remove or remediate previously disposed wastes (including wastes disposed or
released by prior owners or operators) or property contamination (including
groundwater contamination by prior owners or operators) or to perform
remedial plugging operations to prevent future contamination.
The Company generates wastes, including hazardous wastes, that are subject to
the Federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA has limited the disposal options for certain hazardous
wastes and is considering the adoption of stricter disposal standards for non-
hazardous wastes. Furthermore, it is possible that certain wastes currently
exempt from treatment as "hazardous wastes" generated by the Company's oil
and gas operations may in the future be designated as "hazardous wastes"
under RCRA or other applicable statutes, and therefore be subject to more
rigorous and costly disposal requirements.
Superfund. The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons with respect to the release of a "hazardous substance" into the environ-
ment. These persons include the owner and operator of a site and persons that
disposed or arranged for the disposal of the hazardous substances found at a
site. CERCLA also authorizes the EPA and, in some cases, third parties to take
actions in response to threats to the public health or the environment and to
seek to recover from the responsible classes of persons the costs of such
action. Neither the Company nor its predecessors has been designated as a
potentially responsible party by the EPA under CERCLA with respect to any such
site.
Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and regulations
thereunder impose a variety of regulations on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from such
spills in United States waters. A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages. While liability limits apply in some circumstances, a party cannot
take advantage of liability limits if the spill was caused by gross
negligence or willful misconduct or resulted from violation of a federal
safety, construction or operating regulation. If the party fails to report
a spill or to cooperate fully in the cleanup, liability limits likewise do not
apply. Few defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. On August 25, 1993, an advance notice of intention to adopt a rule
under the OPA was published that would require owners and operators of offshore
oil and gas facilities to establish $150 million in financial responsibility.
Under the proposed rule, financial responsibility could be established through
insurance, guaranty, indemnity, surety bond, letter of credit, qualification
as a self-insurer or a combination thereof. It is unlikely that insurance
companies or underwriters will be willing to provide coverage under the OPA
because the statute provides for direct lawsuits against insurers who provide
financial responsibility coverage, and most insurers have strongly protested
this requirement. The financial tests or other criteria that will be used to
judge self-insurance are also uncertain. A number of bills are pending in the
United States Congress to amend or modify the financial responsibility require-
ments under OPA. The Company cannot predict the final form of the financial
responsibility rule that will be adopted. If the original requirements under
OPA are not amended, regulations promulgated thereunder may have the potential
to result in the imposition of substantial additional annual costs on the
Company or otherwise materially adversely affect the Company. The impact of
the rule should not be any more adverse to the Company than it will be to other
similarly or less capitalized owners or operators in the Gulf of Mexico. Pending
adoption of final regulations the Company has not taken any steps to establish
financial responsibility under the OPA.
Air Emissions. The operations of the Company are subject to local, state and
federal regulations for the control of emissions from sources of air pollution.
Administrative enforcement actions for failure to comply strictly with air
regulations or permits are generally resolved by payment of monetary fines
and correction of any identified deficiencies. Alternatively, regulatory
agencies could require the Company to forego construction or operation of
certain air emission sources, although the Company believes that in such case
it would have enough permitted or permittable capacity to continue its
operations without a material adverse effect on any particular producing
field.
OSHA. The Company is subject to the requirements of the Federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the Federal Superfund Amendment and Reauthorization Act and similar
state statutes require the Company to organize and/or disclose information about
hazardous materials used or produced in its operations. Certain of this
information must be provided to employees, state and local governmental
authorities and local citizens.
Management believes that the Company is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance
with existing requirements will not have a material adverse impact on the
Company.
ITEM 2. PROPERTIES
The Company is engaged in the acquisition, development, exploitation and
exploration of oil and gas properties and natural gas transmission and provides
oil and gas property management services for other investors. The Company's
properties are concentrated offshore in the Gulf of Mexico and onshore in
Louisiana and Alabama. As of December 31, 1997, the Company's estimated proved
reserves totaled 3.4 million barrels of oil and 88.7 billion cubic feet of
natural gas, with a pre-tax present value, discounted at 10%, of the estimated
future net revenues based on constant prices in effect at year-end ("Discounted
Cash Flow") of $136.4 million. Gas constitutes approximately 81% of the
Company's total estimated proved reserves and approximately 84% of the
Company's reserves are proved producing reserves. The Company operates 135
wells representing approximately 72% of the total Discounted Cash Flow
attributable to estimated proved reserves.
Significant Producing Properties
The following table shows discounted cash flows and estimated net proved oil
and gas reserves by major field for the Company's five largest producing fields
and for all other properties combined at December 31, 1997.
Percent Estimated Net Proved
Discounted Total Oil Gas Total
Field Name/ Primary Cash Flow Discounted Reserves Reserves Reserves
Location Operator(s) ($000)(a) Cash Flow (MBbls) (MMcf) (MMcfe)
__________________ ___________ __________ __________ ________ ________ ________
Mobile Bay 864 Area Callon/Murphy $ 64,806 47.49% -- 50,782 50,782
Federal Waters
Chandeleur Block 40 Callon 20,761 15.22% -- 12,572 12,572
Federal Waters
Main Pass 32/35 Area Callon 16,354 11.99% 503 6,475 9,493
Louisiana State Waters
Big Escambia Creek Exxon 9,596 7.03% 942 2,373 8,025
Southeast Alabama
Main Pass 163 Area Callon 8,807 6.45% -- 9,782 9,782
Federal Waters
Other properties Various 16,124 11.82% 1,957 6,754 18,496
________ ______ _____ ______ _______
Total $136,448 100.00% 3,402 88,738 109,150
======== ====== ===== ====== =======
______________
(a) Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%,
attributable to estimated proved reserves as of December 31, 1997, as set forth in the Company's independent reserve
reports prepared by Huddleston & Co., Inc. of Houston, Texas.
Mobile Block 864 Area
The Mobile Block 864 Area is located offshore Alabama in the federal waters of
the OCS. During 1997, the Company consummated four acquisitions in this area
for a total of $48.7 million. In total, the Company has acquired an average
55.4% working interest in seven blocks, a 53.3% working interest in the Mobile
Block 864 Area unit and the unit production facilities, a 66.7% working interest
in two producing wells and a 50% working interest in another well. Estimated
net proved reserves at December 31, 1997 were 50.8 Bcf and a PV-10 value of
$64.8 million. Net average daily production during December 1997, was 17.6 MMcf
per day.
During 1997, the Company was appointed operator of the Mobile Block 864 Area
unit. Production from three wells in the area is currently constrained by the
capacity of the unit production facilities. The Company plans to add com-
pression facilities to the existing platform to increase productive capacity
during 1998. The Company has also identified two development prospects and one
exploration prospect in this area using available 3-D seismic. In addition,
the Company plans to conduct an extensive shallow focus, high-resolution
seismic survey over the area to refine its development plans and to explore
for additional prospects during 1998.
Chandeleur Block 40
The Company currently holds a combined 52.3% working (43.6% net revenue)
interest in this property. The field's remaining proved reserves are estimated
to be 12.6 Bcf of natural gas (net to the Company) as of December 31, 1997.
When the Company assumed operations of the field, two wells were producing 5.5
MMcf/d of natural gas from the 3,800 foot sand. In February 1996, the Company
shut-in one well and successfully reworked the other and increased average
field production to 10.5 MMcf/d of natural gas.
During the fourth quarter of 1996, the Company drilled a development well in
the field. For the year ended December 31, 1997, the well was producing an
average of 18.5 MMcf/d. The well resulted in a field extension which added
6 Bcf in estimated net proved reserves to the Company as of December 31, 1996.
Total field production averaged approximately 24.6 MMcf/d during 1997.
Main Pass 32/35 Area
In the Main Pass 32/35 Area, the Company owns and operates 14 producing wells
in a field located in shallow Louisiana-state waters which produces oil and gas
from reservoirs at depths of between 6,000 and 9,000 feet. In November 1996,
the Company completed a 36 square-mile seismic survey covering its Main Pass
Block 35 field and adjoining acreage. Based upon this data, the Company
negotiated two separate farm-in agreements for a 100% working interest
covering a prospect with reserve potential updip from existing production
in a Cib Carst reservoir on Main Pass Block 31. In August 1997, the SL 12002
#1 was drilled to a total vertical depth of 10,900 feet, completed in a
laminated pay section between 10,590 and 10,601 feet. The Company placed
the SL 12002 #1 on production in December 1997 after flowlines were laid to
a Company-operated production facility at Main Pass Block 32. The SL 12002 #1
had proved reserves at December 31, 1997 of 7.9 Bcfe and a PV-10 value of $15.7
million.
Big Escambia Creek
The Company owns an average working interest of 6.0% (6.6% net revenue
interest), subject to a 10% reduction after payout, in nine wells and a 2.9%
average royalty interest in another six wells. The gross average daily
production for these wells during December 1997 was 3.2 MBbls of condensate,
1.7 MBbls of natural gas liquids, 8.4 MMcf of residue natural gas and 375 long
tons of sulfur. These wells are producing from the Smackover formation at
depths ranging from 15,100 to 15,600 feet. Production in this field has been
partially curtailed due to low treatment plant capacity and, as a result, no
significant field production decline occurred during the past several years.
Main Pass 163 Area
In 1996, Callon acquired a 100% working interest in Chandeleur Block 41 and
Main Pass Blocks 159, 160, 161 and 163 located in the Shallow Miocene Trend.
The acquisition initially included five wells producing 4 MMcf/d, as well as
production facilities at Main Pass 163 capable of handling 90 MMcf/d.
Based upon interpretation of seismic data acquired and processed by Callon, an
exploratory well was drilled on Main Pass Block 163 during the fourth quarter
of 1996. A development well was also drilled during the fourth quarter of
1996 on Main Pass Block 161. During the second quarter of 1997, the Company
drilled a successful well on Chandeleur Block 41 and production commenced in
July 1997. Total production from the Main Pass 163 Area averaged approximately
14 MMcf/d for 1997.
The Main Pass 163 Area wells produce from Shallow Miocene reservoirs at
approximate depths of 3,300 feet. Proved reserves at December 31, 1997
attributable to this area were 9.8 Bcf.
Oil and Gas Reserves
The following table sets forth certain information about the estimated proved
reserves of the Company as of the dates set forth below.
December 31, 1997
___________________________________
1997 1996 1995
______ ______ ______
(In thousands)
Proved developed:
Oil (Bbls) 2,976 3,385 3,890
Gas (Mcf) 88,010 49,491 20,408
Proved undeveloped:
Oil (Bbls) 426 434 876
Gas (Mcf) 728 933 9,259
Total proved:
Oil (Bbls) 3,402 3,819 4,766
Gas (Mcf) 88,738 50,424 29,667
Estimated pre-tax future net cash flows $209,264 $216,154 $95,730
======== ======== =======
Discounted cash flows $136,448 $160,171 $63,764
======== ======== =======
The Company's independent reserve engineers (Huddleston & Co., Inc. of Houston,
Texas) 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 Securities and Exchange Commission ("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 the control of the Company and 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, and the accuracy of any reserve or cash flow estimate is a function
of the quality of available data and of engineering and geological interpre-
tation 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 are different from the quantities
of oil and gas that are ultimately recovered.
The Company has not filed any reports with other federal agencies which contain
an estimate of total proved net oil and gas reserves.
Productive Wells
The following table sets forth the wells drilled and completed by the Company
during the periods indicated. All such wells were drilled in the continental
United States including federal and state waters in the Gulf of Mexico.
Years ended December 31,
1997 1996 1995
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Development:
Oil -- -- 1 .09 6 .65
Gas 2 2.00 2 1.52 1 .13
Non-Productive 1 0.66 -- -- -- --
---- ---- ---- ---- ---- ----
Total 3 2.66 3 1.61 7 .78
==== ==== ==== ==== ==== ====
Exploration:
Oil -- -- -- -- 1 .24
Gas 2 .62 1 1.00 -- --
Non-Productive 5 1.20 -- -- -- --
____ ____ ____ ____ ____ ____
Total 7 1.82 1 1.00 1 .24
==== ==== ==== ==== ==== ====
The Company owned working and royalty interests in approximately 614 gross
(29.23 net) producing oil and 317 gross (24.65 net) producing gas wells as of
December 31, 1997. A well is categorized as an oil well or a natural gas well
based upon the ratio of oil to gas reserves on a Mcfe basis. However,
substantially all of the Company's wells produce both oil and gas. At December
31, 1997, the Company had three exploratory gas wells in progress.
Leasehold Acreage
The following table shows the approximate developed and undeveloped (gross and
net) leasehold acreage of the Company as of December 31, 1997.
Leasehold Acreage
Developed Undeveloped
State Gross Net Gross Net
- ----------- ------- ------ ------- ------
Alabama 13,136 12,210 944 190
California -- -- 480 480
Louisiana 46,392 5,484 15,698 10,838
Mississippi 2,523 1,379 564 564
Oklahoma 1,733 124 -- --
Texas 1,815 146 -- --
Federal Waters 100,282 58,731 177,155 48,223
------- ------ ------- ------
Total 165,881 78,074 194,841 60,295
======= ====== ======= ======
As of December 31, 1997, the Company owned various royalty and overriding
royalty interests in 1,366 net developed acres and 6,852 undeveloped acres.
In addition, the Company owned 5,464 developed and 134,536 undeveloped
mineral acres.
Major Customers
For the year ended December 31, 1997, PG&E Energy Trading Corp., Sonat Gas
Marketing Co. L.P., and Williams Energy Services, Inc. purchased 37%, 17% and
10%, respectively, of the Company's natural gas production. Williams Energy
purchased natural gas from the North Dauphin Island Field, and Sonat Gas and
PG&E purchased natural gas primarily from Callon owned interests' in Federal
OCS leases, Chandeleur Block 40, Main Pass 163, Main Pass 164/165, Mobile Block
864 and Mobile Block 952/955 fields. Because of the nature of oil and gas
operations and the marketing of production, the Company believes that the loss
of these customers would not have a significant adverse impact on the Company's
ability to sell its products.
Title to Properties
The Company believes that the title to its 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 the opinion of the Company, are
not so material as to detract substantially from the use or value of such
properties. The Company's 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 the Company or its predecessors in
title; a variety of contractual obligations (including, in some cases,
development obligations) arising under operating agreements, farmout agree-
ments, 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 the Company's rights to production revenues, they have been
taken into account in calculating the Company's net revenue interests and
in estimating the size and value of the Company's reserves. The Company
believes that the burdens and obligations affecting its properties are
conventional in the industry for properties of the kind owned by the Company.
ITEM 3. LEGAL PROCEEDINGS
The Company was not and currently is not a party to any material pending legal
proceedings.
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 1997.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock trades on the Nasdaq National Market System under
the symbol "CLNP". The following table sets forth the high and low sale prices
per share as reported on Nasdaq for the periods indicated.
Quarter Ended High Low
1995:
1st Quarter 11 9 1/2
2nd Quarter 10 1/2 9
3rd Quarter 12 1/4 9 1/4
4th Quarter 11 9 1/32
1996:
1st Quarter 10 1/2 9 1/2
2nd Quarter 14 1/4 10
3rd Quarter 13 1/2 10 3/4
4th Quarter 19 1/8 12 1/2
1997:
1st Quarter 19 1/2 12 1/2
2nd Quarter 16 3/8 13 1/4
3rd Quarter 19 3/8 15
4th Quarter 22 15
As of March 10, 1998, there were approximately 7,991 common stockholders of
record.
The Company has not paid dividends on the Common Stock and intends to retain
its cash flow from operations, net of preferred stock dividends, for the future
operation and development of its business. In addition, the Company's primary
credit facility restricts payments of dividends on its Common Stock.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth, as of the dates and for the periods indicated,
selected financial information for the Company. The financial information for
each of the five years in the period ended December 31, 1997 have been derived
from the audited Consolidated Financial Statements of the Company for such
periods. The information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
and the Consolidated Financial Statements and Notes thereto. The following
information is not necessarily indicative of future results for the Company.
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Year Ended December 31,
1997 1996 1995 1994 1993
--------- --------- --------- -------- ---------
Statement of Operations Data(a):
Revenues:
Oil and gas sales $ 42,130 $ 25,764 $ 23,210 $ 13,948 $ 10,048
Interest and other 1,508 946 627 171 230
--------- --------- --------- --------- ---------
Total revenues 43,638 26,710 23,837 14,119 10,278
--------- --------- --------- --------- ---------
Costs and expenses:
Lease operating expenses 8,123 7,562 6,732 4,042 3,713
Depreciation, depletion and amortization 16,488 9,832 10,376 6,049 3,411
General and administrative 4,433 3,495 3,880 3,717 2,350
Interest 1,957 313 1,794 624 196
--------- --------- --------- --------- ---------
Total costs and expenses 31,001 21,202 22,782 14,432 9,670
--------- --------- --------- --------- ---------
Income (loss) from operations 12,637 5,508 1,055 (313) 608
Income tax expense (benefit) 4,200 50 -- (200) 113
--------- --------- --------- --------- ---------
Income (loss) before cumulative effect of
change in accounting principle 8,437 5,458 1,055 (113) 495
Cumulative effect of change in accounting principle (b) -- -- -- -- 5,262
--------- --------- --------- --------- ---------
Net income (loss) 8,437 5,458 1,055 (113) 5,757
Preferred stock dividends 2,795 2,795 256 -- --
--------- --------- --------- --------- ---------
Net income (loss) available to common shares 5,642 2,663 799 (113) 5,757
Pro forma adjustment for income taxes (c) -- -- -- -- 100
--------- --------- --------- --------- ---------
Pro forma net income (loss) $ 5,642 $ 2,663 $ 799 $ (113) $ 5,657
========= ========= ========= ========= =========
Net income (loss) per common share:
Basic $ .91 $ .46 $ .14 $ (.03) $ 1.53
Diluted $ .88 $ .45 $ .14 $ (.03) $ 1.53
Shares used in computing net income (loss) per common share:
Basic 6,194 5,835 5,755 4,346 3,769
Diluted 6,422 5,952 5,755 4,346 3,769
Balance Sheet Data (end of period)(a):
Oil and gas properties, net $ 150,494 $ 82,489 $ 57,765 $ 43,920 $ 21,000
Total assets $ 190,421 $ 118,520 $ 83,867 $ 73,786 $ 39,825
Long-term debt, less current portion $ 60,250 $ 24,250 $ 100 $ 15,363 $ 233
Stockholders' Equity $ 113,701 $ 77,864 $ 75,129 $ 43,431 $ 27,170
- -------------
(see footnotes on following page)
(a) The Company succeeded to the business and properties of Callon Petroleum Operating Company, Callon Consolidated Partners,
L. P. and CN Resources on September 16, 1994 pursuant to the Consolidation. Historical information about the Company prior
to September 16, 1994 includes the financial and operating information of the predecessors of the Company, other than the
interest in CN not owned by Callon Petroleum Operating Company, combined as entities under common control in a manner similar
to a pooling of interests.
(b) As a result of the combination of the Company and CCP there was a change in the tax status of the Company; therefore, the
Company was able to reduce the valuation allowance at January 1, 1993 by $5,262,000, or $1.40 per common share. The net asset
represents the statutory depletion carryforward (which has an unlimited carryforward period) and the portion of the federal net
operating loss carryforward that the Company's management believes will be utilized. All other temporary differences are
offset by the valuation allowance, which represents that portion of the asset that management believes is more likely than
not, that it will not be realized.
(c) The pro forma adjustment for income taxes of $100,000, or $.03 per common share, relates to the income of CCP prior to the
Consolidation as if such income was taxed as a corporation. Pro forma tax adjustments were provided only to the extent CCP
had income, thus none was recorded in 1994.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
General
The Company's revenues, profitability and future growth and the carrying value
of its oil and gas properties are substantially dependent on prevailing prices
of oil and gas. The Company's ability to maintain or increase its borrowing
capacity and to obtain additional capital on attractive terms is also
influenced by oil and gas prices. Prices for oil and gas are subject to large
fluctuations in response to relatively minor changes in the supply of and demand
for oil and gas, market uncertainty and a variety of additional factors beyond
the control of the Company. These factors include weather conditions in the
United States, the condition of the United States economy, the actions of the
Organization of Petroleum Exporting Countries, governmental regulation,
political stability in the Middle East and elsewhere, the foreign supply of
crude oil and natural gas, the price of foreign imports and the availability
of alternate fuel sources. Any substantial and extended decline in the price
of crude oil or natural gas would have an adverse effect on the Company's
carrying value of its proved reserves, borrowing capacity, revenues, profit-
ability and cash flows from operations. Subsequent to year-end the price of
crude oil has declined. On a Mcfe basis, crude oil represents 17% of proved
reserves at year-end and 15% of the projected 1998 production of such reserves.
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the market
for oil and gas producing properties, as buyers and sellers have difficulty
agreeing on such value. Price volatility also makes it difficult to budget
for and project the return on acquisitions and development and exploitation
projects.
Year 2000 Compliance
The Company does not expect that the cost to modify and replace its information
technology infrastructure to be Year 2000 compliant will be material to its
financial condition or results of operations. The Company does not anticipate
any material disruption in its operations as a result of any failure by the
Company to be in compliance.
Liquidity and Capital Resources
The Company's primary sources of capital are its cash flows from operations,
borrowings from financial institutions and sale of equity securities. Cash
provided from operating activities during 1997 totaled $27.3 million. During
1997, the Company borrowed a net of $36 million and issued $29.3 million in
additional common stock in November, 1997. At December 31, 1997, the Company
had working capital in the amount of $12.7 million.
Effective October 31, 1996, the Company entered into a new Credit Facility with
Chase Manhattan Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. The Credit Facility provides for borrowings of a maximum of the
lesser of $50 million or a borrowing base ("Borrowing Base") determined
periodically on the basis of a discounted present value of future net cash
flows attributable to the Company's proved producing oil and gas reserves.
Pursuant to the Credit Facility, depending upon the percentage of the unused
portion of the Borrowing Base, the interest rate is equal to either the lender's
prime rate or the lender's prime rate plus 0.50%. The Company, at its option,
may fix the interest rate on all or a portion of the outstanding principal
balance at either 1.00% or 1.375% above a defined "Eurodollar" rate, depending
upon the percentage of the unused portion of the Borrowing Base, for periods
of up to six months. The weighted average interest rate for the total debt
outstanding at December 31, 1997 and 1996 was 8.50% and 8.25%, respectively.
Under the Credit Facility, a commitment fee of .25% or .375% per annum on the
unused portion of the Borrowing Base (depending upon the percentage of the
unused portion of the Borrowing Base) is payable quarterly. The Company may
borrow, pay, reborrow and repay under the Credit Facility until October 31,
2000, on which date, the Company must repay in full all amounts then out-
standing. At December 31, 1997, the unpaid balance due on this Credit Facility
was $100,000.
On November 27, 1996, the Company issued $24,150,000 of 10% Senior Subordinated
Notes that will mature December 15, 2001. The Company used the proceeds to pay
down the Credit Facility and for other corporate purposes. Interest is payable
quarterly beginning March 15, 1997. The notes are redeemable at the option of
the Company, in whole or in part, on or after December 15, 1997, at 100% of the
principal amount thereof, plus accrued interest to the redemption date. The
notes are general unsecured obligations of the Company, subordinated in right
of payment to all existing and future indebtedness of the Company. The credit
facility and the subordinated debt contain various covenants including
restrictions on additional indebtedness and payment of cash dividends as well
as maintenance of certain financial ratios. The Company is in compliance with
these covenants at December 31, 1997.
On July 31, 1997, the Company issued $36 million of its 10.125% Series A Senior
Subordinated Notes due 2002 in a private placement for net proceeds of $34.8
million. The Company used $18.5 million of the net proceeds to repay borrow-
ings under the Credit Facility and the remaining net proceeds were allocated
to the Company's capital expenditure budget. On September 10, 1997, pursuant
to a Registration Agreement dated July 31, 1997, the Company commenced an offer
to exchange the Series A Notes for a like principal amount of 10.125% Series B
Senior Subordinated Notes due 2002 (the "Series B Notes" and, together with the
Series A Notes, the "10.125% Notes"). The form and terms of the Series B Notes
are identical in all material respects to the terms of the Series A Notes,
except for certain transfer restrictions and provisions relating to registration
rights. The exchange offer terminated on November 10, 1997. Interest on the
10.125% Notes is payable quarterly, on March 15, June 15, September 15, and
December 15 of each year. The 10.125% Notes are redeemable at the option of
the Company in whole or in part, at any time on or after September 15, 2000.
The 10.125% Notes are general unsecured obligations of the Company,
subordinated in right of payment to all existing and future indebtedness of
the Company and rank pari passu with the 10% Notes. The Credit Facility and
the indenture for the 10.125% Notes contain various covenants including
restrictions on additional indebtedness and payment of cash dividends as well
as maintenance of certain financial ratios. The Company is in compliance
with these covenants at December 31, 1997.
Net capital expenditures for 1997 totaled $85.2 million which included $10.3
million of lease acquisitions and other associated costs, $51.8 million for the
acquisition of producing properties and equipment and $23.1 million for property
development and drilling activities on new and previously existing properties.
The Company's plans for 1998 include capital expenditures of $75 million.
Projected cash flow from operations and borrowings under the Company's Credit
Facility are anticipated to be sufficient to fund this capital budget; however,
the Company may consider alternative sources of financing. However, future
capital expenditure requirements will depend somewhat on exploration results.
Results of Operations
The following table sets forth certain operating information with respect to
the oil and gas operations of the Company for the three year period ended
December 31, 1997.
December 31,
1997 1996 1995
Production:
Oil (MBbls) 462 585 594
Gas (MMcf) 13,114 6,269 6,694
Total production (MMcfe) 15,887 9,781 10,261
Average sales price:
Oil (per Bbl) $ 18.63 $ 18.27 $ 16.68
Gas (per Mcf) $ 2.56 $ 2.40 $ 1.96
Total production (per Mcfe) $ 2.65 $ 2.63 $ 2.24
Average costs (per Mcfe):
Lease operating expenses (excluding
severance taxes) $ 0.42 $ 0.57 $ 0.49
Severance taxes $ 0.09 $ 0.20 $ 0.17
Depreciation, depletion and amortization $ 1.04 $ 1.01 $ 1.01
General and administrative (net of
management fees) $ 0.28 $ 0.36 $ 0.38
Comparison of Results of Operations for the Years Ended
December 31, 1997 and 1996
Oil and Gas Revenues
Total oil and gas revenues increased $16.4 million, or 63%, during 1997 to
$42.1 million compared to $25.8 million in 1996. This increase in oil and
gas revenues was the result ofincreased gas production volumes and increased
average sales prices for both oil and gas.
Oil revenues for 1997 were $8.6 million based on production volume of 462,000
barrels of oil sold at an average sales price of $18.63 per barrel. For 1996,
revenues were $10.7 million based on 585,000 barrels of oil sold at an average
sales price of $18.27. The $2.1 million decline in oil revenues is largely
attributed to normal production declines from several of the Company's oil
producing properties, as well as the divestiture of certain non-core
properties.
Gas revenues for 1997 were $33.5 million based on production volumes of 13.1 Bcf
of gas sold at an average sales price of $2.56 per Mcf. For 1996, revenues were
$15.1 million based on 6.3 Bcf of gas sold at an average sales price of $2.40.
The 109% increase in production volume is largely attributed to the Company's
1996 discoveries at Chandeleur Block 40 and Main Pass 163 Area and the 1997
acquisitions in the Mobile Block 864 Area.
Lease Operating Expenses
Lease operating expenses, including severance taxes, increased from $7.6 million
in 1996 to $8.1 million in 1997. Separately, severance taxes declined from
$1.9 million in 1996 to $1.4 million in 1997 as a result of lower production
on properties subject to severance taxes. Other operating expenses increased
from $5.6 million in 1996 to $6.7 million in 1997 as a result of the new off-
shore producing properties. On a per Mcfe basis, these combined expenses
decreased from $0.77 in 1996 to $0.51 in 1997.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization for 1997 totaled $16.5 million, or
$1.04 per Mcfe. For the same period in 1996, these expenses totaled $9.8
million, or $1.01 per Mcfe.
General and Administrative Expenses
General and administrative expenses for 1997 were $4.4 million, a 27% increase
from the $3.5 million in 1996 as a result of expanded levels of operations and
production. On a per Mcfe basis, these expenses decreased from $0.36 in 1996
to $0.28 in 1997.
Interest Expense
Interest expense for 1997 was $2.0 million. The substantial increase from the
$.3 million in 1996 is reflective of the issuance of the Senior Subordinated
Notes in November 1996 and July 1997.
Income Taxes
The recorded income tax expense for 1997 was $4.2 million. This amount
represents the approximate statutory income tax rate, as adjusted for expected
future utilization of its net operating losses and depletion carryovers.
For 1996, the statutory income tax was $1.9 million, which was primarily
offset by a reduction in the deferred tax asset valuation allowance.
Comparison of Results of Operations for the Years Ended
December 31, 1996 and 1995
Oil and Gas Revenues
Oil and gas sales increased $2.6 million, or 11%, during 1996 to $25.8 million
compared to $23.2 million in 1995. While oil and gas production volumes for
1996 were lower than those reported in 1995, substantial price increases for
both oil and gas more than offset the loss in revenues. The average sales
price per barrel sold in 1996 increased to $18.27, compared to $16.68 for 1995.
The average sales price per Mcf of gas sold increased from $1.96 in 1995 to
$2.40 in 1996.
Oil production for 1996 decreased slightly to 585,000 barrels from the 594,000
barrels produced in 1995. This reduction was primarily attributable to the
implementation of the required environmental protection program (zero discharge)
at our Black Bay Complex, the Company's largest single oil producing prospect.
During this process, several producing wells were shut-in while various new
equipment was installed. In addition, several wells were temporarily shut-in
while repairs were conducted on the service lines. Therefore, average daily
production for 1996 dropped to 1,599 barrels per day compared to 1,629 barrels
per day in 1995.
Gas production for 1996 was 6.3 Bcf, a decrease from the 6.7 Bcf reported in
1995. This reduction was primarily attributable to the loss of production from
the North Dauphin Island Field where problems with excess water content in the
gas sales stream were encountered early in the year requiring the installation
of a dehydrator and removal of water from the lines. Extraneous water
production from the #2A well led to the shut-in of the well and the natural
decline of the reservoir pressure. Also during the year, this field incurred
a lower production rate due to compressor inefficiencies which led to a
compressor restaging program that was completed in late September.
Lease Operating Expenses
Lease operating expenses, including severance taxes, increased from $6.7
million in 1995 to $7.6 million in 1996. A large portion of this increase,
$600,000, is attributable to normal expenses associated with new property
additions. Other expenses included the installation of a dehydrator and the
workover expenses at the North Dauphin Island Field.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization expense for 1996 was $9.8 million
compared to $10.4 million for 1995. When compared on a per unit-of-production
basis, the expense incurred was $1.01 per Mcfe produced for each of the two
years.
General and Administrative Expenses
General and administrative expenses declined from $3.9 million for 1995 to $3.5
million for 1996, as a result of the Company's continued efforts to improve
operational efficiencies.
Interest Expense
Interest expense decreased from $1.8 million in 1995 to $313,000 in 1996. This
expense reduction corresponds with the smaller average monthly outstanding
balance on the long-term debt of the Company for 1995 when compared to 1996.
During the fourth quarter of 1995, the Company used $25.1 million of the
proceeds from the sale of preferred stock to reduce its long-term debt. During
the course of 1996, additional funds advanced under the Company's line of
credit were repaid in November when the Company issued $24,150,000 of 10%
Senior Subordinated Notes. The average outstanding balance in long-term debt
during 1996 was $5.3 million.
Income Taxes
The recorded income tax expense for 1996 was $50,000. The computed provision
for income taxes at the Company's expected statutory rate was $1.9 million,
which was primarily offset by a reduction in the deferred tax asset valuation
allowance as a result of the Company's ability to utilize its net operating
losses and depletion carryovers.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Report of Independent Public Accountants 27
Consolidated Balance Sheets as of the Years Ended
December 31, 1997 and 1996 28
Consolidated Statements of Operations for the Three Years
in the Period Ended December 31, 1997 29
Consolidated Statements of Stockholders' Equity
for the Three Years in the Period Ended December 31, 1997 30
Consolidated Statements of Cash Flows for the Three Years
in the Period Ended December 31, 1997 31
Notes to Consolidated Financial Statements 32-46
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Callon Petroleum Company:
We have audited the accompanying consolidated balance sheets of Callon
Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
1997 and 1996, and the related consolidated statements of operations, stock-
holders' equity and cash flows for each of the three years in the period ended
December 31, 1997. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 financial position of Callon Petroleum
Company and subsidiaries, as of December 31, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
February 20, 1998
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
December 31,
1997 1996
--------- ---------
ASSETS
Current assets:
Cash and cash equivalents $ 15,597 $ 7,669
Accounts receivable 12,168 12,661
Other current assets 723 516
--------- ---------
Total current assets 28,488 20,846
--------- ---------
Oil and gas properties, full cost accounting method:
Evaluated properties 398,046 322,970
Less accumulated depreciation, depletion and amortization (282,891) (266,716)
--------- ---------
115,155 56,254
Unevaluated properties excluded from amortization 35,339 26,235
--------- ---------
Total oil and gas properties 150,494 82,489
Pipeline and other facilities, net 6,504 6,618
Other property and equipment, net 1,938 1,594
Deferred tax asset 1,248 5,412
Long-term gas balancing receivable 242 660
Other assets, net 1,507 901
--------- ---------
Total assets $ 190,421 $ 118,520
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 12,389 $ 8,273
Undistributed oil and gas revenues 2,259 2,260
Accrued net profits interest payable (Note 9) 1,121 5,435
--------- ---------
Total current liabilities 15,769 15,968
--------- ---------
Long-term debt 60,250 24,250
Deferred income 297 48
Long-term gas balancing payable 404 390
--------- ---------
Total liabilities 76,720 40,656
--------- ---------
Stockholders' equity:
Preferred Stock, $0.01 par value; 2,500,000 shares authorized;
1,315,500 shares of Convertible Exchangeable
Preferred Stock, Series A issued and outstanding with a
liquidation preference of $32,887,500 (Note 11) 13 13
Common Stock, $0.01 par value; 20,000,000
shares authorized; 7,855,216 and 5,758,667 shares
outstanding at December 31, 1997 and 1996, respectively 79 58
Unearned compensation - restricted stock (2,232) --
Capital in excess of par value 106,433 74,027
Retained earnings 9,408 3,766
--------- ---------
Total stockholders' equity 113,701 77,864
--------- ---------
Total liabilities & stockholders' equity $ 190,421 $ 118,520
========= =========
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 1997, 1996 and 1995
(In thousands, except per share amounts)
1997 1996 1995
-------- -------- --------
Revenues:
Oil and gas sales $ 42,130 $ 25,764 $ 23,210
Interest and other 1,508 946 627
-------- -------- --------
Total revenues 43,638 26,710 23,837
-------- -------- --------
Costs and expenses:
Lease operating expenses 8,123 7,562 6,732
Depreciation, depletion and amortization 16,488 9,832 10,376
General and administrative 4,433 3,495 3,880
Interest 1,957 313 1,794
-------- -------- --------
Total costs and expenses 31,001 21,202 22,782
-------- -------- --------
Income from operations 12,637 5,508 1,055
Income tax expense 4,200 50 --
-------- -------- --------
Net income 8,437 5,458 1,055
Preferred stock dividends 2,795 2,795 256
-------- -------- --------
Net income available to common shares $ 5,642 $ 2,663 $ 799
======== ======== ========
Net income per common share:
Basic $ .91 $ .46 $ .14
Diluted $ .88 $ .45 $ .14
Shares used in computing net income per common share:
Basic 6,194 5,835 5,755
Diluted 6,422 5,952 5,755
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Unearned
Compensation Capital in
Preferred Common Restricted Excess of Retained
Stock Stock Stock Par Value Earnings
---------- ---------- ---------- ---------- ----------
Balances, December 31, 1994 $ -- $ 58 $ -- $ 43,069 $ 304
Net income -- -- -- -- 1,055
Sale of preferred stock (Note 11) 13 -- -- 30,886 --
Preferred stock dividends -- -- -- -- (256)
-------- -------- -------- -------- --------
Balances, December 31, 1995 13 58 -- 73,955 1,103
Net income -- -- -- -- 5,458
Preferred stock dividends -- -- -- -- (2,795)
Shares issued pursuant to employee
benefit plan -- -- -- 72 --
-------- -------- -------- -------- --------
Balances, December 31, 1996 13 58 -- 74,027 3,766
Net income -- -- -- -- 8,437
Sale of common stock -- 19 -- 29,249 --
Preferred stock dividends -- -- -- -- (2,795)
Tax benefits related to stock
compensation plans -- -- -- 36 --
Shares issued pursuant to employee
benefit and option plan -- -- -- 392 --
Restricted stock issued to officers -- 2 (3,153) 2,729 --
Earned portion of restricted stock -- -- 921 -- --
-------- -------- -------- -------- --------
Balances, December 31, 1997 $ 13 $ 79 $ (2,232) $106,433 $ 9,408
======== ======== ======== ======== ========
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1997, 1996 and 1995
(In thousands)
1997 1996 1995
--------- --------- ---------
Cash flows from operating activities:
Net income $ 8,437 $ 5,458 $ 1,055
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 16,924 10,131 10,600
Amortization of deferred costs 467 114 133
Deferred income tax expense 4,200 50 --
Noncash compensation related to stock compensation plans 1,224 72 --
Changes in current assets & liabilities:
Accounts receivable 493 (4,332) 566
Other current assets (207) (278) (217)
Current liabilities (3,809) 4,049 (2,570)
Change in gas balancing receivable 418 (41) 115
Change in gas balancing payable 14 ( 42) (127)
Change in other long-term liabilities 249 (28) (42)
Change in other assets, net (1,073) (830) (61)
--------- --------- ---------
Cash provided by operating activities 27,337 14,323 9,452
--------- --------- ---------
Cash flows from investing activities:
Capital expenditures (89,609) (37,637) (24,323)
Cash proceeds from sale of mineral interests 4,450 1,574 86
--------- --------- ---------
Cash used in investing activities (85,159) (36,063) (24,237)
--------- --------- ---------
Cash flows from financing activities:
Change in accrued liabilities for capital expenditures 3,610 3,346 --
Equity issued by conversion of stock options 90 -- --
Payments on debt (49,200) (25,850) (25,134)
Proceeds from debt issuance 85,200 50,000 6,000
Common stock canceled (422) -- --
Sale of preferred stock -- -- 30,899
Sale of common stock 29,267 -- --
Increase in accrued preferred stock dividends payable -- 443 256
Dividends on preferred stock (2,795) (2,795) (256)
--------- --------- ---------
Cash provided by financing activities 65,750 25,144 11,765
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 7,928 3,404 (3,020)
Cash and cash equivalents:
Balance, beginning of period 7,669 4,265 7,285
--------- --------- ---------
Balance, end of period $ 15,597 $ 7,669 $ 4,265
========= ========= =========
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Callon Petroleum Company (the "Company") 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 (the "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 7.
The Company and its predecessors have been engaged in the acquisition, develop-
ment and exploration of crude oil and natural gas since 1950. The Company's
properties are geographically concentrated in Louisiana, Alabama and offshore
Gulf of Mexico.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Reporting
The Consolidated Financial Statements include the accounts of the Company, and
its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has
subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing,
Inc. All intercompany accounts and transactions have been eliminated. Certain
prior year amounts have been reclassified to conform to presentation in the
current year.
Use of Estimates
The preparation of financial statements in conformity with 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.
Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued Statement No.
130 ("FAS 130"), Reporting Comprehensive Income. FAS 130 establishes
standards for reporting and display of comprehensive income and its
components in a full set of general purpose financial statements. FAS 130 is
effective for fiscal years beginning after December 15, 1997. The Company
intends to comply with the provisions of FAS 130.
Also in 1997, the Financial Accounting Standards Board issued Statement No.
131 ("FAS 131"), Disclosures about Segments of an Enterprise and Related
Information. FAS 131 establishes standards for the way that public business
enterprises report information about operating segments in annual financial
statements and requires that those enterprises report selected information
about operating segments in interim financial reports issued to shareholders.
It also establishes standards for related disclosures about products and
services, geographic areas, and major customers. This Statement is effective
for financial statements for periods beginning after December 15, 1997. The
Company intends to comply with the provisions of FAS 131.
During early 1997, the Financial Accounting Standards Board issued Statement
No. 129 ("FAS 129"). Disclosure of Information about Capital Structure:
effective for financial statements issued for periods ending after December
15, 1997. The Company believes it is in compliance with the provisions of
this statement.
Property and Equipment
The Company follows the full cost method of accounting for oil and gas
properties whereby all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves, including certain
overhead costs, are capitalized. Such amounts include the cost of drilling
and equipping productive wells, dry hole costs, lease acquisition costs, delay
rentals, interest capitalized on unevaluated leases and other costs related to
exploration and development activities. Payroll and 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. Costs associated with unevaluated
properties are excluded from amortization. Unevaluated property costs are
transferred to evaluated property costs at such time as wells are completed
on the properties, the properties are sold or management determines these costs
have been impaired.
Costs of properties, including future development and net future site restora-
tion, dismantlement and abandonment costs, which have proved reserves and those
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 amortization, exceed the sum of (1) the estimated
future net revenues from proved reserves at current prices and discounted at
10% and (2) the cost of unevaluated properties (the full cost ceiling amount),
then such excess is charged to expense during the period in which the excess
occurs.
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 geological, engineering and regulatory data
available. Such cost estimates are periodically updated for changes in
conditions and requirements. Such estimated amounts are considered as part
of the full cost pool subject to amortization upon acquisition or discovery.
Such costs are capitalized as oil and gas properties as the actual restora-
tion, dismantlement and abandonment activities take place. As of December 31,
1997 and 1996, estimated future site restoration, dismantlement and abandon-
ment costs, net of related salvage value and amounts funded by abandonment
trusts (see Notes 7 and 9) were not material.
Depreciation of other property and equipment is provided using the straight-
line method over estimated lives of three to twenty years. Depreciation of
the pipeline and other facilities is provided using the straight-line method
over estimated lives of 15 to 27 years.
Natural Gas Imbalances
The Company follows an 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 conversely recording a
liability to the extent that a well is in an "overtake" position.
Derivatives
The Company uses derivative financial instruments (see Note 6) for price
protection purposes on a limited amount of its future production, and does not
use them for trading purposes. Such derivatives are accounted for on an accrual
basis and amounts paid or received under the agreements are recognized as oil
and gas sales in the period in which they accrue.
Reserve for Doubtful Accounts
The balance in the reserve for doubtful accounts included in accounts receivable
is $36,000 and $393,000 at December 31, 1997 and 1996, respectively. Net charge
offs were $357,000 and $88,000 in 1997 and 1996 and net recoveries were $2,000
in 1995. There were no provisions to expense in the three year period ended
December 31, 1997.
Statements of Cash Flows
For purposes of the Consolidated Statements of Cash Flows, the Company considers
all highly liquid investments purchased with an original maturity of three
months or less to be cash equivalents.
The Company paid no federal income taxes for the three years ended December 31,
1997. During the years ended December 31, 1997, 1996 and 1995, the Company
made cash payments of $4,167,000, $251,000 and $1,910,000, respectively, for
interest charged on its indebtedness.
Per Share Amounts
In February 1997, the Financial Accounting Standards Board issued Statement No.
128 ("FAS 128"), Earnings per Share, which generally simplified the manner in
which earnings per share are determined. The Company adopted FAS 128 effective
December 15, 1997. In accordance with FAS 128, the Company's previously
reported earnings per share for 1996 and 1995 were restated. The effect of this
accounting change on previously reported earnings per share (EPS) data was as
follows:
Per share amounts: 1996 1995
-------- ---------
Primary EPS as reported $ .45 $ .14
Effect of FAS 128 .01 --
-------- ---------
Basic EPS as restated $ .46 $ .14
======== =========
Fully diluted EPS as reported $ .43 $ .14
Effect of FAS 128 .02 --
-------- ---------
Diluted EPS as restated $ .45 $ .14
======== =========
Basic earnings per common share were computed by dividing net income by the
weighted average number of shares of common stock outstanding during the year.
Diluted earnings per common share for the years 1997 and 1996 were determined
on a weighted average basis using common shares issued and outstanding adjusted
for the effect of stock options considered common stock equivalents computed
using the treasury stock method. The stock options outstanding in 1995 were
not considered common stock equivalents. The conversion of the preferred
stock was not included in any annual calculation due to their antidilutive
effect on diluted income per share.
A reconciliation of the basic and diluted per share computation is as follows
(in thousands, except per share amounts):
1997 1996 1995
(a) Net income available for common stock $ 5,642 $ 2,663 $ 799
(b)Weighted average shares outstanding 6,194 5,835 5,755
(c)Dilutive impact of stock options 228 117 --
(d)Total diluted shares 6,422 5,952 5,755
Basis earnings per share (a/b) $ 0.91 $ 0.46 $ 0.14
Dilute earnings per share (a/d) $ 0.88 $ 0.45 $ 0.14
Fair Value of Financial Instruments
Fair value of cash, cash equivalents, accounts receivable, accounts payable and
long-term debt approximate book value at December 31, 1997 and 1996. Fair value
of long-term debt (specifically the 10% and the 10.125% senior subordinated
notes) was based on quoted market value.
3. INCOME TAXES
The Company follows the asset and liability method of accounting for deferred
income taxes prescribed by Financial Accounting Standards Board Statement No.
109 ("FAS 109") "Accounting for Income Taxes". The statement provides for the
recognition of a deferred tax asset for deductible temporary timing differences,
capital and operating loss carryforwards, statutory depletion carryforward and
tax credit carryforwards, net of a "valuation allowance". The valuation allow-
ance is provided for that portion of the asset, for which it is deemed more
likely than not, that it will not be realized. The Company's management
determined that no valuation allowance was necessary in 1997 and 1996. Accord-
ingly, the Company has recorded a deferred tax asset at December 31, 1997,
1996 and 1995 as follows:
December 31,
1997 1996 1995
------ ------ ------
(In thousands)
Federal net operating loss carryforward $ 3,531 $ 3,441 $ 3,563
Statutory depletion carryforward 4,062 4,089 3,987
Temporary differences:
Oil and gas properties (4,943) (680) 874
Pipeline and other facilities (2,277) (2,316) (1,880)
Non-oil and gas property (86) (20) 23
Other 961 898 655
Total tax asset 1,248 5,412 7,222
Valuation allowance -- -- (1,760)
------- ------- -------
Net tax asset $ 1,248 $ 5,412 $ 5,462
======= ======= =======
At December 31, 1997, the Company had, for tax reporting purposes, operating
loss carryforwards ("NOL") of $10.1 million which expire in 2000 through 2012.
Approximately $5.0 million of such carryovers are subject to limitations on
utilization as a result of ownership changes which occurred in CPOC's common
stock prior to the Consolidation and ownership changes as a result of the
Consolidation. Additionally, the Company had available for tax reporting
purposes $11.6 million in statutory depletion deductions which can be carried
forward for an indefinite period.
The provision for income taxes at the Company's effective tax rate differed
from the provision for income taxes at the statutory rate as follows:
December 31,
1997 1996 1995
------ ------ ------
(In thousands)
Computed expense at the expected
statutory rate $ 4,296 $ 1,910 $ 369
Change in valuation allowance -- (1,760) (551)
Other (96) (100) 182
------- ------- ------
Income tax expense $ 4,200 $ 50 $ --
======= ======= ======
4. ACQUISITIONS
On December 29, 1995, CPOC purchased a 66.67% working interest in Chandeleur
Block 40 (the "CB 40 Acquisition") from Amerada Hess Corporation and, in a
simultaneous transaction under a pre-existing agreement, sold one-third of
the acquired interest to an industry partner. The Company's net purchase
price of $6 million was funded from existing cash on hand.
On June 26, 1997 the Company purchased an 18.8% working interest in the Mobile
Block 864 Area from Elf Exploration, Inc. The Company's net purchase price of
approximately $11.8 million. The Company further increased its ownership in
this area by purchasing Chevron U.S.A. Inc.'s interest in the Mobile Block 864
Area for $21 million, effective July 1, 1997 and closed in November 1997 for a
net acquisition cost of $18.8 million. Both acquisitions were funded from the
Company's credit facility.
The Company, together with an industry partner, was the high bidder on 18 off-
shore tracts at the Outer Continental Shelf ("OCS") Lease Sale #157 and #161,
held during 1996 in New Orleans, Louisiana, and conducted by the U. S. Depart-
ment of the Interior through its Minerals Management Service ("MMS"). The
Company holds a 25% working interest in the leases and its share of the total
lease costs was approximately $15.2 million.
5. LONG-TERM DEBT
Long-term Debt consisted of the following at:
December 31,
1997 1996
------ ------
(In thousands)
Credit Facility $ 100 $ 100
10% Senior Subordinated Notes 24,150 24,150
10.125% Senior Subordinated Notes 36,000 --
-------- --------
60,250 24,250
Less: current portion -- --
-------- --------
$ 60,250 $ 24,250
======== ========
Effective October 31, 1996, the Company entered into a new Credit Facility with
Chase Manhattan Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. Currently, the Credit Facility provides for borrowings of a
maximum of the lesser of $50 million or a $35 million borrowing base ("Borrowing
Base") which is adjusted periodically on the basis of a discounted present value
of future net cash flows attributable to the Company's proved producing oil and
gas reserves. Pursuant to the Credit Facility, depending upon the percentage
of the unused portion of the Borrowing Base, the interest rate is equal to
either the lender's prime rate or the lender's prime rate plus 0.50%. The
Company, at its option, may fix the interest rate on all or a portion of the
outstanding principal balance at either 1.00% or 1.375% above a defined
"Eurodollar" rate, depending upon the percentage of the unused portion of the
Borrowing Base, for periods of up to six months. The weighted average interest
rate for the total debt outstanding at December 31, 1997 and 1996 was 8.50% and
8.25%, respectively. Under the Credit Facility, a commitment fee of .25% or
.375% per annum on the unused portion of the Borrowing Base (depending upon the
percentage of the unused portion of the Borrowing Base) is payable quarterly.
The Company may borrow, pay, reborrow and repay under the Credit Facility until
October 31, 2000, on which date, the Company must repay in full all amounts then
outstanding.
On November 27, 1996, the Company issued $24,150,000 of 10% Senior Subordinated
Notes that will mature December 15, 2001. The Company used the proceeds to
reduce borrowings under the Credit Facility and for other corporate purposes.
Interest is payable quarterly beginning March 15, 1997. The notes are redeem-
able at the option of the Company, in whole or in part, on or after December
15, 1997, at 100% of the principal amount thereof, plus accrued interest to the
redemption date. The notes are general unsecured obligations of the Company,
subordinated in right of payment to all existing and future indebtedness of the
Company.
On July 31, 1997, the Company issued $36 million of its 10.125% Series A Senior
Subordinated Notes due 2002. Interest is payable quarterly beginning September
15, 1997. The Senior Subordinated Notes were offered through a private place-
ment transaction. The net proceeds of the transaction were used to repay the
outstanding balance under the Credit Facility and fund a portion of the
Company's capital expenditure budget. On September 10, 1997, pursuant to a
Registration Agreement dated July 31, 1997, the Company commenced an offer
to exchange the Series A Notes for a like principal amount of 10.125% Series B
Senior Subordinated Notes due 2002 (the "Series B Notes" and, together with the
Series A Notes, the "10.125% Notes"). The form and terms of the Series B Notes
are identical in all material respects to the terms of the Series A Notes,
except for certain transfer restrictions and provisions relating to registra-
tion rights. The exchange offer was completed on November 10, 1997. Interest
on the 10.125% Notes is payable quarterly, on March 15, June 15, September 15,
and December 15 of each year. The 10.125% Notes are redeemable at the option
of the Company in whole or in part, at any time on or after September 15, 2000.
The 10.125% Notes are general unsecured obligations of the Company, subordinated
in right of payment to all existing and future indebtedness of the Company and
rank pari passu with the 10% Notes.
The Credit Facility and the subordinated debt contain various covenants includ-
ing restrictions on additional indebtedness and payment of cash dividends as
well as maintenance of certain financial ratios. The Company is in compliance
with these covenants at December 31, 1997.
6. HEDGING CONTRACTS
The Company periodically uses derivative financial instruments to manage oil
and gas price risk. Settlements of gains and losses on commodity price swap
contracts are generally based upon the difference between the contract price
or prices specified in the derivative instrument and a NYMEX price or other
cash or futures index price, and are reported as a component of oil and gas
revenues. Gains or losses attributable to the termination of a swap contract
are deferred and recognized in revenue when the oil and gas is sold.
As of December 31, 1997, the Company had open collar contracts with third
parties whereby minimum floor prices and maximum ceiling prices are
contracted and applied to related contract volumes. These agreements in
effect for 1998 are for average gas volumes of 229,000 Mcf per month through
September of 1998 at (on average) a ceiling price of $2.89 and floor of $2.24.
During 1995, the Company recognized revenue under swap agreements of $2,466,000
and recognized a reduction in revenue of $2,757,195 for the year ended December
31, 1996 under all contracts. For the twelve months ending December 31, 1997,
$76,000 of net expense was recognized.
The calculation of the fair market value of the outstanding contracts as of
December 31, 1997 indicated a $215,000 market value benefit to the Company based
on market prices at that date.
7. COMMITMENTS AND CONTINGENCIES
As described in Note 9, abandonment trusts (the "Trusts") have been established
for future abandonment obligations of those oil and gas properties of the
Company burdened by a net profits interest. The management of the Company
believes the Trusts will be sufficient to offset those future abandonment
liabilities; however, the Company is responsible for any abandonment expenses
in excess of the Trusts' balances. As of December 31, 1997, total estimated
site restoration, dismantlement and abandonment costs were approximately $19.3
million, net of expected salvage value. Substantially all such costs are
expected to be funded through the Trusts' funds, all of which will be accessible
to the Company when abandonment work begins. In addition as a working interest
owner and/or operator of oil and gas properties, the Company is responsible for
the cost of abandonment of such properties, see Note 2.
The Company, as part of the Consolidation, entered into Registration Rights
Agreements whereby the former stockholders of certain of the Constituent
Entities are entitled to require the Company to register Common Stock of the
Company owned by them with the Securities and Exchange Commission for sale to
the public in a firm commitment public offering 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 discounts and commissions, which will
be paid by the respective sellers of the Common Stock.
8. OIL AND GAS PROPERTIES
The following table discloses certain financial data relating to the Company's
oil and gas activities, all of which are located in the United States.
Year Ended December 31,
1997 1996 1995
-------- -------- --------
(In thousands)
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance $ 322,970 $ 304,737 $ 285,976
Property acquisition costs 51,751 2,999 14,017
Exploration costs 13,620 8,732 785
Development costs 14,155 8,076 4,045
Sale of mineral interest (4,450) (1,574) (86)
---------- ---------- ----------
End of period balance $ 398,046 $ 322,970 $ 304,737
========== ========== ==========
Unevaluated Properties-
Beginning of period balance $ 26,235 $ 10,171 $ 4,919
Additions, net of transfers
to evaluated 7,125 15,714 5,252
Capitalized interest 1,979 350 --
---------- ---------- ----------
End of period balance $ 35,339 $ 26,235 $ 10,171
========== ========== ==========
Accumulated depreciation, depletion
and amortization-
Beginning of period balance $ 266,716 $ 257,143 $ 246,975
Provision charged to expense 16,175 9,573 10,168
---------- ---------- ----------
End of period balance $ 282,891 $ 266,716 $ 257,143
========== ========== ==========
Depreciation, depletion and amortization per unit-of-production (equivalent
barrel of oil) amounted to $6.11, $5.87 and $5.95 for the years ended December
31, 1997, 1996 and 1995, respectively.
9. NET PROFITS INTEREST
Since 1989, the Constituent Entities have entered into separate agreements to
purchase certain oil and gas properties with gross contract acquisition prices
of $170,000,000 ($150,000,000 net as of closing dates) and in simultaneous
transactions, entered into agreements to sell overriding royalty interests
("ORRI") in the acquired properties. These ORRI are in the form of net profits
interests ("NPI") equal to a significant percentage of the excess of gross
proceeds over production costs, as defined, from the acquired oil and gas
properties. A net deficit incurred in any month can be carried forward to
subsequent months until such deficit is fully recovered. The Company has the
right to abandon the purchased oil and gas properties if it deems the
properties to be uneconomical.
The Company has, pursuant to the purchase agreements, created abandonment trusts
whereby funds are provided out of gross production proceeds from the properties
for the estimated amount of future abandonment obligations related to the
working interests owned by the Company. The Trusts are administered by
unrelated third party trustees for the benefit of the Company's working interest
in each property. The Trust agreements limit their funds to be disbursed for
the satisfaction of abandonment obligations. Any funds remaining in the Trusts
after all restoration, dismantlement and abandonment obligations have been met
will be distributed to the owners of the properties in the same ratio as contri-
butions to the Trusts. The Trusts' assets are excluded from the Consolidated
Balance Sheets of the Company because the Company does not control the Trusts.
Estimated future revenues and costs associated with the NPI and the Trusts are
also excluded from the oil and gas reserve disclosures at Note 12. As of
December 31, 1997 and 1996 the Trusts' assets (all cash and investments)
totaled $19,300,000 and $18,200,000, respectively, all of which will be
available to the Company to pay its portion, as working interest owner, of the
restoration, dismantlement and abandonment costs discussed at Note 7.
At the time of acquisition of properties by the Company, the property owners
estimated the future costs to be incurred for site restoration, dismantlement
and abandonment, net of salvage value. A portion of the amounts necessary to
pay such estimated costs was deposited in the Trusts upon acquisition of the
properties, and the remainder is deposited from time to time out of the proceeds
from production. The determination of the amount deposited upon the acquisition
of the properties and the amount to be deposited as proceeds from production
was based on numerous factors, including the estimated reserves of the
properties. The amounts deposited in the Trusts upon acquisition of the
properties were capitalized by the Company as oil and gas properties.
As operator, the Company receives all of the revenues and incurs all of the
production costs for the purchased oil and gas properties but retains only that
portion applicable to its net ownership share. As a result, the payables and
receivables associated with operating the properties included in the Company's
Consolidated Balance Sheets include both the Company's and all other outside
owner's shares. However, revenues and production costs associated with the
acquired properties reflected in the accompanying Consolidated Statements of
Operations represent only the Company's share, after reduction for the NPI.
10. 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 stock-
holders. The following is a brief description of each plan:
- - The Savings and Protection Plan provides employees with the option to defer
receipt of a portion of their compensation and the Company may, at its
discretion, match a portion of the employee's deferral with cash and Company
Common Stock. The Company may also elect, at its discretion, to contribute
a non-matching amount in cash and Company Common Stock to employees. The
amounts held under the Savings and Protection Plan are invested in various
funds maintained by a third party in accordance with the directions of each
employee. An employee is fully vested immediately upon participation in the
Savings and Protection Plan. The total amounts contributed by the Company,
including the value of the common stock contributed, were $438,000,
$241,000, and $176,000 in the years 1997, 1996 and 1995, respectively.
- - The 1994 Stock Incentive Plan (the "1994 Plan") provides for 600,000 shares
of Common Stock to be reserved for issuance pursuant to such plan. Under
the 1994 Plan the Company may grant both stock options qualifying under
Section 422 of the Internal Revenue Code and options that are not qualified
as incentive stock options, as well as performance shares. No options will
be granted at an exercise price of less than fair market value of the Common
Stock on the date of grant. A total of 500,000 options were outstanding and
all such options could be exercised as of December 31, 1996. During 1997,
there were no other options granted and 9,000 shares were exercised at an
average price of $17.94. These options have an expiration date 10 years
from date of grant.
- - 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 provides for the same types of awards as the 1994
Plan and is limited to a maximum of 900,000 shares of common stock that
may be subject to outstanding awards. During 1997 and 1996, the Company
granted stock options to purchase 20,000 and 530,000 shares, respectively,
of Common Stock under the plan. All of such options were granted at an
exercise price equal to the fair market value of the Common Stock on the
date of grant. Terms of the plan for 450,000 options provide that 20% of
the options become exercisable on January 1 of each succeeding year,
beginning January 1, 1997. Non-employee director options aggregating
80,000 shares vest 25% at each succeeding annual meeting of directors
following each annual stockholders' meeting, beginning in 1997. Unvested
options are subject to forfeiture upon certain termination of employment
events and expire 10 years from date of grant.
The Company accounts for the options issued pursuant to the stock incentive
plans under APB Opinion No. 25, under which no compensation cost has been
recognized. Had compensation cost for these plans been determined consistent
with FAS 123, the Company's net income and earnings per common share would
have been reduced to the following pro forma amounts:
1997 1996 1995
-------- -------- --------
(In thousands, except per share data)
Net income: As Reported $ 5,642 $ 2,663 $ 799
Pro Forma 4,977 2,411 677
Basic per share: As Reported .91 0.46 0.14
Pro Forma .80 0.41 0.12
Diluted per share: As Reported .88 0.45 0.14
Pro Forma .77 0.41 0.12
Because the Statement 123 method of accounting has not been applied to options
granted prior to January 1, 1995, the resulting pro forma compensation cost
above may not be representative of that to be expected in future years.
A summary of the status of the Company's two stock option plans at December 31,
1997, 1996 and 1995 and changes during the years then ended is presented in
the table and narrative below:
1997 1996 1995
------------------- ------------------- --------------------
Wtd Avg Wtd Avg Wtd Avg
Shares Ex Price Shares Ex Price Shares Ex Price
--------- -------- --------- -------- --------- --------
Outstanding,
beginning of year 1,030,000 $ 11.10 490,000 $ 10.01 460,000 $ 10.00
Granted 20,000 15.31 550,000 12.06 30,000 10.08
Exercised (9,000) 10.00 -- -- -- --
Forfeited -- -- (10,000) 10.00 -- --
Expired -- -- -- -- -- --
--------- ------- --------- ------- --------- --------
Outstanding, end of year 1,041,000 $ 11.19 1,030,000 $ 11.10 490,000 $ 10.01
========= ======= ========= ======= ========= ========
Exercisable, end of year 621,000 $ 10.65 500,000 $ 10.16 490,000 $ 10.01
========= ======= ========= ======= ========= ========
Weighted average fair value
of options granted $ 6.30 $ 4.96 $ 4.05
========= ========= =========
The options outstanding at December 31, 1997 have exercise prices ranging from
$9.75 to $15.31 with a remaining weighted average contractual life of 7.73
years.
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for options granted during 1997, 1996 and 1995.
Weighted Average Assumptions
1997 1996 1995
------ ------ ------
Risk free interest rate 6.8% 6.5% 6.6%
Expected life (years) 4.0 4.9 5.0
Expected volatility 41.1% 34.7% 32.0%
Expected dividends -- -- --
The Company awarded 225,000 performance shares under the 1996 Plan to the
Company's Executive officers on August 23, 1996. During June 1997, the
Company's stockholders approved the performance share awards and the related
common stock was issued. The issuance was recorded at the fair market value
of the shares on their date of grant, with a corresponding charge to stock-
holder's equity representing the unearned portion of the award. All of the
performance shares granted will vest in whole on January 1, 2001, and will be
subject to forfeiture upon certain termination of employment events. The
unearned portion is being amortized as compensation expense on a straight-
line basis over the vesting period. An additional 25,000 shares were issued
under the 1994 Plan in 1997. Approximately $714,000 in 1997 and $208,000 in
1996 of compensation cost were charged to expense related to the restricted
shares granted.
11. EQUITY TRANSACTIONS
In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible
Exchangeable Preferred Stock, Series A (the "Preferred Stock"). Annual
dividends are $2.125 per share and are cumulative. The net proceeds of the
$.01 par value stock after underwriters discount and expense was $30,899,000.
Each share has a liquidation preference of $25.00, plus accrued and unpaid
dividends. Dividends on the Preferred Stock are cumulative from the date of
issuance and are payable quarterly, commencing January 15, 1996. The
Preferred Stock is convertible at any time, at the option of the holders
thereof, unless previously redeemed, into shares of Common Stock of the
Company at an initial conversion price of $11 per share of Common Stock,
subject to adjustments under certain conditions.
The Preferred Stock is redeemable at any time on or after December 31, 1998, in
whole or in part at the option of the Company at a redemption price of $26.488
per share beginning at December 31, 1998 and at premiums declining to the
$25.00 liquidation preference by the year 2005 and thereafter, plus accrued
and unpaid dividends. The Preferred Stock is also exchangeable, in whole, but
not in part, at the option of the Company on or after January 15, 1998 for the
Company's 8.5% Convertible Subordinated Debentures due 2010 (the "Debentures")
at a rate of $25.00 principal amount of Debentures for each share of Preferred
Stock. The Debentures will be convertible into Common Stock of the Company on
the same terms as the Preferred Stock and will pay interest semi-annually.
On November 25, 1997, the Company completed a public offering of 1,840,000
shares at a price to the public of $17.00. This offering resulted in the
Company receiving cash proceeds of $29,267,000, net of offering costs and
underwriting discount. The Company used a portion of the proceeds to repay
indebtedness incurred to finance the purchase of Chevron U.S.A. Inc.'s interest
in Mobile Block 864 Area (see Note 4) and the remaining proceeds will be used
to fund a portion of the 1998 capital expenditures budget.
12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 1997, 1996 and 1995
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("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 represent estimates only and should not
be construed as being exact. In addition, the present values should not be
construed as the current market value of the Company's oil and gas properties
or the cost that would be incurred to obtain equivalent reserves.
Estimated Reserves
Changes in the estimated net quantities of crude oil and natural gas reserves,
all of which are located onshore and offshore in the continental United States,
are as follows:
Reserve Quantities
Year Ended December 31,
1997 1996 1995
------ ------ ------
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period 3,819 4,766 4,424
Revisions to previous estimates (151) (50) (441)
Purchase of reserves in place -- -- 1,363
Sales of reserves in place (78) (312) (2)
Extensions and discoveries 274 -- 16
Production (462) (585) (594)
------ ------ ------
End of period 3,402 3,819 4,766
====== ====== ======
Natural Gas (MMcf):
Beginning of period 50,424 29,667 24,102
Revisions to previous estimates (11,174) (1,688) (976)
Purchase of reserves in place 52,485 7,391 12,985
Sales of reserves in place (164) (228) (22)
Extensions and discoveries 10,281 21,551 271
Production (13,114) (6,269) (6,693)
------ ------ ------
End of period 88,738 50,424 29,667
====== ====== ======
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period 3,385 3,890 3,309
End of period 2,976 3,385 3,890
Natural Gas (MMcf):
Beginning of period 49,491 20,408 20,582
End of period 88,010 49,491 20,408
Standardized Measure
The following tables present the Company's standardized measure of discounted
future net cash flows and changes therein relating to proved oil and gas
reserves and were computed using reserve valuations based on regulations
prescribed by the SEC. These regulations provide that the oil, condensate and
gas price structure utilized to project future net cash flows reflects current
prices at each date presented and have been escalated only when known and
determinable price changes are provided by contract and law. Future produc-
tion, development and net abandonment costs are based on current costs without
escalation. In 1995 no future income taxes were provided on the future net
inflows as tax credits (including carryovers) and other permanent differences
were expected to be higher than the estimated future income taxes calculated
using the appropriate statutory rates. The resulting net future cash flows
have been discounted to their present values based on a 10% annual discount
factor.
Standardized Measure
December 31,
1997 1996 1995
-------- -------- --------
(In thousands)
Future cash inflows $285,953 $285,727 $157,240
Future costs -
Production (63,709) (59,584) (50,236)
Development and net abandonment (12,984) (9,989) (11,274)
-------- -------- --------
Future net inflows before income taxes 209,260 216,154 95,730
Future income taxes (32,781) (49,438) --
-------- -------- --------
Future net cash flows 176,479 166,716 95,730
10% discount factor (48,400) (36,547) (31,966)
-------- -------- --------
Standardized measure of discounted
future net cash flows $128,079 $130,169 $ 63,764
======== ======== ========
Changes in Standardized Measure
Year Ended December 31,
1997 1996 1995
-------- -------- --------
(In thousands)
Standardized measure - beginning of period $130,169 $ 63,764 $ 41,383
Sales and transfers, net of production costs (34,006) (18,202) (12,477)
Net change in sales and transfer prices,
net of production costs (66,880) 32,268 11,519
Exchange and sale of in place reserves (2,428) (877) (23)
Purchases, extensions, discoveries, and
improved recovery, net of future
production and development costs 90,550 79,983 28,204
Revisions of quantity estimates (13,751) (3,907) (4,242)
Accretions of discount 16,017 6,376 2,963
Net change in income taxes 21,633 (30,000) --
Changes in production rates, timing and other (13,225) 764 (3,563)
-------- -------- --------
Standardized measure - end of period $128,079 $130,169 $ 63,764
======== ======== ========
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors and Executive Officers of the Company
The Company currently has a Board of Directors composed of seven members. In
accordance with the Certificate of Incorporation of the Company, as amended
(the "Charter"), the members of the Board of Directors are divided into three
classes, Class I, Class II and Class III, and are elected for a full term of
office expiring at the third succeeding annual stockholders' meeting following
theirelection to office and when a successor is duly elected and qualified.
The terms of office of the Class I, Class II and Class III directors expire at
the annual meeting of stockholders in 1998, 1999, and 2000, respectively. The
Charter also provides that such classes shall be as nearly equal in number as
possible. At December 31, 1997, the directors and executive officers of the
Company were as follows:
Company
Name Age Position Since Present Company Position
John S. Callon 77 1994 Director (Class II); Chairman of the Board
Fred L. Callon 47 1994 Director (Class III); President; Chief
Executive Officer
Dennis W. Christian 51 1994 Director (Class III); Senior Vice President;
Chief Operating Officer
Robert A. Stanger 58 1995 Director (Class I)
John C. Wallace 59 1994 Director (Class I)
B. F. Weatherly 53 1994 Director (Class II)
Richard O. Wilson 67 1995 Director (Class I)
John S. Weatherly 45 1994 Senior Vice President; Chief Financial
Officer; Treasurer
James O. Bassi 43 1997 Vice President and Controller
Thomas E. Schwager 46 1997 Vice President, Engineering and Operations
H. Michael Tatum, Jr. 69 1994 Vice President; Secretary
Kathy G. Tilley 52 1996 Vice President, Acquisitions/New Ventures
Stephen F. Woodcock 46 1997 Vice President, Exploration
All of the Directors, other than Messrs. Stanger and Wilson, have served as directors since the
Company's inception. Messrs. Stanger and Wilson have served as directors since March 2, 1995.
The following is a brief description of the background and principal occupation
of each director and executive officer:
John S. Callon is Chairman of the Board of Directors of the Company and Callon
Petroleum Operating. Effective January 2, 1997, John S. Callon retired from his
position as Chief Executive Officer of the Company. Mr. Callon founded the
Company's predecessors in 1950, and has held an executive office with the
Company or its predecessors since that time. He has served as a director of
the Mid-Continent Oil and Gas Association and as the President of the
Association's Mississippi-Alabama Division. He has also served as Vice
President for Mississippi of the Independent Petroleum Association of America.
He is a member ofthe American Petroleum Institute. Mr. Callon is the uncle of
Fred L. Callon.
Fred L. Callon is President and Chief Executive Officer of the Company and
Callon Petroleum Operating Company ("Callon Petroleum Operating") and has held
that position with the Company or its predecessors since 1984. He has been
employed by the Company or its predecessors since 1976. He graduated from
Millsaps College in 1972 and received his M.B.A. degree from the Wharton School
of Finance in 1974. Following graduation and until his employment by Callon
Petroleum Operating, he was employed by Peat, Marwick, Mitchell & Co., certified
public accountants. He is a certified public accountant and is a member of the
American Institute of Certified Public Accountants and the Mississippi Society
of Certified Public Accountants. He is the nephew of John S. Callon.
Dennis W. Christian is Senior Vice President and Chief Operating Officer for
the Company and Callon Petroleum Operating. Prior to January 1997, he was
Senior Vice President of Operations and Acquisitions and has held that or
similar positions with the Company or its predecessors since 1981. Prior to
joining Callon Petroleum Operating, he was resident manager in Stavanger,
Norway, for Texas Eastern Transmission Corporation. Mr. Christian received
his B.S. degree in petroleum engineering in 1969 from Louisiana Polytechnic
Institute. His previous experience includes five years with Chevron U.S.A.
Inc.
Robert A. Stanger has been the managing general partner since 1978 of Robert A.
Stanger & Company, Inc., a Shrewsbury, New Jersey-based firm engaged in
publishing financial material and providing investment banking services to
the real estate and oil and gas industries. He is a director of Citizens
Utilities, Stamford, Connecticut, a provider of telecommunications, electric,
gas, and water services and Electric Lightwaves, Inc., Seattle, Washington,
a regional fiber optic telephone company. Previously, Mr. Stanger was Vice
President of Merrill Lynch & Co. He received his B.A. degree in economics
from Princeton University in 1961. Mr. Stanger is a member of the National
Association of Securities Dealers and the New York Society of Security
Analysts.
John C. Wallace is a Chartered Accountant having qualified with Coopers and
Lybrand in Canada in 1963 following which he joined Baring Brothers & Co.,
Limited in London England. For more than the last ten years, he has served
as Chairman of Fred. Olsen Ltd., a London-based corporation which he joined
in 1968, where he has specialized in the business of shipping and property
development. He is a director of Fred. Olsen Energy ASA, Oslo, a publicly
held energy service company, Harland & Wolff PLC, Belfast, ASA Ganger Rolf
and Bonheur ASA, Oslo, publicly traded shipping companies. He is also an
executive officer of NOCO Management, Ltd., a general partner of NOCO and
a director of other companies associated with Fred. Olsen Interests.
B. F. Weatherly is a principal of Amerimark Capital Group, Houston, Texas, an
investment-banking firm. He is an executive officer of NOCO Management Ltd.,
the general partner of the general partner of NOCO. Prior to September 1996,
he was Executive Vice President, Chief Financial Officer and a director of
Belmont Constructors, Inc., a Houston, Texas-based industrial contractor
associated with Fred. Olsen Interests. From 1989 to 1991, he was a partner
in Amerimark Capital Corp., a Dallas investment banking firm. He holds a
Master of Accountancy degree from University of Mississippi. He has previously
been associated with Arthur Andersen LLP, and has served as a Senior Vice
President of Weatherford International, Inc. B. F. Weatherly and John S.
Weatherly are brothers.
Richard O. Wilson is an Offshore Consultant. In his 41 years of working in
offshore drilling and construction he spent two years with Zapata Offshore
and 21 years with Brown & Root, Inc. working in various managerial capacities
in the Gulf of Mexico, Venezuela, Trinidad, Brazil, The Netherlands, The United
Kingdom, and Mexico. He was a Director and Senior Group Vice President of
Brown & Root, Inc. and Senior Vice President of Halliburton, Inc. The last
18 years he has been associated with the Fred. Olsen Interests where he
served as Chairman of OGC International PLC, Dolphin A/S, and Dolphin Drilling
Ltd. and Belmont Constructors, Inc. He holds a B.S. degree in civil engineering
from Rice University. Mr. Wilson is a Fellow in the American Society of Civil
Engineers and a member of the Institute of Petroleum, London, England.
John S. Weatherly is Senior Vice President, Chief Financial Officer and
Treasurer for the Company and Callon Petroleum Operating. Prior to April
1996, he was Vice President, Chief Financial Officer and Treasurer of the
Company and has held those positions since 1983. Prior to joining Callon
Petroleum Operating in August 1980, he was employed by Arthur Andersen LLP
as audit manager in the Jackson, Mississippi office. He received his B.B.A.
degree in accounting in 1973 and his M.B.A. degree in 1974 from the University
of Mississippi. He is a certified public accountant and a member of the
American Institute of Certified Public Accountants and the Mississippi Society
of Certified Public Accountants. John S. Weatherly and B. F. Weatherly are
brothers.
James O. Bassi is Vice President and Controller of the Company and Callon
Petroleum Operating. Prior to being appointed to that position in November,
1997, he was Corporate Controller from June, 1997 and prior thereto was
Manager of the accounting department for the Company and Callon Petroleum
Operating. Mr. Bassi has been employed by the Company and its predecessors
for a total of nine years. Prior to his employment by Callon Petroleum
Operating, he was employed by Arthur Andersen LLP. He received his B.S.
degree in accounting in 1976 from Mississippi State University. He is a
member of the American Institute of Certified Public Accountants and the
Mississippi Society of Certified Public Accountants.
Thomas E. Schwager is Vice President of Engineering and Operations for the
Company and Callon Petroleum Operating. Prior to being appointed to that
position in November 1997, he has held engineering positions with the
Company and its predecessors since 1981. Prior to joining the Company,
Mr. Schwager held various engineering positions with Exxon Company USA in
Louisiana and Texas. He received his B.S. degree in petroleum engineering
from Louisiana State University in 1972.
H. Michael Tatum, Jr. is Vice President and Secretary for the Company and Callon
Petroleum Operating and is responsible for management of administrative matters.
Mr. Tatum has held this position with the Company or its predecessors since
1976, and has been employed by Callon Petroleum Operating since 1969. He
graduated from Southern Methodist University in 1967 and is a member of the
American Society of Corporate Secretaries and the Society for Human Resource
Management.
Kathy G. Tilley is Vice President of Acquisitions and New Ventures for the
Company and Callon Petroleum Operating and has held that position since April
1996. She was employed by Callon Petroleum Operating in December 1989 as
Manager of acquisitions and prior thereto, held that or similar positions
as a consultant from 1981. Ms. Tilley received her B. A. degree in economics
from Louisiana State University in 1967.
Stephen F. Woodcock is Vice President of Exploration for the Company and Callon
Petroleum Operating, being appointed to that position in November, 1997. He
has been employed by the Company and Callon Petroleum Operating since 1995,
serving as Manager of geology and geophysics. Prior thereto, he was Manager of
geophysics for CNG Producing Company and division geophysicist for Amoco
Production Company. Mr. Woodcock received his Masters degree in geophysics
from Oregon State University in 1975.
All officers and directors of the Company are United States citizens, except
Mr. Wallace, who is a citizen of Canada.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934, as amended ("Exchange
Act"), requires the Company's directors and executive officers, and persons
who own more than ten percent of a registered class of the Company's equity
securities, to file with the Securities and Exchange Commission ("Commission")
and the National Association of Securities Dealers' Inc. National Market System
("Nasdaq NMS"), initial reports of ownership and reports of changes in ownership
of Common Stock and other equity securities of the Company. Officers, directors
and greater than ten percent stockholders are required by the Commission's
regulations to furnish the Company with copies of all Section 16(a) forms they
filed with the Commission.
To the Company's knowledge, based solely on review of the copies of such reports
furnished to the Company and written representations that no other reports were
required, during the fiscal year ended December 31, 1997, the Company's
officers, directors and greater than ten percent stockholders had complied with
all Section 16(a) filing requirements.
ITEMS 11, 12 &13
For information concerning Item 11 - Executive Compensation. Item 12 - Security
Ownership of Certain Beneficial Owners and Management and Item 13 - Certain
Relationships and Related Transactions, see the definitive Proxy Statement of
Callon Petroleum Company relating to the Annual Meeting of Stockholders on
May 28, 1998 which will be filed with the Securities and Exchange Commission
and is incorporated herein by reference.
PART IV.
ITEM 14. 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 27
through 46.
Report of Independent Public Accountants
Consolidated Balance Sheets as of the Years Ended December 31, 1997
and 1996
Consolidated Statements of Operations for the Three Years in the Period
Ended December 31, 1997
Consolidated Statements of Stockholders' Equity for the Three Years in
the Period Ended December 31, 1997
Consolidated Statements of Cash Flows for the Three Years in the Period
Ended December 31, 1997
Notes to Consolidated Financial Statements
(a) 2. Schedules other than those listed above are omitted because they are
not required, not applicable or the required information is included in the
financial statements or notes thereto.
(a) 3. Exhibits:
2. Plan of acquisition, reorganization, arrangement, liquidation or
succession
2.1 Agreement and Plan of Consolidation dated August 1, 1994 by
and among the Company, Callon Consolidated Partners, L. P.,
Callon Petroleum Operating Company, CN Resources and Wilcox
Energy Company (incorporated by reference from Exhibit 2.1 of
the Registration Statement on Form 8-B filed October 3, 1994)
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended
(incorporated by reference from Exhibit 3.1 of the Company's
Registration Statement on Form S-4, Reg. No. 33-82408)
3.2 Certificate of Merger of Callon Consolidated Partners, L. P.
with and into the Company dated September 16, 1994
3.3 Bylaws of the Company (incorporated by reference from Exhibit
3.2 of the Company's Registration Statement on Form S-4, Reg.
No. 33-82408)
4. Instruments defining the rights of security holders, including
indentures
4.1 Specimen stock certificate (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form
S-4, Reg. No. 33-82408)
4.2 Specimen Preferred Stock Certificate (incorporated by reference
from Exhibit 4.2 of the Company's Registration Statement on
Form S-1, Reg. No. 33-96700)
4.3 Designation for Series A Preferred Stock (incorporated by
reference from Exhibit 4.3 of the Company's Registration
Statement on Form S-1, Reg. No. 33-96700)
4.4 Indenture for Convertible Debentures (incorporated by reference
from Exhibit 4.4 of the Company's Registration Statement on
Form S-1, Reg. No. 33-96700)
4.5 Certificate of Correction on Designation of Series A Preferred
Stock (incorporated by reference from Exhibit 4.4 of the
Company's Registration Statement on Form S-1/A filed November
22, 1996, Reg. No. 333-15501)
4.6 Form of Note Indenture (incorporated by reference from Exhibit
4.6 of the Company's Registration Statement on Form S-1/A filed
November 22, 1996, Reg. No. 333-15501)
9. Voting trust agreement
9.1 Stockholders' Agreement dated September 16, 1994 among the
Company, the Callon Stockholders and NOCO Enterprises, L. P.
(incorporated by reference from Exhibit 9.1 of the Company's
Registration Statement on Form 8-B filed October 3, 1994)
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between
the Company and NOCO Enterprises, L. P. (incorporated by
reference from Exhibit 10.2 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.2 Registration Rights Agreement dated September 16, 1994 between
the Company and Callon Stockholders (incorporated by reference
from Exhibit 10.3 of the Company's Registration Statement on
Form 8-B filed October 3, 1994)
10.3 Callon Petroleum Company 1994 Stock Incentive Plan
(incorporated by reference from Exhibit 10.5 of the Company's
Registration Statement on Form 8-B filed October 3, 1994)
10.4 Credit Agreement dated October 14, 1994 by and between the
Company, Callon Petroleum Operating Company and Internationale
Nederlanden (U.S.) Capital Corporation (incorporated by
reference from Exhibit 99.1 of the Company's Report on Form
10-Q for the quarter ended September 30, 1994)
10.5 Third Amendment dated February 22, 1996, to Credit Agreement
by and among Callon Petroleum Operating Company, Callon
Petroleum Company and Internationale Nederlanden (U. S.)
Capital Corporation (incorporated by reference from Exhibit
10.9 of the Company's Form 10-K for the fiscal year ended
December 31, 1995)
10.6 Consulting Agreement between the Company and John S. Callon
dated June 19, 1996 (incorporated by reference from Exhibit
10.10 of the Company's Registration Statement on Form S-1,
filed November 5, 1996, Reg. No. 333-15501)
10.7 Callon Petroleum Company 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 10.6 of the Company's
Registration Statement on Form S-1/A, filed November 14,
1996, Reg. No. 333-15501)
10.8 Employment Agreement effective September 1, 1996, between the
Company and Fred L. Callon (incorporated by reference from
Exhibit 10.4 of the Company's Registration Statement on Form
S-1/A, filed November 14, 1996, Reg. No. 333-15501)
10.9 Employment Agreement effective September 1, 1996, between the
Company and Dennis W. Christian (incorporated by reference
from Exhibit 10.7 of the Company's Registration Statement on
Form S-1/A, filed November 14, 1996, Reg. No. 333-15501)
10.10 Employment Agreement effective September 1, 1996, between the
Company and John S. Weatherly (incorporated by reference from
Exhibit 10.8 of the Company's Registration Statement on Form
S-1/A, filed November 14, 1996, Reg. No. 333-15501)
10.11 Letter of Intent from Chevron U.S.A. Inc. dated August 29,
1997 for the sale to Callon Petroleum Company of Chevron's
interest in Mobile Blocks 863, 864, 907 and 908 for depths
from the surface to 4200 feet (incorporated by reference
from Form 8-K, filed November 4, 1997)
11. Statement re computation of per sharing earnings*
12. Statements re computation of ratios*
13. Annual Report to security holders, Form 10-Q or quarterly
reports*
16. Letter re change in certifying accountant*
18. Letter re change in accounting principles*
21. Subsidiaries of the Company
21.1 Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Company's Registration Statement on Form
8-B filed October 3, 1994)
22. Published report regarding matters submitted to vote of security
holders*
23. Consents of Experts and Counsel
23.1 Consent of Arthur Andersen LLP
24. Power of attorney*
27. Financial data schedule
A financial data schedule for the year ended December 31, 1997
(EX-27) was filed electronically along with this Form 10-K
99. Additional Exhibits*
*Inapplicable to this filing.
(b) Reports on Form 8-K.
On November 4, 1997, the Company filed a report on Form 8-K reporting
that the Company agreed to purchase Chevron U.S.A. Inc.'s interest
in the Mobile Block 864 Area (the "Chevron Acquisition") for $34
million. On November 21, 1997, the Company filed an amended report
on Form 8-K/A reporting that the Company agreed to purchase 61% of
Chevron's interest for $21 million effective July 1, 1997. The
Chevron Acquisition closed on November 7, 1997 for a net purchase
price of $18.8 million
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 17, 1998 /s/ Fred L. Callon
--------------------------------------------
Fred L. Callon (principal executive officer,
director)
Date: March 17, 1998 /s/ John S. Weatherly
--------------------------------------------
John S. Weatherly (principal financial officer)
Date: March 17, 1998 /s/ James O. Bassi
--------------------------------------------
James O. Bassi (principal accounting officer)
Date: March 17, 1998 /s/ John S. Callon
--------------------------------------------
John S. Callon (director)
Date: March 17, 1998 /s/ Dennis W. Christian
--------------------------------------------
Dennis W. Christian (director)
Date: March 17, 1998 /s/ B. F. Weatherly
--------------------------------------------
B. F. Weatherly (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 abovesigned, thereunto duly authorized.
CALLON PETROLEUM COMPANY
Date March 17, 1998 BY: /s/ John S. Weatherly
-------------------------------------------
John S. Weatherly, Senior Vice President,
Chief Financial Officer and Treasurer