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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, 1998
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:
Title of each class Name of exchange on which registered
------------------- ------------------------------------
Convertible Exchangeable Preferred Stock, New York Stock Exchange
Series A, Par Value $.01 Per Share
Common Stock, Par Value $.01 Per Share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark 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 $60,644,981, as of March 24, 1999 (based on the
last reported sale price of such stock on the New York Stock Exchange).
As of March 24, 1999, there were 8,543,722 shares of the Registrant's Common
Stock, par value $.01 per share, outstanding.
Document incorporated by reference: Portions of the definitive Proxy Statement
of Callon Petroleum Company (to be filed no later than 120 days after December
31, 1998) relating to the Annual Meeting of Stockholders to be held on April
29, 1999, 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
statements of historical fact included in this report regarding the Company's
financial position and cash requirements, estimated quantities and net present
values of reserves, business strategy, plans and objectives for future
operations and covenant compliance, are forward-looking statements. The
Company can give no assurances that the assumptions upon which such forward-
looking statements are based 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 under "Risk Factors"
and elsewhere in this report and in other filings made by the Company with the
Securities and Exchange Commission ("Commission".) The Cautionary Statements
expressly qualify all subsequent written and oral forward-looking statements
attributable to the Company or persons acting on its behalf.
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 increased its reserves
through the acquisition of producing properties that were
geologically complex, had (or were analogous to fields with) an
established production history from stacked pay zones and were
candidates for exploitation. The Company focused on reducing
operating costs and implementing production enhancements through
the application 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. During this period, Callon has drilled
16 productive wells and nine dry holes for a total of 25 wells and a
success rate of 64%. These 16 wells include two onshore, 12 in the
Gulf of Mexico shelf area and two in the deepwater region of the
Gulf. During 1998, six of these productive wells contributed 55
Bcfe of reserve additions. These additions from the drill bit resulted
in a net reserve replacement cost of $1.15 per Mcfe.
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
Gulf of Mexico Shelf
Eugene Island Block 335. Three wells were drilled on Eugene
Island Block 335 during 1997. The wells encountered a total of
six pay sands, which, with fault separations, form eight productive
reservoirs. Production facility installation was completed during
the fourth quarter of 1998. During the first quarter of 1999 two
dually completed wells came online at a rate of 18.4 million cubic
feet of natural gas (MMcf) and 668 barrels of oil (Bo) per day.
The third well is currently being completed. Callon owns a 20%
working interest in the wells.
Vermilion Block 130. In March 1998 the Vermilion Block 130 #1
well reached a total measured depth of 14,134 feet (total vertical
depth of 13,575 feet) and encountered approximately 85 feet of net
natural gas pay in three intervals. By utilizing nearby production
facilities, the discovery well went online in June 1998. It is
currently producing 3 MMcf and 8 Bo per day from the deepest of
the three pay zones. Callon holds a 25% working interest.
Main Pass Block 26. The State Lease 15827 #1 well at Main Pass
Block 26 was drilled to a depth of 10,450 feet. The well
encountered 45 feet of net natural gas pay over a gross interval
from 10,084 feet to 10,218 feet. The discovery is located
approximately 2.6 miles north of Callon's existing facilities at
Main Pass Block 32. The well was tied-in and placed on
production in February 1999. The current production rate is 5.5
MMcf and 500 Bo per day. Callon owns a 97% working interest.
Main Pass Block 36. In July 1998 Callon acquired from Conoco a
50% working interest in the Garfield prospect located on Main
Pass Block 36. The SL 14964 #1 well has 40 feet of net gas pay in
three zones from 13,300 feet to 16,500 feet and was tested at 14
MMcf and 900 barrels of condensate (Bc) per day. Initial
production is scheduled for the second quarter of 1999.
Main Pass Block 31. The Company's State Lease 2125 #12 well,
the Romeo y Julieta prospect at Main Pass Block 31, was drilled to
a total depth of 12,663 feet and encountered natural gas shows
over a gross interval of 107 feet. The well was perforated over an
interval between 12,498 feet and 12,522 feet and tested at 2.4
MMcf and 210 Bc per day. Production should commence during
the first quarter of 1999. Callon owns a 92.4% working interest in
the well.
Mobile Block 864 Area. Three wells are scheduled for drilling in
the Mobile Block 864 area during 1999. The wells are based upon
results from a 630-mile, high-resolution, shallow-focused seismic
survey conducted during 1998. Callon's working interest in the
three wells will range from 25% to 67%.
High Island 494. In February, 1998, the Company announced its
High Island Block A-494 #C-1 discovery well tested at 20.3
million cubic feet of natural gas per day (MMcf/d). The #C-1 well
(Snapper prospect) reached a total depth of 8,800 feet and
encountered 207 feet of gross gas pay with 80 feet of net natural
gas pay in the objective Cris. S. sandstone formation. It was tested
on a 31/64-inch choke with a flowing tubing pressure of 2,766
pounds per square inch and shut-in tubing pressure of 3,323
pounds per square inch. Callon owns a 50% working interest in
the well and the operator, Petro Quest Energy, Inc. holds the
remaining 50%.
Gulf of Mexico Deepwater
Boomslang. Located in 900 feet of water, the Boomslang prospect
on Ewing Bank Block 994 was drilled to a total depth of 12,955
feet and encountered 185 net feet of oil pay in three separate zones.
Callon owns a 35% working interest in the block. This discovery
is one of the largest discoveries in the history of the Company.
Sidewinder. Prior to development activities at Boomslang
The Company plans to drill the Sidewinder prospect, located
immediately to the southeast of Boomslang on Ewing Bank Block
995 and Green Canyon Blocks 24 and 25. Callon owns at 15%
working interest in these leases.
Garden Banks Block 341. During February 1999 the initial test
well on the Company's Habanero prospect at Garden Banks Block
341 encountered over 200 feet of net pay. Located in 2,000 feet of
water, the well was drilled to a measured depth of 21,158 feet.
This discovery is the second deepwater success for Callon and is
expected to be the largest discovery in the Company's history.
Callon owns an 11.25% working interest in the well. It is operated
by Shell Deepwater Development Inc., which owns a 55% working
interest, with the remaining working interest being owned by
Murphy Oil.
Onshore Activity
West Lake Verret, St. Martin Parish, Louisiana. In January 1999
Callon participated in the drilling and completion of a 16,400-foot
well at West Lake Verret in St. Martin Parish in south Louisiana.
The Company owns a 28.7% working interest in the well, which
will be placed on production in March 1999.
Kemah, Galveston County, Texas. During the first quarter of 1999
the Company drilled and completed a new field discovery well on
its Kemah prospect in Galveston County, Texas. The Callon
Hanson Unit #1 well tested at 3.6 MMcf and 110 Bo per day
through a 20/64-inch choke with a flowing tubing pressure of
1,980 pounds per square inch. Callon owns a 100% working
interest in the prospect.
Recent Acquisitions
In March 1998 Callon added to its prospect inventory by
participating in Outer Continental Shelf (OCS) Lease Sale #169.
The Company submitted bids on a total of 22 tracts, two for our
own account and 20 in combination with seven other companies.
The shelf tracts which were awarded included five blocks with
Murphy Oil Corporation, being Main Pass Block 273, Mobile
Block 999, Ship Shoal Block 319, Vermilion Block 247 and West
Cameron Block 276. Callon owns a 25% working interest.
The Company was also the successful high bidder on three blocks with
Ranger Oil Limited: East Cameron Block 176, West Cameron
Block 434 and West Cameron Block 455. Callon owns a
50% working interest and will operate. Also, Callon was the
successful bidder on West Delta Block 119, which is owned 18.5%
by the Company and the remainder by Murphy, Santos and Ocean
Energy, Inc.
The Company also was awarded five deepwater blocks that are
contiguous to Callon's Boomslang discovery at Ewing Bank Block
994. They are Ewing Bank Blocks 995 and 996 and Green Canyon
Blocks 24, 25 and 27. The Company has a 15% working interest
in the blocks with the balance held by Samedan Oil Corporation
and Murphy.
Sale of Black Bay Complex
The Company finalized the sale of its interest in the Black Bay
Complex in May 1998. Although the Company sold 9.9 Bcfe of
proved reserves, the remaining upside potential of this mature oil
field did not justify the high operating costs, particularly during the
current low oil price environment.
Risk Factors
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. 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. Natural gas prices were lower in 1998 than they
had been in previous years. Although the decrease in gas prices was
not as dramatic as the decrease in oil prices in 1998, if this condition
continues for an extended period or if future gas prices fall even
lower, it could adversely affect the Company in the manner
described above.
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
substantial 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 one gross (0.5 net) development wells and 15 gross (5.7
net) exploratory wells through fiscal 1999. The estimated cost, net
to the Company, to drill and complete these wells is approximately
$36.9 million with dry hole costs of approximately $17.0 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.
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 1999 is approximately $55 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 Item 7A. "Quantitative and Qualitative
Disclosures About Market Risks." 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. Significant reductions in production at times when the
floating price exceeds the fixed price could require the Company
to make payments under the hedge agreements 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, 1998, the Company has hedged
approximately 380,000 Mcf per month from January through
August of 1999 at an average floor price of $2.21 per MMBtu
(NYMEX) and an average ceiling price of $2.68 per MMBtu
(NYMEX). In addition, the Company had oil open collar contracts
for 12,500 barrels per month from January 1999 through June 1999
at a ceiling price of $18.00 and a floor of $14.50 and 12,500
barrels per month from July 1999 through December 1999 at a
ceiling price of $18.54 and a floor of $15.00.
Also at December 31, 1998 the Company had open forward sales
position natural gas contracts of 200,000 Mcf per the month of
March 1999 at a fixed contract average price of $2.45 and 200,000
Mcf per month from April 1999 through September 1999 at a fixed
contract price of $2.35.
Competition
The Company operates in the highly competitive areas of oil and
gas exploration, 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 maintains 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
regulation of oil and gas production and federal regulation of gas
sold or transported 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 marketing 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
approximately 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 111 employees as of December 31, 1998, 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.
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 pipeline'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 pipeline 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 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 interstate pipelines on or before
November 1, 1993. Numerous petitions for judicial review of Order
No. 636 were filed and consolidated for review in the United States
Court of Appeals for the D. C. Circuit. On July 16, 1996, the United
States Court of Appeals for the D. C. Circuit issued its opinion and
upheld the vast majority of the Order No. 636 requirements while
remanding to the FERC certain limited issues. The Company can
not predict what further actions the FERC may take on these
matters; however, the Company does not believe that it will be
affected in a manner materially different than other natural gas
producers.
With respect to the transportation of natural gas on or across the
Outer Continental Shelf ("OCS"), the FERC requires, as part of its
regulation under the Outer Continental Shelf Lands Act, that all
pipelines provide open and non-discriminatory access to both owner
and non-owner shippers. Although to date the FERC has imposed
light-handed regulation on off-shore facilities that meet its
traditional test of gathering status, it has the authority to exercise
jurisdiction under the Outer Continental Shelf Lands Act
("OCSLA") over gathering facilities, if necessary, to permit non-
discriminatory access to service. For those facilities transporting
natural gas across the OCS that are not considered to be gathering
facilities, the rates, terms, and conditions applicable to this
transportation are regulated by FERC under the NGA and NGPA, as
well as the OCSLA.
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. The rates, terms, and
conditions applicable to the interstate transportation of oil and
related products by pipelines are regulated by the FERC under the
Interstate Commerce Act. 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. The FERC will also, under defined circumstances, permit
alternative ratemaking methodologies for interstate oil pipelines
such as the use of cost of service rates, settlement rates, and market-
based rates. Market-based rates will be permitted to the extent the
pipeline can demonstrate that it lacks significant market power in the
market in which it proposes to charge market-based rates. The
cumulative effect that these rules may have on moving the
Company's production to market cannot yet be determined.
With respect to the transportation of oil and condensate on or across
the OCS, the FERC requires, as part of its regulation under the
OCSLA, that all pipelines provide open and non-discriminatory
access to both owner and non-owner shippers. Accordingly, the
FERC has the authority to exercise jurisdiction under the OCSLA, if
necessary, to permit non-discriminatory access to service.
Legislative Proposals. In the past, Congress has been very active in
the area of natural gas regulation. There are legislative proposals
pending in Congress and 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, royalty and related
valuation requirements, 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 costs of construction and
operation of such pipeline would be impacted by the rules and
regulations governing such matters, if any, of such administrative
authority. Further, such a pipeline system would be subject to
various state and/or federal pipeline safety regulations and
requirements, including those of, among others, the Department of
Transportation. Such regulations can increase the cost of planning,
designing, installation and operation of such facilities. The impact
of such pipeline safety regulations would not be any more adverse to
the Company than it would be to other similar owners or operators
of such pipeline facilities.
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 existing 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 transporting, 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 nonhazardous 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
environment. 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 requirements 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, primarily, in Louisiana
and Alabama. As of December 31, 1998, the Company's estimated
proved reserves totaled 6.9 million barrels of oil and 88 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 $99.8 million. Gas
constitutes approximately 68% of the Company's total estimated
proved reserves and approximately 58% of the Company's reserves
are proved producing reserves. The Company operates 38 wells
representing approximately 61% of the total Discounted Cash Flow
attributable to estimated proved reserves at December 31, 1998.
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, 1998.
Percent Estimated Net Proved
Discounted Total Oil Gas Total
Field Name/Well Primary Cash Flow Discounted Reserves Reserves Reserves
Location Operator(s) ($000)(a) Cash Flow (MBbls) (MMcf) (MMcfe)
- ------------------- ------------ ---------- ---------- -------- -------- --------
Mobile Bay 864 Area Callon/Murphy $ 48,308 48.43% -- 41,652 41,652
Federal Waters
Chandeleur Block 40 Callon 9,505 9.53% -- 8,517 8,517
Federal Waters
Main Pass 31 / SL 12002 #1 Callon 8,515 8.54% 171 4,872 5,898
Louisiana State Waters
Main Pass 26 / SL 15827 #1 Callon 6,301 6.32% 461 4,949 7,715
Louisiana State Waters
Main Pass 36 / SL 14964 #1 Callon 5,403 5.42% 163 4,414 5,392
Louisiana State Waters
Big Escambia Creek Exxon 5,298 5.31% 579 1,952 5,426
Southeast Alabama
Ewing Bank 994 Murphy 4,241 4.25% 4,604 8,288 35,912
Federal Waters
Eugene Island 335 Murphy 3,047 3.05% 168 2,654 3,662
Federal Waters
Other properties Various 9,133 9.15% 752 10,732 15,244
-------- ------ ----- ------ -------
Total $ 99,751 100.00% 6,898 88,030 129,418
======== ====== ===== ====== =======
_________
(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, 1998, 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. The Company was appointed operator of
the Mobile Block 864 unit. Estimated net proved reserves at
December 31, 1998 were 41.7 Bcf and a PV-10 value of $48.3
million. Net average daily production during 1998 was 14.7
MMcf per day.
Production from three wells in the area is currently constrained by
the capacity of the unit production facilities. The Company plans
to add compression facilities to the existing platform to increase
productive capacity during 1999.
Three wells are scheduled for drilling in the Mobile Block 864 area
during 1999. The wells are based upon results from a 630-mile,
high-resolution, shallow-focused seismic survey conducted during
1998. Callon's working interest in the three wells will range from
25% to 67%.
Chandeleur Block 40.
In December 1995, the Company acquired a 52.3% working
(43.6% net revenue) interest in Chandeleur Block 40. 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. 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 15.4 MMcf/d during 1998. As of
December 31, 1998 estimated net proved reserves were 8.5 Bcf
with a PV-10 value of $9.5 million.
Main Pass 31 / SL 12002 #1.
Based upon a 1996 seismic survey completed by the Company, 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 and encountered 67 feet of net gas pay
in two zones. The Company completed the well in the lower pay
zone and 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 well produced 1.9 Bcf and 72,000 barrels of condensate before
being recompleted into the primary pay zone in the fourth quarter
of 1998. The well was brought back on-line in January at rates of
10.9 MMcf and 350 barrels of oil per day. As of December 31,
1998, estimated net proved reserves were 4.9 Bcf of gas and 171
MBbls of condensate.
Main Pass 26 / SL 15827 #1.
The Company negotiated a farm-in agreement in 1998 for a 97%
working interest after identifying a prospect on the Main Pass 26
Block based upon a 1996 seismic survey completed by the
Company. In August 1998 the State Lease 15827 #1 well was
drilled to a depth of 10,450 feet. The well encountered 45 feet of
net natural gas pay over a gross interval from 10,084 feet to 10,218
feet. The discovery is located approximately 2.6 miles north of
Callon's existing facilities at Main Pass Block 32. The well was
tied-in and placed on production in February 1999. The current
production rate is 5.5 MMcf and 500 Bo per day. Estimated net
proved reserves at December 31, 1998 were 4.9 Bcf of natural gas
and 461 MBbls of condensate with a PV-10 of $6.3 million.
Main Pass 36 / SL 14964 #1.
Callon acquired a 50% working interest in the Garfield prospect
from Conoco in July 1998. The SL 14964 #1 well was completed
in a reservoir located on Main Pass Block 36. The well has 40 feet
of net gas pay in three zones from 13,300 feet to 16,500 feet and
was tested at 14 MMcf and 900 Bc per day. Initial production is
scheduled for the second quarter of 1999. Callon is the operator
and estimated net proved reserves as of December 31, 1998 were
4.4 Bcf of natural gas and 163 MBbls of condensate. PV-10 of the
reserves was $5.4 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
1998 was 3.0 MBbls of condensate, 1.5 MBbls of natural gas
liquids, 8.0 MMcf of residue natural gas and 349 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.
Ewing Bank 994.
Located in 900 feet of water, the Boomslang prospect on Ewing
Bank Block 994 was drilled to a total depth of 12,955 feet and
encountered 185 net feet of oil pay in three separate zones. Callon
owns a 35% working interest in the block. This discovery is one
of the largest discoveries in the history of the Company.
Estimated net proved reserves at December 31, 1998 were 4.6
million barrels of oil and 8.3 Bcf of natural gas. Prior to designing
production facilities for Boomslang the Company plans to drill the
Sidewinder prospect, located immediately to the southeast of Boomslang
on Ewing Bank Block 995 and Green Canyon Blocks 24 and 25. Callon
owns a 15% working interest in these leases.
Eugene Island 335.
Three wells were drilled on Eugene Island Block 335 during 1997.
The wells encountered a total of six pay sands, which with fault
separations, form eight productive reservoirs. Production facility
installation was completed during the fourth quarter of 1998.
During the first quarter of 1999 two dually completed wells came
on line at a rate of 18.4 MMcf and 668 Bo per day. The third well
is currently being completed. Callon owns a 20% working interest
in the wells. Estimated net proved reserves at December 31, 1998
were 168 MBbls of oil and 2.7 Bcf of natural gas.
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.
Years Ended December 31,
1998 1997 1996
--------------------------
(In thousands)
Proved developed:
Oil (Bbls) 2,079 2,976 3,385
Gas (Mcf) 76,895 88,010 49,491
Proved undeveloped:
Oil (Bbls) 4,819 426 434
Gas (Mcf) 11,135 728 933
Total proved:
Oil (Bbls) 6,898 3,402 3,819
Gas (Mcf) 88,030 88,738 50,424
Estimated pre-tax future net cash flows $152,552 $209,264 $216,154
======== ======== ========
Discounted cash flows $ 99,751 $136,448 $160,171
======== ======== ========
The Company's independent Reserve Engineers 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
the Commission 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
interpretation and judgment. Estimates by different engineers often
vary, sometimes significantly. In addition, physical factors, such as
the results of drilling, testing and production subsequent to the date
of an estimate, as well as economic factors, such as an increase or
decrease in product prices that renders production of such reserves
more or less economic, may justify revision of such estimates.
Accordingly, reserve estimates 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,
------------------------------------------
1998 1997 1996
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Development:
Oil 2 .40 -- -- 1 .09
Gas -- -- 2 2.00 2 1.52
Non-Productive -- -- 1 0.66 -- --
----- --- ----- ---- ----- ----
Total 2 .40 3 2.66 3 1.61
===== === ===== ==== ===== ====
Exploration:
Oil 1 .35 -- -- -- --
Gas 3 2.14 2 .62 1 1.00
Non-Productive 2 1.25 5 1.25 -- --
----- ---- ----- ---- ----- ----
Total 6 3.74 7 1.87 1 1.00
===== ==== ===== ==== ===== ====
The Company owned working and royalty interests in
approximately 288 gross (7.3 net) producing oil and 313 gross (23.8
net) producing gas wells as of December 31, 1998. 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,
1998, the Company had three exploratory gas wells and one exploratory oil
well 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, 1998.
Leasehold Acreage
Developed Undeveloped
State Gross Net Gross Net
- ----------- ------ ------ ------ -----
Alabama 13,136 12,210 944 190
California -- -- 480 480
Louisiana 11,735 8,202 6,821 3,872
Michigan -- -- 246 29
Mississippi 314 314 -- --
Oklahoma 40 10 -- --
Texas 820 378 737 626
Federal Waters 95,281 60,672 279,247 64,126
------- ------ ------- ------
Total 121,326 81,786 288,475 69,323
======= ====== ======= ======
As of December 31, 1998, the Company owned various royalty and
overriding royalty interests in 1,336 net developed acres and 6,862
undeveloped acres. In addition, the Company owned 5,464
developed and 134,536 undeveloped mineral acres.
Major Customers
For the year ended December 31, 1998, Dynegy Marketing & Trade,
PG&E Energy Trading Corp., and Columbia Energy Services
purchased 23%, 26% and 22%, respectively, of the Company's
natural gas and oil production. All three customers purchased
production 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
production.
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 agreements, production sales contracts and
other agreements that may affect the properties or their titles; back-
ins and reversionary interests existing under purchase agreements
and leasehold assignments; liens that arise in the normal course of
operations, such as those for unpaid taxes, statutory liens securing
obligations to unpaid suppliers and contractors and contractual liens
under operating agreements; pooling, unitization and
communitization agreements, declarations and orders; and
easements, restrictions, rights-of-way and other matters that
commonly affect property. To the extent that such burdens and
obligations affect 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 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 affect on the Company's financial position or
results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS
There were no matters submitted to a vote of security holders during
the fourth quarter of 1998.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
Effective April 22, 1998, the Company's Common Stock began
trading on the New York Stock Exchange under the symbol "CPE".
Prior to that time, the Company's Common Stock was traded 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 for the periods indicated.
Quarter Ended High Low
------------- ---- ---
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
1998:
1st Quarter 17 1/8 15 1/4
2nd Quarter 18 3/8 14
3rd Quarter 14 7/8 7 7/8
4th Quarter 14 10 7/8
As of March 24, 1999, there were approximately 7,136 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, 1998 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)
Years Ended December 31,
1998 1997 1996 1995 1994
---------- --------- --------- --------- ---------
Statement of Operations Data(a):
Revenues:
Oil and gas sales $ 35,624 $ 42,130 $ 25,764 $ 23,210 $ 13,948
Interest and other 2,094 1,508 946 627 171
---------- --------- --------- --------- ---------
Total revenues 37,718 43,638 26,710 23,837 14,119
---------- --------- --------- --------- ---------
Costs and expenses:
Lease operating expenses 7,817 8,123 7,562 6,732 4,042
Depreciation, depletion and amortization 19,284 16,488 9,832 10,376 6,049
General and administrative 5,285 4,433 3,495 3,880 3,717
Interest 1,925 1,957 313 1,794 624
Accelerated vesting and retirement benefits 5,761 -- -- -- --
Impairment of oil and gas properties 43,500 -- -- -- --
---------- --------- --------- --------- ---------
Total costs and expenses 83,572 31,001 21,202 22,782 14,432
---------- --------- --------- --------- ---------
Income (loss) from operations (45,854) 12,637 5,508 1,055 (313)
Income tax expense (benefit) (15,100) 4,200 50 -- (200)
---------- --------- --------- --------- ---------
Net income (loss) (30,754) 8,437 5,458 1,055 (113)
Preferred stock dividends 2,779 2,795 2,795 256 --
---------- --------- --------- --------- ---------
Net income (loss) available to common shares $ (33,533) $ 5,642 $ 2,663 $ 799 $ (113)
========== ========= ========= ========= =========
Net income (loss) per common share:
Basic $ (4.17) $ .91 $ .46 $ .14 $ (.03)
Diluted $ (4.17) $ .88 $ .45 $ .14 $ (.03)
Shares used in computing net income (loss) per
common share:
Basic 8,034 6,194 5,835 5,755 4,346
Diluted 8,034 6,422 5,952 5,755 4,346
Balance Sheet Data (end of period)(a):
Oil and gas properties, net $ 141,905 $ 150,494 $ 82,489 $ 57,765 $ 43,920
Total assets $ 181,652 $ 190,421 $ 118,520 $ 83,867 $ 73,786
Long-term debt, less current portion $ 78,250 $ 60,250 $ 24,250 $ 100 $ 15,363
Stockholders' equity $ 84,484 $ 113,701 $ 77,864 $ 75,129 $ 43,431
__________
(a) The Company succeeded to the business and properties of Callon Petroleum
Operating Company, Callon Consolidated Partners, L. P. ("CCP") and CN
Resources ("CN") on September 16, 1994 pursuant to a 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.
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of
the Company's financial condition and results of operations. The
Company's Financial Statements and Notes thereto contain detailed
information that should be referred to in conjunction with the
following discussion. See Item 8. "Financial Statements and
Supplementary Data."
General
Callon Petroleum Company has been engaged in the acquisition,
development and exploration of oil and gas properties since 1950.
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 and its ability to find,
develop and acquire additional oil and gas reserves that are
economically recoverable. 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,
profitability and cash flows from operations. While prices for
natural gas are currently lower than they were prior to 1998, oil
prices are at historic lows. The diametric change in industry
conditions from the beginning of 1998 until the end of 1998
exemplifies the unpredictable nature of oil and gas prices and the
external factors that can affect such prices. The Company uses
derivative financial instruments (see Note 6 and Item 7A.
"Quantitative and Qualitative Disclosures About Market Risks") for
price protection purposes on a limited amount of its future
production and does not use them for trading purposes. On a Mcfe
basis, natural gas represents 84% of the projected 1999 production
and 68% of proved reserves at year-end.
Inflation has not had a material impact on the Company and is not
expected to have a material impact on the Company in the future.
Year 2000 Compliance
Callon, like all other enterprises that utilize computer technology,
faces a threat of business disruption from the Year 2000 issue. The
Year 2000 issue refers to the inability of computer and other
information technology systems to properly process date and time
information, stemming from the outdated programming practice of
using two digits rather than four to represent the year in a date. The
consequence of the Year 2000 issue is that computer and embedded
processing systems are at risk of malfunctioning, particularly during
the transition from 1999 to 2000.
The effects of the Year 2000 issue are exacerbated by the
interdependence of computer and telecommunications systems
throughout the world. This interdependence also exists among the
Company and its vendors, customers and business partners, as well
as with regulators in the United States. The risks associated with the
Year 2000 issue fall into three general areas: (i) financial and
administrative systems, (ii) embedded systems in field process
control units, and (iii) third party exposures.
Three years ago, Callon began its efforts to address the Year 2000
threat. The Company's plan is divided into three phases. Phase one
involves a physical inventory of all hardware, software and devices
containing date-oriented firmware. Phase two requires the Company
to prioritize issues, obtain or devise solutions and make repairs or
replace equipment as necessary. The third phase of the plan calls for
the development of contingency plans to address, among other
things, the failure of the Company's business associates to
adequately address their Year 2000 problems.
As Callon has completed its inventory phase and remedial action is
being taken as necessary, our attention is turned toward the
Company's business partners, vendors and customers. Callon's core
financial accounting software is maintained by one major vendor of
oil and gas industry software. The vendor has indicated that they
believe it will be Year 2000 compliant.
Overseeing our Year 2000 Project is the Callon Year 2000 Project
Committee which meets on a periodic basis to review project status,
provide necessary management input and resolve project issues on a
timely basis. A formal review is presented to the Callon Board of
Directors periodically during the year.
At this date, the Company does not anticipate that Year 2000
compliance will have a material effect on the company's financial
condition or results of operations.
Total costs incurred to date and estimated remaining costs for
consultants, software and hardware applications for the Year 2000
project is less than $200,000. The Company does not separately
account for the internal costs incurred for its Year 2000 compliance
efforts, which consist principally of payroll and related benefits for
its information systems personnel.
Liquidity and Capital Resources
The Company's primary sources of capital are its cash flows from
operations, borrowings and sale of debt and equity securities. Net
cash and cash equivalents declined during 1998 by $9.3 million.
Cash provided from operating activities during 1998 totaled $29.7
million. An additional $18 million was borrowed and $9.9 million
was generated from the sale of property interests during 1998.
Capital expenditures for the twelve-month period totaled $64.1
million and $2.8 million was paid as dividends on preferred stock.
At December 31, 1998, the Company had working capital in the
amount of $1.1 million.
Effective October 31, 1996, the Company entered into a 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 a $50 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. 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. At December 31, 1998, the availability on this Credit
Facility was $31.9 million.
On November 27, 1996, the Company issued $24,150,000 of 10%
Senior Subordinated Notes ("10% Notes") that will mature
December 15, 2001. The notes are redeemable at the option of the
Company, in whole or in part, 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 ("Series A Notes") due 2002
in a private placement for net proceeds of $34.8 million. On
September 10, 1997, pursuant to a Registration Agreement dated
July 31, 1997, the Company exchanged 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 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 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, 1998.
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 were used to fund a
portion of the 1998 capital expenditures budget.
In a December 1998 private transaction, a preferred stockholder
elected to convert 59,689 shares of Preferred Stock into 136,867
shares of the Company's Common Stock. Subsequent to December
31, 1998, certain other preferred stockholders, through private
transactions, agreed to convert 325,185 shares of Preferred Stock
into 772,559 shares of the Company's Common Stock under similar terms.
Gross capital expenditures for 1998 totaled $64.1 million which
included $9.5 million for the acquisition of producing properties and
equipment, $47.0 million for property development and drilling
activities on new and previously existing properties and $7.3 million
for acquisition of oil and gas properties not yet evaluated. Cash
proceeds from the sale of properties, primarily Black Bay, reduced
the capital expenditures to a net of $54.2 million. The Company's
plans for 1999 include capital expenditures of $55 million, primarily
in the Gulf of Mexico. Projected cash flows from operations and
borrowings under the Credit Facility are anticipated to be sufficient
to fund this capital budget; however, the Company may consider altern-
ative sources of financing. 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 each of the
three years in the period ended December 31, 1998.
December 31,
1998 1997 1996
---- ---- ----
Production:
Oil (MBbls) 310 462 585
Gas (MMcf) 14,036 13,114 6,269
Total production (MMcfe) 15,894 15,887 9,781
Average sales price:
Oil (per Bbl) $ 12.41 $ 18.63 $ 18.27
Gas (per Mcf) $ 2.26 $ 2.56 $ 2.40
Total production (per Mcfe) $ 2.24 $ 2.65 $ 2.63
Average costs (per Mcfe):
Lease operating expenses
(excluding severance taxes) $ .44 $ .42 $ .57
Severance taxes $ .06 $ .09 $ .20
Depreciation, depletion and amortization $ 1.19 $ 1.04 $ 1.01
General and administrative
(net of management fees) $ .33 $ .28 $ .36
Comparison of Results of Operations for the Years Ended
December 31, 1998 and 1997
Oil and Gas Revenues
Oil and gas revenues for 1998 were $35.6 million, a 15% reduction
from the 1997 amount of $42.1 million. On a Mcfe basis, 1998
production was the same as that reported for 1997. Therefore, the
reduction in revenues was attributable to the 15% reduction in
average sales price per Mcfe.
Oil production declined from 462,000 barrels in 1997 to 310,000 barrels
in 1998 and the average sales price declined from $18.63 in 1997 to
$12.41 in 1998. As a result, oil revenues declined from $8.6 million
in 1997 to $3.8 million in 1998. This reduction was attributable to
reduced prices and the divestiture of the Black Bay Complex in May 1998.
Gas revenues for 1998 were $31.8 million based on sales of 14 Bcf at
an average sales price of $2.26 per Mcf. For 1997, gas revenues were
$33.5 million based on production of 13.1 Bcf sold at an average sales
price of $2.56 per Mcf.
Lease Operating Expenses and Severance Taxes
Lease operating expenses, including severance taxes, decreased from
$8.1 million in 1997 to $7.8 million in 1998. Separately, severance
taxes declined from $1.4 million in 1997 to $0.9 million in 1998 as
a result of lower production on properties subject to severance taxes
and lower oil and gas prices. Other operating expenses increased
slightly from $6.7 million in 1997 to $6.9 million in 1998 as a result
of a full year of costs associated with acquisitions in the fourth
quarter of 1997 partially offset by a reduction due to the sale of
Black Bay.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization increased as a higher rate
was applied to a relatively constant production volume. Total
charges increased from $16.5 million, or $1.04 per Mcfe, in 1997 to
$19.3 million, or $1.19 per Mcfe in 1998. The increase in the
noncash charge per Mcfe reflects the increase in investment in
evaluated oil and gas properties during 1998.
General and Administrative
General and administrative expenses for 1998 were $5.3 million, or
$.33 per Mcfe, compared to $4.4 million, or $.28 per Mcfe, in 1997.
This 19% increase is primarily the result of the loss of Black Bay
management fees, which normally reduce general and administrative
expenses, and slightly higher normal corporate expenses.
Interest Expense
Interest expense for 1998 and 1997 was $1.9 million and $2.0
million, respectively.
Accelerated Vesting and Retirement Benefits
In December 1998, the Company recorded a charge of $5.8 million
attributable to the accelerated vesting of the remaining
performance shares previously granted under the Company's stock
option plans and of retirement benefits.
Impairment of Oil and Gas Properties
Under the full-cost method of accounting, the net capitalized costs of
proved oil and gas properties are subject to a "ceiling test", which
limits such costs to the estimated present value, net of related tax
effects (discounted at a 10 percent interest rate) of future net cash
flows from proved reserves, based on current economic and operating
conditions (PV10). If capitalized costs exceed this limit, the excess
is charged to expense. During the fourth quarter of 1998, the Company
recorded a noncash impairment provision related to oil and gas properties
in the amount of $43.5 million ($28.7 million after-tax) primarily
due to the significant decline in oil and gas prices.
Income Taxes
The Company's 1998 results include a deferred income tax benefit
of $15.1 million primarily due to the $14.8 million deferred
income tax benefit related to impairment of oil and gas properties
recorded in 1998. The Company expects to realize this benefit for
tax purposes in future years by utilizing its net operating loss and
statutory depletion carryforwards and the turn around of temporary
differences. The Company has evaluated the realizability of the
deferred income tax benefit recorded above in light of its reserve
quantity estimates, its long-term outlook for oil and gas prices and
its expected level of other future expenses. The Company believes
it is more likely than not, based upon this evaluation, that it will
realize the recorded deferred income tax asset. However, there is
no assurance that such asset will ultimately be realized.
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 of increased 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 was 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 was 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 and Severance Taxes
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
offshore producing properties. On a per Mcfe basis, these
combined expenses decreased from $.77 in 1996 to $.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
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 $.36 in 1996 to $.28 in 1997.
Interest Expense
Interest expense for 1997 was $2.0 million. The substantial
increase from the $.3 million in 1996 was 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 represented 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.
ITEM 7A. QUANTATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The Company's revenues are derived from the sale of its crude oil
and natural gas production. From time to time, the Company has
entered into hedging transactions that lock in for specified periods
the prices the Company will receive for the production volumes to
which the hedge relates. The hedges reduce the Company's
exposure on the hedged volumes to decreases in commodities
prices and limit the benefit the Company might otherwise have
received from any increases in commodities prices on the hedged
volumes.
At December 31, 1998, 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 at December 31, 1998 are for average gas
volumes of 380,000 Mcf per month through August of 1999 (on
average) at a ceiling price of $2.68 and floor of $2.21. In addition,
the Company had oil open collar contracts for 12,500 barrels per
month from January 1999 through June 1999 at a ceiling price of
$18.00 and a floor of $14.50 and 12,500 barrels per month from July
1999 through December 1999 at a ceiling price of $18.54 and a floor
of $15.00.
Also at December 31, 1998 the Company had open forward sales
position natural gas contracts of 200,000 Mcf for the month of
March 1999 at a fixed contract average price of $2.45 and 200,000
Mcf per month from April 1999 through September 1999 at a fixed
contract price of $2.35.
Based on projected annual sales volumes for 1999, a 10% decline
in the prices the Company receives for its crude oil and natural gas
production would have an approximate $2.6 million impact on the
Company's revenues. The hypothetical impact on the decline in oil
and gas prices is net of the incremental gain that would be realized
upon a decline in prices by the oil and gas hedging contracts in
place as of March 3, 1999.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Report of Independent Public Accountants 30
Consolidated Balance Sheets as of the Years Ended
December 31, 1998 and 1997 31
Consolidated Statements of Operations for the Three Years
in the Period Ended December 31, 1998 32
Consolidated Statements of Stockholders' Equity
for the Three Years in the Period Ended December 31, 1998 33
Consolidated Statements of Cash Flows for the Three Years
in the Period Ended December 31, 1998 34
Notes to Consolidated Financial Statements 35-51
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, 1998 and 1997, and the related
consolidated statements of operations, stockholders' equity and cash
flows for each of the three years in the period ended December 31,
1998. 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, 1998 and
1997, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
February 19, 1999
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
December 31,
1998 1997
---- ----
ASSETS
Current assets:
Cash and cash equivalents $ 6,300 $ 15,597
Accounts receivable 6,024 12,168
Other current assets 1,924 723
--------- ---------
Total current assets 14,248 28,488
--------- ---------
Oil and gas properties, full-cost accounting method:
Evaluated properties 444,579 398,046
Less accumulated depreciation, depletion and amortization (345,353) (282,891)
--------- ---------
99,226 115,155
Unevaluated properties excluded from amortization 42,679 35,339
--------- ---------
Total oil and gas properties 141,905 150,494
--------- ---------
Pipeline and other facilities, net 6,182 6,504
Other property and equipment, net 1,753 1,938
Deferred tax asset 16,348 1,248
Long-term gas balancing receivable 199 242
Other assets, net 1,017 1,507
--------- ---------
Total assets $ 181,652 $ 190,421
========= =========
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
December 31,
1998 1997
---- ----
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 11,257 $ 12,389
Undistributed oil and gas revenues 1,720 2,259
Accrued net profits interest payable 129 1,121
--------- ---------
Total current liabilities 13,106 15,769
--------- ---------
Accounts payable and accrued liabilities to be refinanced 3,000 --
Long-term debt 78,250 60,250
Accrued retirement benefits 2,323 297
Long-term gas balancing payable 489 404
--------- ---------
Total liabilities 97,168 76,720
--------- ---------
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares authorized;
1,255,811 shares of Convertible Exchangeable Preferred Stock,
Series A issued and outstanding at December 31, 1998 and
1,315,500 outstanding at December 31, 1997 with a liquidation
preference of $31,395,275 at December 31, 1998 13 13
Common Stock, $.01 par value; 20,000,000
shares authorized; 8,178,406 and 7,855,216 shares
outstanding at December 31, 1998 and 1997, respectively 82 79
Treasury stock (73,800 shares at cost) (915) --
Unearned compensation - restricted stock -- (2,232)
Capital in excess of par value 109,429 106,433
Retained earnings (deficit) (24,125) 9,408
--------- ---------
Total stockholders' equity 84,484 113,701
--------- ---------
Total liabilities and stockholders' equity $ 181,652 $ 190,421
========= =========
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 1998, 1997 and 1996
(In thousands, except per share amounts)
1998 1997 1996
---- ---- ----
Revenues:
Oil and gas sales $ 35,624 $ 42,130 $ 25,764
Interest and other 2,094 1,508 946
--------- --------- ---------
Total revenues 37,718 43,638 26,710
--------- --------- ---------
Costs and expenses:
Lease operating expenses 7,817 8,123 7,562
Depreciation, depletion and amortization 19,284 16,488 9,832
General and administrative 5,285 4,433 3,495
Interest 1,925 1,957 313
Accelerated vesting and retirement benefits 5,761 -- --
Impairment of oil and gas properties 43,500 -- --
--------- --------- ---------
Total costs and expenses 83,572 31,001 21,202
--------- --------- ---------
Income (loss) from operations (45,854) 12,637 5,508
Income tax expense (benefit) (15,100) 4,200 50
--------- --------- ---------
Net income (loss) (30,754) 8,437 5,458
Preferred stock dividends 2,779 2,795 2,795
--------- --------- ---------
Net income (loss) available to common shares $ (33,533) $ 5,642 $ 2,663
========= ========= =========
Net income (loss) per common share:
Basic $ (4.17) $ .91 $ .46
Diluted $ (4.17) $ .88 $ .45
Shares used in computing net income (loss)
per common share:
Basic 8,034 6,194 5,835
Diluted 8,034 6,422 5,952
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 Retained
Preferred Common Treasury Restricted Excess of Earnings
Stock Stock Stock Stock Par Value (Deficit)
-------- ------- -------- ------------ ---------- ---------
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 plan -- 2 -- (3,153) 2,729 --
Earned portion of restricted stock -- -- -- 921 -- --
-------- ------- ------- -------- ---------- ---------
Balances, December 31, 1997 13 79 -- (2,232) 106,433 9,408
Net income (loss) -- -- -- -- -- (30,754)
Preferred stock dividends -- -- -- -- 15 (2,779)
Shares issued pursuant to employee
benefit and option plan -- -- -- -- 235 --
Employee stock purchase plan -- -- -- -- 163 --
Restricted stock plan -- 2 -- (2,731) 2,584 --
Earned portion of restricted stock -- -- -- 4,963 -- --
Conversion of preferred shares to common -- 1 -- -- (1) --
Stock buyback plan -- -- (915) -- -- --
-------- ------- ------- -------- --------- ---------
Balances, December 31, 1998 $ 13 $ 82 $ (915) $ -- $ 109,429 $ (24,125)
======== ======= ======= ======== ========= =========
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, 1998, 1997 and 1996
(In thousands)
1998 1997 1996
--------- -------- ---------
Cash flows from operating activities:
Net income (loss) $ (30,754) $ 8,437 $ 5,458
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 19,791 16,924 10,131
Impairment of oil and gas properties 43,500 -- --
Amortization of deferred costs 619 467 114
Deferred income tax expense (benefit) (15,100) 4,200 50
Noncash compensation related to stock compensation plans 7,583 1,224 72
Changes in current assets and liabilities:
Accounts receivable 6,144 493 (4,332)
Other current assets (1,201) (207) (278)
Current liabilities (860) (3,809) 4,049
Change in gas balancing receivable 43 418 (41)
Change in gas balancing payable 85 14 ( 42)
Change in other long-term liabilities -- 249 (28)
Change in other assets, net (129) (1,073) (830)
--------- -------- ---------
Cash provided (used) by operating activities 29,721 27,337 14,323
--------- -------- ---------
Cash flows from investing activities:
Capital expenditures (64,105) (89,609) (37,637)
Cash proceeds from sale of mineral interests 9,909 4,450 1,574
--------- -------- ---------
Cash provided (used) by investing activities (54,196) (85,159) (36,063)
--------- -------- ---------
Cash flows from financing activities:
Change in accrued liabilities for capital expenditures (2,396) 3,610 3,346
Increase in accounts payable and accrued liabilities
to be refinanced 3,000 -- --
Equity issued related to employee stock plans 414 90 --
Purchase of treasury shares (915) -- --
Payments on debt -- (49,200) (25,850)
Proceeds from debt issuance 18,000 85,200 50,000
Common stock canceled (130) (422) --
Sale of common stock -- 29,267 --
Increase (decrease) in accrued preferred stock dividends payable (16) -- 443
Dividends on preferred stock (2,779) (2,795) (2,795)
--------- -------- ---------
Cash provided (used) by financing activities 15,178 65,750 25,144
--------- -------- ---------
Net increase (decrease) in cash and cash equivalents (9,297) 7,928 3,404
Cash and cash equivalents:
Balance, beginning of period 15,597 7,669 4,265
--------- -------- ---------
Balance, end of period $ 6,300 $ 15,597 $ 7,669
========= ======== =========
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,
development and exploration of crude oil and natural gas since 1950.
The Company's properties are geographically concentrated in Louisiana,
Alabama, Texas 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 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133 ("FAS 133"), Accounting for
Derivative Instruments and Hedging Activities. The Statement establishes
accounting and reporting standards requiring that every derivative instrument,
including certain derivative instruments embedded in other contracts, be
recorded in the balance sheet as either an asset or liability measured at
its fair value. FAS 133 is effective for fiscal years beginning after
June 15, 1999, with earlier application permitted. The Company has not
yet determined the timing or method of the adoption of FAS 133 and thus
cannot quantify the impact of adoption. However, the Statement will
create volatility in equity through other comprehensive income.
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
was effective for the Company in 1998. The Company does not have any items
of other comprehensive income.
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. The Company has only one
operating segment and thus separate segment disclosure is not required.
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
restoration, 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 lower of cost or market of unevaluated properties (the full-
cost ceiling amount), net of tax effects, then such excess is charged
to expense during the period in which the excess occurs. See Note 8.
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 restoration, dismantlement and abandonment activities take place.
As of December 31, 1998 and 1997, estimated future site restoration,
dismantlement and abandonment 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.
Accounts Receivable
Accounts receivable consists primarily of accrued oil and gas production
receivable. The balance in the reserve for doubtful accounts included
in accounts receivable is $38,000 and $36,000 at December 31, 1998 and
1997, respectively. Net recoveries were $2,000 in 1998 and net charge
offs were $357,000 and $88,000 in 1997 and 1996. There were no provisions
to expense in the three year period ended December 31, 1998.
For the year ended December 31, 1998, three companies purchased 23%, 26%
and 22%, respectively of the Company's natural gas and oil production.
All three customers purchased production primarily from Callon owned
interests' in Federal OCS leases, CB40, MP163, MP 164/165, MB 864 and
MB 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 productions.
Statements of Cash Flows
For purposes of the Consolidated Financial Statements, 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, 1998. During the years ended December 31, 1998, 1997
and 1996, the Company made cash payments of $6,229,000, $4,167,000,
and $251,000, respectively, for interest.
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 were restated. The effect of this accounting change on previously
reported earnings per share (EPS) data was as follows:
Per share amounts 1996
Primary EPS as reported $ .45
Effect of FAS 128 .01
--------
Basic EPS as restated $ .46
========
Fully diluted EPS as reported $ .43
Effect of FAS 128 .02
--------
Diluted EPS as restated $ .45
========
Basic earnings or loss per common share were computed by dividing net
income or loss 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. In 1998, all options were excluded from the computation
of diluted loss per share because they were antidilutive. The conversion
of the preferred stock was not included in any annual calculation due
to their antidilutive effect on diluted income or loss per share.
A reconciliation of the basic and diluted per share computation is as
follows (in thousands, except per share amounts):
1998 1997 1996
--------- ------- -------
(a) Net income (loss) available for
common stock $ (33,533) $ 5,642 $ 2,663
(b)Weighted average shares outstanding 8,034 6,194 5,835
(c)Dilutive impact of stock options -- 228 117
(d)Total diluted shares 8,034 6,422 5,952
Stock options excluded due to
antidilutive impact 163 -- --
Basic earnings (loss) per share (a/b) $ (4.17) $ .91 $ .46
Diluted earnings (loss) per share (a/d) $ (4.17) $ .88 $ .45
Fair Value of Financial Instruments
Fair value of cash, cash equivalents, accounts receivable, accounts
payable and long-term debt approximates book value at December 31, 1998
and 1997. Fair value of long-term debt (specifically the 10% and the
10.125% senior subordinated notes) was based on quoted market value.
The calculation of the fair market value of the outstanding hedging
contracts (see Note 6) as of December 31, 1998 indicated a $1.4 million
market value benefit to the Company based on market prices at that date.
Accounts Payable and Accrued Liabilities - Long-Term
Approximately $3,000,000 of current accounts payable and accrued
liabilities at December 31, 1998 related to long-term assets, primarily
oil and gas properties that were financed subsequent to year-end with long-
term debt and therefore have been reclassified as long-term.
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 allowance
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 1998 and 1997.
Accordingly, the Company has recorded a deferred tax asset at December 31,
1998 and 1997 as follows:
December 31,
1998 1997
(In thousands)
-------- --------
Federal net operating loss carryforward $ 7,916 $ 3,531
Statutory depletion carryforward 4,083 4,062
Temporary differences:
Oil and gas properties 3,979 (4,943)
Pipeline and other facilities (2,164) (2,277)
Non-oil and gas property (101) (86)
Other 2,635 961
-------- --------
Total tax asset 16,348 1,248
Valuation allowance -- --
-------- --------
Net tax asset $ 16,348 $ 1,248
======== ========
At December 31, 1998, the Company had, for federal tax reporting purposes,
net operating loss carryforwards ("NOL") of $22.6 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 $11.7 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,
1998 1997 1996
(In thousands)
------------------------------
Computed expense (benefit) at the
expected statutory rate $ (15,590) $ 4,296 $ 1,910
Change in valuation allowance -- -- (1,760)
Other 490 (96) (100)
--------- ------- -------
Deferred income tax expense (benefit) $ (15,100) $ 4,200 $ 50
========= ======= =======
4. ACQUISITIONS
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 was 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 $18.8 million in November 1997.
The Company, together with an industry partner, was the high bidder on 18
offshore 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.
Department 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,
1998 1997
(In thousands)
----------------------
Credit Facility $ 18,100 $ 100
10% Senior Subordinated Notes 24,150 24,150
10.125% Senior Subordinated Notes 36,000 36,000
-------- --------
78,250 60,250
Less: current portion -- --
-------- --------
$ 78,250 $ 60,250
======== ========
Borrowings under the Credit Facility, with Chase Manhattan Bank, are
secured by mortgages covering substantially all of the Company's
producing oil and gas properties. Currently, the Credit Facility
provides for a $50 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 the lender's prime rate plus 0.125% (prime plus 0.50%
if utilized percentage of borrowing base is greater than 50%). The
Company, at its option, may fix the interest rate on all or a portion
of the outstanding principal balance at 1.125% above a defined
"Eurodollar" rate for periods up to six months (1.5% above if utilized
percentage of borrowing base is greater than 50%). The weighted
average interest rate for the total debt outstanding at December 31,
1998 and 1997 was 6.68% and 8.50%, 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 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.
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 placement 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, 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 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 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, 1998.
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 production is sold. Approximately
$1,886,000 and $2,466,000 was recognized as additional oil and
gas revenue in 1998 and 1997 and recognized a reduction in
revenue of $2,757,000 in 1996 as a result of such agreements.
At December 31, 1998, 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 at December 31, 1998 are for average
gas volumes of 380,000 Mcf per month through August of 1999
(on average) at a ceiling price of $2.68 and floor of $2.21.
In addition, the Company had oil open collar contracts for
12,500 barrels per month from January 1999 through June 1999
at a ceiling price of $18.00 and a floor of $14.50 and 12,500
barrels per month from July 1999 through December 1999 at a
ceiling price of $18.54 and a floor of $15.00.
Also at December 31, 1998 the Company had open forward sales
position natural gas contracts of 200,000 Mcf for the month
of March 1999 at a fixed contract average price of $2.45 and
200,000 Mcf per month from April 1999 through September 1999
at a fixed contract price of $2.35.
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, 1998, total estimated site restoration, dismantlement
and abandonment costs were approximately $6,360,000, 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.
Years Ended December 31,
1998 1997 1996
(In thousands)
-----------------------------------
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance $ 398,046 $ 322,970 $ 304,737
Property acquisition costs 9,464 51,751 2,999
Exploration costs 42,617 13,620 8,732
Development costs 4,361 14,155 8,076
Sale of mineral interests (9,909) (4,450) (1,574)
--------- --------- ---------
End of period balance $ 444,579 $ 398,046 $ 322,970
========= ========= =========
Unevaluated Properties (excluded
from the full-cost pool) -
Beginning of period balance $ 35,339 $ 26,235 $ 10,171
Additions 11,156 16,924 20,640
Capitalized interest and general
and administrative costs 8,955 5,163 1,883
Transfers to evaluated (12,771) (12,983) (6,459)
--------- --------- ---------
End of period balance $ 42,679 $ 35,339 $ 26,235
========= ========= =========
Accumulated depreciation, depletion
and amortization-
Beginning of period balance $ 282,891 $ 266,716 $ 257,143
Provision charged to expense 18,962 16,175 9,573
Impairment of oil and gas properties 43,500 -- --
--------- --------- ---------
End of period balance $ 345,353 $ 282,891 $ 266,716
========= ========= =========
Unevaluated property costs, primarily lease acquisition costs incurred at
federal and state lease sales and unevaluated drilling costs being excluded
from the amortizable evaluated property base consisted of $17.9 million
incurred in 1998, $8.2 million incurred in 1997 and $16.6 million incurred
in 1996 and prior. These costs are directly related to the acquisition and
evaluation of unproved properties and major development projects. The
excluded costs and related reserves are included in the amortization base as
the properties are evaluated and proved reserves are established or
impairment is determined. The majority of these costs will be evaluated
over the next five year period.
Depreciation, depletion and amortization per unit-of-production (equivalent
barrel of oil) amounted to $7.16, $6.11, and $5.87 for the years ended
December 31, 1998, 1997 and 1996, respectively.
Impairment of Oil and Gas Properties
Under full-cost accounting rules, the capitalized costs of proved oil and
gas properties are subject to a "ceiling test", which limits such costs
to the estimated present value net of related tax effects, discounted at a
10 percent interest rate, of future net cash flows from proved reserves,
based on current economic and operating conditions (PV10). If capitalized
costs exceed this limit, the excess is charged to expense. During the
fourth quarter of 1998, the Company recorded a noncash impairment
provision related to oil and gas properties in the amount of $43.5
million ($28.7 million after-tax) primarily due to the significant
decline in oil and gas prices.
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 contributions 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, 1998 and 1997 the Trusts' assets (all cash and investments)
totaled $6,360,000 and $19,300,000, 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. The trust asset decrease in 1998 was the result of a sale of
an oil and gas property and the related trust.
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
stockholders. 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
$468,000, $438,000, and $241,000 in the years 1998, 1997 and 1996,
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 granted in 1994 and 1995 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. In 1998, 20,000 non-
employee director options were granted under the plan, vesting 100%
in November 1998.
- 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 1,200,000
shares (as amended from the original 900,000 shares) of common
stock that may be subject to outstanding awards. During 1998,
1997 and 1996, the Company granted stock options to purchase
205,000, 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 options granted in 1998 provide that
25% of the options become exercisable each year beginning August
of 1998 and each succeeding January. Terms of the plan for
450,000 options granted in 1996 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:
1998 1997 1996
(In thousands, except per share data)
-------------------------------------
Net income (loss): As Reported $ (33,533) $ 5,642 $ 2,663
Pro Forma (34,421) 4,977 2,411
Basic earnings
(loss) per share: As Reported (4.17) .91 .46
Pro Forma (4.28) .80 .41
Diluted earnings
(loss) per share: As Reported (4.17) .88 .45
Pro Forma (4.28) .77 .41
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, 1998, 1997 and 1996 and changes during the years then
ended is presented in the table and narrative below:
1998 1997 1996
---------------------- ------------------ -------------------
Wtd Avg Wtd Avg Wtd Avg
Shares Ex Price Shares Ex Price Shares Ex Price
------------------------------------------------------------------
Outstanding, beginning of year 1,041,000 $ 11.19 1,030,000 $ 11.10 490,000 $ 10.01
Granted 225,000 10.08 20,000 15.31 550,000 12.06
Exercised -- -- (9,000) 10.00 -- --
Forfeited -- -- -- -- (10,000) 10.00
Expired -- -- -- -- -- --
--------- ------- --------- ------- --------- -------
Outstanding, end of year 1,266,000 $ 11.00 1,041,000 $ 11.19 1,030,000 $ 11.10
========= ======= ========= ======= ========= =======
Exercisable, end of year 802,250 $ 10.90 621,000 $ 10.65 500,000 $ 10.16
========= ======= ========= ======= ========= =======
Weighted average fair value
of options granted $ 4.31 $ 6.30 $ 4.96
====== ====== ======
The options outstanding at December 31, 1998 have exercise prices ranging
from $9.47 to $16.38 with a remaining weighted average contractual life of
7.06 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 1998, 1997 and 1996.
1998 1997 1996
---- ---- ----
Risk free interest rate 5.1% 6.8 % 6.5 %
Expected life (years) 7.0 4.0 4.9
Expected volatility 28.8% 41.1 % 34.7 %
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 stockholders' 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 was
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 and 165,500 shares were issued to certain key
employees other than the Company's Executive officers in 1998.
Approximately $4,963,000 in 1998, $714,000 in 1997 and $208,000
in 1996 of compensation cost were charged to expense related to
the restricted shares granted.
In December 1998, the Company approved the accelerated vesting of
all performance shares. As a result, an additional charge of
$3,469,000 which represents the future unamortized expense related
to unvested shares at the date the acceleration of vesting occurred,
was expensed in 1998.
In addition, the Company recorded a provision of approximately $2.3
million for retirement benefits approved by the compensation
committee of the Board of Directors in December of 1998.
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 were used to fund a portion of the 1998
capital expenditures budget.
In a December 1998 private transaction, a preferred stockholder
elected to convert 59,689 shares of Preferred Stock into 136,867 shares
of the Company's Common Stock. Subsequent to December 31, 1998, certain
other preferred stockholders, through private transactions, agreed to
convert 325,185 shares of Preferred Stock into 772,559 shares of the
Company's Common Stock under similar terms.
12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 1998, 1997
and 1996 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
Years Ended December 31,
1998 1997 1996
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period 3,402 3,819 4,766
Revisions to previous estimates (99) (151) (50)
Purchase of reserves in place 162 -- --
Sales of reserves in place (1,531) (78) (312)
Extensions and discoveries 5,274 274 --
Production (310) (462) (585)
------ ----- -----
End of period 6,898 3,402 3,819
====== ===== =====
Natural Gas (MMcf):
Beginning of period 88,738 50,424 29,667
Revisions to previous estimates (8,631) (11,174) (1,688)
Purchase of reserves in place 4,414 52,485 7,391
Sales of reserves in place (684) (164) (228)
Extensions and discoveries 18,229 10,281 21,551
Production (14,036) (13,114) (6,269)
------- ------- ------
End of period 88,030 88,738 50,424
======= ======= ======
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period 2,976 3,385 3,890
End of period 1,774 2,976 3,385
Natural Gas (MMcf):
Beginning of period 88,010 49,491 20,408
End of period 76,895 88,010 49,491
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
production, development and net abandonment costs are based on current
costs without escalation. The resulting net future cash flows have been
discounted to their present values based on a 10% annual discount factor.
Standardized Measure
December 31,
1998 1997 1996
(In thousands)
---------------------------------
Future cash inflows $256,325 $285,953 $285,727
Future costs -
Production (67,192) (63,709) (59,584)
Development and net abandonment (36,581) (12,984) (9,989)
-------- -------- --------
Future net inflows before income taxes 152,552 209,260 216,154
Future income taxes (--) (32,781) (49,438)
-------- -------- --------
Future net cash flows 152,552 176,479 166,716
10% discount factor (52,801) (48,400) (36,547)
-------- -------- --------
Standardized measure of discounted
future net cash flows $ 99,751 $128,079 $130,169
======== ======== ========
Changes in Standardized Measure
Years Ended December 31,
1998 1997 1996
(In thousands)
-----------------------------
Standardized measure - beginning of period $128,079 $130,169 $ 63,764
Sales and transfers, net of production costs (27,807) (34,006) (18,202)
Net change in sales and transfer prices,
net of production costs (33,029) (66,880) 32,268
Exchange and sale of in place reserves (4,445) (2,428) (877)
Purchases, extensions, discoveries, and improved
recovery, net of future production and
development costs 24,294 90,550 79,983
Revisions of quantity estimates (9,409) (13,751) (3,907)
Accretions of discount 13,645 16,017 6,376
Net change in income taxes 7,926 21,633 (30,000)
Changes in production rates, timing and other 497 (13,225) 764
-------- -------- --------
Standardized measure - end of period $ 99,751 $128,079 $130,169
======== ======== ========
13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
(in thousands, except per share data)
--------------------------------------
1998
- ----
Total revenues $ 11,492 $ 9,733 $ 9,339 $ 7,154
Total costs and expenses 9,664 8,606 7,919 57,383
Income taxes expense (benefit) 621 380 487 (16,588)
Net income (loss) 1,207 747 933 (33,641)
Net income (loss) per share - basic .06 .01 .03 (4.27)
Net income (loss) per share - diluted .06 .01 .03 (4.27)
1997
- ----
Total revenues $ 12,781 $ 8,758 $ 9,201 $ 12,898
Total costs and expenses 7,366 6,971 7,394 9,270
Income taxes expense 1,733 578 615 1,274
Net income 3,682 1,209 1,192 2,354
Net income per share - basic .50 .08 .08 .25
Net income per share - diluted .39 .08 .08 .24
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 their election 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 2001, 1999, and
2000, respectively. The Charter also provides that such classes shall be
as nearly equal in number as possible. On February 1, 1999, the Board of
Directors approved a resolution increasing the size of the Board from seven
to eight directors by providing for an additional Class II director to be
effective as of the date of the 1999 Annual Meeting of Stockholders. At
December 31, 1998, the directors and executive officers of the Company were
as follows:
Company
Position
Name Age Since Present Company Position
---- --- -------- ------------------------
John S. Callon 79 1994 Director (Class II); Chairman of the Board
Fred L. Callon 49 1994 Director (Class III); President; Chief
Executive Officer
Dennis W. Christian 52 1994 Director (Class III); Senior Vice President;
Chief Operating Officer
Robert A. Stanger 59 1995 Director (Class I)
John C. Wallace 60 1994 Director (Class I)
B. F. Weatherly 55 1994 Director (Class II)
Richard O. Wilson 69 1995 Director (Class I)
John S. Weatherly 47 1994 Senior Vice President; Chief Financial
Officer; Treasurer
James O. Bassi 45 1997 Vice President and Controller
Thomas E. Schwager 48 1997 Vice President, Engineering and Operations
H. Michael Tatum 70 1994 Vice President; Secretary
Kathy G. Tilley 53 1996 Vice President, Acquisitions/New Ventures
Stephen F. Woodcock 47 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 Company ("Callon Petroleum Operating").
Effective January 2, 1997, John S. Callon resigned from his position
as Chief Executive Officer of the Company, a position he held since 1980.
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 of the 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. Prior to January 1997, he was President and
Chief Operating Officer of the Company and had 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 tele-
communications, 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, after which he joined Baring Brothers & Co.,
Limited in London, England. For more than the last eleven years, he has
served as Chairman of Fred. Olsen Ltd., a London-based corporation which
he joined in 1968, and which specializes in the business of shipping and
property development. He is a director of Fred. Olsen Energy ASA, a
publicly held Norwegian service company engaged in the offshore energy
service industry; Harland & Wolff PLC, Belfast, a shipbuilding yard for
the offshore oil and gas industry; and Ganger Rolf ASA and Bonheur ASA,
Oslo, both publicly-traded shipping companies. He is also an executive
officer of NOCO Management, Ltd., a general partner of NOCO Enterprises,
L.P. ("NOCO") and of other companies associated with Fred. Olsen Interests.
B. F. Weatherly is a principal of Amerimark Capital Group, Houston, Texas,
an investment banking firm and a general partner of CapSource Fund, L. P.,
Jackson Mississippi, an investment fund. 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. 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 42 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. For 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. Since the sale of
OGC International PLC to Halliburton, Inc. in 1997, he has been a consultant
to Brown & Root, Inc. on oil and gas projects in Brazil, Bolivia, Mexico and
Ecuador. 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 ten 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 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.
Section 16(a) Beneficial Ownership Reporting Compliance
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 Commission
and the New York Stock Exchange, 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 stock-
holders 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, 1998, 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 April 29, 1999 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 30 through 51.
Report of Independent Public Accountants
Consolidated Balance Sheets as of the Years Ended
December 31, 1998 and 1997
Consolidated Statements of Operations for the Three Years
in the Period Ended December 31, 1998
Consolidated Statements of Stockholders' Equity for the
Three Years in the Period Ended December 31, 1998
Consolidated Statements of Cash Flows for the Three Years
in the Period Ended December 31, 1998
Notes to Consolidated Financial Statements
(a) 2. Schedules other than those listed above are omitted because they
are not required, not applicable or the required information is
included in the financial statements or notes thereto.
(a) 3. Exhibits:
2. Plan of acquisition, reorganization, arrangement, liquidation
or succession*
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended
(incorporated by reference 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 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)
10.8 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)
10.9 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)
10.10 Callon Petroleum Company's Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the Post-
Effective Amendment No. 1 to the Company's Registration
Statement on Form S-8, filed February 5, 1999, Reg. No.
333-29537)
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, 1998 (EX-27) was filed
electronically along with the Form 10-K.
99. Additional Exhibits*
- ----------
*Inapplicable to this filing.
(b) Reports on Form 8-K.
None
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 29, 1999 ____________/s/ Fred L. Callon_______________________
Fred L. Callon (principal executive officer, director)
Date: March 29, 1999 ____________/s/ John S. Weatherly____________________
John S. Weatherly (principal financial officer)
Date: March 29, 1999 ____________/s/ James O. Bassi______________________
James O. Bassi (principal accounting officer)
Date: March 29, 1999 ___________/s/ John S. Callon________________________
John S. Callon (director)
Date: March 29, 1999 ___________/s/ Dennis W. Christian___________________
Dennis W. Christian (director)
Date: March 29, 1999 ___________/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 undersigned, thereunto duly authorized.
CALLON PETROLEUM COMPANY
Date: March 29, 1999 By: ___/s/ John S. Weatherly_____________
John S. Weatherly, Senior Vice President,
Chief Financial Officer and Treasurer