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, 1996
Commission File Number 0-25192
CALLON PETROLEUM COMPANY
------------------------------------------------------
(Exact name of Registrant as specified in its charter)
Delaware 64-0844345
------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
200 North Canal Street (601) 442-1601
------------------------------- ------------------------------
Natchez, Mississippi 39120 (Registrant's telephone number
(Address of Principal Executive including area code)
Offices)(Zip Code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
_________________________________________
Common Stock, Par Value $.01 Per Share
Convertible Exchangeable Preferred Stock,
Series A, Par Value $.01 Per Share
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [ X ]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was approximately $39,673,371, as of March 12, 1997 (based on the
last reported sale price of such stock on the Nasdaq National Market System).
As of March 12, 1997, there were 5,758,667 shares of the Registrant's Common
Stock, par value $.01 per share, outstanding.
This report includes "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934. All statements other than state-
ments of historical fact included in this report regarding the Company's
financial position, estimated quantities and net present values of reserves,
business strategy, plans and objectives for future operations and covenant
compliance, are forward-looking statements. Although the Company believes that
the assumptions upon which such forward-looking statements are based are
reasonable, it can give no assurances that such assumptions will prove to have
been correct. Important factors that could cause actual results to differ
materially from the Company's expectations ("Cautionary Statements") are dis-
closed below and elsewhere in this report. All subsequent written and oral
forward-looking statements attributable to the Company or persons acting on
its behalf are expressly qualified by the Cautionary Statements.
PART I.
BUSINESS OF THE COMPANY
ITEM 1. BUSINESS
Overview
Callon Petroleum Company (the "Company") and its predecessors have been
engaged in the acquisition, development and exploration of oil and gas pro-
perties since 1950. The Company's properties are geographically concentrated
in Louisiana, Alabama and offshore Gulf of Mexico. 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.
The Company's objective is to enhance stockholder value through sustained
growth in its reserve base, production levels and resulting cash flows from
operations.
Business Strategy
Over the past seven years, the Company has increased its reserves through the
acquisition of producing properties that are geologically complex, have (or are
analogous to fields with) an established production history from stacked pay
zones and are candidates for exploitation. The Company focuses on reducing
operating costs and implementing production enhancements through the applica-
tion of technologically advanced production and recompletion techniques.
Since 1989, Callon acquired producing properties in 16 negotiated transactions,
on behalf of itself and, in certain cases, its primary institutional investor,
for an aggregate net purchase price of $194 million and, during that period,
the Company had an average Reserve Replacement Cost of $0.84 per Mcfe.
Over the past two years, the Company has shifted its emphasis from the acquisi-
tion of producing properties to the acquisition of acreage with development and
exploratory drilling opportunities to further increase potential recoverable
reserves. In 1995 and 1996, the Company acquired an extensive infrastructure
of production platforms, gathering systems and pipelines and joined with Murphy
Exploration and Production, Inc., ("Murphy") to acquire a 25% working interest
in 18 federal offshore blocks in the Gulf of Mexico. 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 these federal and
state waters in the Gulf of Mexico.
The Company's current exploratory and development operations are concentrated
in three main areas in the Gulf of Mexico: the Shallow Miocene focus area,
located in the state waters of Alabama and in the federal outer continental
shelf in the Gulf of Mexico ("OCS"); the Breton Sound area in the shallow
state waters of Louisiana; and the Gulf of Mexico Shelf Region in water depths
ranging up to 350 feet. Wells drilled in the Shallow Miocene focus area seek
oil and gas deposits from 1,800 to 6,000 feet, and are characterized by
relatively low exploration and development costs, high initial production
rates and short reserve lives. Wells drilled in the Breton Sound and the Gulf
of Mexico Shelf Region are generally more expensive to drill and complete and
have greater risks, but seek larger oil and gas deposits with longer reserve
lives.
In evaluating drilling opportunities, Callon performs extensive geological and
geophysical studies using computer aided exploration techniques ("CAEX"),
including, where appropriate, the acquisition of 3-D seismic or high-resolution
2-D seismic data to facilitate these efforts. Exploration and drilling
activities are generally considered to be of a higher risk than acquisitions
of producing oil and gas properties. 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 explora-
tion for oil and gas without discovery of commercial quantities of reserves will
have a material adverse effect upon the Company.
Risk Management
Volatility of Oil and Gas Prices. The Company's revenues, profitability and
future growth and the carrying value of its oil and gas properties are substan-
tially dependent on prevailing prices of oil and gas. The Company's ability to
maintain or increase its borrowing capacity and to obtain additional capital
on attractive terms is also substantially dependent upon oil and gas prices.
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond the control of the
Company. These factors include weather conditions in the United States, the
condition of the United States economy, the action of the Organization of
Petroleum Exporting Countries, governmental regulation, political stability
in the Middle East and elsewhere, the foreign supply of oil and gas, the
price of foreign imports and the availability of alternate fuel sources. Any
substantial and extended decline in the price of oil or gas would have an
adverse effect on the Company's carrying value of its proved reserves, borrowing
capacity, revenues, profitability and cash flows from operations.
Volatile oil and gas prices make it difficult to estimate the value of produc-
ing 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.
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. In a typical hedge transaction, the Company will have the right to
receive from the counterparty 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 counterparty 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 prices 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.
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 govern-
mental 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 coverage's 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 cover-
age 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 insur-
ance 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 opera-
tions.
Relations with Institutional Investors
Over the past several years, the Company has established relationships with
institutional investors which have been important to its acquisition strategy.
Since 1989, the Company has acquired for its institutional investors, and is
engaged in the operation and production management of oil and gas properties
with a total gross contract acquisition price of $170 million. These
arrangements with institutional investors vary from acquisition to acquisition.
In a typical transaction, the Company acquires a working interest and burdens
the working interest with a net profits interest transferred to the institu-
tional investor. The arrangements with institutional investors generally
provide that the Company earns an increased interest in the properties either
at the time of closing an acquisition or after the institution receives a
certain level of distributions. The Company also receives operating and
property management fees from its institutional investors and other joint
interest partners.
Competition
The oil and gas industry is highly competitive in all of its phases. Callon
encounters competition from other oil and gas companies in all areas of its
operations, including the acquisition of reserves and producing properties and
the marketing of oil and gas. Many of these companies possess greater financial
and other resources than the Company. Competition for producing properties will
be affected by the amount of funds available to the Company, information about
a producing property available to the Company and any standards established by
the Company for the minimum projected return on investment. Because gathering
systems and related facilities are the only practical method for the inter-
mediate transportation of gas, competition for gas delivery is presented by
other pipelines and gas gathering systems. Competition may also be presented
by alternative fuel sources.
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 loca-
tions to its leased space are anticipated to be readily available.
Employees
The Company had 141 employees as of December 31, 1996, none of whom are
currently represented by a union. The Company considers itself to have good
relations with its employees. The Company employs eight petroleum engineers
and four petroleum geoscientists.
Litigation
The Company is a defendant in various legal proceedings and claims which arise
in the ordinary course of Callon's business. Callon does not believe the ulti-
mate resolution of any such actions will have a material effect on the Company's
financial position or results of operations.
Federal Regulations
Sales of Natural Gas. Effective January 1, 1993, the Natural Gas Wellhead
Decontrol Act deregulated prices for all "first sales" of natural gas. Thus,
all sales of gas by the Company may be made at market prices, subject to
applicable contract provisions.
Transportation of Natural Gas. The rates, terms and conditions applicable to
the interstate transportation of natural gas by pipelines are regulated by the
Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act
("NGA"), as well as under section 311 of the Natural Gas Policy Act ("NGPA").
Since 1985, the FERC has implemented regulations intended to make natural gas
transportation more accessible to gas buyers and sellers on an open-access,
non-discriminatory basis.
Most recently, in Order No. 636, et seq., the FERC promulgated an extensive
set of new regulations requiring all interstate pipelines to "restructure"
their services. The most significant provisions of Order No. 636 (i) require
that interstate pipelines provide firm and interruptible transportation solely
on an "unbundled" basis, separate from their sales service, and convert each
pipeline's bundled firm city-gate sales service into unbundled firm transporta-
tion service; (ii) issue blanket certificates to pipelines to provide unbundled
sales service; (iii) require that pipelines provide firm and interruptible
transportation service on a basis that is equal in quality for all natural gas
supplies, whether purchased from the pipeline or elsewhere; (iv) require that
pipelines provide a new non-discriminatory "no-notice" transportation service;
(v) establish two new, generic programs for the reallocation of firm pipeline
capacity; (vi) require that all pipelines offer access to their storage
facilities on a firm and interruptible, open access, contract basis; (vii)
provide pregranted abandonment of unbundled sales and interruptible and
short-term firm transportation service and conditional pregranted abandonment
of long-term transportation service; (viii) modify transportation rate design
by requiring all fixed costs related to transportation to be recovered through
the reservation charge under the straight fixed variable ("SFV") method. The
order also recognized that the elimination of city-gate sales service and the
implementation of unbundled transportation service would result in consider-
able costs being incurred by the pipelines. Therefore, Order No. 636 provided
mechanisms for the recovery by pipelines from present, former and future
customers of certain types of "transition" costs likely to occur due to these
new regulations.
In subsequent orders, the FERC substantially upheld in the requirements imposed
by Order No. 636. Pursuant to Order No. 636, pipelines and their customers
engaged in extensive negotiations in order to develop and implement new service
relationships under Order No. 636. Tariffs instituting these new restructured
services were placed into effect on all pipelines on or before November 1, 1993.
Numerous petitions for judicial review of Order No. 636 have been filed and
consolidated for review in the United States Court of Appeals for the D. C.
Circuit. In addition, numerous parties have sought review of separate FERC
orders implementing Order No. 636 on individual pipeline systems. Since the
restructuring requirements that emerge from this lengthy administrative and
judicial review process may be materially different from those of Order No.
636 as originally adopted, it is not possible to predict what effect, if any,
the final rule resulting from Order No. 636 will have on the Company.
Sales and Transportation of Crude Oil. Sales of crude oil and condensate can be
made by the Company at market prices not subject at this time to price controls.
The price that the Company receives from the sale of these products will be
affected by the cost of transporting the products to market. As required by
the Energy Policy Act of 1992, the FERC has revised its regulations governing
the rates that may be charged by oil pipelines. The new rules, which were
effective January 1, 1995, provide a simplified, generally applicable method
of regulating such rates by use of an index for setting rate ceilings. In
certain circumstances, the new rules permit oil pipelines to establish rates
using traditional cost of service and other methods of ratemaking. The effect
that these new rules may have on moving the Company's products to market cannot
yet be determined. In addition, at the same time as it issued the new rules,
the FERC also issued notices of inquiry regarding market-based pricing for oil
pipeline rates and the information required to be filed for ratemaking and
reporting purposes. It is not possible to predict what rules, if any, the FERC
will ultimately adopt as a result of these inquiry proceedings or the effect
that any rules that are adopted might have on the cost of moving the Company's
products to market.
Legislative Proposals. In the past, Congress has been very active in the area
of natural gas regulation. There are legislative proposals pending in various
state legislatures which, if enacted, could significantly affect the petroleum
industry. At the present time it is impossible to predict what proposals, if
any, might actually be enacted by Congress or the various state legislatures
and what effect, if any, such proposals might have on the Company's operations.
Federal, State or Indian Leases. In the event the Company conducts operations
on federal, state or Indian oil and gas leases, such operations must comply
with numerous regulatory restrictions, including various nondiscrimination
statutes, and certain of such operations must be conducted pursuant to certain
on-site security regulations and other appropriate permits issued by the Bureau
of Land Management ("BLM") or Minerals Management Service or other appropriate
federal or state agencies.
The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect
ownership of any interest in federal onshore oil and gas leases by a foreign
citizen of a country that denies "similar or like privileges" to citizens of
the United States. Such restrictions on citizens of a "non-reciprocal" country
include ownership or holding or controlling stock in a corporation that holds
a federal onshore oil and gas lease. If this restriction is violated, the
corporation's lease can be canceled in a proceeding instituted by the United
States Attorney General. Although the regulations of the BLM (which
administers the Mineral Act) provide for agency designations of non-reciprocal
countries, there are presently no such designations in effect. The Company
owns interests in numerous federal onshore oil and gas leases. It is possible
that holders of equity interests in the Company may be citizens of foreign
countries, which at some time in the future might be determined to be non-
reciprocal under the Mineral Act.
State Regulations
Most states regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. The rate of production may be regulated and the maximum
daily production allowable from both oil and gas wells may be established on
a market demand or conservation basis or both.
The Company may enter into agreements relating to the construction or operation
of a pipeline system for the transportation of natural gas. To the extent that
such gas is produced, transported and consumed wholly within one state, such
operations may, in certain instances, be subject to the jurisdiction of such
state's administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates which the Company could charge
for gas, the transportation of gas, and the construction and operation of such
pipeline would be subject to the rules and regulations governing such matters,
if any, of such administrative authority.
Environmental Regulations
General. The Company's activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. Although no assurances can be made, the Company believes that, absent
the occurrence of an extraordinary event, compliance with existing federal,
state and local laws, rules and regulations regulating the release of materials
in the environment or otherwise relating to the protection of the environment
will not have a material effect upon the capital expenditures, earnings or the
competitive position of the Company with respect to its 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 trans-
porting, processing, treating or storing natural gas and other products, are
subject to stringent environmental regulation by state and federal authorities
including the United States Environmental Protection Agency ("EPA"). Such
regulation can increase the cost of planning, designing, installation and
operation of such facilities. In most instances, the regulatory requirements
relate to water and air pollution control measures. Although the Company
believes that compliance with environmental regulations will not have a
material adverse effect on it, risks of substantial costs and liabilities are
inherent in oil and gas production operations, and there can be no assurance
that significant costs and liabilities will not be incurred. Moreover, it is
possible that other developments, such as stricter environmental laws and
regulations, and claims for damages to property or persons resulting from oil
and gas production, would result in substantial costs and liabilities to the
Company.
Solid and Hazardous Waste. The Company owns or leases numerous properties
that have been used for production of oil and gas for many years. Although
the Company has utilized operating and disposal practices standard in the
industry at the time, hydrocarbons or other solid wastes may have been
disposed or released on or under these properties. In addition, many of
these properties have been operated by third parties. The Company had no
control over such entities' treatment of hydrocarbons or other solid wastes
and the manner in which such substances may have been disposed or released.
State and federal laws applicable to oil and gas wastes and properties have
gradually become stricter over time. Under these new laws, the Company could
be required to remove or remediate previously disposed wastes (including wastes
disposed or released by prior owners or operators) or property contamination
(including groundwater contamination by prior owners or operators) or to per-
form remedial plugging operations to prevent future contamination.
The Company generates wastes, including hazardous wastes, that are subject to
the Federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA has limited the disposal options for certain hazardous
wastes and is considering the adoption of stricter disposal standards for non-
hazardous wastes. Furthermore, it is possible that certain wastes currently
exempt from treatment as "hazardous wastes" generated by the Company's oil and
gas operations may in the future be designated as "hazardous wastes" under RCRA
or other applicable statutes, and therefore be subject to more rigorous and
costly disposal requirements.
Superfund. The Comprehensive Environmental Response, Compensation and Lia-
bility 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 sub-
stances 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, con-
struction 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 respons-
ibility. 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 require-
ments 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 inform-
ation 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 explor-
ation 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 in Alabama, Louisiana, Texas and federal and state
waters in the Gulf of Mexico. As of December 31, 1996, the Company's estimated
proved reserves totaled 3.8 million barrels of oil and 50.4 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 $160.2 million. Gas constitutes approximately 69%
of the Company's total estimated proved reserves and approximately 95% of the
Company's reserves are proved producing reserves. The Company operates 149 wells
representing approximately 78% of the total Discounted Cash Flow attributable
to estimated proved reserves.
Significant Producing Properties
The following table shows Discounted Cash Flows and estimated net proved oil
and gas reserves by major field for the Company's five largest producing fields
and for all other properties combined at December 31, 1996.
Percent Estimated Net Proved
Discounted Total Oil Gas
Field Name/ Primary Cash Flow Discounted Reserves Reserves
Location Operator(s) ($000)(a) Cash Flow (MBbls) (MMcf)
- -------------------- ----------- ---------- ---------- -------- --------
Main Pass 163 Area Callon $ 55,604 34.72% -- 20,196
Federal Waters
Chandeleur Block 40 Callon 48,000 29.97% -- 16,782
Federal Waters
Big Escambia Creek Exxon 14,492 9.05% 991 2,673
Southeast Alabama
Black Bay Complex Callon 11,394 7.11% 1,920 684
Louisiana State
Waters
North Dauphin Island Field Callon 6,455 4.03% -- 2,685
Alabama State
Waters
Other properties Various 24,226 15.12% 908 7,404
-------- ------- ----- ------
Total $160,171 100.00% 3,819 50,424
======== ======= ===== ======
_________
(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, 1996, as set forth in the
Company's independent reserve reports prepared by Huddleston & Co., Inc. of Houston, Texas.
Main Pass 163 Area
In two separate transactions during 1996, Callon acquired a 100% working
interest in Chandeleur Block 41 and Main Pass Blocks 159, 160, 161 and 163.
The acquisition initially included five wells producing 4 MMcf/d, as well as
production facilities at Main Pass 163 capable of handling 90 MMcf/d.
Based upon interpretation of seismic data acquired and processed by Callon an
exploratory well was drilled on Main Pass Block 163 during the fourth quarter
of 1996. At year-end the well was producing 18 MMcf/d. A development well was
also drilled on Main Pass Block 161 and tested at a rate of 4 MMcf/d. This
well and four others were shut-in at year-end waiting on compression equipment
upgrades scheduled for the first quarter of 1997.
The Main Pass 163 Area wells produce from Shallow Miocene reservoirs at approx-
imate depths of 3,300 feet. Proved reserves at year-end attributable to this
area were 20.2 Bcf, representing 34.7% of the Company's Discounted Cash Flow.
Chandeleur Block 40
The Company and an institutional investor purchased a 33.3% working (27.8% net
revenue) interest in Chandeleur Block 40 in 1994. On December 29, 1995, Callon
acquired an additional 66.7% working (55.5% net revenue) interest in the
Chandeleur Block 40 for $9 million and subsequently sold a 22.2% working
interest in the field to the William G. Helis Interest for $3 million. The
Company currently holds a combined 52.3% working (43.6% net revenue) interest
in this property. The field's remaining proved reserves are estimated to be
16.8 Bcf of natural gas (net to the Company).
When the Company assumed operations of the field, two wells were producing 5.5
MMcf per day 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 field
production to 12 MMcf/d of natural gas.
During the fourth quarter of 1996, the Company drilled a development well in the
field which began producing in mid-December at the rate of 21 MMcf/d. The well
resulted in a field extension which added 6 Bcf in net reserves to the Company.
Total field production was approximately 30 MMcf/d at December 31, 1996.
Big Escambia Creek
On June 29, 1995, the Company purchased 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 at December 31, 1996 was 3.0 MBbls
of condensate, 1.6 MBbls of natural gas liquids, 7.6 MMcf of residue natural
gas and 330 long tons of sulphur. 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.
Black Bay Complex
The Company-operated Black Bay Complex (the "Complex") is located in shallow
waters off the Louisiana coast. It consists of eight fields, 90 producing
wells and approximately 30,000 acres of oil and gas leases, all of which are
held by production. The Company owns an average 15.4% working (11.6% net
revenue) interest in the Complex and an institutional investor, whose pro-
perties are managed by the Company, owns a 32.6% working interest. At December
31, 1996 the Complex was producing 4,750 barrels of oil per day and cumulative
production had reached 241 million barrels of oil and 216 Bcf of natural gas.
The discovery well in the Complex was completed in 1949. Forty-five different
sandstone formations and 137 separate reservoirs ranging in depth from 6,200 to
9,600 feet have been identified within the Complex. The Company assumed
operations of the Complex in August 1992, and since that time the Company has
successfully drilled seven development wells, including a horizontal well, and
implemented fourteen recompletions, seven of which employed a new stimulation
technology.
North Dauphin Island Field
The Company owns a 94.4% working (72.6% net revenue) interest in the North
Dauphin Island Field located in shallow Alabama state waters. The field was
discovered in April 1990, and the wells produce from a Shallow Miocene reservoir
at approximately 1,800 feet. At December 31, 1996, there were three producing
gas wells, two of which were drilled horizontally, with gross production of 7.5
MMcf per day.
The Company also owns a production platform, including compressors and dehydra-
tion facilities, an associated gathering system and a 12-inch, 12-mile pipeline
("North Dauphin Island Platform"). This pipeline runs to existing onshore con-
nections with the pipeline systems of Koch Gateway Pipeline Company, Trans-
continental Gas Pipe Line Corporation and Florida Gas Transmission Company.
The Company gathers its production and gas production from other producers
connected to its system, and transports the gas to the major pipeline con-
nections. The current throughput capacity of the gathering and transportation
facility is in excess of 100 MMcf per day and with additional compression, the
throughput capacity can be increased to 130 MMcf per day. The ownership of the
North Dauphin Island Platform and associated pipeline provides the Company with
a significant strategic advantage in the North Dauphin Island area.
In 1995, the Company signed an agreement with a subsidiary of a major oil
company providing for natural gas gathering services and transportation through
the North Dauphin Island Platform to onshore pipeline connections. The agree-
ment further provides for the subsidiary to purchase firm capacity commitments
from the Company for natural gas deliveries through the North Dauphin Island
Platform for 15 years, which commended in April 1996, to transport up to 100
MMcf per day of the subsidiary's natural gas production. Firm capacity reserva-
tions will average over $1.0 million per year through the term of the contract.
Additional revenues may be received depending upon the actual throughput used
by the subsidiary.
Exploration and Development Projects
Over the last two years, the Company shifted the focus of its operations from
the acquisition and exploitation of oil and gas properties to exploratory and
developmental drilling. The Company's exploration and development activity is
focused primarily in three areas in the Gulf of Mexico: the Shallow Miocene
focus area, the Gulf of Mexico Shelf Region and the Breton Sound area.
Shallow Miocene Area
In December 1995, Callon began implementing its new business strategy by
acquiring an additional interest in Chandeleur Block 40 which increased its
ownership to a 52.3% working interest. In June 1996, Callon, through a
property exchange with an industry partner, acquired a 64% average working
interest in Chandeleur Block 41, Main Pass 159, 160, 161 and 163 in the OCS
in the Gulf of Mexico. In July and August, Callon acquired acreage interests
in Main Pass 164 and 165 and an interest in the production facilities at Main
Pass 164. In October, Callon acquired additional interests in Chandeleur Block
41 and Main Pass 159 and 161. As a result of these acquisition efforts, Callon
has developed a concentrated leasehold position of 33,300 net acres in eight
contiguous blocks on which it has 11 producing wells. It owns a 100% working
interest in five of the blocks and an average 55% working interest in the
remaining three. Callon also owns a 100% working interest in the production
facilities at Main Pass 163 and an approximate 55% working interest in the
production facilities at Chandeleur Block 40 and Main Pass Block 164. During
the third quarter, Callon completed the acquisition and processing of more than
1,000 miles of seismic data over these blocks and identified eight potential
drilling locations.
During September and October, three Shallow Miocene prospects were successfully
drilled and completed. The first prospect was drilled on Main Pass 163 and
encountered 54 feet of net pay in a new natural gas reservoir at approximately
3,300 feet. The Company has a 100% working (83% net revenue) interest in the
well and it is producing approximately 18 MMcf/d (15 MMcf/d net to the Company)
at December 31, 1996. The second drilled prospect, Chandeleur Block 40,
encountered 44 feet of net pay at a depth of approximately 3,850 feet. Along
with the previously existing well which is producing 9.2 MMcf/d, total
production from Chandeleur Block 40 stands at 30.2 MMcf/d at December 31, 1996.
This estimated 21 MMcf/d increase in production will add 9.2 MMcf/d net to the
Company's 52% working (43.6% net revenue) interest. The third prospect was a
sidetracked development well at Main Pass 161. This well was completed and
tested at a rate of 4 MMcf/d. Callon's 100% working (77.8% net revenue)
interest in the well should add 3 MMcf/d to our existing production when the
compression facilities are upgraded in the first quarter of next year.
During 1997, the Company's Shallow Miocene plans include the drilling of at
least two developmental wells and performing one major workover and one
recompletion. Also during 1997, the Company will continue evaluating
additional acquisition, exploration and development opportunities in this area.
Gulf of Mexico Shelf Region
In addition to the prospects in its Shallow Miocene focus area, the Company has
developed an inventory in the OCS which is intended to explore for reserves at
depths generally in excess of 10,000 feet. Callon entered this area by enter-
ing into a joint bidding agreement with Murphy Oil Corporation and participating
in the Outer Continental Shelf lease sales conducted by the Minerals Management
Service. In April 1996, the Callon/Murphy team was the high bidders on 13 lease
blocks encompassing 61,000 acres located in offshore Louisiana waters. These
blocks included six in the West Cameron South Addition, two in Mississippi
Canyon and one block each in Eugene Island, South Marsh Island, Vermillion and
Main Pass East Addition. In September, Callon again joined with Murphy and
was the high bidder on six offshore Texas tracts encompassing 35,000 acres.
These blocks include two in the High Island East Addition South Extension,
one in the High Island South Addition and three in Garden Banks. Callon owns
a 25% working interest in the offshore lease blocks acquired jointly with
Murphy.
The Company's 1997 drilling program currently includes ten exploratory wells
on eight blocks. The Company's plans for its deep water prospects on the
Mississippi Canyon and Garden Banks blocks have not yet been finalized. The
Company also plans to again participate with Murphy in the 1997 federal lease
sales in the Gulf of Mexico.
Breton Sound
The Company's Breton Sound focus area is located in shallow state waters off the
Louisiana coast at the mouth of the Mississippi River. Callon owns interests in
and operates several large old prolific fields there, including the Main Pass
32/35 area and the Black Bay Complex consisting of eight fields. The Company's
focus has been on the exploitation of the known producing horizons and now is
directed toward deeper potential prospects.
Main Pass Block 35. Since its discovery in 1951, production from Main Pass
Block 35, located in Louisiana state waters, has totaled 66.4 MMBbls of oil
and 76 Bcf of natural gas from 28 reservoirs ranging in depth from 6,000 to
9,000 feet. The Company purchased a 10% working interest in the field in 1991,
increasing to 19% after payout to the Company's institutional investor who owns
the remaining interest. After extensive analysis of seismic data from the area,
the Company believes there is exploration potential in deeper sands, and in
1995, purchased a 100% interest in two lease blocks that offset the producing
block. The Company contracted a 36 square-mile, 3-D seismic survey, which
commenced in July 1995, and covers the producing and newly acquired leases.
In November 1996, the Company received the survey covering its Main Pass 32/35
area. Callon identified numerous prospects both under and outside of its then
existing 4,467-acre Main Pass 32 lease. Based upon the new seismic, in December
1996, the Company acquired six contiguous tracts covering an additional 5,170
acres at a total cost of $3.1 million. The Company anticipates drilling
activities to begin in this area by mid-year 1997. The Company's interest
in the activities will vary between 10% and 100%, depending on the extent to
which the various leases are pooled.
Black Bay Complex. The Black Bay Complex was discovered in 1949 and since
that time has produced 237 MMBbls of oil and 213 Bcf of natural gas from 45
sandstone formations and 137 reservoirs with depth ranging from 6,200 to 9,600
feet. It consists of eight fields with 90 wells producing 4,750 barrels of oil
per day and 30,000 acres of oil and gas leases held by production. Callon
holds an average 15.4 percent working (11.6 percent net revenue) interest in
the Complex and manages a 32.6 percent working interest for an institutional
investor.
Since assuming operations of the Complex in 1992, the Company has substantially
reduced operating costs, successfully drilling six development wells, including
one horizontally, and implemented 14 recompletions. Callon has an inventory of
over 32 identified development locations and recompletion candidates at Black
Bay, and is evaluating the use of 3-D seismic to identify additional reserves.
Oil and Gas Reserves
The following table sets forth certain information about the estimated proved
reserves of the Company as of the dates set forth below.
December 31,
--------------------------------
1996 1995 1994(a)
(In thousands)
Proved developed:
Oil (Bbls) 3,385 3,890 3,309
Gas (Mcf) 49,491 20,408 20,582
Proved undeveloped:
Oil (Bbls) 434 876 1,115
Gas (Mcf) 933 9,259 3,520
Total proved:
Oil (Bbls) 3,819 4,766 4,424
Gas (Mcf) 50,424 29,667 24,102
Estimated pre-tax future net cash flows $216,154 $95,730 $59,477
Discounted Cash Flows $160,171 $63,764 $41,383
__________
(a) Reserves prior to September 16, 1994 represent the combined reserves
of the Company's predecessors.
The Company's independent reserve engineers (Huddleston & Co., Inc. of Houston,
Texas) prepared the estimates of the proved reserves and the future net cash
flows (and present value thereof) attributable to such proved reserves.
Reserves were estimated using oil and gas prices and production and
development costs in effect on December 31 of each such year, without
escalation, and were otherwise prepared in accordance with Securities
and Exchange Commission ("SEC") regulations regarding disclosure of oil and
gas reserve information.
There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond the control of the Company and the
reserve engineers. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner, and the accuracy of any reserve or cash flow estimate is a function of
the quality of available data and of engineering and geological 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,
---------------------------------------------------
1996 1995 1994(a)
--------------- -------------- -------------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Development:
Oil 1 .09 6 .65 7 .36
Gas 2 1.52 1 .13 -- --
Non-Productive -- -- -- -- 6 .42
---- ---- ---- ---- ---- ----
Total 3 1.61 7 .78 13 .78
==== ==== ==== ==== ==== ====
Exploration:
Oil -- -- 1 .24 -- --
Gas 1 1.0 -- -- -- --
Non-Productive -- -- -- -- 1 .24
---- ---- ---- ---- ---- ----
Total 1 1.0 1 .24 1 .24
==== ==== ==== ==== ==== ====
__________
(a) Drilling results prior to September 16, 1994 represent the combined
drilling results of the Company's predecessors.
The Company owned working and royalty interests in approximately 894 gross
(35.93 net) producing oil and 316 gross (21.15 net) producing gas wells as of
December 31, 1996. 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, 1996, the Company had three exploratory gas wells in progress.
Leasehold Acreage
The following table shows the approximate developed and undeveloped (gross and
net) leasehold acreage of the Company as of December 31, 1996.
Leasehold Acreage
--------------------------------------------
Developed Undeveloped
-------------------- ------------------
State Gross Net Gross Net
- -------------- ------ ------ ------ -----
Alabama 13,136 12,210 944 190
California -- -- 480 480
Louisiana 46,958 5,321 8,766 6,268
Michigan 4,273 185 -- --
Mississippi 3,323 1,433 564 564
Oklahoma 8,987 973 -- --
Texas 12,390 761 -- --
Utah 2,560 295 -- --
Federal Waters 54,962 34,553 96,075 24,019
------- ------ ------- ------
Total 146,589 55,731 106,829 31,521
======= ====== ======= ======
As of December 31, 1996, the Company owned various royalty and overriding
royalty interests in 1,366 net developed acres and 6,953 undeveloped acres.
In addition, the Company owned 5,464 developed and 134,536 undeveloped mineral
acres.
Major Customers
For the year ended December 31, 1996, Northridge Energy Marketing Company,
Williams Energy Services, Inc. and Sonat Gas Marketing Co. L. P. purchased 21%,
27% and 14%, respectively, of the Company's crude oil and natural gas produc-
tion. Northridge purchased crude oil production from the Black Bay Complex,
Williams Energy Services, Inc. purchased natural gas from the North Dauphin
Island Field, and Sonat Gas purchased natural gas from Callon owned interests'
in federal OCS leases, Chandeleur Block 40, Main Pass 163 and Main Pass 164/165.
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 material
adverse impact on the Company's ability to sell its products.
Title to Properties
The Company believes that the title to its oil and gas properties is good and
defensible in accordance with standards generally accepted in the oil and gas
industry, subject to such exceptions which, in the opinion of the Company, are
not so material as to detract substantially from the use or value of such pro-
perties. 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 pro-
perties of the kind owned by the Company.
ITEM 3. LEGAL PROCEEDINGS
The Company was not and currently is not a party to any material pending legal
proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth
quarter of 1996.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock began trading on the Nasdaq National Market System
on September 19, 1994, under the symbol "CLNP". The high and low sale prices
were as follows:
Quarter Ended Low High
September 30, 1994 11 1/4 13 1/2
December 31, 1994 10 1/2 12 3/4
March 31, 1995 9 1/2 11
June 30, 1995 9 10 1/2
September 30, 1995 9 1/4 12 1/4
December 31, 1995 9 1/32 11
March 31, 1996 9 1/2 10 3/4
June 30, 1996 10 14 1/4
September 30, 1996 10 3/4 13 1/2
December 31, 1996 12 1/2 19 1/8
As of March 12, 1997, there were approximately 8,074 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, 1996 have been derived
from the audited Consolidated Financial Statements of the Company for such
periods. The information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements and Notes thereto. The following
information is not necessarily indicative of future results for the Company.
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
Year Ended December 31,
------------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- -------- -------- --------
Statement of Operations Data(a):
Revenues:
Oil and gas sales $ 25,764 $ 23,210 $ 13,948 $ 10,048 $ 10,015
Interest and other 946 627 171 230 232
--------- --------- -------- -------- --------
Total revenues 26,710 23,837 14,119 10,278 10,247
--------- --------- -------- -------- --------
Costs and expenses:
Lease operating expenses 7,562 6,732 4,042 3,713 3,702
Depreciation, depletion and amortization 9,832 10,376 6,049 3,411 3,360
General and administrative 3,495 3,880 3,717 2,350 1,848
Interest 313 1,794 624 196 160
--------- --------- -------- -------- --------
Total costs and expense 21,202 22,782 14,432 9,670 9,070
--------- --------- -------- -------- --------
Income (loss) from operations 5,508 1,055 (313) 608 1,177
Income tax expense (benefit) 50 -- (200) 113 235
--------- --------- -------- -------- --------
Income (loss) before cumulative effect of
change in accounting principle 5,458 1,055 (113) 495 942
Cumulative effect of change in accounting principle (b) -- -- -- 5,262 --
--------- --------- -------- -------- --------
Net income (loss) 5,458 1,055 (113) 5,757 942
Preferred stock dividends 2,795 256 -- -- --
--------- --------- -------- -------- --------
Net income (loss) available to common shares 2,663 799 (113) 5,757 942
Pro forma adjustment for income taxes (c) -- -- -- 100 145
--------- --------- -------- -------- --------
Pro forma net income (loss) $ 2,663 $ 799 $ (113) $ 5,657 $ 797
========= ========= ======== ======== ========
Net income (loss) per common share:
Primary $ .45 $ .14 $ (.03) $ 1.53 $ .25
Assuming full dilution $ .43 $ .14 $ (.03) $ 1.53 $ .25
Shares used in computing net income (loss) per common share:
Primary 5,952 5,755 4,346 3,769 3,769
Assuming full dilution 6,135 5,755 4,346 3,769 3,769
Balance Sheet Data (end of period)(a):
Oil and gas properties, net $ 82,489 $ 57,765 $ 43,920 $ 21,000 $ 22,138
Total assets $ 118,520 $ 83,867 $ 73,786 $ 39,825 $ 35,570
Long-term debt, less current portion $ 24,250 $ 100 $ 15,363 $ 233 $ 580
Stockholders' Equity $ 77,864 $ 75,129 $ 43,431 $ 27,170 $ 22,711
____________
(a) The Company succeeded to the business and properties of Callon Petroleum Operating Company, Callon Consolidated
Partners, L. P. and CN Resources on September 16, 1994 pursuant to the Consolidation. Historical information about
the Company prior to September 16, 1994 includes the financial and operating information of the predecessors of the
Company, other than the interest in CN not owned by Callon Petroleum Operating Company, combined as entities under
common control in a manner similar to a pooling of interests.
(b) As a result of the combination of the Company and CCP there was a change in the tax status of the Company; there-
fore, the Company was able to reduce the valuation allowance at January 1, 1993 by $5,262,000, or $1.40 per common
share. The net asset represents the statutory depletion carryforward (which has an unlimited carryforward period)
and the portion of the federal net operating loss carryforward that the Company's management believes will be utilized.
All other temporary differences are offset by the valuation allowance, which represents that portion of the asset that
management believes is more likely than not, that it will not be realized.
(c) The pro forma adjustment for income taxes of $100,000, or $.03 per common share, relates to the income of CCP prior to
the Consolidated as if such income was taxed as a corporation. Pro forma tax adjustments were provided only to the
extent CCP had income, thus none was recorded in 1994.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
General
The Company's revenues, profitability and future growth and the carrying value
of its oil and gas properties are substantially dependent on prevailing prices
of oil and gas. The Company's ability to maintain or increase its borrowing
capacity and to obtain additional capital on attractive terms is also influenced
by oil and gas prices. Prices for oil and gas are subject to large fluctuation
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.
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.
Liquidity and Capital Resources
The Company's primary sources of capital are its cash flows from operations,
borrowings from financial institutions and sale of equity securities. Cash
provided from operations during 1996 totaled $15.8 million. During 1996, the
Company borrowed $12.9 million from financial institutions and repaid such
borrowing with the proceeds from the sale of $24,150,000 in Senior Sub-
ordinated Notes in November, 1996. At December 31, 1996, the Company had
working capital in the amount of $4.9 million.
Effective October 31, 1996, the Company entered into a new Credit Facility with
Chase Manhattan Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. The Credit Facility provides for borrowings of a maximum of the
lesser of $50 million or a borrowing base ("Borrowing Base") determined
periodically on the basis of a discounted present value of future net cash
flows attributable to the Company's proved producing oil and gas reserves.
Through May 15, 1997, the Credit Facility provides a $30 million Borrowing
Base. Pursuant to the Credit Facility, depending upon the percentage of the
unused portion of the Borrowing Base, the interest rate is equal to either the
lender's prime rate or the lender's prime rate plus 0.50%. The Company, at its
option, may fix the interest rate on all or a portion of the outstanding
principal balance at either 1.00% or 1.375% above a defined "Eurodollar" rate,
depending upon the percentage of the unused portion of the Borrowing Base, for
periods of up to six months. The weighted average interest rate for the total
debt outstanding at December 31, 1996 was 8.25%. 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. At December 31, 1996,
the unpaid balance due on the Credit Facility was $100,000.
On November 27, 1996, the Company issued $24,150,000 of 10% Senior Subordinated
Notes that will mature December 15, 2001. The Company used the proceeds to pay
down the Credit Facility and for other corporate purposes. Interest is payable
quarterly beginning March 15, 1997. The notes are redeemable at the option of
the Company, in whole or in part, on or after December 15, 1997, at 100% of the
principal amount thereof, plus accrued interest to the redemption date. The
notes are general unsecured obligations of the Company, subordinated in right
of payment to all existing and future indebtedness of the Company. The credit
facility and the subordinated debt contain various covenants including
restrictions on additional indebtedness and payment of cash dividends as well
as maintenance of certain financial ratios.
Over the past seven years, the Company has established relationships with
institutional investors which have been important to its producing property
acquisition strategy. The Company believes these relationships provide it with
the ability to make larger acquisitions than would otherwise be possible. In
a typical transaction, the Company will acquire a working interest and burden
the working interest with a net profits interest transferred to the institu-
tional investor. The arrangements generally provide that the Company earns
an increased interest in the properties either at the time of closing or
after the institution receives a certain level of distributions. The Company
also receives operating and property management fees from its institutional
investors and joint interest partners which enables the Company to maintain a
larger and more experienced staff.
Capital expenditures for 1996 totaled $36.1 million which included $19.2
million of lease acquisitions, $2.7 million for the acquisition of producing
properties and equipment and $14.2 million for property development and drilling
activities on new and previously existing properties. Over the past two
years, the Company has shifted its focus from acquisition of producing
properties to the acquisition of acreage with development and drilling
opportunities. Therefore, future capital expenditure requirements will depend
somewhat on exploration results. The Company's plans for 1997 include capital
expenditures equal to or greater than those amounts expended for the current
year. Projected cash flow from operations and borrowings under the Company's
Credit Facility are anticipated to be sufficient to fund this capital budget;
however, the Company will consider alternative sources of financing.
Results of Operations
The following table sets forth certain operating information with respect to
the oil and gas operations of the Company for the three year period ended
December 31, 1996.
December 31,
------------------------------------
1996 1995 1994
-------- -------- --------
Production:
Oil (MBbls) 585 594 364
Gas (MMcf) 6,269 6,694 4,076
Total production (MMcfe) 9,781 10,261 6,260
Average sales price:
Oil (per Bbl) $ 18.27 $ 16.68 $ 15.63
Gas (per Mcf) $ 2.40 $ 1.96 $ 2.00
Total production (per Mcfe) $ 2.63 $ 2.24 $ 2.21
Average costs (per Mcfe):
Lease operating expense (excluding severance taxes) $ 0.57 $ 0.49 $ 0.49
Severance taxes $ 0.20 $ 0.17 $ 0.16
Depreciation, depletion and amortization $ 1.01 $ 1.01 $ 0.97
General and administrative (net of management fees) $ 0.36 $ 0.38 $ 0.59
Comparison of Results of Operations for the Years Ended
December 31, 1996 and 1995
Oil and Gas Revenue
Oil and gas sales increased $2.6 million, or 11%, during 1996 to $25.8 million
compared to $23.2 million in 1995. While oil and gas production volumes for
1996 were lower than those reported in 1995, substantial price increases in
both oil and gas more than offset the loss in revenues. The average sales
price per barrel sold in 1996 increased to $18.27, compared to $16.68 for
1995. The average sales price per Mcf of gas sold increased from $1.96 in
1995 to $2.40 in 1996.
Oil production for 1996 decreased slightly to 585,000 barrels from the 594,000
barrels produced in 1995. This reduction was primarily attributable to the
implementation of the required environmental protection program (zero discharge)
at our Black Bay Complex, the Company's largest single oil producing prospect.
During this process, several producing wells were shut-in while various new
equipment was installed. In addition, several wells were temporarily shut-in
while repairs were conducted on the service lines. Therefore, average daily
production for 1996 dropped to 1,599 barrels per day compared to 1,629 barrels
per day in 1995.
Gas production for 1996 was 6.3 Bcf, a decrease from the 6.7 Bcf reported in
1995. This reduction was primarily attributable to the loss of production from
the North Dauphin Island Field where problems with excess water content in the
gas sales stream were encountered early in the year requiring the installation
of a dehydrator and removal of water from the lines. Extraneous water produc-
tion from the #2A well led to the shut-in of the well and the natural decline
of the reservoir pressure. Also during the year, this field incurred a lower
production rate due to compressor inefficiencies which led to a compressor
restaging program that was completed in late September.
Lease Operating Expenses
Lease operating expenses, including severance taxes, increased from $6.7 million
in 1995 to $7.6 million in 1996. A large portion of this increase, $600,000, is
attributable to normal expenses associated with new property additions. Other
expenses included the installation of a dehydrator and the workover expenses at
the North Dauphin Island Field.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization expense for 1996 was $9.8 million
compared to $10.4 million for 1995. When compared on a per unit-of-production
basis, the expense incurred was $1.01 per Mcfe produced for each of the two
years.
General and Administrative Expenses
General and administrative expenses declined from $3.9 million for 1995 to
$3.5 million for 1996, as a result of the Company's continued efforts to
improve operational efficiencies.
Interest Expense
Interest expense decreased from $1.8 million in 1995 to $313,000 in 1996.
This expense reduction corresponds with the smaller average monthly outstanding
balance on the long-term debt of the Company for 1995 when compared to 1996.
During the fourth quarter of 1995, the Company used $25.1 million of the
proceeds from the sale of preferred stock to reduce its long-term debt. During
the course of 1996, additional funds advanced under the Company's line of credit
were repaid in November when the Company issued $24,150,000 of 10% Senior
Subordinated Notes. The average outstanding balance in long-term debt during
1996 was $5.3 million.
Income Taxes
The recorded income tax expense for 1996 was $50,000. The computed provision
for income taxes at the Company's expected statutory rate was $1.9 million,
which was primarily offset by a reduction in the deferred tax asset valuation
allowance as a result of the Company's ability to utilize its net operating
losses and depletion carryforwards.
Comparison of Results of Operations for the Years Ended
December 31, 1995 and 1994
Oil and Gas Revenue
Oil and gas sales increased $9.3 million, or 66%, during 1995 to $23.2 million
compared to $13.9 million in 1994. This increase was partially attributable to
the Company's purchase in September 1994 of NOCO Enterprises, L. P.'s interest
("NOCO Interest") in CN Resources ("CN") pursuant to the Consolidation as well
as the acquisition of certain properties from W&T Offshore, Inc. The Company's
purchase of the Escambia Minerals properties in June 1995 also contributed
$1.9 million to the increase in oil and gas sales.
Oil production from the newly acquired interest in the Black Bay Complex, the
Escambia Minerals properties and the W&T properties substantially outweighed
normal production declines in previously existing properties, as oil production
for 1995 increased to 594,000 barrels from the 1994 level of 364,000 barrels.
The average price per barrel sold also increased by $1.05 in 1995 compared to
1994 prices, resulting in a total $4.3 million increase in oil revenues.
Total gas production increased 2.6 Bcf to 6.7 Bcf in 1995 compared to 4.1 Bcf
in 1994. A substantial portion of this increase in production was attributable
to the Company's acquisition of the North Dauphin Island Field. Gas production
from North Dauphin Island Field increased from 2.5 Bcf in 1994 to 5.1 Bcf in
1995 and added $5.0 million in revenues in 1995 compared with 1994. Although
spot market gas prices declined in 1995, natural gas price hedges limited the
decline to $.04 per Mcf.
Lease Operating Expenses
Lease operating expenses, including production taxes, increased 67% during 1995
to $6.7 million, compared to $4.0 million for 1994. This increase was largely
attributable to the corresponding increase in oil and gas production caused by
the Company's acquisition of the NOCO Interest, the Escambia Minerals properties
and the W&T properties. The Company's purchase of the NOCO Interest in
September, 1994 resulted in an increase in combined lease operating expenses
attributable to the North Dauphin Island Field and the Black Bay Complex from
$1.5 million in 1994 to $3.6 million in 1995. Lease operating expenses on a
Mcfe basis increased by less than 2% to $0.66 for 1995 compared to $0.65 for
1994.
Depreciation, Depletion and Amortization
Total depreciation, depletion and amortization expense was $10.4 million for
1995, compared to $6.0 million for 1994. This increase reflects additional
production and reserves resulting from the purchase of the NOCO Interest, the
Escambia Minerals properties and the W&T properties.
General and Administrative
General and administrative expenses were $3.9 million for 1995, compared to
$3.7 million in 1994. The increase was primarily attributable to the
Company's expanding operations.
Income Taxes
The Company had a zero effective tax rate for 1995, compared to an effective
rate of (63)% in 1994. The 1995 rate was primarily due to a reduction in the
deferred tax asset valuation allowance of $551,000. The valuation allowance
was reduced during 1995 due to a reduction in the gross deferred tax asset.
This valuation allowance represented the portion of federal net operating loss
carryforward and other temporary differences which the Company believes will
not be utilized.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Report of Independent Public Accountants 27
Consolidated Balance Sheets as of the Years Ended
December 31, 1996 and 1995 28
Consolidated Statements of Operations for the Three Years
in the Period Ended December 31, 1996 29
Consolidated Statements of Stockholders' Equity
for the Three Years in the Period Ended December 31, 1996 30
Consolidated Statements of Cash Flows for the Three Years
in the Period Ended December 31, 1996 31
Notes to Consolidated Financial Statements 32-46
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Callon Petroleum Company:
We have audited the accompanying consolidated balance sheets of Callon Petroleum
Company (a Delaware corporation) and subsidiaries as of December 31, 1996 and
1995, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. 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 presenta-
tion. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
February 19, 1997
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
December 31,
----------------------------
1996 1995
---------- ----------
ASSETS
Current assets:
Cash and cash equivalents $ 7,669 $ 4,265
Accounts receivable 12,661 8,329
Other current assets 516 238
---------- ----------
Total current assets 20,846 12,832
---------- ----------
Oil and gas properties, full cost accounting method:
Evaluated properties 322,970 304,737
Less accumulated depreciation, depletion and amortization (266,716) (257,143)
---------- ----------
56,254 47,594
Unevaluated properties excluded from amortization 26,235 10,171
---------- ----------
Total oil and gas properties 82,489 57,765
Pipeline and other facilities, net 6,618 5,371
Other property and equipment, net 1,594 1,633
Deferred tax asset 5,412 5,462
Long-term gas balancing receivable 660 619
Other assets, net 901 185
---------- ----------
Total assets $ 118,520 $ 83,867
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 8,273 $ 3,131
Undistributed oil and gas revenues 2,260 2,153
Accrued net profits interest payable (Note 9) 5,435 2,836
---------- ----------
Total current liabilities 15,968 8,120
---------- ----------
Long-term debt 24,250 100
Deferred income 48 86
Long-term gas balancing payable 390 432
---------- ----------
Total liabilities 40,656 8,738
---------- ----------
Stockholders' equity:
Preferred Stock, $0.01 par value; 2,500,000 shares authorized;
1,315,500 shares of Convertible Exchangeable
Preferred Stock, Series A issued and outstanding with a
liquidation preference of $32,887,500 (Note 11) 13 13
Common Stock, $0.01 par value; 20,000,000
shares authorized; 5,758,667 and 5,754,529 shares
outstanding at December 31, 1996 and 1995, respectively 58 58
Capital in excess of par value 74,027 73,955
Retained earnings 3,766 1,103
---------- ----------
Total stockholders' equity 77,864 75,129
---------- ----------
Total liabilities & stockholders' equity $ 118,520 $ 83,867
========== ==========
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 1996, 1995 and 1994
(In thousands, except per share amounts)
1996 1995 1994
--------- --------- ---------
Revenues:
Oil and gas sales $ 25,764 $ 23,210 $ 13,948
Interest and other 946 627 171
--------- --------- ---------
Total revenues 26,710 23,837 14,119
--------- --------- ---------
Costs and expenses:
Lease operating expenses 7,562 6,732 4,042
Depreciation, depletion and amortization 9,832 10,376 6,049
General and administrative 3,495 3,880 3,717
Interest 313 1,794 624
--------- --------- ---------
Total costs and expenses 21,202 22,782 14,432
--------- --------- ---------
Income (loss) from operations 5,508 1,055 (313)
Income tax expense (benefit) 50 -- (200)
--------- --------- ---------
Net income (loss) 5,458 1,055 (113)
Preferred stock dividends 2,795 256 --
--------- --------- ---------
Net income (loss) available to common shares $ 2,663 $ 799 $ (113)
========= ========= =========
Net income (loss) per common share:
Primary $ .45 $ .14 $ (.03)
Assuming full dilution $ .43 $ .14 $ (.03)
Shares used in computing net income (loss) per common share:
Primary 5,952 5,755 4,346
Assuming full dilution 6,135 5,755 4,346
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Capital in
Capital Preferred Common Excess of Retained
Accounts Stock Stock Par Value Earnings
---------- ----------- ---------- ---------- -----------
Balances, December 31, 1993 $ 27,170 $ -- $ -- $ -- $ --
Pre consolidation income (loss) (417) -- -- -- --
Distributions (1,191) -- -- -- --
Consolidation (Note 1) (25,562) -- 58 43,069 --
Post consolidation income -- -- -- -- 304
--------- ---------- --------- --------- ----------
Balances, December 31, 1994 -- -- 58 43,069 304
Net income -- -- -- -- 1,055
Sale of preferred stock (Note 11) -- 13 -- 30,886 --
Preferred stock dividends -- -- -- -- (256)
--------- ---------- --------- --------- ----------
Balances, December 31, 1995 -- 13 58 73,955 1,103
Net income -- -- -- -- 5,458
Preferred stock dividends -- -- -- -- (2,795)
Shares issued pursuant to employee
benefit plan -- -- -- 72 --
--------- ---------- --------- --------- ----------
Balances, December 31, 1996 $ -- $ 13 $ 58 $ 74,027 $ 3,766
========= ========== ========= ========= ==========
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, 1996, 1995 and 1994
(In thousands)
1996 1995 1994
--------- --------- ----------
Cash flows from operating activities:
Net income (loss) $ 5,458 $ 1,055 $ (113)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 10,131 10,600 6,328
Amortization of deferred costs 114 133 88
Deferred income tax expense (benefit) 50 -- (200)
Changes in current assets & liabilities:
Accounts receivable, trade (4,332) 566 565
Other current assets (278) (217) (8)
Accounts payable, trade 4,049 (2,570) (1,242)
Change in gas balancing receivable (41) 115 (148)
Change in gas balancing payable (42) (127) 210
Change in deferred income (28) (42) (43)
Change in other assets, net (830) (61) (90)
--------- --------- ----------
Cash provided by operating activities 14,251 9,452 5,347
--------- --------- ----------
Cash flows from investing activities:
Capital expenditures (34,291) (24,323) (10,420)
Equity issued to purchase CN cash (Note 4) -- -- 3,989
Cash proceeds from sale of mineral interests 1,574 86 8
--------- --------- ----------
Cash used in investing activities (32,717) (24,237) (6,423)
--------- --------- ----------
Cash flows from financing activities:
Payments on debt (25,850) (25,134) (20,627)
Proceeds from debt issuance 50,000 6,000 25,734
Dividends/distributions paid -- -- (1,191)
Sale of preferred stock -- 30,899 --
Equity issued pursuant to employee benefit plan 72 -- --
Increase in accrued preferred stock dividends payable 443 256 --
Dividends on preferred stock (2,795) (256) --
--------- --------- ----------
Cash provided by financing activities 21,870 11,765 3,916
--------- --------- ----------
Net increase (decrease) in cash and cash equivalents 3,404 (3,020) 2,840
Cash and cash equivalents:
Balance, beginning of period 4,265 7,285 4,445
--------- --------- ----------
Balance, end of period $ 7,669 $ 4,265 $ 7,285
========= ========= ==========
The accompanying notes are an integral part of these financial statements.
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Callon Petroleum Company, formerly Callon Petroleum Holding 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 to combine the
businesses and properties of Callon Consolidated Partners, L.P. ("CCP"),
Callon Petroleum Operating Company ("CPOC") and CN Resources ("CN"),
directly or indirectly, with the Company. CPOC was the general partner of
CCP, and CN was a general partnership between CPOC and NOCO Enterprises, L. P.
("NOCO"), a limited partnership owned by private investors (CPOC, CCP and CN
are referred to collectively as the "Constituent Entities"). The combination
of the businesses and properties of the Constituent Entities with the Company
was effected in three simultaneous transactions on September 16, 1994
(collectively, the "Consolidation"):
(i) CCP was merged (the "Merger") into the Company and each unit of
limited partner interest in CCP ("Units") was converted into the right
to receive one-third of a share of Common Stock of the Company
("Common Stock"). Subject to compliance with certain requirements,
any holder of less than 100 Units could elect to receive, in lieu of
shares of Common Stock, $4.50 in cash per Unit owned. CCP unitholders
received 1,877,493 shares of Common Stock of the Company.
(ii) Holders of capital stock of CPOC exchanged such capital stock for
an aggregate of 1,892,278 shares of Common Stock of the Company, result-
ing in CPOC becoming a wholly owned subsidiary of the Company (the
"Share Exchange").
(iii) NOCO exchanged its partner interest for 1,984,758 shares of
Common Stock of the Company, resulting in CN becoming directly and
indirectly wholly owned by the Company (the "CN Exchange"). See Note 4.
As a result of the Consolidation, all of the businesses and properties of the
Constituent Entities are owned (directly or indirectly) by the Company, and the
former stockholders of CPOC, partners of CCP and NOCO have become stockholders
of the Company. Certain registration rights were granted to the holders of the
capital stock of CPOC and NOCO. See Note 7.
The Company and its predecessors have been engaged in the acquisition, develop-
ment and exploration of crude oil and natural gas since 1950. The Company's
properties are geographically concentrated in Louisiana, Alabama and offshore
Gulf of Mexico.
Basis of Presentation
The accompanying Consolidated Financial Statements of the Company reflect the
combination of CPOC, CCP, and CPOC's interest in CN as a reorganization of
entities under common control (accounted for similar to a "pooling of
interest"). NOCO's interest in CN was recorded as a purchase effective at the
date of the Consolidation (September 16, 1994), thus amounts related to the CN
Exchange are included from the date of the purchase for the periods presented
in the Consolidated Financial Statements. CPOC made no direct investment in
CN, therefore the inclusion of 100% of the assets and liabilities of CN in the
Consolidated Balance Sheet, as of the purchase date, are attributable to NOCO's
interest in CN. Because no revenues or expenses, as of the date of the Consol-
idation, were attributable to CPOC's interest in CN until NOCO had received a
preferential return on its investment, all of the revenues and expenses of CN
through September 16, 1994, are also attributable to NOCO. See Note 4 for pro
forma information.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Reporting
The Consolidated Financial Statements include the accounts of the Company, and
its subsidiary, CPOC. CPOC also has subsidiaries which are Callon Offshore
Production, Inc., Mississippi Marketing, Inc. and Callon Exploration Company.
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 March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121 ("FAS 121"), "Accounting for the Impair-
ment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of". FAS
121 was adopted by the Company on January 1, 1996. The effect of adopting FAS
121 was not material to the Company's financial position or results of oper-
ations.
In October 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 123 ("FAS 123"), "Accounting for Stock-
Based Compensation", effective for the Company at December 31, 1996. Under
FAS 123, companies can either record expenses based on the fair value of
stock-based compensation upon issuance or elect to remain under the current
"APB Opinion No. 25" method, whereby no compensation cost is recognized upon
grant, and make disclosures as if FAS 123 had been applied. The Company will
continue to account for its stock-based compensation plans under APB Opinion
No. 25. See Note 10.
Property and Equipment
The Company follows the full cost method of accounting for oil and gas pro-
perties whereby all costs incurred in connection with the acquisition, explor-
ation and development of oil and gas reserves, including certain overhead
costs, are capitalized. Such amounts include the cost of drilling and equip-
ping productive wells, dry hole costs, lease acquisition costs, delay rentals,
interest capitalized on unevaluated leases and other costs related to explor-
ation and development activities. Payroll and general and administrative costs
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 restor-
ation, 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 est-
imated future net revenues from proved reserves at current prices and discounted
at 10% and (2) the cost of unevaluated properties (the full cost ceiling
amount), then such excess is charged to expense during the period in which the
excess occurs.
Upon the acquisition or discovery of oil and gas properties, management est-
imates 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, 1996 and 1995,
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 facilities is provided using the straight-line method over a 27
year estimated life.
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 pro-
tection purposes on a limited amount of its future production, and does not
use them for trading purposes. Such derivatives are accounted for on an accrual
basis and amounts paid or received under the agreements are recognized as oil
and gas sales in the period in which they accrue.
Reserve for Doubtful Accounts
The balance in the reserve for doubtful accounts included in accounts receiv-
able is $393,000 and $481,000 at December 31, 1996 and 1995. Net charge offs
were $88,000 and $181,000 in 1996 and 1994 and net recoveries were $2,000 in
1995. There were no provisions to expense in the three year period ended
December 31, 1996.
Statements of Cash Flows
For purposes of the Consolidated Statements of Cash Flows, the Company con-
siders 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,
1996. During the years ended December 31, 1996, 1995 and 1994, the Company
made cash payments of $250,807, $1,910,000 and $377,000, respectively, for
interest charged on its indebtedness.
Per Share Amounts
Per share amounts are calculated on a weighted average basis in accordance with
the common shares issued in the Consolidation described in Note 1, adjusted for
the effect of stock options considered common stock equivalents computed using
the treasury stock method. The preferred stock issued in 1995 (Note 11) is not
a common stock equivalent and is not included in the calculations of fully
diluted per share amounts due to their antidilutive effect on fully diluted
income per share.
Fair Value of Financial Instruments
Fair value of cash, cash equivalents, accounts receivable, accounts payable and
long-term debt approximate book value at December 31, 1996. Fair value of
long-term debt (specifically the 10% senior subordinated notes) is based on
quoted market value.
3. INCOME TAXES
The Company follows the asset and liability method of accounting for deferred
income taxes prescribed by Financial Accounting Standards Board Statement No.
109 ("FAS 109") "Accounting for Income Taxes". The statement provides for the
recognition of a deferred tax asset for deductible temporary timing differ-
ences, capital and operating loss carryforwards, statutory depletion carry-
forward 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. Accordingly, the
Company has recorded a deferred tax asset at December 31, 1996, 1995 and 1994
as follows:
1996 1995 1994
------- -------- -------
(In thousands)
Federal net operating loss carryforward $ 3,441 $ 3,563 $ 2,072
Statutory depletion carryforward 4,089 3,987 4,085
Temporary differences:
Oil and gas properties (680) 874 2,817
Pipeline and other facilities (2,316) (1,880) (1,953)
Non-oil and gas property (20) 23 28
Other 898 655 724
Total tax asset 5,412 7,222 7,773
------- -------- -------
Valuation allowance -- (1,760) (2,311)
------- -------- -------
Net tax asset $ 5,412 $ 5,462 $ 5,462
======= ======== =======
At December 31, 1996, the Company had, for tax reporting purposes, operating
loss carryforwards ("NOL") of $9.8 million which expire in 2000 through 2011.
Approximately $4.7 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 pur-
poses $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:
1996 1995 1994
------- ------- -------
(In thousands)
Computed expense (benefit) at the
expected statutory rate $ 1,910 $ 369 $ (110)
Change in valuation allowance (1,760) (551) (94)
Other (100) 182 4
------- ------- --------
Income tax expense (benefit) $ 50 $ -- $ (200)
======= ======= ========
4. ACQUISITIONS
On September 14, 1994, (with an effective date of September 16, 1994) the unit-
holders of CCP, stockholders of CPOC, and the partners of CN completed the
Consolidation as described in Note 1. Net assets purchased (excluding cash of
$3,989,000) was $13,847,000 of which oil and gas property, including pipeline
facilities, and debt amounted to $24,506,000 and $11,436,000, respectively.
Such amounts represent non-cash transactions and therefore are not included
in the Consolidated Statements of Cash Flows.
On December 29, 1995, CPOC purchased a 66.67% working interest in Chandeleur
Block 40 (the "CB 40 Acquisition") from Amerada Hess Corporation and, in a
simultaneous transaction under a pre-existing agreement, sold one-third of the
acquired interest to an industry partner. The Company's net purchase price of
$6 million was funded from existing cash on hand.
The following information represents unaudited pro forma results of the Company
for the years ended December 31, 1995 and 1994 and includes both the purchase
of CN and the CB 40 Acquisition, presented as if the purchase of CN had
occurred at the beginning of 1994 and the CB 40 Acquisition presented as if it
had occurred at the beginning of 1995 and 1994.
Pro Forma (Unaudited)
---------------------------------------
1995 1994
--------- ---------
(In thousands, except per share amounts)
Total revenues $ 25,207 $ 29,132
Net income before cumulative effect of
change in accounting principle $ 804 $ 3,703
Net income per common share $ .14 $ .64
Weighted average shares outstanding 5,755 5,755
Pro forma shares outstanding used in the above calculations include shares of
the Company issued as a result of the Merger of CCP and the Share Exchange in
addition to the shares of the Company issued in the CN Exchange.
The Company, together with an industry partner, was the high bidder on 12
offshore tracts at the Outer Continental Shelf ("OCS") Lease Sale #157, held
April 24, 1996 in New Orleans, Louisiana, and conducted by the U. S. Depart-
ment of the Interior through its Minerals Management Service ("MMS"). The
Company holds a 25% working interest in the leases and its share of the total
lease costs was approximately $11.4 million.
On September 25, 1996, the Company and the same industry partner submitted bids
and was awarded six additional offshore leases at the OCS Lease Sale #161,
held in New Orleans, Louisiana by the MMS. The Company's share of the costs
was $3.8 million. The Company owns a 25% working interest in the leases.
5. LONG-TERM DEBT
Long-term Debt consisted of the following at:
December 31,
----------------------------
1996 1995
--------- ----------
(In thousands)
Credit Facility $ 100 $ 100
10% Senior Subordinated Notes 24,150 --
--------- ----------
24,250 100
Less: current portion -- --
--------- ----------
$ 24,250 $ 100
========= ==========
Effective October 31, 1996, the Company entered into a new Credit Facility with
Chase Manhattan Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. The Credit Facility provides for borrowings of a maximum of the
lesser of $50 million or a borrowing base ("Borrowing Base") determined period-
ically on the basis of a discounted present value of future net cash flows
attributable to the Company's proved producing oil and gas reserves. Through
May 15, 1997, the Credit Facility provides a $30 million Borrowing Base.
Pursuant to the Credit Facility, depending upon the percentage of the unused
portion of the Borrowing Base, the interest rate is equal to either the lender's
prime rate or the lender's prime rate plus 0.50%. The Company, at its option,
may fix the interest rate on all or a portion of the outstanding principal
balance at either 1.00% or 1.375% above a defined "Eurodollar" rate, depending
upon the percentage of the unused portion of the Borrowing Base, for periods
of up to six months. The weighted average interest rate for the total debt
outstanding at December 31, 1996 was 8.25%. Under the Credit Facility, a
commitment fee of .25% or .375% per annum on the unused portion of the Borrow-
ing 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 Subordin-
ated 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.
The Credit Facility and the subordinated debt contain various covenants includ-
ing restrictions on additional indebtedness and payment of cash dividends as
well as maintenance of certain financial ratios. This Company is in compliance
with these covenants at December 31, 1996.
6. HEDGING CONTRACTS
The Company hedges with third parties certain of its crude oil and natural gas
production in various swap agreement contracts. The contracts are tied to
published market prices for crude oil and natural gas and are settled monthly
based on the differences between contract prices and the average defined market
price for that month applied to the related contract volume. The Company had
no open forward sales position related to this type of contract at December 31,
1996.
As of December 31, 1996, the Company had open collar contracts with third
parties whereby minimum floor prices and maximum ceiling prices are contracted
and applied to related contract volumes. These agreements in effect for 1997
are for average oil volumes of 15,000 barrels per month at (on average) a
ceiling price of $23.33 and floor of $18.00 and for average gas volumes of
583,000 MCF per month in the first quarter of 1997 at (on average) a ceiling
price of $3.36 and floor of $2.88.
During 1994, the Company recognized revenue under swap agreements of $1,227,000
and $1,724,000 on a Historical and a Pro forma basis respectively, and
$2,466,000 for the twelve months ended December 31, 1995. The Company recog-
nized a reduction in revenue of $2,757,195 for the year ended December 31,
1996 under all contracts.
The calculation of the fair market value of the outstanding contracts as of
December 31, 1996 indicates a $308,400 market value benefit to the Company
based on market prices at that date.
7. COMMITMENTS AND CONTINGENCIES
As described in Note 9, abandonment trusts (the "Trusts") have been established
for future abandonment obligations of those oil and gas properties of the
Company burdened by a net profits interest. The management of the Company
believes the Trusts will be sufficient to offset those future abandonment
liabilities; however, the Company is responsible for any abandonment expenses
in excess of the Trusts' balances. As of December 31, 1996, total estimated
site restoration, dismantlement and abandonment costs were approximately
$23,000,000, 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.
Also, as part of the Consolidation, the Company entered into Registration Rights
Agreements whereby the former stockholders of CPOC and NOCO 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 commit-
ment public offering and generally to include shares owned by them, at no cost,
in registration statements filed by the Company. Costs of the offering will
not include discounts and commissions, which will be paid by the respective
sellers of the Common Stock.
8. OIL AND GAS PROPERTIES
The following table discloses certain financial data relating to the Company's
oil and gas activities, all of which are located in the United States.
Year Ended December 31,
---------------------------------
1996 1995 1994
--------- --------- ---------
(In thousands)
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance $ 304,737 $ 285,976 $ 260,971
Property acquisition costs 2,999 14,017 23,037
Exploration costs 8,732 785 798
Development costs 8,076 4,045 1,178
Sale of mineral interest (1,574) (86) (8)
--------- --------- ---------
End of period balance $ 322,970 $ 304,737 $ 285,976
========= ========= =========
Unevaluated Properties-
Beginning of period balance $ 10,171 $ 4,919 $ 955
Additions, net of transfers to evaluated 15,714 5,252 3,964
Capitalized interest 350 -- --
--------- --------- ---------
End of period balance $ 26,235 $ 10,171 $ 4,919
========= ========= =========
Accumulated depreciation, depletion
and amortization-
Beginning of period balance $ 257,143 $ 246,975 $ 240,926
Provision charged to expense 9,573 10,168 6,049
--------- --------- ---------
End of period balance $ 266,716 $ 257,143 $ 246,975
========= ========= =========
Depreciation, depletion and amortization per unit-of-production (equivalent
barrel of oil) amounted to $5.87, $5.95, and $5.80 for the years ended December
31, 1996, 1995 and 1994, respectively.
9. NET PROFITS INTEREST
Since 1989, the Constituent Entities have entered into separate agreements to
purchase certain oil and gas properties with gross contract acquisition price
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 pro-
ceeds 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 remain-
ing in the Trusts after all restoration, dismantlement and abandonment obli-
gations 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 dis-
closures at Note 12. As of December 31, 1996 and 1995 the Trusts' assets
(all cash and investments) totaled $18,200,000 and $16,100,000, respectively,
all of which will be available to the Company to pay its portion, as working
interest owner, of the restoration, dismantlement and abandonment costs
discussed at Note 7.
At the time of acquisition of properties by the Company, the property owners
estimated the future costs to be incurred for site restoration, dismantlement
and abandonment, net of salvage value. A portion of the amounts necessary
to pay such estimated costs was deposited in the Trusts upon acquisition of
the properties, and the remainder is deposited from time to time out of the
proceeds from production. The determination of the amount deposited upon the
acquisition of the properties and the amount to be deposited as proceeds from
production was based on numerous factors, including the estimated reserves
of the properties. The amounts deposited in the Trusts upon acquisition of
the properties were capitalized by the Company as oil and gas properties.
As operator, the Company receives all of the revenues and incurs all of the
production costs for the purchased oil and gas properties but retains only that
portion applicable to its net ownership share. As a result, the payables and
receivables associated with operating the properties included in the Company's
Consolidated Balance Sheets include both the Company's and all other outside
owner's shares. However, revenues and production costs associated with the
acquired properties reflected in the accompanying Consolidated Statements of
Operations represent only the Company's share, after reduction for the NPI.
At December 31, 1996 and 1995 the amounts payable to the NPI owners included
in the accounts payable in the accompanying Consolidated Balance Sheets were
approximately $5,400,000 and $2,800,000, respectively.
10. EMPLOYEE BENEFIT PLANS
The Company has adopted a series of incentive compensation plans designed to
align the interest of the executives and employees with those of its stock-
holders. The following is a brief description of each plan:
- - The Savings and Protection Plan provides employees with the option to defer
receipt of a portion of their compensation and the Company may, at its dis-
cretion, 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 main-
tained 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 $241,000, $176,000 and $154,000 in
the years 1996, 1995 and 1994, 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 are outstanding and all such options
could be exercised as of December 31, 1996. These options have an expiration
date 10 years from date of grant.
- - On August 23, 1996, the Board of Directors of the Company approved and
adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996
Plan"). The 1996 Plan provides for the same types of awards as the 1994 Plan
and is limited to a maximum of 900,000 shares of common stock that may be
subject to outstanding awards. The Company granted stock options to purchase
an aggregate 530,000 shares of Common Stock under the plan, subject to stock-
holder approval of the 1996 Plan. All of such options were granted at an exer-
cise price of $12 per share, the fair market value of the Common Stock on the
date of grant. Terms of the plan for 450,000 options provide that 20% of the
options become exercisable on January 1 of each succeeding year, beginning
January 1, 1997. Non-employee director options aggregating 80,000 shares vest
25% at each succeeding annual meeting of directors following each annual stock-
holders' meeting, beginning in 1997. Unvested options are subject to for-
feiture 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 (see Note 2). Had compensation cost for these plans been deter-
mined consistent with FAS 123, the Company's net income and earnings per common
share would have been reduced to the following pro forma amounts:
1996 1995 1994
-------- -------- --------
(In thousands, except per share data)
Net income (loss): As Reported $ 2,663 $ 799 $ (113)
Pro Forma 2,411 677 (113)
Primary per share: As Reported .45 .14 (.03)
Pro Forma .41 .12 (.03)
Fully diluted per share: As Reported .43 .14 (.03)
Pro Forma .39 .12 (.03)
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
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,
1996, 1995 and 1994 and changes during the years then ended is presented in the
table and narrative below:
1996 1995 1994
-------------------- ------------------ ------------------
Wtd Avg Wtd Avg Wtd Avg
Shares Ex Price Shares Ex Price Shares Ex Price
--------- -------- ------- -------- ------- --------
Outstanding, beginning of year 490,000 $ 10.01 460,000 $ 10.00 -- $ --
Granted 550,000 12.06 30,000 10.08 460,000 10.00
Exercised -- -- -- -- -- --
Forfeited (10,000) 10.00 -- -- -- --
Expired -- -- -- -- -- --
--------- -------- ------- -------- ------- --------
Outstanding, end of year 1,030,000 $ 11.10 490,000 $ 10.01 460,000 $ 10.00
========= ======== ======= ======== ======= ========
Exercisable, end of year 500,000 $ 10.16 490,000 $ 10.01 -- $ --
========= ======== ======= ======== ======== ========
Weighted average fair value of
options granted $ 4.96 $ 4.05 $ 4.53
====== ====== ======
The options outstanding at December 31, 1996 have exercise prices ranging from
$9.75 to $13.75 with a remaining weighted average contractual life of 5.98
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 assump-
tions used for options granted during 1996, 1995 and 1994.
Weighted Average Assumptions
----------------------------
1996 1995 1994
---- ---- ----
Risk free interest rate 6.5% 6.6% 6.0%
Expected life (years) 4.9 5.0 5.0
Expected volatility 34.7% 32.0% 41.3%
Expected dividends -- -- --
The Company also awarded 225,000 performance shares under the 1996 Plan to the
Company's Executive officers on August 23, 1996, to be issued subject to stock-
holder approval of the 1996 Plan. 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. Approximately $208,000 of compen-
sation cost was charged to expense in 1996 related to the performance shares
granted.
The Company has no other formal benefit plans.
11. PREFERRED STOCK
In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible Ex-
changeable 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.
The Company used approximately $21.5 million of the net proceeds from the sale
of the Preferred Stock to repay outstanding indebtedness under its primary
credit facility (See Note 5), which indebtedness was incurred to finance cer-
tain acquisitions of properties. The Company is using the excess of the net
proceeds from the sale of the Preferred Stock over the amount used to repay
indebtedness, together with internally generated cash flows to acquire, develop
and explore oil and gas properties.
12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 1996, 1995 and 1994
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved
reserves. The following reserve data represent estimates only and should not
be construed as being exact. In addition, the present values should not be
construed as the current market value of the Company's oil and gas properties
or the cost that would be incurred to obtain equivalent reserves.
Estimated Reserves
Changes in the estimated net quantities of crude oil and natural gas reserves,
all of which are located onshore and offshore in the continental United States,
are as follows:
Reserve Quantities
Year Ended December 31,
------------------------------
1996 1995 1994
----- ---- ----
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period 4,766 4,424 2,842
Revisions to previous estimates (50) (441) (303)
Purchase of reserves in place -- 1,363 2,245
Sales of reserves in place (312) (2) (3)
Extensions and discoveries -- 16 7
Production (585) (594) (364)
------ ------ ------
End of period 3,819 4,766 4,424
====== ====== ======
Natural Gas (MMcf):
Beginning of period 29,667 24,102 14,167
Revisions to previous estimates (1,688) (976) (2,793)
Purchase of reserves in place 7,391 12,985 16,757
Sales of reserves in place (228) (22) (39)
Extensions and discoveries 21,551 271 85
Production (6,269) (6,693) (4,075)
------ ------ ------
End of period 50,424 29,667 24,102
====== ====== ======
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period 3,890 3,309 2,084
End of period 3,385 3,890 3,309
Natural Gas (MMcf):
Beginning of period 20,408 20,582 11,366
End of period 49,491 20,408 20,582
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. In 1995 and 1994, no future income taxes were provided on
the future net inflows as tax credits (including carryovers) and other per-
manent differences were expected to be higher than the estimated future income
taxes calculated using the appropriate statutory rates. The resulting net
future cash flows have been discounted to their present values based on a 10%
annual discount factor.
Standardized Measure
December 31,
----------------------------------
1996 1995 1994
--------- --------- ---------
(In thousands)
Future cash inflows $ 285,727 $ 157,240 $ 115,659
Future costs -
Production (59,584) (50,236) (43,579)
Development and net abandonment (9,989) (11,274) (12,603)
--------- --------- ---------
Future net inflows before income taxes 216,154 95,730 59,477
Future income taxes (49,438) -- --
--------- --------- ---------
Future net cash flows 166,716 95,730 59,477
10% discount factor (36,547) (31,966) (18,094)
--------- --------- ---------
Standardized measure of discounted
future net cash flows $ 130,169 $ 63,764 $ 41,383
========= ========= =========
Changes in Standardized Measure
Year Ended December 31,
----------------------------------
1996 1995 1994
--------- -------- ---------
(In thousands)
Standardized measure - beginning of period $ 63,764 $ 41,383 $ 22,554
Sales and transfers, net of production costs (18,202) (12,477) (9,815)
Net change in sales and transfer prices,
net of production costs 32,268 11,519 1,368
Exchange and sale of in place reserves (877) (23) (48)
Purchases, extensions, discoveries, and
improved recovery,net of future production
and development costs 79,983 28,204 26,376
Revisions of quantity estimates (3,907) (4,242) (6,297)
Accretions of discount 6,376 2,963 1,488
Net change in income taxes (30,000) -- --
Changes in production rates, timing and other 764 (3,563) 5,757
--------- -------- --------
Standardized measure - end of period $ 130,169 $ 63,764 $ 41,383
========= ======== ========
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 1999, 1998 and 1997, respectively. The
Charter also provides that such classes shall be as nearly equal in number as
possible. At December 31, 1996, the directors and executive officers of the
Company were as follows:
Company
Position
Name Age Since Present Company Position
- ------------------- --- -------- ------------------------
John S. Callon 77 1994 Director; Chairman of the Board;
Chief Executive Officer (Class II)
Fred L. Callon 47 1994 Director; President; Chief Operating
Officer (Class III)
Dennis W. Christian 50 1994 Director; Senior Vice President
(Class III)
Robert A. Stanger 57 1995 Director (Class I)
H. Michael Tatum, Jr 68 1994 Vice President; Secretary
Kathy G. Tilley 51 1996 Vice President
John C. Wallace 58 1994 Director (Class I)
B. F. Weatherly 52 1994 Director (Class II)
John S. Weatherly 45 1994 Senior Vice President; Chief
Financial Officer; Treasurer
Richard O. Wilson 67 1995 Director (Class I)
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.
Effective January 2, 1997, John S. Callon resigned his position as Chief
Executive Officer of the Company (See "Employment Agreements, Termination
of Employment and Change in Control Arrangements").
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 and Chief Executive
Officer of the Company and Callon Petroleum Operating. 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 Operating Officer of the Company and
Callon Petroleum Operating Company ("Callon Petroleum Operating") and has held
that position with the Company or its predecessors since 1984. He has been
employed by the Company or its predecessors since 1976. He graduated from
Millsaps College in 1972 and received his M.B.A. degree from the Wharton
School of Finance in 1974. Following graduation and until his employment
by Callon Petroleum Operating, he was employed by Peat, Marwick, Mitchell
& Co., certified public accountants. He is a certified public accountant
and is a member of the American Institute of Certified Public Accountants
and the Mississippi Society of Certified Public Accountants. He is the
nephew of John S. Callon.
Dennis W. Christian is Senior Vice President of Acquisitions and Operations
for the Company and Callon Petroleum Operating, 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, a Shrewsbury, New Jersey-based firm engaged in publishing
financial material and providing investment banking services to the real estate
and oil and gas industries. He is a director of Citizens Utilities, Stamford,
Connecticut, a provider of telecommunications, electric, natural gas, and water
services. 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, the
New York Society of Security Analysts, the International Association of
Financial Planners, and the Investment Program Association.
H. Michael Tatum, Jr. is Vice President and Secretary for the Company and
Callon Petroleum Operating and is responsible for management of administra-
tive 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.
John C. Wallace is an executive officer of NOCO Management Ltd., the general
partner of the general partner of NOCO Enterprises, L.P., a Delaware limited
partnership ("NOCO"). He is a Chartered Accountant having qualified with
Coopers and Lybrand in Canada in 1963 following which he joined Baring Brothers
& Co., Limited in London. For more than the last ten years, he has served as
Chairman of Fred. Olsen Ltd., a London-based corporation which he joined in
1968, where he has specialized in the business of shipping and property develop-
ment. He is a director of Harland & Wolff PLC, Belfast, A/S Ganger Rolf and A/S
Bonheur, Oslo, publicly traded shipping companies, and O. G. C. International
P. L. C., a Scottish public company engaged in the offshore oil and gas main-
tenance and construction business. He is also director of Belmont Constructors,
Inc., a Houston, Texas-based industrial contractor associated with Fred. Olsen
Interests, and other companies associated with Fred. Olsen Interests.
B. F. Weatherly is a principal of Amerimark Capital Group, Houston, Texas, an
investment banking firm. He is an executive officer of NOCO Management Ltd.,
the general partner of the general partner of NOCO. Prior to September 1996,
he was Executive Vice President, Chief Financial Officer and a director of
Belmont Constructors, Inc., a Houston, Texas-based industrial contractor
associated with Fred. Olsen Interests. From 1989 to 1991, he was a partner
in Amerimark Capital Corp., a Dallas investment banking firm. He holds a
Master of Accountancy degree from University of Mississippi. He has previously
been associated with Arthur Andersen LLP, and has served as a Senior Vice
President of Weatherford International, Inc. B. F. Weatherly and John S.
Weatherly are brothers.
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.
Richard O. Wilson for the past ten years has been Chairman of O.G.C. Inter-
national P.L.C., a Scottish public company engaged in the offshore oil and
gas maintenance and construction business headquartered in Aberdeen, Scotland.
He is also Chairman of Belmont Constructors, Inc., a Houston, Texas-based
industrial contractor associated with Fred. Olsen Interests. In September
1996, after 12 years, Mr. Wilson retired as Chairman of Dolphin AS, Stavanger,
Norway, and Dolphin Drilling Ltd., Aberdeen, Scotland. He holds a B.S.
degree in civil engineering from Rice University. Mr. Wilson is a Fellow in
the American Society of Civil Engineers, a member of the Institute of Petroleum,
London, England, and the Cosmos Club, Washington, D.C.
Messrs. John S. Callon and Fred L. Callon, as nominees of the Callon Family,
and Messrs. B. F. Weatherly and John C. Wallace, as nominees of NOCO, were
elected to the Board of Directors pursuant to the terms of a Stockholders'
Agreement dated September 16, 1994. See Item 12. Security Ownership of
Certain Beneficial Owners and Management - "Stockholders' Agreement."
All officers and directors of the Company are United States citizens, except
Mr. Wallace, who is a citizen of Canada.
Compliance with Section 16(a) of the Securities Exchange Act of 1934
Section 16(a) of the Securities Exchange Act of 1934, as amended ("Exchange
Act"), requires the Company's directors and executive officers, and persons
who own more than ten percent of a registered class of the Company's equity
securities, to file with the Securities and Exchange Commission ("Commission")
and the National Association of Securities Dealers' Inc. National Market
System ("Nasdaq NMS"), initial reports of ownership and reports of changes
in ownership of Common Stock and other equity securities of the Company.
Officers, directors and greater than ten percent stockholders are required by
the Commission's regulations to furnish the Company with copies of all Section
16(a) forms they filed with the Commission.
To the Company's knowledge, based solely on review of the copies of such
reports furnished to the Company and written representations that no other
reports were required, during the fiscal year ended December 31, 1996, the
Company's officers, directors and greater than ten percent stockholders had
complied with all Section 16(a) filing requirements.
ITEM 11. EXECUTIVE COMPENSATION
Compensation of Directors
The Company's Board of Directors holds four regular meetings each year.
During 1996, as compensation for all services as a director of the Company,
each non-employee director was paid $10,000. Non-employee directors are also
granted, upon their initial election or appointment, options to purchase 5,000
shares of Common Stock pursuant to the 1996 Callon Petroleum Stock Incentive
Plan (the "1996 Plan") and will be granted options for an additional 5,000
shares for each year in which they continue to serve as directors. See
"Incentive Plans-1996 Plan". On August 23, 1996, the Compensation Committee
authorized a one-time grant to each non-employee director of an option to
purchase 20,000 shares of Common Stock under the 1996 Plan at a purchase price
of $12.00 per share, the fair market value of the Common Stock on such date,
subject to approval of the 1996 Plan by the Company's stockholders at the 1997
annual meeting of stockholders. One-fourth of each option will vest at each
succeeding annual meeting of directors following each annual stockholders'
meeting, beginning in 1997.
Summary Compensation Table
The following table sets forth information with respect to the Chief Executive
Officer and the four most highly compensated executive officers of the Company
as to whom the total salary and bonus for the years ended December 31, 1996,
1995 and 1994 exceeded $100,000. The amounts for 1994 include compensation
from the Company's predecessors.
Long-Term Compensation
-----------------------------------
Annual Compensation Awards Payouts
------------------------------- ------------------------- --------
Other Restricted Securities All
Annual Stock Underlying LTIP Other
Name and Salary Bonus Compensation Award(s) Options Payouts Compensation
principal position Year ($) ($)(a) ($)(b) ($) (#) ($) ($)(c)
- ------------------ ---- ------- ------- ------------ ---------- ---------- ------- ------------
John S. Callon 1996 195,670 66,500 -- -- -- -- 12,715
Chairman and Chief 1995 190,000 161,500 -- -- -- -- 10,393
Executive Officer 1994 168,000 95,000 -- -- 90,000 -- 9,565
Fred L. Callon 1996 182,761 59,500 -- -- 75,000 -- 12,928
President and Chief 1995 170,000 144,500 -- -- -- -- 10,288
Operating Officer 1994 150,000 85,000 -- -- 80,000 -- 9,096
Dennis W. Christian 1996 160,808 52,500 -- -- 70,000 -- 11,362
Senior Vice 1995 150,000 127,500 -- -- -- -- 9,080
President 1994 118,450 140,000 -- -- 60,000 -- 7,186
John S. Weatherly 1996 143,469 45,500 -- -- 65,000 -- 10,234
Senior Vice President 1995 130,000 110,500 -- -- -- -- 7,873
Chief Financial 1994 100,000 107,500 -- -- 60,000 -- 6,068
Officer and Treasurer
Kathy G. Tilley 1996 119,032 35,000 -- -- 55,000 -- 8,475
Vice President 1995 100,008 85,000 -- -- -- -- 5,933
1994 96,626 78,000 -- -- 30,000 -- 5,739
__________
(a) The amount for 1996 represents that portion of bonuses declared in March 1996 and earned by service during 1996.
It is anticipated that bonuses will be declared in March 1997, a portion of which will be attributable to 1996, however,
such amounts are presently undeterminable. An estimate of such amounts was expensed for financial reporting purposes
in the year ended December 31, 1996.
(b) Amounts in the column do not include perquisites and other personal benefits, securities or property, unless the
annual amount of such compensation exceeds the lesser of $50,000 or 10% of the total of annual salary and bonus reported
for the named executive.
(c) Amounts reflect the Company's contribution in 1996, 1995 and 1994 of $12,043, $9,500 and $8,400 to John S. Callon's
401(k)savings plan and payment of $672, $893 and $1,165 term life insurance premiums; $11,446, $8,500 and $7,500 to Fred
L. Callon's 401(k) savings plan and payment of $1,482, $1,788 and $1,596 term life insurance premiums; $10,060, $7,500 and
$5,923 to Mr. Christian's 401(k) savings plan and payment of $1,302, $1,580 and $1,263 term life insurance premiums; $9,077,
$6,500 and $5,000 to Mr. Weatherly's 401(k) savings plan and payment of $1,157, $1,373 and $1,068 term life insurance
premiums; and $7,509, $5,000 and $4,831 to Ms. Tilley's 401(k) savings plan and payment of $966, $933 and $908 term life
insurance premiums.
Option Grants In Last Fiscal Year
There were no individual grants of stock options under the 1994 Plan made during
the year ended December 31, 1996 to the Chief Executive Officer of the Company
or any of the four most highly compensated executive officers of the Company
named in the Summary Compensation Table. There were grants of stock options
under the 1996 Plan during the year ended December 31, 1996 to the Chief
Executive Officer and the four most highly compensated executive officers of
the Company. The following table sets forth information concerning individual
grants of stock options under the 1996 Plan to the Chief Executive Officer of
the Company and the four most highly compensated executive officers of the
Company.
OPTION GRANTS IN YEAR ENDING DECEMBER 31, 1996
Individual Grants
-------------------------------------------------
% of Total Potential Realizable
Number of Options Value at Assumed
Securities Granted Exercise Annual Rates of
Underlying to Employees or Base Stock Price Appreciation
Options in Fiscal Price Expiration For Option Term (c)
Name Granted Year(a) ($/Sh)(b) Date 5% ($) 10%($)
- ------------ --------- ------------ --------- ------------ ----------- ------------
John S. Callon -- -- -- -- $ -- $ --
Fred L. Callon 75,000 17% $12.00 August 23, 2006 566,005 1,434,368
Dennis W. Christian 70,000 16% $12.00 August 23, 2006 528,271 1,338,744
John S. Weatherly 65,000 14% $12.00 August 23, 2006 490,538 1,243,119
Kathy G. Tilley 55,000 12% $12.00 August 23, 2006 415,070 1,051,870
All Stockholders(d) 5,758,667 N/A N/A N/A 43,459,137 110,133,985
__________
(a) The Company granted a total of 450,000 options to employees under the 1996 Plan for the year ended December 31, 1996.
(b) The options were granted on August 23, 1996. The fair market value of the Common Stock at the date of grant was $12.00.
Options are not exercisable prior to six months from the date of grant and, unless a shorter period is provided by the 1996 Plan
or the Plan Administrator, are for a term of ten years, subject to vesting as provided by the Plan Administrator. Further,
options are subject to forfeiture and/or time limitations in the event of a termination of employment. The options are subject to
approval of the 1996 Plan by the Company's stockholders at the 1997 annual meeting of stockholders. No stock appreciation
rights have been granted by the Company since its inception.
(c) Potential realizable values are net of exercise price, but before taxes associated with exercise. Amounts represent
hypothetical gains that could be achieved for the respective options if exercised at the end of the option term. The assumed
5% and 10% rates of stock price appreciation are provided in accordance with rules of the Securities and Exchange Commission
and do not represent the Company's estimate or projection of the future Common Stock price. Actual gains, if any, on stock
option exercises are dependent on the future performance of the Common Stock and overall market conditions. There can be no
assurance that the amounts reflected will be achieved.
(d) All Stockholders are show for comparison purposes only.
Aggregated Option Exercises in Last Fiscal Year
and Fiscal Year End Option Values
The following table sets forth certain information concerning the number and
value of unexercised options to purchase Common Stock by the Chief Executive
Officer and the four most highly compensated executive officers named in the
Summary Compensation Table at December 31, 1996. No stock options were
exercised by such persons in 1996.
Aggregated Option Exercises in 1996 and Unexercised Options
and Values at December 31, 1996
Unexercised Options at December 31, 1996
----------------------------------------
Number of Value of
Underlying In-the-Money
Securities Options
Shares ---------------- ---------------
Acquired on Value Exercisable/ Exercisable/
Name Exercise(#) Realized($) Unexercisable(a) Unexercisable(b)
- --------- ----------- ----------- ---------------- ----------------
John S. Callon -- -- 90,000/-- $ 815,625/--
Fred L. Callon -- -- 95,000/60,000 830,938/423,750
Dennis W. Christian -- -- 74,000/56,000 642,625/395,500
John S. Weatherly -- -- 73,000/52,000 635,563/367,250
Kathy G. Tilley -- -- 41,000/44,000 349,563/310,750
__________
(a) Represents awards granted under the 1994 Plan and the 1996 Plan.
(b) As of December 31, 1996, the fair market value of the common stock was $19.0625.
Employment Agreements, Termination of Employment and Change
in Control Arrangements
Fred L. Callon, Dennis W. Christian and John S. Weatherly have entered into
employment agreements with the Company effective September 1, 1996 and ending
December 31, 2001. The agreements provide that Mr. Callon, Mr. Christian and
Mr. Weatherly will receive an annual base salary of at least $200,000, $175,000
and $165,000, respectively, and that they will be entitled to participate in
any incentive compensation program established by the Company for its executive
officers. Each agreement terminates upon death or disability or for cause.
If the agreement is terminated for cause, the Company is not required to make
any additional payments. "Cause" is defined generally as any of the following,
as determined by a majority vote of the Board of Directors: intentional or
continual neglect of duties, conviction of a felony, or failure or refusal to
perform duties in accordance with the employment agreement.
The employment agreement further provides that the employee may terminate the
agreement for "good reason," which is defined as (a) failure to be re-elected
to office, (b) significant change in duties, (c) reduction or failure to provide
typical increases in his salary following a change in control of the Company,
(d) his relocation to an office outside the Natchez, Mississippi area, or
(e) failure to maintain the level of participation in the compensation and
benefit plans of the Company following a change in control. If the employee
terminates his agreement for good reason (other than following a change in
control), or if the Company breaches the agreement, compensation shall continue
for a period of two years from the date of termination. If the agreement is
terminated following a change in control, compensation shall continue for a
period of three years. Pursuant to the agreements, a "change in control"
occurs if: (i) any person or group of persons acting in concert (within the
meaning of Section 13(d) of the Exchange Act) shall have become the beneficial
owner of a majority of the outstanding common stock of the Company (other than
pursuant to the Stockholders' Agreement), (ii) the stockholders of the Company
cause a change in a majority of the members of the Board within a twelve-month
period, or (iii) the Company or its stockholders enter into an agreement to
dispose of all or substantially all of the assets or outstanding capital stock
of the Company. If the compensation to be paid upon a change in control would
constitute a "parachute" payment under the Internal Revenue Code, the amount
otherwise payable will be grossed up to an amount such that the employee will
receive the amount he would have received if no portion of such compensation
had been subject to the excise tax imposed by the Internal Revenue Code, and
the Company will be responsible for the amount of the excise tax.
On June 19, 1996, the Company entered into a consulting agreement with John S.
Callon to be effective as of the day he ceases to be the Chief Executive
Officer of the Company. Pursuant to the agreement, John S. Callon is to pro-
vide consulting services to the Company on matters pertaining to corporate or
financial strategy, investor relations and public/private financing opportun-
ities for no more than 20 hours per month, ten months a year. The agreement
remains in effect from the effective date until December 31, 2001, subject to
renewal for succeeding five-year periods unless earlier terminated. As com-
pensation for his services under the agreement, John S. Callon will be paid a
fee ("Consultation Fee") of not less than $190,000 per year increased annually
based upon the change in the Consumer Price Index, as adjusted for inflation.
In addition, he will remain eligible to participate in the Company's major
medical and disability coverage, and will be entitled to participate in all
other employee benefit plans (other than a cash bonus program) provided
to full-time executives of the Company. As an inducement for entering into
the agreement, John S. Callon was granted 25,000 performance shares of Common
Stock, 20% of which vests on each of the first five anniversaries of the
effective date of the agreement, which was January 2, 1997.
Upon termination of the agreement other than for cause, John S. Callon or his
spouse shall be entitled to receive a termination payment equal to the
Consultation Fee, as adjusted for inflation, to be paid annually until the
later of the death of John S. Callon (if applicable) or his spouse. In
lieu of the termination payment, John S. Callon or his spouse may elect to
receive, subject to the approval of the Board of Directors, a lump sum payment
of $1.5 million. In addition, if the agreement terminates due to the Company's
breach, John S. Callon and his spouse shall be entitled to liquidated damages.
The Company may terminate the agreement for cause. "Cause" is defined
generally in the agreement as willful misconduct or intentional and continual
neglect of duties which has materially and adversely affected the Company.
On January 9, 1997, the Company announced the resignation of John S. Callon as
Chief Executive Officer, effective January 2, 1997, and the appointment of Fred
L. Callon, its President, as its new Chief Executive Officer. At the same time,
Dennis W. Christian, Senior Vice President, Acquisitions and Operations, assumed
the position of Chief Operating Officer which was previously held by Fred L.
Callon.
Recent Compensation Awards
On August 23, 1996, the Compensation Committee granted stock options to the
Company's executive officers and senior management under the 1996 Plan, subject
to stockholder approval of the 1996 Plan. Pursuant to the awards, Fred L.
Callon was granted an option to purchase 75,000 shares of Common Stock; Dennis
W. Christian was granted an option to purchase 70,000 shares of Common Stock;
John S. Weatherly was granted an option to purchase 65,000 shares of Common
Stock; Kathy G. Tilley was granted an option to purchase 55,000 shares of
Common Stock; and H. Michael Tatum, Jr. was granted an option to purchase
15,000 shares of Common Stock. In addition, other members of senior
management were granted options to purchase an aggregate 170,000 shares of
Common Stock. All of such options were granted at an exercise price of $12.00
per share, the fair market value of the Common Stock on the date of grant, and
20% of each option vests on January 1 of each succeeding year, beginning
January 1, 1997. Unvested options are subject to forfeiture upon certain term-
ination of employment events.
The Compensation Committee designated performance shares under the 1996 Plan
to the Company's executive officers on August 23, 1996, subject to stockholder
approval of the 1996 Plan. Contingent upon such stockholder approval, Fred L.
Callon will be awarded 60,000 performance shares; Dennis W. Christian will be
awarded 55,000 performance shares; John S. Weatherly will be awarded 50,000
performance shares; Kathy G. Tilley will be awarded 45,000 performance shares;
and H. Michael Tatum, Jr. will be awarded 15,000 performance shares;. 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.
Incentive Plans
The Company currently maintains two Common Stock-based incentive plans for
employees; the 1994 Callon Petroleum Company Stock Incentive Plan (the "1994
Plan") and the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996
Plan"). The Company in the past has used and will continue to use, stock
options and performance share grants to attract and retain key employees in
the belief that employee stock ownership and stock related compensation devices
encourage a community of interest between employees and stockholders. Pursuant
to the 1994 Plan and the 1996 Plan, in the case of a merger or consolidation
where the Company is not the surviving entity, or if the Company is about to
sell or otherwise dispose of substantially all of its assets while unvested
performance shares or unexercised options remain outstanding, the Compensa-
tion Committee or other plan administrator may, in its discretion and without
shareholder approval, declare that such performance shares shall vest, or that
some or all options exercisable in full before or simultaneously with such
merger, consolidation or sale of assets without regard for prescribed waiting
periods. Alternatively, the Compensation Committee or other plan administrator
may cancel all outstanding options provided option holders are given notice
and a period of 30 days prior to the merger, consolidation or sale to exercise
the options in full.
The 1994 Plan was adopted on June 30, 1994. Pursuant to the 1994 Plan, 600,000
shares of Common Stock were reserved for issuance upon the exercise of options
or for grants of performance shares. The 1994 Plan is administered by the
Compensation Committee of the Board of Directors. Members of the Compensation
Committee currently are Messrs. Stanger, Wallace, B. F. Weatherly and Wilson.
No awards were granted under the 1994 Plan during 1995 or 1996, other than the
20,000 automatic stock option grants to non-employee directors and the grant of
25,000 performance shares to John S. Callon in connection with his Consulting
Agreement. A total of 500,000 options are outstanding as of December 31, 1996.
The 1996 Plan was approved and adopted by the Board of Directors of the Company
on August 23, 1996, and awards were granted thereunder to various employees,
in each case subject to approval of the 1996 Plan by the stockholders of the
Company at the 1997 annual meeting. Individual awards under the 1996 Plan may
take the form of one or more of (i) incentive stock options; (ii) non-qualified
stock options; or (iii) performance shares.
The 1996 Plan is administered by a plan administrator which may be either (i)
the Board of Directors of the Company; (ii) any duly constituted committee of
the Board of Directors consisting of at least two non-employee directors; or
(iii) any other duly constituted committee of the Board of Directors. The plan
administrator will select the officers, key employees and consultants who will
receive awards and the terms and conditions of those awards. The maximum
number of shares of Common Stock that may be subject to outstanding awards may
not exceed 900,000. Shares of Common Stock tendered as payment for shares
issued upon exercise of an option or which are attributable to awards which
have expired, terminated or been canceled or forfeited are available for
issuance or use in connection with future awards.
The option price of any incentive stock option shall be 100% of the fair market
value of a share of Common Stock on the date the incentive option is granted.
Any incentive option must be exercised within ten years of the date of grant.
Unless otherwise determined by the plan administrator, the option price of any
non-qualified stock option shall be 100% of the fair market value of a share
of Common Stock on the date the option is granted. Vesting of stock options
and performance shares, and the term of any non-qualified stock option or per-
formance share award is determined by the plan administrator.
The 1996 Plan provides that each non-employee director of the Company shall,
on the date on which he or she is initially elected or appointed a director of
the Company, be granted a stock option to purchase 5,000 shares of Common Stock
for the fair market price on the date of grant and for a term of ten years.
After each subsequent annual meeting of stockholders at which such person
continues to serve as a director, he or she will automatically be granted a
stock option to purchase an additional 5,000 shares of Common Stock for the
fair market price on the date of such grant and for a term of ten years.
In the event of a termination of employment, outstanding options and per-
formance shares may be subject to forfeiture and/or time limitations. Stock
options and performance shares are evidenced by written agreements, the terms
and provisions of which may differ. No stock option is transferable other than
by will or by the laws of descent or distribution.
The 1996 Plan may be amended by the Board of Directors without the consent of
the stockholders except that any amendment, though effective when made, will be
subject to stockholder approval if required by any federal or state law or
regulation or by the rules of any stock exchange or automated quotation system
on which the Common Stock may then be listed or quoted. In addition, no amend-
ment can impair the rights of a holder of an outstanding award under the Plan
without such holder's consent. A total of 145,000 options are outstanding as
of December 31, 1996.
Compensation Committee Interlocks and Insider Participation
The members of the Company's Compensation Committee are Messrs. Stanger,
Wallace, B. F. Weatherly and Wilson, none of whom are or have been officers
or employees of the Company.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of March 12, 1997, certain information
with respect to the ownership of shares of Common Stock and the Company's
Series A Preferred Stock as to (i) all persons known by the Company to be the
beneficial owners of 5% or more of the outstanding shares, (ii) each director,
(iii) each of the executive officers named in the Summary Compensation Table,
and (iv) all executive officers and directors of the Company as a group.
Information set forth in the table with respect to beneficial ownership of
Common Stock and Series A Preferred Stock has been obtained from filings made
by the named beneficial owners with the SEC or, in the case of executive
officers and directors of the Company, has been provided to the Company by
such individuals.
Common Stock Preferred Stock
------------------------- -----------------------
Amount and Amount and
Name and Nature of Nature of
Address of Beneficial Percent of Beneficial Percent of
Beneficial Owner(a) Ownership Class Ownership Class
- --------------------- ------------ ---------- ----------- ----------
Directors:
John S. Callon 262,040 (b) 4.48 0 0
Fred L. Callon 660,171 (c) 11.28 0 0
200 North Canal Street
P. O. Box 1287
Natchez, Mississippi 39120
Dennis W. Christian 74,000 (d) 1.27 0 0
Robert A. Stanger 15,856 (e) * 0 0
John C. Wallace 1,999,758 (f) 34.64 0 0
65 Vincent Square
London, SW1 2RX, England
B. F. Weatherly 2,000,125 (g) 34.64 0 0
9603 Doliver Street
Houston, Texas 77063
Richard O. Wilson 2,002,031 (h) 34.66 1,000 *
2400 West Loop South
Suite 150
Houston, Texas 77027
Named Executive Officers:
John S. Weatherly 73,896 (i) 1.27 0 0
H. Michael Tatum, Jr. 28,000 (j) * 0 0
Kathy G. Tilley 41,147 (k) * 0 0
Directors and Executive Officers
as a Group (10 persons) 3,187,508 (l) 51.24 1,000 *
Certain Beneficial Owners:
NOCO Enterprises, L.P.
6814 Northampton Way
Houston, Texas 77055 1,984,758 (m) 34.47 0 0
Wellington Management Company, LLP
75 State Street
Boston, Massachusetts 02109 607,704 (n) 9.62 247,690 18.83
__________
*less than 1%
(a) Unless otherwise indicated, each of the above persons may be deemed to have sole voting and dispositive power with respect
to such shares.
(b) Of the 262,040 shares beneficially owned by John S. Callon, 97,040 are owned directly by him, and he has sole voting and
dispositive power over such shares, 105,000 shares are held in a family limited partnership, and 90,000 shares are subject to
options under the 1994 Plan exercisable within 60 days. Shares indicated as owned by John S. Callon do not include shares of
Common Stock owned by NOCO and shares of Common Stock owned by certain other members of the Callon Family, including 61,837
shares owned by John S. Callon's wife and over which he disclaims beneficial ownership. Under the terms of a Stockholders'
Agreement John S. Callon and the other members of the Callon Family have the right of first refusal to acquire shares of
Common Stock proposed to be sold by NOCO under certain circumstances and all parties to the Stockholders' Agreement have
agreed to support two directors nominated by the Callon Family and two directors nominated by NOCO. John S. Callon disclaims
beneficial ownership of the NOCO shares.
(c) Of the 656,761 shares beneficially owned by Fred L. Callon, 201,556 shares are owned directly by him; 268,016 shares are
held by him as custodian for certain minor Callon Family members; 78,430 shares are held by him as trustee of certain
Callon Family trusts; 80,000 are subject to options under the 1994 Plan exercisable within 60 days; 15,000 are subject to
options under the 1996 Plan exercisable within 60 days; and 17,169 shares are held by Fred L. Callon as Trustee of shares
held by the Callon Petroleum Company Employee Savings and Protection Plan. Shares indicated as owned by Fred L.
Callon do not include shares of Common Stock owned by NOCO and shares of Common Stock owned by other members of
the Callon Family, including 25,009 shares owned by Fred L. Callon's wife over which he disclaims beneficial ownership.
Under the terms of the Stockholders' Agreement, Fred L. Callon and the other members of the Callon Family have the right
of first refusal to acquire shares of Common Stock proposed to be sold by NOCO under certain circumstances and all parties
to the Stockholders' Agreement have agreed to support two directors nominated by the Callon Family and two directors
nominated by NOCO. Fred L. Callon disclaims beneficial ownership of these shares.
(d) All 60,000 shares are subject to options under the 1994 Plan and 14,000 shares subject to options under the 1996 Plan,
all of which are exercisable within 60 days.
(e) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days.
(f) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days, and 1,984,758 shares owned by
NOCO. See note (l) below.
(g) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days, and 1,984,758 shares owned by
NOCO. See note (l) below.
(h) Includes 15,000 shares subject to options under the 1994 Plan, exercisable within 60 days, 2,273 shares issuable upon
conversion of 1,000 shares of Series A Preferred Stock and 1,984,758 shares owned by NOCO (see note (1) below).
(i) Includes 217 shares which are held by Mr. Weatherly as custodian for his minor children and 60,000 shares which are
subject to options under the 1994 Plan and 13,000 shares which are subject to options under the 1996 Plan, all of which are
exercisable within 60 days.
(j) All 25,000 shares are subject to options under the 1994 Plan and 3,000 shares subject to options under the 1996 Plan,
all of which are exercisable within 60 days.
(k) Includes 30,000 shares subject to options under the 1994 Plan and 11,000 shares subject to options under the 1996 Plan,
all of which are exercisable within 60 days.
(l) Includes 405,000 shares subject to options under the 1994 Plan and 56,000 shares subject to options under the 1996 Plan,
all of which are exercisable within 60 days.
(m) The sole limited partner of NOCO is NOCO Holdings, L.P., and the sole general partner of NOCO is NOCO Properties Inc.,
a wholly-owned subsidiary of NOCO Holdings, L.P. The general partner of NOCO Holdings, L.P. is NOCO Management,
a limited liability company. The management of NOCO Management, Ltd. is vested in its four members: John C. Wallace,
Barry I. Meade, B. F. Weatherly and Richard O. Wilson. The address of NOCO Holdings, L.P. and NOCO Management,
Ltd. is the same as that listed above for NOCO. Mr. Wallace's address is 65 Vincent Square, London England SW1P 2RY.
Mr. Meade's address is 6814 Northampton Way, Houston, Texas 77055. Mr. Weatherly's address is 9603 Doliver Street,
Houston, Texas 77063. Mr. Wilson's address is 2400 West Loop South, Suite 150, Houston, Texas 77027. Messrs.
Wallace, Meade and Weatherly also serve as officers of NOCO Management, Ltd. NOCO Properties Inc. and NOCO
Management, Ltd. may be deemed to be the beneficial owner of the Common Stock to be held by NOCO as a result of their
respective general partner interests in NOCO and NOCO Holdings, L.P. As a result of their positions with NOCO
Management, Ltd., Messrs. Wallace, Meade, B. F. Weatherly and Wilson may be deemed to share the power to vote and
dispose of such Common Stock and thereby to be the beneficial owner of such Common Stock. Under the terms of the
Stockholders' Agreement, NOCO has the right of first refusal to acquire shares of Common Stock proposed to be sold by
members of the Callon Family under certain circumstances and all parties to the Stockholders' Agreement have agreed to
support two directors nominated by the Callon Family and two directors nominated by NOCO. NOCO disclaims beneficial
ownership of the shares owned by members of the Callon Family. Because of the Stockholders' Agreement, NOCO and
members of the Callon Family may be deemed to be a "group" for purposes of beneficial ownership under SEC regulations.
If such a group were deemed to exist, it would beneficially own over 60% of the Common Stock.
(n) Includes 563,000 shares issuable upon conversion of 247,690 shares of Preferred Stock.
Stockholders' Agreement
Pursuant to a Stockholders' Agreement among members of the Callon family and
NOCO dated September 16, 1994, the Callon Family and NOCO each select two
directors to the Company's Board of Directors. Specifically, the Stockholders'
Agreement provides that the Callon Family and NOCO shall use their best
efforts, including voting the shares of Common Stock which they own, to cause
the Company's Board of Directors to be composed of at least four members, two
of such members to be selected by the Callon Family and two of such members to
be selected by NOCO. The Stockholders' Agreement also contains restrictions
on transfer of shares of Common Stock owned by the Callon Family and NOCO and
prohibits the Callon Family and NOCO from taking certain actions which would
result in certain changes of control or fundamental changes, without the
consent of the other party.
As a result of the Stockholders' Agreement, the Callon Family, on the one hand,
and the Callon Family and NOCO, on the other, may be deemed to form a "group"
for purposes of beneficial ownership under SEC regulations. The Callon Family
disclaims beneficial ownership of the Common Stock owned by NOCO. In addition,
each Callon Family stockholder disclaims beneficial ownership of all shares of
Common Stock owned by the other Callon Family stockholders and the existence
of a group comprised of the Callon Family stockholders. If NOCO and the Callon
Family were deemed to be a group, it would beneficially own more than 60% of
the outstanding Common Stock.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Stockholders' Agreement
In connection with the Consolidation, the Company, the Callon Family (including
John S. Callon and Fred L. Callon) and NOCO entered into the Stockholders'
Agreement which (a) provides that the Callon Family shall vote for two directors
to the Company's Board of Directors as directed by NOCO and NOCO will vote for
two directors to the Company's Board of Directors as directed by the Callon
Family, (b) contains certain restrictions on transfer of the Common Stock owned
by the Callon Family and NOCO, and (c) provides that neither the Callon Family
nor NOCO can transfer shares of Common Stock in connection with, or vote for,
consent to or otherwise approve, a transaction which would result in certain
changes of control or fundamental changes without the prior written consent of
the other party. The Callon Family and NOCO own an aggregate of more than 60%
of the Company's outstanding Common Stock.
Contingent Shares
The Callon Family (including John S. Callon and Fred L. Callon), as former
shareholders of Callon Petroleum Operating, may receive additional shares of
Common Stock pursuant to a Contingent Share Agreement dated September 16, 1994
between the Callon Family and the Company (the "Contingent Share Agreement").
The number of shares issued in the Consolidation was based on the respective
asset values of the parties to the Consolidation, including Callon Petroleum
Operating. Callon Petroleum Operating owned certain oil and gas properties
which, for purposes of the Consolidation, could not be properly valued due to
inadequate drilling and production history. The Contingent Share Agreement
provides that shares of Common Stock will be issued to the Callon Family equal
to the present value of the properties at December 31, 1995, (as determined
by independent reserve engineers) divided by $12.05. Due to the continued
limited production history of the properties, the Company amended the Con-
solidation Agreement and extended the valuation date to December 31, 1996.
Subsequently, the valuation of the properties does not warrant the issuance
of additional shares and the Contingent Share Agreement has terminated.
Registration Rights
The Callon Family (including John S. Callon and Fred L. Callon) is party to a
Registration Rights Agreement dated September 16, 1994 (the "Registration Rights
Agreement"), pursuant to which they are entitled to require the Company to
register Common Stock owned by them with the SEC for sale to the public in a
firm commitment public offering and generally to include shares owned by them
in registration statements filed by the Company. NOCO and the Company have
entered into a similar agreement.
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES ANDREPORTS ON FORM 8-K
(a) 1. The following is an index to the financial statements and financial
statement schedules that are filed as part of this Form 10-K on pages 27
through 46.
Report of Independent Public Accountants
Consolidated Balance Sheets as of the Years Ended December 31, 1996 and 1995
Consolidated Statements of Operations for the Three Years in the Period
Ended December 31, 1996
Consolidated Statements of Stockholders' Equity for the Three Years in
the Period Ended December 31, 1996
Consolidated Statements of Cash Flows for the Three Years in the Period
Ended December 31, 1996
Notes to Consolidated Financial Statements
(a) 2. Schedules other than those listed above are omitted because they are
not required, not applicable or the required information is included in the
financial statements or notes thereto.
(a) 3. Exhibits:
2. Plan of acquisition, reorganization, arrangement, liquidation
or succession
2.1 Agreement and Plan of Consolidation dated August 1, 1994 by and
among the Company, Callon Consolidated Partners, L. P., Callon Petroleum
Operating Company, CN Resources and Wilcox Energy Company (incorporated
by reference from Exhibit 2.1 of the Registration Statement on Form 8-B
filed October 3, 1994)
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended (incorporat-
ed 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 Contingent Share Agreement dated September 16, 1994 between the
Company and the Callon Stockholders (incorporated by reference from
Exhibit 10.1 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 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)
10.3 Registration Rights Agreement dated September 16, 1994 between the
Company and Callon Stockholders (incorporated by reference from Exhibit
10.3 of the Company's Registration Statement on Form 8-B filed
October 3, 1994)
10.4 Employment Agreement dated September 16, 1994 between the Company
and Fred L. Callon (incorporated by reference from Exhibit 10.4 of the
Company's Registration Statement on Form 8-B filed October 3, 1994)
10.5 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)
10.6 Employment Agreement effective January 1, 1995, between the
Company and Dennis W. Christian. (incorporated by reference from
Exhibit 10.6 of the Company's Form 10-K for the fiscal year ended
December 31, 1995)
10.7 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)
10.8 Employment Agreement effective January 1, 1995, between the Company
and John S. Weatherly (incorporated by reference from Exhibit 10.8 of the
Company's Registration Statement on Form S-1, Reg. No. 33-96700)
10.9 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)
10.10 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)
10.11 Callon Petroleum Company 1996 Stock Incentive Plan (incorporated
by reference from Exhibit 10.6 of the Company's Registration Statement
on Form S-1/A filed November 14, 1996, Reg. No. 333-15501)
10.12 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)
10.13 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)
10.14 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)
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
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 24, 1997 /s/John S. Callon
______________________________
John S. Callon (principal executive officer
and director)
Date: March 24, 1997 /s/John S. Weatherly
______________________________
John S. Weatherly (principal financial officer
and principal accounting officer)
Date: March 24, 1997 /s/Fred L. Callon
______________________________
Fred L. Callon (director)
Date: March 24, 1997 /s/Dennis W. Christian
______________________________
Dennis W. Christian (director)
Date: March 24, 1997 /s/B. F. Weatherly
______________________________
B. F. Weatherly (director)
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the abovesigned, thereunto duly authorized.
CALLON PETROLEUM COMPANY
Date March 24, 1997 By: /s/John S. Weatherly
______________________________
John S. Weatherly, Senior Vice President,
Chief Financial Officer and Treasurer