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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[Mark One]
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 0-10526
ALEXANDER ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
OKLAHOMA 73-1088777
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
701 CEDAR LAKE BOULEVARD 73114-7800
OKLAHOMA CITY, OKLAHOMA (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code:(405) 478-8686
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: NONE Name of each exchange on
which registered: N/A
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $.03 PAR VALUE
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 [ ] No [X]
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 amendments to
this Form 10-K.
[ ]
THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF THE
REGISTRANT, COMPUTED BY USING THE CLOSING SALE PRICE OF THE REGISTRANT'S
COMMON STOCK AS OF MAY 6, 1996, WAS $43,970,111.
The number of shares outstanding of each of the registrant's classes of common
stock, as of May 6, 1996, was:
12,461,058 SHARES OF COMMON STOCK, PAR VALUE $.03.
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TABLE OF CONTENTS
PART I
Item Page
- ---- ----
1. BUSINESS............................................. 1
1A. EXECUTIVE OFFICERS OF THE REGISTRANT ................ 6
2. PROPERTIES........................................... 7
3. LEGAL PROCEEDINGS.................................... 11
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS... 12
PART II
5. MARKETS FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS................................... 13
6. SELECTED FINANCIAL DATA............................... 14
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS................... 15
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA........... 20
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE................... 21
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.... 21
11. EXECUTIVE COMPENSATION................................ 22
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT........................................ 24
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........ 24
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K........................................... 25
SIGNATURES.................................................. 28
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PART I
ITEM 1. BUSINESS
THE COMPANY
Alexander Energy Corporation, an independent energy company engaged in the
acquisition, exploration, development, production and marketing of natural gas
and crude oil, was organized as an Oklahoma corporation in 1980 by a group of
executive, professional and technical personnel who had previously been
employees of Reserve Oil and Gas Company prior to its acquisition by Getty
Petroleum. The Company was initially organized to provide technical and
operating services to another independent oil and natural gas company, but it
commenced independent operations after its initial public offering in 1981.
Beginning in 1985, the Company participated in two drilling partnerships with
John Hancock Mutual Life Insurance Company and Midwest Capital Group, Inc., a
wholly-owned subsidiary of an Iowa-based public utility holding company. These
partnerships invested over $37.6 million to acquire and develop properties,
drilling a total of 176 wells. In March 1993, the Company completed a second
offering of its common stock. Proceeds of such offering, along with the
Company's cash flow and a bank credit facility, were used to finance its
drilling, exploitation and acquisition program. Since completion of the 1993
offering of common stock, the Company has drilled 60 wells, with an average
working interest of 40%, resulting in 50 completions for a successful
completion rate of 83%. Unless the context otherwise requires, all references
to "Alexander" or the "Company" are to Alexander Energy Corporation and its
subsidiaries, and all information herein has been restated to give effect to
the Company's merger with American Natural Energy Corporation ("ANEC") in July
1994.
In June 1995, the Company merged ANEC, Bradmar Petroleum Corporation
("Bradmar") and Edwards & Leach Oil Company, former subsidiaries, into itself.
The mergers were accomplished in order to attain accounting and other
efficiencies. After giving effect to this merger, none of the Company's
remaining subsidiaries, individually or in the aggregate, has significant
assets, indebtedness, revenues or cash flow.
In November 1994, the Company received two unsolicited acquisition offers.
Subsequent to the offers, the Company hired Prudential Securities in November
1994 as its investment banker and commenced an orderly process of evaluating
possible merger partners. Of the two initially interested companies neither
(i) confirmed financing arrangements, (ii) signed a confidentiality agreement
nor (iii) visited the Company's data room as established to provide information
to interested parties. On March 10, 1995, the Company entered into an
exclusive agreement with Abraxas Petroleum Corporation ("Abraxas") to conduct
negotiations for a possible merger. This agreement was later extended until May
9, 1995. Negotiations with Abraxas by mutual agreement were terminated on May
11, 1995. During the summer of 1995, the Company initiated an offering of
senior notes through private placement (the "Senior Note Offering"). Due to
many factors, including a sharp decline in natural gas prices, an increase in
interest rates on the proposed Senior Note Offering and the filing of a lawsuit
by a stockholder against the Company and its directors (see ITEM 3. LEGAL
PROCEEDINGS), the Senior Note Offering was postponed. In December 1995,
National Energy Group, Inc. ("NEG"), one of the two companies initially
indicating an interest to merge, reinitiated negotiations. The Company and NEG
executed a letter of intent on December 29, 1995, wherein both companies agreed
in principal to an exchange of one share of Alexander stock for 1.8 shares of
NEG stock; however, if the average price of NEG stock was below $2.40 per share
or above $3.60 per share, the parties were under no obligation to consummate
the merger. On March 25, 1996, the letter of intent was amended to provide for
an exchange ratio of 1.7. On May 6, 1996, the Company announced that the
Company and NEG had not reached agreement on the terms of a definitive merger
agreement by the April 30, 1996 standstill deadline; however, both companies
are continuing to negotiate.
BUSINESS STRATEGY
Since 1984, Alexander has increased its proved reserves, production and
operating cash flow by executing its strategy of (i) acquiring mid-continent
reserves that are predominantly natural gas and have significant development
potential; (ii) increasing reserves and production by enhancing and exploiting
its reserves through low risk development drilling and improved operating
practices and recovery techniques including workovers, redrills, compression
adjustments and renegotiating natural gas sales contracts; (iii) controlling
operating costs and obtaining reimbursement for overhead expenses; and (iv)
engaging in controlled exploratory drilling.
Acquisitions. In the past ten years, the Company has made acquisitions
directly or indirectly through limited partnerships formed with institutional
partners. During this period, the Company has completed six acquisitions of
approximately 128.6 billion cubic feet of natural gas equivalents ("Bcfe") of
proved reserves with an aggregate cost of approximately $99.4 million or $0.77
per Mcfe. Two significant acquisitions in the Company's core areas of
operations were consummated in 1994.
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The Company actively pursues property acquisitions. Since 1984, the
Company has continually evaluated potential acquisitions of producing and
nonproducing properties, with an emphasis on producing properties with the
following objectives: (i) established production histories, (ii) existing
reserve estimates, (iii) potential opportunities to increase reserves through
additional recovery or enhancement techniques, (iv) close proximity to the
Company's existing operations, (v) the possibility of reducing expenses
associated with the properties and (vi) control of operations. The Company
relies upon advanced technology, as well as its trained and experienced
personnel, to determine whether a property meets the Company's acquisition
objectives.
In July 1994, the Company acquired ANEC in a transaction accounted for as
a pooling of interests. The ANEC merger added approximately 400 gross wells,
200 of which are now operated by the Company, and nearly doubled the Company's
reserves. The ANEC properties are concentrated in the central Oklahoma portion
of the Anadarko Basin and in the Cotton Valley Trend in eastern Texas where
ANEC experienced success drilling infill wells since 1985. Subsequent to the
merger, the Company conducted workovers on the Cotton Valley Trend properties.
In November 1994, the Company acquired 78 natural gas properties located
in the Arkoma Basin in Oklahoma and Arkansas from JMC Exploration, Inc. ("JMC")
for total consideration of $18.2 million. The 78 properties, one-half of which
are operated by the Company, initially contributed an estimated 21.4 billion
cubic feet ("Bcf") of natural gas to the Company's reserves. The JMC properties
reestablished the Company in the Arkoma Basin, a significant area of
development for the Company in its early years, with a strong position of
proved reserves, 26% of which remain to be developed. Planned exploitation
efforts and expected development of proved undeveloped reserves ("PUD") are
expected to add to the ultimate value of the acquisition.
The acquisitions of ANEC and the JMC properties greatly increased the
Company's proved reserves, production and cash flow. As a result of these
acquisitions, the Company's proved reserves increased 38% from 81.7 Bcfe at
December 31, 1993 to 112.9 Bcfe at December 31, 1995. The natural gas component
of the Company's reserves increased from 77% at December 31, 1993 to 88% at
December 31, 1995. In addition, approximately 34% of the Company's reserves are
proved undeveloped, providing the Company with an inventory of low risk
development drilling opportunities. These transactions increased the Company's
production from 13.4 million cubic feet of natural gas equivalents ("Mmcfe")
per day in 1993 to 27.8 MMcfe per day in 1995.
In additional to the acquisitions of ANEC and JMC properties, since its
inception the Company has increased its producing capabilities through the
acquisitions of (i) Bradmar in 1992; (ii) producing oil and gas properties in
Oklahoma in 1990 (the "MFS Properties"); (iii) leasehold interests in Oklahoma
and Texas through a joint venture in 1990 (the "Zilkha Properties"); and (iv)
oil and gas wells formerly owned by Brooks Hall Energy Corporation in 1984 (the
"Brooks Hall Properties").
Development of Acquisitions. When evaluating possible acquisitions, the
Company's geologists and engineers analyze various means by which production
may be increased or related operating expenses may be decreased. In addition,
the Company's personnel will attempt to identify the existence of any
previously unreported proved undeveloped reserves. For example, Bradmar did not
report proved undeveloped reserves with respect to its properties primarily
because it lacked sufficient capital to identify and develop these reserves;
accordingly, proved undeveloped reserves were not included in the estimated
proved reserves identified at the time of execution of the Bradmar acquisition
agreement. However, the Company's familiarity with the areas in which Bradmar
operated allowed the Company to assume in its acquisition analysis that an
unspecified quantity of proved undeveloped reserves existed.
Drilling and Development Program. The Company's development program
includes (i) identifying and drilling development prospects, (ii) drilling
increased density locations, (iii) adding production equipment and (iv)
renegotiating natural gas contracts. The impact of these programs on the
Company's six major acquisitions completed since 1984 has been significant.
Approximately 34% of the Company's reserves were classified as proved
undeveloped at December 31, 1995. At that date, the Company had identified 80
proved undeveloped locations on its properties with estimated proved
undeveloped reserves of 38.9 Bcfe, which will require approximately $22.5
million of capital costs to develop. Subject to further study and drilling
results, the Company believes that there are numerous potential drilling
locations on the Company's existing properties that should result in additional
proved reserves.
The Company has tentatively budgeted approximately $13 million for its
1996 drilling and development program, substantially all of which relates to
proved undeveloped locations. The actual capital expenditures will be subject
to cash flow from operations, after required debt service, and the Company's
ability to complete one or a combination of financing alternatives. Proceeds
from the financing alternatives will have to be sufficient in amount to also
retire the Company's term note with a bank. See Note 4 of Notes to
Consolidated Financial Statements. As of March 1996, the Company has
commitments to drill $1.6 million of such properties. Any properties not
drilled in 1996 may be deferred until future periods; however, if these
properties are not drilled in 1996 and the Company does not complete
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a significant acquisition, there is no assurance that the Company will be
successful in replacing reserves expected to be produced in 1996. See
Management's Discussion and Analysis of financial Condition and Results of
Operations - Liquidity and Capital Resources.
Controlled Exploration Opportunities. The Company conducts a controlled
exploration program which is designed to provide exposure to selected higher
risk, higher potential rate of return prospects. The Company manages its
exploration risks by limiting its exploration expenditures to approximately 5%
to 15% of its overall capital budget and applying advanced technology to
identifying prospects. Since completion of the 1993 public offering of common
stock, the Company has drilled four exploratory wells at an aggregate cost of
$1.3 million.
Operating and Administrative Expenses. The Company owns working interests
in 768 wells, of which it operates 391 wells representing approximately 86% of
the Present Value (as defined herein) of its proved reserves. By serving as
operator, the Company is able to maintain efficiencies in operations and obtain
operator and management fees which offset the majority of its general and
administrative expenses. Operator and management fees offset 69%, 65% and 77%
of general and administrative expenses in 1993, 1994 and 1995, respectively.
Also, Alexander has pursued a strategy of selling marginal and non-strategic
properties to reduce well operating expenses, both on an absolute and on a
per-unit-of-production basis.
MARKETS AND CUSTOMERS
The Company operates exclusively in the oil and gas industry. Its
revenues are derived from its proportionate interest in domestic oil and gas
producing properties. The Company does not consider its business seasonal;
however, market demand (and the resulting prices received for crude oil and
natural gas) can be affected by weather conditions, economic conditions, import
quotas, the availability and cost of alternative fuels, the proximity to, and
capacity of, natural gas pipelines and other systems of transportation, the
effect of state regulation of production, and federal regulation of oil and gas
sold in intrastate and interstate commerce. All of these factors are beyond
the control of the Company.
The Company sells its crude oil at posted field prices in effect in the
producing fields within which its operations are conducted. During the years
ended December 31, 1994 and 1995, the price for the Company's oil ranged from
$10.65 per 42 U.S. gallon barrel ("Bbl") to $20.59 per Bbl and from $15.25 per
Bbl to $18.58 per Bbl, respectively. Because of restrictions on flaring
natural gas, wells which produce both oil and gas may be shut-in when there is
not a market for the gas, even though a market is otherwise available for the
oil.
Natural gas production of the Company is sold under long-term and spot
market contracts to intrastate and interstate pipeline companies and natural
gas marketing companies. Prices received by the Company for natural gas
production during the years ended December 31, 1994 and 1995 varied from $0.65
per thousand cubic feet ("Mcf") to $4.90 per Mcf and from $0.60 per Mcf to
$4.37 per Mcf, respectively.
Approximately 46% of the Company's natural gas is sold on the spot market
or under short-term contracts (one year or less) providing for variable or
"market-sensitive" prices. Approximately 54% of the Company's natural gas is
marketed under various long-term contracts which dedicate the natural gas to a
purchaser for an extended period of time, but which still involve variable or
market-sensitive pricing of the Company's natural gas.
The Company's natural gas production is sold under contracts with various
purchasers. Natural gas sales to GPM Gas Corporation ("GPM") and Cowboy
Pipeline Service Company ("Cowboy") individually accounted for 12% and 13% of
total revenues for the years ended December 31, 1993 and 1994. During 1995,
natural gas sales to GPM accounted for 13%of total revenues.
The Company does not believe that the loss of any of its existing
customers would have a material adverse effect on the results of operations of
the Company.
REGULATION
General. The oil and natural gas industry is extensively regulated by
federal, state and local authorities. Legislation affecting the oil and natural
gas industry is under constant review for amendment or expansion. In October
1992, comprehensive national energy legislation was enacted which focuses on
electric power, renewable energy sources and conservation. The legislation,
among other things, guarantees equal treatment of domestic and imported natural
gas supplies, mandates expanded use of natural gas and other alternative fuel
vehicles, funds natural gas research and development, permits continued
offshore drilling and use of natural gas for electric generation and adopts
various conservation measures designed to reduce consumption of imported oil.
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Numerous governmental departments and agencies, both federal and state,
have issued rules and regulations binding on the oil and natural gas industry
and its individual members, some of which carry substantial penalties for the
failure to comply. The regulatory burden on the oil and natural gas industry
increases its cost of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.
Exploration and Production. The Company's exploration and development
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells; maintaining bonding requirements in order to drill or operate wells; and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled and the
plugging and abandoning of wells. The Company's operations are also subject to
various conservation matters and rules to protect the correlative rights of
subsurface owners. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells which may be drilled
and the unitization or pooling of oil and natural gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely on voluntary pooling of land and
leases. In addition, state conservation laws establish maximum rates of
production from oil and natural gas wells, generally prohibit the venting or
flaring of natural gas and impose certain requirements regarding the ratability
of production. The effect of these regulations is to limit the amounts of oil
and natural gas the Company can produce from its wells and to limit the number
of wells or the locations at which the Company can drill. Recently enacted
legislation in Oklahoma and regulatory action in Texas modifies the methodology
by which the regulatory agencies establish permissible monthly production
allowables. Such action has generated substantial controversy, especially at
the federal level, and has been labeled as being intended to reduce the total
production of natural gas in order to increase natural gas prices. A recent
attempt to enact a federal prohibition of these recent state proration rule
initiatives was defeated, but various members of Congress and some federal
regulators have declared an intent to monitor the states' actions very
carefully. The Company cannot predict what effect these new prorationing
regulations will have on its production and sales of natural gas.
Certain of the Company's oil and natural gas leases are granted by the
federal government and administered by various federal agencies. Such leases
require compliance with detailed federal regulations and orders which regulate,
among other matters, drilling and operations on these leases and calculation
and disbursement of royalty payments to the federal government. The Mineral
Lands Leasing Act of 1920 (the "MLLA") places limitations on the number of
acres under federal leases that may be owned in any one state. Additionally,
the MLLA and related regulations also may restrict a corporation from holding
federal onshore oil and natural gas leases if stock of such corporation is
owned by citizens of foreign countries which are not deemed reciprocal under
the MLLA. Reciprocity depends, in large part, on whether the laws of the
foreign jurisdiction discriminate against a United States citizen's ownership
of rights to minerals in such jurisdiction. The purchase of shares in the
Company by citizens of foreign countries with laws which are not deemed to be
reciprocal under the MLLA could have an impact on the Company's ownership of
federal leases.
Environmental and Occupational Regulations. The Company has an engineer
who also serves as an environmental compliance officer with the responsibility
to implement an environmental compliance program and to monitor environmental
compliance and potential environmental liabilities of the Company. Operations
of the Company are subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the
acquisition of a permit before drilling commences, limit or prohibit drilling
activities on certain lands lying within wilderness or wetlands and other
protected areas and impose substantial liabilities for pollution resulting from
drilling operations. Such laws and regulations may also restrict air or other
pollution resulting from the Company's operations. Moreover, many commentators
believe that the state and federal environmental laws and regulations will
become more stringent in the future. For instance, legislation has been
proposed in Congress in connection with the pending reauthorization of the
federal Resource Conservation and Recovery Act ("RCRA"), which would amend RCRA
to reclassify oil and natural gas production wastes as "hazardous waste." If
such legislation were to be enacted, it could have a significant impact on the
operating costs of the Company, as well as the oil and natural gas industry in
general. State initiatives to further regulate the disposal of oil and natural
gas wastes are also pending in certain states and these various initiatives
could have a similar impact on the Company. Management believes that compliance
with current applicable environmental laws and regulations will not have a
material adverse impact on the Company. However, many of these laws and
regulations increase the Company's overall operating expenses, and future
changes to environmental laws and regulations could have a material adverse
impact on the Company.
The Company is also subject to laws and regulations concerning
occupational safety and health. While it is not anticipated that the Company
will be required in the near future to expend amounts that are material in the
aggregate to the Company's overall operations by reason of occupational safety
and health laws and regulations, the Company is unable to predict the ultimate
cost of compliance.
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Marketing and Transportation. Historically, the transportation and sale
for resale of natural gas in interstate commerce have been regulated pursuant
to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the
"NGPA"), and the regulations promulgated thereunder by the Federal Energy
Regulatory Commission (the "FERC"). From 1978 until January 1, 1993, maximum
selling prices of certain categories of natural gas sold in "first sales,"
whether sold in interstate or intrastate commerce, were regulated pursuant to
the NGPA. The NGPA established various categories of natural gas and provided
for graduated deregulation of price controls of several categories of natural
gas and the deregulation of sales of certain categories of natural gas.
Several major regulatory changes have been implemented by FERC from 1985
to the present that affect the economics of natural gas production,
transportation and sales. In addition, FERC continues to promulgate revisions
to various aspects of the rules and regulations affecting those segments of the
natural gas industry, most notably interstate natural gas transmission
companies, which remain subject to FERC's jurisdiction. These initiatives may
also affect the intrastate transportation of natural gas under certain
circumstances. The stated purposes of many of these regulatory changes is to
promote competition among the various sectors of the natural gas industry. The
ultimate impact of these complex and overlapping rules and regulations, many of
which are repeatedly subjected to judicial challenge and interpretation, cannot
be predicted.
Various rules, regulations and orders, as well as statutory provisions,
may affect the price of natural gas production and the transportation and
marketing of natural gas.
No Price Controls on Liquid Hydrocarbons. In the past there have been
regulations of the sales price of liquid hydrocarbons, however, there are
currently no price controls on crude oil, condensate or natural gas liquids.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
exploration for and production of oil and natural gas, such as blowouts,
cratering, abnormally pressured formations, explosions, uncontrollable flows of
oil, natural gas or well fluids into the environment, fires, pollution,
releases of toxic gas and other environmental hazards and risks. These hazards
can result in substantial losses to the Company due to personal injury and loss
of life, severe damage to and destruction of property and equipment, pollution
or environmental damage or suspension of operations.
The Company maintains insurance of various types customary in the industry
to cover its operations. The Company's insurance does not cover every potential
risk associated with the drilling and production of oil and natural gas. In
particular, coverage is not obtainable for certain types of environmental
hazards. The occurrence of a significant adverse event, the risks of which are
not fully covered by insurance, could have a material adverse effect on the
Company's financial condition and results of operations. Moreover, no assurance
can be given that the Company will be able to maintain adequate insurance in
the future at rates it considers reasonable.
The Company maintains levels of insurance customary in the industry to
limit its financial exposure in the event of a substantial environmental claim
resulting from sudden and accidental discharges; however, 100% coverage is not
maintained. Unreimbursed expenditures in 1993, 1994 and 1995 were immaterial.
COMPETITION
The Company operates in a highly competitive environment, particularly
with respect to the acquisition of producing properties and proved undeveloped
acreage. A number of the Company's competitors, however, have financial
resources and exploration and development budgets that substantially exceed
those of the Company, and may be able to pay more for desirable leases and to
evaluate, bid for and purchase a greater number of properties or prospects than
the financial or personnel resources of the Company permit.
EMPLOYEES
As of May 1, 1996, the Company employed 35 full-time employees, none of
which was subject to a collective bargaining agreement. The Company's
professional staff includes two landmen, four geologists, three engineers, five
accountants, two division order analysts and a marketing specialist. The
Company considers relations with its employees to be good.
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ITEM 1A. EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers and directors of the Company at March 29, 1996 are
identified below. The officers serve at the pleasure of the Board of Directors.
Roger G. Alexander is the son of Bob G. Alexander.
Name Age Position Since
------------------ --- ------------------------------------- -----
Bob G. Alexander 62 President, Chief Executive Officer 1980
and Director
David E. Grose 43 Vice President, Treasurer, Chief 1983
Financial Officer and Director
Jim L. David 56 Executive Vice President and Director 1980
Roger G. Alexander 41 Vice President (Land) and Director 1987
Phillip J. Lohmann 57 Vice President (Operations) 1996
Sue Barnard 51 Secretary 1982
Brian F. Egolf 46 Director 1992
Robert A. West 56 Director 1994
Bob G. Alexander, a founder of the Company, has been a director and the
President and Chief Executive Officer of the Company since inception in 1980.
From 1976 to 1980, Mr. Alexander was Vice President and General Manager of the
Northern Division of Reserve Oil, Inc. and President of Basin Drilling Corp.
(subsidiaries of Reserve Oil and Gas Company). Mr. Alexander attended the
University of Oklahoma and graduated in 1959 with a bachelor of science degree
in geological engineering. He has extensive experience in exploration, drilling
and production in the Mid-Continent, West Texas and Gulf Coast regions and Utah
for major and independent oil and natural gas companies. Professional
memberships include the Independent Petroleum Association of America ("IPAA"),
of which he currently serves as a member of the Executive and Economic
Committees, and the Oklahoma Independent Petroleum Association ("OIPA"), of
which he serves as a director, treasurer and a member of the OIPA Federal
Energy Policy Task Force. He is former vice-chairman of the Natural Gas Task
Force of Oklahoma and former chairman of The Commission on Natural Gas Policy.
David E. Grose joined the Company at its inception in March 1980 as a
financial accountant and served as Assistant Treasurer from October 1983 until
his election in 1987 as a director and Vice President, Treasurer and Chief
Financial Officer. From 1977 to 1980, he held a position in the corporate
accounting department of Reserve Oil and Gas Company and was the rig accountant
for Basin Drilling Corporation. Mr. Grose received a bachelor of arts degree in
political science from Oklahoma State University in 1974 and a masters degree
in business administration from Central State University in 1977. Professional
memberships include the Petroleum Accountants Society of Oklahoma City and the
IPAA. Mr. Grose formerly served on the Tax Committee of the IPAA.
Jim L. David, a founder of the Company, has served as a director and Vice
President since its inception in March 1980. In August 1987, he was elected
Executive Vice President. Mr. David began his career in oil and gas exploration
with Mobil Oil Corporation as an exploration and development geologist. He
worked in this capacity in Shreveport, Louisiana; Corpus Christi, Texas; New
Orleans, Louisiana; Denver, Colorado; and Anchorage, Alaska. From October 1973
to October 1976, Mr. David served as Alaska chief geologist and senior staff
geologist for Texas International in Oklahoma City. Thereafter, he was employed
as exploration manager for Reserve Oil, Inc., Northern Division, in Oklahoma
City from January 1977 until formation of the Company. Mr. David graduated with
a bachelor of arts degree in geology from Louisiana Tech University in 1962 and
obtained a master of arts in geology from the University of Missouri in 1964.
Professional memberships include the American Association of Geologists and the
Oklahoma City Geological Society. Mr. David is a certified petroleum geologist.
Roger G. Alexander, a certified petroleum landman, has served as Vice
President (Land) and director of the Company since February 1987. Mr. Alexander
joined the Company as a landman in August 1983 and became senior landman in
August 1984. In July 1985, he was named land manager. He was employed as a
landman by Texas Oil & Gas Corporation in its West Texas District, Midland,
Texas, from June 1981 to August 1983. Mr. Alexander graduated with a bachelor
of business administration degree, with a major in petroleum land management,
from the
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University of Oklahoma in 1981. Professional memberships include the American
Association of Petroleum Landmen and the Oklahoma City Association of Petroleum
Landmen.
Phillip J. Lohmann was elected Vice President (Operations) in February
1996. Prior to joining the Company he served as President of Lohmann &
Associates, Inc., Norman, Oklahoma, a petroleum operating and engineering
consulting firm. From 1974 to 1979, Mr. Lohmann was Vice President of Jasper &
Lohmann Engineering, Inc. He held several engineering positions in Oklahoma
City and was the district Manager for McCulloch Oil Corporation in Bakersfield,
California, from 1972 to 1974. He has extensive experience in exploration,
drilling and production in the Mid-Continent, Texas and California. Mr.
Lohmann graduated from the University of Oklahoma in 1962 with a bachelor of
science degree in industrial engineering and is a member of the Society of
Petroleum Engineers.
Sue Barnard has served as Corporate Secretary since 1985 and director of
investor relations since June 1988. Additionally, since 1986 she has served the
Company in the capacities of Risk Manager and Manager of Human Resources. Ms.
Barnard joined the Company in June 1982 as assistant to the Vice President --
Administration and as Assistant Corporate Secretary. Professional memberships
include the American Society of Corporate Secretaries.
Brian F. Egolf received a bachelor of arts degree in political science
and history from Stanford University in 1970. Since graduation, Mr. Egolf has
had an extensive career in the oil and natural gas industry. He was a director
and the president of Bradmar from its inception in 1989 until the Company
acquired Bradmar in March 1992. Mr. Egolf has been a general partner of The
Egolf Company since its formation in 1979. The Egolf Company served as the
general partner of Bradmar's predecessor, Petroleum Investments, Ltd., and
served as the general partner of nine oil and natural gas drilling
partnerships.
Robert A. West, a 1961 graduate of The University of Tulsa, has had a
varied career in the energy business spanning more than 30 years. Since 1973,
Mr. West has owned and/or invested in various energy industry service companies
including Alexander Well Services, Inc. and Beacon Fluid Services (formerly
Beacon Well Services, Inc.). Since 1989, he has served as president and
majority stockholder of The West Group, Inc., a vacuum transport and completion
fluids service company. Mr. West's trade association memberships include the
Oklahoma Independent Petroleum Association. His civic contributions include
serving since 1988 in various capacities on the Board of Trustees of The
University of Tulsa.
ITEM 2. PROPERTIES
Alexander's properties are located primarily in the Anadarko Basin in
Oklahoma, the Cotton Valley Trend of eastern Texas and in the Arkoma Basin in
eastern Oklahoma and western Arkansas. The remainder of the Company's holdings
and operations are located in the Austin Chalk Trend of central Texas, the
Golden Trend of south central Oklahoma, and in Colorado, Kansas, Nebraska and
Wyoming. The Company's estimated proved reserves as of December 31, 1995
consisted of approximately 99 Bcf of natural gas and 2.3 MMBbls of crude oil
with an aggregate present value, before income taxes, of estimated future net
revenues discounted at 10% per annum ("Present Value") of approximately $85
million based on average prices of $1.95 per Mcf and $18.40 per Bbl. Net daily
production averaged 24,843 Mcf and 496 Bbls, or a total of 27,818 Mcfe in 1995,
up 8% from 1994. Approximately 88% of the Company's reserves are natural gas.
In 1995, the Company's proved reserves were estimated by Netherland Sewell
& Associates, independent petroleum engineers. Approximately 31 Bcfe was
reclassified from proved undeveloped to probable and possible at December 31,
1995. The Company believes this is the result of a more conservative
application of engineering assumptions than used previously. Additionally, in
1995 the Company experienced approximately 11 Bcfe of additional downward
reserve revisions. A significant portion of these revisions relates to certain
undeveloped locations which the Company now believes is being depleted through
existing proved producing properties, previously thought to be accessible only
through recompletions and /or additional development drilling. As a result of
these reclassifications and reserve adjustments, approximately 66% of the
Company's proved reserves are classified as proved developed, an increase of 8%
from 1994. See Note 14 of Notes to Consolidated Financial Statements.
7
10
PRIMARY OPERATING AREAS
Proved reserves within the Company's primary operating areas are
summarized as follows:
Natural Percent Number
Natural Gas of of PDNP
Oil Gas Equivalent Proved and PUD
Field (Mbbl) (Mmcf) (Mmcfe) Reserves Locations
- ------------------------ ------ ------ ---------- -------- ---------
Anadarko Basin ........ 1,556 59,514 68,850 61% 73
Cotton Valley Trend ... 215 18,863 20,153 18% 20
Arkoma Basin .......... -- 16,807 16,807 15% 18
Other (1) ............. 537 3,886 7,108 6% 16
(1) Consists of proved reserves of 4.0 Bcfe located in the Austin Chalk Trend
of central Texas, 2.8 Bcfe located in the Golden Trend Field in south
central Oklahoma and 0.3 Bcfe located throughout the Company's other
holdings.
The table above and all other discussion of reserves contained herein
excludes those reserves that are based on geologic and/or engineering data
similar to that used in estimating proved reserves, but technical, contractual,
economic or regulatory uncertainties preclude such reserves from being
classified as proved ("probable and possible"). As of December 31, 1995, the
Company had identified probable and possible locations that add another 31 Bcfe
to the Company's reserve base.
Anadarko Basin. Approximately 61% (68.9 Bcfe) of the Company's proved
reserves are located in the Anadarko Basin primarily in Canadian, Kingfisher,
Major and Logan counties of Oklahoma. Alexander has been operating in the
Anadarko Basin since its inception. The Anadarko Basin is considered a mature
natural gas producing area that is characterized by multiple producing
horizons. Wells in the Anadarko Basin are completed in rocks varying in age
from Pennsylvania through Cambro-Ordovician at depths ranging from 2,000 to
25,000 feet. The Company's Anadarko properties are generally spaced across 640
acres and Alexander has been actively engaged in increased density drilling in
the area. As of December 31, 1995, the Company had identified 31 proved
developed, nonproducing or behind pipe ("PDNP") and 42 PUD locations in the
Anadarko Basin with estimated proved reserves of 23.3 Bcfe. The typical well in
the Anadarko Basin inventory is expected to range from 7,500 to 15,000 feet and
cost approximately $680,000 (gross) to drill and complete and have
approximately 1.9 Bcfe of recoverable reserves.
Cotton Valley Trend. Approximately 18% (20.2 Bcfe) of the Company's proved
reserves are located in the Cotton Valley Trend in Harrison and Rusk counties
in eastern Texas. The Company acquired its properties in the Cotton Valley as a
result of the merger with ANEC, which had been operating in the area since
1985. The Cotton Valley producing formation is 1,500 to 2,000 feet thick, is
located at depths of 8,500 to 10,500 feet and consists of interbedded
sandstones and shales. Although the Cotton Valley consists of low permeability
sandstones, numerous wells have been successfully completed with the use of
hydraulic fracture stimulation. Original development in the Cotton Valley was
drilled on 640 acre spacing, but production performance has revealed that wells
drilled on this spacing are insufficient to adequately drain the reservoir. New
studies show developing these tight sands on 80 acre spacing is necessary to
recover all commercially producible reserves.
The lowermost zone of the Cotton Valley sands, known as the Taylor Sand,
was initially considered the best producing interval, having crossplot porosity
from 2% to in excess of 6% and a thickness of over 100 feet. Recent completions
of the upper and middle sections of the Cotton Valley formation have proved to
be as productive as the Taylor Sand. Intervals to be completed are determined
from a combination of electric log analysis and natural gas shows from mud
logs.
As of December 31, 1995, the Company had identified 8 PDNP and 12 PUD
locations in the Cotton Valley. The typical well in this inventory is expected
to cost approximately $900,000 (gross) to drill and complete and to have
approximately 1.6 Bcfe of recoverable reserves.
Arkoma Basin. Approximately 15% (16.8 Bcfe) of the Company's proved
reserves are located in the Arkoma Basin in eastern Oklahoma and western
Arkansas. This east-west trending basin consists of complexly faulted
anticlinal and synclinal folds with parallel complex fault systems,
crisscrossed by shallow Pennsylvanian age sandstone reservoirs. North-south
trending reservoir sands trapped against these faults and folds result in
commercial natural gas accumulations. Deep structures within the confines of
the producing "fairway" produce natural gas from massive carbonates, highly
fractured by structural movement.
8
11
Natural gas is produced from several sandstone reservoirs and deep massive
carbonates along the south flank of the Arkoma Basin. Most of these channel
sands follow structural grain and are prolific natural gas producers when
trapped by faulting. Drilling ranges from 1,000 feet for shallow Pennsylvanian
age sands to over 15,000 feet for massive Arbuckle carbonates. Most of the
Company's production is from the Red Oak, Cromwell, Spiro and Wapanucka sands
with depths of 7,000 to 8,000 feet.
As of December 31, 1995, the Company had identified 3 PDNP and 15 PUD
locations in the Arkoma Basin. The Company has recently started to fully
evaluate the Arkoma properties acquired from JMC and anticipates that numerous
additional drill sites will be developed. The typical Arkoma Basin well in this
inventory is expected to cost approximately $350,000 (gross) to drill and
complete and have approximately 2.0 Bcfe of ultimate recoverable reserves.
OIL AND NATURAL GAS RESERVES
The following table sets forth estimated proved reserves, the estimated
future net revenues therefrom and the present value thereof as of December 31,
1995. The proved reserves are based upon the Estimate of Reserves and Future
Revenue to the Alexander Interest in Certain Oil and Gas Properties as of
December 31, 1995 of Netherland, Sewell & Associates, Inc. The calculations
used in preparation of such report was prepared using standard geological and
engineering methods generally accepted by the petroleum industry and in
accordance with SEC guidelines (as described in the notes below). These
correspond with the method used in presenting the supplemental information on
oil and gas operations in the Notes to the Consolidated Financial Statements of
the Company, except that income taxes otherwise attributable to such future net
revenues have been disregarded in the presentation below. For supplemental
disclosure of the estimated net quantities of oil and natural gas reserves, see
Note 14 of Notes to Consolidated Financial Statements of the Company.
Natural Pretax
Natural Gas Future Net
Oil Gas Equivalent Revenue Present Value
(MBbls) (Bcf) (Bcfe) (M$) (1) (M$)
------- ------- ---------- ---------- -------------
Proved Reserves ............. 2,308 99.1 112.9 $142,983 $ 85,448
Proved Developed Reserves ... 1,216 66.7 74.0 $ 97,630 $ 61,374
- ---------
(1) Estimated future net revenue represents estimated future gross revenues to
be generated from the production of proved reserves, net of estimated
production and future development costs, using costs and prices in effect
as of December 31, 1995. In certain circumstances, the actual natural gas
price received was less than the December 31, 1995 contract price, in
which case the lower actual price was used. These prices were not changed
except where different prices were fixed and determinable from applicable
contracts. These assumptions yield average prices of $1.95 per Mcf of
natural gas and $18.40 per Bbl of oil over the life of the properties. The
amounts shown do not give effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax
expense or to depreciation, depletion and amortization.
No estimates of the Company's proved reserves have been included in
reports to any federal agency other than the Commission.
The prices used in calculating the estimated future net revenues
attributable to proved reserves do not necessarily reflect market prices for
oil and natural gas production subsequent to December 31, 1995. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations -- Prices and Production Volumes." There
can be no assurance that all of the proved reserves will be produced and sold
within the periods indicated, that the assumed prices will be realized or that
existing contracts will be honored or judicially enforced.
The process of estimating oil and natural gas reserves contains numerous
inherent uncertainties and requires significant subjective decisions in the
evaluation of available geological, engineering and economic data for each
reservoir. The data for a given reservoir may change substantially over time as
a result of, among other things, additional development activity, production
history and viability of production under varying economic conditions.
Consequently, reserve estimates are often materially different from the
quantities of oil and natural gas that are ultimately recovered, and material
revisions to existing reserve estimates may occur in the future. See Note 14 of
Notes to Consolidated Financial Statements.
9
12
PRODUCTION, PRICE AND COST HISTORY
The following tables set forth certain historical information concerning
the Company's oil and natural gas production and prices, net of all royalties,
overriding royalties, and other third party interests.
Years ended December 31,
------------------------------------
1993 1994 1995
---------- ---------- ----------
Average net daily production:
Oil (Bbls) ........................... 776 614 496
Natural gas (Mcf) .................... 17,348 22,057 24,843
Natural gas equivalent (Mcfe) ........ 22,004 25,741 27,818
Average sales price:
Oil (Per Bbl) ........................ $ 16.99 $ 15.44 $ 16.57
Natural gas (Per Mcf) ................ 2.04 1.73 1.50
Natural gas equivalent (Per Mcfe) .... 2.20 1.85 1.64
Average net production cost
per Mcfe(1) .......................... $ .66 $ .65 $ .60
- ---------
(1) Production cost consists of lease operating expenses and production
taxes.
DRILLING ACTIVITIES
In each of the years ended December 31, 1993, 1994 and 1995, the Company
incurred net exploration and development costs of $11.3 million, $12.3 million
and $3.3 million, respectively. The following table sets forth the Company's
historical drilling activities for each of the years ended December 31, 1993,
1994 and 1995:
Year ended December 31,
-----------------------------------------------------
1993 1994 1995
--------------- ---------------- ---------------
Gross Net Gross Net Gross Net
----- ------ ----- ------ ----- -----
Development:
Oil ................. 12 3.431 7 .998 3 .714
Gas ................. 17 5.967 22 7.320 2 1.520
Non-productive ...... 1 1.000 4 2.155 3 1.823
-- ------ -- ------ - -----
Total .............. 30 10.398 33 10.473 8 4.057
Exploratory:
Oil ................. 1 .247 0 .000 0 .000
Gas ................. 0 .000 0 .000 0 .000
Non-productive ...... 0 .000 2 1.495 1 .978
-- ------ -- ------ - -----
Total .............. 1 .247 2 1.495 1 .978
- ---------
The table above only reflects those interests attributable to the Company
either through direct working interests or through the Company's proportionate
share of its partnership's participation; i.e., the interests shown do not
include overriding royalty interests, carried working interests, reversionary
interests or partners' proportionate share of participation.
PRODUCTIVE WELLS AND ACREAGE
The following table reflects the wells and acreage in which the Company
owned a working interest, directly or indirectly, as of December 31, 1995. The
table shows producing oil (including casinghead natural gas) and natural gas
wells, including shut-in oil and natural gas wells capable of producing natural
gas which are (i) awaiting the construction or completion of natural gas plants
or gathering facilities, (ii) shut-in until sufficient reserves of natural gas
are established to justify construction of such facilities or (iii) shut-in due
to the absence of a market. The table does not include 84 gross wells in that
the Company has a revenue interest other than as a working interest owner. The
Company additionally owns overriding royalty interests or other revenue
interests in approximately 218 of the gross wells reflected below.
10
13
Producing Wells Shut-In Wells
------------------------------------------- ---------------------------------------------
Oil Gas Oil Gas
------------------- ---------------------- ---------------------- ---------------------
State Gross Net Gross Net Gross Net Gross Net
- ----- ----- ------------ ------------ -------- ----- --------------- ----------- --------
Arkansas --- --- 35 11.5356 --- --- 8 2.6192
Colorado 8 .0094 --- --- --- --- --- ---
Kansas 6 3.2820 2 .0089 --- --- --- ---
Nebraska 3 .0116 --- --- --- --- --- ---
Oklahoma 243 96.3108 363 142.4220 25 12.8496 25 9.9334
Texas 15 4.4858 26 12.3947 --- --- 2 .1888
Wyoming 2 .0020 4 .0004 --- --- 1 .0001
----- -------- ------ -------- ----- ------- - --------
Totals 277 104.1016 430 166.3616 25 12.8496 36 12.7415
Developed Acreage Undeveloped Acreage
-------------------------- ----------------------------
State Gross Net Gross Net
- ----- ------------ ------------ --------------- -----------
Arkansas 18,431 6,281 1,144 68
Colorado 440 1 --- ---
Kansas 798 192 --- ---
Nebraska 360 1 --- ---
Oklahoma 206,633 68,057 9,559 5,121
Texas 12,585 5,120 1,275 810
Wyoming 440 1 ----- -----
------------ ------------ --------------- -----------
Totals 182,938 61,222 11,978 5,998
Undeveloped acres are those on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas, regardless of whether or not such acreage contains
proved reserves. The amount of acreage held by the Company increases or
decreases in the normal course of business as interests in new acreage are
acquired (including acreage by pooling), as interests are sold or contributed
to others, as wells are drilled, as properties are abandoned (if determined not
to warrant exploration or development) or as leases expire. It is the Company's
policy to formulate drilling plans for the orderly development of undeveloped
acreage within the primary terms of the leases involved.
TITLE TO PROPERTIES
Substantially all of the Company's property interests are held pursuant to
leases from third parties. Title to properties is subject to royalty,
overriding royalty, carried, net profits, working and other similar interests
and contractual arrangements customary in the oil and natural gas industry,
liens incident to operating agreements, liens relating to amounts owed to the
operator, liens for current taxes not yet due and other encumbrances. The
Company believes that such burdens neither materially detract from the value of
such properties nor from the respective interests therein, or materially
interfere with their use in the operation of the business.
OFFICE FACILITIES
The Company owns a 19,000 square foot office building located at 701 Cedar
Lake Boulevard, Oklahoma City, Oklahoma where it maintains its corporate
headquarters. In August 1994, the Company purchased approximately 1.5 acres
adjacent to its corporate headquarters for $216,000.
ITEM 3. LEGAL PROCEEDINGS
A petition was filed in Oklahoma County District Court on July 25, 1995,
against the Company and its directors by Bill V. Dean and Elliott Associates,
L.P. ("Elliott"). The suit purported to be a derivative action on behalf of the
Company against the Board of Directors for breach of fiduciary duties in
enacting a share rights plan, approving certain severance contracts and policy,
and proposing the Senior Note Offering. No damages are being sought against the
Company. The suit asks that the Company's share rights plan and severance
contracts and policy be invalidated, seeks an injunction against the Company's
Senior Note Offering and requests damages to the Company from the directors in
excess of $10,000. In August 1995, the Company elected to defer its proposed
Senior Note Offering. The Company filed a motion to dismiss which was granted
by the court in 1995 dismissing Elliott as plaintiff. The court granted Elliott
leave to file an amended petition. Elliott declined to file an amended petition
and is appealing its dismissal to the Oklahoma Court of Appeals. The Company
and its directors have filed their answer
11
14
denying all allegations. The suit is currently in discovery. The Company
believes the derivative action is without merit and will vigorously defend
against this action.
The Company and its subsidiaries are named defendants in lawsuits and are
involved from time to time in governmental proceedings, all arising in the
ordinary course of business. Although the outcome of these lawsuits and
proceedings cannot be predicted with certainty, management does not expect
these matters will have a material adverse effect on the financial position of
the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of the fiscal year.
12
15
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is traded on the NASDAQ National Market System
under the symbol "AEOK." The following table sets forth the high and low
closing sales price for each of the periods indicated as quoted by NASDAQ.
QUARTER ENDED HIGH LOW
------------- ------- ------
1994
March 31 ......................................... 5 7/8 4 7/8
June 30 .......................................... 5 1/4 4 3/8
September 30 ..................................... 5 1/2 4 1/2
December 31 ..................................... 6 7/8 4 1/2
1995
March 31 ........................................ 6 3/4 4 3/8
June 30 ......................................... 5 5/16 3 5/8
September 30 .................................... 5 4
December 31 ...................................... 4 5/8 3 3/8
1996
March 31 ........................................ 4 13/16 3 3/8
As of May 6, 1996, there were 1,939 stockholders of record.
DIVIDENDS
The Company has never paid cash dividends on its common stock and does not
expect to pay any cash dividends in the foreseeable future. It intends to
retain its earnings to provide funds for operations and expansion of its
business. Moreover, pursuant to the terms of certain of the Company's debt
agreements, the Company is prohibited from declaring or paying any cash
dividends on its common stock. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" and Note 4 of Notes to Consolidated Financial Statements of the
Company.
13
16
Well
- ----
Celsor 10-1
Celsor 10-2 0.03768520 0.02997890 0.02997890
Cimarron
Clinton 31-13 0.24129407 0.19147800
Clouse 5-2
17
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth selected historical financial data with
respect to the Company for each of the five years in the period ended December
31, 1995. The financial data set forth below should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Company's consolidated financial statements and notes
thereto of the Company.
Years ended December 31,
--------------------------------------------
1991 1992(1) 1993 1994(2) 1995
------- ------- ------ ------- -------
(in thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil and natural gas sales ........................ $8,942 $13,107 $17,708 $17,390 $16,599
Well operator and management fees ................ 2,116 2,663 2,668 2,615 2,642
Marketing fees, interest and other ............... 554 247 1,533 678 371
Total revenues ................................... 11,612 16,017 21,909 20,683 19,612
Costs and expenses:
Oil and natural gas operating expenses ........... 3,493 4,617 5,299 6,135 6,107
Amortization and depreciation .................... 3,557 4,583 5,762 7,246 9,252
Provision for impairment of oil and gas properties --- --- --- --- 2,300
General and administrative expenses .............. 2,779 3,241 3,879 4,034 3,442
Interest expense ................................. 2,388 3,029 2,063 2,396 3,961
Nonrecurring expenses (3) ........................ --- --- --- 3,166 752
Provision (credit) for income taxes ............... 275 5 2,331 --- (1,744)
Income (loss) before discontinued operations,
extraordinary items and cumulative effect
of change in accounting for income taxes ........ (880) 542 2,575 (2,294) (4,459)
Net income (loss) applicable to common stock (4) .. (1,006) (300) 2,453 (1,242) (4,459)
Income (loss) before discontinued operations,
extraordinary items and cumulative effect of
change in accounting for income taxes per
common and common equivalent share ............... (.22) .07 .25 (.19) (.36)
Net income (loss) per common and
common equivalent share .......................... (.22) (.06) .24 (.10) (.36)
December 31,
------------------------------------------------
1991 1992 1993 1994 1995
------- ------- -------- ------- -------
(in thousands)
BALANCE SHEET DATA:
Net properties and equipment ............ $43,639 $56,332 $66,504 $91,545 $84,156
Total assets ............................ 52,024 65,832 75,769 99,814 91,867
Current portion of long-term debt ....... 1,607 3,654 1,037 1,016 4,162
Long-term debt, net of current portion .. 23,034 24,194 16,764 46,514 44,354
Total stockholders' equity .............. 14,397 17,644 34,351 34,225 30,628
- ---------
(1) Includes the acquisition of Bradmar, which was consummated on March
18, 1992.
(2) Includes the JMC acquisition which occurred in November 1994. See
Note 2 of Notes to Consolidated Financial Statements.
(3) Includes $2.4 million and $734,000 in 1994 of costs related to the
merger with ANEC and costs to settle litigation against ANEC, respectively, as
discussed in Notes 2 and 10 of Notes to Consolidated Financial Statements.
Includes $300,000 and $452,000 in 1995 of abandoned merger costs and terminated
Senior Note Offering expenses, respectively, as discussed in Note 10 of Notes
to Consolidated Financial Statements.
(4) Includes (a) a loss from discontinued operations of $681,000 in 1992,
(b) a loss from an extraordinary item of $510,000, net of income taxes
associated with the early extinguishment of debt in 1993, and (c) a gain from
an extraordinary item of $1.1 million associated with the extinguishment of a
long-term obligation in 1994. Also includes the cumulative effect of adopting
SFAS 109, "Accounting For Income Taxes," the effect of which was to increase
net income by $425,000 in 1993. See Notes 1 and 12 of Notes to Consolidated
Financial Statements.
14
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
The Company follows the full cost method of accounting for its oil and
natural gas properties. Under such method, the net book value of such
properties, less related deferred income taxes, may not exceed a calculated
"ceiling." The ceiling is the estimated after-tax future net revenues from
proved oil and natural gas properties, discounted at 10% per annum plus the
lower of cost or fair market value of unproved properties. In calculating
future net revenues, prices and costs in effect at the time of the calculation
are held constant indefinitely, except for changes which are fixed and
determinable by existing contracts. The net book value is compared to the
ceiling on a quarterly basis. The excess, if any, of the net book value above
the ceiling is required to be written off as an expense. In the fourth quarter
of 1995, the Company recognized a writedown of its net book value of oil and
gas properties in excess of the ceiling of $2.3 million ($2.0 million, net of
the deferred tax credit). See Notes 1, 11 and 14 of Notes to Consolidated
Financial Statements. Under the Securities and Exchange Commission's full cost
accounting rules, any write-off recorded may not be reversed even though higher
oil and natural gas prices may increase the ceiling applicable to future
periods. There is no assurance that future oil and gas reserve volume or
product price decreases will not result in additional reductions in the net
book value of the oil and gas properties of the Company.
The Company records natural gas sales on the entitlement method,
recognizing only its net share of production as revenues. Any amount received
in excess of the Company's revenue interest is recorded as a natural gas
balancing liability and conversely any deficiency is recorded as a natural gas
balancing asset. The Company has also received non-interest bearing prepayments
on future natural gas production which provide for recoupment, most of which
are refundable upon the earlier of the end of the productive life of the
respective well or expiration of the natural gas purchase contract. The natural
gas prepayments will be recognized as revenue when, and if, the natural gas is
delivered.
Amortization of oil and natural gas properties is computed using a unit of
revenue method based on current gross revenues from production in relation to
estimated future gross revenues from production of proved oil and natural gas
reserves. The amortization rates for future periods will increase or decrease
corresponding with the fluctuations in oil and natural gas prices, reserve
volumes and production.
To manage its acquisition, exploitation and drilling activities, the
Company maintains a professional staff of geologists, engineers, landmen and
others. Although maintaining such staff increases general and administrative
expenses on an absolute basis, the Company's experienced technical staff has
been a key to its ability to generate sufficient drilling prospects and
exploitation opportunities to replace produced reserves. By managing operations
for a substantial number of its wells, the Company has been able to maintain
efficiencies in operations as well as obtain operator and management fees which
offset the majority of its general and administrative expenses.
RESULTS OF OPERATIONS
Total Revenues; Oil and Gas Sales. Total revenues decreased for 1995
compared to 1994. The decrease in total revenues was comprised of decreased oil
and natural gas sales, a slight increase in well operator reimbursements and
decreased other revenues. The decreased oil and natural gas sales are
attributable to lower oil production and a decrease in product price for
natural gas offset by increased oil prices and higher production volumes for
natural gas as a result of the wells drilled during 1994 and 1995 and the
producing gas properties acquired from the JMC Acquisition in November 1994.
Oil revenues decreased by 13% due to a 19% decrease in production
quantities partially offset by a 7% increase in the average price per Bbl of
production for the year ended December 31, 1995 as compared to 1994. Natural
gas revenues decreased by 2% due to a 13% decrease in the average price per Mcf
of natural gas produced for the year ended December 31, 1995 as compared to
1994, offset by a 13% increase in production quantities.
Total revenues decreased for 1994 compared to 1993. The decrease in total
revenues consisted of decreased oil and natural gas sales and a nonrecurring
item in other revenues in 1993 of approximately $1.25 million from the proceeds
of settlement of a lawsuit. The decrease in oil and natural gas sales was due
to lower product prices, partially offset by higher production volumes of
natural gas attributable to wells drilled in 1994.
Oil revenues decreased by 28% due to a 21% decrease in production
quantities and an 9% decrease in the average price per Bbl of production for
the year ended December 31, 1994 as compared to 1993. Natural gas revenues
increased by 8% due to a 27% increase in production quantities, offset by a 15%
decrease in the average price per Mcf of natural gas produced for the year
ended December 31, 1994 as compared to 1993.
15
19
Well Operator and Management Fees. Well operator and management fees
reflect a slight increase for the year ended December 31, 1995 compared to the
same period in 1994. This slight increase is attributable to the inclusion of
the JMC Acquisition operated properties for a full year in 1995, as the JMC
Acquisition closed in mid November 1994, offset by the sale of certain operated
properties in the latter half of 1995. Included in the 1995 management fees
were reimbursements of overhead expense of $10,000 per month from each of the
AEJH 1987 and AEJH 1989 Limited Partnerships.
Well operator and management fees remained fairly constant for the year
ended December 31, 1994 compared to the same period in 1993. Included in the
management fees were reimbursements of overhead expense of $10,000 per month
from each of the AEJH 1987 and AEJH 1989 Limited Partnerships and an average of
$4,750 per month for six months from the AEJH 1987-A Limited Partnership, which
ceased operations during mid 1994.
Marketing Fees, Interest and Other Revenues. The 19% increase in interest
and other revenue (excluding the gains from the Company's sale of other
property and equipment of approximately $130,000 and the finalization and
termination of a take-or-pay contract of approximately $235,000 in 1994) during
the year ended December 31, 1995 compared to 1994 resulted from additional
interest income on invested cash and increased marketing fees for both oil and
natural gas.
The increase in interest and other revenue (excluding the settlement of a
lawsuit of approximately $1.25 million in 1993) during the year December 31,
1994 compared to 1993 resulted from gains on the sale of real estate and the
settlement of a take-or-pay contract recorded as deferred revenue in 1993.
Oil and Gas Prices. Oil prices received by the Company increased 7% during
1995, resulting in an average price of $16.57 per Bbl compared to the average
price per Bbl of $15.44 for 1994. Revenues and operating results for future
periods will continue to be impacted by price fluctuations which are largely
influenced by market conditions and the quantity of the oil sold by OPEC.
During 1995, the Company experienced a decrease in natural gas prices. In
recent years, the Company has sold much of its natural gas under short-term
(typically month-to-month) contracts. Natural gas prices received by the
Company decreased 13% during 1995, resulting in an average price of $1.50 per
Mcf compared to an average price per Mcf of $1.73 for 1994. Future sales prices
will be dependent upon the future supply and demand of natural gas in the
market and the quantities of gas sold under short-term contracts as opposed to
quantities sold under long-term contracts, which currently command higher
prices. The Company does however, expect an increase in the price of natural
gas for the first quarter and possibly the second quarter of 1996 compared to
comparable periods in 1995.
Oil prices received by the Company decreased 9% during 1994, resulting in
an average price of $15.44 per Bbl compared to the average price per Bbl of
$16.99 for 1993. Average gas price received by the Company during 1994 was
$1.73 per Mcf, a decrease of 15% compared to an average gas price received in
1993 of $2.04 per Mcf.
Oil and Gas Production. Production and average prices received per Bbl and
Mcf for each of the last three years are as follows:
Years ended December 31,
-----------------------------------------
1993 1994 1995
--------- --------- ---------
Crude Oil:
Production (Bbls) ............ 283,190 224,230 181,022
Average price per Bbl ........ $16.99 $15.44 $16.57
Natural Gas:
Production (Mcf) ............. 6,332,015 8,050,688 9,067,588
Average price per Mcf ........ $2.04 $1.73 $1.50
Oil and natural gas production volumes for 1995 on an Mcf equivalent
(Mcfe) basis exceeded such volumes for the same period in 1994 by 8% and oil
and natural gas production volumes for 1994 on an Mcfe equivalent basis
exceeded such volumes for 1993 by 17%. These increases in production were from
participation in new wells drilled over the past three years through the
Company and the AEJH 1985 and AEJH 1989 Limited Partnerships, from
recompletions in the Cotton Valley properties in 1994 by the Company and from
production on properties acquired in the JMC Acquisition after closing in mid
November 1994. Although the Company experienced some curtailments of gas
production, these curtailments have not been material. The curtailments were
primarily attributable to excess supply and price competitiveness with oil.
There can be no assurance that the Company will not experience future
curtailments.
16
20
Oil and natural gas production volumes for the year ended December 31,
1996 are expected to be lower than 1995. This expected decrease is primarily
attributable to a decrease in development activities in 1995 compared to such
activities in 1993 and 1994.
Total Expenses; Oil and Gas Operating Expenses. Total costs and expenses
increased for 1995 compared to 1994 due in part to nonrecurring expenses, an
increase in interest expense, depreciation and amortization expense and a
provision for impairment of oil and gas properties. Oil and gas operating
expenses remained fairly constant for 1995 compared to 1994. The Company
recognized additional operating expenses attributable to a greater number of
producing wells and workovers in the first half of 1995, offset by reduced
operating expenses attributable to the sale of certain producing properties
during the third quarter of 1995 and reduced remedial workovers performed
during the latter half of the year. Oil and gas operating expenses continue to
decrease on an Mcfe basis to $.60 for 1995, compared to $.65 per Mcfe for 1994
and $.66 per Mcfe for 1993.
Oil and gas operating expenses increased for 1994 compared to 1993, due to
additional operating expenses attributable to a greater number of producing
wells, which were drilled and completed during 1994 and the latter part of 1993
and due to workover costs performed on certain properties in 1994.
Amortization and Depreciation. The oil and gas property amortization and
depreciation rate per dollar of oil and gas sales for 1995 increased to $.55
compared to $.41 for 1994. The increased rate for 1995 was due principally to
the decreased estimated future gross revenues resulting from the decreased oil
and gas reserve volumes in 1995 as a result of downward revisions to previous
reserve estimates. The amortization and depreciation rates for future periods
will increase or decrease corresponding with the fluctuations in oil and gas
prices, reserve volumes and production.
The oil and gas property amortization and depreciation rate per dollar of
oil and gas sales for 1994 increased to $.41 compared to $.32 for 1993. The
increased rate for 1994 was due to the decreased estimated future gross
revenues resulting from lower product prices in 1994.
Impairment of Oil and Gas Properties. As of December 31, 1995, the
Company's net book value of oil and gas properties exceeded the ceiling
limitations prescribed under the full cost method of accounting for oil and gas
properties. Accordingly, a provision was recognized in the fourth quarter of
1995 of $2.3 million ($2.0 million, net of the deferred tax credit). The
provision for impairment is primarily attributable to declines in estimated
reserves due to downward revisions to reserve estimates (see Note 14 of Notes
to Consolidated Financial Statements).
General and Administrative Expenses. General and administrative expenses
decreased 15% for 1995 compared to 1994. This decrease was primarily related to
fewer personnel for 1995 compared to 1994, as 1994 included personnel and other
general and administrative expenses of ANEC, most of which were not retained
following the merger in July 1994. Well operator and management fees offset 77%
of general and administrative expenses during 1995 compared to 65% during 1994.
General and administrative expenses increased for 1994 compared to 1993.
This increase was primarily related to management bonuses and increased
personnel costs associated with the Company's growth. Well operator and
management fees offset 65% of general and administrative expenses during 1994
compared to 69% during 1993.
Interest Expense. Interest expense increased for 1995 compared to 1994 due
to the amount of outstanding borrowings for the twelve-month period ended
December 31, 1995, as compared to 1994 due principally to the JMC Acquisition,
which closed mid November 1994. At December 31, 1995, the Company's credit
facility bore interest at LIBOR plus 1.5% (a rate of 7.3125%). As discussed
under Liquidity and Capital Resources --- Long Term Debt; the Company's
outstanding borrowings under certain long-term debt agreements will bear
interest at rates higher than the 1995 rates due to modifications to such
agreements in May 1996.
Interest expense increased for 1994 compared to 1993 due to an increase in
the outstanding borrowings associated with property development and the JMC
Acquisition.
Nonrecurring Expenses. On May 10, 1995, the Company announced the
termination of discussions regarding the possible outstanding merger with
Abraxas and, accordingly, expensed $300,000 of related costs. In August 1995,
the Company postponed the Senior Note Offering and subsequent thereto expensed
$452,000 of related costs.
In connection with the merger between the Company and ANEC, the Company
incurred nonrecurring charges to operations in 1994 of $2.4 million. These
costs include legal, accounting, investment banking, printing and other costs.
Litigation Settlement. In the fourth quarter of 1994, in an effort to
resolve ANEC's litigation with various parties which had been ongoing since
1992, the Company acquired certain creditor claims against the operator of a
well in which
17
21
ANEC had an interest and agreed to mediation with the primary plaintiffs of the
outstanding litigation. Although management believed its actions against the
well operator were meritorious and believed the counterclaims of this party
were without merit, after having mediated this matter in December 1994,
management of the Company believe it was in the Company's best interest to
resolve such litigation and terminate the costs associated therewith.
Accordingly, in late December 1994, the Company agreed to a negotiated
settlement, the effect of which resulted in a charge to 1994 operations,
including legal fees, of approximately $734,000.
Taxes. As a result of the Company's and ANEC's secondary public offerings
in 1993, both entities had an ownership change pursuant to Section 382 of the
Internal Revenue Code. In 1995, the Company recorded a tax credit of $1.7
million on pretax loss of $6.2 million, an effective rate of 28%. This credit
was less than the combined statutory federal and state rates due to the
estimated timing of future taxable temporary differences and limitations on the
utilization of the company's net operating loss and statutory depletion
carryforwards as discussed below. In 1994, the Company's provision for income
taxes approximates statutory rates after considering permanent differences. In
1993, the Company sustained a nonrecurring non-cash charge to operations of
$1.2 million due to an increase in the valuation allowance associated with the
change in ownership in the first quarter of 1993 discussed above. The Company
also recorded a deferred tax provision of approximately $1.1 million on pretax
income of $4.9 million, representing an effective rate of 23%. The lower tax
rate for 1993 was primarily attributable to the reduction of a valuation
allowance previously established on pre-acquisition net operating loss
carryforwards of ANEC.
In February 1992, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 109, "Accounting for Income
Taxes" ("SFAS 109"). The Company adopted SFAS 109 on January 1, 1993. Among
other changes, SFAS 109 relaxed the recognition and measurement criteria for
deferred tax assets and alternative minimum tax from that provided for under
its previous method of accounting for income taxes under Statement of Financial
Accounting Standards No. 96 ("SFAS 96"). Adoption of this standard resulted in
the elimination of deferred income taxes payable of $425,000, related entirely
to alternative minimum tax, which is reflected in the 1993 statement of
operations as the cumulative effect of a change in accounting principle.
LIQUIDITY AND CAPITAL RESOURCES
General. The Company's capital requirements relate primarily to
exploitation, development, exploration and acquisition activities. In general,
because the Company's oil and gas reserves are depleted by production, the
success of its business strategy is dependent upon a continuous exploitation,
development, exploration and acquisition program.
Historically, the Company has funded its capital requirements through cash
flow from operations, bank borrowings, various carried interest arrangements
(whereby other parties paid a portion of the Company's share of costs) and
equity sales. The Company's capital resources available to fund capital
requirements consist primarily of cash flow from operations, not otherwise used
to retire outstanding long-term debt. As of March 1996, the Company has capital
expenditure commitments of approximately $1.6 million, which the Company
believes can be funded through cash flow from operations. The Company's capital
expenditure budget for 1996 is approximately $13 million, substantially all of
which represents the development of Company proved undeveloped locations.
Substantially all of the budget amount in excess of that expected to be
available from operations, after debt service, will have to be funded through
various financing alternatives, including equity sales, debt offerings, and/or
non-key property sales. Proceeds from the financing alternatives will have to
be sufficient in amount to also retire the Company's outstanding term note with
a bank, which has a balance at December 31, 1995 of $11.0 million. See Note 4
of Notes to Consolidated Financial Statements. The Company believes it has the
capability of executing such financing alternatives on a timely basis; however,
there are no assurances of that. The Company may defer budgeted expenditures to
future periods. Deferral of the budgeted capital expenditures may cause a delay
in the realization of undeveloped oil and gas reserves.
Cash Flows. In 1995, the Company's net cash provided by operating
activities was $3.4 million, compared to $1.5 million for the year ended
December 31, 1994. This increase was primarily attributable to the decrease in
nonrecurring and litigation expenses of $2.4 million, reduced general and
administrative expenses of $592,000, an increase of $1.1 million due to net
changes in operating assets and liabilities, partially offset by reduced oil
and gas sales of $791,000 and increased interest expense of $1.6 million. The
changes in operating assets and liabilities were primarily attributable to the
reduced oil and gas property development at December 31, 1995 compared with
1994 and events in 1994, explained below, which did not recur in 1995. At
December 31, 1995, the Company had a $3.5 million net gas balancing and gas
prepayment liability attributable to 2.5 Bcf of natural gas production in
excess of the Company's entitled natural gas volumes. The majority of the
excess sales are from properties that have gas balancing agreements which
provide for recoupments by the underproduced owners from 25% of volumes
attributable to the Company's interest. Additionally, most gas prepayments are
refundable upon the end of the productive life of the respective wells. At
December 31, 1995, approximately $1.6 million are classified as due within one
year.
18
22
Net cash used by investing activities in 1995 decreased by $28.1 million
to $4.2 million due primarily to reduced oil and gas property acquisitions and
development offset by reduced proceeds from property sales.
Net cash provided by financing activities in 1995 decreased by $28.9
million to $1.4 million due primarily to reduced long-term debt borrowings in
1995 compared to 1994.
In 1994, the Company's cash provided by operating activities was $1.5
million compared to $12.1 million for the year ended December 31, 1993. This
decrease was primarily attributable to $3.2 million of nonrecurring expenses
associated with the ANEC merger and the settlement of ANEC litigation, the
nonrecurrence of the 1993 $1.25 million gas contract settlement proceeds and
the net change in assets and liabilities resulting from operating activities of
$4.8 million. The $4.8 million net change in assets and liabilities resulting
from operating activities in 1994 is the result of reduced drilling activities,
the availability of additional borrowing capacity associated with the new
credit facility and the nonrecurrence of a natural gas prepayment agreement at
December 31, 1994, compared with December 31, 1993, all of which caused a
reduction in accounts payable, oil and gas proceeds due others and other
liabilities at December 31, 1994 compared with the related balances at December
31, 1993.
Net cash used by investing activities in 1994 increased approximately
$15.3 million to $32.3 million from $17.0 million in 1993. Additions to oil and
gas properties increased by approximately $18.1 million to $36.0 million due to
the JMC acquisition of $18.2 million and the continued redirection of
activities toward exploration and development of reserves after completing the
Secondary Public Offerings in 1993. The acquisition added 25 billion cubic feet
of natural gas reserves to the Company's asset base. The properties acquired
are located in the Arkoma Basin in Oklahoma and Arkansas. During 1994, the
Company also sold its interest in the MFS Properties for approximately $3.2
million which were acquired in 1990 for $3.0 million.
At December 31, 1995, the Company had a working capital deficit of $6.5
million and had no availability under its revolving line of credit. See
"General" above and "Long Term Debt" below.
Long Term Debt. At December 31, 1995, the Company had $44.0 million
outstanding under its revolving credit facility with a bank. Subsequent to
December 31, 1995, the lender reduced the borrowing base to $33.0 million,
effective to December 31, 1995, requiring the $11.0 million excess borrowings to
be converted to a term note. In May 1996, the Company amended the credit
agreement (the "Amended Agreement"). Under the Amended Agreement, the term note
requires, among other things, monthly payments of principal of $350,000 plus
interest, beginning effective April 1996, through its maturity date of April 1,
1997 at which time remaining unpaid principal and interest become due. The term
note will bear interest at the prime rate plus 3% (an aggregate rate of 11.25%
at March 31, 1996) through October 15, 1996 and the prime rate plus 4%
thereafter.
The borrowings associated with the revolving credit facility cannot exceed
the borrowing base, which relates to the Company's oil and gas reserve base. The
borrowing base is subject to semi annual redeterminations each April and October
until April 1, 1997, at which time the borrowing base is reduced quarterly by
1/16th through December 31, 2000. The revolving credit facility interest rate
(7.3125% at December 31, 1995) will also increase, under the Amended Agreement,
beginning effective April 1996. All of the borrowings outstanding with this
lender, under the Amended Agreement, are secured by a first and prior lien on
substantially all of the Company's assets.
In May 1996, the Company obtained a waiver from the lender for certain
events of noncompliance with the credit agreement. In connection with the
Amended Agreement, the lender also reduced the minimum requirements related to
certain financial covenants. The Company expects to be able to comply with the
amended financial requirements in future periods.
At December 31, 1995, the Company also had $3.0 million outstanding under a
term note with a stockholder which contains various financial covenants. In May
1996, the Company obtained a waiver through April 1, 1997 from the stockholder
for noncompliance with certain covenants. Under the waiver, the Company is
required to make its scheduled principal payment of $1.0 million in June 1996.
The Stockholder may, at its sole discretion, require the remaining $2 million of
unpaid principal and accumulated interest due anytime after April 1, 1997. The
Company also secured the stockholder loan on an equal basis with the bank debt
discussed above and agreed to liquidate and distribute the assets of the AEJH
1985, AEJH 1987 and AEJH 1989 Limited Partnerships. See Note 4 of Notes to
Consolidated Financial Statements.
Future Events. On January 2, 1996, the Company announced that it had signed
a letter of intent providing for a combination of National Energy Group, Inc.
("NEG") and the Company. Under terms of the letter of intent as extended, the
Company and NEG had until April 30, 1996 to complete their due diligence
investigations and attempt to reach a definitive agreement on the terms of a
transaction. On May 6, 1996 the Company announced that the Company and NEG had
not reached agreement on the terms of a definitive merger agreement by the April
30, 1996 standstill deadline; however, both companies are continuing to
negotiate. NEG is an independent oil and gas company with 1995 revenues of
approximately $7.9 million.
19
23
The Company has recently focused its current efforts on the due diligence
process. Accordingly, the development of proved undeveloped locations in 1996
may be temporarily delayed due to the above-mentioned factors; however the
Company believes it can accomplish this development program, subject to
obtaining financing on a timely basis, in the last half of 1996 after a
determination is made whether or not to pursue the combination. See "General"
above.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE
----
ALEXANDER ENERGY CORPORATION
REPORTS OF INDEPENDENT AUDITORS ....................... F-1
CONSOLIDATED BALANCE SHEETS ........................... F-3
CONSOLIDATED STATEMENTS OF OPERATIONS ................. F-4
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY ....... F-5
CONSOLIDATED STATEMENTS OF CASH FLOWS ................. F-6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ............ F-8
20
24
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Alexander Energy Corporation
We have audited the accompanying consolidated balance sheets of Alexander
Energy Corporation as of December 31, 1994 and 1995 and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the 1994 and 1995 financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of Alexander Energy Corporation at December 31, 1994 and 1995 and the
consolidated results of its operations and its cash flows for the years then
ended, in conformity with generally accepted accounting principles.
We previously audited and reported on the consolidated statements of
operations, stockholders' equity, and cash flows of Alexander Energy
Corporation for the year ended December 31, 1993, prior to the 1994 restatement
for the pooling of interests as described in Note 2. The contribution of
Alexander Energy Corporation to total revenues and net income represented 65%
and 50% of the respective restated totals. Financial statements of the other
pooled company included in the 1993 restated consolidated statements were
audited and reported on separately by other auditors. We also have audited, as
to combination only, the consolidated statements of operations, stockholders'
equity and cash flows for the year ended December 31, 1993 after restatement
for the 1994 pooling of interests; in our opinion, such 1993 consolidated
financial statements have been properly combined on the basis described in Note
2 to the consolidated financial statements.
As discussed in Note 1 to the consolidated financial statements, in 1993 the
Company changed its method of accounting for income taxes.
ERNST & YOUNG LLP
Oklahoma City, Oklahoma
March 30, 1996, except Notes 4 and 13
for which the date is May 10, 1996
F-1
25
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders
American Natural Energy Corporation
We have audited the consolidated balance sheet of American Natural Energy
Corporation and Subsidiaries as of December 31, 1993 (not included herein) and
the related consolidated statements of operations, stockholders' equity, and
cash flows for the year ended December 31, 1993. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audit.
We conducted our audit 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 assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of American Natural Energy Corporation and Subsidiaries as of December 31, 1993
and the consolidated results of their operations and their cash flows for the
year ended December 31, 1993, in conformity with generally accepted accounting
principles.
As discussed in Notes 2 and 4 of the Company's 1993 financial statements,
the Company changed its method of accounting for its oil and gas properties and
income taxes.
COOPERS & LYBRAND
Tulsa, Oklahoma
February 22, 1994
F-2
26
ALEXANDER ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1994 AND 1995
ASSETS (Note 4)
1994 1995
------------- -------------
Current assets:
Cash and cash equivalents ........................................... $ 792,752 $ 1,451,983
Accounts receivable:
Joint interest operations and other:
Limited partnerships and other related parties (Note 3) ........... 271,617 299,374
Others ............................................................ 1,877,781 602,265
Oil and gas sales .................................................. 3,252,954 3,291,252
Supply inventories, at lower of cost or market ...................... 306,653 370,057
Prepaid expenses and other .......................................... 145,102 158,032
------------- -------------
Total current assets ............................................ 6,646,859 6,172,963
Properties and equipment, at cost (Note 11):
Oil and gas properties, based on full cost accounting:
Properties subject to amortization ................................ 126,490,676 130,833,467
Unproved properties not being amortized ........................... 991,652 734,757
------------- -------------
127,482,328 131,568,224
Other properties and equipment ...................................... 2,392,986 2,450,669
------------- -------------
129,875,314 134,018,893
Less accumulated amortization, depreciation and impairment ........ 38,330,143 49,863,075
------------- -------------
Net properties and equipment .................................... 91,545,171 84,155,818
Notes receivable from related parties, gas balancing receivables,
deferred charges and other assets, at cost (Note 3) ................. 1,622,105 1,537,917
------------- -------------
$ 99,814,135 $ 91,866,698
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade .............................................................. $ 6,589,976 $ 2,723,334
Limited partnerships and other related parties (Note 3) ............ 181,492 29,316
Gas balancing, deferred revenue and oil and gas proceeds:
Limited partnerships (Note 3) ...................................... 765,150 592,094
Others ............................................................. 3,675,130 5,160,770
Long-term debt due within one year (Note 4):
Stockholder ......................................................... 1,000,000 1,000,000
Others .............................................................. 16,253 3,162,475
------------- -------------
Total current liabilities ....................................... 12,228,001 12,667,989
Long-term debt due after one year (Note 4):
Stockholder ......................................................... 3,000,000 2,000,000
Others .............................................................. 42,588,280 41,426,018
Non-recourse debt (Note 5) ........................................... 925,452 924,967
Gas balancing and other noncurrent liabilities ....................... 4,047,859 3,163,282
Deferred income taxes (Note 6) ....................................... 2,800,000 1,056,000
Commitments and contingencies (Note 7)
Stockholders' equity (Notes 2, 4 and 8):
Preferred stock - $.01 par value; 2,000,000 shares authorized;
none issued and outstanding ........................................ -- --
Common stock - $.03 par value; 20,000,000 and 50,000,000 shares
authorized in 1994 and 1995, respectively;
issued -- 12,271,563 in 1994 and 12,451,605 in 1995 ................ 368,147 373,548
Paid-in capital ..................................................... 39,405,383 40,262,808
Accumulated deficit ................................................. (5,548,987) (10,007,914)
------------- -------------
Total stockholders' equity ...................................... 34,224,543 30,628,442
------------- -------------
$ 99,814,135 $ 91,866,698
============= =============
See accompanying notes.
F-3
27
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Years ended December 31,
--------------------------------------------
1993 1994 1995
------------ ------------ ------------
Revenues:
Oil and gas sales (Note 9) ...................................... $ 17,707,809 $ 17,389,814 $ 16,599,191
Well operator and management fees:
Related parties (Note 3) ....................................... 532,816 361,488 308,045
Others ......................................................... 2,135,315 2,253,853 2,334,257
Marketing fees, interest and other (Notes 3 and 10) ............. 1,532,800 677,401 370,235
------------ ------------ ------------
Total revenues ............................................. 21,908,740 20,682,556 19,611,728
Costs and expenses:
Direct lifting costs (Note 3) ................................... 4,129,383 4,959,323 5,030,648
Gross production and severance tax .............................. 1,170,109 1,175,680 1,076,841
Amortization and depreciation (Note 11) ......................... 5,762,107 7,246,329 9,252,410
Provision for impairment of oil and gas properties (Note 11) .... -- -- 2,300,000
General and administrative (Note 3) ............................. 3,878,892 4,033,984 3,441,701
Interest expense:
Stockholder .................................................... 713,852 550,211 447,172
Others ......................................................... 1,348,809 1,845,285 3,513,571
Nonrecurring expenses (Notes 2 and 10) ......................... -- 2,432,002 752,312
Litigation settlement (Note 10) ................................. -- 733,964 --
------------ ------------ ------------
Total costs and expenses ................................... 17,003,152 22,976,778 25,814,655
------------ ------------ ------------
Income (loss) before provision (credit) for income taxes,
extraordinary items and cumulative
effect of change in accounting for income taxes ................. 4,905,588 (2,294,222) (6,202,927)
Provision (credit) for deferred income taxes (Note 6):
Deferred tax .................................................... 1,131,000 -- (1,744,000)
Nonrecurring change in ownership ................................ 1,200,000 -- --
------------ ------------ ------------
2,331,000 -- (1,744,000)
------------ ------------ ------------
Income (loss) before extraordinary items and cumulative
effect of change in accounting for income taxes ................. 2,574,588 (2,294,222) (4,458,927)
Extraordinary items (Note 12):
Gain on extinguishment of long-term obligation .................. -- 1,051,760 --
Loss on early extinguishment of debt, net of income
tax benefit of $298,000 ....................................... (510,000) -- --
------------ ------------ ------------
Income (loss) before cumulative effect of change in
accounting for income taxes ...................................... 2,064,588 (1,242,462) (4,458,927)
Cumulative effect of change in accounting for
income taxes (Note 1) ........................................... 425,000 -- --
------------ ------------ ------------
Net income (loss) ................................................ $ 2,489,588 $ (1,242,462) $ (4,458,927)
============ ============ ============
Net income (loss) applicable to common stock ..................... $ 2,452,931 $ (1,242,462) $ (4,458,927)
============ ============ ============
Weighted average common and common
equivalent shares outstanding ................................... 10,148,552 12,168,172 12,344,767
============ ============ ============
Net income (loss) per common and common equivalent share:
Income (loss) before extraordinary items and cumulative
effect of change in accounting for income taxes ................ $ .25 $ (.19) $ (.36)
Extraordinary items ............................................. (.05) .09 --
Cumulative effect of change in accounting for
income taxes ................................................... .04 -- --
------------ ------------ ------------
Net income (loss) ............................................... $ .24 $ (.10) $ (.36)
============ ============ ============
See accompanying notes.
F-4
28
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1993, 1994 AND 1995
Preferred Common Paid-in Accumulated Treasury
stock stock capital deficit stock Total
---------- -------- ------------ ------------ ------------ ------------
Balance at December 31, 1992 .. $ 360,735 $198,456 $ 24,253,971 $ (6,709,457) $ (460,116) $ 17,643,589
Common stock issued and
conversion of preferred
stock, net of issuance costs (1,000) 134,575 13,167,456 -- 460,116 13,761,147
Issuance of common stock for
royalty interest ............ -- 6,755 187,843 -- -- 194,598
Retirement of Series B
preferred stock ............. (359,735) -- (40,265) -- -- (400,000)
Issuance of warrants ......... -- -- 65,099 -- -- 65,099
Issuance of common stock in
connection with exercise of
warrants .................... -- 10,935 624,065 -- -- 635,000
Exercise of employee stock
options and issuance of stock
awards, net of unearned
compensation ................ -- 744 48,157 -- -- 48,901
Net income ................... -- -- -- 2,489,588 -- 2,489,588
Dividends .................... -- -- -- (86,656) -- (86,656)
---------- -------- ------------ ------------ ------------ ------------
Balance at December 31, 1993 .. -- 351,465 38,306,326 (4,306,525) -- 34,351,266
Exercise of stock options and
issuance of stock awards, net
of unearned compensation .... -- 16,682 1,099,057 -- -- 1,115,739
Net loss ...................... -- -- -- (1,242,462) -- (1,242,462)
---------- -------- ------------ ------------ ------------ ------------
Balance at December 31, 1994 .. -- 368,147 39,405,383 (5,548,987) -- 34,224,543
Exercise of stock options and
vesting of stock awards, net
of unearned compensation .... -- 5,401 857,425 -- -- 862,826
Net loss ...................... -- -- -- (4,458,927) -- (4,458,927)
---------- -------- ------------ ------------ ------------ ------------
Balance at December 31, 1995 .. $ --- $373,548 $ 40,262,808 $(10,007,914) $ --- $ 30,628,442
========== ======== ============ ============ ============ ============
See accompanying notes.
F-5
29
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(CONTINUED ON NEXT PAGE)
Years ended December 31,
-------------------------------------------
1993 1994 1995
------------ ------------ -----------
Cash flows from operating activities:
Net income (loss) ............................................. $ 2,489,588 $ (1,242,462) $(4,458,927)
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Extraordinary loss (gain) before tax and after cash
payment ..................................................... 707,600 (1,131,100) --
Cumulative effect of change in accounting
for income taxes ............................................ (425,000) -- --
Amortization and depreciation ................................ 5,762,107 7,246,329 9,252,410
Provision for impairment of oil and gas properties ........... -- -- 2,300,000
Amortization of deferred compensation for stock awards ....... -- 68,615 405,744
Amortization of loan discount and issuance cost .............. 65,000 -- 97,381
Loss on disposal of other equipment .......................... 8,705 -- --
Accretion of imputed interest ................................ 361,534 220,500 149,500
Deferred income tax provision (credit) ....................... 2,033,000 -- (1,744,000)
Change in assets and liabilities as a result of operating
activities:
Decrease (increase) in accounts receivable .................. 395,167 (654,804) 1,196,268
Decrease (increase) in supply inventories,
prepaid expenses and other ................................. (251,243) 503,552 (76,334)
Increase (decrease) in accounts payable ..................... 1,478,546 (1,930,431) (4,018,818)
Increase (decrease) in gas balancing, natural gas
prepayments, oil and gas proceeds due others and
other noncurrent liabilities ............................... (560,211) (1,615,384) 278,507
------------ ------------ -----------
Net cash provided by operating activities ................ 12,064,793 1,464,815 3,381,731
Cash flows from investing activities:
Additions to oil and gas properties ........................... (17,940,203) (36,009,580) (5,880,605)
Additions to other properties and equipment ................... (351,001) (440,742) (74,683)
Change in deferred charges and other assets, net .............. 595,498 -- --
Proceeds from the sale of assets .............................. 694,007 4,163,219 1,792,231
------------ ------------ -----------
Net cash used by investing activities .................... (17,001,699) (32,287,103) (4,163,057)
F-6
30
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(CONTINUED)
Years ended December 31,
-------------------------------------------
1993 1994 1995
------------ ------------ -----------
Cash flows from financing activities:
Proceeds from long-term debt ............................ $ 18,488,572 $ 30,986,958 $ 2,000,000
Payments on long-term debt and for extinguishment of
long-term obligation ................................... (26,417,193) (2,358,639) (1,016,525)
Collection of stock subscription receivable ............. -- 645,000 --
Proceeds from sale of common, preferred stock and
treasury stock, net of offering costs .................. 13,761,246 -- --
Exercise of employee stock options ...................... 48,901 1,047,124 457,082
Payments to retire preferred stock ...................... (400,000) -- --
Payment of preferred stock dividend ..................... (136,656) -- --
------------ ------------ -----------
Net cash provided by financing activities ........... 5,344,870 30,320,443 1,440,557
------------ ------------ -----------
Net increase (decrease) in cash and cash equivalents
during the year ......................................... 407,964 (501,845) 659,231
Cash and cash equivalents at beginning of year ........... 886,633 1,294,597 792,752
------------ ------------ -----------
Cash and cash equivalents at end of year ................. $ 1,294,597 $ 792,752 $ 1,451,983
============ ============ ===========
SUPPLEMENTAL INFORMATION:
Interest paid amounted to $1,701,127, $2,174,996 and $4,037,025 for the
years ended December 31, 1993, 1994 and 1995, respectively.
See accompanying notes.
F-7
31
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation - The consolidated financial statements
include the accounts of Alexander Energy Corporation (the "Company"), its
wholly-owned subsidiaries which were merged with the Company on June 30, 1995
(Note 2), and the Company's proportionate share of the assets, liabilities,
revenues and costs and expenses of oil and gas limited partnerships in which
the Company acts as general partner.
Nature of operations - The Company's business activities include property
acquisitions and exploitation; geological and geophysical evaluation of
prospective acreage; selection, negotiation and purchase of oil and gas
prospects; participation in drilling exploratory and development wells; and
operation of producing oil and gas properties. The Company diversifies its
exploration efforts between oil and gas with particular emphasis in the Mid-
Continent region of the United States.
Oil and gas properties - The Company follows the full cost method of
accounting for oil and gas properties prescribed by the Securities and Exchange
Commission ("SEC"). Under the full cost method, all acquisition, exploration
and development costs are capitalized. The Company capitalizes internal costs
including: salaries and related fringe benefits of employees directly engaged
in the acquisition, exploration and development of oil and gas properties, as
well as other directly identifiable general and administrative costs associated
with such activities. Such capitalized internal costs were approximately
$885,000, $1,232,000, and $1,101,000, respectively, in each of the three years
in the period ended December 31, 1995.
The costs of unproved properties are excluded from costs to be amortized
pending a determination of the existence of proved reserves. Such unproved
properties are assessed periodically for impairment. The amount of impairment
is included in the costs to be amortized.
Under the full cost method, the net book value of oil and gas properties,
less related deferred income taxes, may not exceed a calculated "ceiling." The
ceiling is the estimated after-tax future net revenues from proved oil and gas
properties, discounted at 10% per annum plus the lower of cost or fair market
value of unproved properties. In calculating future net revenues, prices and
costs in effect at the time of the calculation are held constant indefinitely,
except for changes which are fixed and determinable by existing contracts. The
net book value is compared to the ceiling on a quarterly basis. The excess, if
any, of the net book value above the ceiling is required to be written off as
an expense. As described in Note 11, in 1995 the Company recognized a provision
for impairment of the carrying value of its oil and gas properties. Under the
SEC's full cost accounting rules, any write down recorded may not be reversed
even though higher oil and gas prices may increase the ceiling applicable to
future periods. There can be no assurance that future oil and gas reserve
volume or product price decreases will not result in additional reductions in
the net book value of the oil and gas properties.
Amortization and depreciation - Amortization of oil and gas properties is
computed using a unit of revenue method based on current gross revenues from
production in relation to estimated future gross revenues from production of
proved oil and gas reserves (Note 11).
Depreciation of other properties and equipment is computed on the
straight-line method over estimated useful lives of 3 to 40 years.
Capitalization of interest - Interest costs related to significant
exploratory oil and gas wells and unproved oil and gas leases not being
amortized are capitalized until such time as the properties are evaluated and
transferred to the full cost amortization base. For the years ended December
31, 1993, 1994 and 1995 total interest costs amounted to $2,077,890,
$2,423,496 and $3,995,743 with $15,229, $28,000 and $35,000 being capitalized,
respectively.
Income taxes - On January 1, 1993, the Company adopted Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes"
("SFAS 109"). Among other changes, SFAS 109 relaxed the recognition and
measurement criteria for deferred tax assets and alternative minimum tax from
that provided for under its previous method of accounting for income taxes
under SFAS No. 96. Adoption of this standard resulted in the
F-8
32
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
elimination of deferred income taxes payable of $425,000, related entirely to
alternative minimum tax, which is reflected in the 1993 statement of operations
as the cumulative effect of a change in accounting principle.
Under SFAS 109, deferred income taxes are provided on the tax effect of
presently existing temporary differences, net of operating loss carryforwards
and statutory depletion carryforwards. The tax effect is measured using the
enacted marginal tax rates and laws that will be in effect when the differences
and carryforwards are expected to reverse or be utilized.
Net income (loss) per common and common equivalent share - Net income
(loss) per common and common equivalent share is computed on the basis of
weighted average shares of common stock, stock options and warrants outstanding
during each period, as applicable.
Stock-based compensation - In October 1995, the Financial Accounting
Standards Board issued SFAS No. 123, "Accounting for Stock-Based Compensation,"
which establishes financial accounting and reporting standards for stock-based
employee compensation plans. Effective for fiscal years beginning after
December 15, 1995, the statement provides the option to continue under the
accounting provisions of APB Opinion 25, while requiring pro forma footnote
disclosures of the effects on net income and earnings per share, calculated as
if the new method had been implemented. The Company will adopt the financial
reporting provisions of SFAS 123 for 1996, but expects to elect to continue
under the accounting provisions of APB Opinion 25.
Gas balancing and natural gas prepayments - The Company records gas sales
on the entitlement method, recognizing only its net share of all production as
revenues. Any amount received in excess of the Company's revenue interest is
recorded as a gas balancing liability and, conversely, amounts not received for
the Company's entitled interest in gas produced are accrued as a gas balancing
receivable (collectively referred to as "net gas balancing liability"). The
Company has also received non-interest bearing prepayments on future natural
gas production which provide for recoupment, most of which are refundable upon
the earlier of the end of the productive life of each well or expiration of the
gas purchase contract. The natural gas prepayments will be recognized as
revenue when, and if, the gas is delivered. The portion of the net gas
balancing and natural gas prepayment liabilities that may be contractually
recouped during the next fiscal year is recorded as due within one year in the
accompanying balance sheets. As of December 31, 1994 and 1995 the Company has
net gas balancing and natural gas prepayment liabilities aggregating $3,457,000
and $3,528,000, respectively, of which $785,000 and $1,604,000 are classified
as due within one year.
Cash equivalents - Temporary investments with a maturity at the date of
acquisition of 90 days or less are considered to be cash equivalents.
Credit and market risk - The Company conducts the majority of its
operations in the states of Oklahoma, Texas and Arkansas and operates
exclusively in the oil and natural gas industry. The Company's joint interest
and oil and gas sales receivables are generally unsecured; however, the Company
has not experienced any significant losses in prior years and is not aware of
any significant uncollectible accounts at December 31, 1995.
Fair value of financial statements - Cash and cash equivalents, accounts
receivable, accounts payable and revenues payable are estimated to have a fair
value approximating the carrying amount due to the short maturity of these
instruments.
Due to the uncertainty of the timing of recoupment for net gas balancing
liabilities and gas prepayments management is unable to determine the fair
value of such instruments, however, based upon current product pricing and
expected reserve depletion management believes that the fair value is not
materially different than the carrying value.
The fair value of the unsecured revolving credit facility is believed to
approximate its carrying value due to variable interest rates on the
instruments. Fair values for fixed-rate borrowing approximate carrying values
inasmuch as management believes that the rates and terms approximate such terms
that could be obtained under similar instruments.
F-9
33
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 amounts reported in the financial
statements and accompanying notes. Actual results could differ from those
estimates.
2. BUSINESS COMBINATIONS
On June 30, 1995, a certificate of merger was filed with the State of
Oklahoma merging its wholly-owned subsidiaries, American Natural Energy
Corporation ("ANEC"), Edwards & Leach Oil Company and Bradmar Petroleum
Corporation ("Bradmar") into the Company as the surviving corporation. The
merger had no effect on the consolidated financial position or on the
consolidated results of operations for the periods presented.
In July 1994, the Company acquired ANEC, an Oklahoma corporation based in
Tulsa, Oklahoma, in a merger (the "Merger") accounted for as a pooling of
interests. Accordingly, in 1994 the Merger was given retroactive effect and
the Company's financial statements for periods prior to the Merger represent
the combined financial statements of the previously separate entities adjusted
to conform ANEC's accounting policies to those used by the Company. ANEC became
a wholly owned subsidiary of the Company and each issued and outstanding share
of ANEC's common stock was converted into the right to receive 1.62 shares of
the Company's common stock. In addition, the Company assumed all outstanding
options granted under the stock option plans maintained by ANEC. As a result
of the 1994 transaction, the Company issued approximately 5.8 million shares of
Company common stock.
In connection with the Merger, the Company incurred nonrecurring charges
to operations in 1994 of $2.4 million related to the combination of the Company
and ANEC. These costs include legal, accounting, investment banking, printing
and other costs.
In November 1994, the Company acquired certain producing gas properties,
located principally in Oklahoma and Arkansas, from JMC Exploration, Inc. (the
"JMC Acquisition") for a net purchase price of approximately $18.2 million,
including the assumption of a net gas balancing liability of $320,000. The
operations of the JMC Acquisition have been included in the accompanying
statements of operations and cash flows beginning November 15, 1994.
The following unaudited pro forma combined data gives effect to the JMC
Acquisition as if such transaction had been consummated as of January 1, 1993
and 1994. The pro forma information is based on the historical financial
statements of the Company and the JMC Acquisition, giving effect to the
transaction under the purchase method of accounting. The unaudited pro forma
combined data are presented for illustrative purposes and are not necessarily
indicative of the actual results that would have occurred had the acquisition
been consummated as of January 1, 1993 or 1994, respectively, or of future
results of the combined operations. The data reflect adjustments for (1)
amortization and depreciation of the JMC Acquisition's oil and gas properties,
(2) incremental general and administrative expenses of the JMC Acquisition, (3)
incremental interest expense resulting from the borrowings on the Company's
credit facility used to fund the cash requirements of the acquisition, and (4)
certain other pro forma adjustments.
Years ended December 31,
------------------------
1993 1994
------- --------
(in thousands, except per share data)
Revenues ................................................................ $30,046 $25,295
Income (loss) before discontinued operations, extraordinary items and
cumulative effect of change in accounting .............................. 4,170 (1,741)
Net income (loss) ....................................................... 4,085 (689)
Net income (loss) per common share and common equivalent share .......... $.40 $(.06)
3. TRANSACTIONS WITH RELATED PARTIES
In June 1988, the Chief Executive Officer purchased 200,000 shares of the
Company's treasury stock for a sum aggregating $322,500. In connection with
this transaction the Company advanced the Chief Executive Officer $77,500
F-10
34
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
bearing interest at 10% repayable in 10 annual installments. The remaining
balance of this advance aggregated $52,801 at December 31, 1993. In November
1994, the Board of Directors approved a resolution to forgive the outstanding
receivable from the Chief Executive Officer and also refund the principle and
interest previously paid to the Company, resulting in an aggregate charge to
1994 operations of approximately $190,000.
The Company has interests in three limited partnerships engaged in oil and
gas activities. The Company acts as general partner of these partnerships and
arranges for the exploration, development and subsequent operations of the
partnerships' properties. In return, the Company is entitled to receive
management fees, reimbursement for administrative overhead and share in the
partnerships' revenues and costs and expenses according to the respective
partnership agreements.
During June 1993, the Company acquired the limited partner's interest in
an oil and gas partnership for which the Company served as the general partner.
The purchase price of this acquisition was $1,350,000 and was accounted for
under the purchase method of accounting. The results of the acquisition is
included in the results of operations of the Company since the date of the
acquisition.
During the year ended December 31, 1993 and the eight months ended August
31, 1994, the Company sold approximately 20% and 16%, respectively, of its oil
production through an entity (IEM, Ltd.) in which the Company owned a limited
partner interest recorded on the equity method (Note 9). Net distributable
income of IEM, Ltd. was allocated 60% to the limited partners and 40% to the
general partner. For the year ended December 31, 1993 and the eight months
ended August 31, 1994, the Company received 100% of the amount allocable to the
limited partners. Effective August 31, 1994, the Company terminated its
marketing arrangement with IEM and thus, withdrew as a limited partner. As a
result, the Company's equity interests in IEM's operating profit or loss ceased
as of August 31, 1994. The Company received the highest posted price for all
such production, an indirect marketing fee from the ultimate purchaser and a
percentage of operating profit of IEM, if any. In 1993 and the eight-month
period ended August 31, 1994, the Company recorded pass-through marketing fees
of $96,000 each period and operating profits (losses) of $1,500 and $(9,700),
respectively. At December 31, 1994, the Company had an undistributed net
operating profit receivable associated with this interest of approximately
$84,000 (none in 1995).
The Company also purchases certain well operating chemicals and stimulants
from another entity in which the Company owns a limited partner interest. In
1993, 1994 and 1995 oil and gas operating expenses and property development
costs include approximately $521,000, $726,000 and $465,000, respectively,
related to purchases from this related party.
As a requirement of the 1992 acquisition of Bradmar, the Company entered
into consulting/non-compete agreements with two former officers and directors
of Bradmar, one of which presently serves on the board of directors of the
Company. The agreements required total payments of a minimum $1,320,000 to be
paid in monthly payments of $36,667 over a thirty-six-month period from the
date of the acquisition. During 1995, the Company paid the final installments
under these agreements in the amount of $91,624 ($440,000 in each of 1993 and
1994).
F-11
35
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. LONG-TERM DEBT
Long-term debt consists of:
December 31,
-------------------------
1994 1995
----------- -----------
Revolving credit facility (A) ....................................... $42,000,000 $33,000,000
Term note (A) ....................................................... -- 11,000,000
Notes to stockholder (B) ............................................ 4,000,000 3,000,000
Mortgage note payable, interest at 10.5%; principal and interest
due in monthly installments of $5,382, with the balance
due in December 1999; secured by real estate with a net
book value of $669,429 at December 31, 1995 ........................ 546,545 539,825
Other ............................................................... 57,988 48,668
----------- -----------
46,604,533 47,588,493
Less amounts due within one year .................................... 1,016,253 4,162,475
----------- -----------
Long-term debt due after one year ................................... $45,588,280 $43,426,018
=========== ===========
- -------------
(A) At December 31, 1995, the Company had $44 million outstanding under its
revolving credit facility with a bank. Subsequent to December 31, 1995,
the lender reduced the borrowing base to $33 million, effective to
December 31, 1995, requiring the $11 million excess borrowings to be
converted to a term note. In May 1996, the Company amended the credit
agreement (the "Amended Agreement"). Under the Amended Agreement, the term
note requires monthly payments of principal of $350,000 plus interest,
effective beginning April 1996, through its maturity date of April 1, 1997
at which time the unpaid principal and interest become due. The Company
will also be required to make a principal payment of $750,000 in May 1996
representing proceeds from the sale of oil and gas properties completed in
January 1996. The Amended Agreement further requires that monthly cash
flow from operations, as defined, in excess of $700,000 and proceeds from
the sale of assets, common or preferred stock, debt placements or capital
from any other source to be applied first against the outstanding balance
of the term note. The term note will bear interest at the prime rate plus
3% (an aggregate rate of 11.25% at March 31, 1996) through October 15,
1996 and the prime rate plus 4% thereafter. The borrowings associated with
the revolving credit facility cannot exceed the borrowing base, which
relates to the Company's oil and gas reserve base. The borrowing base is
subject to semiannual redeterminations each April and October until April
1, 1997, at which time the borrowing base is reduced quarterly by 1/16th
through December 31, 2000. In addition to the forgoing semiannual
redeterminations, the lender has the right, at its sole discretion, to
redetermine the borrowing base, subject to certain limitations, any time
until maturity. Under the Amended Agreement, the revolving credit facility
interest rate will also increase beginning effective April 1996. Under the
revolving credit facility, the Company has the ability to choose the index
the interest rate is based on and can fix the rate for a term of up to six
months. At December 31, 1995, the Company had elected to use the one-month
London Interbank Offering Rate ("LIBOR") plus 1.5 % (an aggregate rate of
7.3125%), which will increase under the Amendment to LIBOR plus 2%.
The Amended Agreement requires, among other things, that the company
maintain minimum amounts of tangible net worth, a specified interest
coverage and current ratio, and places limitations on investments,
additional indebtedness, capital expenditures, mergers and liquidations,
consolidations, acquisitions, amounts of gas balancing liabilities and
payment of dividends. In May 1996, the Company obtained a waiver from the
lender for events of noncompliance. Also, in connection with the Amended
Agreement, the lender reduced the minimum requirements related to the
interest coverage and current ratio covenants, as defined, from 4 : 1 and
1 : 1 to 2.65 : 1 and .5 : 1, respectively, through April 1, 1997. The
Company expects to be able to comply with the amended financial
requirements in future periods. All of the borrowings outstanding with
this lender, under the Amended Agreement, are secured by a first and prior
lien on substantially all of the Company's assets.
(B) In June 1988, the Company entered into an agreement with a stockholder
whereby the Company issued 10% unsecured notes in the amount of
$5,000,000. This note agreement requires semiannual interest payments,
with
F-12
36
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
annual principal payments of $1,000,000 beginning in June 1994 and
continuing through 1998. This note agreement requires principal
prepayments if less than 50% of the Company's consolidated cash flow is
not expended on indebtedness, as defined, and capital expenditures. It
also limits the sale or disposition of subsidiaries, partnerships or joint
ventures, the sale of Company assets, the incurrence of additional
indebtedness, declarations of dividends and requires the Company to
maintain cash flow each fiscal year equal to the greater of a) 200% of the
aggregate consolidated principal payments during such fiscal year, b) 200%
of the aggregate consolidated principal payments during the next
succeeding fiscal year, or c) discounted future net revenues equal to 225%
of the aggregate consolidated debt (as defined).
In May 1996, the Company obtained a waiver from the stockholder
through April 1, 1997, for noncompliance with certain covenants existing
as of December 31, 1995. Under the waiver, the Company will be required to
make its previously scheduled principal payment of $1.0 million plus
interest in June 1996. The stockholder may at its sole discretion, require
the remaining $2 million of unpaid principal and accumulated interest due
anytime after April 1, 1997. The Company also secured the stockholder loan
on an equal basis with the bank debt discussed in (A) above and agreed to
liquidate and distribute the assets of the AEJH 1985, AEJH 1987 and AEJH
1989 Limited Partnerships.
As of December 31, 1995, long-term debt, which excludes the non-recourse
debt maturities discussed in Note 5, maturing during the subsequent five years
and thereafter is as follows (based on the Company's borrowing base and
outstanding borrowings at December 31, 1995 and waivers received from lenders):
1996 - $4,162,475; 1997 - $16,050,700; 1998 - $8,263,110; 1999 - $8,257,600;
2000 - $10,320,300 and thereafter - $534,308.
5. NON-RECOURSE DEBT
In 1989, AEJH 1989 Limited Partnership ("AEJH 1989"), for which the
Company serves as general partner, entered into an agreement with a stockholder
of the Company (and limited partner of AEJH 1989), whereby AEJH 1989 issued
secured 10 1/2% notes payable in the amount of $2,185,276 ($1,092,638 net to
the Company's interest at the date of issuance) to acquire leasehold interests
in a group of producing oil and gas properties. These notes require monthly
principal and interest payments equal to 80.75% of net proceeds, as defined,
from the producing oil and gas properties. The lender may recover the
outstanding balance on the notes only from proceeds from the oil and gas
properties of AEJH 1989.
Inasmuch as the future payments on these notes will be paid only from net
proceeds from these producing oil and gas properties, no amounts are included
in current portion of long-term debt in the accompanying balance sheets.
F-13
37
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. INCOME TAXES
A reconciliation of the Company's income tax provision (credit) and the
amount computed by applying the statutory federal income tax rate of 35% to
income (loss) before income taxes, extraordinary items and cumulative effect of
change in accounting is as follows:
Years ended December 31,
---------------------------------------
1993 1994 1995
----------- --------- -----------
Statutory rate applied to income (loss) before income
taxes, extraordinary items and cumulative effect of
change in accounting .................................... $ 1,717,000 $(803,000) $(2,171,000)
Increase (decrease) relating to:
Permanent differences, 1994 primarily related to
nondeductible merger costs ........................... -- 852,000 16,000
Statutory depletion ..................................... (79,000) (106,000) (75,000)
State income taxes, net of federal benefit .............. 112,000 -- (143,000)
Change in the valuation allowance on deferred tax
assets (2) ............................................ 641,000 57,000 635,000
Other ................................................... (60,000) -- (6,000)
----------- --------- -----------
Provision ( credit) for deferred income
taxes (1) ............................................. $ 2,331,000 $ --- $(1,744,000)
=========== ========= ===========
(1) Includes $2,121,000 and $210,000 in 1993 and ($1,589,000) and ($155,000)
in 1995 for federal and state income taxes, respectively.
(2) The 1993 change relates primarily to the nonrecurring change in ownership.
The 1995 change is due to the change in the estimated timing of future
taxable temporary differences and the utilization of net operating loss
and statutory depletion carryforwards as a result of the provision for
impairment of oil and gas properties (Note 11).
Deferred tax assets and liabilities consist of the following at December 31:
1994 1995
------------ ------------
Deferred tax liabilities:
Depreciation and intangible drilling costs deducted
for tax in excess of financial ........................ $ 12,564,000 $ 12,324,000
Deferred tax assets:
Oil and gas revenues recognized for tax
before financial ...................................... 723,000 836,000
Net operating loss carryforwards ....................... 10,859,000 12,429,000
Statutory depletion carryforwards ...................... 1,354,000 1,429,000
Investment tax credit carryforwards .................... 201,000 201,000
Other .................................................. 45,000 89,000
------------ ------------
13,182,000 14,984,000
Valuation allowances (1) ............................... (3,418,000) (3,716,000)
------------ ------------
Net deferred tax assets ................................ 9,764,000 11,268,000
------------ ------------
Net deferred tax liabilities ........................... $ 2,800,000 $ 1,056,000
============ ============
(1) The change in the valuation allowance primarily relates to the effect of
the provision for impairment of oil and gas properties as described above,
partially offset by the expiration of a net operating loss carryforward in
1995 which was included in the 1994 deferred tax assets and valuation
allowance.
F-14
38
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In connection with the Offering in March 1993 (Note 8), the Company had an
ownership change pursuant to Section 382 of the Internal Revenue Code. The
Company sustained a nonrecurring non-cash charge to operations of approximately
$1.2 million during the three months ended March 31, 1993 due to an increase in
the valuation allowance. The increase in the valuation allowance represents the
effects of the annual limitations on the utilization of net operating loss
carryforwards resulting from the change in ownership. In addition, ANEC had an
ownership change in September 1993 as a result of its 1993 offering, which
resulted in a limitation on the utilization of its net operating loss
carryforwards.
At December 31, 1995, the Company has federal income tax net operating
loss ("NOL") carryforwards of approximately $33.3 million which begin to expire
in 1996. For federal income tax purposes, the Company also has investment tax
credit and statutory depletion carryforwards of approximately $201,000
(expiring from 1996 through 2001) and $3.8 million, respectively. The actual
utilization of net operating loss and other carryforwards may differ from the
estimated usage of such tax assets for purposes of estimating the valuation
allowance. As a result, such changes could result in subsequent changes to the
valuation allowance and could have a material impact on the results of
operations and the Company's financial position. Quarterly, management of the
Company evaluates the realizability of its deferred tax assets by assessing the
need for additional valuation allowances.
7. COMMITMENTS AND CONTINGENCIES
In December 1994, the Company executed employment agreements, special
severance agreements and implemented a corporate separation policy for its
management, technical support staff and other employees, respectively, which
become effective upon a change in control of ownership, as defined. As of
December 31, 1995, severance benefits under such agreements, assuming a change
in control, would aggregate approximately $4.1 million. A provision for these
benefits will not be made until a change in control is probable. See Note 13.
A petition was filed in Oklahoma County District Court on July 25, 1995,
against the Company and its directors by Bill V. Dean and Elliott Associates,
L.P. ("Elliott"). The suit purported to be a derivative action on behalf of the
Company against the Board of Directors for breach of fiduciary duties in
enacting a share rights plan, approving certain severance contracts and policy,
and proposing the Senior Note Offering. No damages are being sought against the
Company. The suit asks that the Company's share rights plan and severance
contracts and policy be invalidated, seeks an injunction against the Company's
Senior Note Offering and requests damages to the Company from the directors in
excess of $10,000. In August 1995, the Company elected to defer its proposed
Senior Note Offering. The Company filed a motion to dismiss which was granted
by the court in 1995 dismissing Elliott as plaintiff. The court granted Elliott
leave to file an amended petition. Elliott declined to file an amended petition
and is appealing its dismissal to the Oklahoma Court of Appeals. The Company
and its directors have filed their answer denying all allegations. The suit is
currently in discovery. The Company believes the derivative action is without
merit and will vigorously defend against this action.
The Company is involved in various legal actions arising in the normal
course of business. In the opinion of management, the Company's liability, if
any, in these pending actions would not have a material effect on the Company's
financial position or the results of operations.
8. PREFERRED AND COMMON STOCK
In April 1990, stockholders authorized the Board of Directors of the
Company to issue up to 2,000,000 shares of $.01 par value preferred stock with
preferences, qualifications, limitations and designations as deemed
appropriate.
On May 30, 1990, the Company issued 100,000 shares of 5% Series A
cumulative convertible preferred stock, $.01 par value, to MWR Investments,
Inc., a wholly owned subsidiary of Midwest Capital Group, Inc., ("MWR") for
$1,000,000. The preferred stock was converted into common stock of the Company
in March 1993 at a conversion rate of 1 share of preferred for 3.33 shares of
common.
F-15
39
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 1993, dividends of $.50 per share ($60,273; $50,000 of which was in
arrears at December 31, 1992) and $.20 per share ($26,383) were paid on the
Company's Series A preferred stock and ANEC's Series B preferred stock,
respectively.
In December 1994, the Board of Directors authorized the Company to reserve
300,000 shares of Series A Junior Participating Preferred Stock in connection
with establishing a rights plan providing shareholders one right for each share
of common stock held. Each right entitles its holder to purchase 1/100 of a
share of Series A Junior Participating Preferred Stock for $25.00, subject to
adjustment. The rights become exercisable and separately transferable ten
business days after a) an announcement that a person has acquired or obtained
the right to acquire 20% or more of the common stock or b) commencement of a
tender offer that could result in a person owning 20% or more of the common
stock. See Note 7.
If any person becomes the beneficial owner of 20% or more of the Company's
common stock, each right not beneficially owned by that person entitles its
holder to purchase, in lieu of Series A Junior Participating Preferred Stock,
Company common stock with a value equal to twice the exercise price of the
right, subject to adjustment to prevent dilution. In the event of certain
merger or asset sale transactions with another party or transactions which
would increase the equity ownership of a shareholder who then owned 20% or more
of the Company, each right will entitle its holder to purchase a similar value
of the merging or acquiring party's common stock. The rights, which have no
voting power, expire on December 15, 2004. The rights may be redeemed for $.01
per right until ten business days after a person has acquired 20% or more of
the common stock.
On December 31, 1992, ANEC issued 133,333 shares of Series B preferred
stock and 30,000 shares of ANEC's common stock (48,600 shares of the Company's
common stock) for $400,000. In September 1993, ANEC redeemed such preferred
stock for $400,000 out of the proceeds of a secondary public offering of equity
securities.
In March 1993, the Company registered 2,990,000 shares of the Company's
common stock (the "Offering"), of which the Company and a stockholder sold
2,556,667 and 433,333 shares, respectively. In conjunction with the Offering,
the Company issued to the underwriters warrants to purchase 75,000 shares of
common stock. The warrants are exercisable beginning March 1994 at an exercise
price of $5.10 per share and expire in March 1998. The exercise price and the
number of shares of common stock for which the warrants are exercisable are
subject to adjustment upon the occurrence of certain dilutive events.
In September 1993, ANEC sold 1,100,000 shares of ANEC's common stock
(1,782,000 shares of the Company's common stock) and received $4 million, net
of underwriters commissions and costs of the offering (the "ANEC Offering"). In
connection with this offering, ANEC issued purchase warrants to purchase 97,500
shares of ANEC's common stock (157,950 shares of the Company's common stock) at
$5.70 per share ($3.52 for the Company's common stock), expiring in September
1998.
In April 1993, ANEC issued 139,000 shares of ANEC's common stock (225,180
shares of the Company's common stock) in connection with the acquisition of a
7.5% overriding royalty interest in ANEC's oil and gas properties in connection
with the early termination of a credit agreement.
Also in April 1993, ANEC issued warrants to purchase 260,000 shares of
ANEC's common stock (421,200 shares of the Company's common stock) at $3.00 per
share ($1.85 for the Company's common stock), expiring in April 1996, in
connection with the issuance of subordinated notes, retired in September 1993
with proceeds from the ANEC Offering. In December 1993, ANEC issued 225,000
shares of common stock (364,500 shares of the Company's common stock) upon the
exercise of a like number of warrants in exchange for a stock subscription
receivable of $645,000 which was collected in January 1994. The remaining
35,000 warrants at December 31, 1993 were exercised during 1994 for 56,700
shares of the Company's common stock.
The Company initially reserved 66,666 shares of its common stock for
issuance to directors and key employees under a nonqualified stock option plan
(which terminated in 1991, except for outstanding options at the date of
termination). The plan is administered by the Compensation Committee (the
"Committee") of the Board of Directors. The exercise period of the options was
determined by the Committee at the date of grant, provided the exercise period
F-16
40
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
is between one and ten years from the date of grant. These options provide for
accelerated vesting schedules upon a change in control, as defined (Note 13).
Information regarding the Company's nonqualified stock option plan is
summarized as follows:
Years ended December 31,
---------------------------
1993 1994 1995
------- ------ ------
Options outstanding at beginning of period ................. 14,660 9,245 7,413
Exercised .................................................. (250) -- (583)
Surrendered or forfeited ................................... (5,165) (1,832) (4,665)
------- ------ ------
Options outstanding at end of period ($1.50 to $1.65 per
share at December 31, 1995; all options are exercisable
at December 31, 1995) ..................................... 9,245 7,413 2,165
======= ====== ======
The Company also has reserved 133,333 shares (10,022 available for future
grants at December 31, 1995) of its common stock for issuance to directors and
key employees under an incentive stock option plan (the "Plan"). The Plan is
administered by the Committee and, with the exception of a time period under
which options can be issued, contains similar provisions to the nonqualified
stock option plan.
Years ended December 31,
-------------------------------
1993 1994 1995
-------- -------- -------
Options outstanding at beginning of period ............ 120,393 103,348 86,016
Exercised ............................................. (17,045) (7,333) (9,080)
Surrendered or forfeited .............................. -- (9,999) --
-------- -------- -------
Options outstanding at end of period
($1.50 to $4.125 per share at December 31, 1995;
all options are exercisable at December 31, 1995) .... 103,348 86,016 76,936
======== ======== =======
The Company also has reserved 250,000 (157,964 available for future grants
at December 31, 1995) shares of its common stock for issuance to directors and
key employees under a stock option plan approved at the 1993 annual
stockholders' meeting authorizing grants of both nonqualified and incentive
stock options (the "1993 Plan"). The 1993 Plan is administered by the Committee
and, with the exception of a time period under which options can be issued,
contains similar provisions to the nonqualified and incentive stock option
plans discussed above. During 1993, ANEC granted options for 51,000 shares
(exercise price of $3.25 per share) of its common stock under a plan similar to
the Company's 1993 Plan. As a result of the Merger, those options were
converted to options to acquire shares of the Company's common stock, under the
1993 Plan.
Years Ended December 31,
------------------------------
1993 1994 1995
------- -------- --------
Options outstanding at beginning of period ............... -- 121,920 116,660
Granted (1993 - $2.01 to $5.00 per share;
1994 - $4.625 per share 121,920) ........................ 121,920 35,000 --
Exercised ................................................ -- (3,316) (8,879)
Surrendered or forfeited ................................. -- (36,944) (27,940)
------- -------- --------
Options outstanding at end of period
($2.01 to $5.00 per share at December 31, 1995
41,096 options are exercisable at December 31, 1995) .... 121,920 116,660 79,841
======= ======== ========
F-17
41
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company also has reserved 500,000 shares of its common stock for
awards to directors and key employees under a restricted stock award plan
approved at the 1993 annual stockholders' meeting (the "Award Plan"). The Award
Plan is administered by the Committee. Stock is awarded, issued and held by an
escrow agent until such time as a vesting period, which period is determined by
the Committee, has been satisfied. Voting rights commence at the time of award.
In the fourth quarter of 1993 and 1994, the Company granted 7,500 and 100,000
shares, respectively, under the Award Plan (none in 1995). The market value, at
the award date, was $38,000 and $603,000, respectively, for the 1993 and 1994
awards. Unearned compensation ($113,000, net of forfeitures, at December 31,
1995) is being amortized over the three-year vesting period. Such amortization
amounted to $2,200, $69,000, and $406,000 in 1993, 1994 and 1995 respectively.
These awards provide for accelerated vesting schedules upon a change in
control, as defined (Note 13).
In 1993, ANEC issued options to purchase 51,000 shares of ANEC common
stock (82,620 shares of the Company's common stock) to three business advisors
at $3.00 per share, all of which were exercised during 1994.
In 1993, ANEC granted options to certain members of management to purchase
287,500 shares of ANEC's common stock (465,750 shares of the Company's common
stock), at prices ranging from $3.25 to $5.00 per share ($2.01 to $3.09 for the
Company's shares). These options provided for accelerated vesting schedules
upon change in control. In 1994, immediately prior to and in connection with
the Merger, options were exercised for 187,500 shares of ANEC common stock
(303,750 of the Company's common stock) at prices of $5.00 and $3.25 ($2.01 and
$3.09 for the Company's common stock). In 1995, the remaining options for
162,000 shares of the Company's common stock were exercised at a price of $2.01
(81,000 shares) and $3.09 (81,000 shares).
9. MAJOR PURCHASERS
The Company's oil and gas production is sold under contracts with various
purchasers (Note 3). Gas sales to two purchasers individually approximated 12%
and 13% of total oil and gas revenues for the years ended December 31, 1993 and
1994, respectively. Gas sales to one purchaser approximated 13% of total oil
and gas revenues for the year ended December 31, 1995.
10. OTHER REVENUES, LITIGATION SETTLEMENT, AND OTHER NONRECURRING EXPENSES
In May 1993, the Company settled a lawsuit over the prices received by
Bradmar under certain gas contracts. The Company included approximately $1.25
million of proceeds from the settlement in 1993 revenues.
In the fourth quarter of 1994, in an effort to resolve ANEC's litigation
with Unit Drilling Company ("Unit") and Midwest Energy Corporation ("MEC"), the
Company acquired Unit's claim against MEC and in late December, agreed to
mediation with MEC. On December 22, 1994, the Company agreed to a negotiated
settlement with MEC, the effect of which was a release of the Company's claim
against MEC, the exchange of certain interests in oil and gas properties and a
net payment to MEC of $625,000. The aggregate effect of this negotiated
settlement resulted in a charge to 1994 operations, including legal fees, of
approximately $734,000.
During 1995, the Company incurred aggregate costs of $752,000 related to a
proposed merger and a subsequent senior note offering. As a result of
terminating such merger and debt offering activities, the Company expensed such
costs.
11. AMORTIZATION AND IMPAIRMENT OF OIL AND GAS PROPERTIES
Oil and gas properties amortization expense, excluding impairment, per
dollar of oil and gas revenue for the years ended December 31, 1993, 1994 and
1995 was $.32, $.41 and $.55, respectively. Accumulated amortization and
impairment relating to oil and gas producing activities at December 31, 1994
and 1995 amounted to $37,374,264 and $48,804,474, respectively.
F-18
42
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the fourth quarter of 1995, the Company recorded approximately $660,000
of incremental amortization on oil and gas properties over that recorded in
each of the previous three quarters. The increase is attributable to the
downward revisions in oil and gas reserve estimates (Note 14).
As of December 31, 1995, the Company's net book value of oil and gas
properties exceeded the ceiling (Note 1). The ceiling has been reduced for the
effect of the oil and gas properties sold in January 1996 of approximately $1.9
million and the timing of development cost expenditures of approximately $1.1
million. Accordingly, a provision for impairment was recognized in the fourth
quarter of 1995 of $2.3 million ($2.0 million, net of the deferred tax
benefit). The provision for impairment is primarily attributable to declines in
estimated reserves due to downward revisions to reserve estimates as described
in Note 14 and is highly dependent upon the development of proved undeveloped
reserves consistent with the timing projected in the reserve studies and the
prevailing market prices of oil and gas at each measurement date. Also, see
Note 4.
12. EXTRAORDINARY ITEMS
During April 1993, ANEC terminated a lending agreement with Endowment
Energy Partners, L.P. and repaid the outstanding indebtedness. The action
resulted in an early extinguishment of debt and an extraordinary loss of
$510,000, net of applicable income taxes.
In November 1994, the Company settled a dispute with a stockholder to whom
the Company had issued unsecured notes payable and warrants (the "Stock
Purchase Warrants") to purchase 223,333 shares of the Company's common stock,
resulting in a gain of approximately $1.1 million. In anticipation of the
lender exercising the Stock Purchase Warrants and a related warrant put option,
the Company had accrued $2,231,100 as of December 31, 1993; however, the
Company alleged that the lender failed to exercise the Stock Purchase Warrants,
and failed to properly exercise its warrant put option. After litigating this
matter, through the Federal Court, the Company settled this dispute, resulting
in a $1.1 million reduction of the $2.2 million liability previously recorded
and cancellation of the Stock Purchase Warrants.
13. SUBSEQUENT EVENT
On January 2, 1996, the Company announced that it had signed a letter of
intent providing for a combination of National Energy Group, Inc. ("NEG") and
the Company. Under terms of the letter of intent as extended, the Company and
NEG had until April 30, 1996 to complete their due diligence investigations and
attempt to reach a definitive agreement on the terms of a transaction. On May
6, 1996, the Company announced that the Company and NEG had not reached
agreement on the terms of a definitive merger agreement by the April 30, 1996
standstill deadline; however, both companies are continuing to negotiate. NEG
is an independent oil and gas company with 1995 revenues of approximately $7.9
million.
14. SUPPLEMENTARY OIL AND GAS INFORMATION
FINANCIAL DATA
All of the oil and gas producing activities of the Company are located in
the United States and represent substantially all of the business activities of
the Company. The following costs include all such costs incurred during each
period, except for depreciation and amortization of costs capitalized:
F-19
43
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COSTS INCURRED IN OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES:
Years ended December 31,
--------------------------------------
1993 1994 1995
----------- ----------- ----------
Acquisition of properties:
Proved (2) .................. $3,971,549 $19,303,678 $331,571
Unproved (1) ................ 493,886 647,269 416,392
----------- ----------- ----------
4,465,435 19,950,947 747,963
Exploration costs ............ 20,977 302,098 569,576
Development costs (2) ........ 11,244,307 12,014,693 2,770,835
----------- ----------- ----------
Total costs incurred ......... $15,730,719 $32,267,738 $4,088,374
=========== =========== ==========
- ---------
(1) Net of reimbursed costs and the excess of sales proceeds over cost of
properties transferred to the limited partnerships.
(2) Net of reimbursed costs and sales proceeds from properties sold.
CAPITALIZED COSTS:
December 31,
----------------------------------------------
1993 1994 1995
------------ ------------- -------------
Proved and unproved properties being amortized .... $ 94,599,583 $ 126,490,676 130,833,467
Unproved properties not being amortized ........... 615,007 991,652 734,757
Less accumulated amortization and impairment ...... (30,291,574) (37,374,264) (48,804,474)
------------ ------------- -------------
Net capitalized costs ............................. $ 64,923,016 $ 90,108,064 $ 82,763,750
============ ============= =============
UNPROVED PROPERTIES NOT BEING AMORTIZED:
December 31,
----------------------------------------------
1993 1994 1995
------------ ------------- -------------
Property acquisition costs ........................ $ 533,673 $ 882,318 $ 624,953
Capitalized interest .............................. 81,334 109,334 109,804
------------ ------------- -------------
$ 615,007 $ 991,652 $ 734,757
============ ============= =============
The costs of unproved properties not being amortized are related to
properties which are not individually significant and on which the evaluation
process has not been completed. When evaluated these costs will be transferred
to properties being amortized.
OIL AND GAS RESERVE DATA (UNAUDITED)
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES:
The estimates of proved reserves of the Company were estimated by
independent petroleum engineers, Netherland, Sewell and Associates, Inc. for
1995 and by independent petroleum engineers, Edinger Engineering Inc. for the
1993 and 1994 proved producing reserves, except as noted below for ANEC. Proved
nonproducing and proved undeveloped reserves for 1993 and 1994 were estimated
by Company petroleum engineers and the 1994 reserves were reviewed by Edinger
Engineering Inc., as specified in their letter dated March 29, 1995 except as
noted below for ANEC. This review should not be construed to be an audit as
defined by the Society of Petroleum Engineers' audit guidelines. The estimated
proved reserves of ANEC were determined by ANEC petroleum engineers for 1993
and are combined with the Company below.
F-20
44
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All studies have been prepared in accordance with regulations prescribed
by the SEC. Proved reserves cannot be measured exactly because the estimation
of reserves involves numerous judgmental and arbitrary determinations.
Accordingly, reserve estimates must be continually revised as a result of new
information obtained from drilling and production history or as a result of
changes in economic conditions. It is reasonably possible that significant
revisions of end of the period reserves could occur in the near-term based on
the new information. Additionally, the 1995 reserve study estimates for proved
nonproducing and proved undeveloped reserves are based upon approximately $22.5
million of future capital expenditures, estimated to be incurred primarily over
the next three years. The Company believes it has the capability of executing
such expenditures on a timely basis; however, there can be no assurances of
such. Should the actual timing of such expenditures differ from the projected
timing, the differences could result in subsequent revisions to the discounted
future net revenues associated with such reserves. The majority of the
Company's reserves are located in Arkansas, Oklahoma and onshore Texas.
Crude oil, condensate and
natural gas liquids (barrels) Natural gas (Mcf)
-------------------------------------- -------------------------------------------
Years ended December 31, Years ended December 31,
-------------------------------------- -------------------------------------------
1993 1994 1995 1993 1994 1995
---------- ---------- ---------- ------------ ------------ ------------
Proved developed and
undeveloped reserves:
Beginning of period ............ 3,967,994 3,939,915 3,931,981 101,510,640 121,920,500 145,202,568
Purchases of minerals-in-
place ......................... 371,201 43,344 20,657 4,142,156 28,610,484 359,755
Sales of
minerals-in-place ............. (47,759) (107,935) (373,568) (686,463) (6,293,000) (4,294,334)
Revisions of previous
estimates (A) ................. (262,482) (247,542) (1,167,618) (539,002) (13,971,181) (35,172,247)
Extensions, discoveries and
other additions ............... 194,151 528,429 77,542 23,825,184 22,986,453 2,042,021
Production ..................... (283,190) (224,230) (181,022) (6,332,015) (8,050,688) (9,067,588)
---------- ---------- ---------- ------------ ------------ ------------
End of period .................. 3,939,915 3,931,981 2,307,972 121,920,500 145,202,568 99,070,175
========== ========== ========== ============ ============ ============
(A) In 1994, the Company's oil and gas reserves were revised downwards as a
result of declines in product prices which shortened the economic lives of
the properties. Additionally, gas reserves associated with one field were
revised downward by approximately 13 Bcf based upon the performance
history of the field (which had previously been estimated using the
volumetric method and the limited production data available at that time).
Revisions to this field were somewhat offset by other upward revisions
made to certain producing Oklahoma properties based on the performance
history of those properties.
In 1995, approximately 31 Bcfe was reclassified from proved
undeveloped to probable and possible. The Company believes this is the
result of a more conservative application of engineering assumptions than
used previously. Additionally, in 1995 the Company experienced
approximately 11 Bcfe of additional downward reserve revisions. A
significant portion of these revisions relates to certain undeveloped
locations which the company now believes is being depleted through
existing proved producing properties, previously thought to be accessible
only through recompletions and/or additional development drilling.
F-21
45
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Crude oil, condensate and
natural gas liquids (barrels) Natural gas (Mcf)
--------------------------------- ------------------------------------
Years ended December 31, Years ended December 31,
--------------------------------- ------------------------------------
1993 1994 1995 1993 1994 1995
--------- --------- --------- ---------- ---------- ----------
Proved developed reserves:
Beginning of period ........... 1,819,924 1,797,023 1,754,840 47,289,039 65,068,990 86,085,662
========= ========= ========= ========== ========== ==========
End of period ................. 1,797,023 1,754,820 1,215,916 65,068,990 86,085,662 66,697,746
========= ========= ========= ========== ========== ==========
Reserves of wells which have performance history were estimated through
analysis of production trends and other appropriate performance relationships.
Where production and reservoir data was limited, the volumetric method was used
and it is more susceptible to subsequent revisions.
OIL AND GAS RESERVE DATA (UNAUDITED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:
Future net cash inflows are based on the future production of proved
reserves of crude oil, condensate, natural gas and natural gas liquids as
estimated by petroleum engineers by applying current prices of oil and gas
(with consideration of price changes only to the extent fixed and determinable
and with consideration of the timing of gas sales under existing contracts or
spot market sales) to estimated future production of proved reserves. Prices
used in determining future cash inflows for oil and natural gas for the periods
ended December 31, 1993, 1994 and 1995 were as follows: 1993 - $12.75, $2.20;
1994 - $16.25, $1.62; and 1995 - $18.40, $1.95, respectively. Future net cash
flows are then calculated by reducing such estimated cash inflows by the
estimated future expenditures (based on current costs) to be incurred in
developing and producing the proved reserves and by the estimated future income
taxes. Estimated future income taxes are computed by applying the appropriate
year-end tax rate to the future pretax net cash flows relating to the Company's
estimated proved oil and gas reserves. The estimated future income taxes give
effect to permanent differences and tax credits and allowances.
The standardized measure of discounted future net cash flows is based on
criteria established by Financial Accounting Standards Statement No. 69,
"Accounting for Oil and Gas Producing Activities" and is not intended to be a
"best estimate" of the fair value of the Company's oil and gas properties. For
this to be the case, forecasts of future economic conditions, varying price and
cost estimates, varying discount rates and consideration of other than proved
reserves (i.e., probable reserves) would have to be incorporated into the
valuations.
The following table sets forth the Company's estimated standardized
measure of discounted future net cash flows (in thousands):
Years ended December 31,
-----------------------------------
1993 1994 1995
--------- --------- ---------
Future cash inflows ............................... $ 318,762 $ 298,771 $ 236,825
Future development costs .......................... (35,797) (38,731) (22,528)
Future production costs ........................... (78,793) (70,993) (71,314)
Future income taxes ............................... (55,291) (38,127) (22,193)
--------- --------- ---------
Future net cash flows ............................. 148,881 150,920 120,790
10% annual discount ............................... (54,216) (52,027) (36,742)
--------- --------- ---------
Standardized measure of discounted future net
cash flows ....................................... $ 94,665 $ 98,893 $ 84,048
========= ========= =========
The standardized measure of estimated cash flows includes amounts related
to properties sold in January 1996. It also assumes development costs relating
to proved undeveloped reserves in 1996 of $11.6 million, substantially all of
which
F-22
46
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
will have to be funded from various financing alternatives. Proceeds from the
financing alternative will have to be sufficient in amount to also retire the
Company's outstanding term note with a bank. See Notes 4 and 11.
OIL AND GAS RESERVE DATA (UNAUDITED)
The following table sets forth changes in the standardized measure of
discounted future net cash flows as follows (in thousands):
Years ended December 31,
--------------------------------
1993 1994 1995
-------- -------- --------
Standardized measure of discounted future cash flows -
beginning of period ..................................... $ 84,879 $ 94,665 $ 98,893
Net changes in sales prices and production costs ......... 557 (21,775) 7,337
Sales of oil and gas produced, net of operating
expenses ................................................ (12,358) (11,255) (10,492)
Purchases of minerals-in-place (A) ....................... 5,445 20,414 400
Sales of minerals-in-place ............................... (523) (7,233) (3,626)
Revisions of previous quantity estimates ................. (675) (11,558) (38,157)
Extensions, discoveries and improved recovery, less
related costs ........................................... 20,169 15,119 2,394
Previously estimated development costs incurred during
the year and change in future development costs ......... 4,195 9,347 14,567
Accretion of discount .................................... 6,207 7,715 7,140
Net change in income taxes ............................... (8,987) 12,931 7,896
Other (B) ................................................ (4,244) (9,477) (2,304)
-------- -------- --------
Standardized measure of discounted future cash flows -
end of period ........................................... $ 94,665 $ 98,893 $ 84,048
======== ======== ========
(A) The purchases in 1994 consists primarily of the JMC Acquisition, which
includes proved developed and undeveloped reserves.
(B) The change included in the caption "Other" results principally from net
changes in the timing of production of oil and gas reserves and the change
in timing related to the development of proved undeveloped reserves.
F-23
47
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the identification, business experience and
directorships of each director and executive officer of the Company required by
Item 401 of Regulation S-K is presented in Part I, Item 1A, "Executive Officers
of the Registrant."
COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT OF 1934
Section 16(a) of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), requires the Company's directors, executive officers and
holders of more than 10% of the Company's common stock to file with the SEC
initial reports of ownership and reports of changes in ownership of common
stock and other equity securities of the Company. Such persons are required by
the SEC's regulations to furnish the Company with copies of all Section 16(a)
forms filed by such persons.
Based solely on the Company's review of such forms furnished to the
Company and written representations from certain reporting persons, the Company
believes that all filing requirements applicable to the Company's executive
officers, directors and more than 10% stockholders were complied with, except
for a statement of changes in beneficial ownership (Form 4) of Brian F. Egolf
to report a disposition of 3,607 shares that he sold in September 1995. A 1995
annual statement of changes in beneficial ownership (Form 5) was filed in
February 1996 on Mr. Egolf's behalf to report this disposition.
21
48
ITEM 11. EXECUTIVE COMPENSATION
The following information is set forth with respect to the total cash
compensation paid to the Company's five executive officers (including the
Company's chief executive officer) whose cash compensation exceeded $100,000
during each of the three years ending December 31, 1995, 1994 and 1993. None of
the other executive officers' cash compensations for all services rendered in
all capacities to the Company and its subsidiaries exceeded $100,000 during
1995, 1994 and 1993.
SUMMARY COMPENSATION TABLE
Long-Term Compensation
Awards
Annual Compensation (1) -------------------------------
------------------------------------------------------ Restricted
Other Annual Stock
Fiscal Salary Bonus Compensation Award(s) Options
Name and Principal Position Year ($)(2) ($)(3) ($) ($)(4) (#)
- ------------------------------ ------ ------- -------- ------------ ----------- ----------
Bob G. Alexander 1995 137,121 --- --- --- ---
President and Chief 1994 133,021 233,156(5) --- --- ---
Executive Officer 1993 122,424 69,553 --- --- ---
Jim L. David 1995 89,847 --- --- --- ---
Executive Vice President 1994 88,315 48,370 --- --- ---
1993 79,973 69,553 --- --- ---
David E. Grose 1995 79,778 --- --- --- ---
Vice President, Treasurer 1994 78,631 48,370 --- 189,250 4,000
and Chief Financial Officer 1993 71,308 69,553 --- 10,500 3,000
Roger G. Alexander 1995 78,708 --- --- --- ---
Vice President (Land) 1994 76,599 48,370 --- 189,250 4,000
1993 71,256 69,553 --- 10,500 3,000
James S. Wilson (6) 1995 79,383 --- --- --- ---
Vice President (Operations) 1994 76,881 48,370 --- 189,250 4,000
1993 71,308 69,553 --- 10,500 3,000
- ---------
(1) Excludes the aggregate, incremental cost to the Company of perquisites
and other personal benefits, securities or property, the aggregate amount
of which, with respect to the named individual, does not exceed the lesser
of $50,000 or 10% of reported annual salary and bonus for such person.
(2) Includes amounts paid by the Company which were deferred pursuant to
Section 401(k) of the Internal Revenue Code and accrued during the years
ended December 31, 1995, 1994 and 1993.
(3) The Company has a policy whereby bonuses may be awarded only if the
Company has replaced produced reserves in the previous year. In those
years in which this occurs, 10% of the difference between internally
generated cash flow and the estimated finding cost for reserve replacement
may be awarded to key employees managing key corporate functions. Bonuses
were awarded equally among five executive officers of the Company in 1994
and 1993. No bonuses were paid in 1995. Included in the amount of bonus
awarded for 1993, $9,853 was paid as discretionary performance bonuses
for successful completion of the Company's second public offering of
common stock.
(4) For 1994, the values of the grants are based on $4.625 and $6.00, the
closing sale prices of the Company's common stock at October 5 and
December 8, the respective dates of grants of 2,000 and 30,000 shares,
respectively, to each of Messrs. Roger Alexander and Grose. Value for
1993 is based on $5.25, the closing sale price at November 30, the date of
grant. Restricted stock awards of 32,000 shares in 1994 and 2,000 shares
in 1993 to each of Messrs. Roger Alexander and Grose were made pursuant to
the Company's 1993 Restricted Stock Plan. The restricted stock awards
will automatically vest over a three-year period, assuming continued
employment by the recipient, at a vesting rate of 50% after the first
anniversary, 75% after the second anniversary, and 100% vesting on the
third anniversary of the date of grant. At December 31, 1995, there were
held in escrow for each of Messrs. Roger Alexander and Grose 16,500
restricted shares with a value of $75,281.
22
49
(5) Includes $184,786 of debt forgiveness in the form of a one-time bonus. In
June 1988, Mr. Bob Alexander purchased 200,000 shares of the Company's
treasury stock for a sum aggregating $322,500. In connection with this
transaction, the Company advanced Mr. Bob Alexander $77,500 bearing
interest at 10% repayable in ten annual installments. In November 1994,
the Board of Directors approved a resolution to forgive the outstanding
receivable from Mr. Bob Alexander and to also refund the principle and
interest previously paid to the Company, resulting in an aggregate bonus
of $184,786.
(6) Mr. Wilson resigned his position with the Company on January 9, 1996.
Compensation of Directors. Through June 30, 1994, non-employee directors
of the Company were entitled to receive a fee of $500 for each meeting
attended. Effective July 1, 1994, non-employee directors receive a fee of
$2,000 for each meeting attended in person and $500 for each meeting attended
telephonically.
Option Exercises and Year End Option Values. The following information is
set forth with respect to each exercise of stock options during the year ended
December 31, 1995 by each of the Company's named executive officers, and the
year-end value of outstanding in-the-money options held by those executive
officers.
AGGREGATED OPTION EXERCISES FOR LAST FISCAL YEAR
AND YEAR-END OPTION VALUES
VALUE OF
NUMBER OF UNEXERCISED IN-THE-
UNEXERCISED MONEY OPTIONS AT
OPTIONS AT FISCAL FISCAL YEAR-END
YEAR-END (#) ($) (1)
SHARES
ACQUIRED ON VALUE EXERCISABLE/ EXERCISABLE/
NAME AND PRINCIPAL POSITION EXERCISE (#) REALIZED ($) UNEXERCISABLE UNEXERCISABLE
- --------------------------- ------------ ------------ ----------------- -------------------
Bob G. Alexander --- --- --- ---
Jim L. David --- --- --- ---
David E. Grose --- --- 33,665 / --- 63,567 / ---
Roger G. Alexander 3,333 896 5,833 / --- 29,638 / ---
James S. Wilson --- --- 20,665 / --- 34,300 / ---
- ------------
(1) Based on the closing sale price of the Company's common stock on December
31, 1995 of $4.5625.
Option Grants in Last Fiscal Year. There were no stock options granted
during the year ended December 31, 1995.
TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL ARRANGEMENTS
In December 1994, the Company executed employment agreements with its
executive officers. The employment agreements become effective only upon a
change in control or ownership. The agreements define "change in control" to
have occurred when (i) a person, entity or group acquires beneficial ownership
of (a) 30% or more of the outstanding shares of the common stock and the board
of directors deems the acquisition to be a change in control or (b) 40% or more
of the outstanding shares of common stock; (ii) either the directors who
constitute the Company's board of directors at the time of execution of the
employment agreements (the "Incumbent Board"), or the directors who are elected
by the Company's stockholders subsequent to execution of the employment
agreements and are approved by a majority of the Incumbent Board, cease to hold
at least a majority of the board of directors seats; or (iii) the stockholders
of the Company have approved a reorganization, share exchange, merger or
consolidation which results in the stockholders of the Company owning less than
50% of the combined voting power of the then outstanding voting securities, or
a liquidation or dissolution of the Company or the sale of all or substantially
all of the assets of the Company.
The employment agreements provide for an employment period ending on the
earlier to occur of (i) three years from the change in control or (ii) the
first day of the month next following the executive's attainment of age 65.
During such period, the executive is to receive a base salary at least equal to
the highest monthly base salary paid to the executive during the 36-month
period immediately preceding the month in which the change in control occurs.
In addition to base salary, the executive will be awarded for each fiscal year
an annual bonus in cash at least equal to the highest bonus paid by the Company
to the executive during the last five fiscal years immediately preceding the
fiscal year in which the change in control occurs. The Company estimates the
maximum severance obligation for management
23
50
employees to be $2.9 million, occurring only in the event that all five of the
executives that are parties to the agreements are terminated during the
three-year period subsequent to change in control of the Company. See ITEM 3.
LEGAL PROCEEDINGS.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table and notes thereto set forth, as of May 8, 1996, the
number of shares of common stock of the Company owned by those known by the
Company to own beneficially more than five percent (5%) of the outstanding
shares of the Company's common stock, as well as all shares beneficially owned
by each director, each named executive officer, and all directors and officers
of the Company as a group. Unless otherwise noted, the person named has sole
voting and investment power over the shares reflected opposite his name. The
Company has been provided such information by its directors and officers.
AMOUNT AND
NATURE OF
BENEFICIAL PERCENT
NAME OF BENEFICIAL OWNER OWNERSHIP OF CLASS
- ------------------------------------------------------- ------------- --------
Carl C. Icahn .................................... 1,193,000 (1) 9.57%
Elliott Associates, L.P. ......................... 1,136,843 (2) 9.12%
Bob G. Alexander** ............................... 294,584 (3) 2.36%
Jim L. David** ................................... 266,166 2.14%
David E. Grose** ................................. 81,915 (4) .66%
Roger G. Alexander** ............................. 73,448 (5) .59%
Robert A. West* .................................. 7,066 .06%
Brian F. Egolf* ................................. --- .00%
All Officers and Directors as a group (8 persons). 735,695 (6) 5.88%
- ---------
* Director
** Director and Officer
(1) Reflects ownership as reported on Schedule 13D by High River L.P., a
Delaware limited partnership, Riverdale Investors Corp., Inc., a Delaware
corporation, and Carl C. Icahn, an individual (collectively referred to as
"Carl Icahn"). Riverdale is the general partner of High River and Mr.
Icahn is the sole stockholder of Riverdale. The corporate address for Mr.
Icahn is 114 West 47th Street, 19th Floor, New York, NY 10036.
(2) Reflects ownership as reported on Schedule 13D of the number of shares of
common stock of the Company held by Elliott (together with its affiliates
Westgate International, L.P. and Martley International, Inc.). The
address for Elliott is 712 Fifth Avenue, New York, NY 10019.
(3) The amount shown owned by Mr. Alexander includes 83,882 shares owned by
Mr. Alexander's wife, Donna Ports Alexander. Mr. Alexander disclaims any
beneficial interest in the shares owned by his wife.
(4) Includes the right to acquire 37,915 shares pursuant to stock options
which are presently exercisable, but which have not been exercised and
16,500 shares awarded under the 1993 Restricted Stock Plan, subject to
forfeiture, for which he has sole voting power.
(5) Includes the right to acquire 10,083 shares pursuant to stock options
which are presently exercisable, but which have not been exercised and
16,500 shares awarded under the 1993 Restricted Stock Plan, subject to
forfeiture, for which he has sole voting power.
(6) Includes the right to acquire 55,205 shares pursuant to employee stock
options which are presently exercisable, but which have not been exercised
and 33,625 shares awarded under 1993 Restricted Stock Plan, subject to
forfeiture, for which the recipients have sole voting power.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In March 1992, the Company completed the acquisition of Bradmar. A
condition to closing the acquisition was that Petroleum Investments Securities
Corp. ("PISC") would enter into a consulting/noncompetitive agreement with the
Company. Brian F. Egolf, a non-employee director of the Company, is an
executive officer and director of PISC. Mr. Egolf was a principal stockholder,
executive officer and director of Bradmar prior to the acquisition. Since
consummation
24
51
of the acquisition on March 19, 1992, he has served as a director of the
Company. The Company has paid PISC an amount equal to $440,000 per year for a
period of three years in accordance with the consulting agreement. The
consulting agreement expired on March 18, 1995.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Annual Report on
Form 10-K.
1. Financial Statements. See Financial Statements and Supplementary
Data under Item 8 for a list of all financial statements filed
as a part of this report.
All schedules have been omitted since the schedules are either not
required or the required information is not present or is not
present in amounts sufficient to require submission of the
schedule, or because the information required is included in the
consolidated financial statements and notes thereto.
3. Exhibits.
Exhibit
Number Description
- ------- -----------
2(a) Letter of intent to merge dated December 29, 1995 between the Registrant
and National Energy Group, Inc., as amended.
3(a) Certificate of Incorporation of the Registrant, and amendments thereto,
has been previously filed as Exhibit 3(a) to Form 10-K for the fiscal year
ended December 31, 1991, and such certificate is incorporated herein by
reference.
3(b) Certificate of Amendment of Certificate of Incorporation of the
Registrant as filed with the Oklahoma Secretary of State on May 18, 1993,
has been previously filed as Exhibit 3(b) to Form 10-K for the fiscal year
ended December 31, 1993, and such certificate is incorporated herein by
reference.
3(c) Certificate of Designation of Series A Junior Participating Preferred
Stock of the Registrant as filed with the Oklahoma Secretary of State on
December 15, 1994, has been previously filed as Exhibit 4.1 to Form 8-K
dated December 15, 1994, and such certificate is incorporated herein by
reference.
3(d) Restated Bylaws of the Registrant, effective November 1, 1987, has been
previously filed as Exhibit 3(d) to Form 10-K for the fiscal year ended
December 31, 1994, and such bylaws are incorporated herein by reference.
4(a) Share Rights Agreement by and between the Registrant and Liberty Bank and
Trust Company of Oklahoma City, N.A. dated December 15, 1994, has been
previously filed as Exhibit 4.2 to Form 8-K dated December 15, 1994, and
such agreement is incorporated herein by reference.
4(b) Note Agreement between the Registrant and John Hancock Mutual Life
Insurance Company ("Hancock") dated June 1, 1988, has been previously
filed as Exhibit 4(b) to Form 10-K for the fiscal year ended December 31,
1994, and such agreement is incorporated herein by reference.
4(c) Waiver and Amendment to Note Agreement entered into effective April 15,
1996 by and between the Registrant and Hancock.
4(d) Agreement Regarding Liquidation and Winding Up of Certain Partnerships
entered into effective April 15, 1996 by and among the Registrant, Hancock
and Canadian Imperial Bank of Commerce ("CIBC").
4(e) Note Agreement dated as of April 25, 1989, by and among AEJH 1989 Limited
Partnership, the Registrant and John Hancock Mutual Life Insurance
(10 1/2% Senior Secured Notes) has been previously filed as Exhibit 4(c) to
Form 10-K for the fiscal year ended December 31, 1994, and such agreement
is incorporated herein by reference.
4(f) Consent of Hancock dated effective as of April 15, 1996.
25
52
10(a) Agreement and Plan of Merger by and among the Registrant, Alexander
Acquisition Company and American Natural Energy Corporation ("ANEC")
dated April 21, 1994, has previously been filed as Item 2 to Registration
Statement No. 33-78450 dated May 4, 1994, and such agreement is
incorporated herein by reference.
10(b) Amendment to Agreement and Plan of Merger by and among the Registrant,
Alexander Acquisition Company and ANEC dated June 10, 1994, has
previously been filed as Item 2.1 to Registration Statement No. 33-78450
dated June 14, 1994, and such amendment is incorporated herein by
reference.
10(c) Credit Agreement dated November 14, 1994 among the Registrant, certain
commercial lending institutions and CIBC, as Agent, has previously been
filed as Exhibit 10.1 to Form 8-K dated November 14, 1994, and such
agreement is incorporated herein by reference.
10(d) First Amendment to Credit Agreement dated as of July 14, 1995 by and
among the Registrant, various financial institutions as are or may become
parties to the Amendment and CIBC, as Agent.
10(e) Letter agreement dated November 20, 1995 among the Registrant, certain
commercial lending institutions and CIBC, as the Agent.
10(f) Second Amendment to Credit Agreement dated as of April 15, 1996 by and
among the Registrant, the various financial institutions as are or may
become parties thereto, and CIBC, acting through its New York Agency as
agent.
10(g) Secured Term Note of the Registrant in the principal amount of
$11,000,000 dated April 15, 1996 payable to CIBC.
10(h) Letter agreement dated April 29, 1996 regarding disposition of
hydrocarbons assigned by means of certain mortages, deeds of trust,
assignments, security agreements and financing statements.
10(i) Intercreditor Agreement dated as of April 15, 1996 by and among CIBC, as
agent for certain financial institutions as are or may become parties to
the Credit Agreement ("Lenders"), Hancock (together with its successors
and assigns), Barnett & Co., CIBC, as administrative agent for itself and
the Secured Persons, and CIBC Inc., a Delaware corporation, as collateral
agent for itself and the Secured Persons ("Collateral Agent").
10(j) Agreement and Consent entered into as of April 15, 1996 by and among the
Registrant, the Agent, the Lenders and the Collateral Agent.
10(k) Sale and Purchase Agreement dated September 26, 1994 by and among JMC
Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and the
Registrant has previously been filed as Exhibit 2.1 to Form 8-K dated
November 14, 1994, and such agreement is incorporated herein by
reference.
10(l) First Amendment to Sale and Purchase Agreement dated October 26, 1994 by
and among JMC Exploration, Inc., Ted Bowman, Chris Webb and John
Abrahamson and the Registrant has previously been filed as Exhibit 2.2 to
Form 8-K dated November 14, 1994, and such amendment is incorporated
herein by reference.
10(m) Alexander Energy Corporation 1986 Incentive Stock Option Plan, as
amended, has previously been filed as Exhibit 4.2 to Registration
Statement No. 33-20425 dated March 22, 1988, and such plan is
incorporated herein by reference.
10(n) Alexander Energy Corporation 1993 Stock Option Plan has previously been
filed as Exhibit A to the Registrant's Proxy Statement for the 1993
Annual Meeting of Stockholders, and such plan is incorporated herein by
reference.
10(o) 1993 Restricted Stock Award Plan for Alexander Energy Corporation and
It's Subsidiaries has previously been filed as Exhibit B to the
Registrant's Proxy Statement for the 1993 Annual Meeting of Stockholders,
and such plan is incorporated herein by reference.
10(p) Agreement of Limited Partnership of AEJH 1985 Limited Partnership by and
between the Registrant and John Hancock Mutual Life Insurance Company,
together with all amendments thereto, has previously been filed as
Exhibit 10(e) to Form 10-K for the fiscal year ended December 31, 1991,
and such agreement is incorporated herein by reference.
26
53
10(q) Agreement of Limited Partnership of AEJH 1987 Limited Partnership by and
between the Registrant and John Hancock Mutual Life Insurance Company,
together with all amendments thereto, has previously been filed as
Exhibit 10(g) to Form 10-K for the fiscal year ended December 31, 1991,
and such agreement is incorporated herein by reference.
10(r) Agreement of Limited Partnership of AEJH 1989 Limited Partnership by and
between the Registrant and John Hancock Mutual Life Insurance Company
dated April 25, 1989 has previously been filed as Exhibit 10(l) to
Form 10-K for the fiscal year ended December 31, 1994, and such
agreement is incorporated herein by reference.
10(s) Limited Partnership Agreement of Energy and Environmental Services
Limited Partnership dated May 15, 1991 by and between Energy and
Environmental Services, Inc., as general partner, and Alexander Energy
Corporation and REP, Inc., as limited partners, has previously been filed
as Exhibit 10(l) to Form 10-K for the fiscal year ended December 31,
1991, and such agreement is incorporated herein by reference.
10(t) Alexander Energy Corporation 1981 Non-Qualified Stock Option Plan has
previously been filed as Exhibit 10(w) to Registration Statement No.
33-45182 dated January 24, 1992, and such plan is incorporated herein by
reference.
10(u) Consulting Agreement dated March 19, 1992 between the Registrant and
Petroleum Investment Securities Corp. has previously been filed as
Exhibit 10(t) to Form 10-K for the fiscal year ended December 31, 1993,
and such agreement is incorporated herein by reference.
10(v) Warrant Purchase Agreement among the Registrant, Hanifen, Imhoff Inc. and
The Principal/Eppler, Guerin & Turner, Inc. has previously been filed as
Exhibit 10(u) to Amendment No. 1 to Registration Statement No. 33-57142
dated February 26, 1993, and such agreement is incorporated herein by
reference.
10(w) Purchase Option agreement (warrants) between ANEC and Gaines, Berland,
Inc. dated September 14, 1993 has previously been filed as Exhibit 10(u)
to Form 10-K for the fiscal year ended December 31, 1994, and such
agreement is incorporated herein by reference.
10(x) Alexander Energy Corporation Management Incentive Plan effective January
1, 1991 has previously been filed as Exhibit 10(v) to Registration
Statement No. 33-57142 dated January 19, 1993, and such agreement is
incorporated herein by reference.
10(y) Form of Employment Agreement between the Registrant and the executive
officers of the Registrant has previously been filed as Exhibit 10(dd) to
Form 10-K for the fiscal year ended December 31, 1994, and such agreement
is incorporated herein by reference.
10(z) Form of Special Severance Agreement between the Registrant and the
technical support staff of the Registrant has previously been filed as
Exhibit 10(ee) to Form 10-K for the fiscal year ended December 31, 1994,
and such agreement is incorporated herein by reference.
10(aa) Separation Policy of the Registrant dated December 8, 1994 has
previously been filed as Exhibit 10(ff) to Form 10-K for the fiscal year
ended December 31, 1994, and such agreement is incorporated herein by
reference.
10(bb) Letter of May 8, 1996 by and among CIBC, as agent, CIBC Inc., as Lender
and as Collateral Agent, and the Registrant referencing that certain
Agreement and Consent dated April 15, 1996.
10(cc) Letter of May 7, 1996 referencing the Credit Agreement dated November 14,
1994, as amended, by and among the Registrant, the Lenders and CIBC, as
agent for the Lenders.
10(dd) Letter of May 10, 1996 referencing that certain Credit Agreement among
the Registrant, the Lenders and CIBC, as agent for the Lenders, dated as
of November 14, 1994, as amended.
11 Computation of Earnings (Loss) per share.
21 Subsidiaries of the Registrant
23(a) Consent of Ernst & Young LLP, Independent Auditors
23(b) Consent of Coopers & Lybrand L.L.P., Independent Accountants
27 Financial Data Schedules
(b) The Company filed no reports on Form 8-K during the quarter ended
December 31, 1995.
27
54
SIGNATURES
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 behalf of the undersigned, thereunto duly authorized.
ALEXANDER ENERGY CORPORATION
By /s/ BOB G. ALEXANDER
---------------------------
May 10, 1996 Bob G. Alexander
President
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.
Signature Title Date
------------------ --------------------------- -------------
/s/ BOB G. ALEXANDER Chief Executive Officer
----------------------- and Director
Bob G. Alexander
/s/ DAVID E. GROSE Chief Financial Officer,
----------------------- Controller and Director
David E. Grose
/s/ JIM L DAVID Officer and Director
-----------------------
Jim L. David
/s/ ROGER G. ALEXANDER Officer and Director May 10, 1996
----------------------
Roger G. Alexander
/s/ BRIAN F. EGOLF Director
---------------------
Brian F. Egolf
/s/ ROBERT A. WEST Director
---------------------
Robert A. West
28
55
INDEX TO EXHIBITS
TO FORM 10-K
Exhibit
No.
- -------
2(a) Letter of intent to merge dated December 29, 1995 between the
Registrant and National Energy Group, Inc., as amended.
3(a) Certificate of Incorporation of the Registrant, and amendments
thereto, has been previously filed as Exhibit 3(a) to Form 10-K for
the fiscal year ended December 31, 1991, and such certificate is
incorporated herein by reference.
3(b) Certificate of Amendment of Certificate of Incorporation of the
Registrant as filed with the Oklahoma Secretary of State on May 18,
1993, has been previously filed as Exhibit 3(b) to Form 10-K for the
fiscal year ended December 31, 1993, and such certificate is
incorporated herein by reference.
3(c) Certificate of Designation of Series A Junior Participating Preferred
Stock of the Registrant as filed with the Oklahoma Secretary of State
on December 15, 1994, has been previously filed as Exhibit 4.1 to Form
8-K dated December 15, 1994, and such certificate is incorporated
herein by reference.
3(d) Restated Bylaws of the Registrant, effective November 1, 1987, has
been previously filed as Exhibit 3(d) to Form 10-K for the fiscal year
ended December 31, 1994, and such bylaws are incorporated herein by
reference.
4(a) Share Rights Agreement by and between the Registrant and Liberty Bank
and Trust Company of Oklahoma City, N.A. dated December 15, 1994, has
been previously filed as Exhibit 4.2 to Form 8-K dated December 15,
1994, and such agreement is incorporated herein by reference.
4(b) Note Agreement between the Registrant and John Hancock Mutual Life
Insurance Company ("Hancock") dated June 1, 1988, has been previously
filed as Exhibit 4(b) to Form 10-K for the fiscal year ended December
31, 1994, and such agreement is incorporated herein by reference.
4(c) Waiver and Amendment to Note Agreement entered into effective April
15, 1996 by and between the Registrant and Hancock.
4(d) Agreement Regarding Liquidation and Winding Up of Certain Partnerships
entered into effective April 15, 1996 by and among the Registrant,
Hancock and Canadian Imperial Bank of Commerce ("CIBC").
4(e) Note Agreement dated as of April 25, 1989, by and among AEJH 1989
Limited Partnership, the Registrant and John Hancock Mutual Life
Insurance (10 1/2% Senior Secured Notes) has been previously filed as
Exhibit 4(c) to Form 10-K for the fiscal year ended December 31, 1994,
and such agreement is incorporated herein by reference.
4(f) Consent of Hancock dated effective as of April 15, 1996.
10(a) Agreement and Plan of Merger by and among the Registrant, Alexander
Acquisition Company and American Natural Energy Corporation ("ANEC")
dated April 21, 1994, has previously been filed as Item 2 to
Registration Statement No. 33-78450 dated May 4, 1994, and such
agreement is incorporated herein by reference.
10(b) Amendment to Agreement and Plan of Merger by and among the Registrant,
Alexander Acquisition Company and ANEC dated June 10, 1994, has
previously been filed as Item 2.1 to Registration Statement No.
33-78450 dated June 14, 1994, and such amendment is incorporated
herein by reference.
10(c) Credit Agreement dated November 14, 1994 among the Registrant, certain
commercial lending institutions and CIBC, as Agent, has previously
been filed as Exhibit 10.1 to Form 8-K dated November 14, 1994, and
such agreement is incorporated herein by reference.
2
56
10(d) First Amendment to Credit Agreement dated as of July 14, 1995 by and
among the Registrant, various financial institutions as are or may
become parties to the Amendment and CIBC, as Agent.
10(e) Letter agreement dated November 20, 1995 among the Registrant, certain
commercial lending institutions and CIBC, as the Agent.
10(f) Second Amendment to Credit Agreement dated as of April 15, 1996 by and
among the Registrant, the various financial institutions as are or may
become parties thereto, and CIBC, acting through its New York Agency
as agent.
10(g) Secured Term Note of the Registrant in the principal amount of
$11,000,000 dated April 15, 1996 payable to CIBC.
10(h) Letter agreement dated April 29, 1996 regarding disposition of
hydrocarbons assigned by means of certain mortgages, deeds of trust,
assignments, security agreements and financing statements.
10(i) Intercreditor Agreement dated as of April 15, 1996 by and among CIBC,
as agent for certain financial institutions as are or may become
parties to the Credit Agreement ("Lenders"), Hancock (together with
its successors and assigns), Barnett & Co., CIBC, as administrative
agent for itself and the Secured Persons, and CIBC Inc., a Delaware
corporation, as collateral agent for itself and the Secured Persons
("Collateral Agent").
10(j) Agreement and Consent entered into as of April 15, 1996 by and among
the Registrant, the Agent, the Lenders and the Collateral Agent.
10(k) Sale and Purchase Agreement dated September 26, 1994 by and among JMC
Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and the
Registrant has previously been filed as Exhibit 2.1 to Form 8-K dated
November 14, 1994, and such agreement is incorporated herein by
reference.
10(l) First Amendment to Sale and Purchase Agreement dated October 26, 1994
by and among JMC Exploration, Inc., Ted Bowman, Chris Webb and John
Abrahamson and the Registrant has previously been filed as Exhibit 2.2
to Form 8-K dated November 14, 1994, and such amendment is
incorporated herein by reference.
10(m) Alexander Energy Corporation 1986 Incentive Stock Option Plan, as
amended, has previously been filed as Exhibit 4.2 to Registration
Statement No. 33-20425 dated March 22, 1988, and such plan is
incorporated herein by reference.
10(n) Alexander Energy Corporation 1993 Stock Option Plan has previously
been filed as Exhibit A to the Registrant's Proxy Statement for the
1993 Annual Meeting of Stockholders, and such plan is incorporated
herein by reference.
10(o) 1993 Restricted Stock Award Plan for Alexander Energy Corporation and
It's Subsidiaries has previously been filed as Exhibit B to the
Registrant's Proxy Statement for the 1993 Annual Meeting of
Stockholders, and such plan is incorporated herein by reference.
10(p) Agreement of Limited Partnership of AEJH 1985 Limited Partnership by
and between the Registrant and John Hancock Mutual Life Insurance
Company, together with all amendments thereto, has previously been
filed as Exhibit 10(e) to Form 10-K for the fiscal year ended December
31, 1991, and such agreement is incorporated herein by reference.
3
57
10(q) Agreement of Limited Partnership of AEJH 1987 Limited Partnership by
and between the Registrant and John Hancock Mutual Life Insurance
Company, together with all amendments thereto, has previously been
filed as Exhibit 10(g) to Form 10-K for the fiscal year ended December
31, 1991, and such agreement is incorporated herein by reference.
10(r) Agreement of Limited Partnership of AEJH 1989 Limited Partnership by
and between the Registrant and John Hancock Mutual Life Insurance
Company dated April 25, 1989 has previously been filed as Exhibit
10(l) to Form 10-K for the fiscal year ended December 31, 1994, and
such agreement is incorporated herein by reference.
10(s) Limited Partnership Agreement of Energy and Environmental Services
Limited Partnership dated May 15, 1991 by and between Energy and
Environmental Services, Inc., as general partner, and Alexander Energy
Corporation and REP, Inc., as limited partners, has previously been
filed as Exhibit 10(l) to Form 10-K for the fiscal year ended December
31, 1991, and such agreement is incorporated herein by reference.
10(t) Alexander Energy Corporation 1981 Non-Qualified Stock Option Plan has
previously been filed as Exhibit 10(w) to Registration Statement No.
33-45182 dated January 24, 1992, and such plan is incorporated herein
by reference.
10(u) Consulting Agreement dated March 19, 1992 between the Registrant and
Petroleum Investment Securities Corp. has previously been filed as
Exhibit 10(t) to Form 10-K for the fiscal year ended December 31,
1993, and such agreement is incorporated herein by reference.
10(v) Warrant Purchase Agreement among the Registrant, Hanifen, Imhoff Inc.
and The Principal/Eppler, Guerin & Turner, Inc. has previously been
filed as Exhibit 10(u) to Amendment No. 1 to Registration Statement
No. 33- 57142 dated February 26, 1993, and such agreement is
incorporated herein by reference.
10(w) Purchase Option agreement (warrants) between ANEC and Gaines, Berland,
Inc. dated September 14, 1993 has previously been filed as Exhibit
10(u) to Form 10-K for the fiscal year ended December 31, 1994, and
such agreement is incorporated herein by reference.
10(x) Alexander Energy Corporation Management Incentive Plan effective
January 1, 1991 has previously been filed as Exhibit 10(v) to
Registration Statement No. 33-57142 dated January 19, 1993, and such
agreement is incorporated herein by reference.
10(y) Form of Employment Agreement between the Registrant and the executive
officers of the Registrant has previously been filed as Exhibit 10(dd)
to Form 10-K for the fiscal year ended December 31, 1994, and such
agreement is incorporated herein by reference.
10(z) Form of Special Severance Agreement between the Registrant and the
technical support staff of the Registrant has previously been filed as
Exhibit 10(ee) to Form 10-K for the fiscal year ended December 31,
1994, and such agreement is incorporated herein by reference.
10(aa) Separation Policy of the Registrant dated December 8, 1994 has
previously been filed as Exhibit 10(ff) to Form 10-K for the fiscal
year ended December 31, 1994, and such agreement is incorporated
herein by reference.
10(bb) Letter of May 8, 1996 by and among CIBC, as agent, CIBC Inc., as
Lender and as Collateral Agent, and the Registrant referencing that
certain Agreement and Consent dated April 15, 1996.
10(cc) Letter of May 7, 1996 referencing the Credit Agreement dated November
14, 1994, as amended, by and among the Registrant, the Lenders and
CIBC, as agent for the Lenders.
10(dd) Letter of May 10, 1996 referencing that certain Credit Agreement among
the Registrant, the Lenders and CIBC, as agent for the Lenders, dated
as of November 14, 1994, as amended.
11 Computation of Earnings (Loss) per share.
21 Subsidiaries of the Registrant
23(a) Consent of Ernst & Young LLP, Independent Auditors
23(b) Consent of Coopers & Lybrand L.L.P., Independent Accountants
27 Financial Data Schedules
4