SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the fiscal year ended December 31, 1996
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-19136 (Common Stock) and
333-9045(Senior Notes)
NATIONAL ENERGY GROUP, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 58-1922764
(State or other jurisdiction of (IRS Employer Identification No.)
incorporation or organization)
4925 Greenville Avenue, Suite 1400
Dallas, Texas 75206
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code) (214) 692-9211
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.01 par value
(Title of Class)
Securities registered pursuant to Securities Act of 1933:
Senior Notes, 10 3/4% due 2006
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein and will not be contained, to the
best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendments hereto to this Form 10-K. [X]
The aggregate market value of the shares of Common Stock held by
non-affiliates of the Registrant, as of March 25, 1997 (based upon the last
sales price of $3.6875 as reported by NASDAQ) was $101,743,147.
36,145,359 shares of the Registrant's common stock, $0.01 par value, were
outstanding on March 25, 1997.
The information required by Part III of this Report is incorporated by
reference from Registrant's definitive proxy statement for its 1997 Annual
Meeting of Stockholders (to be filed with the Commission not later than April
30, 1997).
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TABLE OF CONTENTS
PART I
Page
ITEMS 1 AND 2. BUSINESS AND PROPERTIES................................... 2
General........................................................ 2
Business Strategy.............................................. 2
Forward-Looking Statements..................................... 3
Recent Developments............................................ 4
Oil and Natural Gas Properties................................. 6
Principal Areas of Operation................................... 6
Development and Exploitation................................... 7
Exploration.................................................... 9
Oil and Natural Gas Production................................. 11
Productive Well Summary........................................ 11
Production Economics........................................... 12
Leasehold Acreage.............................................. 12
Drilling Activity.............................................. 13
Title to Oil and Natural Gas Properties........................ 13
Production and Sales Prices.................................... 13
Lease Interests................................................ 13
Control Over Production Activities............................. 14
Factors Beyond the Company's Control........................... 14
Markets and Customers.......................................... 14
Regulation..................................................... 14
Operational Hazards and Insurance.............................. 17
Competition.................................................... 17
Office Space and Other......................................... 17
Employees...................................................... 17
ITEM 3. LEGAL PROCEEDINGS.............................................. 17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............ 18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS............................................ 18
Market Information............................................. 18
Holders........................................................ 18
Dividends on Common Stock...................................... 18
ITEM 6. SELECTED FINANCIAL DATA........................................ 19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................ 21
Overview....................................................... 21
Results of Operations.......................................... 21
Pro Forma Results of Operations................................ 23
Liquidity and Capital Resources................................ 24
Changes in Prices and Inflation................................ 27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA .................... 27
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE....................................... 27
PART III
ITEM 10. DIRECTORS AND EXECUIVE OFFICERS OF THE REGISTRANT.............. 27
ITEM 11. EXECUTIVE COMPENSATION......................................... 28
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT..................................................... 28
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................. 28
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K.................................................... 28
Signatures..................................................... 35
1
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES.
General.
National Energy Group, Inc. (the "Company") was incorporated under the laws
of the State of Delaware on November 20, 1990. Effective June 11, 1991, Big
Piney Oil and Gas Company ("Big Piney") and VP Oil, Inc. ("VP") merged with and
into the Company. The principal executive offices of the Company are located at
4925 Greenville Avenue, Suite 1400, Dallas, Texas, 75206.
The Company is an independent energy company engaged in the acquisition,
exploitation, development, exploration and production of oil and natural gas.
Through the acquisition of oil and natural gas properties with significant
reserve and production enhancement potential, and the subsequent exploration,
exploitation and development of those properties, the Company has substantially
increased its reserves and geographically diversified its property holdings. In
its acquisitions of oil and natural gas properties, the Company targets major
producing basins in Texas, Oklahoma, Arkansas, Louisiana, Mississippi, Alabama,
and offshore in the Gulf of Mexico, and seeks to acquire reserves that are
balanced between oil and natural gas with a mix of both short and long reserve
lives. While continuing to pursue attractive acquisition opportunities, the
Company has increased its focus upon implementing a comprehensive exploitation
and development program for its existing properties. This program is designed to
enhance proved producing reserves and convert proved undeveloped reserves to
proved producing reserves through development drilling, workovers, recompletions
and other production enhancement activities. As a complement to these efforts,
the Company recently initiated an exploration program concentrating primarily on
onshore Gulf of Mexico prospects in Texas, Louisiana, Mississippi, and Alabama,
and offshore Gulf of Mexico prospects in shallow state waters in offshore Texas.
As a result of its acquisition, exploitation, development and exploration
activities, the Company has substantially increased its reserves, production and
cash flow since 1991. The Company's estimated net proved reserves and PV10% have
grown from 6.8 Bcfe and $6.1 million, respectively, at December 31, 1991, to
181.7 Bcfe (71% natural gas) and $291.7 million (62% proved developed),
respectively, at December 31, 1996 as determined from reserve reports prepared
by Netherland, Sewell & Associates, Inc. ("Netherland & Sewell"), independent
petroleum engineers. The Company's average net daily production has increased
from 1.2 Mmcfe for 1991 to 41.4 Mmcfe for the fourth quarter of 1996. As a
result of increases in reserves and production, the Company has increased cash
flow from operations from $0.3 million for 1991 to $11.8 million for 1996.
The Company estimates it has a backlog of approximately 206 development
opportunities (including recompletions, drilling locations and proposed
waterfloods) on its existing properties, which the Company believes will provide
at least a three-year inventory of development projects. The Company has
established an aggregate development and exploration capital budget for its
existing properties of approximately $57 million for 1997 consisting of
approximately $45 million for development and exploitation projects and
approximately $12 million for selective exploratory activities primarily on its
onshore Texas, Louisiana, Mississippi, Alabama and offshore Gulf of Mexico
properties. Actual amounts expended by the Company for development and
exploration activities will be dependent on a number of factors, including oil
and natural gas prices, seismic and drilling costs, future drilling results and
the availability of capital.
Business Strategy.
The Company strives to increase reserves, production and cash flow from
operations through a strategy of (i) focusing on development and exploitation
activities to maximize production and ultimate reserve recovery, (ii) acquiring
oil and natural gas properties with significant exploitation, development and/or
exploration potential, (iii) obtaining operational control of its properties,
(iv) maintaining a low operating cost structure, and (v) selectively exploring
and developing properties with significant reserve potential.
2
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Development and Exploitation. In 1994, 1995 and 1996, the Company
participated in the drilling of 9 gross (6.4 net) development wells, 25 gross
(21.3 net) development wells and 29 gross (25.8 net) development wells,
respectively. All but two of the development wells drilled since 1994 have been
commercially productive. The Company intends to intensify development and
exploitation of its existing properties through development drilling, workovers,
redrills, recompletions, and other production enhancement techniques to maximize
its production and reserves. As of December 31, 1996, the Company has identified
approximately 206 development opportunities (including recompletions and
drilling locations) on the Company's existing properties. The Company has a
development and exploitation capital expenditure budget of approximately $45
million for 1997, a major portion of which is targeted to develop proved
undeveloped reserves.
Property Acquisitions. Acquisitions of producing oil and gas properties
have contributed significantly to the Company's historical growth in reserves.
During the period from January 1, 1991 through December 31, 1996, the Company
has acquired, through fifteen transactions, 202.1 Bcfe of estimated net proved
reserves. While the Company expects to generate future growth in reserves and
production through its increased emphasis on development and exploratory
drilling, the Company will continue to seek to opportunistically acquire
properties that complement and enhance its inventory of development,
exploitation and exploration projects. Consistent with its historical
acquisition strategy, the Company expects to focus on purchases of
underdeveloped properties in its core areas of expertise either through
negotiated property acquisitions or acquisitions of companies with oil and
natural gas properties.
Operational Control. The Company generally prefers to operate and, except
for its exploratory prospects, to own a majority working interest in its oil and
natural gas properties. This operating philosophy enables the Company to control
the nature, timing and costs of exploration and development of its properties,
as well as the marketing of the resulting production. At December 31, 1996, the
Company operated 506 of the 833 producing wells in which it owns an interest.
Low Operating Cost Structure. The Company seeks to increase cash flow by
maintaining a low unit operating cost structure through its focus on increasing
production while limiting its field operating and corporate overhead expenses.
Through these efforts, the Company has reduced historical unit lease operating
expenses 40% from $0.70 per Mcfe in 1991 to $.42 per Mcfe during the year ended
December 31, 1996. During these same periods, the Company decreased historical
unit general and administrative expenses 58% from $0.80 per Mcfe to $.34 per
Mcfe.
Selective Exploration Program. To balance its relatively lower risk
development and exploitation activities, the Company expects that exploration
drilling will become a more important aspect of its business in the future. The
Company also seeks to reduce the risks normally associated with exploratory
drilling by (i) allocating only a portion of its capital expenditure budget to
exploration activities, (ii) limiting its working interests in exploratory
prospects through participation by industry partners, (iii) obtaining
operational control of its prospects, and (iv) utilizing advanced technologies,
including 3-D seismic surveys, where cost-effective. The Company's recently
initiated exploration program targets prospects with significant reserve
potential, focusing primarily on its inventory of exploratory prospects in
onshore Texas, Louisiana, Mississippi and Alabama and offshore Gulf of Mexico,
including the Mustang Island Properties and Bayou Sorrel Properties. To provide
additional expertise in prospect generation and analysis for its exploration
program and to control prospect generation costs, the Company has entered into
an agreement with Sandefer Oil and Gas, Inc. ("Sandefer") under which prospects
in Louisiana, Texas and Mississippi are generated exclusively for the Company's
consideration and Sandefer participates with the Company in the evaluation,
marketing and sale of such prospects (collectively, the "Sandefer Exploration
Venture"). The agreement with Sandefer also involves an arrangement with the two
geologists associated with Sandefer, who have substantial exploration experience
in the Gulf Coast region. The geologists have access to the extensive
engineering and licensed geological and geophysical data bases for Louisiana,
Texas and Mississippi owned or licensed by Sandefer.
Forward-Looking Statements.
All statements in this document concerning the Company other than purely
historical information (collectively "Forward-Looking Statements") reflect the
current expectations of management and are based on the Company's historical
operating trends, its proved reserve position as of December 31, 1996, and other
information currently available to management. These statements assume, among
other things, (i) that no significant changes will occur in the operating
environment for the Company's oil and gas properties, and (ii) that there will
be no material acquisitions or divestitures except as disclosed herein. The
Company cautions that the Forward-Looking Statements are subject to all the
3
<PAGE>
risks and uncertainties incident to the acquisition, development and marketing
of, and exploration for, oil and gas reserves. These risks include, but are not
limited to, commodity price risk, environmental risk, drilling risk, reserve and
operations and production risk. Many of these risks are described elsewhere
herein. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations". Moreover, the Company may make material acquisitions or
enter into financing transactions. None of these can be predicted with certainty
and, accordingly, are not taken into consideration in the Forward-Looking
Statements made herein. For all of the foregoing reasons, actual results may
vary materially from the Forward-Looking Statements and there is no assurance
that the assumptions used are necessarily the most likely.
Recent Developments.
In January 1996, the Company completed the acquisition of oil and natural
gas properties in offshore Nueces County, Texas, adjacent to the Company's
Mustang Island property, from C/A Limited, Chartex Petroleum Company and
Petrotex Engineering Company (the "CA Acquisition"). The acquisition included
interests in five wells, a pipeline and separation facility related to Mustang
Island. The consideration for this acquisition consisted of 140,857 shares of
the Company's Common Stock and $675,000 in cash.
In February 1996, the Company completed the acquisition of two oil and
natural gas wells on one offshore block, interests in five other offshore
blocks, and a related production platform and equipment in offshore Nueces
County, Texas, adjacent to the Company's Mustang Island property, from UMC
Petroleum Corporation (the "UMC Acquisition"). The Company paid UMC Petroleum
Corporation $1,500,000 in cash. The acquisition was funded primarily from
borrowings under a credit facility.
In April 1996, the Company was awarded exploration rights on 16 offshore
tracts (covering 7,765 acres) in the Mustang Island area in offshore Nueces
County, Texas through successful bids with the State of Texas ("Offshore Lease
Acquisition"). The Company paid $1,437,302 in cash for these rights and the
purchase was funded by borrowings under a credit facility and available cash.
On August 29, 1996, the Company completed the acquisition of Alexander
Energy Corporation ("Alexander") through a merger of Alexander with and into
National Energy Group of Oklahoma, Inc. ("NEG-OK"), a wholly-owned subsidiary of
the Company, (the "Merger"). Pursuant to the Merger (a) the separate corporate
existence of Alexander terminated, (b) each share of Alexander common stock, par
value $0.03 per share ("Alexander Common Stock"), together with certain rights
associated with the Alexander Common Stock outstanding immediately before the
Merger, were converted into 1.7 shares of the Company's common stock, par value
$0.01 per share ("Common Stock") and (c) all outstanding options and warrants to
purchase Alexander Common Stock were assumed by the Company and converted into
options and warrants to purchase Common Stock. In lieu of fractional shares,
Alexander shareholders otherwise entitled to receive fractional shares of Common
Stock were paid in cash an amount equal to $4.375 multiplied by the fraction of
a share of Common Stock to be received. On December 31, 1996, NEG-OK was merged
into and with the Company and its separate corporate existence ceased to exist.
On August 29, 1996, the Company also closed the sale of 100,000 shares of
its Convertible Preferred Stock, Series D, $1.00 par value per share ("Series
D"), the sale of 50,000 shares of its Convertible Preferred Stock, Series E,
$1.00 par value per share ("Series E"), and warrants to purchase 1,050,000
shares of Common Stock. See Note 6 of Notes to Financial Statements.
In September 1996, the Company completed the acquisition of oil and natural
gas properties located in the South Lake Boeuf Field, La Fourche, Parish,
Louisiana from Araxas Energy Corporation, Araxas SPV-1, Inc. and Araxas
Exploration, Inc. and O'Sullivan Oil and Gas Company (the "Lake Boeuf
Acquisition"). The consideration paid by the Company consisted of $1,500,000 in
cash and 1,758,460 shares of the Company's Common Stock. The cash portion of the
acquisition was funded from available cash.
In October 1996, the Company acquired certain leasehold interests located
in the East Bayou Sorrel Field, Iberville Parish, Louisiana from W&T Offshore,
Inc. (the "W&T Acquisition") The consideration paid by the Company consisted of
$3,300,000 in cash. The Company funded the acquisition with available cash.
In November 1996, the Company completed the acquisition of oil and natural
gas properties and related facilities located in the Bayou Sorrel Field,
Iberville Parish, Louisiana from Panaco, Inc. (the "Bayou Sorrel Acquisition").
The consideration paid by the Company consisted of $9,025,000 cash, 477,612
shares of the Company's Common Stock and conveyance of a 3% overriding royalty
interest in the property acquired, limited to production below 11,000 feet. The
cash portion of the acquisition was funded from available cash.
4
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Also, in November 1996, the Company completed the sale of $100 million
principal amount of 10 3/4% Senior Notes due 2006 (the "Senior Notes"). In 1997,
the Senior Notes were exchanged for notes registered pursuant to the Securities
Act of 1933 ("Exchange Notes") which are substantially identical to the Senior
Notes.
In December 1996, the Company acquired certain oil and natural gas
properties located in the East Bayou Sorrel Field, Iberville Parish, Louisiana
from MCNIC Oil & Gas (the "MCNIC Acquisition"). The consideration paid by the
Company consisted of $7,000,000 in cash. The Company funded the acquisition from
available cash.
5
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Oil and Natural Gas Properties.
The estimated reserves and related future net revenues are based upon
reports prepared by independent petroleum engineers. For the years ended
December 31, 1995 and December 31, 1996 the reports were prepared by Netherland
& Sewell, and for the year ended December 31, 1994, the reports were prepared by
other independent petroleum engineers. All of the Company's reserves are located
in the continental United States. Each of the reserve reports were prepared
using constant prices and costs in accordance with the published guidelines of
the United States Securities & Exchange Commission ("SEC"). All of the Company's
reserves are pledged pursuant to the Company's credit facility.
The Company has not filed any estimates of proved oil and natural gas
reserves with any federal authority or agency other than with the SEC.
The net weighted average prices used in the Company's reserve reports at
December 31, 1994, 1995 and 1996 were $16.59, $18.71 and $25.36 per barrel of
oil, respectively, and $1.62, $1.91 and $3.72 per Mcf of natural gas,
respectively.
The following table sets forth certain information for the Company's total
proved oil and natural gas reserves and the PV10% of estimated future net
revenues from such reserves, at December 31, 1996, as prepared by Netherland &
Sewell. Also presented is the Standardized Measure of the Company's total proved
oil and natural gas reserves:
TOTAL PROVED RESERVES
As of December 31, 1996,
------------------------------------------------
Natural
Natural Gas
Oil Gas Equivalent PV 10%
(Mbbls) (Mmcf) (Mmcfe) (in
thousands)
----------- ----------- ----------- -----------
Proved developed reserves 4,384 77,497 103,801 $179,571
Proved undeveloped reserves 4,419 51,373 77,887 112,102
----------- ----------- ----------- -----------
Total proved reserves 8,803 128,870 181,688 $291,673
=========== =========== =========== ===========
Standardized Measure $229,780
===========
Principal Areas of Operations.
The following table sets forth for the Company's principal areas of operation,
the Company's proved oil and natural gas reserves and PV10% of the estimated
future net revenue from such reserves at December 31, 1996.
<TABLE>
<CAPTION>
Natural
Oil and Natural Gas % of
Consensate Gas Equivalent PV10% Total
Field (Mbbls) (Mmcf) (Mmcfe) (in thousands) PV10%
- -------------------------- -------------- ---------- ------------- ---------------- -----------
<S> <C> <C> <C> <C> <C>
Onshore:
Anadarko Basin, OK 2,270 58,547 72,168 $111,214 38.13%
Cotton Valley Trend, TX 244 35,239 36,701 50,666 17.37
Goldsmith Adobe Unit, TX 3,538 3,804 25,035 34,575 11.85
Lake Boeuf, LA 1,510 6,141 15,200 30,850 10.58
Arkoma Basin, OK and AR - 14,894 14,894 25,016 8.58
Bayou Sorrel, LA 573 1,848 5,288 13,899 4.77
Other Onshore 495 4,433 7,399 16,727 5.73
-------------- ---------- ------------- ---------------- -----------
Total Onshore 8,630 124,906 176,685 282,947 97.01
-------------- ---------- ------------- ---------------- -----------
Offshore:
Mustang Island 173 3,964 5,003 8,726 2.99
-------------- ---------- ------------- ---------------- -----------
Total 8,803 128,870 181,688 $291,673 100.00%
============== ========== ============= ================ ===========
</TABLE>
6
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Development and Exploitation.
While acquisitions historically have been the primary focus of the
Company's business strategy, recently the Company has accelerated the
development and exploitation of its existing properties. The Company develops
and exploits its properties by drilling development wells, including many on
infill locations, engaging in increased density and forced pooling drilling and
recompleting and reworking existing wells and, where appropriate, intends to
develop and implement secondary recovery plans, including waterfloods.
Anadarko Basin. Approximately 40% (72.2 Bcfe) of the Company's proved
reserves are located in the area of the Anadarko Basin in west central Oklahoma.
The Anadarko Basin is considered a mature natural gas producing area that is
characterized by multiple producing horizons and long reserve lives. Drilling a
producing well on these locations not only gives the Company the opportunity to
convert proved undeveloped reserves to proved developed producing reserves but
it also potentially provides additional proved undeveloped drilling locations on
the Company's leasehold acreage.
The Company's Anadarko properties generally are 640 acre producing units.
The Company was successful in demonstrating to Oklahoma regulators that wells in
the Anadarko Basin will not efficiently drain 640 acres and obtained
authorization for increased density drilling on smaller acreage producing units.
Under the forced pooling rules in Oklahoma, even if the Company is not the
operator of the property for which increased density drilling has been approved,
the Company may propose to drill and operate the wells, which may include
spacing for up to three additional wells. Frequently this results in the
proposing party owning a larger portion of the new wells due to other interest
owners declining to participate and occasionally results in such party becoming
the operator of the new wells proposed. The Company intends to continue an
increased density drilling strategy in the Anadarko Basin.
As of December 31, 1996, the Company had identified 34 PDNP and 55 PUD
locations in the Anadarko Basin with estimated proved reserves of 28.1 Bcfe.
These locations are well suited for relatively lower risk exploitation and
development activities that should significantly increase the Company's
production and cash flow from its Anadarko Basin properties in 1997. To develop
a portion of these locations, the Company has budgeted approximately $ 7.9
million to drill 23 gross (12.3 net) wells in the Anadarko Basin for the year
ending December 31, 1997. Wells in the Anadarko Basin are completed at depths
ranging from 2,000 to 25,000 feet, although the Company's wells typically are
completed between 7,000 and 15,000 feet in depth and cost approximately $1
million (gross) to drill and complete.
Cotton Valley Trend. Approximately 20% (36.7 Bcfe) of the Company's proved
reserves are located in the Cotton Valley Trend in Harrison and Rusk counties in
eastern Texas. The Cotton Valley producing formation is 1,500 to 2,000 feet
thick and is located at depths of 8,500 to 10,500 feet. These properties produce
from low permeability reservoirs with long life natural gas reserves.
In 1995 the Company initiated a major development program in the Cotton
Valley Trend. The Company has performed three recompletions, two workovers,
completed one well that had been drilled but not completed at time of the
purchase of the property and has successfully drilled and completed two
development wells, which initially averaged 1,500 Mcf per day. In addition, the
Company spudded four wells during the fourth quarter which were in various
stages of drilling and/or completion at year end 1996 and will be on production
at the end of the first quarter or the beginning of the second quarter of 1997.
Through these development activities combined with the Merger, average daily
production for the Cotton Valley properties has increased from approximately
3,400 Mcf per day in June 1995, when the Company acquired its first interest in
the area, to an average of 9,300 Mcf per day during December 1996.
The original development of the Cotton Valley Trend was based upon 640 acre
spacing, but production results have revealed that wells drilled on this spacing
are insufficient to adequately drain the reservoir due to the low permeability
of the sandstones. New studies show developing these tight sands on 80 acre
spacing is necessary to recover all commercially producible reserves in this
formation. The Cotton Valley Trend properties are now subject to revised field
rules established by the Texas Railroad Commission that permit drilling on 160
acre or, alternatively, on 80 acre spacing, without obtaining a special ruling
from the Texas Railroad Commission for each well. The Company has also been
successful in obtaining the Texas Railroad Commission's approval to indefinitely
suspend maximum production allowables.
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Due to incentives created to drill on certain leases of the Cotton Valley
Trend, production from some of the Company's Cotton Valley properties should
qualify for severance tax abatements.
As of December 31, 1996, the Company had identified 4 PDNP and 19 PUD
locations in the Cotton Valley Trend. The typical well in this area is expected
to cost approximately $1.1 million (gross) to drill and complete. A significant
portion of the cost to complete these wells is due to the low permeability of
the interbedded sandstones and shales, which requires massive hydraulic fracture
stimulation, typically of multiple zones of the producing formation, to fracture
the rock sufficient to obtain the increased production levels necessary to make
such wells commercially viable. The Company has budgeted approximately $14.9
million to drill 12 gross (12 net) development wells in the Cotton Valley Trend
for 1997. All of these wells will be drilled on PUD locations where the Company
owns in excess of 95% of the interests.
Goldsmith Adobe Unit ("GAU"). Approximately 14% (25.0 Bcfe) of the
Company's proved reserves are located in the Clearfork 5600 Reservoir, which is
in the middle of the Permian Basin located in West Texas. These reserves are in
the 7,880 acre Goldsmith Adobe Unit, which the Company operates and in which it
now owns approximately a 95% working interest.
Originally the unit was drilled on 40 acre spacing. Previous operators had
drilled several wells on 20 acre spacing and, based on the results of this
drilling and 20 acre spacing development on adjoining leases, the Company began
a drilling program in July 1994 to develop the unit on 20 acre spacing. The
Company drilled six wells during 1994, 22 wells during 1995 and 28 wells in
1996. Of the 56 wells the Company has drilled on the GAU, 53 are currently
producing. Through the Company's acquisition and exploitation activities,
average daily gross production from the GAU has increased from approximately 450
Boe in 1992 to 1,640 Boe during 1996.
The Company has budgeted approximately $7.6 million to drill an additional
29 gross (27.5 net) wells in the GAU in 1997. The typical well drilled by the
Company is drilled to depths between 5,600 and 6,000 feet and costs
approximately $265,000 (gross) to drill and complete. As of December 31, 1996,
the GAU had approximately 100 infill locations left if the unit were fully
developed on 20 acre spacing, of which 50 are included in the Company's
undeveloped proved reserve volumes as of December 31, 1996. Based on past
drilling results, as the Company continues to drill producing wells in the GAU,
the Company expects that additional reserves will be proved on a substantial
number of the remaining infill locations of the GAU.
Data gained from the drilling and coring of new wells in the GAU suggest
that the reservoir has significant secondary recovery potential from a
waterflood. Waterflooding is one method of secondary recovery in which water is
injected into an oil reservoir for the purpose of forcing oil out of the
reservoir rock and into the bore of a producing well. The Company anticipates
undertaking a waterflood project of the GAU in 1998 or 1999 from which it
expects to significantly increase its recovery rate of the reserves in the GAU.
It has started a pilot waterflood project in the area and currently is making
some of the necessary expenditures for the waterflood project by adding
injection pumps and lines.
Lake Boeuf. Approximately 8% (15.2 Bcfe) of the Company's proved reserves
are located in Lafourche Parish, Louisiana, which reserves were acquired by the
Company in September 1996. These reserves are principally proved undeveloped and
relate to nine different horizons ranging in depths from 9,500 to 15,000 feet,
estimated to contain approximately 1.5 Mmbbls of oil and 6.1 Bcf of natural gas.
The Company owns an approximate 87.5% working interest in the Lake Boeuf
properties.
The Company has identified two PDNP locations which it intends to
recomplete during 1997 for approximately $250,000. Additionally, three PUD
locations containing seven producing zones, have been identified for which the
Company has budgeted approximately $4.8 million to drill two gross (1.75 net)
wells as part of its 1997 capital expenditure program. The Lake Boeuf properties
are located in the parish adjacent to the Company's East Bayou Sorrel properties
in Iberville Parish on which it recently drilled an exploration well that
represents a new field discovery.
Arkoma Basin. Approximately 8% (14.9 Bcfe) of the Company's proved reserves
are located in the Arkoma Basin in eastern Oklahoma and western Arkansas, which
reserves were acquired by the Company as a result of the Merger with Alexander.
Most production comes from the Red Oak, Cromwell, Spiro and Wapanucka sands at
depths of 7,000 to 8,000 feet. Most of these channel sands follow structural
grain and are prolific natural gas producers when the natural gas is trapped by
faults in the grain.
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As of December 31, 1996, the Company had identified three PDNP and eleven
PUD locations in the Arkoma Basin, and the Company expects that additional drill
sites will be developed once it is able to more fully evaluate the additional
reserve potential identified during its acquisition analysis. The typical Arkoma
Basin well is drilled to approximately 7,500 feet and costs approximately
$350,000 (gross) to drill and complete. In 1996, the Company successfully
drilled and completed three wells and participated in two wells successfully
drilled and completed by outside operators in the Arkoma Basin. The Company has
budgeted approximately $1.2 million to drill eight gross (3.7 net) development
wells in the Arkoma Basin in 1997.
Exploration
The Company seeks to balance its strategy of acquiring and exploiting
mature but underdeveloped reserves by dedicating a portion of its capital
expenditure budget to higher risk with potentially much higher reward
exploration opportunities. The Company expects to drill thirteen gross (3.7 net)
exploratory wells in 1997. The Company has budgeted approximately $12 million
for its 1997 exploration program, $1.8 million on prospects on the Mustang
Island properties, including a 90 square mile 3-D seismic survey of the area, $6
million on prospects generated by the Sandefer Exploration Venture and $4.7
million for other prospects. The Company expects that its exploratory projects
will be concentrated in Gulf Coast areas, both onshore and offshore.
Sandefer Exploration Venture. To capitalize upon the extensive geological
and geophysical data base for the Upper Texas Gulf Coast, Louisiana and
Mississippi to which they have access, on January 1, 1996 the Company entered
into the Sandefer Exploration Venture to develop and promote exploration
prospects for the Company in those areas. During the term of the agreements,
which initially is two years, the venture will generate oil and natural gas
prospects in those states and will submit leasing and drilling proposals to the
Company for a monthly retainer. Through 1997, the Company has budgeted $9.0
million for the Sandefer Exploration Venture, which includes amounts payable to
Sandefer, the geologists, anticipated leasing and other costs for prospects
generated by the Sandefer Exploration Venture and the cost to drill and complete
seven gross (1.9 net) exploratory wells in 1997. If the Company accepts a
drilling proposal generated by the Sandefer Exploration Venture, Sandefer will
receive an overriding royalty interest in leases acquired by the Company in the
prospect area and, upon payout of specified costs on a prospect, may have the
right to receive a deferred leasehold interest.
At December 31, 1996, one exploratory well has been drilled on prospects
generated by the Sandefer Exploration Venture. The first prospect drilled by the
Company is the East Bayou Sorrel prospect on which the Schwing # 1 well was
drilled. The Schwing #1 in Iberville Parish, Louisiana represents a new field
discovery in the Cib Haz formation at 13,200 feet and is currently producing
1,400 Bbls of oil and 1,200 Mcf of gas per day, on a 11.5/64 choke size in order
to maintain production at the 1,400 Bbls of oil per day allowable set by the
State of Louisiana.
Although the leasing and drilling costs are generally higher in southern
Louisiana where the Schwing # 1 was drilled, the Company believes that due to
the higher porosity and permeability of the producing formations, the area has
significant reserve potential which could yield much higher production rates
than the Company's Texas, Oklahoma and Arkansas properties. The Company also
believes that the generally shorter life properties in southern Louisiana would
add diversity to its properties and provide balance to its relatively longer
life, lower risk properties in the GAU, Cotton Valley, Anadarko Basin and Arkoma
Basin.
Bayou Sorrel. The Bayou Sorrel area is located approximately eighty miles
west of New Orleans, in Iberville Parish, Louisiana, in the Atchaflaya River
Basin. The topography of the surface is river swamp and all work must be done
with barge mounted drilling rigs and boats. Production platforms are mounted on
pilings. The Company became involved in this area in January 1996, through the
Sandefer Exploration Venture, when it participated in the successful exploratory
test of the Schwing #1 well in the East Bayou Sorrel prospect which is drilled
on the eastern flank of the old Bayou Sorrel Field discovered by Shell Oil
Company in 1954. The Shell Bayou Sorrel Field was drilled in the 1950's and
1960's, with a total of 87 wells drilled and produced in twenty-eight different
horizons ranging in depths from 7,000' to 11,100' in geological age from the
Lower Miocene to the Upper Oligocene. The target depths of the Company's
exploration prospects in this area range from 11,000' to 14,000' and include the
Marg Vag, Marg Howeii, Cib Haz, and Marg Tex zones in geological age from the
Upper Oligocene to the Lower Oligocene.
9
<PAGE>
After the successful test of the East Bayou Sorrel, Schwing #1, the Company
increased its original 17% working interest in the well by acquiring interests
from two other working interest owners. In October 1996, the Company acquired a
14% working interest in the Schwing #1 from W&T Offshore, Inc. In December 1996,
the Company acquired a 29% working interest in the Schwing #1 from MCNIC Oil &
Gas, increasing the Company's working interest in such well to 60%.
In November 1996, the Company acquired 100% of the Shell Bayou Sorrel
Field, adjacent to the Schwing #1 discovery well, from Panaco, Inc., who had
acquired the field from Shell a year earlier. The Bayou Sorrel Acquisition
included 10 wells producing approximately 325 barrels of oil per day and 18 shut
in wells along with 2,000 leasehold acres held by production and production
facilities capable of handling 20,000 barrels of oil per day, 50,000 Mcf of gas
per day and salt water disposal of 30,000 barrels of water per day.
In addition, the Company has acquired leases adjacent to the Bayou Sorrel
and East Bayou Fields which, in total, give the Company 4,080 gross (3,979 net)
acres in the area. The Company has undertaken a complete geologic and
engineering study of the Bayou Sorrel area, which will include a 3-D shoot of at
least thirty square miles encompassing the entire Bayou Sorrel lease position.
Additional deep Cib Haz prospects have been identified which the Company intends
to drill in late 1997 or 1998. The Company has budgeted in 1997 approximately
$5.1 million to drill two wells in the East Bayou Sorrel prospect offsetting the
Schwing #1 and one new exploratory well on the adjacent leases.
Mustang Island. The Mustang Island area located in shallow state waters in
offshore Nueces County, Texas is the other principal area of focus for the
Company's exploration program. When the Company decided to implement an
exploration program, it reviewed numerous prospects, including Mustang Island.
The Company ultimately selected Mustang Island based on extensive geological and
geophysical studies that led the Company to conclude that there may be potential
for large reserves in the upper and lower Frio sands and in even lower depths in
the relatively unexplored transition zone offshore in the Gulf of Mexico. After
a comprehensive analysis, including a review of capital expenditures, markets
for production and the additional infrastructure needed to explore, develop and
market the reserves of the Mustang Island Properties, a decision was made to
commence an exploration program off Mustang Island.
In 1995 the Company initially acquired a 100% interest in one producing
well, one proved undeveloped drilling location and 770 acres of leases. In two
subsequent transactions, it acquired an approximate 72% working interest in an
additional five wells and 1,440 acres of leases, a 100% working interest in
approximately 11 miles of pipeline and a shore tank facility, and a 50% working
interest in two other wells, which wells are part of a natural gas unit
including 3,840 acres. These acquisitions also included four platforms (one
four-pile, one tripod and two monopods), which the Company may use in its
exploratory drilling program. Based upon the Company's reprocessing and
extensive analysis of approximately 500 square miles of 2-D seismic data
purchased by the Company, in April 1996 it bid upon and acquired five year
leases of 17 additional tracts from the State of Texas, consisting of 7,765
acres of leases. All of such tracts are in close geographic proximity to the
offshore acreage the Company previously had acquired and the total acreage now
leased by the Company in the Mustang Island area is 13,810 gross (11,295 net)
acres. The Mustang Island area contains complex geological structures in which
the Company intends to principally drill at depths of 15,000 to 17,000 feet in
the upper and lower Frio sands at a cost of approximately $3.0 million (gross)
to drill and complete each well.
In 1996, the Company recompleted one well, which is currently producing 200
Mcf per day. The Company has budgeted approximately $4.6 million in 1997 to
recomplete the three wells acquired in 1996, to drill one PUD location and one
exploratory well and to commission a 3-D seismic survey of the area. The 3-D
seismic survey will be used to evaluate its options for improving the recovery
of the proved oil and natural gas reserves and to determine possible locations
for the exploratory wells it intends to drill in the area in 1997 and 1998. The
Company intends to limit its working interests in its Mustang Island exploratory
prospects through participation by industry partners.
10
<PAGE>
Oil and Natural Gas Production.
The following table shows the approximate net production attributable to
the Company's oil and natural gas interests for the periods indicated:
OIL AND NATURAL GAS PRODUCTION
Year ended December 31,
---------------------------------------------
1994 1995 1996
-------------- -------------- --------------
Oil (Mbls) 115,642 283,440 521,701
Natural gas (Mmcf) 620,843 1,752,990 5,680,904
Natural gas equivalent (Mmcfe) 1,314,695 3,453,630 8,811,110
Productive Well Summary.
The Company's production of oil and natural gas is primarily derived from
wells located in Texas, Oklahoma and New Mexico. The following table sets forth
the Company's interests in productive wells, by state, as of December 31, 1996:
<TABLE>
<CAPTION>
PRODUCTIVE WELLS
Oil Natural Gas Total
----------------------- ----------------------- -----------------------
Field Gross Net Gross Net Gross Net
- ---------------------------- ---------- ----------- ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Onshore:
Anadarko Basin, OK 204 96.1 268 115.7 472 211.8
Cotton Valley Trend, TX 2 1.4 25 21.4 27 22.8
GAU, TX 114 108.2 - - 114 108.2
Lake Boeuf, LA 1 .9 - - 1 .9
Arkoma Basin, OK and AR - - 119 35.7 119 35.7
Bayou Sorrel, LA 16 15.3 - - 16 15.3
Other Onshore 50 20.4 30 6.1 80 26.5
---------- ----------- ---------- ----------- ---------- -----------
Total Onshore 387 242.3 442 178.9 829 421.2
Offshore:
Mustang Island, TX 1 1 3 1.7 4 2.7
---------- ----------- ---------- ----------- ---------- -----------
Total 388 243.3 445 180.6 833 423.9
========== =========== ========== =========== ========== ===========
</TABLE>
11
<PAGE>
Production Economics.
The following table sets forth the average sales price per barrel of oil
and Mcf of natural gas produced, the average lease operating expenses ("LOE")
and depletion, depreciation and amortization ("DD&A") rates and the general and
administrative ("G&A") costs attributable to the Company's oil and natural gas
production for the periods indicated.
PRODUCTION ECONOMICS
Year ended December 31,
--------------------------------
1994 1995 1996
---------- ---------- --------
Average sales price:
Oil (Bbl) $16.01 $17.22 $21.70
Natural gas (Mcf) 2.11 1.70 2.28
Natural gas equivalent (Mcfe) 2.40 2.28 2.75
LOE per Mcfe .92 .50 .42
G&A per Mcfe .75 .51 .34
DD&A per Mcfe .70 .91 1.11
Leasehold Acreage.
The following table shows the approximate gross and net acres in which the
Company had a leasehold interest as of December 31, 1996:
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
- --------------------------- ------------------------- ------------------------
Fields Gross Net Gross Net
- --------------------------- ----------- ------------ ----------- -----------
Onshore:
Anadarko Basin, OK 106,771 42,622 8,990 4,935
Cotton Valley Trend, TX 4,761 4,410 1,567 1,455
GAU, TX 4,720 4,482 3,160 3,007
Lake Boeuf, LA 143 125 945 827
Arkoma Basin, OK and AR 43,365 14,576 1,144 72
Bayou Sorrel, LA 2,426 2,426 1,654 1,553
Other Onshore (1) 21,856 5,209 29,936 24,498
----------- ------------ ----------- -----------
Total Onshore 184,042 73,850 47,396 36,347
Offshore:
Mustang Island, TX 6,045 3,530 7,765 7,765
=========== ============ =========== ===========
Total 190,087 77,380 55,161 44,112
=========== ============ =========== ===========
(1) Includes acreage in Colorado, Kansas, Louisiana, Oklahoma, Nebraska, New
Mexico, and Wyoming.
Substantially all of the Company's producing oil and natural gas properties
are located on leases held by the Company for an indeterminate number of years
for so long as production is maintained. All of the Company's non-producing
acreage is held under leases from mineral owners or a government entity which
expire at varying dates. The Company is obligated to pay annual delay rentals to
the lessors of certain properties in order to prevent the leases from
terminating. Because substantially all of the Company's undeveloped acreage was
held by production, annual delay rentals for 1996 were nominal; however, such
rentals are expected to increase in future periods.
12
<PAGE>
Drilling Activity.
The following table sets forth development and exploration drilling results
for the years ended December 31, 1994, 1995 and 1996.
DRILLING RESULTS
<TABLE>
<CAPTION>
Years ended December 31,
-------------------------------------------------------------------------
1994 1995 1996
----------------------- ----------------------- -----------------------
Gross Net Gross Net Gross Net
---------- ----------- ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
DEVELOPMENT
Productive 9 6.4 24 20.7 28 25.6
Non-productive - - 1 .6 1 .2
---------- ----------- ---------- ----------- ---------- -----------
Total 9 6.4 25 21.3 29 25.8
EXPLORATORY
Productive - - - - 3 1.4
Non-productive 2 1.0 2 .8 5 1.1
---------- ----------- ---------- ----------- ---------- -----------
Total 2 1.0 2 .8 8 2.5
---------- ----------- ---------- ----------- ---------- -----------
Combined Total 11 7.4 27 22.1 37 28.3
========== =========== ========== =========== ========== ===========
</TABLE>
Title to Oil and Natural Gas Properties.
The Company has acquired interests in producing and non-producing acreage
in the form of working interests, royalty interests and overriding royalty
interests. To reduce the Company's financial exposure in any one exploratory
prospect, the Company often acquires less than 100% of the working interest in a
prospect. Working interests held by the Company may, from time to time, become
subject to minor liens. Furthermore, updated title opinions may not be received
prior to the acquisition of a producing oil and natural gas property. It is
contemplated, however, that investigations will be made in accordance with
standard practices in the industry before the acquisition of such properties and
before drilling.
Production and Sales Prices.
The Company's production of oil and natural gas is derived solely from its
activities in the continental United States. The Company is not obligated to
provide a fixed and determinable quantity of oil and/or natural gas in the
future under existing contracts or agreements. The Company does not plan to
refine or process the oil and natural gas it produces, but plans to sell the
production to unaffiliated oil and natural gas purchasing companies in the area
in which it is produced. The Company expects to sell crude oil on a market price
basis and to sell natural gas under contracts to both interstate and intrastate
gas pipeline companies. The Company currently sells a significant portion of its
oil pursuant to a contract with Plains Marketing and Transportation, Inc.
("Plains"). See "Markets and Customers" below.
Lease Interests.
The Company generally acquires a leasehold interest in the properties to be
explored. The leases grant the lessee the right to explore for and extract oil
and natural gas from a specified area. Rentals usually consists of fixed annual
charges prior to production and, once production has been established, a royalty
based upon the gross proceeds from the sale of oil and natural gas. Once wells
are drilled, a lease generally continues as long as production of oil and
natural gas continues. In some cases, leases may be acquired in exchange for a
commitment to drill or finance the drilling of a specified number of wells to
predetermined depths.
13
<PAGE>
Control Over Production Activities.
The Company operates 506 of the 833 producing wells in which it owns an
interest as of December 31, 1996. The non-operated properties are operated by
unrelated third parties pursuant to operating agreements which are generally
standard in the industry. Significant decisions about operations regarding
non-operated properties may be determined by the outside operator rather than by
the Company. If the Company declines to participate in additional activities
proposed by the outside operator under certain operating agreements, the Company
will not receive revenues from, and/or will lose its interest in the activity in
which it declined to participate.
Factors Beyond the Company's Control.
Although demand for oil is steady, there are seasonal variations in the
demand for natural gas. The Company's oil and natural gas business is also
affected by factors which are beyond its control and the exact effects of which
cannot be accurately predicted. These factors may include war in countries other
than the United States, the extent of domestic production, imports of crude oil,
production by and agreements among OPEC members, the availability of adequate
pipeline and other transportation facilities, the marketing of competitive fuel,
government regulation of prices, production, transportation and marketing,
fluctuating supply and demand, regulation and other matters affecting the
supply and demamd for crude oil and natural gas.
Markets and Customers.
The availability of a ready market for any oil and natural gas produced by
the Company and the prices obtained for such oil and natural gas depends upon
numerous factors beyond its control, including the demand for and supply of oil
and natural gas, fluctuations in production and seasonal demand, proximity of
the wells to adequate transmission facilities, weather conditions, economic
conditions, and the effects of state and federal governmental regulations on the
import, production, transportation and sale of oil and natural gas. The
occurrence of any factor which affects a ready market for the Company's oil and
natural gas or reduces the price obtained for such oil and gas may adversely
affect the Company.
A large percentage of the Company's oil and natural gas sales are made to a
small number of purchasers. During the year ended December 31, 1995, two
suppliers, Plains and Energy Source, Inc. accounted for approximately 59% of the
Company's oil sales and 11% of its natural gas sales. During 1996, Plains
accounted for 83% of the Company's oil sales, while Crosstex Energy, Inc. and
GPM Natural Gas Corporation accounted for 23% and 22%, respectively, of the
Company's natural gas sales. The agreement with Plains, entered into in 1993,
provides for Plains to purchase the Company's oil pursuant to West Texas
Intermediate posted prices plus a small premium. The Company does not believe
that the loss of any customer would have a material and adverse effect on its
business because, under prevailing market conditions, such customer could be
replaced.
Regulation.
General. The Company's oil and natural gas exploration, production and
related operations are subject to extensive rules and regulations promulgated by
federal and state agencies. Failure to comply with such rules and regulations
can result in substantial penalties. The regulatory burden on the oil and
natural gas industry increases the Company's cost of doing business and affects
its profitability. Because such rules and regulations are frequently amended or
interpreted, the Company is unable to predict the future cost or impact of
complying with such laws.
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 regulations 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. Legislation in
Oklahoma and regulatory action in Texas governs the methodology by which the
regulatory agencies establish permissible monthly production allowables. This
action has generated substantial controversy, especially at the federal level,
and has been labeled as an attempt 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
14
<PAGE>
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 places limitations on the number of acres under federal
leases that may be owned in any one state.
Environmental Protection and Occupational Safety. The Company is subject to
numerous federal, state and local laws and regulations governing the release of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentration of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit drilling activities on
certain lands lying within wilderness, wetlands and other protected areas and
impose substantial liabilities for pollution resulting from operations.
Moreover, the recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation has
been proposed in Congress from time to time that would reclassify certain oil
and natural gas production wastes as "hazardous wastes", which reclassification
would make such wastes subject to much more stringent handling, disposal and
clean-up requirements. 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. It is not anticipated that the Company will be
required in the near future to expend amounts that are material in relation to
its total capital expenditure program by reason of environmental laws and
regulations, but because such laws and regulations are frequently changed, the
Company is unable to predict the ultimate cost and effects of such compliance.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to have contributed to the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances. Under CERCLA such persons
or companies may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources. Also, it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury, property damage and recovery of response costs allegedly caused by the
hazardous substance released into the environment.
In addition, the U.S. Oil Pollution Act of 1990 (the "OPA") and regulations
promulgated pursuant thereto impose a variety of regulations on responsible
parties related to the prevention of oil spills and liability for damages
resulting from such spills. The OPA establishes strict liability for owners of
facilities that are the site of a release of oil into "waters of the United
States." While OPA liability more typically applies to facilities near
substantial bodies of water, at least one district court has held that OPA
liability can attach if the contamination could enter waters that may flow into
navigable waters.
Stricter standards in environmental legislation may be imposed in the oil
and natural gas industry in the future, such as proposals made in Congress and
at the state level from time to time, that would reclassify certain oil and
natural gas exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent and costly handling, disposal and
clean-up requirements. The impact of any such changes, however, would not likely
be any more burdensome to the Company than to any other similarly situated
company involved in oil and natural gas exploration and production.
The Resource Conservation and Recovery Act ("RCRA") and regulations
promulgated thereunder govern the generation, storage, transfer and disposal of
hazardous wastes. RCRA, however, excludes from the definition of hazardous
wastes "drilling fluids, produced waters, and other wastes associated with the
exploration, development, or production of crude oil, natural gas or geothermal
energy." Because of this exclusion, many of the Company's operations are exempt
from RCRA regulation. Nevertheless, the Company must comply with RCRA
regulations for any of its operations that do not fall within the RCRA exclusion
(such as painting activities or use of solvents).
15
<PAGE>
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.
Marketing and Transportation. Federal legislation and regulatory controls
in the United States have historically affected the price of the natural gas
produced by the Company and the manner in which such production is marketed. The
transportation and sales for resale of natural gas in interstate commerce are
regulated pursuant to the Natural Gas Act of 1938 (the "NGA") and the Federal
Energy Regulatory Commission ("FERC") regulations promulgated thereunder.
Maximum selling prices of certain categories of natural gas, whether sold in
interstate or intrastate commerce, previously were regulated pursuant to The
Natural Gas Policy Act of 1978 ("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. All price deregulation contemplated under the NGPA
has already taken place. Subsequently, the Natural Gas Wellhead Decontrol Act of
1989 (the "Decontrol Act") terminated all remaining NGA and NGPA price and
non-price controls on wellhead sales of domestic natural gas on January 1, 1993.
While natural gas producers may currently make sales at uncontrolled market
prices, Congress could re-enact price controls in the future.
Commencing in late 1985, the FERC issued a series of orders (Order No. 436,
Order No. 500 and related orders), which promulgated regulations significantly
altering the transportation and marketing of natural gas. Among other things,
these regulations (a) required interstate pipelines that elect to transport
natural gas for others under self-implementing authority to provide
transportation services to all shippers on a non-discriminatory basis, and (b)
permitted each exiting firm sales customer of any such pipeline to modify over
at least a five-year period, its existing purchase obligations. Although the
regulations do not directly regulate natural gas producers such as the Company,
the availability of non-discriminatory transportation services and the ability
of pipeline customers to modify their existing purchase obligations under these
regulations has greatly enhanced the ability of producers to market their
natural gas directly to end users and local distribution companies. In this
regard, access to markets through interstate pipelines is critical to the
Company's marketing initiatives.
In April 1992, the FERC issued its restructuring rule, known as Order No.
636 ("Order No. 636"), that has had a major impact on pipeline operations,
services and rates. The most significant provisions of Order No. 636: (a)
required interstate pipelines to provide firm and interruptible transportation
solely on an "unbundled" basis, separate from their sales service, and to
convert each pipeline's bundled firm sales service into unbundled firm
transportation service; (b) provided for the issuance of blanket certificates to
pipelines to provide unbundled sales service giving all utility customers a
chance to purchase their firm supplies from non-pipeline merchants; (c) required
that pipelines provide firm and interruptible transportation service on a basis
that is equal in quality for all natural gas supplies, whether purchased from
the pipeline or elsewhere; (d) required that pipelines provide a new,
non-discriminatory "no-notice" transportation service that largely replicates
the "bundled" sales service previously provided by pipelines; (e) established
two new, generic programs for the reallocation of firm pipeline capacity; (f)
required that all pipelines offer access to their storage facilities on a firm
and interruptible basis; (g) provided for pregranted abandonment of pipeline
sales agreements, interruptible and firm short-term (defined as one year or
less) transportation agreements and conditional pregranted abandonment of firm
long-term transportation service; (h) modified transportation rate design by
requiring that all fixed costs related to transportation be recovered through
the reservation charge; and (i) provided mechanisms for the recovery by
pipelines of certain transition costs occurring from implementation of Order No.
636.
The rules contained in Order No. 636, as amended by Order No. 636-A (issued
in August 1992) and Order No. 636-B (issued in November 1992) (collectively,
"Order No. 636") are far reaching and complex. In addition, Order No. 636 and
individual orders in restructuring proceedings are currently subject to court
challenges. While Order No. 636 does not directly regulate natural gas producers
such as the Company, the FERC has stated that Order No. 636 is intended to
foster increased competition within the natural gas industry.
16
<PAGE>
Operational Hazards and Insurance.
The Company's operations are subject to all of the risks inherent in oil
and natural gas exploration, drilling and production. 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 believes it is insured prudently against certain of these risks. In
addition, the Company maintains operator's extra expense coverage that provides
coverage for the care, custody and control of wells drilled by the Company. The
Company's insurance does not cover every potential risk associated with the
drilling and production of oil and natural gas. The Company does, however,
maintain 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. 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 believes that it operates in
compliance with government regulations and in accordance with safety standards
which meet or exceed industry standards.
Competition.
The oil and gas industry is intensely competitive in all of its phases,
particularly with respect to the acquisition of desirable producing oil and
natural gas leases and oil and gas companies with production. The Company, which
is a small competitive factor in the industry, encounters strong competition
from major oil companies, independent oil and gas concerns, and individual
producers and operators, many of which have financial resources, staffs,
facilities and experience substantially greater than those of the Company.
Furthermore, in times of high drilling activity, exploration for and production
of oil and natural gas may be affected by the availability of equipment, labor,
supplies and by competition for drilling rigs. The Company cannot predict the
effect these factors will have on its operations. The Company owns no drilling
rigs, and it is anticipated that its drilling will be conducted by third
parties. Furthermore, the oil and gas industry also competes with other
industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers.
Office Space and Other.
The Company leases approximately 20,420 square feet of office space in
Dallas, Texas. The Company also leases a small amount of office space in
Houston, Texas for its business activities. Other than oil and natural gas
properties and securities of oil and gas companies, it does not intend to invest
in real estate, real estate mortgages or securities of, or interests in, persons
primarily engaged in real estate activities for the foreseeable future.
Employees.
At March 25, 1997, the Company had 58 employees, all but one of whom were
full-time. Of the 58 employees, 10 are field related personnel. The Company does
not have any collective bargaining agreements with employees and believes that
relations with its employees are generally satisfactory.
ITEM 3. LEGAL PROCEEDINGS.
On August 30, 1995, the Company filed a lawsuit in the District Court of
Ector County, Texas against R.E. Steakley in which the Company seeks to enjoin
Mr. Steakley from interfering with its operations on the surface property
controlled by Mr. Steakley. The lawsuit alleges tortious interference with the
Company's access to its facilities and wrongful conduct with respect to the
Company's personnel.
On August 31, 1995, in a matter involving the same property described
above, R.E. Steakley and N.M. Steakley filed a lawsuit in the District Court of
Harris County, Texas against Amoco Production Company, Phillips Petroleum
Company, the Company and others. The lawsuit alleges certain environmental
claims and related tortious and contractual claims and sought unspecified
damages. On December 19, 1996, the court in Harris County, Texas signed an order
transferring the R. E. Steakley claim to the court in Ector County, Texas as a
part of the Company's claim against R. E. Steakley. Subsequently, R. E. Steakley
filed a Fourth Amended Original Answer and Original Counterclaims against the
Company in Ector County District Court in which he reasserts the claims filed in
the Harris County Court action. The Company intends to vigorously defend against
the suit and believes that it is operating the property in compliance with
applicable environmental laws and regulations and believes that, based on advice
from legal counsel, that the ultimate resolution of the lawsuit will not have a
material or adverse effect on the Company's financial condition or results of
operations.
17
<PAGE>
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 ended December 31, 1996.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Market Information.
The Company's Common Stock is traded on the NASDAQ National Market System.
The Company's symbol is "NEGX".
The following table shows the range of closing bid prices through August
31, 1995 and the range of closing sales prices starting September 1, 1995, for
the Company's Common Stock, as reported by NASDAQ. The quotations represent
prices between dealers in securities and may not include retail mark-up,
mark-down or commission and may not represent actual transactions.
Since September 1, 1995, the prices reflect trading on the NASDAQ National
Market System and, for prior periods, the prices reflect trading on the NASDAQ
Small Cap Market.
Common Stock Price
-------------------------------
Calendar Years by Quarter High Low
--------------- --------------
1996
First 3 1/2 2 5/8
Second 3 7/8 2 1/2
Third 4 9/16 3 1/16
Fourth 4 3/4 3 1/4
1995
First 2 1/2 1 3/4
Second 3 3/8 2 9/16
Third 4 3
Fourth 4 3 1/16
On March 25, 1997, the latest practical date for providing price
information, the last sales price for the Company's Common Stock was $3 11/16.
Holders.
As of March 25, 1997, the Company had approximately 4,309 record holders of
its shares of Common Stock, including several nominee holders for an
undetermined number of beneficial owners.
Dividends on Common Stock.
The Company has not paid cash dividends on its Common Stock and does not
expect to declare cash dividends in the foreseeable future. Furthermore, any
future dividends on the Common Stock will be limited by the terms of the
Preferred Stock, which prohibits cash dividends on Common Stock unless all
accrued and unpaid dividends on the Preferred Stock have been paid, and the
terms of the Company's credit facility with Bank One, Texas, N.A. ("Bank One")
and Credit Lyonnais New York Branch ("Credit Facility"), which does not permit
dividends on the Common Stock.
18
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA
(in thousands, except per share data)
The following table sets forth selected historical financial and operating data
with respect to the Company as of and for each of the five years in the period
ended December 31, 1996, The Company acquired significant producing oil and
natural gas properties in all the periods presented which affects the
comparability of the historical financial and operating data for the periods
presented. The financial data was derived from the historical financial
statements of the Company. This information is not necessarily indicative of the
Company's future performance. The Company has never declared or paid dividends
on its Common Stock. 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 financial statements and the
related notes thereto included elsewhere herein.
<TABLE>
<CAPTION>
Year Ended December 31,
1992 1993 1994 1995 1996
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Statement of Operations Data: (1) (2)
Oil and natural gas sales.............................. $1,626 $1,803 $3,159 $7,858 $24,319
Well operating fees.................................... 537 427 158 137 876
----------- ----------- ----------- ----------- -----------
Total revenues................................... 2,163 2,230 3,317 7,995 25,195
Cost and expenses:
Lease operating expenses........................... 670 575 1,207 1,732 3,741
Oil and natural gas production taxes............... 109 110 176 416 1,285
General and administrative expenses................ 964 994 985 1,772 3,034
Writedown of oil and natural gas properties (3).... - - - - 43,497
Depreciation, depletion and amortization........... 466 679 1,030 3,149 9,795
----------- ----------- ----------- ----------- -----------
Total costs and expenses......................... 2,209 2,358 3,398 7,069 61,352
----------- ----------- ----------- ----------- -----------
Operating income (loss)................................ (46) (128) (81) 926 (36,157)
Interest expense....................................... (175) (188) (517) (1,032) (4,213)
Other income (expenses)................................ - 17 109 312 309
----------- ----------- ----------- ----------- -----------
Income (loss) before income taxes and extraordinary time (221) (299) (489) 206 (40,061)
Income tax benefit..................................... - - - - 14,504
----------- ----------- ----------- ----------- -----------
Income (loss) before extraordinary item................ $ (221) $ (299) $ (489) $ 206 $(25,557)
=========== =========== =========== =========== ===========
Net loss............................................... $ (221) $ (299) $ (611) $ (226) $(25,849)
=========== =========== =========== =========== ===========
Loss per common share before extraordinary item........ $(0.05) $(0.05) $(0.09) $(0.05) $(1.33)
=========== =========== =========== =========== ===========
Net loss per common share $(0.05) $(0.05) $(0.10) $(0.09) $(1.34)
=========== =========== =========== =========== ===========
Other Financial Data: (4)
EBITDA............................................. $419 $568 $1,058 $4,387 $17,444
========== =========== =========== =========== ===========
Balance Sheet Data (at period end): (1)
Cash and cash equivalents.......................... $ 366 $ 161 $2,594 $6,076 14,182
Working capital (deficit).......................... (2,155) (1,213) 3,561 (2,335) 2,582
Total assets....................................... 8,742 12,710 18,746 43,491 212,035
Long-term debt..................................... 120 3,799 6,000 13,475 100,000
Stockholders' equity............................... 4,864 6,320 11,328 17,775 80,426
</TABLE>
19
<PAGE>
- -----------------
(1) Reflects the revenues, results of operations and production subsequent to
the dates of acquisitions of various oil and natural gas properties that
affect the comparability of the data presented. In April 1992, the Company
acquired substantially all of the assets of TriSearch, Inc. The Company
acquired a 63.8% working interest in the GAU in December 1993 and an
additional interest of 17% in the GAU during 1994. During 1995, the Company
acquired interests in producing oil and natural gas properties in the
Mustang Island area, the Oak Hill Field, and in Eddy County, New Mexico.
During 1996, the Company completed the Merger with Alexander and the
acquisition of Lake Boeuf. See Note 2 of Notes to Financial Statements of
the Company.
(2) Includes extraordinary losses on early extinguishments of debt of $121,917
for the year ended December 31, 1994, $431,762 for the year ended December
31, 1995 and $292,372 for the year ended December 31, 1996.
(3) The historical results of operations for the year ended December 31, 1996
include a noncash writedown of oil and natural gas properties of
approximately $28.3 million (net of deferred taxes), in accordance with the
full cost method of accounting, which resulted from the Merger. See Note 2
of Notes to Financial Statements.
(4) See the Glossary included elsewhere in this Form 10-K for the definition of
EBITDA. EBITDA is not a measure of cash flow as determined by generally
accepted accounting principles. The Company has included information
concerning EBITDA because EBITDA is a measure used by certain investors in
determining the Company's historical ability to service its indebtedness;
however, this measure may not be comparable to similarly titled measures of
other companies. EBITDA should not be considered as an alternative to, or
more meaningful than, net income or cash flow as determined in accordance
with generally accepted accounting principles as an indicator of the
Company's operating performance or liquidity.
20
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
Overview.
During 1995 and 1996, the Company acquired an estimated 26.9 Bcfe and 126.0 Bcfe
in proved reserves, respectively (based on reserve estimates at the date of
acquisition). As a result of acquisitions and efforts to increase production
from the GAU and Cotton Valley Trend, proved reserves, as estimated by
Netherland & Sewell, increased to 54.4 Bcfe and 181.7 Bcfe at December 31, 1995
and December 31, 1996, respectively. In August 1996, the Company completed the
Merger with Alexander whereby the Company acquired 102.1 Bcfe in proved reserves
and, in September 1996, completed the Lake Boeuf Acquisition which added 17.5
Bcfe of proved reserves.
During 1995 and 1996, oil and natural gas sales, net of lease operating expense
and production taxes, increased more rapidly than G&A and DD&A. As a
consequence, the Company recognized net income of $2.4 million (excluding the
$28.3 million write-down of oil and natural gas properties) for the year ended
December 31, 1996 and recognized income from operations of $.9 million for 1995
after recording losses from operations in each year from 1992 through 1994.
Results of Operations.
The following table sets forth certain information regarding the production
volumes, oil and natural gas sales, average sales prices, lease operating
expenses ("LOE"), general and administrative expenses ("G&A") and depreciation,
depletion and amortization ("DD&A") associated with the Company's oil and
natural gas sales for the period indicated.
<TABLE>
<CAPTION>
Year ended December 31,
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Net Production:
Oil (Bbls) 115,642 283,440 521,701
Natural gas (Mcf) 620,843 1,752,990 5,680,904
Natural gas equivalent (Mcfe) 1,314,695 3,453,630 8,811,110
Oil and natural gas sales:
Oil $1,851,443 $4,880,313 $11,320,279
Natural gas 1,307,273 2,978,003 12,999,119
--------- --------- ----------
Total $3,158,716 $7,858,316 $24,319,398
========== ========== ===========
Average sales price:
Oil (Bbls) $16.01 $17.22 $21.70
Natural gas (Mcf) 2.11 1.70 2.29
Natural gas equivalent (Mcfe) 2.40 2.28 2.75
LOE per Mcfe .92 .50 .42
G & A expenses per Mcfe .75 .51 .34
DD&A per Mcfe .70 .91 1.11
</TABLE>
Year ended December 31, 1996 compared with year ended December 31, 1995.
Revenues. Total revenues increased by $17.2 million (215.1%) to $25.2 million
for 1996 from $8.0 million in 1995. The increase in revenues is due to the
increase in production from the development of the GAU, and the increase in
production due to the 1995 acquisitions of Mustang Island, Oak Hill and the
Enron Properties (hereinafter collectively referred to as the "1995
Acquisitions"). The increase is also due to the UMC Acquisition, the CA
Acquisition, the Lake Boeuf Acquisition, the W&T Acquisition, the Bayou Sorrel
Acquisition and the MCNIC Acquisition (hereinafter referred to as the "1996
Acquisitions") completed during 1996, and the Merger with Alexander completed
August 29, 1996. In 1996, the Company produced 521,701 barrels of oil, an
increase of 84.1% over 283,440 barrels in 1995, and 5,680,904 Mcf of natural
gas, an increase of 224.1% over 1,752,990 Mcf in 1995.
Also contributing to the increase in revenues was the increase in average oil
prices of $4.48 per barrel to $21.70 for 1996 from $17.22 for 1995, and the
increase in average natural gas prices of $.58 per Mcf to $2.28 per Mcf for 1996
from $1.70 for 1995.
21
<PAGE>
Costs and Expenses. Total costs and expenses, excluding the write-down,
increased $10.8 million (152.6%) to $17.9 million for 1996 from $7.1 million for
1995. Lease operating expenses and production taxes increased $2.9 million
(138.1%) to $5.0 million for 1996 from $2.1 million for 1995 primarily due to
the development of the GAU, the 1995 Acquisitions, the 1996 Acquisitions and the
Merger. Lease operating expenses per Mcfe decreased by $.08 to $.42 per Mcfe for
1996 from $.50 per Mcfe for 1995. This decrease is a result of the lower
operating costs of the acquired properties combined with reductions in costs at
the GAU obtained through economies of scale resulting from the additional wells
drilled during 1995 and 1996.
DD&A increased $6.6 million (211.0%) to $9.8 million for 1996 compared to $3.1
million for 1995. This increase is due to the increased production from the GAU,
the 1995 Acquisitions, the 1996 Acquisitions and the Merger. The depletion rate
per Mcfe was $1.11 for 1996 compared to .91 for 1995. This increase in the
depletion rate is primarily due to downward revisions in estimated proved
reserves at December 31, 1995 and the acquisition costs associated with the
Merger.
At August 29, 1996, as a result of allocating the cost of acquiring Alexander,
under the purchase method of accounting, to the proved oil and natural gas
properties acquired in connection with the Merger, the Company recognized a
non-cash write-down of the oil and natural gas properties, net of related
deferred income taxes of $28.3 million, based on prices received in August 1996
of $20.75 per Bbl and $2.21 per Mcf. See Note 2 of Notes to Financial
Statements.
Although G&A increased $1.3 million to $3.0 million for 1996, G&A per Mcfe
decreased to $.34 (33.3%) for 1996 from $.51 for 1995. This decrease is
attributable to the increase in production from the GAU, the 1995 and 1996
Acquisitions and to a lesser extent the Merger, without a proportionate increase
in the G&A costs to the Company.
Other Income and Expenses. The increase of $3.2 million (320.0%) in interest
expense to $4.2 million for 1996 from $1.0 million for 1995, was due to the
increase in the amount of outstanding debt as a result of borrowings under a
prior credit facility and the Credit Facility to fund the 1996 Acquisitions and
the Merger during 1996, and was partially offset by the decline in weighted
average interest rates. Also contributing to the increase was the issuance of
the Senior Notes. The average debt outstanding for 1996 was $41.4 million,
including the Senior Notes, as compared to $10.6 million for 1995. The weighted
average interest rate for 1996 was 8.64% compared to 9.66% for 1995.
Net Loss. A net loss of $25.8 million was generated for 1996, compared with a
net loss of $.2 million for 1995. The loss for 1995 includes an extraordinary
charge resulting from the write-off of unamortized loan costs attributable to a
prior credit facility which was paid off out of proceeds from the Credit
Facility. The net loss for 1996 includes a net non-cash write-down of $28.3
million to the Company's oil and natural gas properties, partially offset by the
increased operating income generated by the GAU, the 1995 Acquisitions, the 1996
Acquisitions and the Merger. Also included in the net loss was a loss on sale of
marketable securities of $118,000 for 1996 as compared to a gain of $221,000 for
1995.
Year ended December 31, 1995 compared with year ended December 31, 1994.
Revenues. Total revenues increased by $4.7 million (141.0%) to $8.0 million for
1995 from $3.3 million for 1994. The increase in revenues is principally due to
the continued development of the GAU and the increase in production due to the
1995 Acquisitions. In 1995, the Company produced 283,440 barrels of oil, an
increase of 145.1% over 115,642 barrels in 1994, and 1,752,990 Mcf of natural
gas, an increase of 182.4% over 620,843 Mcf in 1994. The increase in oil
production is almost entirely a result of the GAU's increased oil production
resulting from the development since August 1994. The 1995 Acquisitions
accounted for the increased natural gas production. Also contributing to the
increase in revenues was the increase in average oil prices of $1.21 per barrel
to $17.22 for 1995 from $16.01 for 1994. The decline in average natural gas
prices of $.41 per Mcf to $1.70 for 1995 down from $2.11 for 1994 was offset by
the 182.4% increase in natural gas production.
Costs and Expenses. Total costs and expenses increased $3.7 million (108.0%) to
$7.1 million for 1995 from $3.4 million for 1994. Lease operating expenses and
production taxes increased $764,420 (55.3%) to $2.1 million for 1995 from $1.4
million for 1994 primarily due to the development of the GAU and the 1995
Acquisitions. Lease operating expenses and production taxes attributable to the
GAU increased $284,687 from 1994 to 1995, representing 37.2% of the total
22
<PAGE>
increase for the Company. Lease operating expenses and production taxes
attributable to the 1995 Acquisitions totaled $256,059 for 1995, representing
33.5% of the total increase for the Company since those properties were not
purchased until 1995. Lease operating expenses as a percent of oil and natural
gas sales decreased to 22.0% for 1995 from 38.2% for 1994. This decrease is a
result of the lower operating costs of the acquired properties, reductions in
costs at the GAU obtained through economies of scale resulting from the
additional wells drilled since August 1994 and fewer workovers performed during
1995 than during 1994.
DD&A increased $2.1 million (205.8%) to $3.1 million for 1995 compared to $1.0
million for 1994. This increase, was, in part, related to the increased
production from the GAU and the 1995 Acquisitions. In addition, the depletion
rate on oil and natural gas properties increased to $1.05 per Mcfe for the
fourth quarter from $0.79 per Mcfe due to downward revisions in estimated proved
reserves at December 31, 1995.
Although G&A increased $787,068 to $1.8 million for 1995, G&A per Mcfe decreased
to $0.51 (32.0%) for 1995 from $0.75 for 1994. This decrease is attributable to
the increase in production from the "GAU" and the 1995 Acquisitions, without
proportionate increase in G&A costs to the Company.
Other Income and Expenses. The increase of $515,010 (99.6%) in interest expense
to $1.0 million for 1995 from $517,086 for 1994, was due to the increase in the
amount of outstanding debt as a result of borrowings under a prior credit
facility with Bank One obtained by the Company in 1994 (the "1994 Credit
Facility") and was partially offset by a decline in weighted average interest
rates. The average debt outstanding for 1995 was $10.6 million as compared to
only $5.2 million for 1994. The weighted average interest rate for 1995 was
9.66% as compared to 11.24% for 1994. During 1995, the Company realized a gain
of $220,582 on the sale of marketable securities.
Net Loss. Income before extraordinary item of $205,793 was generated for 1995,
compared with a loss before extraordinary item of $489,369 for 1994. This
increase is directly the result of the increased production on the GAU and the
increase in production resulting from the 1995 Acquisitions. Also contributing
to this increase was a realized gain of $220,582 on the sale of marketable
securities in 1995.
A net loss of $225,969, after an extraordinary charge of $431,762, was generated
for 1995, compared with a net loss of $611,286, after an extraordinary charge of
$121,917, in 1994. The extraordinary charge in 1995 resulting from the write-off
of unamortized loan costs attributable to Texas Gas Fund I credit facility
obtained by the Company in June 1994 ("Texas Gas Fund I"),which was paid off out
of proceeds from the 1994 Credit Facility. The extraordinary charge in 1994 was
in connection with the write-off of unamortized loan costs attributable to the
Company's credit facility with Bank One obtained in 1992, which was paid off in
1994 with proceeds from the credit facility with Texas Gas Fund I.
Pro Forma Results of Operations
The following table sets forth certain information regarding the pro forma
combined production volumes, oil and gas sales, average sales prices, average
lease operating expenses and general and administrative expenses, operating
income and EBITDA assuming the 1995 Acquisitions, the Merger and the Lake Boeuf
Acquisition had been consummated on January 1, 1995. The pro forma combined
information does not purport to represent the actual results which would have
occurred had the Merger been consummated on such date.
23
<PAGE>
<TABLE>
<CAPTION>
Pro Forma
Year ended
December 31,
1995 1996
<S> <C> <C>
Net production:
Oil (Mmbls) 475 608
Natural gas (Mmcf) 11,830 10,887
Natural gas equivalent (Mmcfe) 14,680 14,538
Oil and natural gas sales (in thousands):
Oil $ 8,030 $12,959
Natural gas 17,981 23,648
Total $26,011 $36,607
Average sale price:
Oil (per Bbl) $16.95 $21.30
Natural gas (per Mcf) 1.52 2.17
Natural gas equivalent (per Mcfe) 1.77 2.52
LOE per Mcfe .49 .43
G&A expenses per Mcfe .35 .32
Operating income (loss) ($3,297) $10,776
EBITDA $12,586 $26,767
</TABLE>
Liquidity and Capital Resources.
Year ended December 31, 1996 compared with year ended December 31, 1995.
Net cash provided by operating activities was $11.8 million for the year ended
December 31, 1996, compared to $2.9 million for the same period in 1995. The
increase in cash flow from operating activities is primarily due to the
significant increase in income from operations before DD&A resulting from the
1995 Acquisitions, the 1996 Acquisitions and the Merger discussed above.
Net cash used in investing activities was $49.3 million for 1996 compared with
$16.7 million for 1995. This increase was principally due to increased
expenditures for oil and natural gas property acquisitions, the 1996
Acquisitions, the Merger, and exploration and development costs.
Net cash provided by financing activities was $45.6 million for 1996 compared
with $17.4 million for 1995. The cash provided by financing activities during
1996 primarily consisted of borrowings under credit facilities of $69.0 million,
net proceeds from issuance of the Senior Notes of $96.1 million, and proceeds
from the issuance of preferred stock of $15.0 million, partially offset by
repayments of borrowings under various credit facilities and debt assumed in the
Merger aggregating $141.5 million. Borrowings under credit facilities in 1995
were used to fund acquisitions, development of the GAU and working capital.
The Company's working capital at December 31, 1996 was $2.6 million compared to
a deficit at December 31, 1995 of $2.3 million. The improvement was due
primarily to refinancing of borrowings under a credit facility.
24
<PAGE>
Year ended December 31, 1995 compared with year ended December 31, 1994.
At December 31, 1995, the Company had existing cash and cash equivalents of $6.1
million. Net cash provided by operating activities was $2.9 million for 1995,
compared to $373,292 for 1994. The increase in cash flow from operating
activities is primarily due to the significant increase in income from
operations before DDA.
Net cash used in investing activities was $16.7 million for 1995 compared with
$3.8 million for 1994. This increase was principally due to expenditures for
development of the GAU and the cash used in the 1995 Acquisitions.
Net cash provided by financing activities was $17.4 million for 1995 compared
with $5.9 million for 1994. The cash provided by financing activities during
1995 primarily consisted of increased borrowings under a credit facility of
$21.0 million and the net proceeds from the issuance of the Series C Preferred
Stock of $4.0 million. Borrowings under the credit facility were used to repay
outstanding borrowings under the Texas Gas Fund I of $6.0 million and to fund
acquisitions, development of the GAU and working capital.
The Company's working capital deficit at December 31, 1995 was $2.3 million.
This deficit was primarily attributable to the inclusion of then current portion
of the borrowings under a credit facility which totaled $6.5 million, which was
offset in part by an increased cash and accounts receivable position. Also
contributing to the working capital deficit was the increase in accounts payable
resulting from the increased development activities during 1995.
Future Capital Requirements
The Company has made, and will continue to make, substantial capital
expenditures for acquisition, development and production of oil and natural gas
reserves, particularly since a substantial portion of the proved reserves of the
Company consists of proved undeveloped reserves.
The Company has established an aggregate development and exploration capital
budget for its existing properties of approximately $57 million for the year
ended December 31,1997. The Company is not contractually committed to expend the
budgeted funds. The Company currently expects that available cash, cash flows
from operations and available borrowings under the Credit Facility shall be
sufficient to fund planned capital expenditures for its existing properties
through 1997. However, the Company may need to raise additional capital to fund
acquisitions and the development thereof.
For the periods following 1997, the Company may seek additional capital, if
required, from traditional reserve base borrowings, equity and debt offerings or
joint ventures to further develop and explore its properties and to acquire
additional properties. The Company's ability to access additional capital will
be available to the Company from any source or that, if available, it will be at
prices or on terms acceptable to the Company. Should the Company be unable to
access the capital markets or should sufficient capital not be available, the
development and exploration of the Company's properties could be delayed or
reduced and, accordingly, oil and natural gas revenues and operating results may
be adversely affected.
Notes.
On November 1, 1996, the Company closed the offering of $100 million of its
Senior Notes. The net proceeds of the Senior Notes of approximately $96.1
million were used to repay approximately $62.0 million of borrowings under the
Credit Facility and to increase the Company's working capital. In 1997, the
Senior Notes were exchanged for the Exchange Notes which are substantially
identical to the Senior Notes. Collectively, the Senior Notes and Exchange Notes
are referred to as the "Notes". The Notes bear interest at 10 3/4% per annum,
payable semi-annually on May 1 and November 1, commencing May 1, 1997. The Notes
mature November 1, 2006, but may be redeemed after November 1, 2001, at the
Company's option. The Indenture governing the Notes contains certain covenants,
including, but not limited to, covenants restricting the Company and its
Restricted Subsidiaries, as defined, ability to incur additional indebtedness.
See Note 4 of Notes to Financial Statements.
25
<PAGE>
Credit Facilities.
In August 1996, the Company consummated a $100.0 million reducing revolving line
of credit, with an initial borrowing base of $60.0 million and a $5.0 million
term loan. The proceeds from the initial borrowings were used to refinance the
existing indebtedness of the Company and Alexander. On November 1, 1996 this
facility was paid off with a portion of the proceeds from the Notes.
Simultaneously, the Company entered into amendments with respect to the Credit
Facility. The Credit Facility is a revolving line of credit with an initial
borrowing base of $25.0 million, $10.0 million of which may only be used to make
acquisitions of producing oil and natural gas properties. The Credit Facility
contains certain covenants, including maintenance of a minimum interest coverage
ratio, a current ratio and a minimum tangible net worth. See Note 3 of Notes to
the Consolidated Financial Statements.
Preferred Stock.
In June 1994, the Company consummated the sale of $5.0 million of Series B
Preferred Stock. Fifty thousand shares of Series B Preferred Stock were sold by
the Company at $100 per share. The Series B Preferred Stock is convertible into
shares of Common Stock at a conversion price of $1.625 per share.
In June 1995, the Company consummated the sale of $4.0 million of Series C
Preferred Stock. Fifty thousand shares of Series C Preferred Stock were sold by
the Company at $100 per share. The Series C Preferred Stock is convertible into
shares of Common Stock at a conversion rate of $2.00 per share. The Series B
Preferred Stock and Series C Preferred Stock require that dividends be paid on
the Series B Preferred Stock and Series C Preferred Stock before any dividends
are paid on Common Stock.
In August 1996, the Company completed the sale of 100,000 shares of Series D
Preferred Stock for $10.0 million and 50,000 shares of Series E Preferred Stock
for $5.0 million. The Series D Preferred Stock and Series E Preferred Stock are
convertible into shares of Common Stock at a conversion price of $2.25 per
share. In conjunction therewith, the Company agreed to extend the date at which
it may first redeem its Series B and Series C convertible Preferred Stocks from
June 14, 1997 to June 14, 1999.
See Note 6 of Notes to Consolidated Financial Statements.
Financial Reporting Impact of Full Cost Method of Accounting.
The Company follows the full cost method of accounting for 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 year. 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
and yearly basis. The excess, if any, of the net book value above the ceiling is
required to be written off as a non-cash expense. As a result of allocating
additional cost, under the purchase method of accounting, to the oil and natural
gas properties in connection with the Merger, the Company recognized a noncash
write down of its oil and natural gas properties of approximately $28.3 million,
net of deferred taxes. The amount of the actual write down was charged to
expense in the third quarter of 1996, the period in which the Merger was
consummated. At December 31, 1996, the ceiling exceeded the net book value of
the Company's oil and natural gas properties by approximately $75.0 million
based on the weighted average prices of crude oil and natural gas, received by
the Company at that date, of $25.36 per barrel and $3.72 per mcf, respectively.
At March 25, 1997, the price of crude oil and natural gas had declined to $20.99
per barrel and $1.88 per mcf as quoted on the Mercantile Exchange for oil and
the New York Mercantile Exchange for natural gas. Sustained decreases in oil and
natural gas prices could result in additional write downs during 1997 or future
periods.
26
<PAGE>
Changes in Prices and Inflation.
The Company's revenues and value of its oil and natural gas properties have been
and will continue to be affected by changes in oil and gas prices. Oil and gas
prices are subject to seasonal and other fluctuations that are beyond the
Company's ability to control or predict.
During 1995 and 1996, the Company hedged crude oil and natural gas prices
through the use of commodity swap agreements in an effort to reduce the effects
of the volatility of the price of crude oil and natural gas on the Company's
operations. These agreements involve the receipt of fixed-price amounts in
exchange for variable payments based on NYMEX prices and specific volumes. In
connection with the commodity swap agreements, the Company may also enter into
basis swap agreements to reduce the effects of unusual fluctuations between
prices actually received at the wellhead and NYMEX prices. Through the use of
commodity price and basis swap agreements, the Company can fix the price to be
received for specified volumes of production to the commodity swap price less
the basis swap price. The differential to be paid or received, under the swap
agreement, is accrued in the month of the related production and recognized as a
component of crude oil and natural gas sales. The Company does not hold or issue
financial instruments for trading purposes.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. All hedging
is accomplished pursuant to swap agreements based upon standard forms. The
Company addresses market risk by selecting instruments whose value fluctuations
correlate strongly with the underlying commodity being hedged. Credit risk
related to hedging activities is managed by requiring minimum credit standards
for counter parties, periodic settlements, and market to market valuations. The
Company has not been required to provide collateral relating to hedging
activities. At December 31, 1996, the Company had no hedging or basis swap
agreements outstanding. During 1996, the Company recognized a net gain of
$20,315 related to hedging transactions.
Although certain of the Company's costs and expenses are affected by the level
of inflation, inflation has not had a significant effect on the Company's
results of operations during the years ended December 31, 1994, 1995 and 1996.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The Financial Statements of the Company required by this Item 8 are
included as part of Item 14(a)(1) hereof.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this Item 10 is set forth in the sections entitled
"Election of Directors" and "Certain Relationships and Related Transactions -
Section 16 Reporting" in the Company's definitive proxy statement for its 1997
Annual Meeting of Shareholders (the "Proxy Statement"), and is incorporated
herein by reference.
27
<PAGE>
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item 11 is set forth in the section entitled
"Executive Compensation" in the Company's Proxy Statement, and is incorporated
herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this Item 12 is set forth in the section entitled
"Security Ownership of Certain Beneficial Owners and Management" in the
Company's Proxy Statement, and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this Item 13 is set forth in the section entitled
"Certain Relationships and Related Transactions" in the Company's Proxy
Statement, and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as part of this report.
1. Financial Statements: See Index to Financial Statements and Financial
Statement Schedules on page F-1 of this report .
2. Financial Statement Schedules: See Index to Financial Statement Schedules
on page F-1 of this report.
3. Exhibits: The following documents are filed as exhibits to this report.
2.1 Agreement and Plan of Merger, dated June 6, 1996, among the Company,
NEG-OK, Inc. ("NEG OK"), and Alexander Energy Corporation ("Alexander")(1)
2.2 First Amendment to Agreement and Plan of Merger, dated as of June 20,
1996, among the Company, NEG-OK and Alexander(2)
2.3 Mutual Waiver Agreement dated as of August 29, 1996 by and among the
Company, NEG-OK and Alexander(3)
3.1 Certificate of Incorporation of the Company, which includes the
Certificate of Incorporation of the Company filed with the Secretary of State of
Delaware on November 20, 1990(4), the Certificate of Elimination of the
Redeemable Convertible Preferred Stock, Series A of the Company, filed with the
office of the Secretary of State of the State of Delaware on June 2, 1994(3),
the Certificate of Amendment of Certificate of Incorporation of the Company,
filed with the office of the Secretary of State of the State of Delaware on
August 29, 1996(3), the Certificate of Designations of the Company of 10%
Cumulative Convertible Preferred Stock, Series B(5), the Certificate of
Designations of the Company of 10 1/2% Cumulative Convertible Preferred Stock,
Series C(6), the Certificate of Designations of the Company of Convertible
Preferred Stock, Series D(3), and the Certificate of Designations of the Company
of Convertible Preferred Stock, Series E(3)
3.2 By-laws of the Company(4)
4.1 Certificate of Designations of the Company of 10% Cumulative
Convertible Preferred Stock, Series B(5)
4.2 Certificate of Designations of the Company of 10 1/2% Cumulative
Convertible Preferred Stock, Series C(6)
28
<PAGE>
4.3 Certificate of Designations of the Company of Convertible Preferred
Stock, Series D(3)
4.4 Certificate of Designations of the Company of Convertible Preferred
Stock, Series E(3)
4.5 Note Agreement dated as of April 25, 1989, by and among AEJH 1989
Limited Partnership, Alexander and John Hancock Mutual Life Insurance (10 1/2%
Senior Secured Notes)(8)
4.6 Letter dated August 29, 1996 between Alexander and John Hancock Mutual
Life Insurance Company relating to the payment of the 1989 Notes(3)
4.7 Indenture dated as of November 1, 1996, among the Company, National
Energy Group of Oklahoma, Inc. (the "Guarantor"), formerly NEG-OK, and Bank One,
Columbus, N.A.(9)
10.1 Crude Oil Purchase Contract, dated November 30, 1992, between the
Company and Plains Liquids Transport Inc.(10)
10.2 Amendment to Crude Oil Purchase Contract, dated November 17, 1993,
between the Company and Plains Liquids Transport, Inc.(5)
10.3 Crude Oil Purchase Contract, dated February 8, 1993, between the
Company and Plains Marketing and Transportation Inc. and the predecessor
contract, the Crude Oil Purchase Contract, dated November 12, 1991, between
Sunnybrook Transmission, Inc. and TriSearch Inc.(10)
10.4 Stock Purchase Agreement, dated as of June 2, 1994, among the Company,
Arbco Associates L.P., Offense Group Associates L.P., Kayne, Anderson
Nontraditional Investments L.P., and Opportunity Associates L.P.(5)
10.5 Gaines Berland, Inc. Warrant, dated January 27, 1995(1)
10.11 Purchase and Sale Agreement, dated as of March 29, 1995, between the
Company and Enron Oil and Gas Company(6)
10.12 Agreement for Purchase and Sale (Oak Hill), dated April 12, 1995,
between the Company and Sierra 1994 I Limited Partnership(6)
10.13 Agreement for Purchase and Sale (Mustang Island), dated April 20,
1995, between the Company and Sierra Mineral Development, L.C.(6)
10.14 Stock Purchase Agreement, dated as of June 14, 1995, among the
Company, Arbco Associates L.P., Offense Group Associates L.P., Kayne, Anderson
Nontraditional Investments L.P., and Opportunity Associates L.P.(6)
10.15 Executive Employment Agreement, dated January 1, 1996, between the
Company and Miles D. Bender(11)
10.16 Executive Employment Agreement, dated January 1, 1996, between the
Company and R. Thomas Fetters, Jr.(11)
10.17 Agreement, dated January 1, 1996, between the Company and Randall A.
Carter(11)
10.18 Agreement, dated January 1, 1996, between the Company and Robert A.
Imel(11)
10.19 Executive Employment Agreement, dated January 1, 1996, between the
Company and Melissa Rutledge(11)
10.20 Executive Employment Agreement, dated January 1, 1996, between the
Company and William T. Jones(11)
29
<PAGE>
10.22 Executive Employment Agreement, dated June 6, 1996, between the
Company and David E. Grose(1)
10.23 Executive Employment Agreement, dated June 5, 1996, between the
Company and Sue Barnard(1)
10.24 Executive Employment Agreement, dated June 6, 1996, between the
Company and Jim L. David(1)
10.25 Employment Agreement, dated June 6, 1996, between the Company and Bob
G. Alexander(1)
10.26 Employment Agreement, dated June 6, 1996, between the Company and
Roger G. Alexander(1)
10.29 Prudential Securities Incorporated Warrant to Purchase 100,000 Shares
of the Company's Common Stock(3)
10.30 Gaines Berland, Inc. Warrant to Purchase 300,000 Shares of the
Company's Common Stock(3)
10.31 Gaines Berland, Inc. Warrant to Purchase 700,000 Shares of the
Company's Common Stock(3)
10.32 Agreement dated January 1, 1996 between the Company and Sandefer Oil
& Gas, Inc.(1)
10.33 Consulting Agreement dated January 1, 1996 between the Sandefer Oil &
Gas, Inc. and Potosky Oil & Gas, Inc. and Atocha Exploration, Inc.(1)
10.34 Stock Purchase Agreement dated August 7, 1996 between the Company and
High River Limited Partnership(2)
10.35 High River Limited Partnership Warrant to purchase 700,000 Shares of
Common Stock, dated August 29, 1996(3)
10.36 Stock Purchase Agreement dated as of August 26, 1996, between the
Company and Foremost Insurance Company, Arbco Associates, L.P., Kayne, Anderson
Nontraditional Investments L.P., Offense Group Associates, L.P., Topa Insurance
Company and Kayne, Anderson Offshore Limited (the "Series E Investors")(3)
10.37 Form of Series E Investors' Warrants to purchase an aggregate 350,000
Shares of Common Stock, dated August 29, 1996(3)
10.38 Agreement dated as of August 29, 1996 by and between the Company and
Prudential Securities Incorporated(3)
10.40 Restated Loan Agreement dated August 29, 1996 among Bank One and
Credit Lyonnais New York Branch ("Credit Lyonnais") and the Company, NEG-OK and
Boomer Marketing Corporation ("Boomer")(3)
10.41 $50,000,000 Revolving Note dated August 29, 1996 payable to Bank
One(3)
10.42 $50,000,000 Revolving Note dated August 29, 1996 payable to Credit
Lyonnais(3)
10.43 $2,500,000 Term Note dated August 29, 1996 payable to Bank One(3)
10.44 $2,500,000 Term Note dated August 29, 1996 payable to Credit
Lyonnais(3)
10.45 Unlimited Guaranty of NEG-OK dated August 29, 1996 for the benefit of
Bank One(3)
10.46 Unlimited Guaranty of NEG-OK, dated August 29, 1996 for the benefit
of Credit Lyonnais(3)
10.47 Unlimited Guaranty of Boomer dated August 29, 1996 for the benefit of
Bank One(3)
30
<PAGE>
10.48 Unlimited Guaranty of Boomer dated August 29, 1996 for the benefit of
Credit Lyonnais(3)
10.49 Form of Deeds of Trust, Mortgages, Security Agreements, Assignments
of Production and Financing Statements covering oil and gas properties of the
Company and NEG-OK, dated August 29, 1996(3)
10.50 Sale and Purchase Agreement dated September 26, 1994 by and among JMC
Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and Alexander(12)
10.51 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 Alexander(12)
10.52 Alexander Energy Corporation 1986 Incentive Stock Option Plan, as
amended(13)
10.53 Alexander Energy Corporation 1993 Stock Option Plan(14)
10.54 Agreement of Limited Partnership of AEJH 1985 Limited Partnership by
and between Alexander and John Hancock Mutual Life Insurance Company, together
with all amendments thereto(15)
10.55 Agreement of Limited Partnership of AEJH 1987 Limited Partnership by
and between Alexander and John Hancock Mutual Life Insurance Company, together
with all amendments thereto(15)
10.56 Agreement of Limited Partnership of AEJH 1989 Limited Partnership by
and between Alexander and John Hancock Mutual Life Insurance Company dated April
25, 1989(8)
10.57 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(15)
10.58 Warrant Purchase Agreement among Alexander, Hanifen, Imhoff Inc. and
The Principal/Eppler, Guerin & Turner, Inc.(16)
10.59 Purchase Option Agreement (warrants) between American National Energy
Corporation and Gaines, Berland, Inc. dated September 14, 1993(8)
10.60 Form of Special Severance Agreements between Alexander and the
technical support staff of Alexander, between NEG-OK and Cyndy Burris and John
Christofferson, respectively(8)
10.61 Separation Policy of Alexander dated December 8, 1994(8)
10.62 Asset Purchase and Sale Agreement dated September 30, 1996 by and
between the Company and Araxas Energy Corporation, Araxas SPV-1, Inc., Araxas
Exploration, Inc. and O'Sullivan Oil and Gas Company, Inc.(9)
10.63 Purchase Agreement dated October 29, 1996, by and among the Company,
Guarantor and Bear, Stearns & Co. Inc., Smith Barney Inc. and Jefferies &
Company, Inc. (the "Initial Purchasers")(9)
10.64 Registration Rights Agreement dated October 29, 1996, by and among
the Company, Guarantor and the Initial Purchasers(9)
10.65 First Amendment to Restated Loan Agreement dated October 31, 1996
among Bank One and Credit Lyonnais and the Company, Guarantor and Boomer (9)
23.1 Consent of Ernst & Young LLP, Independent Auditors (18)
23.2 Consent of Netherland, Sewell & Associates, Inc., Independent
Petroleum Engineers (18)
27.1 Financial Data Schedule(17)
31
<PAGE>
99.39 Certificate of Merger with respect to the merger of Alexander with
and into NEG-OK, filed with the offices of the Secretary of State of the State
of Delaware and the Secretary of State of the State of Oklahoma on August 29,
1996(3)
---------------
(1) Incorporated by reference to the Company's Registration Statement on Form
S-4 (No. 333-9045), dated July 29, 1996.
(2) Incorporated by reference to Amendment No. 1 to the Company's Registration
Statement on Form S-4 (No. 333-9045), dated August 7, 1996.
(3) Incorporated by reference to the Company's Current Report on Form 8-K,
dated August 29, 1996.
(4) Incorporated by reference to the Company's Registration Statement on Form
S-4 (No. 33-38331), dated April 23, 1991.
(5) Incorporated by reference to the Company's Current Report on Form 8-K,
dated June 17, 1994.
(6) Incorporated by reference to the Company's Current Report on Form 8-K,
dated July 17, 1995.
(7) Incorporated by reference to the Company's Registration Statement on Form
S-3 (No. 33-81172), dated July 27, 1994.
(8) Incorporated by reference to Alexander's Form 10-K for the fiscal year
ended December 31, 1994.
(9) Incorporated by reference to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1996.
(10) Incorporated by reference to the Company's Annual Report on Form 10-KSB for
the year ended December 31, 1992.
(11) Incorporated by reference to the Company's Annual Report on Form 10-KSB for
the year ended December 31, 1995.
(12) Incorporated by reference to Alexander's Current Report on Form 8-K, dated
November 14, 1994.
(13) Incorporated by reference to Alexander's Registration Statement (No.
33-20425), dated March 22, 1988.
(14) Incorporated by reference to Alexander's Proxy Statement for the 1993
Annual Meeting of Stockholders.
(15) Incorporated by reference to Alexander's Form 10-K for the fiscal year
ended December 31, 1991.
(16) Incorporated by reference to Alexander's Amendment No. 1 to Registration
Statement (No. 33-57142), dated February 26, 1993.
(17) The Financial Data Schedule, for the year ended December 31, 1996, is filed
herewith for EDGAR filings only.
(18) Filed herewith.
-------------
(b) No reports on Form 8-K were filed dring the last quarter of 1996.
32
<PAGE>
GLOSSARY
Wherever used herein, the following terms shall have the meanings specified.
Bbl - One stock tank barrel, or 42 US gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf - One billion cubic feet.
Bcfe - One billion cubic feet of natural gas equivalent.
Behind the Pipe - Hydrocarbons in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending the
production of hydrocarbons from another formation penetrated by the well bore.
The hydrocarbons are classified as proved but non-producing reserves.
Boe - Barrels of oil equivalent (converting six Mcf of natural gas to one
Bbf of oil).
Developed Acreage - Acres which are allocated or assignable to producing
wells or wells capable of production.
Development Well - A well drilled within the proved are of an oil and
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry Well - A well found to be incapable of producing either oil or natural
gas in sufficient quantities to justify completion as an oil or natural gas
well.
EBITDA - Earnings (excluding discontinued operations, extraordinary items,
charges resulting from changes in accounting and significant nonrecurring
revenues and expenses) before interest expense, income taxes, depletion,
depreciation and amortization, and the provision for impairment of oil and
natural gas properties. EBITDA is not a measure of cash flow as determined my
generally accepted accounting principles. EBITDA information has been included
in this Prospectus because EBITDA is a measure used by certain investors in
determining historical ability to service indebtedness. EBITDA should not be
considered as an alternative to, or more meaningful than, net income or cash
flows as determined in accordance with generally accepted accounting principles
as an indicator of operating performance or liquidity.
Exploratory Well - A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a know
reservoir.
Gross Acres or Gross Wells - The total acres or wells, as the case may be,
in which a working interest is owned.
Infill Well - A well drilled between known producing wells to better wells
to better exploit the reservoir.
Mbbl - One thousand Bbl.
Mmbbl - One million Bbl.
Mboe - One thousand barrels of oil equivalent.
Mcf - One thousand cubic feet.
Mcfe - One thousand cubic feet of natural gas equivalent, using the ratio
of one Bbl of crude oil to six Mcf of natural gas.
Mmcf - One million cubic feet of natural gas equivalent.
33
<PAGE>
Net Acres or Net Wells - The sum of the fractional working interests owned
in gross acres or gross wells.
NYMEX - New York Mercantile Exchange.
Oil and Natural Gas Lease - An instrument by which a mineral fee owner
grants to a lessee the right for a specific period of time to explore for oil
and natural gas underlying the lands covered by the lease and the right to
product any oil and natural gas so discovered generally for so long as there is
production in economic quantities from such lands.
Overriding Royalty Interest - A fractional undivided interest in an oil and
natural gas property entitling the owner to a share of oil and natural gas
production, in addition to the usual royalty paid to the owner, free of costs of
production.
PDNP - Proved developed, nonproducing or behind the pipe reserves.
Productive Well - A well that is producing oil or natural gas or that is
capable of production.
Proved Developed Reserves - Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves - The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped Reserves or PUD - Reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for completion.
PV 10% - The discounted future net cash flows for proved oil and natural
gas reserves computed on the same basis as the Standardized Measure, but without
deducting income taxes, which is not in accordance with generally accepted
accounting principles. PV 10% is an important financial measure for evaluating
the relative significance of oil and natural gas properties and acquisitions,
but should not be construed as an alternative to the Standardized Measure (as
determined in accordance with generally accepted accounting principles).
Royalty Interest - An interest in an oil and natural gas property entitling
the owner to a share of oil and natural gas production free of costs of
production.
SEC - Securities and Exchange Commission.
Secondary Recovery - A method of oil and natural gas extraction in which
energy sources extrinsic to the reservoir are utilized.
Standardized Measure - The estimated future net cash flows from proved oil
and natural gas reserves computed using prices and costs, at the date indicated,
after income taxes and discounted at 10%.
Undeveloped Acreage - Lease acreage 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 such acreage contains proved
reserves.
Working Interest - The operating interest which gives the owner the right
to drill, produce and conduct operating activities on the property and a share
of production, subject to all royalties, overriding royalties and other burdens
and to all costs of exploration, development and operations and all risks in
connection therewith.
34
<PAGE>
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 its
behalf by the undersigned, thereunto duly authorized.
NATIONAL ENERGY GROUP, INC.
By: /s/ Miles D. Bender March 31, 1997
-------------------
Miles D. Bender
President and Chief Executive Officer
By: /s/ Robert A. Imel March 31, 1997
------------------
Robert A. Imel
Chief Financial Officer and
Senior Vice President
By: /s/ Melissa H. Rutledge March 31, 1997
-----------------------
Melissa H. Rutledge
Controller and Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed by the following persons on behalf of the registrant and in the
capacities on March 31, 1997
By: /s/Miles D. Bender
------------------
Miles D. Bender
President,
Chief Executive Officer
and Director
By: /s/George B. McCullough
-----------------------
George B. McCullough
Chairman of the Board
and Director
By: /s/Norman C. Miller
-------------------
Norman C. Miller
Chairman, Executive
Committee and Director
By: /s/ Robert H. Kite
------------------
Robert H. Kite
Director
By: /s/George M. McDonald
---------------------
George M. McDonald
Director
By: /s/Robert V. Sinnott
--------------------
Robert V. Sinnott
Director
By: /s/Elwood W. Schafer
--------------------
Elwood W. Schafer
Director
By: /s/Bob G. Alexander
-------------------
Bob G. Alexander
Director
By: /s/Jim L. David
---------------
Jim L. David
Vice President -
Exploitation and Director
By: /s/Robert A. West
-----------------
Robert A. West
Director
By: /s/Robert J. Mitchell
---------------------
Robert J. Mitchell
Director
35
<PAGE>
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
FINANCIAL STATEMENTS Page
------
Report of Independent Auditors........................................ F-2
Balance Sheets at December 31, 1995 and 1996.......................... F-3
Statements of Operations for the years ended December 31, 1994,
1995 and 1996...................................................... F-4
Statements of Cash Flows for the years ended December 31, 1994,
1995 and 1996...................................................... F-5
Statements of Changes in Stockholders' Equity for the years
ended December 31, 1994, 1995 and 1996............................. F-6
Notes to Financial Statements......................................... F-8
FINANCIAL STATEMENT SCHEDULES
All schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and therefore have been omitted.
F-1
<PAGE>
REPORT OF INDEPENDENT AUDITORS
The Board of Directors
National Energy Group, Inc.
We have audited the accompanying balance sheets of National Energy Group,
Inc., as of December 31, 1995 and 1996, and the related statements of
operations, changes in stockholders' equity, and cash flows for each of the
three years in the period ended December 31, 1996. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of National Energy Group, Inc.,
at December 31, 1995 and 1996, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1996, in
conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Dallas, Texas
March 18, 1997
F-2
<PAGE>
NATIONAL ENERGY GROUP, INC.
BALANCE SHEETS
<TABLE>
<CAPTION>
December 31,
1995 1996
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................................................... $ 6,076,199 $14,182,246
Marketable securities........................................................ 1,824,724 --
Accounts receivable-- oil and gas sales...................................... 1,407,349 6,812,358
Accounts receivable-- joint interest and other............................... 262,619 3,003,661
Other........................................................................ 335,751 1,131,736
------------ ------------
Total current assets............................................................ 9,906,642 25,130,001
Oil and gas properties, at cost (full cost method):
Proved oil and gas properties................................................ 37,493,394 169,863,109
Unproved oil and gas properties.............................................. 707,913 24,682,425
------------ ------------
38,201,307 194,545,534
Accumulated depreciation, depletion, and amortization........................... 5,366,293 15,039,999
------------ ------------
Net oil and gas properties...................................................... 32,835,014 179,505,535
Other property and equipment.................................................... 372,395 2,869,227
Accumulated depreciation........................................................ 236,278 347,841
------------ ------------
Net other property and equipment................................................ 136,117 2,521,386
Other assets, net............................................................... 613,593 4,878,234
------------ ------------
Total assets.................................................................... $43,491,366 $212,035,156
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable-- trade..................................................... $ 3,649,906 $ 12,012,655
Accounts payable-- revenue and other......................................... 984,299 7,281,271
Accounts payable-- broker margin............................................. 978,656 --
Accrued merger costs......................................................... -- 1,462,724
Accrued interest............................................................. 128,938 1,791,667
Note payable and current portion of long-term debt........................... 6,500,000 --
------------ ------------
Total current liabilities....................................................... 12,241,799 22,548,317
Other long-term liabilities..................................................... -- 1,786,813
Long-term debt, less current portion............................................ 13,475,000 --
10 3/4% Senior Notes due 2006................................................... -- 100,000,000
Deferred income taxes........................................................... -- 7,273,829
Stockholders' equity:
Convertible preferred stock, $1.00 par:
Authorized shares 1,000,000
Issued and outstanding shares -- 92,500 and 242,500 at December 31, 1995 and
1996, respectively
Aggregate liquidation preference -- $9,250,000 and $24,250,000 at December 31,
1995 and 1996, respectively.............................................. 92,500 242,500
Common stock, $.01 par value:
Authorized shares -- 50,000,000 and 100,000,000 at December 31, 1995 and 1996,
respectively
Issued and outstanding shares -- 11,880,125 and 35,977,140 at December 31,
1995 and 1996, respectively.............................................. 118,801 359,771
Additional paid-in capital................................................... 21,485,224 110,293,386
Unrealized loss on marketable securities, net................................ (247,492) --
Deficit...................................................................... (3,674,466) (30,469,460)
------------ ------------
Total stockholders' equity...................................................... 17,774,567 80,426,197
------------ ------------
Total liabilities and stockholders' equity...................................... $43,491,366 $212,035,156
============ ============
</TABLE>
See accompanying notes.
F-3
<PAGE>
NATIONAL ENERGY GROUP, INC.
STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year ended December 31,
1994 1995 1996
------------ ------------ -----------
<S> <C> <C> <C>
Revenue:
Oil and gas sales............................................... $3,158,716 $ 7,858,316 $24,319,398
Well operator fees.............................................. 157,845 136,943 876,247
----------- ------------ -----------
3,316,561 7,995,259 25,195,645
Costs and expenses:
Lease operating................................................. 1,207,251 1,732,124 3,740,525
Oil and gas production taxes.................................... 176,320 415,867 1,285,410
Depreciation, depletion, and amortization....................... 1,029,986 3,149,464 9,795,283
Writedown of oil and gas properties............................. -- -- 43,497,000
General and administrative...................................... 984,304 1,771,372 3,034,146
----------- ------------ -----------
3,397,861 7,068,827 61,352,364
----------- ------------ -----------
Operating income (loss)............................................ (81,300) 926,432 (36,156,719)
Interest expense................................................... (517,086) (1,032,096) (4,212,564)
Interest income and other, net..................................... 109,017 90,875 426,021
Gain (loss) on sale of marketable securities....................... -- 220,582 (117,955)
----------- ------------ -----------
Income (loss) before income taxes.................................. (489,369) 205,793 (40,061,217)
Benefit for income taxes........................................... -- -- (14,503,595)
----------- ------------ ------------
Income (loss) before extraordinary item............................ (489,369) 205,793 (25,557,622)
Extraordinary loss on early extinguishments of debt................ (121,917) (431,762) (292,372)
----------- ------------ -----------
Net loss........................................................... $(611,286) $ (225,969)$(25,849,994)
============ ============= ============
Loss per common share:
Loss before extraordinary item.................................. $ (.09) $ (.05) $ (1.33)
============ ============= ============
Net loss........................................................ $ (.10) $ (.09) $ (1.34)
============ ============= ============
Weighted average number of common and common equivalent
shares outstanding.............................................. 8,476,821 10,701,635 19,939,975
============ ============= ============
</TABLE>
See accompanying notes.
F-4
<PAGE>
NATIONAL ENERGY GROUP, INC.
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year ended December 31,
1994 1995 1996
------------- ------------- --------------
<S> <C> <C> <C>
Operating Activities
Net loss............................................................. $ (611,286) $ (225,969) $(25,849,994)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depreciation, depletion, and amortization....................... 1,029,986 3,149,464 9,795,283
Writedown of oil and gas properties............................. -- -- 43,497,000
Amortization of loan costs...................................... 19,114 21,060 151,063
Amortization of deferred compensation........................... 41,694 39,809 36,083
Benefit for deferred income taxes............................... -- -- (14,503,595)
Extraordinary loss on early extinguishment of debt.............. 121,917 431,762 292,372
Common stock, options, and warrants issued for services......... 64,290 104,614 216,206
Loss (gain) on sale of marketable securities.................... -- (220,582) 117,955
Changes in operating assets and liabilities excluding
effects of business acquisitions:
Accounts receivable......................................... (217,192) (784,668) (4,729,262)
Accounts receivable from related parties.................... -- 23,999 --
Other current assets........................................ (101,530) (108,615) (320,601)
Accounts payable and accrued liabilities.................... 26,299 425,626 3,085,455
------------ ------------ -------------
Net cash provided by operating activities............................ 373,292 2,856,500 11,787,965
------------ ------------ -------------
Investing Activities
Purchases of marketable securities................................... (1,081,041) (2,917,659) (9,008)
Proceeds from sale of marketable securities.......................... 35,176 2,111,890 1,675,669
Proceeds from broker margin.......................................... -- 978,656 --
Purchases of other property and equipment............................ (48,632) (42,950) (1,553,355)
Oil and gas acquisition, exploration, and development expenditures... (2,849,508) (16,912,919) (46,945,872)
Acquisition of Alexander Energy Corporation, net of cash acquired of -- -- (2,455,993)
$1,332,444........................................................
Proceeds from sales of oil and gas properties........................ 90,500 69,306 --
Other ............................................................... 41,471 (11,963) 11,638
------------ ------------- -------------
Net cash used in investing activities................................ (3,812,034) (16,725,639) (49,276,921)
------------ ------------ -------------
Financing Activities
Proceeds from issuance of 10 3/4% Notes due 2006, net................ -- -- 96,059,119
Proceeds from issuance of long-term debt, net........................ 5,691,366 17,514,077 69,026,613
Proceeds from issuance of note payable............................... -- 3,000,000 8,000,000
Repayments of long-term debt......................................... (4,200,000) (6,875,000) (130,510,233)
Repayments of note payable........................................... -- -- (11,000,000)
Repayments of other long-term liabilities............................ (77,571) -- (534,815)
Proceeds from exercise of stock options and warrants................. 35,938 467,987 499,704
Proceeds from issuance of convertible preferred stock, net........... 4,436,372 3,980,343 15,000,000
Preferred stock dividends............................................ (14,705) (735,000) (945,000)
Payments for redemption of fractional shares......................... (477) (714) (385)
------------ ------------ -------------
Net cash provided by financing activities............................ 5,870,923 17,351,693 45,595,003
------------ ------------ -------------
Increase in cash and cash equivalents................................ 2,432,181 3,482,554 8,106,047
Cash and cash equivalents at beginning of period..................... 161,464 2,593,645 6,076,199
------------ ------------ -------------
Cash and cash equivalents at end of period........................... $2,593,645 $ 6,076,199 $ 14,182,246
============ ============ =============
Supplemental Cash Flow Information
Interest paid in cash................................................ $ 457,949 $ 983,075 $ 2,549,835
============ ============ =============
</TABLE>
See accompanying notes.
F-5
<PAGE>
NATIONAL ENERGY GROUP, INC.
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Common Stock
Issuable
Convertible Under Asset
Preferred Stock Common Stock Acquisition
Shares Amount Shares Amount Agreement
------ ------ ------ ------ ---------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1993...... -- $ -- 7,844,732 $ 78,447 $ 97,910
Common stock issued upon
exercise of options........... -- -- 62,500 625 --
Common stock issued or issuable
under asset acquisition
agreements................... -- -- 200,000 2,000 38,125
Issuance of Series B Preferred
Stock........................ 50,000 50,000 -- -- --
Common stock issued for services -- -- 60,250 602 --
Common stock issued upon
conversion
of Series A Preferred Stock.. -- -- 425,000 4,250 --
Common stock issued on
conversion of long-term debt -- -- 415,054 4,151 --
Unrealized gain on marketable
securities................... -- -- -- -- --
Preferred stock dividends...... 2,500 2,500 -- -- --
Net loss....................... -- -- -- -- --
---------- ---------- ----------- ---------- -----------
Balance at December 31, 1994...... 52,500 52,500 9,007,536 90,075 136,035
Common stock issued upon
exercise of options and warrants -- -- 327,992 3,280 --
Common stock issued under asset
acquisition agreement........ -- -- 300,000 3,000 (136,035)
Common stock and warrants
issued for services.......... -- -- 13,000 130 --
Common stock issued upon
conversion of Class B Common
Stock........................ -- -- 1,166,796 11,668 --
Common stock and warrants
issued to acquire interests
in oil and gas properties -- -- 1,064,801 10,648 --
Issuance of Series C Preferred
Stock........................ 40,000 40,000 -- -- --
Preferred stock dividends...... -- -- -- -- --
Unrealized loss on marketable
securities................... -- -- -- -- --
Net loss....................... -- -- -- -- --
---------- ---------- ----------- ---------- -----------
Balance at December 31, 1995...... 92,500 92,500 11,880,125 118,801 --
</TABLE>
<TABLE>
<CAPTION>
Gain (Loss)
Additional on Available Total
Paid-In for-Sale Stockholders'
Capital Securities Deficit Equity
------- ---------- ------- ------
<S> <C> <C> <C> <C>
Balance at December 31, 1993...... $ 7,980,992 $ -- $(1,837,506) $ 6,319,843
Common stock issued upon
exercise of options.......... 35,313 -- -- 35,938
Common stock issued or issuable
under asset acquisition
agreements................... 123,000 -- -- 163,125
Issuance of Series B Preferred
Stock........................ 4,386,372 -- -- 4,436,372
Common stock issued for services 51,908 -- -- 52,510
Common stock issued upon
conversion...................
of Series A Preferred Stock.. 420,720 -- -- 424,970
Common stock issued on
conversion of long-term debt. 380,311 -- -- 384,462
Unrealized gain on marketable
securities................... -- 136,285 -- 136,285
Preferred stock dividends...... 247,500 -- (264,705) (14,705)
Net loss....................... -- -- (611,286) (611,286)
------------- ----------- ------------- -------------
Balance at December 31, 1994...... 13,626,116 136,285 (2,713,497) 11,327,514
F-6
<PAGE>
Common stock issued upon
exercise of options and warrants 464,707 -- -- 467,987
Common stock issued under asset
acquisition agreement........ 133,035 -- -- --
Common stock and warrants
issued for services.......... 79,203 -- -- 79,333
Common stock issued upon
conversion of Class B Common
Stock........................ (11,668) -- -- --
Common stock and warrants
issued to acquire interests
in oil and gas properties.... 3,269,003 -- -- 3,279,651
Issuance of Series C Preferred
Stock........................ 3,924,828 -- -- 3,964,828
Preferred stock dividends...... -- -- (735,000) (735,000)
Unrealized loss on marketable
securities................... -- (383,777) -- (383,777)
Net loss....................... -- -- (225,969) (225,969)
------------- ----------- ------------- -------------
Balance at December 31, 1995...... 21,485,224 (247,492) (3,674,466) 17,774,567
</TABLE>
F-7
<PAGE>
NATIONAL ENERGY GROUP, INC.
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (CONTINUED)
<TABLE>
<CAPTION>
Common Stock
Issuable
Convertible Under Asset
Preferred Stock Common Stock Acquisition
Shares Amount Shares Amount Agreement
------ ------ ------ ------ ---------
<S> <C> <C> <C> <C> <C>
Common stock issued upon
exercise of options and warrants -- $ -- 351,242 $ 3,513 $ --
Common stock, options, and
warrants issued for services..... -- -- 50,000 500 --
Common stock issued to acquire
interests in oil and gas
properties....................... -- -- 2,416,332 24,163 --
Issuance of Series D and E
Convertible Preferred Stock
and related warrants to
purchase common stock............ 150,000 150,000 -- -- --
Common stock, stock options,
and warrants issued or assumed
in acquisition of Alexander
Energy Corporation............... -- -- 21,279,441 212,794 --
Preferred stock dividends.......... -- -- -- -- --
Change in unrealized gain on
marketable securities............ -- -- -- -- --
Net loss........................... -- -- -- -- --
------- -------- ---------- --------- ---------
Balance at December 31, 1996.......... 242,500 $242,500 35,977,140 $359,771 $ --
======= ======== ========== ========= =========
</TABLE>
<TABLE>
<CAPTION>
Unrealized
Gain (Loss)
Additional on Available Total
Paid-In for-Sale Stockholders'
Capital Securities Deficit Equity
------- ---------- ------- ------
<S> <C> <C> <C> <C>
Common stock issued upon
exercise of options and warrants $ 496,191 $ -- $ -- $ 499,704
Common stock, options, and
warrants issued for services..... 215,706 -- -- 216,206
Common stock issued to acquire
interests in oil and gas
properties....................... 8,319,203 -- -- 8,343,366
Issuance of Series D and E
Convertible Preferred Stock
and related warrants to
purchase common stock............ 14,850,000 -- -- 15,000,000
Common stock, stock options,
and warrants issued or assumed
in acquisition of Alexander
Energy Corporation............... 64,927,062 -- -- 65,139,856
Preferred stock dividends.......... -- -- (945,000) (945,000)
Change in unrealized gain on
marketable securities............ -- 247,492 -- 247,492
Net loss........................... -- -- (25,849,994) (25,849,994)
------------- ----------- ------------- ------------
Balance at December 31, 1996.......... $110,293,386 $ -- $(30,469,460) $80,426,197
============= =========== ============= ============
</TABLE>
See accompanying notes.
F-8
<PAGE>
NATIONAL ENERGY GROUP, INC.
NOTES TO FINANCIAL STATEMENTS
December 31, 1996
1. Significant Accounting Policies
Organization and Business
National Energy Group, Inc. (the "Company") was incorporated under the laws
of the State of Delaware on November 20, 1990. The Company is engaged in the
acquisition, development, and production of crude oil and natural gas.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
Cash and Cash Equivalents
Cash and cash equivalents include demand deposits and money-market
investments with maturities of three months or less when purchased. At December
31, 1995 and 1996, all cash and cash equivalents were invested with Bank One,
Texas, N.A. ("Bank One").
Marketable Securities
The Company's marketable securities are classified as available-for-sale.
Available-for-sale securities are carried at fair value, with the unrealized
gains and losses, net of tax, reported as a separate component of stockholders'
equity. Realized gains and losses and declines in value judged to be
other-than-temporary are included in interest income. The cost of securities
sold is based on the specific identification method.
The following is a summary of available-for-sale securities at December 31,
1995 (none in 1996):
<TABLE>
<CAPTION>
Gross Gross
Unrealized Unrealized Estimated
Cost Gains Losses Fair Value
---- ----- ------ ----------
<S> <C> <C> <C> <C>
Common stocks........................... $ 2,072,216 $1,026 $ 248,518 $ 1,824,724
=========== ====== ========= ===========
</TABLE>
The marketable securities were comprised of securities of other independent
oil and gas companies. The common stock of one oil and gas company accounted for
62% of the estimated fair market value of the total marketable securities held
at December 31, 1995.
During the years ended December 31, 1995 and 1996, the Company sold
available-for-sale securities with a fair value at the date of sale of
$2,111,890 and $1,675,669, respectively. The gross realized gains on such sales
totaled $224,443 in 1995 and $9,765 in 1996. The gross realized losses on such
sales totaled $3,861 and $127,720 during 1995 and 1996, respectively.
Accounts Receivable
The Company sells crude oil and natural gas to various customers. In
addition, the Company participates with other parties in the operation of crude
oil and natural gas wells. Substantially all of the Company's accounts
receivable are due from either purchasers of crude oil and natural gas or
participants in crude oil and natural gas
F-9
<PAGE>
NATIONAL ENERGY GROUP, INC.
NOTES TO FINANCIAL STATEMENTS (continued)
December 31, 1996
wells for which the Company serves as the operator. Generally, operators of
crude oil and natural gas properties have the right to offset future revenues
against unpaid charges related to operated wells. Crude oil and natural gas
sales are generally unsecured.
Natural Gas Production Imbalances
The Company accounts for natural gas production imbalances using the sales
method, whereby the Company recognizes revenue on all natural gas sold to its
customers notwithstanding the fact that its ownership may be less than 100% of
the natural gas sold.
Oil and Gas Properties
The Company utilizes the full cost method of accounting for its crude oil
and natural gas properties. Under the full cost method, all productive and
nonproductive costs incurred in connection with the acquisition, exploration,
and development of crude oil and natural gas reserves are capitalized and
amortized on the units-of-production method based upon total proved reserves.
The costs of unproven properties are excluded from the amortization calculation
until the individual properties are evaluated and a determination is made as to
whether reserves exist. Capitalized costs are limited to the aggregate of the
present value of future net reserves plus the lower of cost or fair market value
of unproved properties. Conveyances of properties, including gains or losses on
abandonments of properties, are treated as adjustments to the cost of crude oil
and natural gas properties, with no gain or loss recognized. The Company does
not believe that future costs related to dismantlement, site restoration, and
abandonment costs, net of estimated salvage values, will have a significant
effect on its results of operations or financial position because the salvage
value of equipment and related facilities should approximate or exceed any
future expenditures for dismantlement, restoration, or abandonment. The Company
has not incurred any net expenditures for costs of this nature during the last
two years.
The Company has capitalized internal costs of $158,961, $141,516, and
$487,835 for the years ended December 31, 1994, 1995, and 1996, respectively.
Such capitalized costs include salaries and related benefits of individuals
directly involved in the Company's acquisition, exploration, and development
activities based on the percentage of their time devoted to such activities.
Other Property and Equipment
Other property and equipment includes gas processing and field production
facilities, furniture, fixtures, and other equipment. Such assets are recorded
at cost and are depreciated over their estimated useful lives using the
straight-line method.
Maintenance and repairs are charged against income when incurred; and
renewals and betterments, which extend the useful lives of property and
equipment, are capitalized.
Income Taxes
The Company uses the liability method in accounting for income taxes. Under
the liability method, deferred tax assets and liabilities are determined based
on differences between financial reporting and tax bases of assets and
liabilities and are measured using the enacted tax rates and laws that will be
in effect when the differences are expected to reverse.
Natural Gas Hedging Activities
In 1995 and 1996, the Company hedged natural gas prices through the use of
commodity price swap agreements in an effort to reduce the effects of the
volatility of the price of natural gas on the Company's
F-10
<PAGE>
operations. These agreements involve the receipt of fixed-price amounts in
exchange for variable payments based on NYMEX prices and specific volumes. In
connection with the commodity price swap agreements, the Company may also enter
into basis swap agreements to reduce the effects of unusual fluctuations between
prices actually received at the wellhead and NYMEX prices. Through the use of
commodity price and basis swap agreements, the Company can fix the price to be
received for specified volumes of production to the commodity swap price less
the basis swap price. The differential to be paid or received under the swap
agreement is accrued in the month of the related production and recognized as an
adjustment to oil and gas sales. The Company does not hold or issue financial
instruments for trading purposes.
Stock Options
The Company has elected to follow Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB 25) in accounting for its
employee stock options. Under APB 25, if the exercise price of an employee's
stock options equals or exceeds the market price of the underlying stock on the
date of grant, no compensation expense is recognized.
Earnings (Loss) Per Share
Primary earnings (loss) per common and common equivalent share data is
computed by dividing net income (loss), adjusted for preferred stock dividend
requirements of $264,705, $735,000, and $945,000 for 1994, 1995, and 1996,
respectively, by the weighted average number of common and common equivalent
shares outstanding during each period. Shares issuable upon exercise of options
and warrants are included in the computation of earnings per common and common
equivalent share to the extent that they are dilutive. Fully diluted earnings
(loss) per share computations also assume the conversion of the Company's
preferred stock (Note 5) if such conversion has a dilutive effect.
For the years ended December 31, 1994, 1995, and 1996, neither the common
equivalent shares nor the assumed conversion of the preferred stock had a
dilutive effect on the loss per share calculations. Accordingly, the loss per
share calculations for such periods are based on the weighted average number of
common shares outstanding during each year.
Reclassifications
Certain previously reported amounts have been reclassified to conform with
the current presentation.
2. Acquisitions
During 1994, the Company acquired an additional 17.0% working interest in
the Goldsmith Adobe Unit ("GAU"). Such interest was acquired for $584,095 in
cash. The Company is the operator of the GAU and holds a 91.8% working interest
in the GAU.
In April 1995, the Company purchased a 100% working interest (77% net
revenue interest) in State of Texas Lease No. 69153 and the State Tract 901-S
Field, Nueces County, Texas ("Mustang Island") for $900,000 in cash and 352,500
shares of Common Stock. The cash portion of the acquisition was funded from
available cash.
In June 1995, the Company completed the acquisition of producing gas
properties in the Oak Hill Field ("Oak Hill") in Rusk County, Texas, which is a
component of the Cotton Valley Trend. The consideration paid by the Company for
Oak Hill consisted of $7,200,000 in cash, 612,301 shares of Common Stock and
warrants to purchase 200,000 shares of Common Stock at a price per share of
$2.00. The cash portion of the acquisition was funded primarily by borrowings
under a credit facility with Bank One.
F-11
<PAGE>
In addition, in June 1995, the Company completed the acquisition of
producing oil and gas properties in Eddy County, New Mexico from Enron Oil and
Gas Company (the "Enron Properties") for $2,119,295 in cash. This acquisition
was funded by borrowings under a credit facility with Bank One and available
cash.
The following pro forma data presents the results of the Company for the
years ended December 31, 1994 and 1995, as if the acquisition of Mustang Island,
Oak Hill, and the Enron Properties had occurred on January 1, 1994. The pro
forma results of operations are presented for comparative purposes only and are
not necessarily indicative of the results which would have been obtained had the
acquisitions been consummated as presented. The following data reflect pro forma
adjustments for the oil and gas revenues, production costs, and depreciation and
depletion related to the properties and additional interest on borrowed funds
(in thousands, except per share amounts).
<TABLE>
<CAPTION>
Pro Forma
Year ended December 31,
1994 1995
---------------- -------------
<S> <C> <C>
(Unaudited)
Revenues........................................................... $ 5,051 $ $9,254
=============== ==============
Loss before extraordinary item..................................... $ (573) $ --
=============== ==============
Loss before extraordinary item per common share.................... $ (.06) $ (.06)
=============== ==============
</TABLE>
In January 1996, the Company completed the acquisition of oil and gas
properties in offshore Nueces County, Texas, adjacent to the Company's Mustang
Island property, from C/A Limited, Chartex Petroleum Company, and Petrotex
Engineering Company. The acquisition includes interests in five wells, a
pipeline and separation facility related to Mustang Island. The consideration
for this acquisition consisted of 140,857 shares of the Company's Common Stock
and $675,000 in cash.
In February 1996, the Company completed the acquisition of two oil and gas
wells on one offshore block, interests in five other offshore blocks, and a
related production platform and equipment in offshore Nueces County, Texas,
adjacent to the Company's Mustang Island property, from UMC Petroleum
Corporation (the "UMC Acquisition"). The consideration for this acquisition
consisted of $1.5 million in cash, which was funded primarily from borrowings
under a credit agreement with Bank One.
In April 1996, the Company won exploration rights on 16 offshore tracts
(covering 7,765 acres) in the Mustang Island area in offshore Nueces County,
Texas through successful bids with the State of Texas ("Offshore Lease
Acquisition"). The Company paid $1,437,302 in cash for these rights, and the
purchase was funded by borrowings under a credit facility with BankOne and
available cash.
On August 29, 1996, the Company completed the acquisition of Alexander
Energy Corporation ("Alexander"). The transaction consisted of a merger (the
"Merger") of Alexander with and into National Energy Group of Oklahoma, Inc.,
formerly known as NEG-OK, Inc., a wholly-owned subsidiary of the Company
("NEG-OK"). Pursuant to the Merger, (a) the separate corporate existence of
Alexander terminated, (b) each share of Alexander common stock, par value $.03
per share ("Alexander Common Stock"), together with certain rights associated
with the Alexander Common Stock outstanding immediately before the Merger, were
converted into 1.7 shares of the Company's Common Stock, and (c) all outstanding
options and warrants to purchase Alexander Common Stock were assumed by the
Company and converted into options and warrants to purchase Common Stock. In
lieu of fractional shares, Alexander shareholders otherwise entitled to receive
fractional shares of Common Stock were paid in cash an amount equal to $4.375
multiplied by the fraction of a share of Common Stock to be received. On
December 31, 1996, NEG-OK was merged into and with the Company and its separate
corporate existence ceased to exist.
F-12
<PAGE>
In connection with the Merger, on August 29, 1996, the Company, NEG-OK, and
Boomer Marketing Corporation ("Boomer Marketing"), a wholly-owned subsidiary of
NEG-OK, entered into a new credit facility. See Note 3. On August 29, 1996, the
Company also closed the sale of 100,000 shares of its Convertible Preferred
Stock, Series D, $1.00 par value per share, the sale of 50,000 shares of its
Convertible Preferred Stock, Series E, $1.00 par value per share, and warrants
to purchase 1,050,000 shares of Common Stock. See Note 6.
The cost of acquiring Alexander was approximately $69.4 million, consisting
of the following (in thousands):
Fair value of 21.1 million shares of the Company's Common
Stock issued........................................................ $63,404
Cost of 105,740 shares of NEG-OK common stock owned by the
Company............................................................. 288
Alexander stock options and warrants assumed.......................... 340
Fair value of 122,324 shares of the Company's
Common Stock and 800,000 warrants issued for services
provided by investment advisors..................................... 1,322
Other investment advisor, legal, and accounting professional
fees and other Merger related costs................................. 4,009
-----
$69,363
=======
The fair value of the securities issued in connection with the Merger was
calculated using the price of the Company's Common Stock at the time the Merger
was announced to the public of $3.00 per share.
The Company's purchase price has been allocated to the consolidated assets
and liabilities of NEG-OK based on preliminary estimates of fair values with the
remaining purchase price allocated to proved oil and gas properties. No goodwill
has been recorded in this transaction.
The preliminary allocation of the purchase price is summarized as follows
(in thousands):
Working capital (deficit) assumed, excluding current portion
of long-term debt.................................................$ (87)
Oil and gas properties:
Proved............................................................ 132,756
Unproved.......................................................... 6,319
Other property and equipment........................................ 970
Other non-current assets............................................ 198
Long-term debt assumed.............................................. (45,853)
Other non-current liabilities assumed............................... (3,163)
Deferred income taxes............................................... (21,777)
---------
$ 69,363
==========
Under the full cost method of accounting, the carrying value of oil and gas
properties (net of related deferred taxes) is generally not permitted to exceed
the sum of the present value (10% discount rate) of estimated future net cash
flows, after tax, from proved reserves, based on current prices and costs, plus
the lower of cost or estimated fair value of unproved properties (the "cost
center ceiling"). Based upon the combined cost center ceiling at August 29,
1996, and the preliminary allocation of the Company's purchase price, the
purchase price allocated to oil and gas properties was in excess of the cost
center ceiling using oil and natural gas prices being received by the Company
and NEG-OK in August 1996 of $20.75 per Bbl and $2.21 per Mcf. Such excess was
written off at the date of acquisition, resulting in a charge to the Company's
results of operations of $28.3 million as follows (in thousands):
Writedown of oil and gas properties...................................$ 43,497
Deferred income tax benefit........................................... (15,224)
----------
$ 28,273
==========
F-13
<PAGE>
In September 1996, the Company acquired an approximate 87.5% working
interest in two wells and certain proved undeveloped reserves in the South Lake
Boeuf Field, La Fourche Parish, Louisiana (the "Lake Boeuf Acquisition") for
approximately $7.2 million, consisting of $1.5 million in cash and 1,758,460
shares of Common Stock.
The following pro forma data presents the results of the Company for the
years ended December 31, 1995 and 1996, as if the acquisitions of Mustang
Island, Oak Hill, the Enron Properties, NEG-OK, and the Lake Boeuf Acquisition
had occurred on January 1, 1995. The historical results of the CA Acquisition
and the UMC Acquisition were not significant. The pro forma results of
operations are presented for comparative purposes only and are not necessarily
indicative of the results which would have been obtained had the acquisitions
been consummated as presented. The following data reflect pro forma adjustments
for oil and gas revenues, production costs, depreciation, and depletion related
to the properties and businesses acquired, interest on borrowed funds,
additional preferred stock dividend requirements, and the related income tax
effects (in thousands, except per share amounts).
Pro Forma
Year ended December 31,
1995 1996
---------- ------------
(Unaudited)
Total revenues.........................................$ 28,790 $ 38,818
=========== ============
Income (loss) before extraordinary item................$ (6,131) $ 3,652
=========== ============
Income (loss) before extraordinary item per share......$ (.20) $ .06
=========== ============
In October 1996, the Company acquired certain leasehold interests located in the
Easy Bayou Sorrel Field, Iberville Parish, Louisiana from W&T Offshore, Inc. The
consideration paid by the Company consisted of $3,300,000 in cash. In November
1996, the Company completed the acquisition of oil and natural gas properties
and related facilities located in the Bayou Sorrel Field, Iberville Parish,
Louisiana. The consideration paid by the Company consisted of $9,025,000 cash,
477,612 shares of the Company's Common Stock and conveyance of 3% overriding
royalty interest in the property acquired, limited to production below 11,000
feet. In December 1996, the Company acquired certain oil and natural gas
properties located in the East Bayou Sorrel Field, Iberville Parish, Louisiana.
The consideration paid by the Company consisted of $7,000,000 in cash. The
Company funded the cash portion of these acquisitions from available cash. These
acquisitions consisted principally of proved developed nonproducing and unproved
properties and, accordingly, did not have a significant impact on the Company's
results of operations for 1996.
3. Credit Facilities
Borrowings of $6,000,000 were outstanding at December 31, 1994, under a
credit facility with Texas Gas Fund I. A portion of the proceeds from the Texas
Gas Fund I facility were used to repay the Company's previous loan with Bank One
which resulted in an extraordinary charge of $121,917, or $.01 per common share.
In June 1995, the Company consummated a $33,000,000 reducing revolving line
of credit facility (the "Prior Credit Facility") with Bank One. The initial
advance under the Facility of $12,500,000 was used to pay off the Company's
credit facility with Texas Gas Fund I, to purchase Oak Hill and the Enron
Properties (Note 2), and for closing fees. The repayment of borrowings under the
Texas Gas Fund I facility resulted in an extraordinary charge of $431,762 or
$.04 per common share.
At December 31, 1995, the Prior Credit Facility consisted of a revolving
note of up to $30,000,000, subject to a borrowing base, and an advance note of
up to $3,000,000 (primarily for the development of GAU). Interest on the
F-14
<PAGE>
revolving note was at a rate of prime plus 1% (subject to reduction in certain
circumstances) or LIBOR plus 3.75% (subject to reduction in certain
circumstances), at the Company's option. Interest on the advance note was at a
rate of prime plus 4%. Payments of interest and principal were made monthly. The
Facility was secured by all of the Company's principal oil and gas properties
and related equipment, oil and gas inventory, and related receivables.
Prepayments were allowed at any time. At December 31, 1995, the Company had
$16,975,000 outstanding under the revolving note and $3,000,000 outstanding
under the advance note.
On August 29, 1996, the Company, NEG-OK and Boomer Marketing, entered into
a credit facility (the "Credit Facility") with Bank One, as Bank and
Administrative Agent, and the Credit Lyonnais New York Branch, as Bank and
Syndication Agent (collectively, the "Banks"). The Credit Facility consisted of
a $100.0 million reducing revolving line of credit, with an initial borrowing
base of $60.0 million and a $5.0 million term loan. Interest under the reducing
revolving line of credit was payable monthly at the Bank One base rate. The
proceeds from the Credit Facility were used to repay the Prior Credit Facility
and the existing indebtedness of NEG-OK, resulting in an extraordinary charge of
$292,372 or $.01 per common share.
On November 1, 1996, the Company repaid the outstanding borrowings under
the Credit Facility with a portion of proceeds from the issuance of $100.0
million principal amount of 10 3/4% Senior Notes due 2006 (the "Senior Notes").
See Note 4.
In connection with the issuance of the Senior Notes, the Company amended
the Credit Facility. The borrowing base, pursuant to the amended Credit
Facility, was reduced to $25.0 million, limited to $15.0 million for general
corporate purposes and $10.0 million for acquisitions of producing oil and gas
properties. The borrowing base will be redetermined at least semiannually and
may require mandated monthly principal reductions by an amount determined by the
Banks from time to time. No principal reductions will be required before the
next borrowing base redetermination scheduled for April 1, 1997. The principal
is due at maturity, August 29, 2000. Interest is payable monthly and is
calculated at the Bank One base rate, as determined from time to time by Bank
One (which increases by .25% if the outstanding loan balance is greater than 75%
of the borrowing base). The Company may elect to calculate interest under the
EuroDollar Rate, as defined in the Credit Facility. At December 31, 1996, the
Company had no outstanding indebtedness under the amended Credit Facility.
The Company is required to pay a commitment fee on the unused portion of
the borrowing base equal to this of 1% per annum and paid a facility fee equal
to 3/4% of the initial borrowing base under the Credit Facility.
The Company granted to the Banks liens on substantially all of the Company's
oil and natural gas properties, whether currently owned or hereafter acquired,
and a negative pledge on all other oil and natural gas properties. The Credit
Facility requires, among other things, semiannual engineering reports covering
oil and natural gas properties, and maintenance of certain financial ratios,
including the maintenance of a minimum interest coverage, a current ratio, and a
minimum tangible net worth.
The Credit Facility includes other covenants prohibiting cash dividends,
distributions, loans, or advances to third parties, except that cash dividends
on preferred stock will be allowed so long as no event of default exists or
would exist as result of the payment thereof. In addition, if the Company is
required to purchase or redeem any portion of the Notes, or if any portion of
the Notes become due, the borrowing base is subject to reduction. At December
31, 1996, the Company was not in violation of any covenants of the Credit
Facility.
4. 10 3/4% Senior Notes due 2006
On November 1, 1996, the Company completed the sale of $100.0 million
principal amount of Senior Notes. The net proceeds of the Senior Notes of
approximately $96.0 million were used to repay approximately $62 million of
borrowings outstanding under the Credit Facility and to increase the Company's
working capital. In 1997, the Senior Notes were exchanged for an equal principal
amount of the Company's 10 3/4% Senior Notes due 2006 ("Exchange Notes") which
are substantially identical to the Senior Notes. Collectively, the Senior Notes
and the Exchange Note are referred to as the "Notes." The Notes bear interest at
an annual rate of 10 3/4%, payable
F-15
<PAGE>
semiannually in arrears on May 1 and November 1 of each year. The Notes are
senior, unsecured obligations of the Company, ranking pari passu with all
existing and future senior indebtedness of the Company, and senior in right of
payment to all future subordinated indebtedness of the Company. Subject to
certain limitations set forth in the indenture covering the Notes (the
"Indenture"), the Company and its subsidiaries may incur additional senior
indebtedness and other indebtedness.
The Indenture provides that the Notes will be unconditionally guaranteed
(the "Guarantee") by any subsidiary designated by the Company as a Restricted
Subsidiary (a "Guarantor"). As a result of the merger of NEG-OK into the Company
on December 31, 1996, the Company has no Restricted Subsidiaries.
The Indenture contains certain covenants limiting the Company and any
Restricted Subsidiaries, with respect to the following: (i) assets sales; (ii)
restricted payments; (iii) the incurrence of additional indebtedness and the
issuance of certain redeemable preferred stock; (iv) liens; (v) sale and
leaseback transactions; (vi) lines of business; (vii) dividend and other payment
restrictions affecting subsidiaries; (viii) mergers and consolidations; and (ix)
transactions with affiliates.
At any time on or after November 1, 2001, the Company may, at its option,
redeem all or any portion of the Notes at the redemption prices expressed as
percentages of the principal amount of the Notes set forth below, plus, in each
case, accrued and unpaid interest thereon to the applicable redemption date, if
redeemed during the 12-month period beginning November 1 of the years indicated
below:
Year Percentage
-------------- ------------
2001..................................................105.375%
2002..................................................102.688%
2003 and thereafter...................................100.000%
Notwithstanding the foregoing, at any time prior to November 1, 2001, the
Company may, at its option, redeem all or any portion of the Notes at the
Make-Whole Price, as defined, plus accrued and unpaid interest to the date of
redemption. In addition, in the event the Company consummates one or more Equity
Offerings, as defined, on or prior to November 1, 1999, the Company, at its
option, may redeem up to $35.0 million of the aggregate principal amount of the
Notes with all or a portion of the aggregate net proceeds received by the
Company from such Equity Offering or Equity Offerings at a redemption price of
110.75% of the aggregate principal amount of the Notes so redeemed, plus accrued
and unpaid interest thereon to the redemption date; provided, however, that
following such redemption, at least $65.0 million of the aggregate principal
amount of the Notes remains outstanding.
Upon a Change of Control, as defined, the Company will be required, subject
to certain conditions, to offer to repurchase all Notes at 101% of the principal
amount thereof, plus accrued and unpaid interest to the date of purchase.
The carrying value of the Notes approximates their fair value.
5. Commitments and Contingencies
The Company leases office space under an operating lease. Rental expense
charged to operations was approximately $80,000, $101,000, and $117,000 during
the years ended December 31, 1994, 1995, and 1996, respectively. Minimum lease
payments under future operating lease commitments at December 31, 1996, are as
follows:
1997............................... $ 269,164
1998............................... 317,089
1999............................... 317,723
Thereafter......................... 14,660
----------
$ 918,636
==========
F-16
<PAGE>
On August 30, 1995, the Company filed a lawsuit in the District Court of
Ector County, Texas against R.E. Steakley in which the Company seeks to enjoin
Mr. Steakley from interfering with its operations on the surface property
controlled by Mr. Steakley. The lawsuit alleges tortuous interference with the
Company's access to its facilities and wrongful conduct with respect to the
Company's personnel.
On August 31, 1995, R.E. Steakley and N.M. Steakley filed a lawsuit in the
District Court of Harris County, Texas, against Amoco Production Company,
Phillips Petroleum Company, the Company, and others. The lawsuit alleges certain
environmental claims and related tortuous and contractual claims and seeks
unspecified damages. On December 19, 1996, the Court in Harris County, Texas
signed and order transferring the R.E. Steakley claim to the court in Ector
County, Texas as a part of the Company's claim against R.E. Steakley.
Subsequently, R.E. Steakley filed a Fourth Amended Original Answer and Original
Counterclaims against the Company in Ector County District Court in which he
reasserts the claims filed in the Harris County action. The Company believes
that it is operating in compliance with applicable environmental laws and
regulations and believes, based on the advice of counsel, that the ultimate
resolution of the lawsuit will not have a material effect on the Company's
financial condition or results of operations.
The Company is not a defendant in any additional pending legal proceedings
other than routine litigation incidental to its business. While the ultimate
results of these proceedings cannot be predicted with certainty, the Company
does not believe that the outcome of these matters will have a material adverse
effect on the Company.
6. Stockholders' Equity
Capital Stock
In connection with the Merger, the Company's shareholders approved an
amendment to the Company's Certificate of Incorporation to eliminate the
authorization of the Class B Common Stock, to change the name of Class A Common
Stock to "Common Stock," and to increase the number of authorized shares of
Common Stock from 50,000,000 to 100,000,000 shares.
Preferred Stock
At December 31, 1996, the Company has authorized 330,000 shares of $1.00 par
value convertible preferred stock designated in four series B through E:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Series B Series C Series D Series E
-------- -------- -------- --------
Number of authorized shares................ 100,000 80,000 100,000 50,000
Number of shares issued and
outstanding:
December 31, 1994........................ 52,500 -- -- --
December 31, 1995........................ 52,500 40,000 -- --
December 31, 1996........................ 52,500 40,000 100,000 50,000
Conversion price per common share.......... $ 1.625 $ 2.00 $ 2.25 $ 2.25
Liquidation preference value per
share.................................... $ 100.00 $ 100.00 $ 100.00 $ 100.00
Dividend rights............................ 10% 10 1/2% Participation Participation
payable payable with with
semi- semi- common common
annually annually stock stock
(cumulative) (cumulative)
</TABLE>
F-17
<PAGE>
In connection with the acquisition of certain oil and gas assets in 1992,
the Company's Board of Directors authorized the issuance of up to 5,000 shares
of redeemable convertible preferred stock designated as 5% Redeemable
Convertible Preferred Stock, Series A, par value, $1.00 per share ("Series A
Preferred Stock"). The Series A Preferred Stock was converted into 425,000
shares of Common Stock during 1994.
On June 3, 1994, the Company consummated the sale of $5,000,000 of the
Company's 10% Cumulative Convertible Preferred Stock, Series B ("Series B").
Fifty thousand shares of Series B were sold by the Company at $100.00 per share.
The Series B is convertible into shares of Common Stock at a conversion price of
$1.625 per share. The Series B has a liquidation and dividend preference over
the Common Stock. The Series B has a 10% dividend, payable semi-annually. The
Company has the option to make six dividend payments in shares of Series B;
after the sixth such payment, the holders of Series B have the option to receive
additional dividends in shares of Series B or to accrue such dividends in cash.
If the Company makes four dividend payments in shares of Series B, the holders
of Series B have the right to appoint one-third of the members of the Company's
Board of Directors. As of December 31, 1996 all dividend payments were current.
The Series B is redeemable by the Company beginning June 14, 1999, at $100.00
per share, plus accrued and unpaid dividends; provided, however, that the
Company cannot redeem any shares of Series B unless and until all outstanding
shares of the Series C have been redeemed by the Company. The holders of Series
B currently have the right to appoint one member to the Company's Board of
Directors. The Series B requires that dividends be paid on the Series B before
any dividends are paid on Common Stock.
The holders of Series B are entitled to one vote for each share as to
matters upon which by law they are entitled to vote as a class, and the approval
of a majority of the Series B, voting separately as a class, is required to make
changes to the Company's Certificate of Incorporation or By-Laws which adversely
affect the Series B, to authorize or issue additional shares of Series B or to
issue preferred stock equal to or senior to the Series B as to dividends or
liquidation, or, subject to certain exceptions, to effect an extraordinary
transaction that requires a vote of the Company's stockholders. As a result, a
class vote of the holders of Series B would be required for the Company to merge
or be acquired and may therefore delay, deter, or prevent a change in control of
the Company.
In June 1995, the Company consummated the sale of $4,000,000 of the
Company's 10 1/2% Cumulative Convertible Preferred Stock, Series C ("Series C").
Forty thousand shares of Series C were sold by the Company at $100.00 per share.
The Series C is convertible into shares of Common Stock at a conversion price of
$2.00 per share.
The Series C has a liquidation and dividend preference over the Common Stock
and is parity stock to the previously issued Series B. The Series C has a 10
1/2% dividend, payable semi-annually. The Company has the option to make six
dividend payments in shares of Series C; after the sixth such payment, the
holders of Series C have the option to receive additional dividends in shares of
Series C or to accrue such dividends in cash.
If the Company makes four dividend payments in shares of Series C, the
holders of Series C (voting as a class with other affected series of preferred
stock with similar voting rights) have the right to appoint one-third of the
members of the Company's Board of Directors; provided, however, that if the
holders of Series B are presently entitled to a similar right, then the holders
of Series C shall have no such right until the right of the holders of Series B
terminates. As of December 31, 1996, all dividend payments are current and have
been made in cash. The Series C is redeemable by the Company beginning June 14,
1999, at $100.00 per share, plus accrued and unpaid dividends. The holders of
the Series C currently have the right to appoint one member to the Company's
Board of Directors. The holders of Series C are entitled to one vote for each
share as to matters upon which by law they are entitled to vote as a class, and
the approval of a majority of the Series C, voting separately as a class, is
required to make changes to the Company's Certificate of Incorporation or
By-Laws which adversely affect the Series C, to authorize or issue additional
shares of Series C or to issue preferred stock equal to or senior to the Series
C as to dividends or liquidation, or, subject to certain exceptions, to effect
an extraordinary transaction that requires a vote of the Company stockholders.
As a result, a class vote of the holders of Series C, as well as the
F-18
<PAGE>
Series B, would be required for the Company to merge or be acquired and may
therefore delay, deter, or prevent a change in control of the Company.
On August 29, 1996, the Company closed the sale for $10.0 million to High
River Limited Partnership ("High River") of 100,000 shares of its Convertible
Preferred Stock, Series D, $1.00 par value per share ("Series D") and warrants
to purchase 700,000 shares of Common Stock exercisable immediately at $2.50 per
share, which warrants expire five years from their date of issuance. The rights
and preferences of the Series D are described in the Certificate of Designations
of the Series D and include the immediate right to convert all the shares of the
Series D into 4,444,444 shares of Common Stock, based upon the initial
conversion price of $2.25 per share.
The holders of the Series D are entitled to one vote for each share when
entitled to vote as described below and as to matters upon which by law they are
entitled to vote as a class. The holders of Series D will have the right to
appoint one member to the Board of Directors. The Company may not, without the
consent of the director appointed by the holders of Series D, voluntarily file
for protection under federal or other bankruptcy laws. In addition, the holders
of Series D will have the right to choose to appoint one-half of the members of
the Board of Directors plus one member (including the member appointed by the
Series D) if the Series D contingent voting rights are triggered and the holders
of the Series D exercise their rights.
On August 29, 1996, simultaneously with the closing of the sale for $10.0
million of the Series D to High River, the Company also closed the sale for $5.0
million to two insurance companies and four affiliates of Kayne, Anderson
Investment Management, Inc. ("KAIM"), a registered investment adviser, of 50,000
shares of Convertible Preferred Stock, Series E, $1.00 par value per share
("Series E") and warrants to purchase 350,000 shares of the Common Stock
exercisable immediately at $2.50 per share, which warrants expire five years
from their date of issuance. The Series E has the rights and preferences
described in the Certificate of Designations of the Series E which include the
immediate right to convert all of the shares of the Series E into 2,222,222
shares of the Common Stock, based upon the initial conversion price of $2.25 per
share. The Series E will vote together with the Common Stock on all matters
submitted to the holders of Common Stock and shall have that number of votes per
share equal to the number of shares of Common Stock into which such share is
convertible as of the record date for the vote.
Common Stock
Holders of Common Stock are entitled to one vote for each share held of
record on all matters voted on by stockholders. The shares of the Common Stock
do not have cumulative voting rights, which means that the holders of more than
50% of the shares of the Common Stock voting for the election of the directors
can elect all of the directors to be elected by holders of the Common Stock, in
which event the holders of the remaining shares of Common Stock will not be able
to elect any director. Upon any liquidation, dissolution, or winding-up of the
affairs of the Company, holders of the Common Stock would be entitled to
receive, pro rata, all of the assets of the Company available for distribution
to stockholders, after payment of any liquidation preference of any Preferred
Stock that may be issued and outstanding at the time. Holders of the Common
Stock have no subscription, redemption, sinking fund, or preemptive rights.
The Class B Common Stock ("Class B") was entitled to special conversion
rights. In June 1995, as a result of the Company's proven crude oil and natural
gas reserves reaching a value in excess of $25,000,000, the 129,644 shares of
Class B common stock which were outstanding at December 31, 1994, were converted
into 1,296,440 shares of Common Stock, in accordance with the terms of the Class
B. Under the terms of the Class B, such shares cannot be reissued.
F-19
<PAGE>
Warrants
In June 1994, in connection with the sale of the Series B Preferred Stock,
the Company issued warrants to purchase 307,692 shares of Common Stock at a
price of $1.625 per share. During 1995, 255,492 of these warrants were exercised
and the remainder were exercised in 1996. In 1995, the Company granted warrants
to purchase 300,000 shares of Common Stock at a price of $1.625 per share,
pursuant to a consulting agreement. The estimated fair value of the warrants was
deferred at the date of grant and charged to general and administrative expenses
over the vesting period. In June 1995, in connection with the acquisition of Oak
Hill (Note 2), the Company issued warrants to purchase 200,000 shares of Common
Stock at a price of $2.00 per share. During 1996, 100,000 of these warrants were
exercised.
During 1996, the Company issued warrants to purchase 1,050,000 shares of
Common Stock with exercise prices of $2.50 per share to the purchasers of the
Series D and Series E and issued warrants to purchase 300,000 shares of Common
Stock with exercise prices of $2.875 per share to financial advisors in
connection with this transaction. In connection with the Merger, the Company
issued warrants to purchase 800,000 shares of Common Stock to two financial
advisors. Warrants to purchase 700,000 shares have an exercise prices of $2.875
per share while warrants to purchase 100,000 shares have an exercise prices of
$4.09 per share. In the Merger, the Company also assumed 396,015 warrants to
purchase Common Stock at prices ranging from $2.07 to $3.00 in the Merger.
The following table summarizes warrants outstanding at December 31, 1996:
<TABLE>
<CAPTION>
Number of Shares Expiration Warrants Exercise
Under Warrant Date Exercisable Prices
------------- ---- ----------- ------
<S> <C> <C> <C>
100,000...................................................... July 31, 1997 100,000 $ 1.625
100,000...................................................... July 31, 1998 100,000 1.625
100,000...................................................... July 31, 1999 100,000 1.625
100,000...................................................... June 30, 1998 100,000 2.00
1,050,000...................................................... August 29, 2001 1,050,000 2.50
300,000...................................................... August 29, 2001 300,000 2.875
700,000...................................................... August 29, 2001 700,000 2.875
100,000...................................................... August 29, 2001 100,000 4.09
127,500...................................................... March 10, 1998 127,500 3.00
268,515...................................................... September 14, 1998 268,515 2.07
---------- -----------
2,946,015 2,946,015
========= ===========
</TABLE>
Stock Options
During 1992, the Company's Board of Directors and stockholders approved the
Company's 1992 Stock Option Plan (the "1992 Plan"). At December 31, 1996, 15,000
options had been granted pursuant to the 1992 Plan. At present, the Company does
not plan to issue further options under the 1992 Plan.
During 1994, 1995, and 1996, the Company's Board of Directors granted
options to purchase 40,000, 765,000, and 5,000 shares of Common Stock,
respectively, to certain officers and directors. These options were issued
outside of the 1992 Plan.
As a result of the Merger, the Company assumed 135,028 outstanding stock
options previously issued pursuant to three stock option plans of Alexander. No
additional stock options will be granted pursuant to such plans. The stock
options assumed may be exercised to purchase shares of Common Stock at prices
ranging from $0.88 to $2.94 per share.
F-20
<PAGE>
A summary of the Company's stock option activity, and related information
for the years ended December 31, 1994, 1995, and 1996, follows:
<TABLE>
<CAPTION>
1994 1995 1996
---------------------------- ---------------------------- -------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Options Price Options Price Options Price
-------------- -------------- -------------- -------------- --------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at
beginning of year 297,500 $ .64 240,000 $ .79 932,500 $ 2.02
Granted 40,000 1.62 765,000 1.93 5,000 3.00
Assumed in merger
with Alexander
-- -- -- -- 135,028 2.25
Exercised (62,500) .58 (72,500) .72 (199,042) 1.08
Cancelled (35,000) .81 -- -- -- --
-------------- ---------------
==============
Outstanding at end of
year 240,000 .79 932,500 2.02 873,486 2.28
============== ============== ===============
Exercisable at end of
year 200,000 .63 347,500 1.24 503,484 2.24
============== ============== ===============
Weighted-average fair
value of options
granted or assumed
during the year $ $
1.31 2.15
============== ===============
</TABLE>
At December 31, 1996, the exercise prices of outstanding options ranged
from $0.625 to $3.00 per share. The weighted average remaining contractual life
of such options was 3.4 years.
On August 30, 1996 the Board of Directors approved the isssuance of options
to purchase 700,000 shares of Common Stock to the Company's chief executive
officer. The options have an exercise price of $4.0625 per share. The options
become exercisable when the price of the Common Stock reaches and remains at or
above $8.125 for a period of 30 days. If the price target is not met within five
years, the options expire. In December 1996, the Company's Board of Directors
approved grants of options to purchase 966,500 shares of Common Stock for $3.75
per share. Both grants are subject to approval of a new stock option plan by the
stockholders of the Company and, therefore, are not included in the above table.
Statement of Financial Accounting Standards No. 123, "Accounting for Stock
Based Compensation," (SFAS 123) requires the disclosure of pro forma net income
and earnings per share information computed as if the Company had accounted for
its employee stock options granted subsequent to December 31, 1994, under the
fair value method set forth in SFAS 123. The fair value for these options was
estimated at the date of grant using a Black-Scholes option pricing model with
the following weighted-average assumptions for 1995 and 1996, respectively: a
risk-free interest rate of 6%, a dividend yield of 0%, and a volatility factor
of .54. In addition, the fair value of these options was estimated based on an
expected life of three years for options granted by the Company and one year for
the options assumed in the merger with Alexander.
The Black-Scholes option valuation model was developed for use in estimating
the fair value of traded options which have no vesting restrictions and are
fully transferable. In addition, option valuation models require the input of
highly subjective assumptions including the expected stock price volatility.
Because the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its employee stock options. In addition, because
SFAS 123 is applicable only to options granted subsequent to December 31, 1994,
the pro forma information does not reflect the pro forma effect of all previous
stock option grants of the Company, and thus the pro forma information is not
necessarily indicative of future amounts until SFAS 123 is applied to all
outstanding stock options.
F-21
<PAGE>
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information follows (in thousands except for earnings per share
information):
Year ended December 31,
1995 1996
-------------- ----------
Pro forma net loss........................ $ (321,559) $ (26,380,771)
============ ==============
Pro forma net loss per common share....... $ (.10) $ (1.37)
============ ==============
7. Income Taxes
The reconciliation of income taxes computed at the U.S. federal statutory
tax rates to the benefit for income taxes on the income (loss) before
extraordinary item is as follows:
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------
1994 1995 1996
----------- ---------- ---------------
<S> <C> <C> <C>
Income tax (benefit) at statutory rate............................ $ (166,385) $ 69,970 $(14,021,426)
Utilization of net operating loss carryforward.................... -- (69,970) (414,177)
Benefit of net operating loss not recognized...................... 166,385 -- --
Other............................................................. -- -- (67,992)
----------- ---------- ---------------
$ -- $ -- $(14,503,595)
=========== ========== ============
The computation of the net deferred tax asset (liability) follows:
December 31,
1995 1996
------------- ---------
Deferred tax liabilities:
Property and equipment......................................................... $(1,778,045) $(19,948,392)
Other.......................................................................... (8,378) (38,549)
Deferred tax assets:
Net operating loss carryforwards............................................... 2,402,574 14,564,346
Statutory depletion carryforwards.............................................. -- 1,340,763
Other.......................................................................... -- 1,812,635
-------- ---------
616,151 (2,269,197)
Less valuation allowance......................................................... (616,151) (5,004,632)
------------- ---------
$ -- $ (7,273,829)
============ ==============
</TABLE>
At December 31, 1996, the Company had net operating loss carryforwards
available for federal income tax purposes of approximately $42 million which
expire beginning in 1997. Utilization of substantially all of the net operating
loss carryforwards is subject to various limitations because of previous changes
in stock ownership (as defined in the Internal Revenue Code) of the Company and
Alexander. Additional net operating loss limitations may be imposed as a result
of subsequent changes in stock ownership of the Company. For federal income tax
purposes, the Company also has statutory depletion carryforwards of $3.8
million, which do not expire. As a result
F-22
<PAGE>
of the limitations on the utilization of net operating loss carryforwards, the
Company has established a valuation allowance to reduce deferred tax assets to
amounts that are more likely than not to be realized.
8. Gas Hedging Activities and Commitments
While the use of hedging arrangements limits the downside risk of adverse
price movements, it may also limit future gains from favorable movements. All
hedging is accomplished pursuant to swap agreements based upon standard forms.
The Company addresses market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged.
Credit risk related to hedging activities is managed by requiring minimum credit
standards for counterparties, periodic settlements, and mark to market
valuations. The Company has not been required to provide collateral relating to
its hedging activities.
In December 1995, the Company had entered into various swap agreements to
fix the selling prices for natural gas at a weighted average NYMEX price of
$2.805 per Mcf for 225,000 Mcf of natural gas to be produced during 1996. The
Company closed the positions prior to December 31, 1995, resulting in a deferred
gain of approximately $70,875 which was recognized in 1996.
During the year ended December 31, 1996, the Company recognized a net gain
of $20,315 related to hedging transactions. At December 31, 1996, the Company
has no hedging agreements outstanding.
9. Crude Oil and Natural Gas Producing Activities
The unproven properties are excluded from the amortization base and consist
primarily of acreage, acquisition costs, and related geological and geophysical
costs. These costs are expected to be evaluated during the Company's drilling
program during the next three to five years.
Costs incurred in connection with acquisition, development, exploitation and
exploration of crude oil and natural gas properties for the years ended December
31, 1994, 1995, and 1996, are as follows:
<TABLE>
<CAPTION>
Year ended December 31,
1994 1995 1996
------------ --------- ------------
<S> <C> <C> <C>
Acquisitions of properties:
Proved....................................................... $ 1,153,548 $ 13,657,383 $151,511,108
Unproved..................................................... 134,512 707,913 24,534,610
Exploration costs.............................................. 130,182 73,034 4,406,015
Development costs.............................................. 2,006,183 8,595,363 19,389,494
Amortization rate per Mcfe..................................... .70 .91 1.11
</TABLE>
The acquisitions of properties in 1996 include $132.8 million of proved
properties and $6.3 million of unproved properties acquired in the Merger. See
Note 2.
Depletion, depreciation, and amortization increased $351,964 for the fourth
quarter of 1995 due to downward revisions in estimated proved reserves at
December 31, 1995.
F-23
<PAGE>
Revenues from individual customers that exceed 10% of total crude oil and
natural gas sales are as follows:
<TABLE>
<CAPTION>
Year ended December 31,
-------------------------------------------
<S> <C> <C> <C>
1994 1995 1996
------------ ----------- ----------
Plains Marketing and Transportation................ $ 1,614,711 $ 4,618,136 $9,382,466
Crosstex Energy.................................... -- -- 2,919,944
GPM Natural Gas Corporation........................ 553,613 -- 2,832,049
Energy Source, Inc................................. -- 870,285 --
</TABLE>
The Company believes that the loss of these customers would not have a
significant impact on the Company's results of operations or financial
condition.
10. Supplementary Crude Oil and Natural Gas Reserve Information (Unaudited)
The Company has interests in crude oil and natural gas properties that are
principally located in Texas, Oklahoma, New Mexico, Wyoming, and offshore Texas.
The Company does not own or lease any crude oil and natural gas properties
outside the United States.
The Company retains independent engineering firms to provide annual year-end
estimates of the Company's future net recoverable crude oil, natural gas, and
natural gas liquids reserves. Estimated proved net recoverable reserves as shown
below include only those quantities that can be expected to be commercially
recoverable at prices and costs in effect at the balance sheet dates under
existing regulatory practices and with conventional equipment and operating
methods.
Proved developed reserves represent only those reserves expected to be
recovered through existing wells. Proved undeveloped reserves include those
reserves expected to be recovered from new wells on undrilled acreage or from
existing wells on which a relatively major expenditure is required for
recompletion.
Net quantities of proved developed and undeveloped reserves of natural gas
and crude oil, including condensate and natural gas liquids, are summarized as
follows:
Natural Gas
Crude Oil (Thousand
(Barrels) Cubic Feet)
--------- -----------
December 31, 1993......................... 3,721,084 11,047,393
Purchase of reserves in place........... 1,035,137 1,858,271
Extensions and discoveries.............. 906,526 1,996,771
Revisions of previous estimates......... (387,840) (879,838)
Production.............................. (115,642) (620,843)
Sales of reserves in place.............. (3,524) (21,280)
------------ --------------
December 31, 1994......................... 5,155,741 13,380,474
Purchase of reserves in place........... 190,063 25,785,458
Revisions of previous estimates......... (1,141,288) (6,453,623)
Production.............................. (283,440) (1,752,990)
Sales of reserves in place.............. -- (90,207)
----------- --------------
December 31, 1995......................... 3,921,076 30,869,112
Purchase of reserves in place........... 4,691,982 97,840,796
Extensions and discoveries.............. 37,800 371,062
Revisions of previous estimates......... 703,594 6,104,198
Production.............................. (521,701) (5,680,904)
Sales of reserves in place.............. (29,880) (634,386)
----------- -------------
December 31, 1996......................... 8,802,871 128,869,878
=========== =============
F-24
<PAGE>
Proved developed reserves:
December 31, 1993....................... 1,641,800 8,781,785
December 31, 1994....................... 1,532,470 9,205,784
December 31, 1995....................... 1,632,404 13,304,031
December 31, 1996....................... 4,383,926 77,496,645
The Company's principal individual properties are the GAU, located onshore
in Texas, and the South Lake Boeuf Field located in La Fourche Parish,
Louisiana. As of December 31, 1994, 1995, and 1996, the Company's net interests
in the proved reserves of the GAU was approximately 32,532 Mmcfe, 25,002 Mmcfe,
and 25,035 Mmcfe, respectively. As of December 31, 1996, the Company's net
interest in the South Lake Boeuf Field was 15,200 Mmcfe.
The following is a summary of a standardized measure of discounted net cash
flows related to the Company's proved crude oil and natural gas reserves. For
these calculations, estimated future cash flows from estimated future production
of proved reserves were computed using crude oil and natural gas prices as of
the end of each period presented. Future development and production costs
attributable to the proved reserves were estimated assuming that existing
conditions would continue over the economic lives of the individual leases and
costs were not escalated for the future. Estimated future income tax expenses
were calculated by applying future statutory tax rates (based on the current tax
law adjusted for permanent differences and tax credits) to the estimated future
pretax net cash flows related to proved crude oil and natural gas reserves, less
the tax basis of the properties involved.
The Company cautions against using this data to determine the fair value of
its crude oil and natural gas properties. To obtain the best estimate of fair
value of the crude oil and natural gas properties, forecasts of future economic
conditions, varying discount rates, and consideration of other than proved
reserves would have to be incorporated into the calculation. In addition, there
are significant uncertainties inherent in estimating quantities of proved
reserves and in projecting rates of production that impair the usefulness of the
data.
The standardized measure of discounted future net cash flows relating to
proved crude oil and natural gas reserves are summarized as follows:
<TABLE>
<CAPTION>
December 31,
-----------------------------------
1995 1996
-------------- ------------
<S> <C> <C>
Future cash inflows...................................................... $ 132,218,400 $ 702,089,600
Future production and development costs.................................. (71,109,500) (220,155,000)
Future income tax expenses............................................... (7,123,405) (105,547,035)
-------------- -------------
Future net cash flows.................................................... 53,985,495 376,387,565
10% annual discount for estimated timing of cash flows................... (21,858,394) (146,607,933)
--------------- ---------------
Standardized measure of discounted future net cash
flows.................................................................. $ 32,127,101 $229,779,632
============== =============
</TABLE>
F-25
<PAGE>
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------------------------
1994 1995 1996
------------- ------------- ------------
<S> <C> <C> <C>
Sales and transfers of crude oil and natural
gas produced, net of production costs................ $(1,775,145) $ (5,710,325) $(19,293,463)
Net changes in prices and production costs............. 14,785,630 14,654,096 131,330,518
Development costs incurred during the period
and changes in estimated future development
costs................................................ (119,443) (11,886,400) 4,884,876
Purchases of reserves in place......................... 3,414,926 15,455,400 117,893,900
Sales of reserves in place............................. (30,585) (97,210) (450,300)
Extensions and discoveries, less related
costs................................................ 4,605,206 -- 850,200
Revisions of previous quantity estimates............... (1,985,978) (8,871,208) 16,576,531
Accretion of discount.................................. 1,439,950 2,744,504 3,627,860
Net change in income taxes............................. (6,952,217) 2,590,707 (57,743,416)
Changes in production rates (timing) and other......... (4,221,647) 2,408,034 (24,175)
------------- ------------ ------------
Net change............................................. $ 9,160,697 $ 11,287,598 $197,652,531
============= ============ ============
</TABLE>
During recent years, there have been significant fluctuations in the prices
paid for crude oil in the world markets. This situation has had a destabilizing
effect on crude oil posted prices in the United States, including the posted
prices paid by purchasers of the Company's crude oil. The net weighted average
prices of crude oil and natural gas at December 31, 1994, 1995, and 1996, used
in the above table were $16.59, $18.71, and $25.36 per barrel of crude oil,
respectively, and $1.62, $1.91, and $3.72 per thousand cubic feet of natural
gas, respectively.
F-26
<PAGE>
INDEX TO EXHIBITS
2.1 Agreement and Plan of Merger, dated June 6, 1996, among the Company,
NEG-OK, Inc. ("NEG OK"), and Alexander Energy Corporation ("Alexander")(1)
2.2 First Amendment to Agreement and Plan of Merger, dated as of June 20, 1996,
among the Company, NEG-OK and Alexander(2)
2.3 Mutual Waiver Agreement dated as of August 29, 1996 by and among the
Company, NEG-OK and Alexander(3)
3.1 Certificate of Incorporation of the Company, which includes the Certificate
of Incorporation of the Company filed with the Secretary of State of
Delaware on November 20, 1990(4), the Certificate of Elimination of the
Redeemable Convertible Preferred Stock, Series A of the Company, filed with
the office of the Secretary of State of the State of Delaware on June 2,
1994(3), the Certificate of Amendment of Certificate of Incorporation of
the Company, filed with the office of the Secretary of State of the State
of Delaware on August 29, 1996(3), the Certificate of Designations of the
Company of 10% Cumulative Convertible Preferred Stock, Series B(5), the
Certificate of Designations of the Company of 10 1/2% Cumulative
Convertible Preferred Stock, Series C(6), the Certificate of Designations
of the Company of Convertible Preferred Stock, Series D(3), and the
Certificate of Designations of the Company of Convertible Preferred Stock,
Series E(3)
3.2 By-laws of the Company(4)
4.1 Certificate of Designations of the Company of 10% Cumulative Convertible
Preferred Stock, Series B(5)
4.2 Certificate of Designations of the Company of 10 1/2% Cumulative
Convertible Preferred Stock, Series C(6)
4.3 Certificate of Designations of the Company of Convertible Preferred Stock,
Series D(3)
4.4 Certificate of Designations of the Company of Convertible Preferred Stock,
Series E(3)
4.5 Note Agreement dated as of April 25, 1989, by and among AEJH 1989 Limited
Partnership, Alexander and John Hancock Mutual Life Insurance (10 1/2%
Senior Secured Notes)(8)
4.6 Letter dated August 29, 1996 between Alexander and John Hancock Mutual Life
Insurance Company relating to the payment of the 1989 Notes(3)
4.7 Indenture dated as of November 1, 1996, among the Company, National Energy
Group of Oklahoma, Inc. (the "Guarantor"), formerly NEG-OK, and Bank One,
Columbus, N.A.(9)
10.1 Crude Oil Purchase Contract, dated November 30, 1992, between the Company
and Plains Liquids Transport Inc.(10)
10.2 Amendment to Crude Oil Purchase Contract, dated November 17, 1993, between
the Company and Plains Liquids Transport, Inc.(5)
10.3 Crude Oil Purchase Contract, dated February 8, 1993, between the Company
and Plains Marketing and Transportation Inc. and the predecessor contract,
the Crude Oil Purchase Contract, dated November 12, 1991, between
Sunnybrook Transmission, Inc. and TriSearch Inc.(10)
10.4 Stock Purchase Agreement, dated as of June 2, 1994, among the Company,
Arbco Associates L.P., Offense Group Associates L.P., Kayne, Anderson
Nontraditional Investments L.P., and Opportunity Associates L.P.(5)
10.5 Gaines Berland, Inc. Warrant, dated January 27, 1995(1)
<PAGE>
10.11 Purchase and Sale Agreement, dated as of March 29, 1995, between the
Company and Enron Oil and Gas Company(6)
10.12 Agreement for Purchase and Sale (Oak Hill), dated April 12, 1995, between
the Company and Sierra 1994 I Limited Partnership(6)
10.13 Agreement for Purchase and Sale (Mustang Island), dated April 20, 1995,
between the Company and Sierra Mineral Development, L.C.(6)
10.14 Stock Purchase Agreement, dated as of June 14, 1995, among the Company,
Arbco Associates L.P., Offense Group Associates L.P., Kayne, Anderson
Nontraditional Investments L.P., and Opportunity Associates L.P.(6)
10.15 Executive Employment Agreement, dated January 1, 1996, between the Company
and Miles D. Bender(11)
10.16 Executive Employment Agreement, dated January 1, 1996, between the Company
and R. Thomas Fetters, Jr.(11)
10.17 Agreement, dated January 1, 1996, between the Company and Randall A.
Carter(11)
10.18 Agreement, dated January 1, 1996, between the Company and Robert A.
Imel(11)
10.19 Executive Employment Agreement, dated January 1, 1996, between the Company
and Melissa Rutledge(11)
10.20 Executive Employment Agreement, dated January 1, 1996, between the Company
and William T. Jones(11)
10.22 Executive Employment Agreement, dated June 6, 1996, between the Company
and David E. Grose(1)
10.23 Executive Employment Agreement, dated June 5, 1996, between the Company
and Sue Barnard(1)
10.24 Executive Employment Agreement, dated June 6, 1996, between the Company
and Jim L. David(1)
10.25 Employment Agreement, dated June 6, 1996, between the Company and Bob G.
Alexander(1)
10.26 Employment Agreement, dated June 6, 1996, between the Company and Roger G.
Alexander(1)
10.29 Prudential Securities Incorporated Warrant to Purchase 100,000 Shares of
the Company's Common Stock(3)
10.30 Gaines Berland, Inc. Warrant to Purchase 300,000 Shares of the Company's
Common Stock(3)
10.31 Gaines Berland, Inc. Warrant to Purchase 700,000 Shares of the Company's
Common Stock(3)
10.32 Agreement dated January 1, 1996 between the Company and Sandefer Oil &
Gas, Inc.(1)
<PAGE>
10.33 Consulting Agreement dated January 1, 1996 between the Sandefer Oil & Gas,
Inc. and Potosky Oil & Gas, Inc. and Atocha Exploration, Inc.(1)
10.34 Stock Purchase Agreement dated August 7, 1996 between the Company and High
River Limited Partnership(2)
10.35 High River Limited Partnership Warrant to purchase 700,000 Shares of
Common Stock, dated August 29, 1996(3)
10.36 Stock Purchase Agreement dated as of August 26, 1996, between the Company
and Foremost Insurance Company, Arbco Associates, L.P., Kayne, Anderson
Nontraditional Investments L.P., Offense Group Associates, L.P., Topa
Insurance Company and Kayne, Anderson Offshore Limited (the "Series E
Investors")(3)
10.37 Form of Series E Investors' Warrants to purchase an aggregate 350,000
Shares of Common Stock, dated August 29, 1996(3)
10.38 Agreement dated as of August 29, 1996 by and between the Company and
Prudential Securities Incorporated(3)
10.40 Restated Loan Agreement dated August 29, 1996 among Bank One and Credit
Lyonnais New York Branch ("Credit Lyonnais") and the Company, NEG-OK and
Boomer Marketing Corporation ("Boomer")(3)
10.41 $50,000,000 Revolving Note dated August 29, 1996 payable to Bank One(3)
10.42 $50,000,000 Revolving Note dated August 29, 1996 payable to Credit
Lyonnais(3)
10.43 $2,500,000 Term Note dated August 29, 1996 payable to Bank One(3)
10.44 $2,500,000 Term Note dated August 29, 1996 payable to Credit Lyonnais(3)
10.45 Unlimited Guaranty of NEG-OK dated August 29, 1996 for the benefit of Bank
One(3)
10.46 Unlimited Guaranty of NEG-OK, dated August 29, 1996 for the benefit of
Credit Lyonnais(3)
10.47 Unlimited Guaranty of Boomer dated August 29, 1996 for the benefit of Bank
One(3)
10.48 Unlimited Guaranty of Boomer dated August 29, 1996 for the benefit of
Credit Lyonnais(3)
10.49 Form of Deeds of Trust, Mortgages, Security Agreements, Assignments of
Production and Financing Statements covering oil and gas properties of the
Company and NEG-OK, dated August 29, 1996(3)
10.50 Sale and Purchase Agreement dated September 26, 1994 by and among JMC
Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and
Alexander(12)
10.51 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 Alexander(12)
10.52 Alexander Energy Corporation 1986 Incentive Stock Option Plan, as
amended(13)
10.53 Alexander Energy Corporation 1993 Stock Option Plan(14)
10.54 Agreement of Limited Partnership of AEJH 1985 Limited Partnership by and
between Alexander and John Hancock Mutual Life Insurance Company, together
with all amendments thereto(15)
10.55 Agreement of Limited Partnership of AEJH 1987 Limited Partnership by and
between Alexander and John Hancock Mutual Life Insurance Company, together
with all amendments thereto(15)
10.56 Agreement of Limited Partnership of AEJH 1989 Limited Partnership by and
between Alexander and John Hancock Mutual Life Insurance Company dated
April 25, 1989(8)
10.57 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(15)
10.58 Warrant Purchase Agreement among Alexander, Hanifen, Imhoff Inc. and The
Principal/Eppler, Guerin & Turner, Inc.(16)
10.59 Purchase Option Agreement (warrants) between American National Energy
Corporation and Gaines, Berland, Inc. dated September 14, 1993(8)
<PAGE>
10.60 Form of Special Severance Agreements between Alexander and the technical
support staff of Alexander, between NEG-OK and Cyndy Burris and John
Christofferson, respectively(8)
10.61 Separation Policy of Alexander dated December 8, 1994(8)
10.62 Asset Purchase and Sale Agreement dated September 30, 1996 by and between
the Company and Araxas Energy Corporation, Araxas SPV-1, Inc., Araxas
Exploration, Inc. and O'Sullivan Oil and Gas Company, Inc.(9)
10.63 Purchase Agreement dated October 29, 1996, by and among the Company,
Guarantor and Bear, Stearns & Co. Inc., Smith Barney Inc. and Jefferies &
Company, Inc. (the "Initial Purchasers")(9)
10.64 Registration Rights Agreement dated October 29, 1996, by and among the
Company, Guarantor and the Initial Purchasers(9)
10.65 First Amendment to Restated Loan Agreement dated October 31, 1996 among
Bank One and Credit Lyonnais and the Company, Guarantor and Boomer (9)
23.1 Consent of Ernst & Young LLP, Independent Auditors (18)
23.2 Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum
Engineers (18)
27.1 Financial Data Schedule(17)
99.39 Certificate of Merger with respect to the merger of Alexander with and
into NEG-OK, filed with the offices of the Secretary of State of the State
of Delaware and the Secretary of State of the State of Oklahoma on August
29, 1996(3)
<PAGE>
---------------
(1) Incorporated by reference to the Company's Registration Statement on Form
S-4 (No. 333-9045), dated July 29, 1996.
(2) Incorporated by reference to Amendment No. 1 to the Company's Registration
Statement on Form S-4 (No. 333-9045), dated August 7, 1996.
(3) Incorporated by reference to the Company's Current Report on Form 8-K,
dated August 29, 1996.
(4) Incorporated by reference to the Company's Registration Statement on Form
S-4 (No. 33-38331), dated April 23, 1991.
(5) Incorporated by reference to the Company's Current Report on Form 8-K,
dated June 17, 1994.
(6) Incorporated by reference to the Company's Current Report on Form 8-K,
dated July 17, 1995.
(7) Incorporated by reference to the Company's Registration Statement on Form
S-3 (No. 33-81172), dated July 27, 1994.
(8) Incorporated by reference to Alexander's Form 10-K for the fiscal year
ended December 31, 1994.
(9) Incorporated by reference to the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1996.
(10) Incorporated by reference to the Company's Annual Report on Form 10-KSB for
the year ended December 31, 1992.
(11) Incorporated by reference to the Company's Annual Report on Form 10-KSB for
the year ended December 31, 1995.
(12) Incorporated by reference to Alexander's Current Report on Form 8-K, dated
November 14, 1994.
(13) Incorporated by reference to Alexander's Registration Statement (No.
33-20425), dated March 22, 1988.
(14) Incorporated by reference to Alexander's Proxy Statement for the 1993
Annual Meeting of Stockholders.
(15) Incorporated by reference to Alexander's Form 10-K for the fiscal year
ended December 31, 1991.
(16) Incorporated by reference to Alexander's Amendment No. 1 to Registration
Statement (No. 33-57142), dated February 26, 1993.
(17) The Financial Data Schedule, for the year ended December 31, 1996, is filed
herewith for EDGAR filings only.
(18) Filed herewith.
Exhibit 23.1
CONSENT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Registration Statements
(Form S-3 No. 33-81172, Form S-3 No. 33-88008, Form S-3 No. 33-62851, Form S-3
No. 333-01485, Form S-3 No. 333-20097, Form S-8 No. 333-12949, and Form S-4 No.
333-17817) and related Prospectuses of our report dated March 18, 1997, with
respect to the financial statements of National Energy Group, Inc. included in
its Annual Report on Form 10-K for the year ended December 31, 1996 filed with
the Securities and Exchange Commission.
ERNST & YOUNG LLP
Dallas, Texas
March 28, 1997
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to our firm in "Items 1 and 2 Description of
Business and Properties" and to the use of our report, dated March 6, 1997,
presenting estimated reserves and future revenue for the oil and gas properties
of National Energy Group, Inc., in National Energy Group,Inc.'s Annual Report on
Form 10-K for the year ended December 31, 1996.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Frederick D. Sewell
------------------------
Frederick D. Sewell
President
Dallas, Texas
March 31, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Form 10-K for the year ended December 31, 1996 and is qualified in its
entirety by reference to such Form 10-K.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 14,182,246
<SECURITIES> 0
<RECEIVABLES> 9,816,019
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 25,130,001
<PP&E> 197,414,761
<DEPRECIATION> 15,387,840
<TOTAL-ASSETS> 212,035,156
<CURRENT-LIABILITIES> 22,548,317
<BONDS> 0
0
242,500
<COMMON> 359,771
<OTHER-SE> (79,823,926)
<TOTAL-LIABILITY-AND-EQUITY> 212,035,156
<SALES> 25,195,645
<TOTAL-REVENUES> 25,195,645
<CGS> 0
<TOTAL-COSTS> 61,352,364
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,212,564
<INCOME-PRETAX> (40,061,217)
<INCOME-TAX> (14,503,595)
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 292,372
<CHANGES> 0
<NET-INCOME> (25,849,994)
<EPS-PRIMARY> (1.34)
<EPS-DILUTED> (1.34)
</TABLE>
