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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-KSB
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3TEC ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 76-0624573
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
TWO SHELL PLAZA, SUITE 2400
777 WALKER STREET
HOUSTON, TEXAS 77002
(713) 821-7100
(Address, including zip code, and telephone number, including area code,
of registrant's principal executive offices)
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Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
----------------------------- --------------------
None N/A
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.02 Par Value
Series C Convertible Redeemable Preferred Stock, $.02 Par Value
Check whether the Registrant (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 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 [ ]
Check if disclosure of delinquent filers in response to Item 405 of Regulation
S-B is not contained in this form, and will not be contained, to the best of
Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB. [x]
Revenues of Registrant for fiscal year ended December 31, 1999 are $22,020,066.
The aggregate market value as of March 8, 2000 of voting and nonvoting stock
held by nonaffiliates of the Registrant was $20,070,413.
As of March 8, 2000 the Registrant had 6,419,022 shares of Common Stock, $.02
par value outstanding.
Documents Incorporated by Reference:
Related Section Document
- --------------------------------------------------------------------------------
Part III Definitive Proxy Statement to be filed pursuant to Regulation 14A
on or before May 1, 2000.
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TABLE OF CONTENTS
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Page
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ITEM 1-BUSINESS
Background...................................................................................... 3
Business Strategy............................................................................... 3
Our Strengths................................................................................... 4
Significant Developments Since December 31, 1998................................................ 4
Marketing....................................................................................... 5
Competition..................................................................................... 6
Regulation...................................................................................... 6
Employees....................................................................................... 8
Our Executive Offices........................................................................... 8
ITEM 2-PROPERTIES
Description of Our Properties................................................................... 8
Description of Magellan Properties.............................................................. 9
Natural Gas and Oil Reserves.................................................................... 10
Volumes, Prices and Operating Expenses.......................................................... 11
Development, Exploration and Acquisition Capital Expenditures................................... 11
Drilling Activity............................................................................... 12
Productive Wells................................................................................ 12
Acreage Data.................................................................................... 12
ITEM 3-LEGAL PROCEEDINGS........................................................................ 13
ITEM 4-SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS........................................ 13
Forward-Looking Statements...................................................................... 13
Risk Factors.................................................................................... 14
ITEM 5-MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.................... 20
ITEM 6-MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview........................................................................................ 21
Results of Operations........................................................................... 23
Year Ended December 31, 1999, Compared With Year Ended December 31, 1998........................ 24
Year Ended December 31, 1998, Compared With Year Ended December 31, 1997........................ 24
ITEM 7-FINANCIAL STATEMENTS..................................................................... 27
ITEM 8-CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE..... 27
ITEM 9-DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT....................................... 27
ITEM 10-EXECUTIVE COMPENSATION.................................................................. 28
ITEM 11-SECURITY OWNERSHIP OF CERTAIN BENEFICAL OWNERS AND MANAGEMENT........................... 28
ITEM 12-CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................................... 28
ITEM 13-EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K........................................................................................ 28
Glossary of Certain Oil and Gas Terms........................................................... 31
Signatures...................................................................................... 33
_____________
________________________________________________________________________________________________________
Item 13(a) includes the Index of Exhibits to be filed with the Securities and
Exchange Commission relative to this Report.
________________________________________________________________________________________________________
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PART I
ITEM 1. BUSINESS
BACKGROUND
3TEC Energy Corporation ("3TEC", "the Company", "we", "our" and "us") is the
successor to Middle Bay Oil Company, Inc. ("Middle Bay"), an Alabama corporation
formed on November 30, 1992. 3TEC was incorporated in Delaware on November 24,
1999, as a wholly owned subsidiary of Middle Bay for the sole purpose of merging
with Middle Bay to effect a change in domicile to Delaware and to change our
name to 3TEC Energy Corporation. Effective December 7, 1999, Middle Bay was
merged into us and each share of common stock of Middle Bay was converted into
one share of our common stock.
We are engaged in the acquisition, development, production and exploration
of oil and natural gas reserves. Our properties are concentrated in East Texas
and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of
Mexico. We also own significant properties in the Permian and San Juan basins
and in the Mid-Continent region. Our management and technical staff have
substantial experience in each of these areas. As of December 31, 1999, we had
estimated total net proved reserves of 218.7 Bcfe, of which approximately 73%
were natural gas and approximately 82% were proved developed, with an estimated
PV-10 value of $198.6 million. As of December 31, 1999, our net daily production
was approximately 38.1 Mmcf of natural gas and 3.1 MBbls of oil or 56.7 Mmcfe.
We have increased our reserves and production principally through
acquisitions. We focus on properties that have a substantial proved reserve
component and which management believes to have additional exploitation
opportunities. Recently, we have also acquired a number of drilling prospects
covered by an extensive 3-D seismic database that we believe have exploration
potential. We have assembled an experienced management team and technical staff
with expertise in property acquisitions and development, reservoir engineering,
exploration and financial management.
BUSINESS STRATEGY
Our business strategy focuses on achieving increases in the per share value
of our common stock through the continued pursuit of attractive acquisitions,
the further development of our existing proved properties, the drilling of
exploration projects and the rationalization of our existing asset base. This
strategy includes:
. Pursue Strategic Acquisitions. We continually review opportunities to
acquire producing properties, leasehold acreage and drilling prospects.
We seek to acquire operational control of properties that we believe have
significant exploitation and/or exploration potential. We also intend to
increase our holdings in fields and basins in which we already own
properties.
. Further Develop Existing Properties. We intend to further develop our
properties having proved reserves. We seek to add proved reserves and
increase production through detailed technical analysis of our properties
and by drilling infill locations and selective recompletions of existing
wells. We also plan to drill step-out wells to expand known field limits.
We intend to enhance the efficiency and quality control of these
activities by operating the majority of our projects.
. Utilize the Latest Available Technology. We intend to continue to utilize
advanced technologies, including 3-D seismic interpretation, computer-
aided exploration, horizontal drilling and advanced completion
technologies, to optimize our operational and financial results.
. Grow Through Exploration. We conduct an active technology driven
exploration program that is designed to complement our property
acquisition and development drilling efforts with moderate to high risk
exploration projects that have greater reserve potential. We generate
exploration prospects through the analysis of geological and geophysical
data and the interpretation of 3-D seismic data. We intend to
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manage our exploration expenditures through the optimal scheduling of our
drilling program and by selectively reducing our participation in certain
exploratory prospects through sales of interests to industry partners.
. Rationalize Property Portfolio. We intend to actively pursue
opportunities to reduce and control operating costs of our existing
properties and properties we may acquire in the future through the
consolidation of overlapping operations, the sale of marginal properties
and by increasing the number of fields we operate as a percentage of our
total properties.
. Maintain Financial Flexibility. We intend to maintain a substantial
unused borrowing capacity under our bank credit facility by periodically
refinancing our bank debt in the capital markets when conditions are
favorable. We believe our expanded base of internally generated cash flow
and other financial resources provide us with the financial flexibility
to pursue additional acquisitions of producing properties and leasehold
acreage and to develop our project inventory in an optimal fashion.
OUR STRENGTHS
We believe our historical success and future performance are, and will be,
directly related to the following combination of strengths:
. Proven Acquisition Experience. Since the investment by W/E LLC (described
below) in August 1999, through the acquisition of the Floyd Oil
Properties (described below), we have added approximately 165 Bcfe of
proved reserves with a PV-10 value of $146.1 million as of December 31,
1999. In addition, in early February we closed the acquisition of
Magellan Exploration, L.L.C. Our acquisition efforts are managed by an
experienced team of property aggregators with extensive engineering,
operating and financial skills.
. Experienced Technical Team. Our technical team is comprised of respected
energy industry professionals with an average of over 20 years of
industry experience.
. Substantial Inventory of Development and Exploration Prospects. We have
assembled an inventory of in excess of 90 drilling locations balanced
between what we believe to be low to moderate risk development locations
and higher risk, higher potential exploratory locations defined by, and
supported with, 3-D seismic data. Our inventory of drilling locations and
degree of operating control provide us flexibility in project selection
and the timing of drilling projects.
. Financial Flexibility. We have the financial flexibility to respond
quickly to opportunities for growth and changing business conditions.
SIGNIFICANT DEVELOPMENTS SINCE DECEMBER 31, 1998
. Acquisition of Control by W/E Energy Company L.L.C. In August 1999, W/E
Energy Company L.L.C., formerly named 3TEC Energy Company L.L.C. ("W/E
LLC"), which is owned by affiliates of EnCap Investments L.L.C. ("EnCap")
and Floyd C. Wilson, purchased a significant interest in us for
approximately $20.5 million in cash and $875,000 in producing properties.
As of December 31, 1999, W/E LLC owned approximately 30% of our
outstanding common stock. Concurrently with the investment by W/E LLC,
Mr. Wilson was named our Chairman, President and Chief Executive Officer.
. Acquisition of Floyd Oil Properties. In November 1999, we completed the
acquisition of properties and interests managed by Floyd Oil Company (the
"Floyd Oil Properties") for $86.8 million in cash and 503,426 shares of
our common stock. The majority of these properties are located in Texas
and Louisiana and, as of December 31, 1999, had estimated proved reserves
of 165 Bcfe with an associated PV-10 value
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of $146.1 million. Additionally, 76% of the acquired reserves are natural
gas and 77% are classified as proved developed. We operate approximately
53% on a PV-10 value basis and, as of December 31, 1999, net daily
production was approximately 41.6 Mmcfe. We plan to aggressively exploit
these properties and have budgeted approximately $17 million for
development drilling and exploitation activity in 2000. Floyd Oil Company
was not affiliated with Floyd C. Wilson prior to its acquisition by the
Company.
. Credit Facility. Concurrent with our acquisition of the Floyd Oil
Properties, we entered into a new $250 million credit facility with Bank
One, Texas, N.A., as agent, and Union Bank of California, N.A., Wells
Fargo Bank, CIBC, Inc. and The Bank of Nova Scotia as participating
lenders. Our borrowing base, which is redetermined semi-annually, has
been initially set at $95.0 million with $87.5 million outstanding as of
December 31, 1999.
One-for-Three Reverse Stock Split. We held a Special Meeting of
Shareholders on January 14, 2000, at which meeting our shareholders
approved an Amendment to the Company's Certificate of Incorporation which
effected a 1-for-3 reverse stock split of our common stock. The reverse
stock split became effective on January 18, 2000. Among the reasons we
proposed the reverse stock split was an effort to increase the trading
price of our common stock to a level above $5 per share, which is the
minimum trading price for admission of the common stock for trading on
the Nasdaq National Market. We have applied for the listing of our common
stock on the Nasdaq National Market.
. Recent Acquisition of Magellan Exploration, LLC. On February 3, 2000, we
completed the acquisition of Magellan Exploration, LLC ("Magellan"), from
certain affiliates of EnCap and other third parties for consideration
consisting of (a) 1,085,934 shares of common stock, (b) four year
warrants to purchase up to 333,333 shares of common stock at $30.00 per
share, (c) 617,008 shares of 5% Series D Convertible Preferred Stock with
a redemption value of $24.00 per share and (d) the assignment of a
performance based "back-in" working interest of 5% of Magellan's interest
in 12 exploration prospects. The acquisition cost, applying the purchase
method of accounting, was $18.3 million. Magellan's properties are
located both onshore and in the shallow waters of south Louisiana and
consist of over 20,000 gross (11,650 net) acres in three prospective
areas. As of December 31, 1999, Ryder Scott Company ("Ryder Scott"),
estimated that Magellan's net proved reserves were 26.6 Bcfe with an
associated PV-10 value of $40.1 million. These proved reserves are
approximately 66% natural gas and 80% of the volumes are classified as
proved undeveloped. Magellan operates approximately 80% of its properties
on a PV-10 value basis. In addition to the proved reserves, the Magellan
properties contain several exploratory drilling locations that have been
identified using 3-D seismic data.
YEAR 2000 COMPLIANCE
We had undertaken various initiatives to ensure that our hardware,
software and equipment functioned properly with the rollover of the date to
January 1, 2000. We experienced no problems as a result of rollover of the dates
to January 1, 2000, and the costs incurred for Year 2000 compliance were
immaterial to our financial position and results of operations. Although we can
provide no assurance, we anticipate any future costs associated with Year 2000
compliance to be immaterial to our financial position and results of operations.
MARKETING
We have marketed the natural gas and oil produced from our properties
through typical channels for these products. We generally sell our oil at local
field prices paid by the principal purchasers of oil. The majority of our
natural gas production is sold at spot prices.
Both natural gas and oil are purchased by marketing companies, pipelines,
major oil companies, public utilities, industrial customers and other users and
processors of petroleum products. We are not confined to, or dependent upon, any
one purchaser or small group of purchasers. Accordingly, the loss of a single
purchaser, or a few purchasers, would not have a long-term material effect on
our business because there are numerous purchasers in the areas in which we sell
our production.
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COMPETITION
We face competition from other oil and gas companies in all aspects of our
business, including acquisition of producing properties and oil and gas leases,
marketing of oil and gas, and obtaining goods, services and labor. Many of our
competitors have substantially larger financial and other resources. Factors
that affect our ability to acquire producing properties include available funds,
available information about the property and our standards established for
minimum projected return on investment. Competition is also presented by
alternative fuel sources, including heating oil and other fossil fuels. We
believe that we are competing and will compete effectively as a result of our
expertise in the acquisition, exploration, and development of oil and gas
reserves and our financial ability to take advantage of such opportunities.
REGULATION
Federal Regulation of Transportation of Natural Gas. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated by the Natural Gas Act of 1938, the Natural Gas Policy Act of
1978, and the regulations promulgated by the Federal Energy Regulatory
Commission. In the past, the federal government has regulated the prices at
which natural gas could be sold. Deregulation of natural gas sales by producers
began with the enactment of the Natural Gas Policy Act. In 1989, Congress
enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining
Natural Gas Act and Natural Gas Policy Act price and non-price controls
affecting producer sales of natural gas effective January 1, 1993. Congress
could, however, reenact price controls in the future.
Our sales of natural gas are affected by the availability, terms and cost of
pipeline transportation. The price and terms for access to pipeline
transportation remain subject to extensive federal regulation. Beginning in
April 1992, the Federal Energy Regulatory Commission issued Order No. 636 and a
series of related orders, which required interstate pipelines to provide open-
access transportation on a basis that is equal for all natural gas suppliers.
The Federal Energy Regulatory Commission has stated that it intends for Order
No. 636 to foster increased competition within all phases of the natural gas
industry. Although Order No. 636 does not directly regulate our production and
marketing activities, it does affect how buyers and sellers gain access to the
necessary transportation facilities and how we and our competitors sell natural
gas in the marketplace. The courts have largely affirmed the significant
features of Order No. 636 and the numerous related orders, although some appeals
remain pending and the Federal Energy Regulatory Commission continues to review
and modify its regulations regarding the transportation of natural gas. One
broad and significant pending review involves examination of several questions,
including whether the transportation regulations should be changed to better
operate together with changes in state law that are introducing competition in
retail natural gas markets, whether the historical method of setting
transportation rates based on cost should be changed for certain transportation,
whether short term transportation capacity should be allocated based only on
auctions, and whether additional changes need to be made to long term
transportation policies to prevent a market bias in favor of short term
transportation. We cannot predict what action the Federal Energy Regulatory
Commission will take on these matters, nor can we accurately predict whether the
Federal Energy Regulatory Commission's actions will achieve the goal of
increasing competition in markets in which our natural gas is sold. However, we
do not believe that any action taken will affect us in a way that materially
differs from the way it affects other oil and natural gas producers.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the Federal Energy Regulatory Commission
and the courts. The natural gas industry historically has been very heavily
regulated; therefore, we cannot assure you that the less stringent regulatory
approach recently pursued by the Federal Energy Regulatory Commission and
Congress will continue.
Federal Regulation of Transportation of Oil. Oil and sales of oil,
condensate and natural gas liquids by us are not currently regulated and are
made at market prices. Effective as of January 1, 1995, the Federal Energy
Regulatory Commission implemented regulations establishing an indexing system
for transportation rates for interstate common carrier oil pipelines. These
rates are generally indexed to inflation, subject to conditions and limitations.
These regulations may, over time, tend to increase transportation costs or
reduce wellhead prices for oil.
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However, we do not believe that these regulations affect us any differently than
other oil and gas producers, gatherers and marketers.
State Regulation. Our oil and gas operations are subject to various types of
regulation at the state and local levels. These regulations require drilling
permits, regulate the methods for developing new fields and the spacing and
operating of wells and waste prevention, and sometimes impose production
limitations. These regulations may limit our production from wells and the
number of wells or locations we can drill.
Some states have adopted regulations with respect to gathering systems.
These regulations have not had a material effect on the operation of our
gathering systems, but we cannot predict whether any future regulations in this
area may have a material impact on our gathering systems.
Federal, State and Indian Leases. Our operations on federal, state or Indian
oil and gas leases are subject to numerous restrictions, including
nondiscrimination statutes. We must conduct our operations on these leases
pursuant to permits and authorization and other regulations issued by the Bureau
of Land Management, Minerals Management Service and other agencies. The Minerals
Management Service currently has under consideration a proposal to change the
manner in which crude oil is valued for purposes of calculating royalty due the
government. If adopted, these changes would decrease reliance on historical
valuation methods and instead adopt an indexing method intended to better
reflect market value, but which may not reflect the proceeds actually received
in the sale of the oil. We cannot predict what action the Minerals Management
Service may ultimately take or how it will affect royalty payable on our
production from federal leases, however, if adopted the changes may tend to
increase costs of royalty payments.
Environmental Regulations. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Our exploration and production
operations and facilities for gathering, treating, processing and handling
hydrocarbons and related exploration and production wastes are subject to
stringent environmental regulation. These laws and regulations sometimes require
government approvals before activities occur, limit or prohibit activities
because of protected areas or species, impose substantial liabilities for
pollution and provide penalties for noncompliance. As with the industry
generally, compliance with existing and anticipated regulations increases our
overall cost of business. These regulations, however, generally affect us and
our competitors similarly. Environmental laws and regulations are subject to
frequent change, and we are not able to predict the costs or other impacts of
environmental regulation on our future operations.
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 some classes of persons
that are considered to have contributed to the release or threat of 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 found at
the site. Persons who are or were responsible for releases of hazardous
substances under CERCLA 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, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.
Our operations are also subject to regulation of air emissions under the
Clean Air Act and comparable state and local requirements. Implementation of
these laws could lead to the gradual imposition of new air pollution control
requirements on our operations. As a result, we may incur capital expenditures
over the next several years to upgrade our air pollution control equipment. We
do not believe that our operations would be materially affected by any such
requirements, nor do we expect such requirements to be any more burdensome to us
than to other companies our size involved in natural gas and oil exploration and
production activities.
In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil exploration and production wastes
as "hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If Congress were to
enact this legislation, it
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could increase our operating costs, as well as those of the natural gas and oil
industry in general. Initiatives to further regulate the disposal of natural gas
and oil wastes are also pending in some states, and these various initiatives
could have a similar impact on us.
The Clean Water Act imposes restrictions and controls on the discharge of
oil and gas wastes and other forms of pollutants into waters of the United
States. Federal law also imposes strict liability on owners of facilities for
consequences of an oil spill where the spill is in navigable waters or along
shorelines. These laws impose penalties for unauthorized discharges and
substantial liability for costs of removal and damages resulting from an
unauthorized discharge. State laws for the control of water pollution provide
similar penalties and liabilities. The cost of compliance with water pollution
laws has not historically been material to our operations. There can be no
assurance that changes in federal, state or local water pollution laws and
programs will not materially adversely affect our operations in the future.
Our management believes that we are in substantial compliance with current
environmental laws and regulations that affect us and that continued compliance
with these requirements will not have a material adverse impact on us.
EMPLOYEES
At December 31, 1999, we had 46 full-time employees. We believe that our
relationships with our employees are satisfactory. None of our employees is
covered by a collective bargaining agreement. From time to time, we use the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design, well-
site surveillance, permitting and environmental assessment.
OUR EXECUTIVE OFFICES
Our principal executive offices are located at Two Shell Plaza, 777 Walker
Street, Suite 2400, in Houston, Texas 77002, and our telephone number is
(713) 821-7100.
ITEM 2. PROPERTIES
DESCRIPTION OF OUR PROPERTIES
We present information regarding our natural gas and oil reserves,
properties, and operating results below. We separately describe the properties
of Magellan, which we acquired on February 3, 2000, under the caption
"Description of Magellan Properties." Except as set forth following the caption
"Description of Magellan Properties", we have not otherwise included information
for the properties of Magellan in any of the information that follows.
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<CAPTION>
As of December 31, 1999
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Budgeted
Estimated Net Proved Reserves Percent 2000
------------------------------- PV-10 Total Identified Capital
Gas Oil Total Value PV-10 Drilling Expenditures
(Mmcf) (MBblS) (Mmcfe) ($000) Value Locations ($000)
------- ------ ------- ------- -------- --------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
East Texas............................. 61,595 669 65,608 44,189 22.2% 53 7,605
Gulf Coast Area........................ 50,661 1,543 59,929 59,771 30.0% 19 7,530
Permian/San Juan Area.................. 20,766 4,793 49,521 55,021 27.7% 2 35
Mid-Continent Area..................... 26,590 2,398 40,978 36,162 18.3% 16 830
Other Areas............................ 87 432 2,676 3,472 1.8% 0 0
------- ----- ------- ------- ----- ----- ------
Total................................. 159,699 9,835 218,712 198,615 100.0% 90 16,000
======= ===== ======= ======= ===== ===== ======
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East Texas. Our properties in the East Texas region produce primarily from
the Cotton Valley and Travis Peak Formations which range in depth from 7,000
feet to 10,500 feet. As of December 31 1999, our estimated net daily production
from this area was 10.6 Mmcfe per day. The producing
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formations of this area tend to contain multiple producing horizons and are
typically low permeability sands that require fracture stimulation to achieve
optimal producing rates. This type of fracture stimulation usually results in
relatively high initial production rates that decline rapidly during the first
year of production and subsequently stabilize at fairly low, more easily
predictable annual decline rates. Much of our production in this area is from
wells that have been producing for several years and are in their latter, more
stable stage of production, resulting in a relatively long reserves to
production ratio. Additionally, reservoirs with multiple producing horizons
typically provide numerous recompletion and workover opportunities to enhance
proved reserves and production. We have identified 53 proved undeveloped
drilling locations in this area. Many of these development drilling locations
are based on a change in regulatory field rules that now permit wells to be
drilled on 80 acre spacing as opposed to 160 acre spacing. This type of infill
drilling is generally effective in low permeability sands, such as the Cotton
Valley, where one wellbore is only capable of draining an area less than the
permitted spacing. Drilling infill wells on 80 acre spacing has been successful
throughout the area in such notable Cotton Valley fields as Carthage, Oak Hill
and Willow Springs. For 2000 we have budgeted approximately $7.6 million for the
drilling of development wells and various exploitation activities.
Gulf Coast Area. We have established a substantial base of proved reserves
and undeveloped acreage with significant exploration potential along the Gulf
Coast of Texas and Louisiana. As of December 31, 1999, our estimated net daily
production from this area was 17.8 Mmcfe per day. Onshore in southern Louisiana
and southeast Texas our production is mainly from the Hackberry, Miogyp and
Vicksburg formations which range from 13,000 feet to 17,000 feet in depth. Along
the central and southern Texas coast we are active in two main areas, the Stuart
City field in the Edwards Reef Trend and the Segundo Olmos field in Webb County,
Texas. The Edwards Reef Trend extends from the Mexican border through the Texas
Gulf Coast into southern Louisiana and has been extensively drilled since the
late 1950s. The Edwards Reef Trend formation is a very thick section of low
permeability limestone that requires fracture stimulation to achieve optimal
production rates and even then will only drain a limited area. Our acreage has
seven producing wells that were drilled on 320 acre spacing and we have
identified seven additional proved undeveloped locations on this acreage based
on drilling infill locations on 120 acre spacing. Infill drilling has been
successful throughout this trend. We are also evaluating the drilling of new
horizontal legs in existing wells and conducting additional fracture
stimulations, both of which have been successful in the Edwards Reef Trend. The
Segundo Olmos field produces from the Olmos formation, a relatively low
permeability sandstone, at a depth of 7,000 feet. This field was originally
drilled on 160 acre spacing and has been successfully drilled on 80 acre spacing
throughout the trend. We have identified an additional five proved undeveloped
locations in this field. In 2000, we have budgeted approximately $7.5 million
for the drilling of development wells and associated exploitation activity in
these areas.
Permian, San Juan and Mid-Continent Areas. We own interests in numerous
fields in the Anadarko, Arkoma, Permian and San Juan basins in the states of
Kansas, Oklahoma, Texas and New Mexico and our estimated net daily production as
of December 31, 1999, was 28.3 Mmcfe per day. These fields are generally
characterized as mature producing fields that have very stable low rates of
decline and a relatively small amount of development drilling and exploitation
potential. In 2000, we have budgeted approximately $900,000 for the drilling of
wells and associated exploitation projects in these areas.
DESCRIPTION OF MAGELLAN PROPERTIES
Through the acquisition of Magellan, we acquired interests in Breton Sound
Block 34 in Louisiana state waters and the Bay De Chene and Garden City fields
in south Louisiana. While there is a relatively small amount of existing
production, all three fields have had 3-D seismic surveys and in the aggregate
have substantial proved undeveloped and proved developed non-producing reserves.
Management believes these properties also have additional exploration potential.
Several experienced engineers and geoscientists at Magellan, who developed many
of the exploration prospects and have extensive experience in south Louisiana,
have joined our technical staff.
Breton Sound Block 34 is located in 12 feet to 15 feet of water east of the
Main Pass area of the Mississippi River delta. This field is currently producing
0.8 Mmcfe per day net to our interest and has significant proved developed
non-producing and proved undeveloped reserves in the Krumbar and Hollywood
formations at approximately 15,000 feet to 17,000 feet in depth. Additionally,
we have identified a proved undeveloped location supported by 3-D seismic data
in Breton Sound Block 34 ("Alpha Prospect") that is structurally high to an
offsetting well drilled by
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Conoco. In addition to our Alpha Prospect, we have identified four additional
exploration prospects in untested fault blocks that have similar characteristics
to the Alpha Prospect based on the interpretation of the 3-D seismic data. In
2000, we have budgeted approximately $3.7 million for development drilling and
recompletions.
The Bay De Chene field and the Garden City field are older fields that have
produced substantial amounts of oil and gas which we believe to have further
development and exploration potential. The Bay De Chene field is a highly
faulted, geologically complex salt dome based structure that has produced over
100 MBbls of oil and 230 Bcf of gas from over 67 different reservoirs. In 1997,
Western Geophysical conducted a 72 square mile 3-D seismic survey resulting in
the identification of numerous potential development drilling locations and
exploitation projects and several exploration drilling prospects. The majority
of these opportunities are between 7,000 feet and 10,000 feet in depth and are
in reservoirs that have been productive throughout the field. This field is
currently producing 1.0 Mmcfe per day net to our interest. The Garden City field
has produced over 2 Tcfe since its discovery and contains one proved undeveloped
drilling location and several exploration prospects. All of these drilling
opportunities have been evaluated with 3-D seismic and subsurface data. In 2000,
we have budgeted approximately $2.8 million for the Bay De Chene and Garden City
fields for development drilling and recompletions. We will continue to evaluate
our exploration projects in these fields.
NATURAL GAS AND OIL RESERVES
The following table presents our estimated net proved natural gas and oil
reserves and the PV-10 value of our reserves as of December 31, 1999 and 1998.
The period end prices of oil and natural gas at December 31, 1999 and 1998, used
in the PV-10 calculation were $23.64 and $9.50 per barrel of oil and $2.23 and
$2.10 per thousand cubic feet of natural gas, respectively. Our estimated net
proved natural gas and oil reserves and the PV-10 value of our reserves as of
December 31, 1999, are based on a reserve report prepared by Ryder Scott Company
for our properties. In 1998 such estimates for our properties were prepared by
Lee Keeling and Associates, Inc. and H.J. Gruy and Associates, Inc. The PV-10
values shown in the table are not intended to represent the current market value
of the estimated natural gas and oil reserves we own. For further information
concerning the PV-10 values of these proved reserves, please read note 15 of the
notes to our December 31, 1999 consolidated financial statements. The
information set forth below does not include reserve information of Magellan
which we acquired in February 2000. See "Description of Magellan Properties."
<TABLE>
<CAPTION>
December 31,
1999 1998
-------- -------
<S> <C> <C>
Proved reserves:
Natural gas (Mmcf)............................................... 159,699 43,483
Oil (MBbls)...................................................... 9,835 3,342
Natural gas equivalents (Mmcfe).................................. 218,711 63,535
Proved developed reserves:
Natural gas (Mmcf)............................................... 122,914 36,731
Oil (MBbls)...................................................... 9,358 3,118
Natural gas equivalents (Mmcfe).................................. 179,062 55,439
Estimated future net cash flows before income taxes, in thousands... $370,258 $71,464
PV-10 value, in thousands........................................... 198,615 38,894
</TABLE>
There are numerous uncertainties in estimating quantities of proved reserves
and in projecting future rates of production and the timing of development
expenditures, including many factors beyond our control. The reserve data herein
are only estimates. Although we believe these estimates to be reasonable,
reserve estimates are imprecise and may be expected to change as additional
information becomes available. Estimates of oil and natural gas reserves, of
necessity, are projections based on engineering data, and there are
uncertainties inherent in the interpretation of this data, as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be exactly
measured. Therefore, estimates of the economically recoverable quantities of oil
and natural gas attributable to any particular group of properties,
classifications of the reserves based on risk of recovery and the estimates are
a function of the quality of available data and of engineering and geological
interpretation and judgment and the future net cash flows expected therefrom,
prepared by different engineers or by
10
<PAGE>
the same engineers at different times may vary substantially. There also can be
no assurance that the reserves set forth herein will ultimately be produced or
that the proved undeveloped reserves will be developed within the periods
anticipated. Actual production, revenues and expenditures with respect to our
reserves will likely vary from estimates, and the variances may be material. In
addition, the estimates of future net revenues from our proved reserves and the
present value thereof are based upon certain assumptions about future production
levels, prices and costs that may not be correct. We emphasize with respect to
the estimates prepared by independent petroleum engineers that PV-10 value
should not be construed as representative of the fair market value of our proved
oil and natural gas properties since discounted future net cash flows are based
upon projected cash flows which do not provide for changes in oil and natural
gas prices or for escalation of expenses and capital costs. The meaningfulness
of such estimates is highly dependent upon the accuracy of the assumptions upon
which they are based. Actual future prices and costs may differ materially from
those estimated.
Volumes, Prices and Operating Expenses
The following table presents information regarding the production volumes
of, average sales prices received for, and average production costs associated
with, our sales of oil and natural gas for the periods indicated. The oil and
natural gas production from the properties acquired in the Floyd Oil
Acquisition, during the period November 23, 1999 to December 31, 1999, was 75
thousand barrels of oil and 1,112 Mmcf of natural gas.
<TABLE>
<CAPTION>
Years Ended December 31,
----------------------------------------------
1999 1998 1997
------------- --------------- ------------
<S> <C> <C> <C>
Production volumes:
Natural gas (Mmcf)..................................... 4,737 3,847 1,929
Oil (MBbls)............................................ 532 581 254
Natural gas equivalents (Mmcfe)........................ 7,928 7,333 3,453
Average sale prices:
Natural gas ($ per Mcf)................................ $ 2.18 $ 2.00 $ 2.39
Oil ($ per Bbl)........................................ 16.88 11.52 18.06
Natural gas equivalents ($ per Mcfe)................... 2.43 1.96 2.82
Average costs ($ per Mcfe):
Lease operating and production taxes................... $ 0.85 $ 1.06 $ 1.11
General and administrative............................. 0.60 0.58 0.68
Depreciation, depletion and amortization............... 0.84 0.97 1.32
</TABLE>
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES
The following table presents unaudited information regarding our net costs
incurred in the purchase of properties and in exploration and development
activities.
<TABLE>
<CAPTION>
Years Ended December 31,
---------------------------
1999 1998
---------- ------------
(in thousands)
<S> <C> <C>
Acquisition.................................... $91,424 $29,215
Exploration.................................... 824 1,802
Development.................................... 2,154 3,041
------- -------
Total costs incurred...................... $94,402 $34,058
======= =======
</TABLE>
11
<PAGE>
DRILLING ACTIVITY
The following table shows our drilling activity for the years ended December
31, 1999, 1998 and 1997. In the table, "gross" refers to the total wells in
which we have a working interest and "net" refers to gross wells multiplied by
our working interest in these wells.
<TABLE>
<CAPTION>
Years Ended December 31
-------------------------------------------------------------
1999 1998 1997
------------------- ------------------ ------------------
Gross Net Gross Net Gross Net
-------- -------- ------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Exploration Wells:
Productive................ 0 0.000 1 0.125 8 0.452
Non-Productive............ 5 0.900 8 0.793 11 1.280
-- ----- -- ----- -- -----
Total.................. 5 0.900 9 0.918 19 1.732
== ===== == ===== == =====
Development Wells:
Productive................ 21 5.667 12 1.508 17 5.627
Non-Productive............ 0 0.000 2 1.100 6 4.150
-- ----- -- ----- -- -----
Total.................. 21 5.667 14 2.608 23 9.777
== ===== == ===== == =====
</TABLE>
Productive Wells
The following table sets forth the number of productive natural gas and oil
wells in which we owned an interest as of December 31, 1999.
<TABLE>
<CAPTION>
Total Productive Wells
----------------------
Gross Net
------- ----------
<S> <C> <C>
Natural Gas................ 677 252
Oil........................ 1,478 395
----- ---
Total................. 2,155 647
===== ===
</TABLE>
Productive wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections to commence deliveries
and oil wells awaiting connection to production facilities. At December 31,
1999, we operated approximately 425 wells, located primarily in Texas.
ACREAGE DATA
The following table presents information regarding our developed and
undeveloped lease acreage as of December 31, 1999. Developed acreage refers to
acreage within producing units and undeveloped acreage refers to acreage that
has not been placed in producing units.
<TABLE>
<CAPTION>
Developed Undeveloped
------------------------- ---------------------------
Acreage Acreage Total
------------------------- --------------------------- ---------------------------
Gross Net Gross Net Gross Net
----------- ----------- ------------ ------------ ------------- -----------
<S> <C> <C> <C> <C> <C> <C>
Texas............. 169,924 53,245 6,575 1,315 176,499 54,560
Louisiana......... 23,031 2,691 2,568 983 25,599 3,674
Kansas............ 20,579 13,171 6,507 6,507 27,086 19,678
Oklahoma.......... 79,256 22,846 205 205 79,461 23,051
Other............. 164,857 60,258 560 490 165,417 60,748
------- ------- ------ ----- ------- -------
Total........ 457,647 152,211 16,415 9,500 474,062 161,711
======= ======= ====== ===== ======= =======
</TABLE>
Excluded from the acreage data are approximately 35,214 net mineral acres
owned by us, primarily in La Fourche, St. Mary and Terrebonne parishes of
Louisiana, all of which we believe have potential for oil and natural gas
exploration.
CURRENT ACTIVITIES
As of March 29, 2000, five wells (1.486 net wells) were being drilled. Three
wells are in Louisiana, one in Texas and one in Oklahoma.
12
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are party to various routine litigation proceedings
incidental to our business. We currently are not a party to any material
litigation.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On October 28, 1999, a proxy was mailed to shareholders of record on
October 1, 1999, soliciting their vote at a Special Meeting of Shareholders of
the Company on November 18, 1999. The following matters were submitted to a vote
of shareholders (Shares Eligible to Vote on All Matters: 4,453,744):
1. To approve a change in the Company's state of incorporation from Alabama to
Delaware by means of a merger of the Company with and into a wholly-owned
subsidiary, 3TEC Energy Corporation, a Delaware corporation, which the
Company formed for this purpose.
The reincorporation to Delaware was approved.
For Against Abstain
3,823,583 1,919 964
2. To approve a change of the Company's name to 3TEC Energy Corporation.
The name change was approved.
For Against Abstain
4,093,954 5,336 1,357
3. To approve an increase in the number of authorized shares of common stock of
the Company from 40,000,000 to 60,000,000
The increase in the authorized shares of common stock was approved.
For Against Abstain
4,091,636 7,243 1,081
4. To consider and approve the Company's 1999 Stock Option Plan
The 1999 Stock Option Plan was approved.
For Against Abstain
3,816,955 7,392 2,119
FORWARD-LOOKING STATEMENTS
This information herein and the information incorporated by reference
contain statements that constitute "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. These statements appear
in a number of places and include statements regarding our plans, beliefs,
intentions or current expectations, including those plans, beliefs, intentions
and expectations of our officers and directors with respect to, among other
things:
. budgeted capital expenditures;
. increases in oil and gas production;
. our outlook on oil and gas prices;
13
<PAGE>
. estimates of our oil and gas reserves;
. our future financial condition or results of operations; and
. our business strategy and other plans and objectives for future
operations.
More specifically, some of the statements contained herein under "Risk
Factors," "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Business and Properties" that relate to our business
and the industry in which we operate are forward-looking. Statements or
assumptions related to or underlying these forward-looking statements include,
without limitation, statements regarding:
. the quality or value of our properties with regard to, among other
things, the existence of reserves in economic quantities;
. our ability to increase our reserves through exploration and development
activities;
. the number of locations to be drilled and the time frame within which
they will be drilled;
. future prices of oil and natural gas;
. anticipated domestic demand for oil and natural gas; and
. the adequacy of our capital resources and liquidity.
Actual results may differ materially from those suggested by the forward-looking
statements for various reasons, including those discussed under "Risk Factors".
RISK FACTORS
OIL AND GAS PRICES ARE VOLATILE, AND LOW PRICES HAVE IN THE PAST AND COULD IN
THE FUTURE HAVE A MATERIAL ADVERSE IMPACT ON OUR BUSINESS.
Our revenues, profitability and future growth and the carrying value of our
properties depend substantially on prevailing oil and gas prices. Prices also
affect the amount of cash flow available for capital expenditures and our
ability to borrow and raise additional capital. The amount we will be able to
borrow under our credit facility will be subject to periodic redetermination
based in part on changing expectations of future prices. Lower prices may also
reduce the amount of oil and gas that we can economically produce.
Historically, the markets for oil and gas have been volatile, and they are
likely to continue to be volatile in the future. For example, natural gas and
oil prices declined significantly in late 1997 and 1998. These declines had a
significant negative impact on our financial results for 1997, 1998 and the
first two quarters of 1999, contributing to our losses for those periods. Among
the factors that can cause volatility are:
. the domestic and foreign supply of natural gas and oil;
. the ability of members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil prices and production levels;
. political instability or armed conflict in oil or gas producing regions;
. the level of consumer product demand;
. weather conditions;
. the price and availability of alternative fuels;
. the price of foreign imports; and
. worldwide economic conditions.
These external factors and the volatile nature of the energy markets make it
difficult to estimate future prices of oil and gas.
WE MAY NOT SUCCESSFULLY INTEGRATE THE OPERATIONS OF THE PROPERTIES WE HAVE
ACQUIRED OR MAY ACQUIRE OR ACHIEVE THE BENEFITS WE ARE SEEKING.
Our success will partially depend upon the integration of the operations and
selected personnel relating to the Floyd Oil Properties and the acquisition of
Magellan. Our management team does not have experience with the
14
<PAGE>
combined activities of 3TEC, the Floyd Oil Properties and Magellan. In addition,
our new management team, including personnel formerly with Magellan and Floyd
Oil Company, has not previously worked together as a single team and thus is
subject to the personnel and other risks experienced by newly combined
operations. We may not be able to integrate these operations without loss of
important employees, loss of revenues, increases in operating or other costs, or
other difficulties. In addition, we may not be able to realize the operating
efficiencies and other benefits sought from our acquisitions.
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES THROUGH OUR DRILLING
OR ACQUISITION ACTIVITIES.
In general, the volume of production from oil and gas properties declines as
reserves are depleted. Our reserves will decline as they are produced unless we
acquire properties with proved reserves or conduct successful development and
exploration activities. Our future natural gas and oil production is highly
dependent upon our level of success in finding or acquiring additional reserves.
However, we cannot assure you that our future acquisition, development and
exploration activities will result in additional proved reserves or that we will
be able to drill productive wells at acceptable costs.
Our recent growth is due largely to acquisitions of producing properties.
The successful acquisition of producing properties requires an assessment of a
number of factors. These factors include recoverable reserves, future oil and
gas prices, operating costs and potential environmental and other liabilities,
title issues and other factors. Such assessments are inexact and their accuracy
is inherently uncertain. In connection with such assessments, we perform a
review of the subject properties that we believe is generally consistent with
industry practices. However, such a review will not reveal all existing or
potential problems. In addition, the review will not permit a buyer to become
sufficiently familiar with the properties to fully assess their deficiencies and
capabilities. Although the increased availability of properties has caused a
decrease in the prices paid for these properties, we cannot assure you that we
will be able to acquire properties at acceptable prices because the competition
for producing oil and gas properties is intense and many of our competitors have
financial and other resources which are substantially greater than those
available to us.
OUR LEVEL OF BORROWINGS MAY MATERIALLY AFFECT OUR OPERATIONS.
As of December 31, 1999, our long-term debt was $87.5 million and we had
$7.5 million of additional available borrowing capacity under our bank credit
facility. The borrowing base limitation under our credit facility is semi-
annually redetermined. Upon a redetermination, we could be forced to repay a
portion of our bank debt. We may not have sufficient funds to make such
repayments. We intend to finance our development, acquisition and exploration
activities with cash flow from operations, bank borrowings and other financing
activities. In addition, we may significantly alter our capitalization in order
to make future acquisitions or develop our properties. These changes in
capitalization may significantly increase our level of debt. We may also be able
to incur substantial additional indebtedness in the future. If we incur
additional debt for these or other purposes, the related risks that we now face
could intensify. A higher level of debt also increases the risk that we may
default on our debt obligations. Our ability to meet our debt obligations and to
reduce our level of debt depends on our future performance. General economic
conditions and financial, business and other factors affect our operations and
our future performance. Many of these factors are beyond our control. Our level
of debt affects our operations in several important ways, including the
following:
. a portion of our cash flow from operations is used to pay interest on
borrowings;
. the covenants contained in the agreements governing our debt limit our
ability to borrow additional funds, dispose of assets or issue shares of
preferred stock and otherwise may affect our flexibility in planning
for, and reacting to, changes in business conditions;
. a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes;
. a leveraged financial position would make us more vulnerable to economic
downturns and could limit our ability to withstand competitive
pressures; and
15
<PAGE>
. any debt that we incur under our credit facility will be at variable
rates which makes us vulnerable to increases in interest rates.
WE HAVE INCURRED LOSSES FROM OPERATIONS IN THE PAST, AND OUR FAILURE TO ACHIEVE
OR SUSTAIN PROFITABILITY IN THE FUTURE COULD ADVERSELY AFFECT THE MARKET PRICE
OF OUR COMMON STOCK.
We incurred net losses of $4.0 million in 1999 and $6.7 million in 1998. On
a pro forma basis, giving effect to the acquisition of the Floyd Oil Properties,
we would have earned a profit of $2.4 million for the year ended December 31,
1999, but the pro forma results may not be indicative of actual operating
results had we acquired the Floyd Oil Properties at the beginning of the period.
We cannot assure you that we will achieve or sustain profitability in the
future. Our failure to achieve or sustain profitability in the future could
adversely affect the market price of our common stock.
PRICES OF OUR COMMON STOCK MAY BE VOLATILE.
The market price of our common stock may be subject to significant
fluctuations in response to events beyond our control. Normal fluctuations in
the prices of our stock may be increased by our trading volumes, which have been
historically low. Our trading volumes may be further reduced by the 1-for-3
reverse split of our common stock effected on January 18, 2000.
OUR ABILITY TO FINANCE OUR BUSINESS ACTIVITIES WILL REQUIRE US TO GENERATE
SUBSTANTIAL CASH FLOW.
Our business activities require substantial capital. We have budgeted total
capital expenditures for 2000 of approximately $23 million. We intend to finance
our capital expenditures in the future through cash flow from operations, the
incurrence of additional indebtedness and/or the issuance of additional equity
securities. We cannot be sure that our business will continue to generate cash
flow at or above current levels. Future cash flow and the availability of
financing will be subject to a number of variables, such as:
. the level of production from existing wells;
. prices of oil and natural gas;
. our results in locating and producing new reserves; and
. general economic, financial, competitive, legislative, regulatory and
other factors beyond our control.
If we are unable to generate sufficient cash flow from operations to service
our debt, we may have to obtain additional financing. We cannot be sure that any
additional financing will be available to us on acceptable terms. Issuing equity
securities to satisfy our financing requirements could cause substantial
dilution to our existing stockholders. The level of our debt financing could
also materially affect our operations. See "Our level of borrowings may
materially affect our operations."
If our revenues were to decrease due to lower oil and natural gas prices,
decreased production or other reasons, and if we could not obtain capital
through our credit facility or otherwise, our ability to execute our development
and acquisition plans, replace our reserves or maintain production levels could
be greatly limited.
DRILLING WELLS IS SPECULATIVE, OFTEN INVOLVES SIGNIFICANT COSTS AND MAY NOT
RESULT IN ADDITIONS TO OUR PRODUCTION OR RESERVES.
Developing and exploring for oil and gas reserves involves a high degree of
operating and financial risk. The budgeted costs of drilling, completing and
operating wells are often exceeded and can increase significantly when drilling
costs rise due to a tightening in the supply of various types of oilfield
equipment and related services. Drilling may be unsuccessful for many reasons,
including title problems, weather, cost overruns, equipment shortages and
mechanical difficulties. Moreover, the successful drilling of an oil or gas well
does not ensure a profit on investment. Exploratory wells bear a much greater
risk of loss than development wells. A variety of factors, both geological and
market-related, can cause a well to become uneconomical or only marginally
economic. In addition to their cost, unsuccessful wells can hurt our efforts to
replace reserves.
16
<PAGE>
WE DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE SERIOUSLY HARMED BY
UNEXPECTED LIABILITIES.
Exploration for and production of oil and natural gas can be hazardous,
involving natural disasters and other unforeseen occurrences such as blowouts,
cratering, fires and loss of well control, which can damage or destroy wells or
production facilities, injure or kill people, and damage property and the
environment. Because third party drilling contractors are used to drill our
wells, we may not realize the full benefit of workmen's compensation laws in
dealing with their employees. We maintain insurance against many potential
losses and liabilities arising from our operations in accordance with customary
industry practices and in amounts that we believe to be prudent. However, our
insurance does not protect us against all operational risks.
ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE AND ANY
MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES WILL MATERIALLY AFFECT THE
QUANTITIES AND PV-10 VALUE OF OUR RESERVES.
The information herein contains estimates of our proved oil and gas reserves
and the estimated future net revenues from such reserves. These estimates are
based upon various assumptions, including assumptions required by the Securities
and Exchange Commission relating to oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The process of
estimating oil and gas reserves is complex. This process requires significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Therefore, these
estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves will most likely vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves
set forth herein and the information incorporated by reference. Our properties
may also be susceptible to hydrocarbon drainage from production by other
operators on adjacent properties. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development,
prevailing oil and gas prices and other factors, many of which are beyond our
control. Actual production, revenues, taxes, development expenditures and
operating expenses with respect to our reserves will likely vary from the
estimates used. These variances may be material.
At December 31 1999, approximately 18% of our estimated proved reserves were
undeveloped. The percentage of proved undeveloped properties were increased as a
result of the addition of the Magellan properties. Undeveloped reserves, by
their nature, are less certain than developed reserves. Recovery of undeveloped
reserves requires significant capital expenditures and successful drilling
operations. The reserve data assumes that we will make significant capital
expenditures to develop our reserves. Although we have prepared estimates of our
oil and gas reserves and the costs associated with these reserves in accordance
with industry standards, we cannot assure you that the estimated costs are
accurate, that development will occur as scheduled or that the actual results
will be as estimated.
In addition, you should not construe PV-10 value as the current market value
of the estimated oil and natural gas reserves attributable to our properties. We
have based the estimated discounted future net cash flows from proved reserves
on prices and costs as of the date of the estimate, in accordance with
applicable regulations, whereas actual future prices and costs may be materially
higher or lower. Many factors will affect actual future net cash flow,
including:
. prices for oil and natural gas;
. the amount and timing of actual production;
. supply and demand for oil and natural gas;
. curtailments or increases in consumption by oil and natural gas
purchasers; and
. changes in governmental regulations or taxation.
The timing of the production of oil and natural gas properties and of the
related expenses affect the timing of actual future net cash flow from proved
reserves and, thus, their actual PV-10 value. In addition, the 10% discount
factor, which we are required to use in calculating PV-10 value for reporting
purposes, is not necessarily the most appropriate discount factor given actual
interest rates and risks to which our business or the oil and natural gas
industry in general are subject.
17
<PAGE>
A SMALL NUMBER OF EXISTING STOCKHOLDERS CONTROL OUR COMPANY, WHICH COULD LIMIT
YOUR ABILITY TO INFLUENCE THE OUTCOME OF STOCKHOLDER VOTES.
W/E LLC, an affiliate of EnCap and Floyd C. Wilson, our President and Chief
Executive Officer, Kaiser-Francis Oil Company, C. J. Lett, III, Weskids, L.P.,
Alvin V. Shoemaker and EnCap and its affiliates collectively own approximately
68% of our outstanding common stock as of December 31, 1999. These stockholders
have entered into an agreement pursuant to which they have agreed to vote all
their shares to elect three members of the board of directors designated by W/E
LLC and two members of the board of directors designated collectively by Kaiser-
Francis Oil Company, C.J. Lett III, Weskids, L.P. and Alvin V. Shoemaker. As a
result, these entities will have a significant voice in the outcome of
stockholder votes, including votes concerning the election of directors, the
adoption or amendment of provisions in our charter or bylaws and the approval of
mergers and other significant corporate transactions so long as they maintain
their current holdings of common stock.
COMPETITION IN OUR INDUSTRY IS INTENSE, AND WE ARE SMALLER AND HAVE A MORE
LIMITED OPERATING HISTORY THAN MANY OF OUR COMPETITORS.
We compete with major integrated oil and gas companies and independent oil
and gas companies in all areas of operation. In particular, we compete for
property acquisitions and for the equipment and labor required to operate and
develop these properties. Most of our competitors have substantially greater
financial and other resources than we have. In addition, larger competitors may
be able to absorb the burden of any changes in federal, state and local laws and
regulations more easily than we can, which would adversely affect our
competitive position. These competitors may be able to pay more for exploratory
prospects and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than we can. Our ability to explore for
natural gas and oil prospects and to acquire additional properties in the future
will depend on our ability to conduct operations, to evaluate and select
suitable properties and to consummate transactions in this highly competitive
environment. In addition, most of our competitors have operated for a much
longer time than we have and have demonstrated the ability to operate through
industry cycles.
HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.
In order to manage our exposure to price risks in the marketing of our oil
and natural gas production, we have in the past and may in the future enter into
oil and gas price hedging arrangements with respect to a portion of our expected
production. Our hedging arrangements may include futures contracts on the New
York Mercantile Exchange. While intended to reduce the effects of volatile oil
and gas prices, such transactions may limit our potential gains if oil and gas
prices were to rise substantially over the price established by the hedge. In
addition, such transactions may expose us to the risk of financial loss in
certain circumstances, including instances in which:
. our production is less than expected;
. there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement;
. the counterparties to our future contracts fail to perform the
contracts; and
. a sudden, unexpected event materially impacts oil or gas prices.
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE.
Our management changed significantly with W/E LLC's investment. We have
three new directors, a new chief executive officer and a number of other new
management and professional personnel. Our operations will be dependent upon
retaining this group of key management and technical personnel. Recognizing
their importance, we have entered into employment agreements with Floyd C.
Wilson and Stephen W. Herod. We cannot assure you that such individuals will
remain with us for the immediate or foreseeable future. If we cannot retain our
current personnel or attract additional experienced personnel, our ability to
compete could be adversely affected.
WE ARE SUBJECT TO COMPLEX LAWS AND REGULATIONS, INCLUDING ENVIRONMENTAL
REGULATIONS, THAT CAN ADVERSELY AFFECT THE COST, MANNER OR FEASIBILITY OF DOING
BUSINESS.
18
<PAGE>
Our operations are subject to numerous laws and regulations governing the
operation and maintenance of our facilities and the discharge of materials into
the environment or otherwise relating to environmental protection. These laws
and regulations may:
. require that we acquire permits before commencing drilling;
. restrict the substances that can be released into the environment in
connection with drilling and production activities;
. limit or prohibit drilling activities on protected areas such as
wetlands or wilderness areas; and
. require remedial measures to mitigate pollution from former operations,
such as plugging abandoned wells.
Under these laws and regulations, we could be liable for personal injury and
clean-up costs and other environmental and property damages, as well as
administrative, civil and criminal penalties. We maintain limited insurance
coverage for some but not all of the environmental damages for which we could be
liable. Moreover, we do not believe that insurance coverage for the full
potential liability that could be caused by sudden and accidental environmental
damages is available at a reasonable cost. Accordingly, we may be subject to
liability or we may be required to cease production from properties in the event
of environmental damages.
These laws and regulations have been changed frequently in the past. In
general, these changes have imposed more stringent requirements that increase
operating costs or require capital expenditures in order to remain in
compliance. It is also possible that unanticipated developments could cause us
to make environmental expenditures that are significantly different from those
we currently expect. Existing laws and regulations could be changed, and any
changes could have an adverse effect on our business.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION
Our common stock is currently quoted on the Nasdaq SmallCap Market under the
market symbol "TTEN." We have applied for inclusion of the common stock on the
Nasdaq National Market. We held a Special Meeting of Shareholders on January 14,
2000, at which meeting our shareholders approved an Amendment to the Company's
Certificate of Incorporation which effected a 1-for-3 reverse stock split of our
common stock. The reverse stock split became effective on January 18, 2000.
Among the reasons we proposed the reverse stock split was an effort to increase
the trading price of our common stock to a level above $5 per share, which is
the minimum trading price for admission of the common stock for trading on the
Nasdaq National Market. Our trading price has remained above $5 per share since
January 18, 2000. All share and share related numbers in this report have been
prepared, unless otherwise indicated, based on the number of shares outstanding
after the reverse split.
The following table sets forth the high and low bid prices per share of our
common stock for the periods indicated on the Nasdaq SmallCap Market, as
reported by the National Quotation Bureau, LLC. The high and low bid amounts for
periods prior to January 18, 2000, have been adjusted to reflect the 1-for-3
reverse split of our common stock effective on that date. The bid information
below reflects inter-dealer prices, without retail mark-ups, mark-downs or
commissions and may not necessarily represent actual transactions.
<TABLE>
<CAPTION>
Period High Low
------ -------- --------
<S> <C> <C> <C>
1998 First Quarter.............................................................. $30.00 $17.25
Second Quarter............................................................. 23.25 15.19
Third Quarter.............................................................. 15.38 9.00
Fourth Quarter............................................................. 9.75 5.25
1999 First Quarter.............................................................. 8.63 4.13
Second Quarter............................................................. 8.06 5.25
Third Quarter.............................................................. 14.44 7.50
Fourth Quarter............................................................. 13.59 7.13
2000 First Quarter (through March 13, 2000)..................................... 10.68 7.50
</TABLE>
On March 13, 2000, the last reported sale price of our common stock on the
Nasdaq SmallCap Market was $8.00 per share.
On March 13, 2000, there were 916 holders of record of our common stock.
Our transfer agent is American Stock Transfer and Trust Company located at
40 Wall Street, New York, New York 10005. You may call them toll free at
800-937-5449 to answer any questions about transferring your stock.
We have never declared or paid any cash dividends on our common stock. We
currently intend to retain future earnings, if any, for the operation and
development of our business and do not anticipate paying any cash dividends on
our common stock in the foreseeable future. In addition, our credit facility
prohibits us from paying cash dividends on our common stock. Any future
dividends are also restricted by the terms of our outstanding preferred stock
and may be restricted by any debt agreements which we may enter into from time
to time.
We are obligated to pay net cash dividends in the amount of approximately
$570,000 per year on our Series C Preferred Stock and dividends of $740,000 per
year on our Series D Preferred Stock which may be paid, at our option, in cash
or in additional shares of Series D Preferred Stock during the three years
ending February 1, 2003. Our credit facility permits the payment of dividends on
our Series C Preferred Stock. We currently do not have a
20
<PAGE>
waiver under the credit facility to pay cash dividends on Series D Preferred
Stock. However, we expect to pay dividends on the Series D Preferred Stock in
additional Series D shares.
EQUITY PLACEMENT NOT REGISTERED UNDER THE SECURITIES ACT
On October 19, 1999, we closed a transaction exempt under Section 4 of the
Securities Act of 1933, as amended (the "Act"), with the Prudential Insurance
Company of America ("Prudential"), an accredited investor, pursuant to which
Prudential purchased 351,681 shares of our common stock and five-year warrants
(the "Warrants") to purchase 266,226 shares of our common stock at an exercise
price of $3.00 per share for a total purchase price of $2.4 million.
Additionally, we issued Prudential a five-year senior subordinated convertible
promissory note in the principal amount of $2,373,844 (the "Note"). The Note is
convertible at any time into our common stock at $9.00 per share (a total of
263,760 shares of our common stock). Interest at nine percent (9%) per annum is
payable on the Note quarterly. We may defer fifty percent (50%) of the first
eight interest payments and add them to the principal due at maturity. The Note
is subordinate to our bank credit facility. Prudential (as noteholder) must
approve certain changes including changes in the credit facility and corporate
structure of 3TEC until the Note is paid.
Sixty percent (60%) of the Warrants may be exercised by Prudential at any
time. The remaining forty percent (40%) may be exercised incrementally over the
five-year term of the Warrants. If the entire principal balance of Note is
converted to common stock , all of the outstanding warrants immediately become
exercisable. The Warrants may be exercised for cash or reduction of the Note
principal.
On November 23, 1999, we closed a transaction to purchase properties and
interests owned by a group of private accredited investors which were managed by
Floyd Oil Company (the "Floyd Oil Properties"). The transaction had an adjusted
purchase price of approximately $86.8 million in cash and 503,426 shares of
our common stock. The source of the funds used to purchase the Floyd Oil
Properties was existing working capital and our credit facility. The transaction
was exempt under Section 4 of the Act.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
You should read the following discussion and analysis in conjunction with
our audited consolidated financial statements. The following information
contains forward-looking statements. See "Forward-Looking Statements".
Overview
- --------
We are engaged in the acquisition, development, production and exploration
of oil and natural gas reserves. Our properties are concentrated in East Texas
and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of
Mexico. We also own significant properties in the Permian and San Juan basins
and in the Mid-Continent region. Our management and technical staff have
substantial experience in each of these areas. As of December 31, 1999, we had
estimated total net proved reserves of 218.7 Bcfe, of which approximately 73%
were natural gas and approximately 82% were proved developed, with an estimated
PV-10 value of $198.6 million. As of December 31, 1999, our net daily production
was approximately 38.1 Mmcf of natural gas and 3.1 MBbls of oil or 56.7 Mmcfe.
We have increased our reserves and production principally through acquisitions.
We focus on properties that have a substantial proved reserve component and
which management believes to have additional exploitation opportunities. In
early 2000, we acquired a number of drilling prospects covered by an extensive
3-D seismic database that we believe have exploration potential. We have
assembled an experienced management team and technical staff with expertise in
property acquisitions and development, reservoir engineering, exploration and
financial management.
Formerly known as Middle Bay Oil Company, Inc., an entity formed under the
laws of the state of Alabama in 1992, we underwent a change of control in August
1999, in a transaction in which W/E Energy Company, LLC (formerly 3TEC Energy
Company, LLC) invested $21.4 million in cash and oil and gas properties for
common stock representing at that time approximately 36% of our then outstanding
common stock.
Since our formation in 1992, we have grown principally through several
acquisitions of proved properties in the Gulf Coast and Mid-Continent regions.
Acquisitions made in 1997 and 1998 significantly increased our reserves and
production but were primarily nonoperated properties with high per Mcfe lease
operating costs. Following the change in control discussed above, during the
second half of 1999, we closed several transactions that changed our senior
management team, capitalization and our property base. In addition, we added
several experienced professionals to our technical staff. Because of these
recent transactions, our historical results of operations and cash flows will
differ materially from, and will not be representative of, our future results.
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<PAGE>
We increased our asset base substantially and decreased our operating cost
per Mcfe on a pro forma basis with the acquisition of the Floyd Oil Properties
in November 1999. The Floyd Oil Properties had estimated net proved reserves at
December 31, 1999, of 165 Bcfe with a PV-10 value of $146.1 million. On a pro
forma basis, the Floyd Oil Properties resulted in additional pro forma EBITDAX
of $17.9 million and $20.6 million and additional pro forma revenues of $34.1
million and $33.8 million for the years ended 1998 and 1999, respectively.
Compared to our historical operating cost per Mcfe, on a pro forma basis, after
giving effect to the Floyd Oil Properties, our total operating cost per Mcfe for
the years ended 1998 and 1999 declined 10% and 1% to $0.95 and $0.84,
respectively. Compared to our historical general and administrative cost per
Mcfe, on a pro forma basis, general and administrative cost per Mcfe for the
same periods declined 45% and 50% to $0.32 and $0.30, respectively. Revenues and
expenses from the Floyd Oil Properties are included in our historical operating
results only for the period from November 23, 1999, the date of acquisition,
through December 31, 1999.
Additionally, in early 2000 we closed the acquisition of Magellan
Exploration, LLC ("Magellan"), which owns primarily proved undeveloped reserves,
with significant 3-D seismic data. We plan to fund a development program of
Magellan's undeveloped properties, which we believe could increase future
reserves and production. In addition, we are continually seeking and reviewing
acquisitions of properties and companies which we believe will be accretive to
our reserves and production, and expect our acquisition program to continue to
be a significant source of growth for us, depending, of course, on the market
for oil and gas properties, and industry conditions generally.
Certain Accounting Practices
- ----------------------------
We use the successful efforts method of accounting for our investments in
oil and natural gas properties. Under this method, we capitalize all direct
costs incurred in connection with the acquisition, drilling and development of
productive oil and natural gas properties. Costs associated with unsuccessful
exploration are expensed as incurred. Geological and geophysical costs and costs
of carrying and retaining unevaluated properties are expensed as incurred.
Depreciation, depletion and amortization of capitalized costs are computed
separately for each field based on the unit of production method using only
proved oil and gas reserves.
We review our oil and gas properties on a field level for impairment when
circumstances indicate that the capitalized costs less accumulated depreciation,
depletion and amortization (the "Carrying Value") of the property may not be
recoverable. If the Carrying Value of the property exceeds the expected future
undiscounted cash flows, an amount equal to the excess of the Carrying Value
over the fair value of the property is charged to operations. An impairment
results in a non-cash charge to earnings but does not affect cash flows.
Liquidity and Capital Resources
- -------------------------------
CASH FLOW. We believe that our cash flows from operations are adequate to meet
the requirements of operating our business. However, future cash flows are
subject to a number of variables, including our level of production and prices,
and we cannot assure you that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of capital
expenditures. Our principal operating sources of cash include sales of natural
gas and oil.
Our pro forma EBITDAX, including the Floyd Oil Properties, for the years
ended December 31, 1999 and 1998, was $29.2 million and $21.4 million,
respectively. For the year 2000, we have budgeted approximately $23 million for
capital expenditures, including an estimated $7 million with respect to the
properties acquired in the Magellan acquisition. We are obligated to pay
dividends of approximately $570,000 per year on the Series C Preferred Stock in
cash and dividends of $740,000 per year on the Series D Preferred Stock which we
may pay in either cash or in additional shares of Series D Preferred Stock
during the three years ending February 1, 2003. We are obligated to pay interest
on the convertible subordinated notes of approximately $1.2 million per year.
22
<PAGE>
Our primary source of financing for acquisitions has been borrowing under
our credit facility, discussed below. We believe we will have sufficient cash
flow from operations and borrowings under our credit facility to meet our
obligations and operating needs for the coming year. However, future cash flows
are subject to a number of variables, including our level of production and
prices, and we cannot assure you that operations and other capital resources
will provide cash in sufficient amounts to maintain planned levels of capital
expenditures.
CREDIT FACILITY. In connection with our acquisition of the Floyd Oil
Properties on November 23, 1999, we entered into a credit facility with Bank
One, Texas, N.A. and certain other financial institutions. Our then existing
bank debt of $26.6 million was paid in full with proceeds from the new facility.
The credit facility provides for a borrowing base which is adjusted periodically
on the basis of the discounted present value attributable to our proved
producing oil and gas reserves, as determined by our lenders. The credit
facility currently provides for a $95 million borrowing base. The borrowing base
will be redetermined semi-annually on May 1 and November 1 of each year.
Interest under the facility accrues at our option at a rate calculated as either
the bank's prime rate plus 25 basis points or LIBOR plus basis points increasing
from a low of 125 to a high of 187.5 as loans outstanding increase as a
percentage of the borrowing base. We are currently paying 7.63% per annum
interest on the entire principal balance of the facility of $85 million. The
loan matures on November 30, 2002. Prior to maturity, no payments of principal
are required so long as the borrowing base exceeds the loan balance. The
borrowings under the facility are secured by substantially all of our
properties. At December 31, 1999, the amount available to be borrowed under the
credit facility was approximately $7.5 million.
In connection with this credit facility, we are required to adhere to certain
affirmative and negative covenants. The loan agreement contains a number of
dividend restrictions and restrictive covenants which, among other things,
require the maintenance of minimum current and interest coverage ratios.
MARKET RISK. We generally sell our oil at local field prices paid by the
principal purchasers of oil. The majority of our natural gas production is sold
at spot prices. Accordingly, we are generally subject to the commodity prices
for these resources as they vary from time to time. Prices since mid-1998 have
generally followed an increasing trend, but the market continues to have
considerable volatility. We are engaged in certain hedging transactions with
respect to our activities.
INFLATION AND CHANGES IN PRICES. Our revenues and the value of our oil and gas
properties have been and will be affected by changes in natural gas and crude
oil prices. Our ability to maintain current borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent on
natural gas and crude oil prices. These prices are subject to significant
seasonal and other fluctuations that are beyond our ability to control or
predict. During 1999, we received an average of $16.88 per barrel of crude oil
and $2.18 per Mcf of gas. Although some costs and expenses are affected by the
level of inflation, inflation has not had a significant effect in recent years.
Should conditions in the industry continue to improve, causing an increase in
competition resulting in a relative shortage of oilfield supplies and/or
services, inflationary cost pressures may resume.
Results of Operations
- ---------------------
Our revenue, profitability, and future rate of growth are dependent upon
prevailing prices for oil and gas, which, in turn, depend upon numerous factors
such as economic, political, and regulatory developments as well as competition
from other sources of energy. The energy markets historically have been highly
volatile, and future decreases in prices could have an adverse effect on our
financial position, results of operations, quantities of reserves that may be
economically produced, and access to capital.
23
<PAGE>
Due to our significant property and corporate acquisitions in 1999, our 1999
change of control and our current capitalization structure, comparisons of our
historical financial position and results of operations from 1998 to 1999 are
not meaningful. You should read the following discussion and analysis together
with our audited consolidated financial statements and the related notes for the
fiscal years ended December 31, 1999 and 1998.
1999 Compared With 1998
- -----------------------
REVENUE. Total revenue for the year ended December 31, 1999, was $22.0
million, an increase of $4.3 million (24%) over total revenue for 1998. Natural
gas revenues for the 1999 period were $10.3 million, approximately 34% higher
than 1998 natural gas revenues of $7.7 million. Natural gas production volumes
increased 23% in 1999; oil production volumes decreased by approximately 9%,
principally as a result of property sales during the period. Oil revenues for
the 1999 period were $8.9 million, approximately 33% higher than 1998 oil
revenues of $6.7 million. Gas plant and other product sales revenue of $648,000
increased 2% from $632,000 in 1998. Average natural gas sale prices increased
9% from the 1998 to the 1999 period, while oil prices increased 46% during the
same period. For 1999, approximately 52% of the dollar amount of our product
sales were natural gas. In addition, production from the Floyd Oil Properties
from the date of acquisition (November 23, 1999) to year-end contributed
approximately $4.5 million (approximately 20%) to our total revenues in the 1999
period.
GAIN ON PROPERTY SALES, INTEREST AND OTHER INCOME. In 1999 and 1998, our
property divestment resulted in gains of $1.0 million and $1.9 million,
respectively. Other income for 1999 of $1.0 million, consisted principally of
interest income and a lawsuit settlement
EXPENSES. Total expenses for the year ended December 31, 1999 were $26.9
million, a slight decrease over the $27.1 million in 1998. Comparability of
total expenses was affected by certain non-recurring expenses in 1999 of $1.7
million and additional expenses of $2.3 million attributable to the properties
acquired in the Floyd Oil Acquisition. Lease operating expense of $6.7 million
or approximately $0.85 per Mcfe, decreased by approximately $1.1 million from
the 1998 period, reflecting the effect of property sales. Depreciation and
depletion expense was $6.7 million, or approximately $0.84 per Mcfe, compared to
$7.1 million or approximately $0.97 per Mcfe for 1998. An increase in depletion
due to the properties acquired in the Floyd Oil Company Acquisition was offset
by lower depletion due to impairments, property sales and lower production on
properties owned the entire period of 1999. Impairment expense for 1999, was
approximately $2.5 million, relating to impairments on fee mineral acreage, non-
producing leasehold and proved oil and gas properties. More specifically,
1999 impairments were related to certain fee mineral acreage that reverted to
the landowners, management's decision not to participate in additional
exploration on certain prospects and new reserve engineers employed by us
resulted in valuation changes on certain proved properties. The impairment
expense in 1998 was principally attributable to decreasing oil prices. General
and administrative expense was $4.7 million, or approximately $0.60 per Mcfe,
compared to $4.3 million or approximately $0.58 per Mcfe for 1998. The general
and administrative expense increase was primarily the result of increases in
salary, legal and consulting expenses in 1999 offset partially by declines in
certain expenses due to the closing of the Enex offices in Kingwood, Texas.
Interest expense of $3.2 million, increased $1.23 million (62%) in the 1999
period, the increase reflecting increased borrowings under our credit facility
for acquisitions.
The non-recurring expense of $1.7 million was triggered by the change of
control resulting from the sale of securities to W/E LLC and consists of stock
compensation expense of $730,000, severance payment of $624,000, compensation
plan payment of $292,000 and other expenses of $60,000.
NET LOSS. The net loss for 1999 was approximately $3.4 million compared to a
loss of approximately $6.6 million in 1998. The current period net loss
decreased primarily as a result of the increased income from oil and natural gas
and the lower depletion and impairment expenses.
DIVIDENDS TO PREFERRED STOCKHOLDERS. Dividends to preferred stockholders of
approximately $574,000 in 1999 increased 745% over 1998. The increase was due
to the dividends on the Series C Preferred Stock that began to accrue dividends
on December 31, 1998 and the conversion of the Series A Preferred Stock to
common on January 31, 1998.
1998 COMPARED WITH 1997
For the year ended December 31, 1998, the revenues and expenses attributable
to the acquisition of Enex Corp. and Enex LP are included for the period April
through December, and those attributable to the Service Drilling acquisition are
included for the months of May through December. For the comparable 1997 period,
the revenues and expenses attributable to the acquisition of Bison Energy
Corporation ("Bison") are included for the period March through December, the
acquisition of Shore Oil Company ("Shore") for the period July through December,
and the acquisition of properties in the Riceville Field in Vermillion Parish,
Louisiana ("Riceville"), for the period August through December.
24
<PAGE>
REVENUES. Total revenues for the year ended December 31, 1998, of
$17,702,000, were $6,270,000 higher than the comparable 1997 period. The
increase in total revenues was primarily the result of higher oil and gas
revenues of $4,798,000 and higher gain on the sale of properties. During the
year ended December 31, 1998, lease bonus and rental income on the mineral
acreage acquired in the acquisition of Shore decreased $758,000 and other
revenues increased $283,000 as compared to the 1997 period.
Oil and gas revenues of $15,011,000 for the year ended December 31, 1998,
increased $4,798,000, consisting of a $1,574,000 increase in oil revenues, a
$3,071,000 increase in gas revenues and a $153,000 increase in other revenues.
The increase in oil and gas revenues was the result of a 105% increase in oil
production and a 99% increase in gas production as compared to the comparable
1997 period. The production increases were primarily the result of the
acquisition of Riceville which closed in 1997, and the acquisitions of Enex
Corp. and Service Drilling, which both closed in 1998.
The gain on the sale of properties of $1,953,000 for the year ended December
31, 1998, was primarily the result of sales of non-strategic properties and was
$1,946,000 higher than the comparable 1997 period.
Other income decreased $474,000. We received $217,000 in lease bonus and
delay rental income on the fee mineral acreage acquired in the acquisition of
Shore in the year ended December 31, 1998, versus $975,000 in the comparable
1997 period. A decrease in leasing activity was the primary reason for the
decline in income. This decrease was offset by other income in the year ended
December 31, 1998, which increased over the comparable 1997 periods primarily as
the result of a lawsuit settlement and an accounts payable settlement.
COSTS AND EXPENSES. Total expenses for the year ended December 31, 1998, of
$27,106,000 were $7,351,000 lower than the comparable 1997 period primarily as
the result of a decrease of $16,984,000 in impairment charge to $4,164,000
versus $21,148,000 in the comparable 1997 period. The lower impairment charge
was partially offset by a $3,953,000 increase in lease operating expenses, a
$2,549,000 increase in depreciation, depletion and amortization, and a
$1,906,000 increase in general and administrative expenses.
Lease operating expenses of $7,801,000 increased by $3,952,000. The increase
was primarily the result of expenses associated with the properties acquired in
the Enex Corp. and Service Drilling acquisitions.
G&G expenses increased $655,000. The primary G&G expenses in the current
period include approximately $716,000 on the Hawkins Ranch Prospect and $135,000
on the Sherburne Prospect.
Dry hole expense of $503,000 decreased by $616,000 for the year ended
December 31, 1998 as a result of a decrease in drilling activity. The dry hole
costs in the year ended December 31, 1998, were primarily the result of
abandonment costs on two unsuccessful wells.
Depreciation, depletion and amortization expense of $7,116,000 increased by
$2,549,000 for the year ended December 31, 1998. Depreciation, depletion and
amortization expense increased primarily as a result of the depletion associated
with the properties acquired in the Enex Corp. and Service Drilling
acquisitions.
The impairment expense for the year ended December 31, 1998, of $4,164,000
was primarily attributable to oil and gas property impairments of $4,092,000 due
to a decline in oil prices and an unsuccessful recompletion.
Interest expense of $1,972,000 for the year ended December 31, 1998,
increased by $1,301,000 as a result of a higher loan balance resulting from
funds borrowed to finance the Enex Corp. acquisition in March and to partially
finance the Service Drilling acquisition in April.
Stock compensation of $266,000 increased by $64,000 for the year ended
December 31, 1998, as the result of the grant of a warrant to purchase 25,000
shares of our common stock to a consultant. The warrant fully vested on
January 1, 1999, and was expensed in the current period.
25
<PAGE>
General and administrative expenses of $4,267,000 increased by $1,906,000,
primarily as a result of higher salary expense of $752,000, higher professional
fees of $310,000 and higher office expenses of $195,000. The increase in salary
expense was the result of increases in salaries of existing employees and
salaries of new employees. The increase in professional fees was the result of
higher accounting and engineering expenses related to a change in auditors and
increased reserve report requirements.
Other expenses of $139,000 for the year ended December 31, 1998, decreased
$179,000 over the comparable 1997 period. The decrease primarily reflects a
reduction in 1998 in the level of integration expense associated with the Bison
and Shore mergers which closed in 1997.
OPERATING LOSS AND NET LOSS. We reported an operating loss before minority
interest of $9,404,000 for the year ended December 31, 1998, compared to an
operating loss of $23,025,000 in the comparable 1997 period. The operating loss
decreased primarily due to lower dry hole and impairment expenses.
As a result of the acquisition of Enex Corp., we recorded a minority
interest on our income statement to remove the net income or loss attributable
to the minority interest owners of Enex Corp. For the year ended December 31,
1998, the minority interest increased the operating loss by $15,000. We did not
have a minority interest in the comparable period.
We reported an income tax benefit of $2,830,000 for the year ended December
31, 1998, as compared to an income tax benefit of $7,445,000 in the comparable
1997 period.
We reported a net loss of $6,589,000 for year ended December 31, 1998, as
compared to a net loss of $15,580,000 for the comparable 1997 period. We paid
preferred dividends of $68,000 for the year ended December 31, 1998, and
$605,000 in the comparable 1997 period and reported a net loss to common
stockholders of $6,657,000 for the year ended December 31, 1998, as compared to
a net loss to common stockholders of $16,185,000 in the comparable 1997 period.
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ITEM 7. FINANCIAL STATEMENTS
The Consolidated Financial Statements that constitute this item follow the
text of this report. An index to the Consolidated Financial Statements and
Schedules appears in Item 13 of this report.
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
In April 1998, as part of our annual consideration and selection of
independent accountants, we decided not to engage Schultz, Watkins & Company,
who had served as our independent certified public accountants since 1993, and
retained KPMG LLP to serve as our independent certified public accountants.
Management had no disagreement with Schultz, Watkins & Company on any
material matter of accounting principles or practices, financial statement
disclosure or auditing scope or procedure. Schultz, Watkins & Company's report
on our financial statements for 1997 did not contain an adverse opinion or a
disclaimer of opinion and was not qualified or modified as to uncertainty,
audit scope or accounting principles.
PART III
ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item is incorporated by reference from the
Company's Proxy Statement for the 2000 Annual Meeting of Stockholders.
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<PAGE>
ITEM 10. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from the
Company's Proxy Statement for the 2000 Annual Meeting of Stockholders.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated by reference from the
Company's Proxy Statement for the 2000 Annual Meeting of Stockholders.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference from the
Company's Proxy Statement for the 2000 Annual Meeting of Stockholders.
ITEM 13. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements:
See Index to Consolidated Financial Statements on page F-1
2. Financial Statement Schedules
See Index to Consolidated Financial Statements on page F-1
3. Exhibits: The following documents are filed as exhibits to this
report:
2.1 Agreement and Plan of Merger, dated November 24, 1999, by and between 3TEC
Energy Corporation, a Delaware corporation and Middle Bay Oil Company, Inc., an
Alabama corporation (Incorporated by reference to Exhibit A to the definitive
Proxy Statement of Middle Bay Oil Company, Inc., filed October 25, 1999
(Commission File No. 0-21702) (Incorporated by reference to Exhibits to Form 8-K
filed December 6, 1999.)
2.2 Form of Purchase Agreement between and among Middle Bay Oil Company, Inc.
and private sellers of the properties managed by Floyd Oil Company (Incorporated
by reference to Exhibits to Form 8-K filed December 7, 1999.)
2.3 Real Estate Exchange Agreement by and between Middle Bay Oil Company, Inc.
and Floyd Oil Company (Incorporated by reference to Exhibits to Form 8-K/A filed
December 17, 1999.)
2.4 Certificate of Merger of Middle Bay Oil Company, Inc. into 3TEC Energy
Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.)
3.1 Certificate of Incorporation of 3TEC Energy Corporation (Incorporated by
reference to Exhibits to Form 8-K/A filed December 6, 1999.)
3.2 Bylaws of the Company (Incorporated by reference to Exhibit C of the
Company's definitive proxy statement filed October 25, 1999.)
3.3 Certificate of Amendment to the Certificate of Incorporation of 3TEC Energy
Corporation. *
4.1 Certificate of Designation of Series B Preferred Stock of 3TEC Energy
Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.)
4.2 Certificate of Designation of Series C Preferred Stock of 3TEC Energy
Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.)
28
<PAGE>
4.3 Certificate of Designation of Series D Preferred Stock of 3TEC Energy
Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.)
10.1 Securities Purchase Agreement, dated July 1, 1999 by and between the
Company and 3TEC Energy Corporation (Incorporated by reference to Exhibits to
definitive Proxy Statement filed July 19, 1999.)
10.2 Securities Purchase Agreement, dated August 27, 1999 by and between the
Company and Shoemaker Family Partners, LP (Incorporated by reference to Exhibits
to Form 10-QSB filed November 15, 1999.)
10.3 Securities Purchase Agreement, dated August 27, 1999 by and between the
Company and Shoeinvest II, LP (Incorporated by reference to Exhibits to Form 10-
QSB filed November 15, 1999.)
10.4 Securities Purchase Agreement, dated October 19, 1999 between The
Prudential Insurance Company of America and the Company (Incorporated by
reference to Exhibits to Form 8-K filed November 2, 1999.)
10.5 Shareholders Agreement, dated August 27, 1999 by and among the Company,
3TEC Energy Corporation and the Major Shareholders (Incorporated by reference to
Exhibits to Form 10-QSB filed November 15, 1999.)
10.6 Registration Rights Agreement, dated August 27, 1999 by and among the
Company, 3TEC Energy Corporation, the Major Shareholders, Shoemaker Family
Partners, LP and Shoeinvest II, LP (Incorporated by reference to Exhibits to
Form 10-QSB filed November 15, 1999.)
10.7 Amendment to Registration Rights Agreement, dated October 19, 1999 by and
among the Company, W/E Energy Company, L.L.C. f/k/a 3TEC Energy Company L.L.C.,
f/k/a 3TEC Energy Corporation, Shoemaker Family Partners, LP, Shoeinvest II, LP,
and The Prudential Insurance Company of America (Incorporated by reference to
Exhibits to Form 8-K filed November 2, 1999.)
10.8 Participation Rights Agreement, dated October 19, 1999 by and among the
Company, The Prudential Insurance Company of America and W/E Energy Company
L.L.C. (Incorporated by reference to Exhibits to Form 8-K filed November 2,
1999.)
10.9 Employment Agreement, dated August 27, 1999 by and between Floyd C. Wilson
and the Company (Incorporated by reference to Exhibits to Form 10-QSB filed
November 15, 1999.)
10.10 Employment Agreement, dated August 27, 1999 by and between John J. Bassett
and the Company (Incorporated by reference to Exhibits to Form 10-QSB filed
November 15, 1999.)
10.11 Credit Agreement, dated March 27, 1998 by and among the Company, Compass
Bank, and Bank of Oklahoma, National Association (Incorporated by reference to
Exhibits to Form 10-QSB filed November 15, 1999.)
10.12 First Amendment to Credit Agreement, dated August 27, 1999 by and among
the Company, Compass Bank, and Bank of Oklahoma, National Association
(Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.)
10.13 Second Amendment to Credit Agreement, dated October 19, 1999 by and among
the Company, Compass Bank, and Bank of Oklahoma, National Association
(Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.)
10.14 Subordination Agreement, dated August 27, 1999 by and between 3TEC Energy
Corporation, Compass Bank, and Bank of Oklahoma, National Association
(Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.)
10.15 Subordination Agreement, dated August 27, 1999 by and among Shoemaker
Family Partners, LP, Compass Bank, and Bank of Oklahoma, National Association
(Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.)
29
<PAGE>
10.16 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest II,
LP, Compass Bank, and Bank of Oklahoma, National Association (Incorporated by
reference to Exhibits to Form 10-QSB filed November 15, 1999.)
10.17 Letter Amendment No. 1 to Middle Bay Oil Company, Inc. Securities
Purchase Agreement dated November 23, 1999, by and between Middle Bay Oil
Company, Inc. (n/k/a 3TEC Energy Corporation) and The Prudential Insurance
Company of America (replacing the unexecuted Exhibit 10.17 of Form 10-QSB filed
November 15, 1999).
10.18 Restated Credit Agreement by and among Middle Bay Oil Company, Inc., Enex
Resources Corporation and Middle Bay Production Company, Inc. as borrowers, and
Bank One, Texas, N.A. and other institutions as lenders. (Incorporated by
reference to Exhibits to Form 8-K filed December 17, 1999.)
27.1 Financial Data Schedule *
* Filed herewith
(b) The following reports were filed on Form 8-K during the fourth quarter of
1999:
On October 22, 1999, the Company filed a Form 8-K under Item 5 describing
a letter of intent to purchase oil and gas properties and interests, managed by
Floyd Oil Company, from a group of private sellers.
On November 2, 1999, the Company filed a Form 8-K under Item 5 describing
the sale of securities to The Prudential Insurance Company of America.
On December 6, 1999, the Company filed a Form 8-K under Items 5 and 7
describing the agreement and plan of merger between Middle Bay Oil Company, Inc.
and 3TEC Energy Corporation.
On December 7, 1999, the Company filed a Form 8-K under Items 2, 5 and 7
describing the acquisition of assets, managed by Floyd Oil Company, from a group
of private sellers and the closing of a new credit facility with Bank One,
Texas, N.A.
On December 16, 1999, the Company filed an amendment under Item 7 to the
Form 8-K originally filed on December 6, 1999 describing the designation of the
Series B and Series C Preferred Stocks and the Certificate of Merger between
Middle Bay Oil Company, Inc. and 3TEC Energy Corporation.
On December 17, 1999, the Company filed an amendment under Item 7 to the
Form 8-K originally filed on December 7, 1999 describing the real estate
exchange agreement between Middle Bay Oil Company, Inc. and Floyd Oil Company
and the restated credit agreement by and among Middle Bay Oil Company, Inc.,
Enex Resources Corporation, Middle Bay Production Company and Bank One, Texas,
N.A. and other institutions.
30
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Auditors........................................... F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998............. F-3
Consolidated Statements of Operations for the years ended December 31,
1999 and 1998........................................................... F-4
Consolidated Statements of Cash Flows for the years ended December 31,
1999 and 1998........................................................... F-5
Consolidated Statements of Changes in Stockholders' Equity for the years
ended December 31, 1999 and 1998........................................ F-6
Notes to Consolidated Financial Statements............................... F-7
</TABLE>
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
3TEC Energy Corporation:
We have audited the accompanying consolidated balance sheets of 3TEC Energy
Corporation (formerly Middle Bay Oil Company, Inc.) and subsidiaries as of
December 31, 1999 and December 31, 1998 and the related consolidated
statements of operations, changes in stockholders' equity, and cash flows for
each of the years then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of 3TEC
Energy Corporation and subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the years then
ended in conformity with generally accepted accounting principles.
KPMG LLP
Houston, Texas
February 25, 2000
F-2
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31, December 31,
1999 1998
------------ ------------
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents........................ $ 6,141,153 $ 1,040,096
Accounts receivable.............................. 9,453,551 3,309,043
Accounts receivable-Insurance Claim.............. -- 448,083
Other current assets............................. 176,226 141,364
------------ -----------
Total current assets............................ 15,770,930 4,938,586
PROPERTY (AT COST)
Oil and gas-successful efforts method............ 168,840,499 90,849,439
Other............................................ 1,141,879 795,323
------------ -----------
169,982,378 91,644,762
Accumulated depreciation, depletion and
amortization...................................... (38,208,298) (39,073,584)
------------ -----------
131,774,080 52,571,178
OTHER ASSETS....................................... 1,698,496 431,053
------------ -----------
TOTAL ASSETS....................................... $149,243,506 $57,940,817
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable-trade........................... $ 5,726,569 $ 3,643,241
Accounts payable-Enex LP Dissenters and
Fractional Shares............................... -- 538,750
Revenue payable.................................. 1,576,731 342,931
Accounts payable-Stockholder Dissenters.......... 1,118,678 --
Other current liabilities........................ 347,733 275,010
------------ -----------
Total current liabilities....................... 8,769,711 4,799,932
LONG-TERM DEBT..................................... 87,500,000 27,454,567
SENIOR SUBORDINATED CONVERTIBLE NOTES.............. 13,223,844 --
DEFERRED INCOME TAXES.............................. 290,643 1,733,167
OTHER LIABILITIES.................................. 257,627 437,949
MINORITY INTEREST.................................. 1,089,044 957,369
STOCKHOLDERS' EQUITY
Preferred stock, $0.02 par, 20,000,000 shares
authorized, 266,667 designated Series B and
2,300,000 shares designated Series C, none other
designated...................................... -- --
Convertible preferred stock Series B, $7.50
stated value, 266,667 shares issued and
outstanding. $2,000,000 aggregate liquidation
preference...................................... 3,627,000 3,627,000
Convertible preferred stock Series C, $5.00
stated value, 1,139,506 and 1,142,663 shares
issued and outstanding at December 31, 1999 and
December 31, 1998, respectively. $5,697,530
aggregate liquidation preference................ 5,198,440 5,281,937
Common stock, $.02 par value, 60,000,000 shares
authorized, 5,338,771 and 2,850,655 shares
issued at December 31, 1999 and December 31,
1998, respectively.............................. 106,778 57,016
Additional paid-in capital....................... 57,775,199 37,061,627
Accumulated deficit.............................. (27,408,062) (23,401,707)
Treasury stock; 7,258 shares..................... (1,186,718) (68,040)
------------ -----------
TOTAL STOCKHOLDERS' EQUITY...................... 38,112,637 22,557,833
COMMITMENTS AND CONTINGENCIES
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY......... $149,243,506 $57,940,817
============ ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-3
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1999 1998
----------- -----------
<S> <C> <C>
REVENUE
Oil and gas sales and plant income................ $19,951,750 $15,011,354
Gain on sale of properties........................ 1,047,860 1,953,362
Delay rental and lease bonus income............... 64,911 217,404
Other............................................. 955,545 520,458
----------- -----------
TOTAL REVENUE................................... 22,020,066 17,702,578
----------- -----------
COSTS AND EXPENSES
Lease operating, production taxes and plant
costs............................................ 6,727,948 7,801,249
Geological and geophysical........................ 199,499 877,643
Dry hole costs.................................... 624,780 503,444
Depreciation, depletion and amortization.......... 6,690,961 7,116,116
Impairments....................................... 2,477,980 4,164,184
Interest.......................................... 3,204,768 1,971,595
Stock compensation................................ 729,938 266,445
Severance payment................................. 624,420 --
Compensation plan payment......................... 292,527 --
General and administrative........................ 4,735,723 4,266,727
Other............................................. 583,998 138,855
----------- -----------
TOTAL COSTS AND EXPENSES........................ 26,892,542 27,106,258
LOSS BEFORE INCOME TAX BENEFIT, MINORITY INTEREST
AND DIVIDENDS TO PREFERRED STOCKHOLDERS............ (4,872,476) (9,403,680)
Minority Interest................................... 2,323 15,089
Income tax benefit.................................. (1,442,524) (2,829,762)
----------- -----------
NET LOSS............................................ (3,432,275) (6,589,007)
Dividends to preferred stockholders................. 574,080 67,945
----------- -----------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS........ $(4,006,355) $(6,656,952)
=========== ===========
NET LOSS PER COMMON SHARE, basic and diluted........ $ (1.14) $ (2.48)
=========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING, basic
and diluted........................................ 3,519,532 2,683,369
=========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Years Ended December 31,
--------------------------
1999 1998
------------ ------------
<S> <C> <C>
OPERATING ACTIVITIES
Net loss........................................... $ (3,432,275) $ (6,589,007)
Adjustments to reconcile net loss to net cash
provided by operating activities
Depreciation, depletion and amortization.......... 6,690,961 7,116,116
Impairments....................................... 2,477,980 4,164,184
Dry hole costs.................................... 624,780 503,444
Stock compensation expense........................ 729,938 266,445
Gain on sale of properties........................ (1,047,860) (1,953,362)
Deferred income taxes............................. (1,442,524) (2,829,762)
Minority interest................................. 2,323 15,089
Other charges..................................... 377,885 20,000
------------ ------------
Cash flow from operations before changes in current
assets and liabilities............................ 4,981,208 713,147
Changes in current assets and liabilities net of
acquisition effects:
Increase in accounts receivable and other current
assets........................................... (5,852,041) (185,887)
Increase in accounts payable, revenue payable and
other current liabilities........................ 2,272,159 1,541,025
------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES....... 1,401,326 2,068,285
INVESTING ACTIVITIES
Payment for acquisition of 80% of Enex Corp., net
of cash acquired of $4,698,211................... -- (11,403,189)
Payment for acquisition of assets of Service
Drilling Co., LLC................................ -- (6,328,208)
Payment for acquisition of assets managed by Floyd
Oil Company...................................... (82,829,903) --
Proceeds from sales of oil and gas properties..... 6,230,420 4,812,326
Proceeds from sales of other assets............... 13,363 390,927
Additions to oil and gas assets................... (3,449,083) (4,100,252)
Additions to other assets......................... (509,773) (322,816)
Payments from (advances to) stockholder........... 173,115 (6,950)
------------ ------------
NET CASH USED IN INVESTING ACTIVITIES........... (80,371,861) (16,958,162)
FINANCING ACTIVITIES
Proceeds from issuance of debt.................... 91,036,000 32,469,604
Proceeds from issuance of senior subordinated
convertible notes................................ 13,223,844 --
Proceeds from issuance of common stock............ 12,465,591 --
Principal payments on debt........................ (30,990,568) (16,105,287)
Preferred stock dividends......................... (245,029) (67,945)
Partnership distributions......................... -- (1,348,098)
Debt, common stock and preferred stock issue and
registration costs............................... (1,418,246) (605,485)
------------ ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES....... 84,071,592 14,342,789
Net increase (decrease) in cash and cash
equivalents....................................... 5,101,057 (547,088)
Cash and cash equivalents-Beginning................ 1,040,096 1,587,184
------------ ------------
Cash and cash equivalents-Ending................... $ 6,141,153 $ 1,040,096
============ ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest.......................................... $ 3,269,354 $ 1,657,362
============ ============
Income taxes...................................... -- --
============ ============
Non-cash investing and financing activities:
Preferred dividends incurred but not paid......... $ 329,051 --
============ ============
Common stock issued for acquisition of oil and gas
properties from W/E LLC.......................... $ 875,000 --
============ ============
Common stock repurchase contingency accrual....... $ 1,118,678 --
============ ============
Common stock issued in asset acquisition from
Floyd Oil Company................................ $ 6,992,587 --
============ ============
Common stock issued as finders fee in Enex
Resources Corp. tender offer..................... -- $ 245,232
============ ============
Common stock issued in asset acquisition from
Service Drilling Corp., LLC...................... -- $ 3,554,774
============ ============
Present value of consulting agreement of former
president of Enex Resources Corp................. -- $ 788,563
============ ============
Preferred stock issued in acquisition of Enex
Consolidated Partners, LP........................ -- $ 5,713,317
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1999 AND 1998
<TABLE>
<CAPTION>
Preferred Stock
-----------------------------------------------------------------
Series A Series B Series C Common Stock Unearned
----------------------- ------------------ --------------------- ------------------- Paid-in Stock
Shares Par Shares Par Shares Par Shares Par Capital Compensation
---------- ----------- ------- ---------- --------- ---------- --------- -------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance January
1, 1998......... 1,666,667 10,000,000 266,667 3,627,000 -- -- 1,506,269 30,128 23,089,563 (67,500)
Preferred Series
A conversion.... (1,666,667) (10,000,000) 1,111,111 22,222 9,977,778
Common shares
issued as
finders fee in
Enex Corp.
tender offer.... 11,275 226 245,006
Asset
acquisition of
Service Drilling
Co., LLC........ 222,000 4,440 3,550,334
Restricted stock
awards earned... 67,500
Warrant issued
as compensation. 198,946
Preferred Series
C issued in Enex
Consolidated
Partners, LP
acquisition..... 1,142,663 5,713,317
Preferred Series
C registration
costs........... -- (431,380)
Net Loss........
Preferred stock
dividends.......
---------- ----------- ------- ---------- --------- ---------- --------- -------- ----------- -------
Balance January
1, 1999......... -- -- 266,667 3,627,000 1,142,663 5,281,937 2,850,655 57,016 37,061,627 --
Preferred Series
C registration
costs........... (67,711)
Common stock and
warrants issued
to 3TEC Energy
Company, LLC.... 1,585,185 31,703 10,668,297
Common stock and
warrants issued
to related
party........... 22,222 444 149,556
Common stock and
warrants issued
to The
Prudential
Insurance Co. of
America......... 351,680 7,034 2,366,810
Common stock
issued in asset
acquisition from
Floyd Oil
Company......... 503,426 10,069 6,982,518
Stockholder
dissenters
repurchase
contingency.....
Common stock
registration
costs........... (365,571)
Preferred Series
C conversions... (13,157) (65,786) 4,103 82 65,704
Preferred Series
C issued as
consulting fee.. 10,000 50,000
Employee stock
option plan
expense......... 729,938
Employee stock
option
exercises....... 21,500 430 116,320
Net Loss........
Preferred stock
dividends.......
---------- ----------- ------- ---------- --------- ---------- --------- -------- ----------- -------
Balance December 31,
1999............ -- $ -- 266,667 $3,627,000 1,139,506 $5,198,440 5,338,771 $106,778 $57,775,199 $ --
========== =========== ======= ========== ========= ========== ========= ======== =========== =======
<CAPTION>
Accumulated Treasury Stockholders'
Deficit Stock Equity
------------- ------------ -------------
<S> <C> <C> <C>
Balance January 1,
1998............ (16,744,755) (68,040) 19,866,396
Preferred Series
A conversion.... --
Common shares
issued as
finders fee in
Enex Corp.
tender offer.... 245,232
Asset
acquisition of
Service Drilling
Co., LLC........ 3,554,774
Restricted stock
awards earned... 67,500
Warrant issued
as
compensation.... 198,946
Preferred Series
C issued in Enex
Consolidated
Partners, LP
acquisition..... 5,713,317
Preferred Series
C registration
costs........... (431,380)
Net Loss........ (6,589,007) (6,589,007)
Preferred stock
dividends....... (67,945) (67,945)
------------- ------------ -------------
Balance January 1,
1999............ (23,401,707) (68,040) 22,557,833
Preferred Series
C registration
costs........... (67,711)
Common stock and
warrants issued
to W/E Energy
Company, LLC.... 10,700,000
Common stock and
warrants issued
to related
party........... 150,000
Common stock and
warrants issued
to The
Prudential
Insurance Co. of
America......... 2,373,844
Common stock
issued in asset
acquisition from
Floyd Oil
Company......... 6,992,587
Stockholder
dissenters
repurchase
contingency..... (1,118,678) (1,118,678)
Common stock
registration
costs........... (365,571)
Preferred Series
C conversions... --
Preferred Series
C issued as
consulting fee.. 50,000
Employee stock
option plan
expense......... 729,938
Employee stock
option
exercises....... 116,750
Net Loss........ (3,432,275) (3,432,275)
Preferred stock
dividends....... (574,080) (574,080)
------------- ------------ -------------
Balance December
31, 1999........ $(27,408,052) $(1,186,718) $38,112,637
============= ============ =============
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999 and 1998
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
3TEC Energy Corporation (the Company), formerly Middle Bay Oil Company,
Inc., was incorporated under the laws of the state of Alabama on November 20,
1992. The Company was reincorporated in Delaware on December 7, 1999 and
changed its name to 3TEC Energy Corporation. The reincorporation and name
change were part of a series of transactions related to a securities purchase
agreement that closed on August 27, 1999 between the Company and W/E Energy
Company, LLC ("W/E LLC"), formerly known as 3TEC Energy Company, LLC, whereby
the Company received $21.4 million in cash and oil and natural gas properties
for the sale of common stock, warrants and debt securities (See Note 3).
Effective March 27, 1998, the Company acquired 79.2% of Enex Resources
Corporation ("Enex") and over a three week period ending December 23, 1998,
the Company acquired an additional 0.80% of Enex for a total 80% of Enex.
Effective April 16, 1998, the Company acquired the oil and gas assets of
Service Drilling Co., LLC ("Service Drilling"). Effective October 1, 1998, the
Company acquired 100% of Enex Consolidated Partners, L.P. ("Enex Partnership"),
a limited partnership of which Enex owned greater than a 50% interest. Effective
November 23, 1999, the Company acquired oil and natural gas properties and
interests managed by Floyd Oil Company ("Floyd Oil Company ") from a group of
private sellers. The Company is engaged in the acquisition, development,
production and exploration of oil and natural gas in the contiguous United
States. The Company considers its business to be a single operating segment.
Significant Accounting Policies
The Company's accounting policies reflect industry standards and conform to
generally accepted accounting principles. The more significant of such
policies are described below.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company,
its wholly-owned subsidiaries and Enex, an 80% owned subsidiary. The equity of
the minority interests in Enex is shown in the consolidated financial
statements as "minority interest". All significant intercompany balances and
transactions have been eliminated in consolidation.
Cash and Cash Equivalents
For purposes of the statements of cash flows, the Company classifies all
cash investments with original maturities of three months or less as cash.
Oil and Gas Property
The Company follows the successful efforts method of accounting for oil and
natural gas properties, and accordingly, capitalizes all direct costs incurred
in connection with the acquisition, drilling and development of productive oil
and natural gas properties. Costs associated with unsuccessful exploration are
charged to expense currently. Geological and geophysical costs and costs of
carrying and retaining unevaluated properties are charged to expense.
Depreciation, depletion and amortization of capitalized costs are computed
separately for each field based on the unit-of-production method using only
proved oil and natural gas reserves. In arriving at such rates, commercially
recoverable reserves have been estimated by independent petroleum engineering
firms. The Company reviews its undeveloped properties continually and charges
them to expense on a property by
F-7
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
property basis when it is determined that they have been condemned by dry
holes, or have otherwise diminished in value. The Company recorded impairments
of $1.5 million on its undeveloped properties, principally fee minerals and
non-producing leasehold costs, for the year ended December 31, 1999. Gains and
losses are recorded on sales of interests in proved properties and on sales of
entire interests in unproved properties. For the years ended December 31, 1999
and 1998, the Company realized gains on sales of properties of $1.0 million
and $2.0 million, respectively.
Proved oil and natural gas reserves are the estimated quantities of oil,
natural gas and natural gas liquids which are expected to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation tests.
The Company reviews long-lived assets for impairment when events or changes
in circumstances indicate that the carrying value of such an asset may not be
recoverable. This review consists of a comparison of the carrying value of the
asset to the asset's expected future undiscounted cash flows. Estimates of
expected future cash flows represent management's best estimate based on
reasonable and supportable assumptions and projections. If the expected future
cash flows, assuming escalated prices, are less than the carrying value of the
asset, an impairment exists and is measured as the excess of the carrying
value over the estimated fair value of the asset. The Company estimates
discounted future net cash flows to determine fair value. Any impairment
provisions recognized are permanent and may not be restored in the future. For
the years ended December 31, 1999 and 1998, the Company's proved properties
were assessed for impairment on an individual field basis and the Company
recorded impairment provisions on certain producing properties of $1.0 million
and $4.1 million, respectively.
Site Restoration, Dismantlement and Abandonment Costs
Site restoration, dismantlement and abandonment costs (P&A costs) are common
in the oil and natural gas industry. P&A costs are costs associated with
removing the facilities and equipment required to operate a well and restoring
the well site to specified conditions. P&A costs are incurred when the oil and
natural gas reserves of a well or wells are depleted or when production drops
to the point that it is no longer economically feasible to produce.
The Company, in conjunction with its independent engineers and the operators
of the wells, continually reviews its working interests with respect to
potential P&A costs. Estimated P&A costs (net of estimated salvage value) are
amortized through depletion using the unit-of-production method.
As of December 31, 1999 and 1998, the Company's estimated P&A costs were
approximately $495,000.
Other Property and Equipment
Other property and equipment are stated at cost and depreciation is computed
on the straight line method over estimated lives ranging from five to seven
years. Additions and betterments which provide benefits to several periods are
capitalized.
Environmental Liabilities
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an
existing condition caused by past operations, and do not contribute to current
or future revenue generation, are expensed. Liabilities are recorded when
environmental assessments
F-8
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
and/or clean-ups are probable, and the costs can be reasonably estimated.
Generally, the timing of these accruals coincides with the Company's
commitment to a formal plan of action.
As of December 31, 1999, the Company had accrued estimated environmental
costs of approximately $250,000.
Revenue
Oil and natural gas revenues are recorded using the sales method, whereby
the Company recognizes revenues based on the amount of oil and natural gas
sold to purchasers on its behalf. At December 31, 1999 and 1998, the Company's
net imbalance position was immaterial.
Hedging
The Company periodically enters into derivative contracts to hedge the risk
of future oil and natural gas price fluctuations. Such contracts may either
fix or support oil and natural gas prices or limit the impact of price
fluctuations with respect to the Company's sales of oil and natural gas.
The Company uses the hedge or deferral method of accounting for derivative
contracts and, as a result, gains and losses on commodity derivative financial
instruments are generally offset by similar changes in realized prices of
commodities. In order to qualify as hedges, price movements in the underlying
commodity derivative must be highly correlated with the hedged commodity.
Gains and losses on such hedging activities are recognized in oil and natural
gas production revenues when hedged production is sold. If a derivative ceases
to qualify as a hedge, changes in fair value of the derivative instrument are
recognized in earnings currently.
Income Taxes
The Company uses the asset and liability method of accounting for income
taxes under which deferred tax assets and liabilities are determined by
applying enacted statutory tax rates applicable to future years to the
difference between the financial statement and tax basis of assets and
liabilities. The effect on deferred tax assets and liabilities of a change in
tax rates is recognized as part of the provision for income taxes in the
period that includes the enactment date.
Stock Based Compensation
The Company accounts for stock-based compensation under the intrinsic value
method. Under this method, the Company records no compensation expense for
stock options granted when the exercise price of options granted is equal to
or greater than the fair market value of the Company's common stock on the
date of grant.
Earnings Per Share
Basic earnings and loss per common share are based on the weighted average
shares outstanding without any dilutive effects considered. Diluted earnings
and loss per share reflects dilution from all potential common shares,
including options, warrants and convertible preferred stock and notes. Diluted
loss per share does not include the effect of any potential common shares if
the effect would be to decrease the loss per share.
All share and per share amounts have been retroactively adjusted for a one-
for-three reverse split that was approved on January 14, 2000 (See Note 14).
F-9
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
Concentrations of Market Risk
The future results of the Company will be affected by the market prices of
oil and natural gas. The availability of a ready market for oil and natural
gas in the future will depend on numerous factors beyond the control of the
Company, including weather, production of other oil and natural gas, imports,
marketing of competitive fuels, proximity and capacity of oil and natural gas
pipelines and other transportation facilities, any oversupply or undersupply
of oil and natural gas, the regulatory environment, and other regional and
political events, none of which can be predicted with certainty.
Concentrations of Credit Risk
Financial instruments which subject the Company to concentrations of credit
risk consist primarily of cash and accounts receivable. The Company places its
cash investments with high credit qualified financial institutions. Risk with
respect to receivables is concentrated primarily in the current production
revenue receivable from multiple oil and natural gas producers, both major and
independent, and is typical in the industry. No single customer accounted for
greater than 10% of the Company's total oil and natural gas sales for the
years ended December 31, 1999 and 1998.
Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". SFAS No. 133 standardizes the accounting
for and disclosures of derivative instruments, including certain derivative
instruments embedded in other contracts. The statement is effective for
financial statements for periods beginning after June 15, 2000. The Company
has not yet determined the impact of the Statement on its financial condition
or results of operations.
Use of Estimates
Management of the Company has made a number of estimates and assumptions
relating to the reporting of assets and liabilities to prepare the financial
statements in conformity with generally accepted accounting principles. Actual
results could differ from those estimates.
Reclassifications
Certain reclassifications of prior period amounts have been made to conform
to the current presentation.
(2) ACQUISITIONS
On March 27, 1998, the Company acquired 1,064,432 common shares,
approximately 79.2%, of Enex for $15.9 million. The Company purchased the
common shares of Enex through a cash tender offer that commenced February 19,
1998 (the "Enex Acquisition"). The Company also incurred approximately $60,934
in legal, accounting and printing expenses and issued 11,275 shares of Company
common stock for finders fees to unrelated third parties. At the time, Enex
was general partner of the Enex Partnership, a New Jersey limited partnership
whose principal business is oil and natural gas exploration and production.
Enex's general partner interest in the Enex Partnership was 4.1%. Enex also
owned an approximate 56.2% limited partner interest in the Enex Partnership.
As part of the Enex Acquisition, the Company entered into a consulting
agreement, effective April 15, 1998, with the former president of Enex that
provides for monthly payments of $20,000 until expiration of the
F-10
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
agreement on May 18, 2002. The monthly payments serve as consideration for
consulting, a covenant not to compete and a preferential right to purchase
certain oil and natural gas acquisitions which the former president controls
or proposes to acquire during the term of the agreement. The Company will
reimburse the former president each month for reasonable and necessary
business expenses incurred in connection with the performance of consulting
services. The agreement survives the former president and his spouse and is
nonassignable. At December 31, 1999 and 1998, the present value of the
agreement, applying a 10% discount, was approximately $497,627 and $677,949,
respectively. The long-term portion of the agreement is classified as other
liabilities in the financial statements.
The cost of acquiring 79.2% of Enex was allocated using the purchase method
of accounting to the consolidated assets and liabilities of Enex based on
estimates of the fair values with the remaining purchase price allocated to
proved oil and natural gas properties.
The allocation of the purchase price is summarized as follows: (in
thousands)
<TABLE>
<S> <C>
Working capital.................................................. $ 5,640
Oil and natural gas properties (proved and unproved)............. 19,090
Minority interest................................................ (7,669)
-------
Total.......................................................... $17,061
=======
</TABLE>
Over a three-week period ending December 23, 1998, the Company acquired an
additional 0.80% (9,747 common shares) of Enex common stock for approximately
$68,000.
On April 16, 1998, the Company acquired substantially all of the oil and
natural gas assets of Service Drilling, in exchange for 222,000 shares of
Company common stock and $6.5 million in cash for a total acquisition cost of
$10.0 million, before post-closing adjustments (the "Service Acquisition").
The fair value of the securities issued in connection with the Service
Acquisition was calculated using the price of the Company's common stock at
the time the Service Acquisition was announced to the public and further
adjusted for tradability restrictions. An independent valuation firm
determined the tradability discount for the Company's common stock. The
effective date of the acquisition was March 1, 1998 and the cost was allocated
using the purchase method of accounting.
On December 30, 1998, the Company completed the acquisition of the Enex
Partnership (the "Enex Partnership Acquisition"). The transaction consisted of
an exchange offer whereby the Company offered to exchange 2.086 shares of
Series C Preferred stock ("Series C") for each Enex Partnership unit (the
"Exchange Offer"). In connection with the Exchange Offer, the Company
submitted a proposal to investors in the Enex Partnership to amend the
partnership agreement to provide for the transfer of all of the assets and
liabilities of the Enex Partnership to the Company as of October 1, 1998 and
dissolve the Enex Partnership. The Exchange Offer was approved on December 30,
1998 and the Company issued 2,177,481 Series C shares for 100% of the
outstanding limited partner units. At the close of the Exchange Offer, the
Enex Partnership had 1,102,631 units outstanding. Enex was issued 1,293,522
Series C shares for its 56.2% ownership of the Enex Partnership. The remaining
883,959 Series C shares were issued to the limited partners that elected to
take Series C shares in lieu of cash. In January 1999, certain dissenting
limited partners were paid $516,000 and other unitholders were paid $23,000 in
lieu of fractional shares. Because of the dissenting limited partners, Enex
owns 59.4% of the Series C shares, of which 20% (258,704 shares) are
considered outstanding and held by third parties in the consolidated financial
statements at December 31, 1999 and 1998.
F-11
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
The intent of the Exchange Offer was to acquire the 43.8% of the outstanding
limited partner units that the Company did not currently own. The tables below
present the consideration paid for 100% of the Enex Partnership and for the
43.8% of the Enex Partnership not owned by Enex.
The cost of acquiring 100% of the outstanding limited partner units was
approximately $11.9 million, consisting of the following (in thousands):
<TABLE>
<S> <C>
Estimated fair value of 2,177,481 shares of Company Series C
preferred stock.................................................. $10,887
Cash consideration................................................ 539
Legal, accounting and other expenses.............................. 431
-------
Total........................................................... $11,857
=======
</TABLE>
Since Enex is consolidated into the Company's financial statements, the
number of shares outstanding and the value of the shares outstanding
attributable to the 43.8% of the Enex Partnership not owned by Enex and the
minority interest owners of Enex (20%) is 1,142,663 and $5.7 million,
respectively. The cost of acquiring the outstanding limited partner units that
were not owned by Enex was approximately $6.7 million, consisting of the
following (in thousands):
<TABLE>
<S> <C>
Estimated fair value of 1,142,663 shares of Company Series C
preferred stock................................................... $5,713
Cash consideration................................................. 539
Legal, accounting and other expenses............................... 431
------
Total............................................................ $6,683
======
</TABLE>
The Company's purchase price was allocated to the assets and liabilities
attributable to the 43.8% of the Enex Partnership based on estimates of the
fair values with the remaining purchase price allocated to proved oil and
natural gas properties. The registration costs of approximately $431,000
reduced the value of the Series C shares issued. Because the Enex Partnership
was consolidated in the financial statements of the Company as of the
effective date of October 1, 1998, the preliminary purchase price allocation
below shows the effect of the acquisition on the consolidated financial
statements (in thousands):
<TABLE>
<S> <C>
Working capital..................................................... $ (539)
Oil and natural gas properties...................................... (23)
Minority interest................................................... 5,844
------
Series C Preferred Stock.......................................... $5,282
======
</TABLE>
On November 23, 1999, the Company completed the acquisition of oil and
natural gas properties and interests, managed by Floyd Oil Company, owned by a
group of private sellers (the "Floyd Oil Acquisition") for $86.8 million in
cash and 503,426 shares of Company common stock. Prior to the acquisition,
there was no relationship between Floyd C. Wilson, President of the Company
and Floyd Oil Company. The effective date of the acquisition was January 1,
1999 and the cost was allocated using the purchase method of accounting. The
total purchase price of $90.2 million, considering post-closing adjustments
and transaction costs, was allocated principally to oil and natural gas
properties.
F-12
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
The following pro forma data presents the results of the Company for the
years ended December 31, 1999 and 1998, as if the acquisitions of Enex,
Service, Enex Partnership and Floyd Oil had occurred on January 1, 1998. The
pro forma results 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 natural gas revenues, production costs,
depreciation and depletion related to the properties and businesses acquired,
preferred stock dividends on preferred stock issued, interest expense on debt
issued and the related income tax effects (in thousands, except per share
amounts):
<TABLE>
<CAPTION>
Pro Forma
---------------
1999 1998
------- -------
(Unaudited)
<S> <C> <C>
Total revenues............................................ $55,735 $55,299
Net income (loss) attributable to common stockholders..... 2,413 (4,725)
Net income (loss) per share attributable to common
stockholders
Basic................................................... 0.45 (0.89)
Diluted................................................. 0.41 (0.89)
</TABLE>
(3) COMMON STOCK, WARRANT AND SENIOR SUBORDINATED CONVERTIBLE NOTE SALE TO
W/E ENERGY COMPANY, L.L.C. ("W/E LLC")
On August 27, 1999, the Company closed a Securities Purchase Agreement (the
"Agreement") for a total of $21.4 million with W/E Energy Company, LLC
("W/E LLC"). The Securities Purchase Agreement and contemplated transactions
were approved by the stockholders at the Company's annual meeting on August 10,
1999.
The controlling person of W/E LLC is EnCap Investments L.L.C., a Delaware
limited liability company ("EnCap Investments"). The sole member of EnCap
Investments is El Paso Field Services Company, a Delaware corporation
("El Paso Field Services"). The controlling person of El Paso Field Services is
El Paso Energy Corporation, a Delaware corporation. The Company received $9.8
million in cash and properties valued at $875,000 for 1,585,185 shares of common
stock and 1,200,000 warrants (the "Warrants") and $10.7 million for a 5-year
senior subordinated convertible note with a face value of $10.7 million (See
Note 7).
At closing, W/E LLC became the Company's largest shareholder with current
ownership of approximately 30% of the current outstanding shares of common
stock.
(4) RELATED PARTY TRANSACTIONS
The Company had a note receivable from Bay City Energy Group, Inc., a
shareholder of the Company, as of December 31, 1998 in the amount of $173,115.
In conjunction with the sale of securities to W/E LLC (See Note 3) in August,
1999, the note and all accrued interest was paid in full. The principal
balance of the note accrued interest at 5% annually and was due January 1,
2001. The note was secured by 25,000 shares of Company common stock. Interest
of $34,110 was accrued on the note as of December 31, 1998.
The Company rents office space from C.J. Lett III, a shareholder and former
officer and director of the Company. The rent is $3,000 per month for three
years through February, 2000. Mr. Lett has common stock ownership in two oil
service companies that provide services to the Company. The Company paid
approximately $117,000 and $203,000 to these companies for the years ended
December 31, 1999 and 1998, respectively.
F-13
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
David B. Miller and D. Martin Phillips, directors of the Company, are
managing directors of EnCap Investments, which is the controlling person of
W/E LLC which owns approximately 30% of the common stock of the Company,
excluding shares attributable to the warrants and convertible notes, as of
December 31, 1999. Gary R. Christopher, a shareholder and director of the
Company, is employed by Kaiser-Francis Oil Co., which owns approximately 21%
of the common stock of the Company as of December 31, 1999.
(5) ACCOUNTS RECEIVABLE-INSURANCE CLAIM
The Company owns a 100% working interest in the Louis Mayard #1 well (the
"Well") located in the Esther Field in Vermillion Parish, Louisiana. Due to a
failed recompletion attempt and the inability of the Company to shut in the
Well using normal operating methods, the Company incurred approximately $1.9
million during 1998 to gain control of the Well using special crews. On
November 4, 1998, the insurance company made a partial payment to the Company
under its well control insurance policy of approximately $1.4 million. In
April, 1999 the Company was paid $383,000 in final settlement of all claims
related to the Well. The Company had recorded the estimated remaining amount
due from the insurance company in current assets as Accounts Receivable-
Insurance Claim at December 31, 1998.
(6) LONG-TERM DEBT
Long-term debt at December 31, 1999 and 1998, consisted of the following
(in thousands):
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
$250 million Credit Facility............................. $87,500 $ --
$100 million Revolver.................................... -- 27,455
------- -------
Total.................................................... 87,500 27,455
Less current maturities.................................. -- --
------- -------
Long term debt excluding current maturities............ $87,500 $27,455
======= =======
</TABLE>
Concurrent with the Floyd Oil Acquisition, the Company entered into a $250
million credit facility (the "Facility") with Bank One, Texas, NA as agent and
four other banks. The Company's borrowing base has been initially set at $95
million with $87.5 million outstanding at December 31, 1999. The borrowing
base will be redetermined semi-annually on May 1 and November 1. Interest
under the Facility accrues at a rate calculated at the Company's option as
either the bank's prime rate plus 25 basis points or LIBOR plus basis points
increasing from a low of 125 to a high of 187.5 as loans outstanding increase
as a percentage of the borrowing base. As of December 31, 1999, the Company
was paying 8.08% per annum interest on $82.5 million and 8.36% per annum
interest on $5 million of the principal balance of the Facility. The loan
matures on November 30, 2002. Prior to maturity, no payments of principal are
required so long as the borrowing base exceeds the loan balance. The
borrowings under the Facility are secured by substantially all of the
Company's oil and natural gas properties.
The Facility requires an interest coverage ratio of two and a half to one
(2.5:1) determined on a quarterly basis prior to the quarter ending September
30, 2000 and each four quarter period thereafter, and a current ratio,
excluding current maturities of the Facility, of one to one (1:1), determined
on a quarterly basis.
The Facility also requires certain other affirmative and negative covenants
including, but not limited to:
. Use of all proceeds from sales of oil and natural gas properties for the
repayment of the outstanding debt.
F-14
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
. Prohibits the declaration or payment of any cash dividend; purchase,
redeem or otherwise acquire for value any outstanding stock; return
capital to stockholders; or make any distribution of assets to
stockholders, except for dividends on Series C Preferred Stock and
redemption of Series C Preferred Stock under certain circumstances.
. Agree not to enter into any hedge transactions except with the bank's
consent and for certain pre-approved hedging activities in connection
with oil and natural gas properties.
Events of default under the Facility include a final judgement or order in
excess of $1 million, a change of control of the Company or Floyd C. Wilson
ceasing to act as President and Chief Executive Officer.
Aggregate amounts of expected required repayments of long term debt at
December 31 are as follows (in thousands):
<TABLE>
<S> <C>
2000.............................................................. $ --
2001.............................................................. --
2002.............................................................. 87,500
Thereafter........................................................ --
-------
Total........................................................... $87,500
=======
</TABLE>
(7) SENIOR SUBORDINATED CONVERTIBLE NOTES
On August 27, 1999, senior subordinated convertible promissory notes (the
"Senior Notes") were sold to W/E LLC and affiliates of Alvin V. Shoemaker
("Shoemaker"), a former director and significant shareholder, for $10.7
million and $150,000, respectively. On October 19, 1999, $2.4 million of
Senior Notes were sold to The Prudential Insurance Company of America
("Prudential"). The Senior Notes bear interest at an annual rate of 9%.
Interest is payable beginning on December 31, 1999, every March 31, June 30,
September 30 and December 31, until maturity on August 27, 2004. The Company
may defer payment of fifty percent (50%) of the first eight quarterly interest
payments. The Senior Notes may be prepaid, without premium or penalty, in
whole or in part, at any time after August 27, 2001. The holders of the Senior
Notes may convert all or any portion of outstanding principal and accrued
interest at any time into shares of Company common stock at a conversion price
of $9.00 per common share, a total of 1,469,316 common shares. The conversion
price may be adjusted from time to time based on the occurrence of certain
events. In the event of a change in control, the entire outstanding principal
balance and all accrued but unpaid interest is immediately due and payable.
The Senior Notes rank senior in right of payment to all Company notes and
indebtedness other than the Facility.
(8) INCOME TAXES
Income tax benefit for the years ended December 31, 1999 and 1998 consisted
of the following (in thousands):
<TABLE>
<CAPTION>
December 31,
----------------
1999 1998
------- -------
<S> <C> <C>
Current................................................. $ -- $ --
Deferred................................................ (1,443) (2,830)
------- -------
Total................................................. $(1,443) $(2,830)
======= =======
</TABLE>
F-15
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
The reconciliation of income tax computed at the U.S. federal statutory tax
rates to the provision for income taxes is as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
----------------
1999 1998
------- -------
<S> <C> <C>
Income tax benefit at statutory rate................... $(1,656) $(3,202)
Increase (decrease) in valuation allowance............. (151) 860
Increase due to non-deductible stock compensation...... 248 --
Purchase price adjustment.............................. -- (508)
Other.................................................. 116 20
------- -------
Total................................................ $(1,443) $(2,830)
======= =======
</TABLE>
The Company's net deferred tax liability at December 31, 1999 and 1998 is as
follows (in thousands):
<TABLE>
<CAPTION>
1999 1998
-------- -------
<S> <C> <C>
Deferred tax liability
Oil and natural gas properties....................... $ 1,428 $ --
-------- -------
Deferred tax asset
NOL carryforward..................................... (6,643) (4,057)
AMT tax credit carryforward.......................... (36) (36)
Oil and natural gas properties....................... -- (19)
Other................................................ (547) (395)
-------- -------
(7,226) (4,507)
Valuation allowance.................................... 6,089 6,240
-------- -------
Net deferred tax liability............................. $ 291 $ 1,733
======== =======
</TABLE>
In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred
tax asset will not be realized. Management considers the scheduled reversal of
deferred tax liabilities, projected future taxable income, and tax planning
strategies in making this assessment. Based upon projections for future
taxable income over the periods in which the deferred tax assets are
deductible and the Section 382 limitation discussed below, management believes
it is more likely than not that the Company will realize the benefits of these
deductible differences, net of the existing valuation allowances at December
31, 1999 and 1998.
The Enex Acquisition caused an ownership change pursuant to Section 382 in
March 1998. As a result of this ownership change, the Company's use of its net
operating loss carryforwards subsequent to that date will be limited. The
Floyd Oil Acquisition in November 1999 also caused an ownership change
pursuant to Section 382. As a result of this ownership change, the Company's
use of its net operating loss carryforwards subsequent to that date will be
limited to approximately $1.5 million per year.
As of December 31, 1999, the Company had net operating loss carryforwards of
approximately $20 million, expiring beginning in 2009 through 2019.
(9) RETIREMENT PLAN AND EMPLOYEE INCENTIVE PLAN
All of the employees of the Company are eligible to participate in a defined
contribution plan that provides for maximum discretionary employee
contributions of 15% of total wages paid to employees for the year and Company
contributions. No Company contributions were made to the plan for the years
ending December 31, 1999 and 1998.
F-16
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
In March 1995, the Board of Directors adopted an employee incentive
compensation plan (the "Plan") for the benefit of Company employees. The Plan
benefits were equal to one percent (1%) of the annual net profit from oil and
natural gas properties acquired or discovered on or after January 1, 1994 and
one percent (1%) of the annual sales proceeds from any oil and natural gas
properties sold on or after January 1, 1994. The Compensation Committee of the
Board of Directors had sole authority regarding the amount and timing of
payment of any Plan benefits to eligible employees.
On August 27, 1999, the Company paid $274,625 to the eligible participants
in the Plan and terminated the Plan pursuant to the terms of the W/E LLC
agreement. The payment was equal to 100% of the Plan benefits through August
27, 1999. The entire amount of the payment, including associated taxes of
$17,902, was recognized during the year ended December 31, 1999. Prior to the
Compensation Committee's authorization, the Plan benefits were not accrued as
an expense in the financial statements because the likelihood that the
Compensation Committee would determine that the benefits would be payable to
eligible employees was less than probable.
(10) STOCK OPTION PLANS
At December 31, 1999, the Company had two fixed stock option plans, the 1995
Stock Option and Stock Appreciation Rights Plan (the "1995 Plan") and the 1999
Stock Option Plan (the "1999 Plan"). As discussed in Note 1, for the years
ended December 31, 1999 and 1998, no compensation cost has been recognized,
relating to stock options issued, as the exercise price of each option equals
the market price of the Company's common stock on the date of grant. Had
compensation cost for the Company's 1995 Plan been determined based on the
fair value at the grant date for stock options granted for the years ending
December 31, 1999 and 1998, the Company's net loss and loss per share would
have been increased to the pro forma amounts listed below (in thousands,
except per share amounts):
<TABLE>
<CAPTION>
December 31,
----------------
1999 1998
------- -------
<S> <C> <C>
Net loss
As Reported.......................................... $(4,006) $(6,657)
Pro Forma............................................ (4,110) (7,120)
Net loss per common share, basic and diluted
As Reported.......................................... $ (1.14) $ (2.48)
Pro Forma............................................ (1.17) (2.65)
</TABLE>
The weighted average fair value of stock options granted during 1999 and
1998 was $2.40 and $8.91 per share, respectively. The fair value of each
option is estimated on the date of grant using the Black-Scholes option-
pricing model with the following assumptions used for the grants in 1999 and
1998; no dividend yield; expected volatility of 77%; weighted average risk-
free interest rate of 4.78% and 4.93%, respectively; and an expected life of 3
years. At December 31, 1999, the range of exercise prices and weighted average
remaining contractual life of options outstanding was $4.50 to $23.25 and 2.81
years, respectively.
At December 31, 1999 there were 157,300 and 500,000 shares of common stock
available for grant under the 1995 and 1999 Plans, respectively. All of the
options granted under the 1995 Plan expire five (5) years from the date of
grant if not exercised and are 100% vested. As of December 31, 1999, no
options have been issued under the 1999 Plan. The 1995 and 1999 Plans are
administered by the Compensation Committee of the Board of Directors.
F-17
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
On August 24, 1999, the Company amended the 1995 Plan due to the change in
control that resulted from the Agreement (See Note 3). The 1995 Plan was
amended to extend the exercise date for all options issued prior to July 1,
1999 to one year from the following dates: (1) the termination date of
employees if the termination date is without cause and occurred during the
six-month period commencing with the closing of the Purchase Agreement; (2)
the date of termination for employees terminated for "Good Reason" as defined
in such employee's employment agreement; and (3) the date of resignation of a
holder who is also a director who resigns at closing of the Agreement.
The extension of the exercise period of the employee stock options resulted
in a new measurement date and compensation expense, equal to the intrinsic
value of all of the outstanding options, of approximately $730,000, was
recognized as stock compensation.
Information relating to stock options and certain warrants is summarized
below:
<TABLE>
<CAPTION>
Average Exercise
Shares Price Per Share
------- ----------------
<S> <C> <C>
Options and warrants outstanding at January 1,
1998............................................ 201,389 $16.71
Granted.......................................... 102,333 $16.71
-------
Options and warrants outstanding at December 31,
1998............................................ 303,722 $16.71
Granted.......................................... 66,667 $ 4.50
Exercised........................................ (21,500) $ 5.43
Forfeited........................................ (12,967) $17.40
-------
Options and warrants outstanding at December 31,
1999............................................ 335,922 $15.00
=======
Options and warrants exercisable at December 31,
1999............................................ 335,922 $15.00
=======
</TABLE>
Options to acquire 75,000 shares of the Company common stock at an exercise
price of $16.50 were granted outside of the 1995 Plan on February 13, 1997 to
certain officers of the Company. Warrants to acquire 25,000 shares of the
Company common stock at an exercise price of $15.00 were granted outside of
the 1995 Plan on September 15, 1998 to a consultant (See Note 11). Both grants
are included in the table above. Warrants to purchase 1,216,822 shares and
266,226 shares of common stock at $3.00 per share were issued on August 27,
1999 and October 19, 1999, respectively, and are excluded from the table above
because the warrants were issued in conjunction with the sales of stock and
are not stock-based compensation.
(11) STOCKHOLDERS' EQUITY
Preferred Stock-Series A
On September 4, 1996, the Company signed a stock purchase agreement with
Kaiser Francis Oil Company ("Kaiser-Francis"). Kaiser-Francis agreed to
purchase 1,666,667 shares of Series A Preferred Stock ("Series A") at $6.00
per share, for a total investment of $10 million. The parties agreed to a
five-year purchase period, effective September 4, 1996, with minimum
incremental investments of $500,000 each. Each issuance of Series A was
subject to approval by Kaiser-Francis of the use of proceeds. The Series A was
nonvoting and accrued dividends at 8% per annum, payable quarterly in cash.
The Series A was convertible at any time after issuance into shares of common
stock at the rate of 0.66 shares of common stock for each share of Series A
before January 1, 1998. The conversion rate decreases for every full year
(excluding partial years) thereafter at 8% per annum. As of December 31, 1997,
1,666,667 shares of the Series A had been issued. On January 31, 1998 Kaiser-
Francis converted 100% of the Series A into 1,111,111 common shares of the
Company.
F-18
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
Preferred Stock--Series B
In connection with the merger of Shore Oil Company , effective June 30,
1997, the Company issued 266,667 shares of Series B Preferred Stock
("Series B"). The Series B is nonvoting and pays no dividends. The Series B has
a liquidation value of $7.50 per share. Until December 31, 2002, any holder of
the Series B may convert all or any portion of Series B shares into Company
Common Stock ("Common") at the greater ratio of (i) three shares of Series B for
one share of Common or (ii) at a ratio based upon the "Alternative Conversion
Factor." The Alternative Conversion Factor is determined by dividing the net
increase in value of approximately 40,000 net mineral acres owned by the Company
in South Louisiana by $8,000,000 and multiplying the product by 355,333 to
arrive at the potential number of total Common shares all holders would receive
upon conversion. In no event shall the aggregate total number of shares of
Common into which the Series B are converted be less than 88,889 shares or
exceed 444,444 shares, unless further increased for any anti-dilution
provisions. Upon expiration of the conversion period, unless the Company has
given notice to redeem the Series B, all of the shares of the Series B shall be
automatically converted.
At December 31, 1999, the value of the fee minerals had increased to a level
that resulted in the Series B shares being convertible into an additional
1,891 common shares applying the Alternative Conversion Factor. At December
31, 1999, none of the Series B had been converted.
Preferred Stock--Series C
In connection with the Enex Partnership Acquisition, on December 30, 1998,
the Company issued 2,177,481 shares of Series C Preferred Stock ("Series C")
in exchange for 100% of the Enex Partnership units. The holders of Series C
are entitled to receive cumulative cash dividends in an amount per share of
$0.50 per year (10% annual rate), payable semi-annually on March 31 and
September 30 of each year. These dividends are payable in preference to and
prior to the payment of any dividend or distribution to any holder of Company
common stock or other junior security. The Series C dividends began to accrue
on December 30, 1998. The banks have granted the Company a waiver allowing the
Company to pay the dividends on the Series C as long as no default or event of
default exists or would exist as a result of any Series C dividend payment.
The Series C has a liquidation preference of $5.00 per share plus an amount
equal to all accumulated, accrued and unpaid dividends. The liquidation
preference of Series C ranks on parity with the Series B.
Each share of Series C is convertible into one-third share of Company common
stock. On or after January 1, 2000, the Company may redeem all or a portion of
the Series C, at its option, at a purchase price of $5.00 per share, plus an
amount equal to all accumulated, accrued and unpaid dividends.
The Series C is generally nonvoting; however, holders of Series C are
entitled to vote on any amendment, alteration or appeal of any provision of
the Company's Articles of Incorporation which would adversely affect any
holder's rights and preferences.
As a result of its limited partnership interest in the Enex Partnership,
Enex owns 1,293,522 shares of the Series C of which the Company owns 80%, or
1,034,818 shares through its 80% ownership of Enex.
Common Stock and Warrants
On August 27, 1999, the Company sold to W/E LLC 1,585,185 shares of common
stock and five-year warrants to purchase 1,200,000 shares of common stock for
$9.8 million in cash and oil and natural gas properties valued at $875,000. On
the same date, the Company sold 22,222 shares of common stock and five-year
warrants to purchase 16,822 shares of common stock to Shoemaker for $150,000
(See Notes 3 and 7).
F-19
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
On October 19, 1999, the Company closed a private placement of securities to
Prudential. The economic terms and conditions of the private placement are
similar to those of the securities purchase agreement with W/E LLC and
Shoemaker entered into on July 1, 1999. The private placement consisted of the
sale of 351,681 shares of common stock and five-year warrants to purchase
266,226 shares at $3.00 per share of common stock for $2.4 million and a five-
year senior subordinated convertible note for $2.4 million (See Note 7).
The warrants issued to W/E LLC, Shoemaker and Prudential are exercisable
for $3.00 per share and expire five years from the issue date. Sixty percent
of the warrants are immediately exercisable, in whole or in part at any time
until the expiration date. An additional 10% of the warrants may be exercised
at each anniversary of the grant date until expiration. On the occurrence of
either a change of control, payment in full of the Senior Notes or conversion
of the entire principal balance of the Senior Notes, all of the warrants
become immediately exercisable. If less than the entire principal balance of
the Senior Notes are converted, a pro-rata portion of the warrants will be
convertible based on the portion of the Senior Notes that are converted.
On September 15, 1998 the Company entered into a consulting agreement with
Edward K. Andrew ("Andrew") for a term of five years beginning January 1,
1999. As compensation, the Company granted to Andrew a warrant to purchase
25,000 shares of Company common stock at a price of $15.00. The warrants
vested over the period September 15, 1998 to January 1, 1999. The estimated
fair value of the warrants was determined at the date of grant and charged to
stock compensation expense over the vesting period.
On February 13, 1997, the Company awarded to certain officers 16,364 shares
of restricted stock of the Company. The restricted stock awards were
contingent on the performance of services to the Company in the future with
50% of the restricted shares being earned over the six month period July 1,
1997 to December 31, 1997 and 50% over the six month period January 1, 1998 to
June 30, 1998. All restricted shares were earned and issued as of December 31,
1998.
Earnings Per Share
At December 31, 1999 and 1998, the Company had a weighted average of
1,149,476 and 283,297, combined stock options, warrants and convertible
preferred stock and notes outstanding, respectively, which were not included
in the computation of diluted earnings per share, because the effect of the
assumed exercise of these stock options, warrants and convertible securities
would have an antidilutive effect on the computation of diluted loss per
share. At December 31, 1999 and 1998, the Company had outstanding convertible
preferred stock that was convertible into 469,744 and 469,778 shares of common
stock, and dividends of $574,080 and $67,945, respectively, which were not
reflected in the computation of diluted earnings per share, because the effect
of the assumed conversion of these preferred shares would have an antidilutive
effect on the computation of diluted loss per share. At December 31, 1999, the
Company had $4,154,292 weighted average face value of convertible subordinated
notes that were convertible into 461,588 shares of common stock and interest
expense of $376,367, which were not reflected in the computation of diluted
earnings per share, because the effect of the assumed conversion of these
subordinated notes would have an antidilutive effect on the computation of
diluted loss per share.
(12) COMMITMENTS AND CONTINGENCIES
The Company is obligated under the terms of certain operating leases for
office space that continue through January 31, 2005. Total rent expense was
$267,337 and $268,477 for the years ended December 31, 1999 and 1998,
respectively. Future minimum rental payments under the Company's leases total
$309,372, $248,694, $194,016, $194,016 and $194,016 for the years ending
December 31, 2000 through 2004, respectively.
F-20
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
On November 18, 1999, the Company's shareholders approved a reincorporation
of the Company from Alabama to Delaware (See Note 1). The Alabama Code has a
shareholder dissent provision that allows a shareholder to dissent from the
reincorporation and demand cash payment equal to the fair value of the common
stock owned at the date of the reincorporation. Before the November 18
meeting, the Company received shareholder dissents representing ownership of
99,438 shares of common stock. Over the period December 15, 1999 to January
25, 2000, the Company received formal demands for payment from the dissenting
shareholders (the "dissenters"). The Company expects to make an offer to the
dissenters before March 10, 2000. Once the offer is made, the dissenters have
30 days to accept the offer or make a counteroffer. If the Company and the
dissenters cannot reach agreement on the fair value of the common shares
within 60 days of the dissenters' counteroffer, if any, the matter is then
moved to the Circuit Court of Washington County, Alabama for resolution. The
exact amount to be paid to the dissenters for their common shares cannot be
determined at this time. Based on the Company's closing stock price on
November 23, 1999 of $11.25 per share and accrued interest from November 23,
1999, the Company accrued the estimated cash payment to the dissenters of
approximately $1.1 million.
As of December 31, 1999, the Company had $55,000 of irrevocable standby
letters of credit outstanding.
The Company is a defendant in various legal proceedings which are considered
routine litigation incidental to the Company's business, the disposition of
which management believes will not have a material effect on the financial
position or results of operations of the Company.
(13) FINANCIAL INSTRUMENTS
In April 1999, the Company entered into costless collar hedges for
approximately 3,650 Mcf per day with a weighted average floor and ceiling of
$2.06 and $2.20, respectively, for the months of May through October of 1999.
During the year ending December 31, 1999, the Company incurred hedging losses of
approximately $164,000. At December 31, 1999, the Company had no open derivative
instruments.
Fair value of cash, receivables and payables approximates carrying value.
Fair value of long-term debt also approximates carrying value due to the
nature of the Facility, whereby the interest rates are floating rates which
reflect market rates.
At December 31, 1999, the fair value of the $13.2 million senior
subordinated convertible notes was $13.1 million.
(14) SUBSEQUENT EVENTS
On January 14, 2000, the Company's stockholders voted to effect a one-for-
three reverse split of the Company's common stock for the stockholders of
record on December 9, 1999. The reverse stock split resulted in a decrease of
10,677,542 in the number of shares issued at December 31, 1999, 14,515 of
which are held in treasury. The par value of these shares was transferred to
additional paid-in capital. All common share and earnings per common share
amounts as of December 31, 1999 and 1998 have been retroactively restated in
the accompanying consolidated financial statements to reflect the reverse
stock split.
On February 3, 2000, the Company closed the acquisition of Magellan
Exploration, LLC ("Magellan"), a privately held Delaware limited liability
company, for an estimated purchase price of $18.3 million. In connection with
the acquisition, the Company issued 1,085,934 common shares and warrants to
purchase 333,333 shares of common stock with an exercise price of $30.00 per
share, which are exercisable for four years. The Company also issued 617,008
shares of Series D convertible preferred stock with a stated value of $24.00
per share,
F-21
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
dividend rate of 5% per annum with an option for three years for the Company
to pay the dividends in additional Series D shares and with each Series D
share convertible at any time into Company common stock on a one-for-one
basis. The Company may redeem the Series D shares upon 30 days written notice
and there are no rights of holders to "put" the Series D shares to the
Company. The owners of Magellan also received a 5% "Back-In" working interest
in twelve (12) exploration prospects.
(15) SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED)
Capitalized Costs and Costs Incurred
The following tables present the capitalized costs related to oil and
natural gas producing activities and the related depreciation, depletion,
amortization and impairment as of December 31, 1999 and 1998 and costs
incurred in oil and natural gas property acquisition, exploration and
development activities (in thousands) for the years ended December 31, 1999
and 1998.
<TABLE>
<CAPTION>
1999 1998
-------- -------
<S> <C> <C>
Capitalized Costs
Proved properties..................................... $162,455 $84,325
Nonproducing leasehold................................ 6,385 6,524
Accumulated depreciation, depletion, amortization and
impairment........................................... (37,861) (38,810)
-------- -------
Net capitalized costs............................... $130,979 $52,039
======== =======
Costs Incurred
Proved properties..................................... $ 91,081 $28,878
Unproved properties................................... 343 337
Exploration costs..................................... 824 1,802
Development costs..................................... 2,154 3,041
-------- -------
Total............................................... $ 94,402 $34,058
======== =======
Depletion, depreciation, amortization and impairment.... $ 9,067 $11,013
======== =======
</TABLE>
Estimated Quantities of Reserves
The Company has interests in oil and natural gas properties that are located
principally in Texas, Louisiana, Kansas, Oklahoma and New Mexico. The Company
does not own or lease any oil and natural gas properties outside the United
States. There are no quantities of oil and natural gas subject to long-term
supply or similar agreements with any governmental agencies.
The Company retains independent engineering firms to provide year-end
estimates of the Company's future net recoverable oil, natural gas and natural
gas liquids reserves. In 1999, such estimates were prepared by Ryder Scott
Company. In 1998, such estimates were prepared by Lee Keeling and Associates,
Inc. and H.J. Gruy & Associates, Inc.. The reserve information was prepared in
accordance with guidelines established by the Securities and Exchange
Commission.
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
F-22
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
include those reserves expected to be recovered from new wells or 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 oil,
including condensate and natural gas liquids, for the years ended December 31,
1999 and 1998 are summarized as follows (in barrels):
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Proved Reserves
Beginning of year................................. 3,342,048 2,933,000
Revisions of previous estimates................... 502,139 (277,291)
Extensions and discoveries........................ 12,667 103,506
Purchases of reserves in place.................... 6,865,638 1,254,663
Sales of reserves in place........................ (355,190) (90,373)
Production for the year........................... (531,881) (581,457)
--------- ---------
End of year..................................... 9,835,421 3,342,048
========= =========
Proved Developed Reserves
Beginning of year................................. 3,117,839 2,580,000
End of year....................................... 9,358,048 3,117,839
</TABLE>
Net quantities of proved developed and undeveloped reserves of natural gas
for the years ended December 31, 1999 and 1998 are summarized as follows
(in Mcf):
<TABLE>
<CAPTION>
1999 1998
----------- ----------
<S> <C> <C>
Proved Reserves
Beginning of year.............................. 43,482,980 18,419,000
Revisions of previous estimates................ (5,135,492) (82,742)
Extensions and discoveries..................... 1,225,665 290,347
Purchases of reserves in place................. 126,556,624 30,997,247
Sales of reserves in place..................... (1,693,121) (2,294,193)
Production for the year........................ (4,737,656) (3,846,679)
----------- ----------
End of year.................................. 159,699,000 43,482,980
=========== ==========
Proved Developed Reserves
Beginning of year.............................. 36,731,365 14,251,000
End of year.................................... 122,914,000 36,731,365
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves
The following is a summary of the standardized measure of discounted future
net cash flows related to the Company's proved oil and natural gas reserves.
For these calculations, estimated future cash flows from estimated future
production of proved reserves are computed using 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 taxes were
calculated by applying statutory tax rates (based on current law adjusted for
permanent differences and tax credits) to the estimated future pre-tax net
cash flows related to proved oil and natural gas reserves, less the tax basis
of the properties involved.
F-23
<PAGE>
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 1999 and 1998
The Company cautions against using this data to determine the value of its
oil and natural gas properties. To obtain the best estimate of the fair value
of the 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 oil and natural gas reserves for the years ended December 31, 1999 and
1998 are summarized as follows (in thousands):
<TABLE>
<CAPTION>
1999 1998
--------- --------
<S> <C> <C>
Future cash inflows................................... $ 594,023 $133,549
Future production costs and development costs......... (223,765) (62,085)
Future income tax expenses............................ (92,975) --
--------- --------
Future net cash flows................................. 277,283 71,464
10% discount to reflect timing of cash flows.......... (128,542) (32,570)
--------- --------
Standardized measure of discounted future net cash
flows................................................ $ 148,741 $ 38,894
========= ========
</TABLE>
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows for the years ended December 31,
1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
1999 1998
-------- -------
<S> <C> <C>
Sales of oil and natural gas, net of production cost.... $(13,224) $(7,210)
Net changes in prices and production cost............... 18,646 (5,459)
Extensions and discoveries.............................. 1,945 732
Purchases of reserves................................... 150,295 23,092
Sales of reserves....................................... (1,643) (1,528)
Revisions of previous quantity estimates................ (1,994) (1,573)
Net change in income taxes.............................. (49,874) 2,712
Accretion of discount................................... 3,889 3,635
Changes in production rates (timing) and other.......... 1,807 --
-------- -------
Change for year......................................... $109,847 $14,401
======== =======
</TABLE>
During recent years, there have been significant fluctuations in the prices
paid for oil in the world markets. The situation has had a destabilizing
effect on posted prices for oil in the United States, including the posted
prices paid by purchasers of the Company's oil. The period end prices of oil
and natural gas at December 31, 1999 and 1998, used in the above table were
$23.64 and $9.50 per barrel of oil and $2.23 and $2.10 per thousand cubic feet
of natural gas, respectively.
F-24
<PAGE>
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used
in the oil and gas industry and herein:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas
liquids.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a primarily
natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to
productive wells or wells capable of production.
Development well. A well drilled into a proved natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find and produce natural gas or oil
reserves that are not proved, to find a new reservoir in a field previously
found to be productive of natural gas or oil in another reservoir or to extend a
known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic level.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Mmbtu. One million British Thermal Units.
Mmcf. One million cubic feet of natural gas.
Mmcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Productive well. A well that is found to be capable of producing sufficient
quantities of oil and gas so that proceeds from the sale of the production are
greater than production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the
discovery of oil and natural gas.
31
<PAGE>
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 oil, natural gas and natural gas
liquids that 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. Reserves that are expected to be recovered from
new wells on developed acreage where the subject reserves cannot be recovered
without drilling additional wells.
PV-10 value. The estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated production
costs and future development costs, using prices and costs in effect as of a
certain date, without escalation and without giving effect to non-property
related expenses, such as general and administrative expenses, debt service,
future income tax expense, or depreciation, depletion, and amortization.
Recompletion. The completion of an existing well for production from a
formation that exists behind the casing of the well.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in a natural gas and oil property entitling the
owner to a share of natural gas and oil production free of costs of production.
Standardized measure. The estimated future net cash flows from proved natural
gas and oil reserves computed using prices and costs, at a specific date, after
income taxes and discounted at 10%.
Tcfe. One trillion cubic feet of natural gas equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas
liquids.
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 natural gas and oil regardless of whether such acreage contains proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production.
32
<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 by
the undersigned, thereunto duly authorized, as of March 30, 2000.
3TEC ENERGY CORPORATION
(Registrant)
By: /s/ Floyd C. Wilson
____________________________________________
Floyd C. Wilson
Chief Executive Officer, President and Chairman
By: /s/ Stephen W. Herod
____________________________________________
Stephen W. Herod
Executive Vice-President,
Chief Financial Officer, Secretary
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Floyd C. Wilson and Stephen W. Herod, and each of
them, his true and lawful attorneys-in-fact and agents, each with full power of
substitution and resubstitution, to sign any and all amendments (including post-
effective amendments) to this Annual Report on Form 10-KSB and to file the same,
with exhibits thereto and other documents in connection therewith, with the
Securities and Exchange Commission, granting unto said attorney-in-fact and
agents, and each of them, full power and authority to do and perform each and
every act and thing requisite and necessary to be done in connection therewith,
as fully to all intents and purposes as he or she might or could do in person,
hereby ratifying and confirming all that said attorneys-in-fact, or their
substitute or substitutes, or any of them, shall do or cause to be done by
virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:
March 30, 2000 /s/ Floyd C. Wilson
_________________________ ________________________________________________
Date Floyd C. Wilson
Chief Executive Officer, President and Chairman
March 30, 2000 /s/ Stephen W. Herod
_________________________ ________________________________________________
Date Stephen W. Herod
Director, Executive Vice-President,
Chief Financial Officer, Secretary
33
<PAGE>
March 30, 2000 /s/ Gary R. Christopher
_________________________ ________________________________________________
Date Gary R. Christopher
Director
March 30, 2000 /s/ D. Martin Phillips
_________________________ ________________________________________________
Date D. Martin Phillips
Director
March 30, 2000 /s/ David B. Miller
_________________________ ________________________________________________
Date David B. Miller
Director
34
<PAGE>
EXHIBIT 3.3
CERTIFICATE OF AMENDMENT
OF
CERTIFICATE OF INCORPORATION
OF
3TEC ENERGY CORPORATION
The undersigned, being the Executive Vice President of 3TEC Energy
Corporation (the "Corporation") DOES HEREBY CERTIFY as follows:
1. The name of the Corporation is 3TEC Energy Corporation.
2. The Certificate of Incorporation of the Corporation is hereby amended
to effect a one (1) for three (3) reverse split of all of the Corporation's
issued common stock, par value $.02 per share (the "Common Stock"), whereby
each three (3) issued shares of Common Stock shall be changed into one (1)
share of Common Stock, and, in that connection, to reduce the stated
capital of the Corporation. This Certificate of Amendment shall be
effective as of 11:59 p.m. Eastern Standard Time on January 14, 2000.
3. In order to effectuate the amendment set forth in Paragraph 2 above:
(a) All of the Corporation's issued Common Stock, having a par value
of $.02 per share, is hereby changed into new Common Stock,
having a par value of $.02 per share, on the basis of one (1) new
share of Common Stock for each three (3) shares of Common Stock
issued as of the date of filing of the Amendment with the
Secretary of State for the State of Delaware, provided, however,
that no fractional shares of Common Stock shall be issued
pursuant to such change. Each stockholder who would otherwise be
entitled to a fractional share as a result of such change shall
have only a right to receive a cash payment equal to the amount
produced by multiplying such fraction times the closing price of
one share of Common Stock as of the close of business on the date
of filing of this Amendment, in lieu of any fractional share
otherwise issuable upon conversion.
(b) The Corporation's 60,000,000 authorized shares of Common Stock,
having a par value of $.02 per share, shall not be changed;
(c) The Corporation's 20,000,000 authorized shares of preferred
stock, having a par value of $.02 per share, shall not be
changed; and
(d) The Corporation's stated capital shall be reduced by an amount
equal to the aggregate par value of the shares of Common Stock
issued prior to the effectiveness of this Amendment which, as a
result of the reverse split provided for herein, are no longer
issued shares of Common Stock.
4. The foregoing amendments of the Certificate of Incorporation of the
Corporation
<PAGE>
have been duly adopted by the Corporation's Board of Directors and
Stockholders in accordance with the provisions of Section 242 of the
Delaware General Corporation Law.
IN WITNESS WHEREOF, the undersigned have subscribed this document on the
date set forth below.
Dated: January 14, 2000
- ------------------------------------------
Stephen W. Herod, Executive Vice President
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<PAGE>
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<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
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