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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(Mark One)
[X] Annual report under Section 13 or 15(d) of the Securities Exchange Act
of 1934
For the fiscal year ended December 31, 2002
[_] Transition report under Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the transition period from to
Commission file number: 001-14745
3TEC ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
Delaware 63-1081013
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
700 Milam Street, Suite 1100
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 to be registered pursuant to Section 12(b) of the Act: None
Securities to be registered pursuant to Section 12(g) of the Act:
Common Stock, $.02 Par Value
Indicate by check mark whether the Registrant (1) filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers in response to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [_]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [_]
Revenues of Registrant for fiscal year ended December 31, 2002 are
$91,102,240.
The aggregate market value as of March 18, 2003 of voting and nonvoting
common stock held by nonaffiliates of the Registrant was $206,864,294.
As of March 18, 2003 the Registrant had 16,696,597 shares of Common Stock,
$.02 par value outstanding.
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TABLE OF CONTENTS
Page
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PART I
Item 1. Business.................................................................. 4
Background................................................................ 4
Recent Developments....................................................... 4
Business Strategy......................................................... 5
Marketing................................................................. 5
Competition............................................................... 5
Regulation................................................................ 6
Employees................................................................. 8
Our Executive Offices..................................................... 8
Item 2. Properties................................................................ 9
Description of Our 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
Current Activities........................................................ 13
Item 3. Legal Proceedings......................................................... 13
Item 4. Submission of Matters to Vote of Security Holders......................... 13
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters..... 14
Item 6. Selected Financial Data................................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations.............................................................. 16
Overview.................................................................. 16
Description of Critical Accounting Policies............................... 17
Liquidity and Capital Resources........................................... 19
Results of Operations..................................................... 20
Year Ended December 31, 2002, Compared With Year Ended December 31, 2001.. 20
Year Ended December 31, 2001, Compared With Year Ended December 31, 2000.. 21
Item 7A. Quantitative and Qualitative Disclosures About Market Risk................ 23
Item 8. Financial Statements and Supplementary Data............................... 24
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial
Disclosure.............................................................. 24
PART III
Item 10. Directors and Executive Officers of the Registrant........................ 25
Item 11. Executive Compensation.................................................... 27
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters..................................................... 34
Item 13. Certain Relationships and Related Transactions............................ 36
Item 14. Controls and Procedures................................................... 36
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 37
Glossary of Certain Oil and Gas Terms..................................... 41
Signatures................................................................ 43
Power of Attorney......................................................... 43
Item 13(a) includes the Index of Exhibits to be filed with the Securities and
Exchange Commission relative to this Report.
2
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Some of the information in this Annual Report on Form 10-K, including
information incorporated by reference, contains forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities and Exchange Act of 1934. The forward-looking statements
speak only as of the date made and the Company undertakes no obligation to
update such forward-looking statements. These forward-looking statements may be
identified by the use of the words "believe," "expect," "anticipate," "will,"
"contemplate," "would" and similar expressions that contemplate future events.
These future events include the following matters:
. financial position;
. business strategy;
. budgets;
. amount, nature and timing of capital expenditures;
. drilling of wells;
. natural gas and oil reserves;
. timing and amount of future production of natural gas and oil;
. operating costs and other expenses;
. cash flow and anticipated liquidity;
. prospect development and property acquisitions; and
. marketing of natural gas and oil.
Numerous important factors, risks and uncertainties may affect the Company's
operating results, including:
. the risks associated with exploration;
. the ability to find, acquire, market, develop and produce new properties;
. natural gas and oil price volatility;
. uncertainties in the estimation of proved reserves and in the projection
of production of proved reserves;
. future rates of production and timing of development expenditures;
. operating hazards attendant to the natural gas and oil business;
. downhole drilling and completion risks that are generally not recoverable
from third parties or insurance;
. potential mechanical failure or under-performance of significant wells;
. climactic conditions;
. availability and cost of material and equipment;
. delays in anticipated start-up dates;
. actions or inactions of third-party operators of the Company's properties;
. the ability to find and retain skilled personnel;
. availability of capital;
. the strength and financial resources of competitors;
. regulatory developments;
. environmental risks; and
. general economic conditions, including wars and acts of terrorism.
Any of the factors listed above and other factors contained in this Form
10-K could cause the Company's actual results to differ materially from the
results implied by these or any other forward-looking statements made by the
Company or on its behalf. The Company cannot assure you that future results
will meet its expectations.
3
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. Our common stock is quoted on the
Nasdaq National Market under the symbol "TTEN".
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. As of December 31, 2002, we had estimated total net proved reserves
of 296 Bcfe, of which approximately 259 Bcfe, or 87%, were natural gas and
approximately 239 Bcfe, or 81%, were proved developed, with an estimated SEC
Case PV-10 value of $488 million. For the fourth quarter of 2002, our average
net daily production rate was 86 Mmcfe.
Historically, 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. Additionally, 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.
In August 1999, W/E Energy Company L.L.C. ("W/E LLC"), an entity which was
owned by affiliates of EnCap Investments L.L.C. ("EnCap") and Floyd C. Wilson,
purchased a controlling interest in us for approximately $20.5 million in cash
and $875,000 in producing properties. Concurrently with the investment by W/E
LLC, Mr. Wilson was named our Chairman and Chief Executive Officer. Following
the change in control in August 1999, during the fourth quarter of 1999 and the
first half of 2000 we closed several transactions that changed our senior
management team, capital structure and our property base. During the fourth
quarter of 2001, W/E LLC was dissolved and its holdings of 3TEC common stock
and warrants were distributed to its members. See discussion in Note 3 of the
Company's notes to consolidated financial statements.
On June 30, 2000, the Company completed a public offering of 8.05 million
shares of the Company's common stock priced at $9.00 per share. The net
proceeds, approximately $66.6 million, were used primarily to repay a portion
of the outstanding debt under the Company's Credit Facility, hereafter defined.
Recent Developments
On February 2, 2003, the Company entered into a definitive agreement with
Plains Exploration & Production Company ("Plains") whereby Plains will acquire
the Company for a combination of cash and stock. Under the terms of the
agreement, the Company's shareholders will receive $8.50 in cash and 0.85
shares of Plains' Common Stock for each share of the Company's Common Stock,
subject to certain adjustments if the average share price of Plains's Common
Stock (as determined during a twenty-day trading period prior to closing) is
less than $7.65 per share or greater than $12.35 per share. Although subject to
shareholder approval and other customary closing conditions, the aforementioned
transaction is expected to close during the second quarter of 2003.
4
Business Strategy
Our business strategy is focused on the following:
. Pursuit of 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 exploration potential. We are
especially focused on increasing our holdings in fields and basins in
which we already own an interest.
. Further Development of Existing Properties. We intend to further develop
our properties that have proved reserves. We seek to add proved reserves
and increase production through the use of advanced technologies,
including detailed technical analysis of our properties, and by drilling
in-fill locations and selectively recompleting 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 properties.
. Growth 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 engineering, geological and
geophysical data and the interpretation of 3-D seismic data. We intend to
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.
. Rationalization of 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.
. Maintenance of Financial Flexibility. We intend to maintain a
substantial unused borrowing capacity under our 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, including our existing
financial partners, 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.
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 current market rates.
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.
In order to manage our exposure to price risks in the marketing of our
natural gas and oil production, we have in the past and may in the future enter
into natural gas and oil price hedging arrangements with respect to a portion
of our expected production.
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.
5
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.
A significant portion of the Company's working interests are operated by
third parties. The operations of the Company's interests are governed by joint
operating agreements with the third party operators and contain customary
industry standard terms and conditions. Wagner & Brown, Ltd. is the Company's
largest single third party operator, operating approximately 15% of the
Company's total produced oil and gas volumes on a monthly basis. No other third
party operator operates interests that generate greater than 5% of the
Company's monthly production.
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.
6
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. 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
7
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 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, 2002, we had 75 full-time employees. We believe that our
relationships with our employees are satisfactory. None of our employees are
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 and Website
Our principal executive offices are located at 700 Milam Street, Suite 1100,
Houston, Texas 77002, and our telephone number is 713.821.7100. Our website is
www.3tecenergy.com. We make available, free of charge, through our website, our
annual report on Form 10K, quarterly reports on Form 10Q, current reports on
Form 8-K, and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable
after we electronically file such material with, or furnish it to, the
Securities and Exchange Commission.
8
Item 2. Properties
Description of Our Properties
We present information regarding our natural gas and oil reserves,
properties, and operating results below.
As of December 31, 2002
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Estimated Net Proved Reserves Percent Proved Budgeted
----------------------------- PV-10 Total Undeveloped 2003 Capital
Gas Oil Total Value PV-10 Drilling Expenditures
(Mmcf) (MBbls)(1) (Mmcfe) ($000) Value Locations ($MM)
------- ---------- ------- ------- ------- ----------- ------------
East Texas. 168,465 1,375 176,715 270,693 55.5% 128 16.6
Gulf Coast. 28,554 1,544 37,818 119,157 24.4% 2 38.6
South Texas 31,457 2 31,469 34,940 7.2% 10 7.0
Other Areas 30,550 3,287 50,272 63,183 12.9% 7 0.8
------- ----- ------- ------- ----- --- ----
Total... 259,026 6,208 296,274 487,973 100.0% 147 63.0(2)
======= ===== ======= ======= ===== === ====
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(1) Includes oil, condensate and plant products barrels.
(2) As discussed in "Liquidity and Capital Resources" within Management's
Discussion and Analysis, the Company's capital expenditure budget for 2003
is $63 million.
East Texas. Our largest fields are located in the East Texas area. The
Rosewood, Glenwood, White Oak, Beckville, Carthage, East Henderson and Oak Hill
fields all produce from the Cotton Valley sand formation and have numerous
proved undeveloped drilling locations. 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. At December
31, 2002 we have identified 128 proved undeveloped locations in this area. For
2003, we have budgeted approximately $16.6 million for drilling of development
wells and exploitation activities in this area.
Gulf Coast. We have established a substantial base of proved reserves and
undeveloped acreage with significant exploration potential along the Gulf Coast
of Texas and Louisiana. We have generated multiple drilling projects in several
areas of South Louisiana, the most significant of those being in the state
waters of Louisiana in Breton Sound/Main Pass/Chandeleur Sound, and the Garden
City field in St. Mary Parish, Louisiana. During 2002, we participated in six
exploratory wells in South Louisiana, of which five were gas discoveries. Four
of the discoveries were in the Breton Sound/Main Pass/Chandeleur Sound, and one
was located in Garden City. In 2003, we intend to drill a total of ten
exploratory wells, with six being located in Breton Sound/Main Pass/Chandeleur
Sound, two in Garden City, one in Queen Bess Island field in Jefferson Parish
and one in Black Bayou field in Cameron Parish. Other significant fields in
south Louisiana include Bay de Chene, East Roanoke and Riceville. For 2003, we
have budgeted approximately $38.6 million for drilling of development wells and
exploration activities in this area.
South Texas. In South Texas, we are active in three main areas: Stuart City
field in La Salle County, Segundo/Owen field in Webb County and Northeast
Thompsonville field in Jim Hogg County. In 2003, we have budgeted approximately
$7 million for development drilling in this area.
Other. We own interests in numerous fields in the Anadarko, Permian, San
Juan and Arkoma basins in Oklahoma, Texas and New Mexico. Our largest fields in
these areas are Puerto Chiquito and Basin in the San Juan basin, and West
Stigler in eastern Oklahoma. In 2003, we have budgeted approximately $750,000
for development drilling in these areas.
9
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, 2002, 2001, and
2000. The period end prices of oil and natural gas at December 31, 2002, 2001,
and 2000, used in the PV-10 calculation were $31.20, $19.84 and $25.31 per
barrel of oil and $4.79, $2.57 and $9.40 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, 2002, 2001, and 2000, are
based on reserve reports prepared by Ryder Scott Company for our properties.
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 16 of the notes to our December 31, 2002 consolidated financial statements.
December 31,
----------------------------
2002 2001 2000
-------- -------- ----------
Proved Reserves:
Natural gas (Mmcf)....................................... 259,026 231,266 237,693
Oil (MBbls)(1)........................................... 6,208 5,337 10,672
Natural gas equivalents (Mmcfe).......................... 296,274 263,288 301,725
Proved Developed Reserves:
Natural gas (Mmcf)....................................... 205,301 175,659 177,252
Oil (MBbls)(1)........................................... 5,546 4,705 9,895
Natural gas equivalents (Mmcfe).......................... 238,577 203,889 236,622
Proved Reserves:
Estimated future net cash flows before income taxes, (in
thousands)............................................. $947,670 $385,335 $1,996,831
PV-10 value, (in thousands).............................. $487,973 $212,349 $1,047,364
- --------
(1) Includes oil, condensate and plant product barrels.
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 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.
10
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.
Years Ended December 31,
-----------------------------
2002 2001 2000
------- ------- -------
Net Production Data:
Natural gas (Mmcf)............................................ 25,647 22,352 17,764
Oil (MBbls)................................................... 828 952 1,139
Natural gas equivalents (Mmcfe)............................... 30,615 28,065 24,598
Average Sale Prices (before effect of 3TEC's hedging activities):
Natural gas ($ per Mcf)....................................... $ 3.25 $ 4.15 $ 4.12
Oil ($ per Bbl)............................................... 23.01 23.95 26.99
Natural gas equivalents ($ per Mcfe).......................... 3.35 4.12 4.23
Average Sales Prices (after effect of 3TEC's hedging activities):
Natural gas ($ per Mcf)....................................... $ 3.25(1) $ 4.15(1) $ 4.12
Oil ($ per Bbl)............................................... 23.01 23.95 25.11
Natural gas equivalents ($ per Mce)........................... 3.35 4.12 4.20
Expenses: ($ per Mcfe)
Lease operations(2)........................................... $ 0.48 $ 0.57 $ 0.61
Production, severance and ad valorem taxes(2)................. $ 0.24 $ 0.27 $ 0.27
Gathering, transportation and other(2)........................ $ 0.11 $ 0.11 $ 0.06
General and administrative.................................... $ 0.30 $ 0.25 $ 0.25
Depreciation, depletion and amortization...................... $ 1.22 $ 1.10 $ 0.80
- --------
(1) 3TEC's natural gas derivative financial instruments were not designated as
hedges at the time the instruments were executed, and in accordance with
SFAS 133, were marked-to-market through earnings in each period.
(2) Represents production cost.
Development, Exploration and Acquisition Capital Expenditures
The following table presents information regarding our net costs incurred in
the purchase of properties and in exploration and development activities.
Years Ended December 31,
----------------------------
2002 2001 2000
------- -------- --------
(in thousands)
Acquisition............. $ 302 $ 84,326(2) $ 79,865
Exploration(1).......... 21,531 11,059 695
Development(3).......... 37,510 62,668 25,346
------- -------- --------
Total costs incurred. $59,343 $158,053 $105,906
======= ======== ========
- --------
(1) Exploration costs include geological and geophysical expenses, dry hole
expenses and other exploratory drilling expenditures.
(2) Excludes approximately $29 million of acquisition costs related to deferred
taxes recorded in connection with the Classic Acquisition.
(3) Development costs include expenditures of $14.0 million in 2002, $8.7
million in 2001 and $5.1 million in 2000 related to the development of
proved undeveloped reserves included in 3TEC's proved oil and gas reserves
at the beginning of each year.
11
Drilling Activity
The following table shows our drilling activity for the years ended December
31, 2002, 2001 and 2000. 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.
Year Ended December 31,
-----------------------------------
2002 2001 2000
----------- ----------- -----------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Exploration Wells:
Productive..... 5 2.67 4 2.52 -- --
Non-Productive. 2 1.02 5 1.93 -- --
-- ----- -- ----- -- -----
Total...... 7 3.69 9 4.45 -- --
== ===== == ===== == =====
Development Wells:
Productive..... 52 18.46 71 26.80 66 18.30
Non-Productive. 1 0.92 2 1.30 -- --
-- ----- -- ----- -- -----
Total...... 53 19.38 73 28.10 66 18.30
== ===== == ===== == =====
Productive Wells
The following table sets forth the number of productive natural gas and oil
wells in which we owned a working interest as of December 31, 2002.
Total
Productive
Wells
---------
Gross Net
----- ---
Natural Gas 885 395
Oil........ 114 52
--- ---
Total... 999 447
=== ===
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.
Additionally, the Company owns a royalty interest in 184 wells and an
overriding royalty interest in 876 wells. At December 31, 2002, we operated
approximately 321 wells.
Acreage Data
The following table presents information regarding our developed and
undeveloped leasehold acreage as of December 31, 2002. Developed acreage refers
to acreage within producing units and undeveloped acreage refers to acreage
that has not been placed in producing units.
Undeveloped
Developed Acreage Acreage Total
----------------- ------------- ---------------
Gross Net Gross Net Gross Net
------- ------- ------ ------ ------- -------
Texas.... 128,788 62,782 8,752 5,402 137,540 68,184
Louisiana 25,036 10,439 17,386 9,528 42,422 19,967
Oklahoma. 22,375 8,864 790 138 23,165 9,002
Other.... 84,472 49,514 1,307 776 85,779 50,290
------- ------- ------ ------ ------- -------
Total. 260,671 131,599 28,235 15,844 288,906 147,443
======= ======= ====== ====== ======= =======
12
Excluded from the acreage data are approximately 33,495 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. Additionally, the Company has lease options covering 28,427 gross
acres in the Bayou Carlin area of St. Mary Parish, Louisiana, which begin
expiring April, 2004.
Current Activities
As of March 7, 2003, 4 wells (1.4 net wells) were being drilled. Three wells
are in Texas and one is in Louisiana.
Item 3. Legal Proceedings
On October 7, 1994, J.B. Hanks Co., Inc. ("Hanks") filed litigation in the
21st Judicial District, Parish of Livingston, State of Louisiana against Shore
Oil Company ("Shore"), which merged with Middle Bay on June 30, 1997, seeking
specific performance of a July, 1994 Agreement of Purchase and Sale (the
"Agreement"). On the same date, Shore filed suit against Hanks in the 129th
Judicial District, County of Harris, State of Texas also seeking specific
performance of the Agreement. Hanks alleges that Shore failed to comply with
the Agreement inasmuch as Hanks contended that royalties on certain of the oil
and gas leases had not been properly paid. The petition alleges that at the
time of the contemplated transaction, Shore was in an overproduced position
with respect to the taking of gas on the allegedly affected oil and gas leases
and that instead of Shore paying royalties based on actual production,
royalties were paid based on entitlements. Despite having received no demand
from the particular lessors, Hanks claimed that Shore was in violation of the
oil and gas leases; an assertion that Shore denies. On November 15, 1994, the
parties entered into a standstill agreement, which dismissed both actions.
Nearly two (2) years after the dismissal, Hanks informed Shore that the royalty
problems alleged by Hanks had been cured by the passage of time and that Hanks
was therefore prepared to purchase the property in accordance with the
Agreement. Shore refused to comply. Both parties again filed suit. The
Louisiana litigation was removed to Federal District Court where the matter
will be decided. In October 2002, the parties attempted to mediate their
dispute. A settlement was not reached. The Company intends to vigorously pursue
the defense of this matter. In the opinion of management, the ultimate
resolution of this lawsuit will not have a material adverse effect on the
Company's financial position or results of operations.
Item 4. Submission of Matters to a Vote of Security Holders
None.
13
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 National Market under the
market symbol "TTEN."
The following table sets forth the high and low closing prices per share of
our common stock for the periods indicated on the Nasdaq National Market.
Period High Low
------ ------ ------
2002
First Quarter.. $19.00 $13.57
Second Quarter. $18.20 $14.34
Third Quarter.. $17.47 $12.73
Fourth Quarter. $15.33 $12.31
2001
First Quarter.. $18.63 $15.69
Second Quarter. $20.40 $14.88
Third Quarter.. $17.30 $12.27
Fourth Quarter. $15.10 $13.20
2000
First Quarter.. $11.44 $ 6.38
Second Quarter. $13.50 $ 7.00
Third Quarter.. $17.25 $ 9.63
Fourth Quarter. $19.13 $13.38
On March 18, 2003 the last reported sales price of our common stock on the
Nasdaq National Market was $15.76 per share.
On March 18, 2003 there were 863 holders of record of our common stock.
Our transfer agent is American Stock Transfer and Trust Company located at
59 Maiden Lane, New York, New York 10038. 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
$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 D Preferred Stock.
14
Item 6. Selected Financial Data
The following table sets forth the Company's summary consolidated and
combined historical financial information that has been derived from the
audited combined statements of income and cash flows for the Company's business
for each of the years ended December 31, 2002, 2001, 2000, 1999 and 1998 the
unaudited consolidated statements of income and cash flows for the Company for
the nine months ended. You should read this financial information in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations of the Company" and the Company's financial
statements and notes thereto.
Years Ended December 31, (1)
------------------------------------------------------
2002 2001 2000 1999 1998
-------- --------- -------- -------- --------
(Amounts in thousands, except per share data) (audited)
Statement of Income Data:
Revenues
Oil, gas and plant income........................ $103,064 $ 116,080 $102,148 $ 20,088 $ 15,011
Gain (loss) on sale of properties................ (159) 815 800 1,048 1,953
Gain (loss) on derivative fair value............. (6,632) 3,081 -- -- --
Gain (loss) on derivative settlements............ (5,644) 162 -- -- --
Other............................................ 473 836 813 1,020 738
-------- --------- -------- -------- --------
Total revenues............................... 91,102 120,974 103,761 22,156 17,702
Costs and Expenses:
Production expenses.............................. 25,326 26,670 23,179 7,788 7,801
Geological and geophysical....................... 2,683 1,172 666 473 878
Dryhole and Impairments.......................... 8,918 12,261 29 3,103 4,668
Surrendered and expired acreage.................. 860 7,875 -- -- --
Stock compensation (general and
administrative)................................ 816 -- -- 730 266
Interest......................................... 3,962 6,773 7,556 3,205 1,972
Severance payments............................... -- -- -- 624 --
Compensation plan payments....................... -- -- -- 293 --
General and administrative....................... 9,154 6,991 6,141 4,122 4,266
Depreciation, depletion and amortization......... 37,357 30,983 19,779 6,691 7,116
Other............................................ 629 250 -- -- 139
-------- --------- -------- -------- --------
Total Expenses............................... 89,705 92,975 57,350 27,029 27,106
-------- --------- -------- -------- --------
Income (loss) before income taxes, minority interest
and dividends to preferred stockholders........... 1,397 27,999 46,411 (4,873) (9,404)
Minority interest................................... -- 511 305 (2) 15
Income tax (benefit) expense........................ 45 10,640 14,442 (1,443) (2,830)
-------- --------- -------- -------- --------
Net income (loss)................................... $ 1,352 $ 16,848 $ 31,664 $ (3,432) $ (6,589)
Dividends to preferred stockholders................. 738 710 1,488 574 68
-------- --------- -------- -------- --------
Net income (loss) attributable to common shares..... $ 614 $ 16,138 $ 30,176 $ (4,006) $ (6,657)
======== ========= ======== ======== ========
Basic net income (loss) per common share............ $ 0.04 $ 1.06 $ 2.91 $ (1.14) $ (2.48)
======== ========= ======== ======== ========
Diluted net income (loss) per common share.......... $ 0.03 $ 0.91 $ 2.28 $ (1.14) $ (2.48)
======== ========= ======== ======== ========
Weighted averaged common shares outstanding:
Basic............................................ 16,533 15,170 10,383 3,520 2,683
======== ========= ======== ======== ========
Diluted.......................................... 18,362 18,969 13,895 3,520 2,683
======== ========= ======== ======== ========
Other Financial Data:
Net cash provided by operating activities........... 49,802 89,780 44,468 1,401 2,068
Net cash used in investing activities............... (55,868) (122,519) (83,771) (80,372) (16,958)
Net cash provided by (used in) financing activities. (9,447) 46,065 37,598 84,072 14,343
Oil and gas capital expenditures.................... 59,343 158,053 105,906 94,402 34,058
15
Year Ended December 31,
-------------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- -------
(Amounts in thousands, except per share data) (audited)
Balance Sheet Data:
Cash and cash equivalents $ 2,249 $ 17,762 $ 4,436 $ 6,141 $ 1,040
Working capital (deficit) (1,637) 14,343 15,242 7,001 139
Total assets............. 349,185 363,038 254,764 149,243 57,941
Total debt............... 99,000 108,000 76,224 100,724 27,455
Stockholders' equity..... 182,964 180,712 149,595 38,112 22,558
- --------
(1) Certain reclassifications of prior period amounts have been made to conform
to the current presentation.
Item 7. 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 "Cautionary Statement About 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. As of December 31, 2002, we had estimated total net proved reserves
of 296 Bcfe, of which approximately 259 Bcfe, or 87%, were natural gas and
approximately 239 Bcfe, or 81%, were proved developed, with an estimated SEC
case PV-10 value of $488 million. For the fourth quarter of 2002, our average
net daily production rate was 86 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.
Description Of Critical Accounting Policies
Oil and Natural Gas Properties. We utilize the successful efforts method of
accounting for our oil and natural gas properties. Under this method, all
development and acquisition costs of proved properties are capitalized and
amortized on a unit-of-production basis over the remaining life of proved
developed reserves or proved reserves, as applicable. Exploration expenses,
including geological and geophysical expenses and delay rentals, are charged to
expense as incurred. Costs of drilling exploratory wells are initially
capitalized, but charged to expense if and when the well is determined to be
unsuccessful. Expenditures for repairs and maintenance to sustain or increase
production from the existing producing reservoir are charged to expense as
incurred. Expenditures to recomplete a current well in a different or
additional proven or unproven reservoir are capitalized pending determination
that economic reserves have been added. If the recompletion to an unproven
reservoir is not successful, the expenditures are charged to expense.
Expenditures for redrilling or directional drilling in a previously abandoned
well are classified as drilling costs to a proven or unproven reservoir for
determination of capital or expense. Significant tangible equipment added or
replaced is capitalized. Expenditures to construct facilities or increase the
productive capacity from existing reserves are capitalized. Internal costs
directly associated with the development and exploitation of properties are
capitalized as a cost of the property and are classified accordingly in the
Company's financial statements. Crude oil volumes are converted to equivalent
Mcf's at the rate of one barrel to six Mcf.
16
The Company is required to assess the need for an impairment of capitalized
costs of oil and natural gas properties and other long-lived assets whenever
events or circumstances indicate that the carrying value of those assets may
not be recoverable. If impairment is indicated based on a comparison of the
asset's carrying value to its undiscounted expected future net cash flows, then
it is recognized to the extent that the carrying value exceeds fair value. Any
impairment charge incurred is recorded in accumulated depletion, depreciation,
and amortization ("DD&A") to reduce our recorded basis in the asset. Each part
of this calculation is subject to a large degree of management judgment,
including the determination of the property's reserves, future cash flows, and
fair value.
Management's assumptions used in calculating oil and natural gas reserves or
regarding the future cash flows or fair value of our properties are subject to
change in the future. Any change could cause impairment expense to be recorded,
reducing our net income and our basis in the related asset. Future prices
received for production and future production costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of calculating
reserve estimates. With consideration of anticipated future commodity prices
and field operation costs, all proved undeveloped reserves included in the
Company's year-end reserve report have been scheduled for execution and
included in the development plan and capital expenditure budget estimate by the
Company for each respective year. Actual production may not equal the estimated
amounts used in the preparation of reserve projections. As these estimates
change, the amount of calculated reserves change. Any change in reserves
directly impacts our estimate of future cash flows from the property, as well
as the property's fair value. Additionally, as management's views related to
future prices change, this changes the calculation of future net cash flows and
also affects fair value estimates. Changes in either of these amounts will
directly impact the calculation of impairment.
DD&A expense is also directly affected by the Company's reserve estimates.
Any change in reserves directly impacts the amount of DD&A expense the Company
recognizes in a given period. Assuming no other changes, such as an increase in
depreciable base, as the Company's reserves increase, the amount of DD&A
expense in a given period decreases and vice versa. Changes in future commodity
prices would likely result in increases or decreases in estimated recoverable
reserves.
The Company also uses estimates to record its accrual for oil and natural
gas revenues. The production estimate portion of the accrual of revenue for a
given period is based upon field production reports (both operated and
non-operated), estimates of production added via drilling or acquisitions,
historical production averages and natural production declines of the Company's
properties. The price component of the Company's accrual for revenue
incorporates historical averages of the Company's sales for periods being
accrued as compared to the monthly closing NYMEX price for natural gas and the
West Texas Intermediate index price for crude oil.
Several factors can impact the Company's ability to estimate its production
volume including the fact that a significant portion of the Company's
production is operated by third parties. The Company's working interests, which
are operated by third parties, are governed by joint operating agreements with
the third party operators and contain customary industry standard terms and
conditions. Wagner & Brown, Ltd. is the Company's largest single third party
operator, operating approximately 15% of the Company's total produced oil and
gas volumes on a monthly basis. No other third party operator operates
interests that generate greater than 5% of the Company's monthly production.
Reliance on accurate and timely data from the operators of these properties can
change the actual amounts of production for which the Company receives payment.
Additionally, production meters that are manually read can be different than
the volume metered at the Company's sales points.
Both the Company's estimate of sold volumes and the estimate of the price
received for these sales is adjusted on an on-going basis as the Company
receives payment for accrued volumes. Changes in the estimates of the accrual
are adjusted in subsequent periods as payment is received or additional
supporting data is obtained.
Bad Debt Expense. The Company routinely assesses the recoverability of all
material trade and other receivables to determine their collectibility. The
Company historically has not required collateral or other
17
performance guarantees from creditworthy counterparties. Many of our
receivables are from joint interest owners on property of which we are the
operator. Thus, we may have the ability to withhold future revenue
disbursements to cover any non-payment of joint interest billings. Our oil and
natural gas receivables quickly turnover, usually one month for oil and two
months for gas; thus, signaling any problem accounts in a timely manner.
Counterparties to our derivative commodity contracts are routinely reviewed for
creditworthiness to determine the realizability of any related derivative
assets we might carry on our books. This review of receivables and
counterparties is heavily dependent on the judgment of management. If it is
determined that the carrying value of a receivable or financial instrument
might not be recoverable, we record an allowance to the extent we believe the
receivable or asset is not recoverable. The determination as to what extent a
receivable or asset might be impaired is also heavily dependent on the judgment
of management. As more information becomes known related to a particular
counterparty or customer, management will continually reassess previous
judgments and any resulting change in the related allowance could have a
material positive or negative effect on our financial position and results of
operations in the period of the change.
Derivative Activities. We use various financial instruments in the normal
course of our business to manage and reduce price volatility and other market
risks associated with our crude oil and natural gas production. This activity
is referred to as risk management. These arrangements are structured to reduce
our exposure to commodity price decreases, but they can also limit the benefit
we might otherwise receive from commodity price increases. Our risk management
activity is generally accomplished through over-the-counter forward derivative
contracts executed with large financial institutions.
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities". This standard requires us to recognize all
of our derivative and hedging instruments in our consolidated balance sheets as
either assets or liabilities and measure them at fair value. If a derivative
does not qualify for hedge accounting, it must be adjusted to fair value
through earnings. However, if a derivative does qualify for hedge accounting,
depending on the nature of the hedge, changes in fair value can be offset
against the change in fair value of the hedged item through earnings or
recognized in other comprehensive income until such time as the hedged item is
recognized in earnings.
To qualify for cash flow hedge accounting, the cash flows from the hedging
instrument must be highly effective in offsetting changes in cash flows due to
changes in the underlying items being hedged. In addition, all hedging
relationships must be designated, documented, and reassessed periodically. The
Company's natural gas derivative financial instruments were not designated as
hedges at the time the instruments were executed. According to the provisions
of SFAS 133, these instruments are marked-to-market through earnings each
period.
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 are sales of natural gas
and oil.
For 2002 and 2001, the Company's development, exploitation and exploratory
drilling related capital expenditures, exclusive of acquisitions, were
approximately $43.3 million and $67.8 million, respectively. For the year 2003,
we have budgeted approximately $63 million for capital expenditures. The 2003
capital expenditure plan is comprised of developmental, exploitation and
exploratory activities by area as follows: East Texas, $16.6 million
(developmental drilling), Gulf Coast, $38.6 million (primarily exploration and
exploitation drilling), South Texas, $7.0 million (both developmental and
exploitation drilling) and all other areas of non-core activities of $0.8
million. We are obligated to pay dividends of approximately $740,000 per year
on the Series D
18
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. The
Company paid the 2002 dividends and anticipates paying the 2003 Series D
dividends in cash, financed through operating cash flow and if required, bank
borrowings.
Our activities in 2002 have been financed through operating cash flow and
bank borrowings. Our primary source of financing for acquisitions has been
borrowing under our Credit Facility described below.
Credit Facility. The Company has in place a $250 million credit facility
(the "Credit Facility") with Bank One, NA as agent and seven other banks. The
Credit Facility, as amended, matures August 31, 2004. As of March 18, 2003, the
Company's borrowing base under its Credit Facility was $160 million. The
borrowing base is to be redetermined semi-annually on May 1 and November 1 and
provides for interest as revised under the Credit Facility to accrue at a rate
calculated at the Company's option as either the bank's prime rate plus a low
of zero to a high of 37.5 basis points or LIBOR plus basis points increasing
from a low of 150 to a high of 200 as loans outstanding increase as a
percentage of the borrowing base. As of December 31, 2002, the Company was
paying an average of 2.99% per annum interest on the principal balance of $99
million under the Credit Facility. Prior to maturity, no payments of principal
are required so long as the borrowing base exceeds the loan balance. The
borrowings under the Credit Facility are secured by substantially all of the
Company's oil and natural gas properties. At December 31, 2002, the amount
available to be borrowed under the Credit Facility was approximately $61
million. At February 28, 2003, borrowings under the Credit Facility totaled $99
million.
In connection with the 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. As of
December 31, 2002, we were in compliance with the covenants contained in the
Credit Facility and we expect to be in compliance for 2003.
The following table illustrates the Company's contractual obligations
outstanding at December 31, 2002:
Payments Due By Period
------------------------------------
Contractual Obligations Total 2003 2004-2005 2006-2007 Thereafter
----------------------- ------- ----- --------- --------- ----------
(in thousands)
Long-term debt...... 99,000 -- 99,000 -- --
Operating leases.... 6,043 1,256 2,170 1,696 921
------- ----- ------- ----- ---
Totals........... 105,043 1,256 101,170 1,696 921
======= ===== ======= ===== ===
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.
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. We use various financial instruments in the course of our business to
manage and reduce price volatility risks. During 2002, we received an average
of $23.01 per barrel of crude oil and $3.25 per Mcf of gas. Additionally costs
and expenses are affected by inflationary pressures, which could have a
significant impact on the costs necessary to operate our business.
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
19
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.
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, 2002, 2001 and 2000.
2002 Compared With 2001
Revenue. Total revenue for the year ended December 31, 2002 was $91.1
million, a decrease of $29.9 million (25%) over total revenue for 2001 of
$121.0 million. Oil, natural gas and plant income revenues for the 2002 period
were $103.1 million compared to $116.1 million in 2001, a decrease of $13.0
million (11%). Realized prices for the Company's production were $3.35/Mcfe in
2002 compared to $4.12/Mcfe in 2001, while production volumes increased to
30,615 Mmcfe in 2002 compared to 28,065 Mmcfe in 2001. The Company believes
that lower natural gas prices in 2002 were a result of several dynamics.
Natural gas prices for the year were 22% lower than the prior year as
diminished economic conditions slowed industrial and commercial demand. Both
historically high levels of working gas in storage and stable wellhead
production further impacted price discovery for natural gas. These supply and
demand factors combined to create a less favorable price for North American
natural gas and geopolitical events continued to influence world oil prices,
which in turn effect natural gas prices.
Gain/(Loss) on Sale of Properties and Other Revenue. In 2002 vs. 2001,
gains (losses) on property divestments were a loss of $0.2 million and a gain
of $0.8 million, respectively, which is a direct result of minimal divestiture
activity in 2002 versus significant efforts to divest non-strategic oil and gas
properties in 2001. Other revenues in 2002 were $0.5 million compared to $0.8
million in 2001. Other revenue consists primarily of interest, delay rental and
lease bonus income.
Gain/(Loss) on Derivative Fair Value. During the fourth quarter of 2001,
the Company entered into certain derivative transactions that were not
designated as hedges and therefore are required under generally accepted
accounting principals to be "marked-to-market." At December 31, 2002, these
contracts had a fair value liability of $3.6 million, which resulted in a loss
of $6.6 million in 2002. See further discussion in Note 12 of the Company's
Notes to Consolidated Financial Statements.
Expenses. Total expenses for the year ended December 31, 2002 were $89.7
million, a decrease of $3.3 million (4%) from total expenses in 2001 of $93.0
million. Comparability of total expenses was impacted by the decrease in dry
hole and impairment expenses, surrendered and expired acreage and the increase
in depreciation, depletion and amortization. On a per Mcfe basis, the Company's
lease operating expenses decreased by 16% to $0.48 in 2002 from $0.57 in 2001.
Production, severance and ad valorem tax decreased 11% to $0.24/Mcfe in 2002
from $0.27/Mcfe in 2001. Gathering, transportation and other expenses were
$0.11/Mcfe for both 2002 and 2001. General and administrative expense was
$0.30/Mcfe in 2002 compared to $0.25/Mcfe in 2001, interest expense $0.13/Mcfe
vs. $0.24/Mcfe in 2001, and DD&A $1.22/Mcfe in 2002 compared to $1.10/Mcfe in
2001.
Lease operating expenses on a unit basis continued to benefit from the
Company's Classic Acquisition and 2001 divestiture program. The properties in
the Classic Acquisition were natural gas wells with lower lease operating costs
as compared to the divested properties that had higher lease operating costs
which were primarily oil producers.
Production, severance and ad valorem taxes were decreased year over year as
expected with average sales prices on an mcfe basis being $3.35/Mcfe in 2002
vs. $4.12/Mcfe in 2001.
General and administrative expenses were higher year over year as staffing
needs increased as a result of the Company's significant growth.
The increase on a per unit basis to depreciation, depletion and amortization
("DD&A") is attributed to (i) the Company's developmental drilling activity,
which thereby increases the depletable property base and (ii) the increase in
South Louisiana volumes, which carry a higher DD&A rate.
20
Income Taxes. The Company recorded a $0.1 million income tax provision
during 2002 as compared to a $10.6 million income tax provision for 2001. The
results from the Company's operations generated pre-tax income of $1.4 million
during 2002 vs. a pre-tax income of $28.0 million in 2001. During 2002, the
Company's effective tax rate was approximately 3%.
Net Income. The Company's 2002 net income of $1.4 million is compared to
$16.8 million in 2001.
Dividends to Preferred Shareholders. Dividends to preferred shareholders of
$0.7 million in 2002 was comparable to $0.7 million in 2001.
2001 Compared With 2000
Revenue. Total revenue for the year ended December 31, 2001 was $121.0
million, an increase of $17.2 million (17%) over total revenue for 2000 of
$103.8 million. Oil, natural gas and plant income revenues for the 2001 period
were $116.1 million compared to $102.1 million in 2000, an increase of $14.0
million (14%). Realized prices for the Company's production was $4.12/Mcfe in
2001 compared to $4.23/Mcfe in 2000, while production volumes increased to
28,065 Mmcfe in 2001 compared to 24,598 Mmcfe in 2000. Realized price increases
for 2001 and 2000 were reflective of the continued strong commodity price
environment in the industry. Comparability of the Company's revenues and
volumes were both driven by a significant drilling program in 2001 and 2000 and
the acquisitions of Magellan Properties in February 2000, the CWR Properties in
May 2000 and the Classic Properties in January 2001, offset by the 2001
property divestments which were all significant contributors to the year over
year increases. See further discussion in Note 2 of the Company's Notes to
Consolidated Financial Statements.
Gain on Sale of Properties and Other Revenue. In 2001 vs. 2000, property
divestments resulted in the recognition of gains of $0.8 million and $0.8
million, respectively. The Company continues to actively review and manage its
property portfolio for divestiture of non-strategic properties. Other revenues
in 2001 were $0.8 million compared to $0.8 million in 2000. Other revenue
consists primarily of interest, delay rental and lease bonus income.
Gain on Derivative Fair Value. During the fourth quarter of 2001, the
Company entered into certain derivative transactions that were not designated
as hedges and therefore are required under generally accepted accounting
principals to be "marked-to-market." At December 31, 2001, these contracts had
a fair market value of $3.1 million. See further discussion in Note 12 of the
Company's Notes to Consolidated Financial Statements.
Expenses. Total expenses for the year ended December 31, 2001 were $93.0
million, an increase of $35.6 million (62%) from total expenses in 2000 of
$57.4 million. Comparability of total expenses was impacted by the increase in
dry hole and impairment expenses, surrendered and expired acreage and the
increase in depreciation, depletion and amortization. On a per Mcfe basis, the
Company's lease operating expenses decreased by 7% to $0.57 in 2001 from $0.61
in 2000. Production, severance and ad valorem tax was flat at $0.27/Mcfe in
2001 vs. $0.27/Mcfe in 2000. General and administrative expense was $0.25/Mcfe
in 2001 compared to $0.25/Mcfe in 2000, interest expense $0.24/Mcfe vs.
$0.31/Mcfe in 2000, and DD&A $1.10/Mcfe in 2001 compared to $0.80/Mcfe in 2000.
Lease operating expenses on a unit basis were impacted by the Company's Classic
Acquisition and 2001 divestiture program. The properties in the Classic
Acquisition were natural gas wells with lower lease operating costs as compared
to the divested properties that had higher lease operating costs which were
primarily oil producers.
Production, severance and ad valorem taxes were comparable year over year as
expected with average sales prices on an Mcfe basis being $4.12/Mcfe in 2001
vs. $4.23/Mcfe in 2000.
The increase on a per unit basis to depreciation, depletion and amortization
("DD&A") is attributed to the Classic Acquisition and the Company's
developmental drilling program. At the time the Company acquired the
21
stock of Classic Resources, Inc., the historical tax basis of the Classic
Acquisition properties were carried over to the Company's books. A
corresponding deferred tax liability was recorded in the Company's purchase
price allocation for the difference between the allocated value and the
historical tax basis. This "gross-up" to record the deferred tax liability,
resulted in approximately $29.0 million being added to the depletable book
basis of the Classic Acquisition properties. The Company's development drilling
activities during 2001 also contributed to the increase in the Company's DD&A
rate in 2001 due to a majority of the proved undeveloped reserves associated
with these capitalized costs associated having been already included the
Company's December 31, 2000 reserve report estimate. Thus, additional costs
were added to a relatively static reserve figure, thereby increasing the per
unit rate.
Income Taxes. The Company recorded a $10.6 million income tax provision
during 2001 as compared to a $14.4 million income tax provision for 2000. The
results from the Company's operations generated pre-tax income of $28.0 million
during 2001 vs. a pre-tax income of $46.4 million in 2000. During 2001, the
Company's effective tax rate was approximately 38%.
Net Income. The Company's 2001 net income of $16.8 million is compared to
$31.7 million in 2000.
Dividends to Preferred Shareholders. Dividends to preferred shareholders of
$0.7 million in 2001 is a $0.8 million decrease (53%) over 2000 dividends of
$1.5 million. The Company redeemed its Series C preferred stock in September,
2000 and recognized a non-cash charge to dividend expense of $0.5 million in
2000.
Factors that may Affect Financial Condition and Future Results
The Company's business and stock price may be adversely affected if the
merger with Plains Exploration & Production Company ("Plains") is not
completed. On February 2, 2003, the Company entered into a definitive agreement
with Plains whereby Plains will acquire the Company for a combination of cash
and stock. If the acquisition is not completed, the Company could be subject to
a number of risks that may adversely affect its business and stock price,
including the following:
. The Company would not realize the benefits it expects by being part of a
combined company with Plains, as well as the potentially enhanced
financial and competitive position as a result of being part of the
combined company.
. The diversion of management attention from The Company's day-to-day
business and the unavoidable disruption to its employees and business
partners as a result of efforts and uncertainties relating to the
Company's anticipated merger with Plains may detract from its ability to
grow revenues and minimize costs, which, in turn may lead to a loss of
opportunities that the Company could be unable to regain if the merger
does not occur.
. The Company's ability to borrow in certain capital markets may be
hindered, resulting in increased borrowing costs, more restrictive
covenants and the extension of less open credit; the market price of
shares of the Company's common stock may decline to the extent that the
current market price of those shares reflects a market assumption that
the merger will be completed.
. Under certain circumstances the Company could be required to pay Plains a
$9.0 million termination fee plus Plains' expenses up to $1.0 million;
the Company must pay its costs related to the merger, such as legal and
accounting fees and a portion of the investment banking fees.
. The Company may not be able to continue its present level of operations,
may need to scale back its business, may have to consider additional
reductions in force, may have to consider alternative sources of funding
and may not be able to take advantage of future opportunities or
effectively respond to competitive pressures, any of which could have a
material adverse effect on its business and results of operations.
22
In connection with the proposed merger, The Company and Plains have filed a
preliminary joint proxy statement/prospectus with the SEC. Once the joint proxy
statement/prospectus has been declared effective by the SEC, such definitive
joint proxy statement/prospectus will be mailed to all holders of the Company
stock and will contain important information about the Company, Plains and the
proposed merger, risks relating to the merger and the combined company, and
related matters. The Company urges all of its stockholders to read the
definitive joint proxy statement/prospectus when it becomes available.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
The Company is exposed to changes in interest rates. Changes in interest
rates affect the interest earned on cash, cash equivalents and short-term
investments and the interest rate paid on borrowings under the Credit Facility.
The Company does not currently use interest rate derivative instruments to
manage exposure to interest rate changes, but may do so in the future.
Commodity Price Risk
The Company's revenues, profitability and future growth depend substantially
on prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and the Company's ability to
borrow and raise additional capital. Lower prices may also reduce the amount of
natural gas and oil production under fixed or floating market price contracts.
The Company enters into commodity derivative arrangements from time to time to
reduce its exposure to fluctuations in natural gas and oil prices and to
achieve more predictable cash flow. However, these contracts also limit the
benefits the Company would realize if prices increase. These financial
arrangements take the form of swap contracts or costless collars and are placed
with major trading counterparties the Company believes represent minimum credit
risks. The Company cannot provide assurance that these trading counterparties
will not become credit risks in the future. Under its current derivative
practice, the Company generally does not hedge more than 75 percent of its
estimated twelve-month production quantities.
The Company enters into New York Mercantile Exchange ("NYMEX") related swap
contracts and collar arrangements from time to time. The Company's swap
contracts will settle based on the reported settlement price on the NYMEX for
the last three trading days of each month for natural gas. In a swap
transaction, the counterparty is required to make a payment to the Company for
the difference between the fixed price and the settlement price if the
settlement price is above the fixed price. As of March 18, 2003, the Company's
commodity price risk management positions in fixed price natural gas and crude
oil swap, put and call contracts were as follows:
Natural Gas Hedges (Mmbtu/d)
2003
Swaps--$5.02/Mmbtu (April - December)................ 50,000
2004
Swaps--$4.45/Mmbtu (January - December).............. 20,000
Collar--$4.00 x $5.15/Mmbtu (January - December)..... 20,000
Crude Oil Hedges (Bbls/d)
2003
Swaps--$29.62/Bbl (April - December)................. 1,000
2004
Swaps--$24.94/Bbl (January - December)............... 1,000
Based upon the fair value of the Company's derivative contracts outstanding
at December 31, 2002, we reported a net current liability on that date of $3.5
million. The Company did not elect to classify these derivative contracts as
hedges and therefore is required to mark the contracts to market at the end of
each period and
23
recognize the resulting gain or loss through current period earnings. In
connection with the derivative contracts outstanding during 2002 and 2001, the
Company recognized derivative settlement gains (losses) in revenues of $(5.6)
million and $0.2 million, respectively. Through March 18, 2003, the Company had
paid net cash settlements of approximately $14.9 million related to 2003 closed
contract months (January 2003 - March 2003). The $14.9 million net cash paid
for settlements will be recognized in the 2003 statement of operations as a
loss on derivative settlements. As of March 18, 2003, the Company only has
contracts from April 2003 forward open, which have a fair value liability of
$5.4 million. A 10% increase to the March 18, 2003 NYMEX prices would result in
settlements of the open contract months (April 2003 through December 2004) for
the Company's derivatives to increase by $12.7 million, while a 10% decrease in
such prices would result in a $13.4 million decrease to these contract
settlements versus the March 18, 2003 mark-to-market loss. Although these
derivatives were not designated by the Company as hedges for accounting
purposes, the economic volatility of these positions is substantially offset by
the physical prices being received for its production.
Item 8. Financial Statements and Supplementary Data
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 15 of this report.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
24
PART III
Item 10. Directors and Executive Officers of the Registrant; Compliance with
Section 16(a) of the Exchange Act
DIRECTORS AND EXECUTIVE OFFICERS
Name Age Position(s) Held Since
---- --- ----------------------------------------------- -----
Floyd C. Wilson....... 56 Chairman, Chief Executive Officer and Director 1999
R. A. Walker.......... 46 President, Chief Financial Officer and Director 2000
Stephen W. Herod...... 44 Executive Vice President--Corporate Development 1997
and Assistant Secretary
Shane M. Bayless...... 36 Vice President, Controller and Treasurer 2000
Richard K. Stoneburner 49 Vice President--Exploration 1999
Mark S. Holt.......... 47 Vice President--Land and Assistant Secretary 1999
C.E. Hackstedt........ 53 Vice President--Engineering and Operations 2000
David S. Elkouri...... 49 Secretary 2000
David B. Miller....... 53 Director 1999
D. Martin Phillips.... 49 Director 1999
Larry L. Helm......... 55 Director 2000
Larry J. Bump......... 63 Director 2002
James L. Irish III.... 58 Director 2002
- --------
FLOYD C. WILSON, Chairman and Chief Executive Officer, joined the Company on
August 27, 1999, concurrent with the investment in the Company by W/E Energy
Company L.L.C., formerly known as 3TEC Energy Company L.L.C. ("W/E"). Mr.
Wilson has been a director of 3TEC since 1999. Mr. Wilson founded W/E in 1998.
Mr. Wilson began his career in the energy business in Houston in 1970 as a
completion engineer. He moved to Wichita in 1976 to start an oil and gas
operating company, one of several private energy ventures which preceded the
formation of W/E. Mr. Wilson founded Hugoton Energy Corporation ("Hugoton") in
1987, and served as its Chairman, President and Chief Executive Officer. In
1994, Hugoton completed an initial public offering and was merged into
Chesapeake Energy Corporation in 1998.
R.A. WALKER, President and Chief Financial Officer, joined 3TEC effective
May 1, 2000. Mr. Walker has been a director of 3TEC since 2000. Prior to this
he was a Senior Managing Director and Co-head of Prudential Capital Group, a
$32 billion asset management and merchant banking affiliate of The Prudential
Insurance Company of America investing in privately-placed debt and equity
securities. From 1990 to 1998, Mr. Walker was the Managing Director of the
Dallas office of Prudential Capital Group where he was responsible for the
firm's global energy investments, as well as general corporate finance for the
Southwestern United States. He joined Prudential in 1987, holding various
responsibilities in its Boston, Dallas and Newark offices, after spending
approximately six years in commercial banking and two years with an independent
oil and gas company.
STEPHEN W. HEROD has served as the Company's Executive Vice
President-Corporate Development since December 1999 and as Assistant Secretary
since May 2001. Mr. Herod served as a director of the Company from July 1997
until January 2002. Mr. Herod served as the Treasurer of the Company from 1999
until 2001. From July 1997 to December 1999, Mr. Herod was Vice
President-Corporate Development. Mr. Herod served as President and a director
of Shore Oil Company ("Shore") from April 1992 until the merger of Shore with
the Company on June 30, 1997. He joined Shore's predecessor as Controller in
February 1991. Mr. Herod was employed by Conquest Exploration Company from 1984
until 1991 in various financial management positions, including Operations
Accounting Manager. From 1981 to 1984, Superior Oil Company employed Mr. Herod
as a financial analyst.
25
SHANE M. BAYLESS joined the Company in July 2000 as Vice President and
Controller. Mr. Bayless has served as the Treasurer of the Company since March
2001. Prior to joining 3TEC, Mr. Bayless was employed by Encore Acquisition
Company as Vice President and Controller from 1998 to 2000. Mr. Bayless worked
as the Controller from 1996 to 1998 and as the Accounting Manager from 1993 to
1996 at Hugoton. From 1990 to 1993, Mr. Bayless was an Audit Senior with Ernst
& Young LLP. He is a Certified Public Accountant.
RICHARD K. STONEBURNER joined the Company in August 1999 and became Vice
President--Exploration in December 1999. Mr. Stoneburner was employed by W/E as
District Geologist from 1998 to 1999. Prior to joining 3TEC, Mr. Stoneburner
worked as a geologist for Texas Oil & Gas, The Reach Group, Weber Energy
Corporation, Hugoton and, independently through his own company, Stoneburner
Exploration, Inc. Mr. Stoneburner has over 20 years of experience in the energy
field.
MARK S. HOLT joined the Company in August 1999 and became Assistant
Secretary in November 1999 and Vice President--Land in December 1999. W/E
employed Mr. Holt as District Landman from 1998 to 1999. From 1985 to 1998, Mr.
Holt was the owner of Holt Resources, which provided land consulting services
to various oil and gas companies and operators. From 1979 to 1985, Mr. Holt was
a Senior Landman for Sun Oil Company.
C.E. HACKSTEDT joined the Company in December 2000 and became Vice
President--Engineering and Operations in March 2001. Prior to joining 3TEC, Mr.
Hackstedt was Vice President of Engineering and Operations for Panther
Resources Corporation from 1999 to 2000. Mr. Hackstedt was the Vice President
of Operations, Gulf Coast Division from 1995 to 1998 and Vice President of
Operations from 1992 to 1995 for UMC Petroleum Corporation.
DAVID S. ELKOURI became Secretary of the Company in May 2000. Mr. Elkouri is
a founding member of the Wichita, Kansas law firm, Hinkle Elkouri Law Firm
L.L.C., which was established in 1986. Mr. Elkouri is currently the firm's
Co-Managing Director and the Chairman of its Corporate Department. Prior to
establishing Hinkle Elkouri Law Firm L.L.C., Mr. Elkouri was a partner in the
Wichita law firm of Regan & McGannon and an associate in the San Diego,
California law firm of Gray Cary Wave & Freidenrich LLP. He is currently a
member of the Board of Directors of Rand Graphics, Inc. and served as a
director of Hugoton from 1993 until 1998. He has served an Adjunct Professor of
Law at the University of Kansas School of Law teaching business planning.
DAVID B. MILLER has served as a director of the Company since 1999 and is a
member of our Compensation Committee. Mr. Miller is a Managing Director and
co-founder of EnCap. EnCap is an investment management and merchant banking
firm focused on the upstream and midstream sectors of the oil and gas industry
that was founded in 1988. From 1988 to 1996, Mr. Miller also served as
President of PMC Reserve Acquisition Company, a partnership jointly owned by
EnCap and Pitts Energy Group. Prior to the establishment of EnCap, Mr. Miller
served as Co-Chief Executive Officer of MAZE Exploration Inc., a Denver,
Colorado, based oil and gas company he co-founded in 1981. Mr. Miller is also a
director of Denbury Resources Inc.
D. MARTIN PHILLIPS has served as a director of the Company since 1999. Mr.
Phillips is a member of our Compensation Committee and chairman of our
Nominating Committee. Mr. Phillips is a Managing Director and principal of
EnCap. EnCap is an investment management and merchant banking firm focused on
the upstream and midstream sectors of the oil and gas industry that was founded
in 1988. Prior to joining EnCap in 1989, from 1978 to 1989, Mr. Phillips served
in various management capacities with NCNB Texas National Bank, including as
Senior Vice President in the Energy Banking Group. Mr. Phillips is also a
director of Mission Resources Corporation and Plains Resources, Inc.
LARRY L. HELM has served as a director of the Company since 2000 and is
chairman of our Compensation Committee. Mr. Helm is also a member of our Audit
Committee. Mr. Helm is responsible for the nationwide Middle Market Banking
Group of Bank One Corporation, a position he assumed in 2001. Mr. Helm joined
Bank One, NA in 1989 and has held increasingly more responsible positions with
Bank One, NA,
26
including, most recently, head of Energy & Utilities Banking. Mr. Helm is a
former director of the Independent Petroleum Association of America.
LARRY J. BUMP has served as a director of the Company since 2002 and is a
member of our Audit and Nominating Committees. Mr. Bump has served as Chairman
of the Board of Willbros Group, Inc., an international engineering and
construction company, since 1980.
JAMES L. IRISH III has served as a director of the Company since 2002 and is
chairman of our Audit Committee and a member of our Nominating Committee. Mr.
Irish is currently of counsel with Thompson & Knight, L.L.P., a Texas based law
firm. Mr. Irish has been an attorney with Thompson & Knight, L.L.P. serving in
various capacities, including Managing Partner, since 1969.
Section 16(a) Beneficial Ownership Reporting Compliance
For the period January 1, 2002, to December 31, 2002, Larry J. Bump and
David B. Miller each had one transaction that was not timely filed on a Form 4.
EnCap had two transactions that were not timely filed on a Form 4.
Item 11. Executive Compensation
Executive Compensation
Summary Compensation Table. The following table sets forth the aggregate
cash compensation earned by and paid to 3TEC's named executive officers for
fiscal years 2002, 2001, and 2000. All numbers are rounded to the nearest
dollar.
Annual Compensation
------------------------------------------------------------------
Long-Term
Awards Compensation
Restricted Securities Payouts
Stock Options/ Underlying All Other
Salary Bonus Awards SARs LTIP Compensation
Name and Principal Position Year ($) ($) ($)(2) (#) Payouts ($) ($)(1)
- --------------------------- ---- ------- ------- ---------- -------- ----------- ------------
Floyd C. Wilson..................... 2002 400,000 130,000 -- -- -- 12,000
Chairman of the Board; Chief 2001 400,000 200,000 655,500(3) -- -- 10,500
Executive Officer 2000 296,875 525,000 -- 800,000 -- 10,500
R.A. Walker......................... 2002 300,000 90,000 -- -- -- 11,000
President; Chief Financial Officer 2001 300,000 175,000 437,500(4) -- -- 10,500
2000 200,000 280,000 -- 900,000 -- 10,500
Shane M. Bayless.................... 2002 150,000 90,000 -- -- -- 11,000
Vice President--Controller; 2001 150,000 100,000 131,100(5) -- -- 10,500
Treasurer 2000 52,083 80,000 -- 180,000 -- 4,552
Richard K. Stoneburner.............. 2002 165,000 170,000 -- -- 11,000
Vice President--Exploration 2001 135,416 100,000 131,100(5) -- -- 10,500
2000 102,833 110,000 -- 160,000 -- 7,013
C.E. Hackstedt...................... 2002 165,000 130,000 -- -- 11,000
Vice President--Engineering 2001 150,000 100,000 135,100(5) 20,000 10,500
and Operations 2000 -- -- -- 50,000 -- --
- --------
(1) Company matching contribution to 401(K) Plan.
(2) Value as of date granted, which was May 8, 2002. Any dividends declared by
the Company will be paid on the restricted stock. The shares vest in three
equal installments beginning on the date of grant and continuing on the
first and second anniversary date of the grant thereafter.
(3) Represents 37,500 shares valued at $532,125 as of December 31, 2002 (based
upon a stock closing price on December 31, 2002 of $14.19). In addition to
the vesting provisions contained in footnote 2 above, these
27
shares shall not vest in any part unless and until the last trade price of
the Company's common stock shall be at least $18.00 per share for a period
of at least thirty (30) consecutive calendar days, with such thirty (30) day
period occurring prior to the date the final one-third of the restricted
stock would vest absent such condition.
(4) Represents 25,000 shares valued at $354,750 as of December 31, 2002 (based
upon a stock closing price on December 31, 2002 of $14.19). In addition to
the vesting provisions contained in footnote 2 above, these shares shall
not vest in any part unless and until the last trade price of the Company's
common stock shall be at least $18.00 per share for a period of at least
thirty (30) consecutive calendar days, with such thirty (30) day period
occurring prior to the date the final one-third of the restricted stock
would vest absent such condition.
(5) Represents 7,500 shares valued at $106,425 as of December 31, 2002 (based
upon a stock closing price on December 31, 2002 of $14.19).
Aggregated Option Exercises in Last Fiscal Year and Option Value Table as of
December 31, 2002. The following table sets forth certain information
concerning each exercise of stock options during the year ended December 31,
2002, by each of the named executive officers and the aggregated fiscal
year-end value of the unexercised options of each such named executive officer:
Number of Securities
Underlying Unexercised Value of Unexercised In-
Options/SARs at FY End the-Money Options/ SARs
Value (#) at FY End ($) (1)
- Shares Acquired Realized ------------------------- -------------------------
Name on Exercise (#) ($) Exercisable Unexercisable Exercisable Unexercisable
---- --------------- -------- ----------- ------------- ----------- -------------
Floyd C. Wilson....... -- -- 633,335 166,665 2,000,838 400,162
R.A. Walker........... -- -- 725,001 174,999 2,587,502 517,498
Shane M. Bayless...... -- -- 150,000 30,000 476,875 95,375
Richard K. Stoneburner 5,500 49,843 133,334 26,666 332,979 73,469
C.E. Hackstedt........ -- -- 55,001 14,999 -- --
- --------
(1) Amounts are based on the fair market value of Company common stock on the
last trading day of the year, December 31, 2002, which was $14.19. There is
no guarantee that, if and when these options are exercised, they will have
this value.
Employment Contracts, Termination of Employment and Change-in-Control
Arrangements
Floyd C. Wilson and 3TEC entered into an employment agreement commencing on
April 15, 2000, and terminating on December 31, 2002, with automatic one-year
extensions upon each anniversary date of the last day of the employment period
thereafter, unless either party gives at least 90 days' notice of termination,
to serve as Chief Executive Officer with a $325,000 base annual salary. The
Company may terminate Mr. Wilson's employment under the employment agreement
for "Cause." "Cause" is defined as (i) the inability of employee, despite any
reasonable accommodation required by law, due to bodily injury or disease or
any other physical or mental incapacity, to perform the services provided for
under the employment agreement for a period of 120 days in the aggregate,
within any given period of 180 consecutive days during the term of the
employment agreement, in addition to any statutorily required leave of absence,
(ii) conduct of the employee that constitutes fraud, theft, or a criminal act
involving moral turpitude, in each case only if it materially affects his
ability to perform the duties and responsibilities of his position or has a
material adverse effect on the Company, (iii) commission of a material act of
fraud against the Company, (iv) embezzlement of funds or misappropriation of
other property by the employee from the Company; (v) failure of employee to
observe or perform his material duties and obligations as an employee of the
Company or a material breach of the employment agreement, after 30 days advance
written notice of such failure or breach which has not been cured; (vi)
employee's habitual use of illegal controlled substances, or intoxication
during normal business hours while conducting the Company's business, which, in
the reasonable judgment of the Board, so impairs employee's credibility and
reputation that employee can no longer perform his duties; or (vii) employee
has been found civilly liable for sexual harassment or related offenses (or the
Company has been found civilly liable for such actions by employee).
28
If a Change of Control (hereafter defined) has occurred, Mr. Wilson may
terminate his employment for Good Reason. "Good Reason" is defined as the
occurrence, without employee's express written consent, of any one or more of
the following events: (i) a material change in employee's duties (without the
consent of employee) or a change in the title or offices held by employee, or
any occurrence which causes employee to have his principal place of employment
somewhere other than Houston, Texas; (ii) a reduction in employee's
compensation or the failure by the Company to continue to provide prompt
payment (or reimbursement to employee) of all reasonable expenses incurred by
employee in connection with employee's professional and business activities;
(iii) a failure by the Company to waive any and all restrictions that might
exist on the exercise of any stock options held by employee under the Company's
stock option plans as of the date of a Change of Control; and (iv) the failure
of the Company to obtain the assumption of the employment agreement, without
limitation or reduction, by any successor to the Company. A "Change of Control"
shall have occurred if: (i) fifty percent (50%) or more of the outstanding
common stock of the Company has been acquired by any person or persons (as
defined in Section 3(a)(9) of the Securities Exchange Act of 1934 (the "Act")),
provided such person(s) is not a stockholder(s) of the Company currently
holding ten percent (10%) or more of the outstanding common stock of the
Company at the time of the execution of the employment agreement. For purposes
of this paragraph, such person shall include affiliated persons (as defined in
the Act); (ii) there has been a merger or equivalent combination involving the
Company after which fifty percent (50%) or more of the voting stock of the
surviving corporation is held by persons other than those persons who were
stockholders holding ten percent (10%) or more of the outstanding stock of the
Company immediately prior to the date of such merger or equivalent combination;
or (iii) there has been a merger or equivalent combination or stock sale
involving the Company and after such transaction fifty percent (50%) or more of
the members of the surviving company's Board elected by stockholders are
persons who were not directors immediately prior to such transaction.
If Mr. Wilson is terminated by 3TEC without Cause, or Mr. Wilson leaves for
Good Reason, the Company is required to pay him a lump sum amount equal to two
times his annual base salary.
The employment agreement contains certain noncompete, confidentiality and
noninterference provisions. For example, during the term of the employment
agreement Mr. Wilson may not be employed or render advisory, consulting or
other services in connection with any business enterprise or person that is
engaged in leasing, acquiring, exploring, producing, gathering or marketing
hydrocarbons and related products. Further, during the term of the employment
agreement Mr. Wilson may not be financially interested, invest or engage in any
business that is engaged in leasing, acquiring, exploring, producing, gathering
or marketing hydrocarbons and related products, with certain limited
exceptions. The agreement also provides that Mr. Wilson will not disclose or
make use of any trade secrets or confidential or proprietary information
pertaining to the Company in a way that is materially detrimental to the
Company. Mr. Wilson is also prohibited during the two-year period of his
employment agreement or the period in which Mr. Wilson is employed by the
Company, whichever is longer, and for a six-month period commencing upon the
termination of such longer period from soliciting any employee of the Company
or any other person who is under contract with or rendering services to the
Company to (i) terminate his or her employment with the Company, (ii) refrain
from extending or renewing his or her employment with the Company, (iii)
refrain from rendering services to or for the Company, or (iv) become employed
by or to enter into contractual relations with any persons other than the
Company.
R.A. Walker and 3TEC entered into an employment agreement commencing on May
1, 2000, and terminating on December 31, 2002, with automatic one-year
extensions upon each anniversary date of the last day of the employment period
thereafter, unless either party gives at least 90 days' notice of termination,
to serve as President and Chief Financial Officer with a $300,000 base salary.
The agreement provides that Mr. Walker will be granted stock options giving him
the right to purchase 500,000 shares of common stock in the Company, one-half
of which shall be vested upon grant with the remaining one-half to vest equally
over a three (3) year period. The option price shall be the fair market value
of the stock on the date of grant. The Company may terminate Mr. Walker's
employment under the employment agreement for Cause or without Cause. "Cause"
is defined as (i) the inability of employee, despite any reasonable
accommodation required by law, due to bodily injury or disease or any other
physical or mental incapacity, to perform the services provided for under the
employment agreement for a period of 120 days in the aggregate, within any
given period of 180 consecutive
29
days during the term of the employment agreement, in addition to any
statutorily required leave of absence, (ii) conduct of the employee that
constitutes fraud, theft, or a criminal act involving moral turpitude, in each
case only if it materially affects his ability to perform the duties and
responsibilities of his position or has a material adverse effect on the
Company, (iii) commission of a material act of fraud against the Company, (iv)
embezzlement of funds or misappropriation of other property by the employee
from the Company; (v) failure of employee to observe or perform his material
duties and obligations as an employee of the Company or a material breach of
the employment agreement, after 30 days advance written notice of such failure
or breach which has not been cured, (vi) employee's habitual use of illegal
controlled substances, or intoxication during normal business hours while
conducting the Company's business, which, in the reasonable judgment of the
Board, so impairs employee's credibility and reputation that employee can no
longer perform his duties, or (vii) employee has been found civilly liable for
sexual harassment or related offenses (or the Company has been found civilly
liable for such actions by employee).
If a Change of Control (hereafter defined) has occurred, Mr. Walker may
terminate his employment for Good Reason. "Good Reason" is defined as the
occurrence, without employee's express written consent, of any one or more of
the following events: (i) a material change in employee's duties (without the
consent of employee) or a change in the title or offices held by employee, or
any occurrence which causes employee to have his principal place of employment
somewhere other than Houston, Texas; (ii) a reduction in employee's
compensation or the failure by the Company to continue to provide prompt
payment (or reimbursement to employee) of all reasonable expenses incurred by
employee in connection with employee's professional and business activities;
(iii) a failure by the Company to waive any and all restrictions that might
exist on the exercise of any stock options held by employee under the Company's
stock option plans as of the date of a Change of Control; and (iv) the failure
of the Company to obtain the assumption of the employment agreement, without
limitation or reduction, by any successor to the Company. A "Change of Control"
shall have occurred if: (i) fifty percent (50%) or more of the outstanding
common stock of the Company has been acquired by any person or persons (as
defined in Section 3(a)(9) of the Act), provided such person(s) is not a
stockholder(s) of the Company currently holding ten percent (10%) or more of
the outstanding common stock of the Company at the time of the execution of the
employment agreement. For purposes of this paragraph, such person shall include
affiliated persons (as defined in the Act); (ii) there has been a merger or
equivalent combination involving the Company after which fifty percent (50%) or
more of the voting stock of the surviving corporation is held by persons other
than those persons who were stockholders holding ten percent (10%) or more of
the outstanding stock of the Company immediately prior to the date of such
merger or equivalent combination; or (iii) there has been a merger or
equivalent combination or stock sale involving the Company and after such
transaction fifty percent (50%) or more of the members of the surviving
company's Board elected by stockholders are persons who were not directors
immediately prior to such transaction.
If Mr. Walker is terminated by 3TEC without Cause, or Mr. Walker leaves for
Good Reason, the Company is required to pay him a lump sum amount equal to two
times his annual base salary.
The employment agreement contains certain noncompete, confidentiality and
noninterference provisions. For example, during the term of the employment
agreement Mr. Walker may not be employed or render advisory, consulting or
other services in connection with any business enterprise or person that is
engaged in leasing, acquiring, exploring, producing, gathering or marketing
hydrocarbons and related products. Further, during the term of the employment
agreement Mr. Walker may not be financially interested, invest or engage in any
business that is engaged in leasing, acquiring, exploring, producing, gathering
or marketing hydrocarbons and related products, with certain limited
exceptions. The agreement also provides that Mr. Walker will not disclose or
make use of any trade secrets or confidential or proprietary information
pertaining to the Company in a way that is materially detrimental to the
Company. Mr. Walker is also prohibited during the period of his employment
agreement or the period in which Mr. Walker is employed by the Company,
whichever is longer, and for a six-month period commencing upon the termination
of such longer period from soliciting any employee of the Company or any other
person who is under contract with or rendering services to the Company to (i)
terminate his or her employment with the Company, (ii) refrain from extending
or renewing his or her
30
employment with the Company, (iii) refrain from rendering services to or for
the Company, (iv) become employed by or to enter into contractual relations
with any persons other than the Company.
The Board approved an arrangement in December, 2000, whereby Shane M.
Bayless is to receive a lump sum payment equal to two (2) times his annual
compensation if Mr. Bayless is terminated by the Company without Cause or if
Mr. Bayless terminates his employment for Good Reason. Cause and Good Reason
are as defined in Mr. Wilson's employment agreement.
On October 29, 2002, the Board approved a Severance Compensation Plan (the
"Severance Plan") for employees, including the executive officers named herein.
Upon the execution of a definitive agreement providing for a transaction
resulting in a Change of Control ("Control Transaction"), if the surviving
entity in such transaction or its affiliate does not, on or before thirty (30)
days prior to the date set for closing (the "Closing") of the Change in
Control, offer any Company employee a job with substantially comparable duties
and at a base salary and fringe benefits at a level equal to or greater than
those in effect at the time such offer is made and in a location that is within
a fifteen mile radius of the metropolitan city in which such employee's
employment is located at the time such offer is made, such employee shall be
entitled to a severance benefit, as set forth on an exhibit to the Severance
Plan (the "Severance Benefit"), which shall be paid by the Company prior to
Closing.
In addition, if within one (1) year following the occurrence of a Change in
Control, the Company (or its successor) (a) terminates the employment of any
employee (other than for cause as defined below), or (b) without such
employee's consent (i) substantially changes such employee's duties, (ii)
reduces such employee's base salary, (iii) fails to maintain fringe benefits at
a level equal to or greater than those in effect at the date of the Change of
Control, or (iv) relocates such employee outside a fifteen (15) miles radius of
the metropolitan city in which such employee's employment location is located,
the Severance Benefit will payable to the former employee within ten (10) days
of such event.
Change in Control is defined as: (i) the Company shall not be the surviving
entity in any merger, consolidation or other reorganization (or survives only
as a subsidiary of an entity other than a previously wholly-owned subsidiary of
the Company), (ii) the Company sells, leases or exchanges substantially all of
its assets to any other person or entity (other than a wholly-owned subsidiary
of the Company), (iii) the Company is to be dissolved and liquidated, (iv) any
person or entity, including a "group" as contemplated by Section 13(d)(3) of
the Securities Exchange Act of 1934 acquires or gains ownership or control
(including, without limitation, power to vote) of more than 50% of the
outstanding shares of the Company's voting stock (based upon voting power), or
(v) as a result of or in connection with a contested election of directors, the
persons who were directors of the Company before such election shall cease to
constitute a majority of the Board.
Cause is defined as (i) the inability of an employee, despite any reasonable
accommodation required by law, due to bodily injury or disease or any other
physical or mental incapacity, to perform his services for the Company for a
period of 120 days in the aggregate, within any given period of 180 consecutive
days, in addition to any statutorily required leave of absence, (ii) conduct of
the employee that constitutes fraud, theft, or a criminal act involving moral
turpitude, in each case only if it materially affects his ability to perform
the duties and responsibilities of his position or has a material adverse
effect on the Company, (iii) commission of a material act of fraud against the
Company, (iv) embezzlement of funds or misappropriation of other property by
the employee from the Company; (v) failure of the employee to observe or
perform his material duties and obligations as an employee of the Company,
which after thirty (30) days advance written notice of such failure has not
been cured; (vi) employee's habitual use of illegal controlled substances, or
intoxication during normal business hours while conducting the Company's
business, which, in the reasonable judgment of the Board, so impairs the
employee's credibility and reputation that employee can no longer perform his
duties; or (vii) employee has been found civilly liable for sexual harassment
or related offenses (or the Company has been found civilly liable for such
employee's actions).
31
Compensation of Directors
As adopted by the Board on November 1, 2001 to be effective as of January 1,
2002, the Company pays each non-employee director an annual board retainer fee
of $15,000. Additionally, the Company pays each non-employee director $1,000
for attending meetings of the Board or its Nominating and Compensation
committees, whether in attendance in person or by telephone. As adopted by the
Board on October 29, 2002, effective as of that date, the Company pays each
non-employee director who is a member of the Audit Committee $2,500 for each
meeting of the Audit Committee and $3,500 to the Chairman of the Audit
Committee for each meeting of the Audit Committee, whether in attendance in
person or by telephone. Non-employee directors are given the opportunity to
receive their cash compensation in the form of Company common stock based on
the closing market price of the common stock on the last trading day of the
calendar quarter during which such director is entitled to receive the cash
compensation.
3TEC reimburses directors' documented travel and lodging expenses incurred
in connection with services to the Company.
Each non-employee director is eligible for incentive awards under the
Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan,
however none were issued in 2002.
Pursuant to the 3TEC Energy Corporation 2000 Non-Employee Directors' Stock
Option Plan, as amended (the "2000 Non-Employee Plan"), on the date an
individual becomes a non-employee director, the director receives an initial
option to purchase 15,000 shares of common stock. In addition, on the first
trading day on or after January 1st of each year, each non-employee director
who is then serving and has served as a non-employee director for more than six
months receives an option to purchase 10,000 shares of common stock. The
exercise price of an option is the fair market value which is defined as the
closing price of the common stock reported by NASDAQ on the date of grant.
Options vest and are exercisable immediately.
In January 2002, Mr. Helm, Mr. Phillips and Mr. Miller were each granted an
option to purchase 10,000 shares of common stock under the 2000 Non-Employee
Plan, and Mr. Bump and Mr. Irish were each granted an option to purchase 15,000
shares of common stock under the 2000 Non-Employee Plan. Mr. Phillips and Mr.
Miller then assigned their options to EnCap Energy Capital Fund III, L.P.
Compensation Committee Interlocks and Insider Participation
During 2002:
None of the members of the Board's Compensation Committee was an officer (or
former officer) or employee of the Company or any of its subsidiaries;
None of the Company's executive officers served on the compensation
committee (or another board committee with similar functions, or in the
absence of any such committee, the entire board of directors) of any entity
where one of that entity's executive officers served on the Company's
Compensation Committee;
None of the Company's executive officers was a director of another entity
where one of that entity's executive officers served on the Company's
Compensation Committee; and
None of the Company's executive officers served on the compensation
committee (or another board committee with similar functions, or in the
absence of any such committee, the entire board of directors) of another
entity where one of that entity's executive officers served as a director on
the Company's Board.
Larry L. Helm, the chairman of the Compensation Committee and a director of
the Company, is responsible for the nationwide Middle Market Banking Group of
Bank One Corporation. The Company has a $250 million credit facility with Bank
One, NA, as administrative agent, Bank of Montreal, as syndication agent, and
Union Bank of California, N.A., Wells Fargo Bank Texas, National Association,
CIBC, Inc., Comerica Bank, Fleet
32
National Bank and The Bank of Nova Scotia as participating lenders. The
borrowing base is redetermined semi-annually and as of March 7, 2003, was $160
million. In addition, the Company is a party to certain derivative contracts
that Bank One, NA is the counter-party to. These derivative contracts cover a
portion of the Company's anticipated natural gas production for 2003.
On February 2, 2003, the Company entered into a definitive agreement with
Plains Exploration & Production Company ("Plains") whereby Plains will acquire
the Company for a combination of cash and stock. Under the terms of the
agreement, the Company's shareholders will receive $8.50 in cash and 0.85
shares of Plains' Common Stock for each share of the Company's Common Stock,
subject to certain adjustments based on Plains' share price prior to closing.
Although subject to shareholder approval, the aforementioned transaction is
expected to close during the second quarter of 2003. Two members of 3TEC's
Board who are also members of the Compensation Committee, D. Martin Phillips
and David B. Miller, are managing directors of EnCap, which beneficially owns
453,980 shares of 3TEC preferred stock and 2,980,635 shares of 3TEC common
stock, as well as 1,848,728 shares of Plains's common stock.
33
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
The following table sets forth the shares of 3TEC's common stock
beneficially owned by those persons known by 3TEC to be the beneficial owner of
more than five percent of 3TEC's issued and outstanding common stock, as well
as the shares of 3TEC's common stock beneficially owned by each director and
named executive officer and all directors and executive officers as a group.
All percentages are based on 16,780,776 shares of common stock issued and
outstanding on February 12, 2003:
Amount and
Nature of Percent
Beneficial of
Name and Address of Beneficial Owner Ownership (1) Class
------------------------------------ ------------- -------
Shane M. Bayless................................................ 152,500(2) *
Larry J. Bump................................................... 25,000 *
C.E. Hackstedt.................................................. 60,834(3) *
Larry L. Helm................................................... 55,000 *
James L. Irish III.............................................. 26,799 *
David B. Miller................................................. 0 *
D. Martin Phillips.............................................. 0 *
Richard K. Stoneburner.......................................... 130,334(4) *
R.A. Walker..................................................... 727,001 4.2%
Floyd C. Wilson................................................. 1,495,959(5) 8.5%
Directors and executive officers of 3TEC as a group (13 persons) 3,015,113 18.0%
Artisan Partners Limited Partnership
1000 N. Water Street, Suite 770
Milwaukee, WI 53202........................................... 1,449,808(6) 8.6%
EnCap Energy Acquisition III-B, Inc. (7)........................ 1,445,537(8) 8.4%
EnCap Energy Capital Fund III, L.P. (7)......................... 2,021,322(9) 11.5%
EnCap Energy Capital Fund III-B, L.P. (7)....................... 1,445,537(10) 8.4%
EnCap Investments L.L.C. (7).................................... 4,609,452(11) 25.0%
Kaiser-Francis Oil Company
6733 South Yale
Tulsa, OK 74136............................................... 1,112,578(12) 6.6%
Plains Exploration & Production Company
500 Dallas Street, Suite 700
Houston, TX 77002............................................. 7,139,465(13) 35.3%
Royce & Associates, Inc.
1414 Avenue of the Americas
New York, NY 10019............................................ 1,731,075(14) 10.3%
T. Rowe Price Associates, Inc.
100 E. Pratt Street
Baltimore, MD 21202........................................... 1,198,500(15) 7.1%
Wentworth, Hauser & Violich
353 Sacramento Street, Suite 600
San Francisco, CA 94111....................................... 1,439,151(16) 8.6%
- --------
* Represents less than 1%.
(1) Includes both outstanding shares of 3TEC common stock and shares of 3TEC
common stock such person has the right to acquire within 60 days of
February 12, 2003 by the exercise of outstanding stock options. Shares
subject to stock options exercisable within 60 days of February 12, 2003
include: 150,000 shares for Mr. Bayless; 25,000 shares for Mr. Bump; 58,334
shares for Mr. Hackstedt; 55,000 shares for Mr. Helm; 25,000 shares for Mr.
Irish; 127,834 shares for Mr. Stoneburner; 725,001 shares for Mr. Walker;
and 633,335 shares for Mr. Wilson.
34
(2) Includes 2,500 shares of restricted stock.
(3) Includes 2,500 shares of restricted stock.
(4) Includes 2,500 shares of restricted stock.
(5) Includes 5,000 shares of common stock owned by Wilvest Limited Partnership
of which Mr. Wilson is the general partner; and warrants to purchase
290,014 shares of common stock granted to Mr. Wilson. Mr. Wilson disclaims
beneficial ownership of the shares owned by Wilvest Limited Partnership
except to the extent of his pecuniary interest therein.
(6) As disclosed in a joint filing with Artisan Investment Corporation, Andrew
A. Ziegler and Carlene Murphy Ziegler on Schedule 13 G/A filed with the SEC
on January 31, 2003.
(7) The address for EnCap Energy Acquisition III-B, Inc., EnCap Energy Capital
Fund III, L.P., EnCap Energy Capital Fund III-B, L.P. and EnCap Investments
L.L.C. is 1100 Louisiana, Suite 3150, Houston, TX 77002.
(8) As disclosed in a joint filing on Schedule 13D/A filed with the SEC on
February 12, 2003. This figure includes 957,587 shares of common stock,
145,850 shares of Series D Preferred Stock convertible into 145,850 shares
of common stock, and warrants to purchase 342,100 shares of common stock.
(9) As disclosed in a joint filing on Schedule 13D/A filed with the SEC on
February 12, 2003. This figure includes 1,266,144 shares of common stock,
192, 846 shares of Series D Preferred Stock convertible into 192,846 shares
of common stock, warrants to purchase 452,332 shares of common stock, and
110,000 shares issuable upon exercise of stock options.
(10) As disclosed in a joint filing on Schedule 13D/A filed with the SEC on
February 12, 2003. Includes 1,445,537 shares owned by EnCap Acquisition
described in footnote 8 above. As the controlling person of EnCap
Acquisition, EnCap III-B may be deemed to share voting and dispositive
power with respect to the shares of common stock owned by EnCap
Acquisition; however, EnCap III-B disclaims any beneficial ownership of
these shares.
(11) As disclosed in a joint filing on Schedule 13 D/A filed with the SEC on
February 12, 2003. As the general partner or controlling person of each
entity, Encap Investments L.L.C. ("EnCap") may be deemed to have the power
to vote and direct the vote or to dispose or direct the disposition of
4,609,452 shares of common stock beneficially owned by EnCap Energy
Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc. ("EnCap
Acquisition"), ECIC Corporation, and BOCP Energy Partners, L.P. ("BOCP").
This figure includes the shares described in footnotes 8 and 9 above, as
well as 447,095 shares of common stock, 68,097 shares of Series D
Preferred Stock convertible into 68,097 shares of common stock, and
warrants to purchase 159,725 shares of common stock beneficially owned by
ECIC Corporation, and 309,809 shares of common stock, 47,187 shares of
Series D Preferred Stock convertible into 47,187 shares of common stock,
and warrants to purchase 110,680 shares of common stock beneficially owned
by BOCP. The controlling person of EnCap is El Paso Merchant Energy North
America Company ("El Paso Merchant Energy"). The controlling person of El
Paso Merchant Energy is El Paso Corporation. El Paso Merchant Energy and
El Paso Corporation may be deemed to have the power to vote and direct the
vote or to dispose or direct the disposition of the shares. El Paso
Merchant Energy and El Paso Corporation disclaim any beneficial ownership
of these shares.
(12) Kaiser-Francis Oil Company is a wholly owned subsidiary of GBK
Corporation, which is owned 78.22% directly by George B. Kaiser and 21.78%
indirectly by Mr. Kaiser through affiliates.
(13) Represents (i) 3,668,131 shares of 3TEC common stock, (ii) 1,354,851
shares of 3TEC common stock issuable upon exercise of warrants; (iii)
453,980 shares of Series D Preferred Stock, convertible into common
shares, and (iv) 1,662,503 shares of 3TEC common stock issuable upon
exercise of options that are subject to a voting agreement detailed below
in the section titled Changes in Control. The voting agreement was
executed in connection with the execution of a definitive merger agreement
with Plains whereby Plains will acquire the Company for a combination of
cash and stock. As a result of entering into the voting
35
agreement, Plains may be deemed to have the power to vote, and to be the
beneficial owner of 7,139,465 shares. Each voting agreement will terminate
upon the first to occur of (i) the effective time of the merger or (ii) the
date upon which the merger agreement is terminated.
(14) As disclosed in a filing on Schedule 13 G/A filed with the SEC on February
5, 2003.
(15) As disclosed in a filing on Schedule 13 G/A filed with the SEC on February
5, 2003.
(16) As disclosed in a joint filing with Laird Norton Financial Group, Inc. on
Schedule 13 G/A filed with the SEC on February 13, 2002.
Changes in Control
On February 2, 2003, the Company entered into a definitive agreement with
Plains whereby Plains will acquire the Company for a combination of cash and
stock. In connection with the execution of the merger agreement, each of EnCap
Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP
Energy Partners, L.P., ECIC Corporation, Floyd C. Wilson, Stephen W. Herod and
R.A. Walker entered into voting agreements with Plains and 3TEC to vote all of
the shares of 3TEC common stock and 3TEC preferred stock they own in favor of
the adoption of the merger agreement. Mr. Wilson and Mr. Walker are officers
and directors of 3TEC. Mr Herod is an officer of 3TEC. The entities described
above in the aggregate and Mr. Wilson own more than 5% of 3TEC's common stock
and, in the case of the entities, a majority of the 3TEC preferred stock. In
addition, each has agreed not to transfer their shares of 3TEC common stock or
3TEC preferred stock (except they may transfer their shares to an affiliate or
other stockholder of 3TEC who agrees to be bound by the terms of the voting
agreement), not to grant a proxy with respect to such shares and not to solicit
or vote in favor of any competing transaction to the merger. Finally, each has
agreed to not exercise their employee stock options or warrants to purchase
3TEC common stock for $3.00, except as contemplated by the merger agreement.
The aggregate amount of shares of 3TEC common stock and 3TEC preferred stock
subject to these voting agreements represents approximately 22% of the
outstanding 3TEC common stock and approximately 74% of the outstanding 3TEC
preferred stock. Each voting agreement will terminate upon the first to occur
of (i) the effective time of the merger or (ii) the date upon which the merger
agreement is terminated.
In addition, as a result of the merger with Plains: (1) all restrictions on
restricted common stock held the Company's officers and directors (except
37,500 shares held by Mr. Wilson and 25,000 shares held by Mr. Walker, which
will be cancelled) will fully vest on or before the effective date of the
merger, and (2) all outstanding options that have not vested (except for 80,000
stock options held by Mr. Wilson and 70,000 stock options held by Mr. Walker,
which will be cancelled) will fully vest on or before the effective date of the
merger and will be converted into merger consideration on a cashless exercise
basis.
Item 13. Certain Relationships and Related Transactions
Larry L. Helm, the chairman of the Compensation Committee and a director of
the Company, is responsible for the nationwide Middle Market Banking Group of
Bank One Corporation. The Company has a $250 million credit facility with Bank
One, NA, as administrative agent, Bank of Montreal, as syndication agent, and
Union Bank of California, N.A., Wells Fargo Bank Texas, National Association,
CIBC, Inc., Comerica Bank, Fleet National Bank and The Bank of Nova Scotia as
participating lenders. The borrowing base is redetermined semi-annually and as
of March 7, 2003, was $160 million. In addition, the Company is a party to
certain derivative contracts that Bank One, NA is the counter-party to. These
derivative contracts cover a portion of the Company's anticipated natural gas
production for 2003.
On February 2, 2003, the Company entered into a definitive agreement with
Plains Exploration & Production Company ("Plains") whereby Plains will acquire
the Company for a combination of cash and stock. Under the terms of the
agreement, the Company's shareholders will receive $8.50 in cash and 0.85
shares of Plains' Common Stock for each share of the Company's Common Stock,
subject to certain adjustments based on Plains' share price prior to closing.
Although subject to shareholder approval, the aforementioned transaction is
expected to close during the second quarter of 2003. Two members of 3TEC's
Board, D. Martin Phillips and David B. Miller, are managing directors of EnCap,
which beneficially owns 453,980 shares of 3TEC preferred stock and 2,980,635
shares of 3TEC common stock, as well as 1,848,728 shares of Plains's common
stock.
36
Item 14. Controls and Procedures
Within 90 days of the filing date of this report, the Company carried out an
evaluation, under the supervision and with the participation of the Company's
management, including the Company's Chief Executive Officer and Chief Financial
Officer, of the Company's disclosure controls and procedures (as defined in
Rule 13a-14(c) of the Securities Exchange Act of 1934). Based upon that
evaluation, the Chief Executive Officer and Chief Financial Officer have
concluded that the Company's disclosure controls and procedures are effective.
There have been no significant changes in the Company's internal controls or
in other factors that could significantly affect these controls subsequent to
the date of their evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Item 15. 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. Exhibits: The following documents are filed as exhibits to this
report:
2.1 Agreement and Plan of Merger, dated December 21, 1999, by and between 3TEC Energy Corporation,
3TM Acquisition L.L.C., Magellan Exploration, LLC and ECIC Corporation, EnCap Energy Capital
Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners, L.P., and Pel-Tex
Partners, L.L.C. (Incorporated by reference to Exhibit C to Form DEF14A, filed January 11, 2000.)
2.2 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 Form DEF14A, filed October 25, 1999.)
2.3 First Amendment to Agreement and Plan of Merger, effective as of January 14, 2000, by and among
3TEC Energy Corporation, 3TM Acquisition L.L.C., Magellan Exploration, LLC, ECIC Corporation,
EnCap Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners,
L.P., and Pel-Tex Partners, L.L.C. (Incorporated by reference to Exhibit 2.1 to Form 8-K filed
February 4, 2000.)
2.4 Second Amendment to Agreement and Plan of Merger, effective as of February 2, 2000, by and among
3TEC Energy Corporation, 3TM Acquisition L.L.C., Magellan Exploration, LLC, ECIC Corporation,
EnCap Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc., BOCP Energy Partners,
L.P., and Pel-Tex Partners, L.L.C. (Incorporated by reference to Exhibit 2.2 to Form 8-K filed
February 4, 2000.)
2.5 Form of Agreement of Sale and Purchase by and between C.W. Resources, Inc., Westerman Royalty,
Inc., and Carl A. Westerman and 3TEC Energy Corporation. (Incorporated by Reference to Exhibit
10.32 to Form S-2 filed April 28, 2000.)
2.6 Form of Stock Purchase Agreement by and between 3TEC Energy Corporation and Classic Resources,
Inc., Natural Gas Partners IV, L.P., Natural Gas Partners V, L.P., and certain individual signatories.
(Incorporated by reference to Exhibit 2.1 to Form 8-K filed February 13, 2001.)
2.7 Merger Agreement, dated October 25, 2001, by and among 3TEC Energy Corporation, 3NEX
Acquisition Corporation and Enex Resources Corporation. (Incorporated by reference to Exhibit 2.7 to
form 10-KSB filed April 1, 2002.)
2.8 Certificate of Ownership and Merger Merging Enex Resources Corporation into 3TEC Energy
Corporation filed with the Delaware Secretary of State January 31, 2002. (Incorporated by reference to
Exhibit 2.8 to Form 10-KSB filed April 1, 2002.)
2.9 Certificate of Ownership and Merger Merging 3TEC/CRI Corporation into 3TEC Energy Corporation
filed with the Delaware Secretary of State August 6, 2002. *
2.10 Agreement and Plan of Merger by and among Plains Exploration & Production Company, PXP Gulf
Coast Inc. and 3TEC Energy Corporation dated as of February 2, 2003. (Incorporated by reference to
Exhibit 10.1 to Form 8-K filed February 4, 2003).
37
3.1 Certificate of Incorporation of 3TEC Energy Corporation. (Incorporated by reference to Exhibit 3.1 of
Form 8-K filed December 6, 1999.)
3.2 Certificate of Amendment to the Certificate of Incorporation of 3TEC Energy Corporation.
(Incorporated by reference to Exhibit 3.3 of Form 10-KSB filed March 30, 2000.)
3.3 Certificate of Amendment of the Certificate of Incorporation of 3TEC Energy Corporation, dated
June 14, 2001 (Incorporated by reference to Exhibit 3.5 Form 10-QSB filed August 8, 2001.)
3.4 Certificate of Merger of Middle Bay Oil Company, Inc. into 3TEC Energy Corporation. (Incorporated
by reference to Exhibit 3.3 of Form 8-K/A filed December 16, 1999.)
3.5 Bylaws of the Company. (Incorporated by reference to Exhibit C to Form DEF14A filed October 25,
1999.)
3.6 Amendment No. 1 to Bylaws of the Company. (Incorporated by reference to Exhibit 4.5 Form S-8 filed
October 26, 2001.)
3.7 Amendment No. 2 to Bylaws of 3TEC Energy Corporation. (Incorporated by reference to Exhibit 3.6 to
Form 10-QSB filed August 8, 2001.)
4.1 Certificate of Designation of Series B Preferred Stock of 3TEC Energy Corporation. (Incorporated by
reference to Exhibit 3.1 to Form 8-K/A filed December 16, 1999.)
4.2 Certificate of Designation of Series D Preferred Stock of 3TEC Energy Corporation. (Incorporated by
reference to Exhibit 4.3 to Form 10-QSB filed May 15, 2000.)
10.1 Securities Purchase Agreement, dated July 1, 1999 by and between the Company and 3TEC Energy
Corporation. (Incorporated by reference to Exhibit C Form DEF14A 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 Exhibit 10.2 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 Exhibit 10.3 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 Exhibit 10.1 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 Exhibit 10.5 to Form 10-QSB
filed November 15, 1999.)
10.6 Agreement to Terminate Shareholders' Agreement, dated April 30, 2001, by and among the Company
and the Major Shareholders. (Incorporated by reference to Exhibit 10.6 to Form 10-QSB filed
November 8, 2001.)
10.7 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 Exhibit 10.6 to Form 10-QSB filed November 15, 1999.)
10.8 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 Exhibit 10.2 to Form 8-K filed November 2, 1999.)
10.9 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
Exhibit 10.3 to Form 8-K filed November 2, 1999.)
38
10.10 Employment Agreement, dated April 15, 2000 by and between Floyd C. Wilson and the Company.
(Incorporated by reference to Exhibit 10.9 to Form S-2 filed April 28, 2000.)
10.11 Employment Agreement, dated May 1, 2000, by and between R.A. Walker and the Company.
(Incorporated by reference to Exhibit 10.9 to Form S-2 filed April 28, 2000.)
10.12 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 Exhibit 10.1 to Form 8-K/A filed
December 17, 1999.)
10.13 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest II, LP, Compass Bank,
and Bank of Oklahoma, National Association. (Incorporated by reference to Exhibit 10.16 to Form
10-QSB filed November 15, 1999.)
10.14 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest II, LP, Compass Bank,
and Bank of Oklahoma, National Association. (Incorporated by reference to Exhibit 10.16 to Form
10-QSB filed November 15, 1999.)
10.15 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 (Incorporated by reference to Exhibit 10.21 to
Form S-2 filed April 28, 2000 and replacing the unexecuted Exhibit 10.17 of Form 10-QSB filed
November 15, 1999.)
10.16 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc., Bank
One Texas, N.A. and 3TEC Energy Company L.L.C. (Incorporated by reference to Exhibit 10.18 to
Form S-2 filed April 28, 2000.)
10.17 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc., Bank
One Texas, N.A. and Shoemaker Family Partners, LP. (Incorporated by reference to Exhibit 10.19 to
Form S-2 filed April 28, 2000.)
10.18 Intercreditor Agreement, dated as of November 23, 1999, among Middle Bay Oil Company, Inc., Bank
One Texas, N.A. and Shoeinvest II, LP. (Incorporated by reference to Exhibit 10.20 to Form S-2 filed
April 28, 2000.)
10.19 Amendment to Securities Purchase Agreement, dated as of November 23, 1999, among Middle Bay
Oil Company, Inc. and 3TEC Energy Company L.L.C. (Incorporated by reference to Exhibit 10.22 to
Form S-2 filed April 28, 2000.)
10.20 Amendment to Securities Purchase Agreement, dated as of November 23, 1999, among Middle Bay
Oil Company, Inc. and Shoemaker Family Partners, LP. (Incorporated by reference to Exhibit 10.23 to
Form S-2 filed April 28, 2000.)
10.21 Amendment to Securities Purchase Agreement, dated as of November 23, 1999, among Middle Bay
Oil Company, Inc. and Shoeinvest II, LP. (Incorporated by reference to Exhibit 10.24 to Form S-2
filed April 28, 2000.)
10.22 Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan. (Incorporated by
reference to Exhibit B to Form DEF 14A filed May 5, 1997.)
10.23 Amendment No. 1 to the Amended and Restated 1995 Stock Option and Stock Appreciation Rights
Plan. (Incorporated by reference to Exhibit B to Form DEF 14A filed May 5, 1998.)
10.24 Amendment No. 1 to Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan.
(Incorporated by reference to Exhibit 99.7 Form S-8 filed November 6, 2000.)
10.25 Amendment No. 3 to Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan.
(Incorporated by reference to Exhibit 99.8 Form S-8 filed November 6, 2000.)
10.26 1999 Stock Option Plan. (Incorporated by reference to Exhibit E to Form DEF 14A filed October 25,
1999.)
39
10.27 Amendment No. 1 to 3TEC Energy Corporation 1999 Stock Option Plan. (Incorporated by reference
to Exhibit 99.4 Form S-8 filed November 6, 2000.)
10.28 2000 Stock Option Plan (Incorporated by reference to Exhibit A to Form DEF 14A filed on May 1,
2000.)
10.29 Amendment No. 1 to 3TEC Energy Corporation 2000 Stock Option Plan. (Incorporated by reference
to Exhibit 99.2 Form S-8 filed November 6, 2000.)
10.30 3TEC Energy Corporation 2001 Stock Option Plan. (Incorporated by reference to Exhibit 99.1 Form
S-8 filed October 26, 2001.)
10.31 3TEC Energy Corporation 2000 Non-Employee Directors Stock Option Plan. (Incorporated by
reference to Exhibit 99.2 Form S-8 filed October 26, 2001.)
10.32 Amendment No. 1 to 3TEC Energy Corporation 2000 Non-Employee Directors' Stock Option Plan.
(Incorporated by reference to Exhibit 10.32 to Form 10-Q filed May 13, 2002.
10.33 Second Restated Credit Agreement among 3TEC Energy Corporation, Enex Resources Corporation,
Middle Bay Production Company, Inc., and Magellan Exploration, LLC, as Borrowers, and Bank One,
Texas, N.A. and the Institutions named therein, as Lenders, Bank One, Texas, N.A., as Administrative
Agent, Bank of Montreal as Syndication Agent and Banc One Capital Markets, Inc., as Arranger,
dated May 31, 2000. (Incorporated by reference to Exhibit 10.28 to Form S-2/A filed June 6, 2000.)
10.34 First Amendment to Shareholders' Agreement by and among 3TEC Energy Corporation, the W/E
Shareholders and the Major Shareholders, dated May 30, 2000. (Incorporated by reference to Exhibit
10.29 to Form S-2/A filed June 6, 2000.)
10.35 Third Restated Credit Agreement among 3TEC Energy Corporation, Enex Resources Corporation and
3TEC/CRI Corporation, as Borrowers, and Bank One, N.A. and the Institutions named therein, as
Lenders, Bank One, N.A., as Administrative Agent, Bank of Montreal as Syndication Agent and Banc
One Capital Markets, Inc., as Arranger, dated March 12, 2001. (Incorporated by reference to Exhibit
10.27 to Form 10-QSB filed May 14, 2001.)
10.36 3TEC Energy Corporation Amended and Restated 2001 Stock Option and Restricted Stock Plan
(Incorporated by reference to Exhibit B to Form DEF 14A filed April 4, 2002.
10.37 Letter Amendment to Third Restated Credit Agreement among 3TEC Energy Corporation, as
Borrower, and Bank One, N.A., as Administrative Agent and Lender, and the Major Lenders, dated
September 30, 2002. (Incorporated by reference to Exhibit 10.37 to Form 10Q filed November 11,
2002.
23.1 Consent of KPMG LLP, independent auditors. *
23.2 Consent of Ryder Scott Company, independent petroleum engineers. *
99.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002. *
99.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002. *
- --------
* Filed herewith
(b) The following reports were filed on Form 8-K during the fourth quarter
of 2002: None
40
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.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
41
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.
42
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized, as of March 26,
2003.
3TEC ENERGY CORPORATION
(Registrant)
By: /s/ FLOYD C. WILSON
-----------------------------
Floyd C. Wilson
Chairman and Chief Executive
Officer
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Floyd C. Wilson, his true and lawful
attorney-in-fact and agent, 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-K 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:
Signature Title Date
--------- ----- ----
/s/ FLOYD C. WILSON Chairman and Chief Executive March 26, 2003
- ----------------------------- Officer
Floyd C. Wilson
/s/ R.A. WALKER President, Chief Financial March 26, 2003
- ----------------------------- Officer, Director
R. A. Walker
/s/ SHANE M. BAYLESS Vice President--Controller & March 26, 2003
- ----------------------------- Treasurer Principal
Shane M. Bayless Accounting Officer
/s/ LARRY J. BUMP Director March 26, 2003
- -----------------------------
Larry J. Bump
/s/ LARRY L. HELM Director March 26, 2003
- -----------------------------
Larry L. Helm
/s/ DAVID B. MILLER Director March 26, 2003
- -----------------------------
David B. Miller
/s/ D. MARTIN PHILLIPS Director March 26, 2003
- -----------------------------
D. Martin Phillips
/s/ JAMES L. IRISH III Director March 26, 2003
- -----------------------------
James L. Irish III
43
CERTIFICATIONS
I, Floyd C. Wilson, certify that:
1. I have reviewed this annual report on Form 10-K of 3TEC Energy Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) Designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) Presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 26, 2003
By: /s/ Floyd C. Wilson
----------------------------
Floyd C. Wilson
Chief Executive Officer
44
I, R.A. Walker, certify that:
1. I have reviewed this annual report on Form 10-K of 3TEC Energy Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) Designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) Presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 26, 2003
By: /s/ R.A. Walker
----------------------------
R.A. Walker
Chief Financial Officer
45
INDEX TO FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report............................................................................. F-2
Consolidated Balance Sheets as of December 31, 2002 and 2001............................................. F-3
Consolidated Statements of Operations for each of the years in the three-year period ended December 31,
2002................................................................................................... F-4
Consolidated Statements of Cash Flows for each of the years in the three-year period ended December 31,
2002................................................................................................... F-5
Consolidated Statements of Changes in Stockholders' Equity for each of the years in the three-year period
ended December 31, 2002................................................................................ F-6
Notes to Consolidated Financial Statements............................................................... F-7
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
3TEC Energy Corporation:
We have audited the accompanying consolidated balance sheets of 3TEC Energy
Corporation and subsidiaries, as of December 31, 2002 and 2001, and the related
consolidated statements of operations, changes in stockholders' equity, and
cash flows for each of the years in the three-year period ended December 31,
2002. 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 auditing standards generally
accepted in the United States of America. 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, 2002 and 2001, and the results
of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
As explained in Note 1 to the consolidated financial statements, the Company
changed its method of accounting for derivative instruments and hedging
activities effective January 1, 2001.
KPMG LLP
Houston, Texas
February 14, 2003
F-2
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
As of December 31,
-------------------
2002 2001
--------- --------
ASSETS
Current Assets:
Cash and cash equivalents................................................................................ $ 2,249 $ 17,762
Accounts receivable...................................................................................... 17,486 16,835
Income tax receivable.................................................................................... -- 4,464
Other.................................................................................................... 1,285 4,473
--------- --------
Total Current Assets.................................................................................. 21,020 43,534
Properties and Equipment, at cost:
Oil and gas properties, successful efforts method........................................................ 435,591 385,264
Other property and equipment............................................................................. 3,931 3,549
--------- --------
439,522 388,813
Accumulated depletion, depreciation and amortization........................................................ (112,732) (71,039)
--------- --------
Net Properties and Equipment................................................................................ 326,790 317,774
--------- --------
Other Assets, net........................................................................................... 1,375 1,730
TOTAL ASSETS................................................................................................ $ 349,185 $363,038
========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable......................................................................................... $ 13,440 $ 25,052
Accrued liabilities...................................................................................... 1,340 1,322
Series C Preferred stock redemption payable.............................................................. 1,272 1,349
Derivative fair value liability.......................................................................... 3,551 --
Other current liabilities................................................................................ 3,055 1,468
--------- --------
Total Current Liabilities............................................................................. 22,658 29,191
--------- --------
Long-term debt........................................................................................... 99,000 108,000
Deferred income taxes.................................................................................... 44,563 45,135
--------- --------
TOTAL LIABILITIES........................................................................................... 166,221 182,326
--------- --------
Commitments and Contingencies (Note 11)..................................................................... -- --
STOCKHOLDERS' EQUITY
Preferred stock, $.02 par value, 20,000,000 shares authorized, 266,667 shares designated Series B,
2,300,000 shares designated Series C and 725,167 shares designated Series D, none other designated...... -- --
Convertible preferred stock Series B, $7.50 stated value, 266,667 shares issued and outstanding as of
December 31, 2001. $2,000 aggregate liquidation preference.............................................. -- 3,627
Convertible preferred stock Series D, 5% $24.00 redemption value, 613,919 shares and 614,776 issued and
outstanding at December 31, 2002 and December 31, 2001, respectively, $14,734 aggregate liquidation
preference at December 31, 2002......................................................................... 7,475 7,485
Common stock, $.02 par value, 60,000,000 shares authorized, 16,850,572 and 16,547,595 shares issued at
December 31, 2002 and December 31, 2001, respectively................................................... 337 331
Additional paid-in capital............................................................................... 157,557 151,412
Retained earnings........................................................................................ 19,520 18,906
Treasury stock; 69,807 shares at December 31, 2002 and December 31, 2001................................. (1,049) (1,049)
Deferred compensation.................................................................................... (876) --
--------- --------
TOTAL STOCKHOLDERS' EQUITY.................................................................................. 182,964 180,712
--------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................................................................. $ 349,185 $363,038
========= ========
See accompanying notes to consolidated financial statements.
F-3
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
Year Ended December 31,
------------------------------------
2002 2001 2000
----------- ----------- -----------
REVENUES:
Oil, natural gas and plant income................ $ 103,064 $ 116,080 102,148
Gain (loss) on sale of properties................ (159) 815 800
Gain (loss) on derivative fair value............. (6,632) 3,081 --
Gain (loss) on derivative settlements............ (5,644) 162 --
Other............................................ 473 836 813
----------- ----------- -----------
TOTAL REVENUES............................... $ 91,102 $ 120,974 $ 103,761
EXPENSES:
Production--
Lease operations............................. $ 14,590 $ 15,957 $ 14,994
Production, severance and ad valorem tax..... 7,271 7,711 6,692
Gathering, transportation and other.......... 3,465 3,002 1,493
Geological and geophysical....................... 2,683 1,172 666
Dry hole and impairments......................... 8,918 12,261 29
Surrendered and expired acreage.................. 860 7,875 --
General and administrative....................... 9,154 6,991 6,141
Stock compensation (general and administrative).. 816 -- --
Interest......................................... 3,962 6,773 7,556
Depreciation, depletion and amortization......... 37,357 30,983 19,779
Other............................................ 629 250 --
----------- ----------- -----------
TOTAL EXPENSES............................... $ 89,705 $ 92,975 $ 57,350
NET INCOME BEFORE INCOME TAXES, MINORITY
INTEREST AND DIVIDENDS TO PREFERRED
STOCKHOLDERS...................................... 1,397 27,999 46,411
Minority Interest................................... -- 511 305
Income Tax Expense.................................. 45 10,640 14,442
----------- ----------- -----------
NET INCOME.......................................... 1,352 16,848 31,664
Dividends to preferred stockholders................. 738 710 1,488
----------- ----------- -----------
NET INCOME ATTRIBUTABLE TO COMMON
STOCKHOLDERS...................................... $ 614 $ 16,138 $ 30,176
=========== =========== ===========
NET INCOME PER COMMON SHARE:
Basic............................................ $ 0.04 $ 1.06 $ 2.91
=========== =========== ===========
Diluted.......................................... $ 0.03 $ 0.91 $ 2.28
=========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic............................................ 16,533,405 15,170,116 10,382,836
=========== =========== ===========
Diluted.......................................... 18,361,956 18,968,973 13,894,961
=========== =========== ===========
See accompanying notes to consolidated financial statements.
F-4
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended
-------------------------------------
December 31, December 31, December 31,
2002 2001 2000
------------ ------------ ------------
OPERATING ACTIVITIES
Net income....................................................................... 1,352 16,848 31,664
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization...................................... 36,758 30,265 18,713
Amortization of debt issue costs and other.................................... 599 967 1,066
Dry hole and impairments...................................................... 8,918 12,261 29
Surrendered and expired leases................................................ 860 7,875 --
(Gain)/Loss on derivative fair value.......................................... 6,632 (3,081) --
(Gain)/Loss on sale of properties............................................. 159 (815) (800)
Deferred income taxes......................................................... (67) 9,017 6,480
Minority interest............................................................. -- 511 305
Restricted stock compensation (general and administrative).................... 816 -- --
Other changes................................................................. 28 166 --
Changes in operating assets and liabilities:..................................
Accounts receivable and other current assets.................................. 3,834 9,961 (21,706)
Account payable and accrued liabilities....................................... (10,087) 5,805 8,717
-------- --------- --------
CASH PROVIDED BY OPERATING ACTIVITIES............................................ 49,802 89,780 44,468
INVESTING ACTIVITIES
Proceeds from sales of oil and gas properties................................. 1,181 36,818 5,840
Acquisition of Magellan Exploration LLC, net of cash acquired................. -- -- 418
Acquisition of Classic Resources, Inc., net of cash acquired.................. -- (58,670) --
Acquisition of Enex Resources Corporation..................................... -- (3,803) --
Acquisition of oil and gas properties......................................... (302) (22,380) (64,612)
Development of oil and gas properties......................................... (56,356) (72,554) (24,091)
Additions of other assets..................................................... (391) (1,930) (1,326)
-------- --------- --------
CASH USED IN INVESTING ACTIVITIES................................................ (55,868) (122,519) (83,771)
FINANCING ACTIVITIES
Proceeds from long-term debt.................................................. 51,000 130,000 66,100
Proceeds from issuance of common stock........................................ -- -- 68,103
Proceeds from exercise of stock options and warrants.......................... 616 1,590 705
Payments on long-term debt.................................................... (60,000) (85,000) (90,600)
Preferred stock dividends..................................................... (738) (525) (1,369)
Treasury stock purchase--Alabama dissenters................................... -- -- (981)
Redemption of Preferred Series C stock........................................ -- -- (1,433)
Debt issuance costs........................................................... (325) -- (2,927)
-------- --------- --------
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES.................................. (9,447) 46,065 37,598
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS................................. (15,513) 13,326 (1,705)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD................................... 17,762 4,436 6,141
-------- --------- --------
CASH AND CASH EQUIVALENTS, END OF PERIOD......................................... $ 2,249 $ 17,762 $ 4,436
======== ========= ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest...................................................................... $ 3,915 $ 6,795 $ 7,539
Income Taxes.................................................................. -- 10,571 3,500
Non-cash investing and financing activities:
Common stock and warrants issued in acquisition of Magellan Exploration LLC... -- -- 10,573
Preferred Stock Series D issued in acquisition of Magellan Exploration LLC.... -- -- 7,453
Preferred Stock Series C conversions to common stock.......................... -- -- 362
Preferred dividends incurred but not paid..................................... 185 185 --
Common stock repurchase contingency accrual--Alabama dissenters............... -- -- 138
Conversion of Preferred Series C into Common Stock............................ -- -- 910
Preferred dividends paid in-kind.............................................. -- -- 118
Liability for redemption of Preferred Stock Series C.......................... -- -- 2,856
Deferred taxes recorded in acquisition of Classic Resources, Inc.............. -- 29,347 --
Preferred Stock Series B conversions to Common Stock.......................... 3,627 -- --
Preferred Stock Series D conversions to Common Stock.......................... 10 -- --
See accompanying notes to consolidated financial statements.
F-5
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(in thousands, except shares)
Preferred Stock
-------------------------------------------------------
Series B Series C Series D Common Stock
----------------- ------------------- --------------- ----------------
Shares Par Shares Par Shares Par Shares Par
-------- ------- ---------- ------- ------- ------ ---------- ----
Balance January 1, 2000...................... 266,667 $ 3,627 1,139,506 $ 5,198 -- -- 5,338,771 $107
Common stock issued in merger with
Magellan Exploration LLC.................... 1,085,934 22
Warrants issued in merger with Magellan
Exploration LLC.............................
Preferred Series D issued in merger with
Magellan Exploration LLC.................... 617,009 7,453
Stockholder dissenters repurchase contingency
adjustment..................................
Preferred Series C conversions............... (72,496) (362) 63,465 1
Common stock issued.......................... 8,050,000 161
Common stock offering and registration
costs.......................................
Preferred Series C redemption................ (1,067,010) (4,836) 36,527 1
Reverse split fractional shares.............. (314)
Employee stock option exercises.............. 95,190 2
Warrant exercises............................ 18,333
Net Income...................................
Preferred stock dividends.................... 4,921 119
-------- ------- ---------- ------- ------- ------ ---------- ----
Balance December 31, 2000.................... 266,667 $ 3,627 -- -- 621,930 $7,572 14,687,906 $294
======== ======= ========== ======= ======= ====== ========== ====
Employee stock option exercises.............. 81,682 2
Preferred Series D Conversions............... (7,154) (87) 7,154
Warrant exercises............................ 283,047 6
Senior subordinated debt conversions......... 1,487,806 29
Net Income...................................
Preferred stock dividends....................
-------- ------- ---------- ------- ------- ------ ---------- ----
Balance December 31, 2001.................... 266,667 $ 3,627 -- $ -- 614,776 $7,485 16,547,595 $331
======== ======= ========== ======= ======= ====== ========== ====
Employee Stock Option Exercises.............. 58,817 1
Preferred Series B Conversions............... (266,667) (3,627) 186,230 4
Preferred Series D Conversions............... (857) (10) 857
Common Stock Issues.......................... 1,799
Restricted Stock Grants...................... 95,000 2
Net Income...................................
Preferred Stock Dividends....................
Employee Stock Option Deferred Tax
Adjustment..................................
Other........................................ (39,726) (1)
-------- ------- ---------- ------- ------- ------ ---------- ----
Balance December 31, 2002.................... -- $ -- -- $ -- 613,919 $7,475 16,850,572 $337
======== ======= ========== ======= ======= ====== ========== ====
Accumulated Treasury
Paid-in Earnings Deferred Stock Stockholders'
Capital (Deficit) Compensation Par Equity
-------- ----------- ------------ -------- -------------
Balance January 1, 2000...................... $ 57,775 $(27,408) $(1,187) $ 38,112
Common stock issued in merger with
Magellan Exploration LLC.................... 10,251 10,273
Warrants issued in merger with Magellan
Exploration LLC............................. 300 300
Preferred Series D issued in merger with
Magellan Exploration LLC.................... 7,453
Stockholder dissenters repurchase contingency
adjustment.................................. 138 138
Preferred Series C conversions............... 361 --
Common stock issued.......................... 67,943 68,104
Common stock offering and registration
costs....................................... (1,497) (1,497)
Preferred Series C redemption................ 547 (4,288)
Reverse split fractional shares.............. --
Employee stock option exercises.............. 648 650
Warrant exercises............................ 55 55
Net Income................................... 31,664 31,664
Preferred stock dividends.................... (1,488) (1,369)
-------- -------- ----- ------- --------
Balance December 31, 2000.................... $136,383 $ 2,768 $ -- $(1,049) $149,595
======== ======== ===== ======= ========
Employee stock option exercises.............. 739 741
Preferred Series D Conversions............... 85 (2)
Warrant exercises............................ 843 849
Senior subordinated debt conversions......... 13,362 13,391
Net Income................................... 16,848 16,848
Preferred stock dividends.................... (710) (710)
-------- -------- ----- ------- --------
Balance December 31, 2001.................... $151,412 $ 18,906 $ -- $(1,049) $180,712
======== ======== ===== ======= ========
Employee Stock Option Exercises.............. 615 616
Preferred Series B Conversions............... 3,623 --
Preferred Series D Conversions............... 10 --
Common Stock Issues.......................... 26 26
Restricted Stock Grants...................... 1,690 (876) 816
Net Income................................... 1,352 1,352
Preferred Stock Dividends.................... (738) (738)
Employee Stock Option Deferred Tax
Adjustment.................................. 181 181
Other........................................ (1)
-------- -------- ----- ------- --------
Balance December 31, 2002.................... $157,557 $ 19,520 $(876) $(1,049) $182,964
======== ======== ===== ======= ========
See accompanying notes to consolidated financial statements
F-6
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
3TEC Energy Corporation, (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).
3TEC Energy Corporation (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. Effective November 23, 1999, the Company acquired oil and
natural gas properties and interests managed by Floyd Oil Company from a group
of private sellers. Effective February 3, 2000, the Company acquired oil and
natural gas properties through a merger with Magellan Exploration, LLC.
Effective May 31, 2000, the Company acquired oil and natural gas properties
from C.W. Resources, Inc. Effective November 15, 2000, the Company acquired oil
and natural gas properties from H.G. Westerman and a group of private sellers.
Effective January 30, 2001, the Company acquired oil and natural gas properties
through the purchase of the stock of Classic Resources, Inc.
On February 2, 2003, the Company entered into a definitive agreement with
Plains Exploration & Production Company ("Plains") whereby Plains will acquire
the Company for a combination of cash and stock. Under the terms of the
agreement, the Company's shareholders will receive $8.50 in cash and 0.85
shares of Plains's Common Stock for each share of the Company's Common Stock,
subject to certain adjustments if the average share price of Plains's Common
Stock (as determined during a twenty-day trading period prior to closing) is
less than $7.65 per share or greater than $12.35 per share. Although subject to
shareholder approval and other customary closing conditions, the aforementioned
transaction is expected to close during the second quarter of 2003.
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
and Enex Resources Corporation ("Enex") which prior to December 31, 2001 was an
80% owned subsidiary. The equity of the minority interests in Enex is reflected
in the consolidated financial statements as "minority interest". On
December 31, 2001, the Company acquired the remaining 20% of Enex pursuant to
the merger of Enex into a wholly-owned subsidiary of the Company for cash
consideration of $3.8 million. All significant intercompany balances and
transactions have been eliminated in consolidation.
Reclassifications
Certain prior-year amounts have been reclassified to conform with current
year presentation.
Consolidated Statements of Cash Flows
For the purpose of cash flows, the Company considers all highly liquid
investments with a maturity date of three months or less to be cash
equivalents. Significant transactions may occur which do not directly affect
cash
F-7
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
balances and as such will not be disclosed in the Consolidated Statements of
Cash Flows. Certain of such non-cash transactions are disclosed in the
Consolidated Statements of Shareholders' Equity relating to shares issued as
compensation, and shares issued for stock and debt of an acquired company.
Oil and Gas Properties
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 an independent petroleum
engineering firm. The Company reviews its undeveloped properties continually
and charges them to expense on a property-by-property basis when it is
determined that they have been condemned by dry holes, or have otherwise
diminished in value. For the years ended December 31, 2002, 2001 and 2000, the
Company recorded surrendered and expired acreage expense on its undeveloped
properties of $0.9 million, $7.9 million and $-0-, respectively. Gains and
losses are recorded on sales of interests in proved properties and on sales of
entire interests in unproved properties. The Company realized losses on sales
of properties of $0.2 million for the year ended December 31, 2002 and gains of
$0.8 million for both years ended December 31, 2001 and 2000.
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 productability 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, 2002, 2001 and 2000, 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 $5.6 million, $3.4
million, and $-0- respectively.
Revenue Recognition of Production Imbalances
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 not-withstanding its ownership percentage. At
December 31, 2002 and 2001, the Company's net imbalance position was immaterial.
Hedging
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS 133"). In June 2000, the FASB issued
SFAS 138, Accounting for Derivative Instruments and Hedging Activities, an
amendment of FASB Statement No. 133. SFAS 133, as amended, establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts)
F-8
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
be recorded in the balance sheet as either an asset or liability measured at
its fair market value. The statement requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge criteria
are met. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in the statement of
operations, and requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting. The
Company adopted SFAS 133 effective January 1, 2001. Based upon the historical
volatility of oil and gas commodity prices, the Company expects that SFAS 133
will increase volatility in the Company's earnings and other comprehensive
income for periods where hedging activities are present.
SFAS 133, in part, allows hedge accounting. SFAS 133 provides that the
effective portion of the gain or loss on a derivative instrument designated and
qualifying as a cash flow hedging instrument be reported as a component of
other comprehensive income and be reclassified into earnings in the same period
during which the hedged forecasted transaction affects earnings. The remaining
gain or loss on the derivative instrument, if any, must be recognized currently
in earnings.
To qualify for cash flow hedge accounting, the cash flows from the hedging
instrument must be highly effective in offsetting changes in cash flows due to
changes in the underlying items being hedged. In addition, all hedging
relationships must be designated, documented, and reassessed periodically. The
Company's natural gas derivative instruments entered into during the periods
presented were not designated as hedges at the time the instruments were
executed. In accordance with provisions of SFAS 133, these instruments were
marked-to-market through earnings at December 31, 2002 and 2001, resulting in a
decrease to revenues of $6.6 million and an increase to revenues of $3.1
million during those annual periods, respectively.
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 reflect dilution from all potential common shares, including
options, warrants and convertible preferred stock and convertible 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.
At December 31, 2002, 2001 and 2000, the Company had a weighted average of
2,442,929, 3,798,857 and 3,512,000 combined stock options, warrants and
convertible preferred stock and notes outstanding included in the Company's
fully diluted per share calculation, respectively.
F-9
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Basic and diluted earnings per share for the years ended December 31, 2002,
2001 and 2000 were determined as follows (in thousands):
2002 2001 2000
------- ------- -------
Basic net income attributable to common shareholders................. $ 614 $16,138 $30,176
Plus preferred stock dividends....................................... -- (1) 710 1,488
Plus interest expense (net of tax) on subordinated convertible notes. -- 505 --
------- ------- -------
Fully diluted net income attributable to common shareholders......... $ 614 $17,353 $31,664
======= ======= =======
Basic shares outstanding (weighted average shares)................... 16,533 15,170 10,383
Plus potentially dilutive securities:
.. Dilutive options and warrants applying treasury stock method.... 1,688 2,052 1,390
.. Shares from conversion of subordinated convertible notes........ 996 1,469
.. Shares from conversion of Series B preferred stock.............. 127 132 91
.. Shares from conversion of Series D preferred stock.............. -- 619 562
.. Non-vested restricted stock..................................... 14 -- --
------- ------- -------
Fully diluted shares outstanding (weighted average shares)........... 18,362 18,969 13,895
======= ======= =======
- --------
(1) Preferred stock dividends in the amount of $738,000 were not included in
the 2002 calculation as they were antidilutive.
All share and per share amounts have been retroactively adjusted for a
one-for-three reverse split that was approved by the Company's shareholders on
January 14, 2000.
Income Taxes
Income taxes are accounted for under the asset and liability method.
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases and operating loss and tax credit carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in income in the period that includes the
enactment date.
Stock Compensation
Stock-based employee compensation is accounted for under the intrinsic value
method of Accounting Principles Bulleting No. 25 "Accounting for Stock Issued
to Employees." For the years ending December 31, 2002, 2001 and 2000, the
exercise price of the options granted is equal to the quoted market price of
the Company's stock at the grant date, and therefore, no compensation costs
have been recognized for its stock option plans. Had compensation cost for the
Company's Plans been determined based on the fair value at the grant date for
stock options granted for the years ending December 31, 2002, 2001 and 2000,
the Company's net income and income per share would have been adjusted to the
pro forma amounts listed below (in thousands, except per share amounts):
F-10
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002 and 2001
December 31,
-------------------------
2002 2001 2000
------- ------- -------
Net Income attributable to Common Stockholders
As Reported....................................................... $ 614 $16,138 $30,176
Add: Stock-based employee compensation expense included and
reported in net income, net of tax.............................. 530 -- --
Less: Total stock-based employee compensation expense
determined under fair value based methods for all awards net of
related tax effects............................................. (3,098) (2,691) (8,287)
Pro Forma......................................................... $(1,954) $13,447 $21,889
Net Income per common share, basic
As Reported....................................................... $ 0.04 $ 1.06 $ 2.91
Pro Forma......................................................... $ 0.04 $ 0.89 $ 2.11
Net Income per common share, diluted
As Reported....................................................... $ 0.03 $ 0.91 $ 2.28
Pro Forma......................................................... $ 0.03 $ 0.77 $ 1.58
The fair value of grants was estimated on the date of grant using the Black
Scholes option pricing model with the following weighted-average assumptions
used in 2002, 2001 and 2000, respectively: risk free interest rates of 4.30%,
3.96% and 6.48%, expected volatility of 65%, 69% and 72%, no dividend yield,
and an expected life of the option of 3 years in 2002, 2001 and 2000. The
weighted average fair value of stock options granted in 2002, 2001 and 2000 was
$6.33, $7.02 and $5.72 per share, respectively.
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 purchasers, and is typical
in the industry. Concentrations within the industry have the potential to
impact the Company's overall exposure to credit risk, either positively or
negatively, in that the customer base may be similarly affected by changes in
economic, industry or other conditions. For 2002, Superior Natural Gas
Corporation, Conoco Inc. and Wagner & Brown, Ltd. accounted for approximately
15%, 14% and 11% of total oil and gas sales, respectively. Calpine Producer
Services, L.P. (formerly Highland Energy Company) and Wagner & Brown, Ltd.
accounted for approximately 22% and 19% of total oil and natural gas sales,
respectively, for the year ended December 31, 2001. No single customer
accounted for greater than 10% of the Company's total oil and natural gas sales
for the year ended December 31, 2000.
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 these estimates.
F-11
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Accounting Pronouncements
In October, 2001, the FASB issued SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, which addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. While SFAS 144
supersedes SFAS 121, Accounting for the Impairment of Long-Lived Assets and for
Long Lived Assets to Be Disposed Of, it retains many of the fundamental
provisions of that Statement.
SFAS 144 also supersedes the accounting and reporting provisions of APB
Opinion No. 30, Reporting the Results of Operations - Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions, for the disposal of a segment
of business. However, it retains the requirement in Opinion 30 to report
separately discontinued operations and extends that reporting to a component of
an entity that either has been disposed of (by sale, abandonment, or in a
distribution to owners) or is classified as held for sale. By broadening the
presentation of discontinued operations to include more disposal transactions,
the FASB has enhanced managements ability to provide information that helps
financial statement users to assess the effects of a disposal transaction on
the ongoing operations of an entity.
In August, 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations". SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. The standard applies to legal
obligations associated with the retirement of long-lived assets that result
from the acquisition, construction, development and (or) normal use of the
asset. SFAS 143 requires that the fair value of a liability for an asset
retirement obligation be recognized in the period in which it is incurred if a
reasonable estimate of fair value can be made. The fair value of the liability
is added to the carrying amount of the associated asset and this additional
carrying amount is depreciated over the life of the asset. The liability is
accreted at the end of each period through charges to operating expense. If the
obligation is settled for other than the carrying amount of the liability, the
Company will recognize a gain or loss on settlement. The Company adopted SFAS
No. 143 as of January 1, 2003. Upon adoption of this statement, the Company
expects to record a cumulative effect accounting adjustment of between $0.1
million and $1.0 million, net of deferred tax expense of between $0.03 million
and $0.5 million. Additionally, the Company expects to establish a liability
for asset retirement obligations of between $4.0 million and $6.0 million, a
corresponding increase in property, plant and equipment of between $3.0 million
and $5.0 million and a decrease in accumulated DD&A of between $0.1 million and
$1.0 million in the Company's balance sheets.
During second quarter 2002 the FASB issued SFAS No. 145, Rescission of FASB
Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, and requires that all gains and losses from
extinguishment of debt should be classified as extraordinary items only if they
meet the criteria in APB No. 30. Applying APB No. 30 will distinguish
transactions that are part of an entity's recurring operations from those that
are unusual or infrequent or that meet the criteria for classification as an
extraordinary item. Any gain or loss on extinguishment of debt that was
classified as an extraordinary item in prior periods presented that does not
meet the criteria in APB No. 30 for classification as an extraordinary item
must be reclassified. The Company does not expect that there will be any
current impact from SFAS No. 145.
The FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities, in June 2002. This statement addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring).
F-12
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
SFAS No. 146 applies to costs incurred in an "exit activity," which includes,
but is not limited to, a restructuring, or a "disposal activity" covered by
SFAS No. 144. SFAS No. 146 will be effective for the Company in January 2003.
In December 2002, SFAS No. 148, "Accounting for Stock-Based
Compensation--Transition and Disclosure--an amendment of FASB Statement No.
123" was issued. SFAS 148 amends SFAS 123, "Accounting for Stock-Based
Compensation", to provide alternative methods of transition for a voluntary
change to the fair value based method of accounting for stock-based employee
compensation. In addition, this Statement amends the disclosure requirements of
SFAS 123 to require prominent disclosures in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results. The provisions of SFAS
148 are effective for financial statements for fiscal years ending after
December 15, 2002. SFAS 148 does not change the provisions of SFAS 123 that
permit entities to continue to apply the intrinsic value method of Accounting
Principles Bulletin No. 25, "Accounting for Stock Issued to Employees". We have
and will continue to account for stock-based compensation in accordance with
the provisions of APB No. 25.
During 2002, the FASB issued two interpretations: FIN 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" and FIN 46 "Consolidation of Variable
Interest Entities". There was no current impact of FIN 45 or FIN 46 on the
Company's financial position or results of operations.
(2) ACQUISITIONS AND DIVESTITURES
On January 30, 2001, the Company acquired 100% of the issued and outstanding
stock of Classic Resources Inc. (the "Classic Acquisition") for cash
consideration of approximately $53.5 million plus other acquisition costs. The
operating results of the Classic Acquisition have been included in the
consolidated financial statements since that date. Classic was a privately-held
exploration and production company with properties located in East Texas. The
Company's estimate of total net proved reserves at the time of the acquisition
for Classic's oil and gas properties was 47 Bcfe and net daily production of
approximately 11 Mmcfe. The Company financed the acquisition under its existing
Credit Facility. The purchase price of the Classic Acquisition was allocated
principally to proved properties, with additional amounts allocated to working
capital related to amounts recorded for production related receivables and
payables in existence and accrued for at January 30, 2001.
On May 31, 2000, we completed the acquisition of the CWR Properties (the
"CWR Acquisition") located in East Texas for cash consideration of
approximately $51.7 million. Operating results from this acquisition are
included in the Company's consolidated financial statements beginning June 1,
2000. The CWR Acquisition was financed under our existing Credit Facility,
which we amended prior to closing the acquisition. The total purchase price was
allocated principally to oil and natural gas properties using the purchase
method of accounting.
On February 3, 2000, we completed the acquisition of Magellan Exploration
LLC (the "Magellan Acquisition"), from certain affiliates of EnCap Investments
L.L.C. ("EnCap"), a Delaware limited liability company and an investor in W/E
LLC, 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) 617,009 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 total purchase price of
approximately $19 million was allocated principally to proved undeveloped oil
and natural gas properties using the purchase method of accounting.
F-13
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
The following pro forma data presents the results of the Company for the
year ended December 31, 2000, as if the Classic Acquisition and the CWR
Acquisition had occurred on January 1, 2000, and the results of the Company for
the year ended December 31, 2001 as if the Classic Acquisition had occurred on
January 1, 2001. The unaudited pro forma data assumes the acquisition of the
respective properties and the debt financing transactions related to these
acquisitions. The unaudited 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. (in
thousands, except per share amounts):
Pro Forma Pro Forma
Year Ended Year Ended
December 31, 2001 December 31, 2000
----------------- -----------------
(unaudited) (unaudited)
Total revenues................................... $120,008 $120,662
Net income attributable to common stockholders... 13,958 24,266
Net income per basic share attributable to common
stockholders................................... $ 0.92 $ 2.34
During 2001, the Company completed the sale of certain non-strategic oil and
gas properties for net cash proceeds of approximately $36.7 million. In order
to defer the tax gain on the sales of the properties, the Company successfully
replaced a portion of these properties in accordance with the Like-Kind
Exchange regulations of the Internal Revenue Service. At December 31, 2001, the
Company had $13.9 million of cash in like-kind escrow accounts. In January
2002, the like-kind replacement term expired in accordance with the Internal
Revenue Service regulations and the balance of the escrow accounts were used to
reduce borrowings under the Company's Credit Facility.
(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 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 was EnCap. The sole member of EnCap is El
Paso Field Services Company, a Delaware corporation ("El Paso Field Services").
The controlling person of El Paso Field Services is El Paso 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 6).
On November 28, 2001, W/E LLC was dissolved and all shares of common stock
and warrants of the Company held by W/E LLC were distributed to its members.
(4) RELATED PARTY TRANSACTIONS
David B. Miller and D. Martin Phillips, directors of the Company, are
managing directors of EnCap, which was the controlling person of W/E LLC. Floyd
C. Wilson, Chairman and Chief Executive Officer of the Company, was also a
member of W/E LLC. Gary R. Christopher, a shareholder and director of the
Company until December 31, 2001, is employed by Kaiser-Francis Oil Co., which
owns approximately 7% of the common stock of the Company as of December 31,
2002.
F-14
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
In 2000, the Company paid EnCap a fee of $500,000 in connection with a
private equity shelf facility related to the CWR Acquisition. As required by
the Company's Credit Facility, the private equity shelf facility would have
allowed the Company to require EnCap Investments to purchase up to $20 million
of a new class of exchangeable preferred stock from the Company. Upon
completion of the Company's public offering of common stock on June 30, 2000,
the shelf facility expired.
The Company has a $250 million credit facility (the "Credit Facility") with
Bank One, NA, as administrative agent, Bank of Montreal, as syndication agent,
and Union Bank of California, N.A., Wells Fargo Bank Texas, N.A., CIBC, Inc.,
Comerica Bank, Fleet National Bank and The Bank of Nova Scotia as participating
lenders. The borrowing base is redetermined semi-annually and as of December
31, 2002, was $160 million. In addition, the Company is a party to certain
derivative contracts that Bank One, NA is the counterparty to. These derivative
contracts cover a portion of the Company's anticipated natural gas and oil
production for 2003 and 2004. Larry L. Helm, a director of the Company, is
responsible for the nationwide Middle Market Banking Group of Bank One
Corporation.
(5) LONG-TERM DEBT
Long-term debt at December 31, 2002 and 2001, consisted of the following (in
thousands):
2002 2001
------- --------
$250 million Credit Facility............... $99,000 $108,000
Less current maturities.................... -- --
------- --------
Long-term debt excluding current maturities $99,000 $108,000
======= ========
The Company's Credit Facility is with Bank One, NA as agent and seven other
banks. The Credit Facility as amended, matures August 31, 2004. As of December
31, 2002, the borrowing base was $160 million. The borrowing base is to be
redetermined semi-annually on May 1 and November 1 and provides for interest as
revised under the Credit Facility to accrue at a rate calculated at the
Company's option as either the bank's prime rate plus a low of zero to a high
of 37.5 basis points or LIBOR plus basis points increasing from a low of 150 to
a high of 200 as loans outstanding increase as a percentage of the borrowing
base. As of December 31, 2002, the Company was paying an average of 2.99% per
annum interest on the principal balance of $99 million under the Credit
Facility. Prior to maturity, no payments of principal are required so long as
the borrowing base exceeds the loan balance. The borrowings under the Credit
Facility are secured by substantially all of the Company's oil and natural gas
properties. At December 31, 2002, the amount available to be borrowed under the
Credit Facility was approximately $61 million.
The Credit Facility is governed by various financial and other covenants,
including requirements to maintain a current ratio of one to one (1:1), and an
interest rate coverage ratio of 2.5 to 1. Additionally, limitations on asset
dispositions, declaration and payment of cash dividends and the entering into
hedge transactions without the bank's consent are included. Aggregate amounts
of expected required repayments of long term debt at December 31, 2002 are as
follows (in thousands):
2002...... $ --
2003...... --
2004...... 99,000
Thereafter --
-------
Total.. $99,000
=======
F-15
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
(6) SENIOR SUBORDINATED CONVERTIBLE NOTES
On August 27, 1999, senior subordinated convertible promissory notes (the
"Senior Subordinated 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 $0.2 million, respectively. On October 19, 1999, $2.4 million
of Senior Subordinated Notes were sold to The Prudential Insurance Company of
America ("Prudential"). The Senior Subordinated Notes bore interest at an
annual rate of 9%. Interest was payable beginning on December 31, 1999, every
March 31, June 30, September 30 and December 31, until maturity on August 27,
2004. The Company could defer payment of fifty percent (50%) of the first eight
quarterly interest payments. The Senior Subordinated Notes could be prepaid,
without premium or penalty, in whole or in part, at any time after August 27,
2001. The holders of the Senior Subordinated Notes could 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 could 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 would be immediately due and payable.
The Senior Subordinated Notes ranked senior in right of payment to all
Company notes and indebtedness other than the Credit Facility.
During the second quarter of 2001, the Company received notice of an
election by Shoemaker to convert approximately $0.2 million of Senior
Subordinated Notes. The conversion resulted in the retirement of $0.2 million
in senior subordinated debt and the issuance of an additional 16,666 shares of
common stock of the Company.
During the third quarter of 2001, the Company sent notice of an election to
W/E LLC to prepay the $10.7 million of Senior Subordinated Notes. Pursuant to
the terms of the convertible note agreement, W/E LLC elected instead to
exercise its right to convert the principal and accrued interest outstanding
into common shares of the Company. Under the terms of the convertible note
agreement, the balance of the note plus any accrued interest was to be
converted at $9.00 per share. The conversion by W/E LLC resulted in the
retirement of approximately $10.7 million in senior subordinated debt and the
issuance of an additional 1,206,127 shares of common stock of the Company.
During the fourth quarter of 2001, the Company received notice of an
election by Prudential to convert approximately $2.4 million of Senior
Subordinated Notes. The conversion resulted in the retirement of $2.4 million
in senior subordinated debt and the issuance of an additional 265,013 shares of
common stock of the Company.
(7) INCOME TAXES
The components of income tax expense for the years ended December 31, 2002,
2001 and 2000 consisted of the following (in thousands):
2002 2001 2000
-------------------- ---------------------- ----------------------
Federal State Total Federal State Total Federal State Total
------- ----- ----- ------- ------ ------- ------- ------ -------
Current.. $ 438 $ 179 $ 617 $1,143 $ 479 $ 1,622 $ 6,120 $1,842 $ 7,962
Deferred. (427) (146) (573) 7,582 1,436 9,018 6,224 256 6,480
----- ----- ----- ------ ------ ------- ------- ------ -------
Total. $ 11 $ 33 $ 44 $8,725 $1,915 $10,640 $12,344 $2,098 $14,442
===== ===== ===== ====== ====== ======= ======= ====== =======
F-16
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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):
December 31,
-----------------------
2002 2001 2000
----- ------- -------
Income tax provision at statutory rate.... $ 489 $ 9,800 $16,137
State income taxes, net of federal benefit 70 1,224 1,364
Decrease in valuation allowance........... -- -- (2,523)
Utilization of Sec. 29 tax credits........ (500) (500) (400)
Other..................................... (15) 116 (136)
----- ------- -------
Total.................................. $ 44 $10,640 $14,442
===== ======= =======
The Company's net deferred tax liability at December 31, 2002 and 2001 is as
follows (in thousands):
2002 2001 2000
------- ------- -------
Deferred tax liability
Basis difference in oil and natural gas properties. $45,709 $47,563 $ 9,547
------- ------- -------
Deferred tax asset
NOL carryforward................................... (3,868) (5,237) (5,812)
AMT tax credit carryforward........................ (4,367) (327) (36)
Other.............................................. (408) (430) (495)
------- ------- -------
(4,712) (5,994) (6,343)
Valuation allowance................................ 3,566 3,566 3,566
------- ------- -------
Net deferred tax liability............................ $44,563 $45,135 $ 6,770
======= ======= =======
In connection with the Classic Acquisition, the Company recorded $29.3
million in deferred taxes for the future tax impact of the difference between
the allocated book basis and the historical tax basis of the Classic Properties.
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, 2002,
2001 and 2000. The net change in the total valuation allowance for the years
ended December 31, 2002, 2001 and 2000 was $-0-, $-0- and $2.5 million and the
amount remaining at December 31, 2002 is $3.6 million.
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 these changes, the Company's use of its net
operating loss carryforwards subsequent to that date will be limited. In
February 2000, Enex had an ownership change pursuant to Section 382 with
respect to its net operating losses.
F-17
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
As of December 31, 2002, the Company had net operating loss carryforwards of
approximately $11.1 million, expiring beginning in 2009 through 2019.
(8) 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 the maximum employee contributions
permissible under the Internal Revenue Code and discretionary Company
contributions. Company contributions made to the plan for the years ending
December 31, 2002, 2001 and 2000 were $365,172, $462,763 and $135,225,
respectively.
(9) STOCK OPTION PLANS
The Company's stock option plans authorize the granting of options to key
employees and non-employee directors at prices equivalent to the market value
at the date of grant. Options generally become exercisable in the following
manner: 50% upon the date of grant with the remaining 50% exercisable in three
annual installments commencing one year after the date of grant and, if not
exercised, expire 10 years from the date of grant.
A summary of the status of the Company's plans as of December 31, 2002, 2001
and 2000, and changes during the years ended on those dates is presented below:
Average Exercise
Shares Price Per Share
--------- ----------------
Options outstanding at January 1, 2000.......... 335,922 $15.00
Granted in 2000.............................. 2,898,500 $11.07
Exercised in 2000............................ (95,190) $ 6.83
Forfeited in 2000............................ (248,160) $16.39
--------- ------
Options outstanding at January 1, 2001 2,891,072 $11.15
Granted in 2001.............................. 502,835 $14.67
Exercised in 2001............................ (81,682) $ 9.12
Forfeited in 2001............................ (36,729) $18.53
--------- ------
Options outstanding at January 1, 2002.......... 3,275,496 $11.66
Granted in 2002.............................. 269,500 $13.71
Exercised in 2002............................ (58,817) $10.54
Forfeited in 2002............................ (14,833) $16.50
--------- ------
Options outstanding at December 31, 2002........ 3,471,346 $11.82
Options outstanding at December 31, 2001........ 3,275,496 $11.66
Options outstanding at December 31, 2000........ 2,891,072 $11.15
Options exercisable at December 31, 2002........ 2,605,528 $11.49
Options exercisable at December 31, 2001........ 2,058,765 $11.45
Options exercisable at December 31, 2000........ 1,442,995 $11.16
Options available for grant at December 31, 2002 757,360
Options available for grant at December 31, 2001 1,012,527
Options available for grant at December 31, 2000 275,298
- --------
At December 31, 2002, the range of exercise prices and weighted average
remaining contractual life of options outstanding was $4.50 to $18.56 and 7.9
years, respectively.
F-18
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
Warrants to purchase 1,216,822 shares and 266,226 shares of common stock at
$3.00 per share, which were issued on August 27, 1999 and October 19, 1999,
respectively, and warrants to purchase 333,333 shares of common stock at $30.00
per share, which were issued on February 3, 2000, are excluded from the table
above because the warrants were issued in conjunction with the sales of stock
and are not stock-based compensation. During 2002, no warrants were exercised.
(10) STOCKHOLDERS' EQUITY
Preferred Stock--Series B
In connection with the merger with 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. During the first quarter of 2002, 58,762
shares of Series B were converted into 34,065 shares of Company Common Stock
("Common"). On December 31, 2002, the remaining 207,905 Series B shares were
converted into 152,165 shares of Common. The conversion calculation was
calculated as 88,889 shares plus the result of multiplying (i) (the value of
approximately 40,000 net mineral acres owned by the Company in South Louisiana
(the "Mineral Acres") minus $2,000,000) divided by $8,000,000 times (ii)
355,555.
Preferred Stock--Series C
On August 31, 2000, the Company sent notices to the holders of its Series C
Preferred Stock (the "Series C") advising that the Series C would be redeemed
on September 30, 2000. The Series C had a redemption price of $5.00 per share
and the holders had the right to convert their Series C shares into Company
common stock at a ratio of one share of common for three shares of Series C
prior to September 30, 2000. A total of 2,101,827 shares of the Series C were
outstanding on September 30, 2000 with 1,293,521 (62%) held by the Company's
then 80% owned subsidiary, Enex. 109,580 Series C shares were converted to
36,527 shares of common stock and approximately 1,992,247 Series C shares were
redeemed. On a consolidated basis, the Company's initial liability for the
Series C redemption was approximately $4.8 million. As a result of the Series C
redemption, the Company recognized a charge to dividend expense in 2000 of
$498,706. At December 31, 2002, the remaining liability was $1.3 million.
Preferred Stock--Series D
On February 3, 2000, we completed the Magellan Acquisition, from certain
affiliates of EnCap and an investor in W/E LLC, 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) 617,009 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 total purchase price of approximately $19 million was allocated
principally to proved undeveloped oil and natural gas properties. During 2002,
857 shares of the Series D were converted to common stock.
Common Stock
On June 30, 2000, the Company completed its public offering of 8.05 million
shares of the Company's common stock (priced at $9.00 per share). The net
proceeds, approximately $66.6 million, were used primarily to repay a portion
of the outstanding debt under the then existing Credit Facility.
On January 14, 2000, the Company's stockholders voted to affect a
one-for-three reverse split of the Company's common stock for the stockholders
of record on December 9, 1999. The par value of these shares
F-19
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
was transferred to additional paid-in capital. All common share and earnings
per common share amounts have been retroactively restated in the accompanying
consolidated financial statements to reflect the reverse stock split.
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 $0.9 million.
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 $0.2
million (See Notes 3 and 6).
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 6).
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 were 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. At December 31, 2001, 1,200,000
warrants were exercisable. As a result of the conversion of the entire
principal balance of the Senior Subordinated Notes during 2001, all of the
warrants became immediately exercisable. During 2002, no warrants were
exercised.
On February 3, 2000, the Company 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 Company 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
performance based "back-in" working interest of 5% of Magellan's interest in 12
exploration prospects. During 2002, no warrants were exercised. At December 31,
2002, 333,333 warrants were exercisable.
Restricted Stock
During May 2002, the Company issued 95,000 shares of restricted stock to
certain members of the Company's management valued at $1.6 million. During the
year ended December 31, 2002, the Company recognized approximately $0.8 million
as restricted stock compensation expense and will recognize the remaining $0.8
million over the remaining service and vesting periods of two years. Of the
95,000 shares that were issued, 10,832 shares had vested and were outstanding
as of December 31, 2002. The remaining shares will vest either over a two-year
period, when the Company's stock price meets a certain price target or when
there is a change of control, as defined by the plan documents.
(11) COMMITMENTS AND CONTINGENCIES
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, 1999
meeting, the Company received shareholder dissents representing ownership of
99,438 shares of common stock. Over the period December 15,
F-20
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
1999 to January 25, 2000, the Company received formal demands for payment from
the dissenting shareholders (the "dissenters"). At December 31, 1999 the
Company had accrued the estimated cash payment to the dissenters of
approximately $1.1 million. The Company made an offer to the dissenters on
March 14, 2000 and the dissenters made a counteroffer in late March. On May 26,
2000, the Company agreed to a settlement with the dissenters for them to
surrender 62,549 shares of common stock for a total of $980,800, including
interest. The settlement closed on June 30, 2000 and the shares are held by the
Company as treasury stock. A shareholder holding 36,889 shares of common stock
agreed to withdraw his dissent.
On October 7, 1994, J.B. Hanks Co., Inc. ("Hanks") filed litigation in the
21st Judicial District, Parish of Livingston, State of Louisiana against Shore
Oil Company ("Shore"), which merged with Middle Bay on June 30, 1997, seeking
specific performance of a July, 1994 Agreement of Purchase and Sale (the
"Agreement"). On the same date, Shore filed suit against Hanks in the 129th
Judicial District, County of Harris, State of Texas also seeking specific
performance of the Agreement. Hanks alleges that Shore failed to comply with
the Agreement inasmuch as Hanks contended that royalties on certain of the oil
and gas leases had not been properly paid. The petition alleges that at the
time of the contemplated transaction, Shore was in an overproduced position
with respect to the taking of gas on the allegedly affected oil and gas leases
and that instead of Shore paying royalties based on actual production,
royalties were paid based on entitlements. Despite having received no demand
from the particular lessors, Hanks claimed that Shore was in violation of the
oil and gas leases; an assertion that Shore denies. On November 15, 1994, the
parties entered into a standstill agreement which dismissed both actions.
Nearly two (2) years after the dismissal Hanks informed Shore that the royalty
problems alleged by Hanks had been cured by the passage of time and that Hanks
was therefore prepared to purchase the property in accordance with the
Agreement. Shore refused to comply. Both parties again filed suit. The
Louisiana litigation was removed to Federal District Court where the matter
will be decided. In October 2002, the parties attempted to mediate their
dispute. A settlement was not reached. The Company intends to vigorously pursue
the defense of this matter. In the opinion of management, the ultimate
resolution of this lawsuit will not have a material adverse effect on the
Company's financial position or results of operations.
The Company has commitments for operating leases (primarily for office space
in Houston, Texas). Rental expense for office space was $1,135,485 in 2002 and
$670,842 in 2001. Future minimum lease commitments at December 31, 2002 are
$1,255,546 in 2003; $1,285,412 in 2004; $884,171 in 2005; $847,822 in 2006; and
$1,769,192 in years thereafter.
(12) FINANCIAL INSTRUMENTS
Oil and Natural Gas Derivatives
During February 2002, the Company unwound the floor portion of the April
through October 2002 collar for net proceeds of approximately $5.8 million
($0.48/Mmbtu), and then re-swapped the 56,000 Mmbtu of daily natural gas
production for the same period at $2.56/Mmbtu. Also during February 2002, the
Company put in place a collar on 20,000 Mmbtu of daily gas production from
November 2002 to March 2003 with a floor of $3.20/Mmbtu and a weighted average
ceiling of $3.53/Mmbtu.
F-21
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
The following table details the Company's derivative contract positions
which were in place at December 31, 2002, which had a fair value liability of
$3.5 million at that date.
Natural Gas Derivatives
-----------------------
Mmbtu Total NYMEX
Period Per Day Mmbtu Type Price
------ ------- --------- ---- -----
January 2003-March 2003 20,000 3,020,000 Put $3.20
January 2003-March 2003 10,000 1,510,000 Call $3.40
January 2003-March 2003 20,000 3,020,000 Call $3.60
Through December 31, 2002, the Company has paid net cash settlements of
approximately $11.4 million related to its derivative activities. The $5.8
million gain from the sale of the put floor and the $11.4 million of net cash
paid for settlements on the derivative activities have been included in the
statement of operations as loss on derivative settlements.
Counterparty Risk
The Company's counterparties to the derivative contracts open at December
31, 2002 are Bank One, NA and Bank of Montreal, both commercial banks who are
also participants in the Company's Credit Facility. We feel the credit
worthiness of our current counterparties is sound and do not anticipate any
non-performance of contractual obligations.
F-22
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
(13) QUARTERLY FINANCIAL DATA (Unaudited)
The following unaudited summarized quarterly financial data is presented in
thousands, except per share data.
2002
------------------------------------
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
-------- -------- -------- --------
Total Revenues............................. $ 3,589 $31,820 $23,887 $ 31,806
Operating Income (loss).................... (14,179) 8,651 3,732 3,193
Net Income (loss).......................... (8,648) 5,277 2,277 2,447
Net Income (loss) per share (fully diluted) $ (0.54) $ 0.27 $ 0.12 $ 0.12
2001
------------------------------------
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
-------- -------- -------- --------
Total Revenues............................. $ 44,296 $39,879 $17,530 $ 19,269
Operating Income (loss).................... 26,294 21,495 (766) (19,024)
Net Income (loss).......................... 16,177 13,209 (915) (11,623)
Net Income (loss) per share (fully diluted) $ 0.86 $ 0.70 $ (0.07) $ (0.72)
2000
------------------------------------
1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.
-------- -------- -------- --------
Total Revenues............................. $ 17,609 $21,986 $26,893 $ 37,273
Operating Income........................... 4,764 7,505 13,852 20,290
Net Income................................. 3,116 4,914 9,085 14,549
Net Income per share (fully diluted)....... $ 0.35 $ 0.50 $ 0.50 $ 0.93
The financial results of the Company have been restated for the first and
second quarters of 2001. The changes reflect adjustments to oil and natural gas
production and revenues as a result of the Company's overaccrual of revenue
related to these quarters. The impact of the adjustments decreased the
previously reported amounts as follows (in thousands):
2001
-----------------
1st Qtr. 2nd Qtr.
-------- --------
Total Revenues....................... $4,345 $3,494
Cost and operating expenses.......... 693 961
Operating Income..................... 3,652 2,533
Net Income........................... 2,272 1,571
Net Income per share, (fully-diluted) 0.12 0.08
F-23
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
(14) 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, 2002 and 2001 and costs incurred
in oil and natural gas property acquisition, exploration and development
activities (in thousands) for the years ended December 31, 2002, 2001 and 2000.
2002 2001 2000
--------- -------- --------
Capitalized Costs
Proved properties................................................ $ 421,512 $374,449 $263,801
Nonproducing leasehold........................................... 14,079 10,974 6,477
Accumulated depreciation, depletion, amortization and impairment. (111,238) (70,299) (54,260)
--------- -------- --------
Net capitalized costs........................................ $ 324,353 $315,124 $216,018
========= ======== ========
Costs Incurred
Proved properties................................................ $ 302 $ 75,766 $ 79,770
Unproved properties.............................................. -- 8,560 95
Exploration costs................................................ 21,531 11,059 695
Development costs................................................ 37,510 62,668 25,346
--------- -------- --------
Total........................................................ $ 59,343 $158,053 $105,906
========= ======== ========
Depletion, depreciation, amortization and impairment................ $ 42,943 $ 32,982 $ 18,459
========= ======== ========
Estimated Quantities of Reserves
The Company has interests in oil and natural gas properties that are located
principally in Texas, Louisiana, 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.
F-24
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
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 2002, 2001 and 2000, such estimates were prepared by
Ryder Scott Company. 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 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,
2002 and 2001 are summarized as follows:
2002 2001 2000
------------------ ------------------ ------------------
Oil Gas Oil Gas Oil Gas
(MBbls)(1) (MMcf) (MBbls)(1) (MMcf) (MBbls)(1) (MMcf)
---------- ------- ---------- ------- ---------- -------
Proved Reserves
Beginning of year............... 5,337 231,266 10,672 237,693 9,835 159,699
Purchases of reserves in place.. 6 2,282 211 33,712 1,981 85,437
Extensions and discoveries...... 738 21,066 308 11,547 51 2,699
Revisions of previous estimates. 1,056 30,189 (1,520) (18,822) 659 8,698
Sales of reserves in place...... (101) (130) (3,382) (10,512) (715) (1,076)
Production for the year......... (828) (25,647) (952) (22,352) (1,139) (17,764)
----- ------- ------ ------- ------ -------
End of year................. 6,208 259,026 5,337 231,266 10,672 237,693
===== ======= ====== ======= ====== =======
Proved Developed Reserves
Beginning of year............... 4,705 175,659 9,895 177,252 9,358 122,914
===== ======= ====== ======= ====== =======
End of year..................... 5,546 205,301 4,705 175,659 9,895 177,252
===== ======= ====== ======= ====== =======
- --------
(1) Includes oil, condensate and plant product barrels.
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.
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.
F-25
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2002, 2001 and 2000
The standardized measure of discounted future net cash flows relating to
proved oil and natural gas reserves for the years ended December 31, 2002, 2001
and 2000 are summarized as follows (in thousands):
2002 2001 2000
---------- --------- ----------
Future cash inflows..................................... $1,285,657 $ 628,537 $2,349,534
Future production costs................................. (284,860) (188,783) (301,344)
Future development costs................................ (53,127) (54,418) (51,359)
Future income tax expenses.............................. (277,372) (58,051) (676,227)
---------- --------- ----------
Future net cash flows................................... 670,298 327,285 1,320,604
10% discount to reflect timing of cash flows............ (320,858) (145,686) (627,930)
---------- --------- ----------
Standardized measure of discounted future net cash flows $ 349,440 $ 181,599 $ 692,674
========== ========= ==========
3TEC anticipates spending $30.3 million in 2003, $12.2 million in 2004 and
$5.5 million in 2005 to develop its proved undeveloped reserves.
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows for the years ended December 31,
2002, 2001 and 2000 (in thousands):
2002 2001 2000
--------- --------- ---------
Sales of oil and natural gas, net of production cost........... $(102,120) $ (89,410) $ (78,969)
Net changes in prices and production cost...................... 244,957 (765,134) 467,920
Changes in estimated future development costs.................. 810 (2,699) (25,849)
Previously estimated development costs incurred during the year 15,364 15,591 5,102
Extensions and discoveries..................................... 77,849 11,388 15,393
Purchases of reserves.......................................... 2,514 26,461 397,280
Sales of reserves.............................................. (1,503) (22,682) (8,789)
Revisions of previous quantity estimates....................... 62,484 (24,809) 39,442
Net change in income taxes..................................... (130,153) 322,700 (304,816)
Accretion of discount.......................................... 21,235 104,736 19,843
Changes in production rates (timing) and other................. (23,596) (87,217) 17,376
--------- --------- ---------
Change for year................................................ $ 167,841 $(511,075) $ 543,933
========= ========= =========
The period end prices of oil and natural gas at December 31, 2002, 2001 and
2000, used in the above table were $31.20, $19.84 and $25.31 per barrel of oil
and $4.79, $2.57 and $9.40 per thousand cubic feet of natural gas, respectively.
F-26