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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
-------------------------------------------------------------------
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
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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 prope