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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2002
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ____________ to ____________.
Commission File No. 1-12508
MAGNUM HUNTER RESOURCES, INC.
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(Exact name of registrant as specified in its charter)
Nevada 87-0462881
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039
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(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (972) 401-0752
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class Name of each exchange on which registered
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Common Stock ($.002 par value) New York Stock Exchange
Securities registered under Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclose of delinquent filers pursuant to Item 405 of
regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether registrant is an accelerated filer (as defined in
Rule 12b-2 of the Act). Yes [X] No [ ]
As of June 28, 2002, the aggregate market value of voting stock held by
non-affiliates, computed by reference to the closing price as reported by the
New York Stock Exchange, was $540,228,276.
The number of shares outstanding of the registrant's common stock at March 21,
2003 was 67,255,584.
TABLE OF CONTENTS
SECURITIES AND EXCHANGE COMMISSION
ITEM NUMBER AND DESCRIPTION
PART I
Item 1. Business............................................................................... 1
The Company............................................................................ 1
Business Strategy...................................................................... 2
Properties............................................................................. 3
Development and Exploration Activities................................................. 9
Gathering and Processing of Gas........................................................ 10
Marketing of Production................................................................ 11
Petroleum Management and Consulting Services........................................... 11
Competition............................................................................ 12
Regulations............................................................................ 12
Employees.............................................................................. 14
Facilities............................................................................. 14
Risk Factors........................................................................... 15
Item 2. Description of Properties.............................................................. 20
Oil and Gas Reserves................................................................... 20
Oil and Gas Production, Prices and Costs............................................... 23
Drilling Activity...................................................................... 24
Oil and Gas Wells...................................................................... 25
Oil and Gas Acreage.................................................................... 26
Item 3. Legal Proceedings...................................................................... 26
Item 4. Submission of Matters to a Vote of Security Shareholders............................... 26
PART II
Item 5. Market for Common Equity and Related Stockholder Matters............................... 26
Item 6. Selected Financial Data................................................................ 27
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.. 30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................. 45
Item 8. Financial Statements and Supplementary Data............................................ 48
Item 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosure.... 49
PART III
Item 10. Directors and Executive Officers of the Registrant..................................... 50
Item 11. Executive Compensation................................................................. 54
Item 12. Security Ownership of Certain Beneficial Owners and Management......................... 57
Item 13. Certain Relationships and Related Transactions......................................... 58
Item 14. Controls and Procedures................................................................ 58
Glossary............................................................................... 59
Item 15. Exhibits, Financial Statement Schedule and Reports on Form 8-K......................... 61
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This document includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements, other than statements of historical facts,
included in this document that address activities, events or developments that
we expect, project, believe or anticipate will or may occur in the future are
forward-looking statements. These include such matters as:
. future stock market valuations;
. repayment of debt;
. business strategies;
. expansion and growth of operations after the merger with Prize
Energy Corp.; and
. future operating results and financial condition.
We have based these statements on our assumptions and analyses in light of our
experience and perception of historical trends, current conditions, expected
future developments and other factors we believe are appropriate in the
circumstances. These statements are subject to a number of assumptions, risks
and uncertainties, including:
. general economic and business conditions;
. prices of crude oil, natural gas and natural gas liquids and
industry expectations about future prices;
. the business opportunities, or lack of opportunities, that may be
presented to and pursued by us; and
. changes in laws or regulations.
These factors are in addition to the risks described in the "Risk Factors" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" sections of this document. Most of these factors are beyond our
control. We caution you that forward-looking statements are not guarantees of
future performance and that actual results or developments may differ materially
from those projected in these statements. You should not place undue reliance on
forward-looking statements. Each forward-looking statement speaks only as of the
date of the particular statement, and we undertake no obligation to publicly
update or revise any forward-looking statements.
ITEM 1. BUSINESS
THE COMPANY
In this Annual Report on Form 10K, the words "Magnum Hunter", "company", "we",
"our", and "us" refer to Magnum Hunter Resources, Inc., and its consolidated
subsidiaries unless otherwise stated or the context otherwise requires.
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K, registration statements and other items with the Securities
and Exchange Commission (SEC). We provide access free of charge to all of these
SEC filings, as soon as reasonably practicable after filing, on our Internet
site located at www.magnumhunter.com. In addition, the public may read and copy
any materials we file with the SEC at the SEC's Public Reference Room at 450
Fifth Street, NW., Washington, D.C. 20549. The public may obtain information on
the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
The SEC maintains an Internet site (www.sec.gov) that contains reports, proxy
and information statements and other information regarding issuers that file
electronically with the SEC.
Magnum Hunter is an independent energy company engaged in the exploration,
exploitation and development, acquisition and operation of oil and gas
properties with a geographic focus in the Mid-Continent Region, Permian Basin
Region, Gulf Coast Region and the Gulf of Mexico. Our management has implemented
a business strategy that emphasizes the acquisition of long-lived proved
reserves with significant exploitation and development opportunities where we
generally can control the operations of the properties.
1
As part of this strategy, from 1996 through 2002, we acquired significant
properties from Burlington Resources Inc. ("Burlington"), Spirit Energy 76
("Spirit 76"), a business unit of Union Oil Company of California, Vastar
Resources, Inc. ("Vastar") and Mallon Resources Corporation ("Mallon"). On March
15, 2002, we acquired Prize Energy Corp., which was merged into one of our
wholly-owned subsidiaries. Prize was a publicly traded independent oil and gas
company engaged primarily in the acquisition, enhancement and exploitation of
producing oil and gas properties. Prize owned oil and gas properties principally
located in three core operating areas, which were in the Permian Basin of West
Texas and Southeastern New Mexico, the onshore Gulf Coast area of Texas and
Louisiana and the Mid-Continent area of Oklahoma and the Texas Panhandle. Over
80% of Prize's oil and gas property base was located in Texas. In addition to
our focus on selected exploratory drilling prospects in the Gulf of Mexico as
described below, we intend to continue to concentrate our efforts on additional
producing property acquisitions strategically located within our geographic area
of operations. We also intend to continue to develop our substantial inventory
of drilling and workover opportunities located onshore. We have identified over
561 development drilling locations (including both production and injection
wells) and workover opportunities on our properties to which proved reserves
have been attributed, substantially all of which are low-risk in-fill drilling
or enhanced recovery opportunities.
In 1998, we acquired an approximate 40% beneficial ownership interest in TEL
Offshore Trust ("TEL"), a trust created under the laws of the state of Texas.
The principal asset of TEL consists of a 99.99% interest in the TEL Offshore
Trust partnership. Chevron USA Inc. owns the remaining .01% interest in the
partnership. The partnership owns an overriding royalty interest equivalent to a
25% net profits interest in certain oil and gas properties located offshore
Louisiana in the shallow waters in the Gulf of Mexico. As of March 15, 2003,
Magnum Hunter owned approximately 38% of the units of beneficial ownership in
TEL.
Additionally, we own and operate three gas gathering systems covering over 480
miles and a 50% or greater ownership interest in four natural gas processing
plants that are located adjacent to certain company-owned and operated producing
properties within the states of Texas, Oklahoma and Arkansas.
At December 31, 2002, Magnum Hunter had an interest in 5,612 wells and had
estimated proved reserves of 837 Bcfe with a present value discounted at 10%
("PV-10") of $1.25 billion. Approximately 78% of these reserves were proved
developed reserves with a geographic breakdown as follows: 36% attributable to
the Mid-Continent Region, 44% attributable to the Permian Basin Region, 9%
attributable to the Gulf Coast Region and 11% attributable to the Gulf of
Mexico. At December 31, 2002, our proved reserves had an estimated reserve life
of approximately 10.3 years and were 55% natural gas. The company serves as
operator for approximately 79% of our properties, based on the gross number of
wells in which we own an interest, and 76% of our properties, based upon the
year-end PV-10 value.
As a result of our property acquisitions and successful drilling activities
during 2002, Magnum Hunter has achieved growth as described below:
. Proved reserves increased 121% to 837 Bcfe at year-end 2002 from
378 Bcfe at year-end 2001; and
. Average daily production increased 113% to 194,338 Mcfe during
fiscal 2002 from 91,292 Mcfe in fiscal 2001. The company had an
exit rate of approximately 186 MMcfe at year-end 2002.
BUSINESS STRATEGY
Our overall strategy is to increase our reserves, production, cash flow and
earnings, utilizing a properly balanced program of:
. selective exploration;
. the exploitation and development of acquired properties; and
. strategic acquisitions of additional proved reserves.
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The following are key elements of our strategy:
Exploration. We plan to continue to participate in drilling Gulf of Mexico
exploratory wells in an effort to add higher-output production to our reserve
mix, especially during high commodity price periods. The continued use of 3-D
seismic information as a tool in our exploratory drilling in the Gulf of Mexico
will be significant. Over the last three years, we have built a significant
inventory of undrilled offshore lease blocks. We plan to continue to align
ourselves with other active Gulf of Mexico industry partners who have similar
philosophies and goals with respect to a "fast track" program of placing new
production online. This typically involves drilling wells near existing
infrastructure such as production platforms, facilities and pipelines. We also
maintain an active onshore exploration program primarily concentrated in West
Texas and Southeastern New Mexico where we have various other operations in core
areas. From time to time, we participate in higher-risk new exploration projects
generated by third parties in areas along the Gulf Coast of Texas and Louisiana.
Exploitation and Development of Existing Properties. We have a substantial
inventory of over 561 development/exploitation projects which include
development drilling, workovers and recompletion opportunities. We will continue
to seek to maximize the value of our existing properties through development
activities including in-fill drilling, waterflooding and other enhanced recovery
techniques. Typically, our exploitation projects do not have significant time
limitations due to the existing mineral acreage being held by current
production. By operating substantially all of our properties, our management is
provided maximum flexibility with respect to the timing of capital expended to
develop these opportunities.
Property Acquisitions. Although we currently have an extensive inventory of
exploitation and development opportunities, we will continue to pursue strategic
acquisitions which fit our objectives of increasing proved reserves in similar
geographic regions that contain development or exploration potential combined
with maintaining operating control. We plan to continue to pursue an acquisition
strategy of acquiring long-lived assets where operating synergies may be
obtained and production enhancements, either on the surface or below ground, may
be achieved.
Management of Overhead and Operating Costs. We will continue to emphasize strict
cost controls in all aspects of our business and will continue to seek to
operate our properties wherever possible, utilizing a minimum number of
personnel. By operating approximately 76% of our properties on a PV-10 basis, we
will generally be able to control direct operating and drilling costs as well as
to manage the timing of development and exploration activities. This operating
control also provides greater flexibility as to the timing requirements to fund
new capital expenditures. By strictly controlling Magnum Hunter's general and
administrative expenses, management strives to maximize our net operating
margin.
PROPERTIES
The company's major properties are located in four core areas: (i) the
Mid-Continent region, (ii) the Permian Basin, (iii) Gulf Coast region and (iv)
the Gulf of Mexico.
Mid-Continent Region
Our properties located in the Mid-Continent region were acquired principally
from Burlington, Spirit 76, Vastar and Prize.
We have received an engineering evaluation from DeGolyer and MacNaughton ("D&M")
and Cawley Gillespie & Associates, Inc. ("Cawley Gillespie"), independent
petroleum engineers we engaged to evaluate our properties, on the net reserves
in the Mid-Continent region. According to D&M and Cawley Gillespie, as of
December 31, 2002, the Mid-Continent properties had proved reserves of 12.84
MMBbl of oil and 177.4 Bcf of natural gas, or on a natural gas equivalent basis,
254.4 Bcfe. D&M and Cawley Gillespie further estimated the PV-10 for the
Mid-Continent properties to be $324.56 million as of December 31, 2002. The
proved reserves are located principally in the Ardmore Basin in south central
Oklahoma, in the Oklahoma/Texas panhandle and in Southwestern Arkansas.
Approximately 70% of the estimated reserves are natural gas and 30% are oil
located on approximately 235,083 net mineral leasehold acres in twenty-seven
counties in Oklahoma, eleven counties in Texas and two counties in Arkansas.
Total net daily production from the Mid-Continent properties for the month of
December 2002 was approximately 35.8 million cubic feet of natural
3
gas production and 2,509 barrels of oil and natural gas liquids. Magnum Hunter's
wholly-owned subsidiary, Gruy Petroleum Management Co. ("Gruy"), is the operator
of approximately 85% of the wells located in the Mid-Continent region.
The major fields in the Mid-Continent region are the Panoma, Eola-Robberson,
Cumberland, Walnut Bend and Madill.
Panoma. The Panoma properties currently consist of approximately 550 natural gas
wells in the West Panhandle, East Panhandle, and South Erick Fields along a
corridor 66 miles long and 20 miles wide stretching from Beckham County,
Oklahoma to Gray County, Texas. All wells are less than 2,300 feet deep and
produce natural gas from the Granite Wash and/or Brown Dolomite formations. For
the month of December 2002, net production natural gas sales were approximately
11.1 MMcf/d, (gross production was 14.0 Mmcf/d), which excludes liquids
processed from this natural gas stream through our gas processing facility
located adjacent to these fields, known as the McLean Plant. Development
continues with increased density drilling in the West Panhandle.
Eola-Robberson. The Eola-Robberson Field is located in Garvin County, Oklahoma
and has been producing since 1920. It is productive in multiple reservoirs from
the fractured Devonion Klippe at 6,400' to the Basal Oil Creek at 11,800'. The
field has primarily been developed within two units, the Eola North Fault Block
Unit and the South Eola Bromide Sand Unit. The waterfloods for this field were
discontinued in 1992 and the wellbores are being recompleted into bypassed oil
pockets in the Bromide, McLish and Oil Creek and the fractured gas reservoirs
such as the Sycamore, Woodford, Hunton and Viola. We have an interest in 65
producing wells, with working interests varying from 8% to 100%. We operate all
but four of these wells. For the month of December 2002, gross production from
the field averaged 8,523 Mcf/d and 530 Bbl/d (or 4,454 Mcf/d and 311 Bbl/d net
to the company).
Cumberland. The Cumberland Field is located in Bryan and Marshall Counties,
Oklahoma. It was discovered in 1940 and is productive in multiple reservoirs
from the Goddard down to the Arbuckle formation. Depths range from 2,000' to
6,800'. Initially, the field produced oil from the Bromide, McLish and Oil Creek
formations. These zones were unitized in 1964 for waterflood operations, which
continue today. The "Shallow Gas" zones include the Sycamore, Woodford, Hunton,
and Viola. These formations are predominantly gas productive and are produced
commingled. Development drilling plans exist for four additional proved
undeveloped locations to exploit the shallow gas on 160 acre spacing. The
shallowest zone in the field is the Goddard, which is a channel sand. We have an
interest in 71 active wells, with working interests varying from 17% to 100%. We
operate all but ten of these wells. For the month of December 2002, gross
production from the field averaged 7,291 Mcf/d and 198 Bbl/d (or 4,478 Mcf/d and
172 Bbl/d net to the company).
Walnut Bend. The Walnut Bend Field is located in Cooke County, Texas. The field
was discovered in the late 1930's and produces oil and gas from numerous
intervals ranging in depth from 2,000' in the Montgomery sands to over 7,000' in
the Ellenburger carbonate. There are currently 97 active producing wells and 28
active injection wells. Our working interest ownership in the wells is
approximately 91%. For the month of December 2002, gross production from the
wells averaged 127 Mcf/d and 641 Bbl/d (or 116 Mcf/d and 583 Bbl/d net to the
company). Current activities in the field include a recompletion program on both
active and inactive wellbores as identified by a two-year geological study. This
will include the initiation of numerous small waterflood projects.
Madill. The Madill Field is located in Marshall County in Southern Oklahoma. The
first production from this field occurred in 1906 and produces primarily gas
from various shallow reservoirs, such as the Sycamore, Woodford, Viola and
Bromide at depths ranging from 3,750' to 5,700'. There are currently 60 active
producing wells. Magnum Hunter's working interest ownership in the wells varies
from 41% to 100%. For the month of December 2002, gross production from the
wells averaged 1,918 Mcf/d and 75 Bbl/d (or 1,212 Mcf/d and 51 Bbl/d net to the
company).
PERMIAN BASIN
The company owns an interest in 3,348 wells located in 170 fields in the Permian
Basin. Gruy is the operator of approximately 77% of the producing wells.
Management believes the Permian Basin properties will continue to provide
significant opportunities for exploitation of oil and gas through infill
drilling, workovers and recompletions and optimization of enhanced oil recovery
projects.
4
According to D&M and Cawley Gillespie, as of December 31, 2002, the Permian
Basin properties had proved reserves of 43.8 MMBbl of oil and 152.8 Bcf of gas,
or on a natural gas equivalent basis, 415.8 Bcfe. D&M and Cawley Gillespie
further estimated the PV-10 for the Permian Basin properties to be $545.8
million as of December 31, 2002.
Total net daily production from the Permian Basin properties for the month of
December 2002 was approximately 34,742 MMcf of natural gas production and 6,306
Bbls of oil.
The top valued fields in the Permian Basin are Westbrook, Warwink, Howard
Glasscock, Jo-Mill, Kermit, Keystone, Willo, P&P and the southeast New Mexico
area.
Westbrook. The Westbrook field is located in Mitchell County, Texas and produces
from the Clearfork formation at a depth of approximately 3,200 feet. Gruy
operates the Southwest Westbrook Unit and Morrison G lease and the company owns
an 89% and 100% working interest, respectively. The company also owns a small
working interest in the Chevron/Texaco operated North Westbrook Unit. There are
currently 150 active wells in these three leases. For the month of December
2002, net production from the wells averaged 373 Bbl/d.
The initial wells in this area were drilled in the 1920's and waterflood
operations began in the 1960's. The company is actively drilling infill wells
and optimizing waterflood operations in the Southwest Westbrook Unit.
Warwink. The Warwink field is located in Winkler County, Texas. The company owns
interests in 20 wells producing from the Cherry Canyon formation at depths from
4,800 to 7,400 feet. The company's working interest ownership in these wells
varies from 70.75% to 85% and all wells are operated by Gruy. For the month of
December 2002, the company's net production from these wells averaged 472 Bbl/d
and 1,550 Mcf/d.
The wells in this field have multiple stacked Cherry Canyon sands that can be
produced together. Several behind pipe zones have been identified and the
company is actively adding these zones in the existing wells.
Howard Glasscock. The Howard Glasscock field is located on the border of Howard
and Glasscock Counties, Texas. The company owns an interest in 81 wells, of
which 78% are operated by Gruy. The company acquired additional interests in
2002 on two properties, regaining operations and increasing the working interest
from 50% to 100%. The company's working interest in the other wells in this area
range from 5% to 100%.
The properties in the Howard Glasscock field consist of multiple waterfloods in
the San Andres, Glorietta and Clearfork formations. The company also owns
interest in leases that have been identified as future waterflood candidates.
Jo-Mill. The Jo-Mill field is located in Borden County, Texas and produces in
the Sprayberry formation at approximately 7,100 to 7,500 feet. The company owns
a non-operated working interest that ranges from 0.5% to 33% in three different
waterflood units. The company's net production from these three units averaged
629 Bbl/d and 205 Mcf/d in December of 2002.
These fields were unitized between 1963 and 1973 and were initially waterflooded
on a peripheral pattern with 80 acre spacing. Since the mid 70's, multiple
infill wells have been drilled to convert the floods to a line drive pattern on
40 acre spacing. D&M has assigned net proved undeveloped reserves of 2,543 MMcfe
to an additional 31 locations in the Chevron/Texaco operated Jo-Mill Unit.
Kermit. The Kermit field is located in the heart of Winkler County, Texas. The
company owns interests in 167 oil and gas wells with a working interest varying
from 21% to 100%. Gruy operates 87% of the wells in this field. The average
December 2002 net production from these wells was 159 Bbl/d and 4,200 Mcf/d.
The wells in this field produce from several different horizons, including the
Ellenburger, McKee, Fusselman, Devonian, Clearfork, Holt, Colby and Yates. The
majority of the wells the company has an interest in are currently producing
from the Yates gas cap.
5
Keystone. The Keytone field is located in Winkler County, Texas. The company
owns an interest in 233 oil and gas wells of which 99.6% are operated by Gruy.
These wells produced an average of 340 Bbl/d and 893 Mcf/d net in December 2002.
The company owns 100% working interests in the East Keystone Unit where
waterflood operations commenced in June of 2002. This unit is flooding the San
Andres and Holt formations on a 20 acre 5 spot pattern. Initial waterflood
response has been seen in some parts of the field.
Willo. The Willo field is located in Crockett and Val Verde Counties, Texas. The
company owns an interest in 14 oil and gas wells producing from the Ellenburger,
Strawn and Canyon/Wolfcamp formations. The company's working interest ranges
from 23% to 100% in this field with 82% of the wells operated by Gruy. The
company's average net production for December 2002 for these wells was 1,986
Mcf/d. The most prolific zone in this field is the Ellenburger dolomite at an
average depth of 14,000 feet. This zone accounts for 97% of the 10,681 MMcfe net
proved developed producing reserves assigned to this field by D&M. Proved
undeveloped reserves of 17,145 MMcfe net for six additional Ellenburger wells
have been identified by D&M.
P&P. The P&P field is located in Crane County, Texas producing from the Devonian
at a depth of 5,500 feet. This field was unitized as the River Bend Devonian
Unit for waterflood operations in 2000. Water injection was started in September
of 2000 and the unit has experienced an increase in net oil production from 160
Bbl/d in April of 2001 to 300 Bbl/d in December of 2002. The company owns a 47%
working interest in 20 wells and all are operated by Gruy.
This field is located adjacent to the Gruy operated Abell Devonian Unit that has
been under waterflood operations in the Devonian since 1961. Proved undeveloped
reserves were assigned by D&M to the River Bend Devonian Unit in contemplation
of a carbon dioxide injection project that is anticipated to follow waterflood
operations.
Southeast New Mexico. The Southeast New Mexico properties consist of
approximately 760 wells in Lea and Eddy Counties, of which 80% are operated by
Gruy. Several of the company's fields in Lea County produce from the Yates,
Seven Rivers, Queen and other formations at depths generally shallower than
3,000 feet. The average net production for the Southeast New Mexico properties
for December 2002 was 1,030 Bbl/d and 16,245 Mcf/d.
The company has been actively drilling increased density wells in the Morrow
formation at approximately 11,500 feet. The company participated in 20 Morrow
wells in 2002 and has 26 wells planned for 2003. D&M has identified 22 proved
undeveloped locations for the Morrow, with net reserves of 12,789 MMcfe.
Several of the Morrow wells have identified behind pipe pay in the Atoka and
Strawn formations. A recent recompletion to the Strawn formation from the Morrow
in the Magnum 5, Federal #2 came in flowing at rates over 800 Bbl/d and 3,000
Mcf/d gross. The company has a 50% working interest in this well and is
currently drilling an offset location.
Gulf Coast
We own an interest in 432 wells in the Gulf Coast region, of which Gruy is the
operator of approximately 73% of the wells. Magnum Hunter has received an
engineering evaluation from DeGolyer and MacNaughton on the net reserves in the
Gulf Coast. According to D&M, as of December 31, 2002, the Gulf Coast properties
had proved reserves of 2.9 MMBbl of oil and 66.2 Bcf of natural gas, or on a
natural gas equivalent basis, 83.7 Bcfe. D&M further estimated the PV-10 for the
Gulf Coast properties to be $148.8 million as of December 31, 2002.
Approximately 79% of the estimated reserves are natural gas and 21% are oil.
Total net daily production from the Gulf Coast properties for the month of
December 2002 was approximately 17.6 million cubic feet of natural gas and 1,048
barrels of oil.
The principal fields in the onshore gulf coast region are Perry Point, Buchel,
Alta Loma and Word, North.
Perry Point. This field is located in southwestern Louisiana in Acadia Parish.
The company owns various working interests, between 53% and 83%, in three
producing wells and one saltwater disposal well. All of the wells are operated
and produce from the Marg Howei and Bol Mex formations between 11,160 feet and
15,150 feet. Production attributable to the company's interest averaged 1,620
Mcf/d and 39 Bbl/d in December 2002. Additional perforations were added
6
in one of the wells in late December which are expected to increase net
production substantially. As of December 31, 2002, the net proved reserves for
Perry Point field were 6.5 Bcfe.
Buchel. The company operates seven producing wells, one shut-in well and one
salt water disposal well in this Dewitt County, Texas field. We have an 87.5%
working interest in two of the wells and own a 100% working interest in the
remaining wells. The producing interval in the Buchel field is the lower
cretaceous Edwards formation at approximately 14,000 feet. Production averaged
2,027 Mcf/d and 22 Bbl/d in December 2002 net to the company's interest. Net
proved reserves for this field were 10.1 Bcfe as of December 31, 2002.
Alta Loma. The company owns a 41% and a 48% working interest in two producing
wells in this field. In addition, we also own and operate a salt water disposal
well. This field is located in Galveston County, Texas and produces from the
Frio formation at approximately 12,500 feet. Production attributable to the
company's interest averaged 1,230 Mcf/d and 108 Bbl/d in December 2002. As of
December 31, 2002, the net proved reserves assigned to this field were 4.8 Bcfe.
Word, North. We own varying working interests, between 4% and 100% in 24 wells
in this field located in Lavaca County, Texas. Eighteen of the wells are
operated by us. Production is from the Edwards formation at approximately 14,000
feet and averaged 1,183 Mcf/d and 3 Bbl/d in December 2002 net to our interest.
Net proved reserves for this field were 10.1 Bcfe as of December 31, 2002.
Gulf of Mexico
Our initial entry into the Gulf of Mexico occurred March 27, 1998 when we
acquired approximately 40% beneficial ownership interest in TEL Offshore Trust.
One year later in May 1999, we began participating as a working interest owner
in new exploratory drilling on the shallow water shelf. We currently own an
interest in 174 blocks in the Gulf of Mexico ranging from 12.5% to 100%. Proved
reserves have been assigned in 35 blocks encompassing 62 gross wells (24.7 net
wells). The company operates 18 of these wells (12.9 net wells). According to
D&M, as of December 31, 2002, the Gulf of Mexico properties had proved reserves
of 3.47 MMBbl of oil and 62.3 Bcf of natural gas (83.14 Bcfe) with a PV-10 value
of $227.3 million. Approximately 75% of the estimated reserves is natural gas
and the remaining 25% is oil. Total net daily production from the Gulf of Mexico
properties for the month of December 2002 was 31.4 million cubic feet of natural
gas and 1,197 barrels of oil. At December 31, 2002, the company had eight
additional discoveries that are scheduled to commence production in 2003.
TEL Offshore Trust. The principal asset of TEL consists of a 99.99% interest in
the TEL Offshore Trust partnership. Chevron USA Inc. owns the remaining 0.01%
interest in the partnership. The partnership owns an overriding royalty interest
equivalent to a 25% net profits interest in certain oil and gas properties
located offshore Louisiana. As of December 31, 2002, the company owned
approximately 38% of the units of beneficial ownership in TEL. TEL produced a
total of approximately .46 Bcfe in calendar 2002 net to the company.
Distributions from the partnership totaling $451 thousand net to the company
were received in 2002.
Main Pass 178 Area. This area comprises Main Pass blocks 164 and 178 and is
located in Federal waters west of Plaquemines Parish, Louisiana in water depths
of 135 feet to 150 feet. The company owns a 100% working interest and operates
four existing wells from two platforms. First production was established in
December 2001. These wells produce from various sands of Lower Pliocene to
Middle Miocene age, at depths ranging from 4,800 feet to 12,000 feet. Production
attributable to the company's interest averaged 1.2 Mmcf/d in December 2002. Two
of the wells began having sand problems in mid to late 2002 and were not
producing in December. The wells are currently being reworked to reestablish
production. Net proved reserves for the Main Pass Area were 11.7 Bcfe as of
December 31, 2002. In addition, the company is currently drilling a fifth well
targeting the deeper Middle Miocene sands and is retaining a 50% working
interest.
South Timbalier 265 Area. This area encompasses South Timbalier blocks 250, 264
and 265 and is located in Federal waters south of Terrebonne Parish, Louisiana
in water depths of 185 feet to 225 feet. The company owns working interests in
fifteen wells ranging from 40% to 100%. The company operates all of the wells
from four platforms. The company initially acquired its interest in South
Timbalier 265 through a like-kind property exchange with Kerr McGee
7
in August 2000. Additional interests in the area were acquired from El Paso in
March 2001. The wells produce from various sands ranging in depth from 4,800
feet to 16,000 feet. Production averaged 12.3 Mmcf/d and 216 Bbl/d in December
2002 net to the company's interest. As of December 31, 2002, the net proved
reserves for the South Timbalier 265 Area were 18.2 Bcfe.
Main Pass 108 Area. The company owns a 33.33% working interest in one well in
Main Pass 107 and a 25% working interest in one well in Main Pass 108. Kerr
McGee operates both wells. These wells are in 50 feet to 70 feet of water and
are located in Federal waters west of Plaquemines, Louisiana. Production from
the well in block 108 started in June 2002 and averaged 1.4 Mmcf/d and 45 Bbl/d
in December 2002 net to the company's interest. The well in block 107 was not
put on production until late January 2003. Production is from the Tex W series
of sands with multiple zones currently behind pipe. Net proved reserves
attributable to this area were 12.9 Bcfe as of December 31, 2002.
Eugene Island 302. Our interest in Eugene Island 302 consists of a 30% working
interest in two wells operated by Remington Oil & Gas. Current production is
from the Basal Nebraskan at approximately 10,000 feet with additional zones
behind pipe. The field is located in 220 feet of water on Federal leases south
of St. Mary Parish, Louisiana. First production from both wells was established
in May 2002; however, production was interrupted in October 2002 due to damage
caused by Hurricane Lili to Newfield's production platform at Eugene Island 324.
The wells were rerouted to Forest's Eugene Island 325 platform and were returned
to production in February 2003. Net proved reserves attributable to these two
wells were 4.7 Bcfe as of December 31, 2002.
East Cameron 184 Area. This area encompasses East Cameron blocks 179, 184 and
185. We own a 30% working interest in three wells operated by Remington Oil &
Gas. The wells are located in Federal waters south of Cameron Parish, Louisiana
in a water depth of approximately 95 feet. Production for the first two wells
was initiated in April 2002 and averaged 1.2 Mcf/d and 47 Bbl/d in December 2002
net to our interest. The third well was completed in late 2002 but facilities
were not completed until mid-February 2003. All three wells produce from the Bul
1 10,800' sand. As of December 31, 2002, the net proved reserves for the East
Cameron 184 Area were 3.1 Bcfe.
South Timbalier 275 Area. The company owns a 10% working interest in one well in
South Timbalier 274 and a 50% working interest in one well in South Timbalier
275. Spinnaker operates both wells. These wells are in 265 feet of water and are
located on Federal leases south of Terrebonne Parish, Louisiana. Production from
South Timbalier 274 and 275 started in April and June 2002, respectively.
Production attributable to the company's interest averaged 7.7 Mcf/d and 135
Bbl/d in December 2002. Both wells produce from the Bul 1 series of sands. Net
proved reserves for these two wells were 3.3 Bcfe as of December 31, 2002.
Gas Processing Plants
McLean Plant. In January 1997, we complemented our Panoma acquisition by
purchasing a 50% ownership interest in the McLean Gas Plant and a related 22
mile products pipeline. This plant is a modern cryogenic plant utilizing
approximately 2,000 horsepower of high speed compression and a gas processing
capacity of approximately 23 MMcf/d. For the month of December 2002, throughput
of the plant averaged 15,034 Mcf/d with processed liquids of 1,018 Bbl/d.
Madill Plant. In December 1999, we acquired the Madill Gas Processing Plant and
associated gathering system assets from Dynegy Midstream Services, Limited
Partnership, a wholly-owned subsidiary of Dynegy Inc. The gas processing plant
and associated facilities are located in Marshall and Bryan Counties, Oklahoma
and were acquired in conjunction with our 50% partner, Carrera Gas Gathering
Co., L.L.C., of Tulsa, Oklahoma who acquired the other 50% of the gas plant and
associated assets. The acquisition includes over 130 miles of gas gathering
pipelines. This modern cryogenic plant has 3,350 horsepower of high speed
compression and has gas processing capacity of approximately 18 MMcf/d. For the
month of December 2002, throughput of the plant averaged 13,934 Mcf/d of natural
gas with processed liquids of 872 Bbl/d.
Walker Creek Plant. In conjunction with the Vastar acquisition, we acquired an
approximate 59% ownership interest and became the operator of the Walker Creek
Plant and associated gathering system. In 2000, we sold a 44.2% interest in the
Walker Creek Plant to Mallard Hunter L.P., of which we are the general partner.
This facility is located in southwest Arkansas in Lafayette and Columbia
counties. This propane refrigeration plant utilizes 3,160 horsepower of leased
compression and has a gas
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processing capacity of 12 Mmcf/d. For the month of December 2002, throughput of
the plant averaged 3,857 Mcf/d with processed liquids of 216 Bbl/d.
Elmore City Processing Plant: We acquired a 100% ownership interest in the
Elmore City Plant in the Prize merger. This gas processing facility and
associated gathering system assets are located in Garvin County, Oklahoma.
These facilities include over 25 miles of gathering pipelines and an NGL
extraction plant consisting of a cryogenic unit and approximately 7,000
horsepower of various types of compressors. The plant's 2002 throughput has
averaged 11.3 MMcf/d with a total throughput capacity of approximately 40
MMcf/d.
DEVELOPMENT AND EXPLORATION ACTIVITIES
Overview
We presently intend to continue to focus our efforts on exploration, property
acquisitions and our substantial inventory of exploitation and development
drilling projects.
Magnum Hunter seeks to minimize our overhead and capital expenditures by
subcontracting the drilling, redrilling and workover of wells to independent
drilling contractors and by outsourcing other services. We typically compensate
our drilling subcontractors on a turnkey (fixed price), footage or day-rate
basis depending on our assessment of risk and cost considerations on each
individual project.
Development Drilling
Magnum Hunter's development strategy focuses on maximizing the value and
productivity of our oil and gas asset base through development drilling and
enhanced recovery projects. We have budgeted approximately $54 million for
exploitation and development activities for 2003 with $36.7 million of such
budget allocated to our proved undeveloped reserves. We have identified 561
development drilling locations and workover opportunities on our properties to
which proved reserves have been attributed. In exploiting our producing
properties, we rely upon our in-house technical staff of petroleum engineering
and geological professionals and utilize the services of outside consultants on
a selective basis.
Mid-Continent Region. We believe that developmental drilling can continue to
enhance the value of the Panoma properties, which produce from the Brown
Dolomite and Granite Wash formations in the Texas Panhandle and western
Oklahoma. The easternmost fields are developed on 160 acre spacing because the
original spacing of 640 acres proved inadequate to drain reserves efficiently.
The westernmost field has now been developed with approximately 320 acre
spacing, and future development drilling will bring the spacing down to a more
efficient 160 acres per well. Ten wells were drilled in 2002 and seven wells
have been drilled in the ten well 2003 drilling program through March 15, 2003.
The Cumberland Field was discovered in 1940 and is productive in multiple
reservoirs from the Goddard down to the Arbuckle formation. Depths range from
2,000' to 6,800'. Initially, the field produced oil from the Bromide, McLish and
Oil Creek formations. These zones were unitized in 1964 for waterflood
operations, which continue today. The "Shallow Gas" zones include the Sycamore,
Woodford, Goddard, Hunton, and Viola. These formations are predominantly gas
productive and are produced commingled. We have identified four locations in
which additional wells could be drilled in proved undeveloped reserves to
complete development of the shallow gas on 160 acre spacing. Additional drilling
and recompletions are budgeted in 2003.
Additional Mid-Continent development, drilling and recompletion activities and
improvements to existing waterflood operations will focus on the Walnut Bend
Field in Cooke County, Texas, the Madill Field in Marshall County, Oklahoma and
the Eola-Robberson field in Garvin County, Oklahoma..
Permian Basin Properties. In evaluating the Permian Basin properties, we have
identified over 180 drilling locations including production and injection wells.
Primary development focus will be on increased density drilling opportunities.
Numerous workovers, recompletions and development wells are targeted for the
shallow gas properties in Lea County, New Mexico. Further development of the
Westbrook Field in Mitchell County, Texas began in 2000 when seven producing
wells and five injection wells were drilled. Approximately 12 new wells are
scheduled to be drilled in the Westbrook Field in 2003.
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EXPLORATORY DRILLING
We spent $34.3 million of our $141 million 2002 capital budget on exploratory
drilling and related land and geophysical costs. Twenty-nine offshore
exploratory wells were drilled in 2002 of which twenty-three were completed as
producing wells providing us with a 79% success rate. The most significant
change in strategy occurred when we entered the Gulf of Mexico as a working
interest owner in new exploratory drilling on the shallow water shelf in May
1999. This program has yielded 57 completions in 66 attempts by the end of 2002
and as the proved reserves associated with these new wells are developed, they
have been adding significant cash flow. Production from our producing blocks was
approximately 44.0 MMcfe/d net to the company as of March 2003. Eight new
platforms scheduled to commence production in 2003 should add substantially to
these levels. We own an interest ranging from 12.5% to 100% in 136 offshore
blocks and expect to add to the number of OCS blocks in 2003. An aggressive
drilling program will continue in 2003.
The onshore exploration program remains active. Drilling in New Mexico in 2002
and early 2003 has resulted in 15 new Morrow gas wells with working interests
ranging from 12.5% to 100%. Per well production has ranged from one-half million
to five million cubic feet of natural gas equivalents per day. Forty seven
proved undeveloped locations remain to be drilled in New Mexico and over 120
drill sites are identified as a result of activity in New Mexico.
New prospects on the Texas and Louisiana Gulf Coast area and a continuing
offshore Gulf of Mexico program should provide ample opportunity to grow
reserves and production in future years.
GATHERING AND PROCESSING OF GAS
Hunter Gas Gathering, Inc., a wholly-owned subsidiary of the company, owns three
gas gathering systems located in Oklahoma, Texas and Arkansas, none of which are
subject to regulation by the Federal Energy Regulatory Commission ("FERC"), and
ownership interests in four gas processing plants. Gruy operates all of the gas
gathering systems and two of the gas processing plants.
Generally, the gathering systems transport the natural gas from wells to a
common point where it is dehydrated prior to redelivery to downstream pipelines.
In managing our gas gathering systems, we have emphasized operating efficiency
and overhead management and introduced a program in certain areas which ties
throughput costs to volume transported rather than to compression capacity. We
believe that our focus on volume-based pricing reduces the potential financial
impact of a decline in actual throughput. Since most of the compression costs
are not fixed, but are tied to volumes transported, the compression operator has
an incentive to ensure that as much volume is being transported as possible. The
lower the volume transported, the lower the fee to the compression operator, and
in some situations, the compression operator incurs a penalty.
The Panoma system, the largest of our gas gathering systems, consists of
approximately 449 miles of pipeline. The main trunklines run east to west for
approximately 66 miles with the east end starting in Beckham County, Oklahoma
and the west end starting in Gray County, Texas. At December 31, 2002, gas
throughput for the Panoma gas gathering system was approximately 15,533 Mcf/d.
The Panoma gas gathering system is connected to a third party "header" system
which provides access to all major interstate pipelines in the area via seven
pipeline interconnects serving Midwestern, Western and Oklahoma intrastate
markets. We operate approximately 523 of the approximately 610 wells connected
to the Panoma system, and are actively seeking to add new wells to such system
through acquisition, development or arrangements with third party producers.
We acquired a 100% ownership interest in the Elmore City Plant in the Prize
merger. This gas processing facility and associated gathering system assets are
located in Garvin County, Oklahoma. These facilities include over 25 miles of
gathering pipelines and an NGL extraction plant consisting of a cryogenic unit
and approximately 7,000 horsepower of various types of compressions. The plant's
2002 throughput has averaged 11.3 MMcf/d with a total throughput capacity of
approximately 40 MMcf/d.
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Effective January 1997, we purchased a 50% ownership interest in the McLean Gas
Plant, a gas processing facility located adjacent to our gas gathering system.
The purchase also included a 22 mile products pipeline between the McLean Gas
Plant and the Koch Pipeline at Lefors, Texas and all gas and product purchase
and sales agreements related to the plant. The McLean Gas Plant is a modern
cryogenic gas processing plant with a throughput capacity of 23.0 Mmcf/d. For
the month of December 2002, throughput, net to Hunter Gas Gathering, was
approximately 7,516 Mcf/d with processed liquids of 528 Bbl/d. We acquired our
50% ownership interest in the plant from Carrera Gas Company, L.L.C. ("Carrera")
of Tulsa, Oklahoma, which owns the remaining 50% of the plant and operates the
facility on our behalf.
In December 1999, we acquired the Madill Gas Processing Plant and associated
gathering system assets from Dynegy Midstream Services, Limited Partnership, a
wholly-owned subsidiary of Dynegy Inc. The gas processing plant and associated
facilities are located in Marshall and Bryan Counties, Oklahoma and were
acquired in conjunction with our 50% partner, Carrera. The acquisition includes
over 130 miles of gas gathering pipelines. This modern cryogenic plant has 3,350
horsepower of high speed compression and has gas processing capacity of
approximately 18 Mmcf/d. For the month of December 2002, throughput of the
plant, net to Hunter Gas Gathering, was approximately 6,967 Mcf/d of natural gas
with processed liquids of 435 Bbl/d.
In conjunction with the Vastar acquisition, we acquired approximately 59%
ownership interest and became the operator of the Walker Creek Plant and
associated gathering system. In 2000, we sold a 44.2% interest in the Walker
Creek Plant to Mallard Hunter L.P., of which we are the general partner. This
facility is located in southwest Arkansas in Lafayette and Columbia counties.
This propane refrigeration plant utilizes 3,160 horsepower leased compression
and has a gas processing capacity of 12 MMcf/d. For the month of December 2002,
throughput of the plant, net to Hunter Gas Gathering, was approximately 231
Mcf/d with processed liquids of 13 Bbl/d.
MARKETING OF PRODUCTION
We market all of our gas production as well as gas we purchase from third
parties to gas marketing firms or end-users either on (i) the spot market under
contracts of less than one year at prevailing spot market prices (approximately
75% of our volume) or (ii) at market responsive prices under multi-year
contracts (approximately 25% of our volume). Marketing gas for our own account
exposes the company to the attendant commodities risk which we attempt to
mitigate through various financial hedges. We normally sell our own oil under
month-to-month contracts with a variety of crude oil purchasers. Oil is usually
sold for our own account through the services of Enmark Services, a marketing
agent in Dallas, Texas. While we have historically been able to sell oil above
posted prices, we are also exposed to the commodities risk inherent in
short-term contracts which we attempt to mitigate through various financial
hedges. For a discussion of our hedging activities, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources - Hedging Activity" and Note 12 to our consolidated financial
statements.
In December 1997, Hunter Gas Gathering, Inc. acquired a thirty percent (30%)
membership interest in NGTS, LLC ("NGTS"), a subsidiary of Natural Gas
Transmission Services, Inc. NGTS is a Dallas-based natural gas marketing and
trading company with operations concentrated in the western two-thirds of the
country. As of December 31, 2002, NGTS marketed approximately 15.4% of our
natural gas under short term contracts. The balance of our production is
marketed through other marketing companies or gatherer/processors.
The market for oil and natural gas we produce depends on factors beyond our
control, including the extent of domestic production and imports of oil and
natural gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, weather, demand for oil and natural gas, the
marketing of competitive fuels and the effects of state and federal regulation.
The oil and natural gas industry also competes with other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers.
PETROLEUM MANAGEMENT AND CONSULTING SERVICES
We acquired Gruy in December 1995. Gruy, which conducts operations for both
Magnum Hunter and third parties, has over a 45-year history of managing
properties for financial institutions, bankruptcy trustees, estates, individual
investors, trusts and independent oil and gas companies. Gruy provides drilling,
completion and other well-site services; advice regarding environmental and
other regulatory compliance; receipt and disbursement functions, expert witness
testimony
11
and other managerial services and petroleum engineering services. Gruy manages,
operates and provides consulting services on oil and gas properties, gathering
systems and processing plants located in Texas, Oklahoma, Mississippi,
Louisiana, New Mexico and Kansas. Gruy is an important component of our
acquisition program. As the operator of wells for third parties and as a
provider of consulting services for the energy industry, Gruy is often uniquely
able to identify attractive acquisition opportunities.
For additional information on our business segments, see Note 15 to our
consolidated financial statements.
COMPETITION
The oil and gas industry is highly competitive. Our competitors include major
oil companies, other independent oil and gas concerns, and individual producers
and operators, many of which have substantially greater financial resources and
larger staffs and facilities than those of the company. In addition, we
frequently encounter competition in the acquisition of oil and gas properties,
gas gathering systems, gas processing plants and in our management and
consulting business. The principal means of such competition are the amount and
terms of the consideration offered. The principal means of such competition with
respect to the sale of oil and gas production are product availability and
price. The price at which our products may be sold will continue to be affected
by a number of factors, including the price of alternate fuels such as oil,
natural gas, nuclear power, hydroelectric power and coal and competition among
various gas producers and marketers.
REGULATIONS
General Federal and State Regulations
There have been, and continue to be, numerous federal and state laws and
regulations governing the oil and gas industry that are often changed in
response to the current political or economic environment. Compliance with this
regulatory burden is often difficult and costly and may carry substantial
penalties for noncompliance. The following are some specific regulations that
may affect the company. We cannot predict the impact of these or future
legislative or regulatory initiatives.
Regulation of Natural Gas and Oil Exploration and Production
Our operations are subject to various types of regulation at the federal, state
and local levels. Such regulation includes requiring permits for drilling wells,
maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. Our operations are also subject to various conservation laws
and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells which may be drilled
in and the unitization or pooling of oil and gas properties. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations may
limit the amount of oil and gas we can produce from our wells and may limit the
number of wells or the locations at which we can drill. The regulatory burden on
the oil and gas industry increases our cost of doing business and, consequently,
affects our profitability. Inasmuch as such laws and regulations are frequently
expanded, amended and reinterpreted, we are unable to predict the future cost or
impact of complying with such regulations.
Federal Regulation of Sales Prices and Transportation
Currently, there are no federal, state or local laws that regulate the price for
sales of our natural gas, NGLs, crude oil or condensate. However, the rates
charged and terms and conditions for the movement of gas in interstate commerce
through certain intrastate pipelines and production area hubs are subject to
regulation under the Natural Gas Policy Act of 1978 ("NGPA"). Pipeline and hub
construction activities are, to a limited extent, also subject to regulations
under the Natural Gas Act of 1938 ("NGA"). While these controls do not apply
directly to the company, their effect on natural gas markets can be significant
in terms of competition and cost of transportation services. Additional
proposals and proceedings that might affect the natural gas industry are
considered from time to time by Congress, FERC, state
12
regulatory bodies and the courts. We cannot predict when or if any such
proposals might become effective and their effect, if any, on our operations.
Historically, the natural gas industry has been heavily regulated; therefore,
there is no assurance that the less stringent regulatory approach recently
pursued by FERC, Congress and the states will continue indefinitely into the
future.
Gathering Regulations
State regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory take requirements.
Such regulation has not generally been applied against gatherers of natural gas,
although natural gas gathering may receive greater regulatory scrutiny in the
future. Our operations on federal, state or Indian oil and gas leases are
subject to numerous restrictions, including nondiscrimination statutes. Such
operations must be conducted pursuant to certain on-site security regulations
and other permits and authorizations issued by the Bureau of Land Management,
Minerals Management Service and other agencies.
Environmental Regulation
Our exploration, development, and production of oil and gas, including our
operation of saltwater injection and disposal wells, are subject to various
federal, state and local environmental laws and regulations. Such laws and
regulations can increase the costs of planning, designing, installing and
operating oil and gas wells. Our domestic activities are subject to a variety of
environmental laws and regulations, including but not limited to, the Oil
Pollution Act of 1990 ("OPA"), the Clean Water Act ("CWA"), the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA"), the Resource
Conservation and Recovery Act ("RCRA"), the Clean Air Act ("CAA"), and the Safe
Drinking Water Act ("SDWA"), as well as state regulations promulgated under
comparable state statutes. We are also subject to regulations governing the
handling, transportation, storage, and disposal of naturally occurring
radioactive materials that are found in our oil and gas operations. Civil and
criminal fines and penalties may be imposed for non-compliance with these
environmental laws and regulations. Additionally, these laws and regulations
require the acquisition of permits or other governmental authorizations before
undertaking certain activities, limit or prohibit other activities because of
protected areas or species, and impose substantial liabilities for cleanup of
pollution.
Under the OPA, a release of oil into water or other areas designated by the
statute could result in the company being held responsible for the costs of
remediating such a release, certain OPA specified damages, and natural resource
damages. The extent of that liability could be extensive, as set forth in the
statute, depending on the nature of the release. A release of oil in harmful
quantities or other materials into water or other specified areas could also
result in the company being held responsible under the CWA for the costs of
remediation, and civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws, can impose
joint and several and retroactive liability, without regard to fault or the
legality of the original conduct, on certain classes of persons for the release
of a "hazardous substance" into the environment. In practice, cleanup costs are
usually allocated among various responsible parties. Potentially liable parties
include site owners or operators, past owners or operators under certain
conditions, and entities that arrange for the disposal or treatment of, or
transport hazardous substances found at the site. Although CERCLA, as amended,
currently exempts petroleum, including but not limited to, crude oil, gas and
natural gas liquids from the definition of hazardous substance, our operations
may involve the use or handling of other materials that may be classified as
hazardous substances under CERCLA. Furthermore, there can be no assurance that
the exemption will be preserved in future amendments of the act, if any.
RCRA and comparable state and local requirements impose standards for the
management, including treatment, storage, and disposal of both hazardous and
nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in
connection with its routine operations. From time to time, proposals have been
made that would reclassify certain oil and gas wastes, including wastes
generated during drilling, production and pipeline operations, as "hazardous
wastes" under RCRA which would make such solid wastes subject to much more
stringent handling, transportation, storage, disposal, and clean-up
requirements. This development could have a significant impact on our operating
costs. While state laws vary on this issue, state initiatives to further
regulate oil and gas wastes could have a similar impact.
Because oil and gas exploration and production, and possibly other activities,
have been conducted at some of our properties by previous owners and operators,
materials from these operations remain on some of the properties and in
13
some instances require remediation. In addition, in certain instances we have
agreed to indemnify sellers of producing properties from which we have acquired
reserves against certain liabilities for environmental claims associated with
such properties. While we do not believe that costs to be incurred by us for
compliance and remediating previously or currently owned or operated properties
will be material, there can be no guarantee that such costs will not result in
material expenditures.
Additionally, in the course of our routine oil and gas operations, surface
spills and leaks, including casing leaks, of oil or other materials occur, and
we incur costs for waste handling and environmental compliance. Moreover, we are
able to control directly the operations of only those wells for which we act as
the operator. Management believes that the company is in substantial compliance
with applicable environmental laws and regulations.
It is not anticipated that we will be required in the near future to expend
amounts that are material in relation to our total capital expenditures program
by reason of environmental laws and regulations, but inasmuch as such laws and
regulations are frequently changed, we are unable to predict the ultimate cost
of compliance. There can be no assurance that more stringent laws and
regulations protecting the environment will not be adopted or that we will not
otherwise incur material expenses in connection with environmental laws and
regulations in the future.
EMPLOYEES
At December 31, 2002, we had 221 full-time employees of which 54 were
management, 99 were administrative and 68 were field personnel. None of our
employees are represented by a union. Management considers our relations with
employees to be very good.
FACILITIES
Magnum Hunter occupies approximately 23,386 square feet of office space at 600
East Las Colinas Boulevard, Suite 1100, Irving, Texas, under a lease that
expires in November 2005. We also occupy approximately 19,635 square feet of
office space in Grapevine, Texas, under a lease that expires in December 2005.
We own field offices and production yards in Shamrock and Gainesville, Texas,
Cumberland and Madill, Oklahoma and Taylor, Arkansas. We also lease field
production offices in Midland, Kermit, Victoria and Abilene, Texas; Artesia and
Eunice, New Mexico and Oklahoma City and Woodward, Oklahoma.
14
RISK FACTORS
RISKS RELATING TO THE OIL AND GAS INDUSTRY
A decrease in oil and natural gas prices will adversely affect our financial
results.
Our revenues, profitability and the carrying value of our oil and gas properties
depend substantially upon prevailing prices of, and demand for, oil and gas and
the costs of acquiring, finding, developing and producing reserves. Oil and gas
prices also substantially affect our ability to maintain or increase our
borrowing capacity, to repay current or future indebtedness, and to obtain
additional capital on attractive terms. Historically, the markets for oil and
gas have been volatile and are likely to continue to be volatile in the future.
Prices for oil and gas fluctuate widely in response to:
. relatively minor changes in the supply of, and demand for, oil and
gas;
. market uncertainty both domestically and worldwide; and
. a variety of additional factors, all of which are beyond our
control.
These factors include domestic and foreign political conditions, the price and
availability of domestic and imported oil and gas, the level of consumer and
industrial demand, weather, domestic and foreign government relations, the price
and availability of alternative fuels and overall economic conditions. Also, our
ability to market our production depends in part upon the availability,
proximity and capacity of gathering systems, pipelines and processing
facilities. Volatility in oil and gas prices could affect our ability to market
our production through such systems, pipelines or facilities. Currently, we sell
substantially all our gas production to gas marketing firms or end users either
on the spot market on a month-to-month basis at prevailing spot market prices or
under long-term contracts based on current spot market prices.
Under the full cost accounting method, we are required to take a non-cash charge
against earnings if capitalized costs of acquisition, exploration and
development, net of depletion, depreciation and amortization, less deferred
income taxes, exceed the present value of our proved reserves and the lower of
cost or fair value of unproved properties after income tax effects. Once
incurred, a write-down of oil and gas properties is not reversible at a later
date even if oil and gas prices increase. We did not incur a write-down of our
oil and gas property pool at year-end 2002.
You should not place undue reliance on our reserve data because they are
estimates.
This document contains estimates of Magnum Hunter's oil and gas reserves and the
future net cash flows that were prepared by independent petroleum consultants as
of December 31, 2002. There are numerous uncertainties inherent in estimating
quantities of proved reserves of oil and natural gas and in projecting future
rates of production and the timing of development expenditures, including many
factors beyond our control. The estimates in this document rely on various
assumptions, including, for example, constant oil and gas prices, operating
expenses, capital expenditures and the availability of funds, and are therefore
inherently imprecise indications of future net cash flows. Actual future
production, cash flows, taxes, operating expenses, development expenditures and
quantities of recoverable oil and gas reserves may vary substantially from those
assumed in the estimates. Any significant variance in these assumptions could
materially affect the estimated quantity and value of reserves.
You should not construe the present value of proved reserves referred to in this
document as the current market value of the estimated proved reserves of oil and
natural gas attributable to our properties. We have based the estimated
discounted future net cash flows from proved reserves generally on year-end
prices and costs, but actual future prices and costs may vary significantly. The
following factors may also affect actual future net cash flows:
. the timing of both production and related expenses;
. changes in consumption levels; and
. governmental regulations or taxation.
In addition, the calculation of the present value of the future net cash flows
uses a 10% discount rate, which is not necessarily the most appropriate discount
rate based on interest rates in effect from time to time and risks associated
with our reserves or the oil and gas industry in general. Furthermore, we may
need to revise our reserves downward or upward based upon actual production,
results of future development and exploration, supply and demand for oil and
natural gas, prevailing oil and natural gas prices and other factors, many of
which are beyond our control.
15
Maintaining reserves and revenues in the future depends on successful
exploration and development.
Our future success depends upon our ability to find or acquire additional oil
and gas reserves that are economically recoverable. Unless we successfully
explore or develop or acquire properties containing proved reserves, our proved
reserves will generally decline as we produce them. The decline rate varies
depending upon reservoir characteristics and other factors. Our future oil and
gas reserves and production, and, therefore, cash flow and income, depend
greatly upon our success in exploiting our current reserves and acquiring or
finding additional reserves. We cannot assure you that our planned development
projects and acquisition activities will result in significant additional
reserves or that we will successfully drill productive wells at economic returns
to replace our current and future production.
Our operations are subject to delays and cost overruns, and our activities may
not be profitable.
We intend to increase our exploration activities and to continue our development
activities. Exploratory drilling and, to a lesser extent, developmental drilling
of oil and gas reserves involve a high degree of risk. We have expanded, and
plan to increase our capital expenditures on, our exploration efforts, including
offshore exploration, which involve a higher degree of risk than our development
activities. It is possible that we will not obtain any commercial production or
that drilling and completion costs will exceed the value of production. The cost
of drilling, completing and operating wells is often uncertain. Numerous
factors, including title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of equipment,
may curtail, delay or cancel drilling operations. Furthermore, completion of a
well does not assure a profit on the investment or a recovery of drilling,
completion and operating costs.
We conduct waterflood projects and other secondary recovery operations.
Secondary recovery operations involve certain risks, especially the use of
waterflooding techniques. Our inventory of development prospects includes
waterflood projects. With respect to our properties located in the Permian
Basin, we have identified significant potential expenditures related to further
developing existing waterfloods. Waterflooding involves significant capital
expenditures and uncertainty as to the total amount of recoverable secondary
reserves. In waterflood operations, there is generally a delay between the
initiation of water injection into a formation containing hydrocarbons and any
increase in production. The operating cost per unit of production of waterflood
projects is generally higher during the initial phases of such projects due to
the purchase of injection water and related production enhancement costs. Costs
are also higher during the later stages of the life of the project as production
declines. The degree of success, if any, of any secondary recovery program
depends on a large number of factors, including the amount of primary
production, the porosity and permeability of the formation, the technique used,
the location of injector wells and the spacing of both producing and injector
wells.
We hedge our oil and gas production.
Periodically, we have entered into hedging transactions to reduce the effects of
fluctuations in crude oil and natural gas prices. At March 15, 2003, Magnum
Hunter had 72% of its natural gas production and 65% of its crude oil production
hedged through December 31, 2003. In addition, Magnum Hunter has 40% of its
natural gas production and 9% of its crude oil production hedged for the
calendar year 2004. The hedging activities of the company, while intended to
reduce sensitivity to changes in market prices of oil and gas, are subject to a
number of risks including instances in which we or the counterparties to our
hedging contracts fail to perform. Additionally, the fixed price sales and
hedging contracts limit the benefits the combined company will realize if actual
prices rise above the contract prices.
Our operations are subject to many laws and regulations.
The oil and gas industry is heavily regulated. Extensive federal, state, local
and foreign laws and regulations relating to the exploration for and
development, production, gathering and marketing of oil and gas affect our
operations. Some of the regulations set forth standards for discharge permits
for drilling operations, drilling and abandonment bonds or other financial
responsibility requirements, reports concerning operations, the spacing of
wells, unitization and pooling of properties and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on
16
production by restricting the rate of flow of oil and gas wells below actual
production capacity to conserve supplies of oil and gas.
Numerous environmental laws, including but not limited to, those governing the
management of waste, the protection of water and air quality, the discharge of
materials into the environment, and the preservation of natural resources,
impact and influence our operations. If we fail to comply with environmental
laws regarding the discharge of oil, gas, or other materials into the air, soil
or water we may be subject to liabilities to the government and third parties,
including civil and criminal penalties. These regulations may require us to
incur costs to remedy the discharge. Laws and regulations protecting the
environment have become more stringent in recent years, and may, in some
circumstances, result in liability for environmental damage regardless of
negligence or fault. New laws or regulations, or modifications of or new
interpretations of existing laws and regulations, may increase substantially the
cost of compliance or adversely affect our oil and gas operations and financial
condition. From time to time, we have agreed to indemnify sellers of producing
properties against some liabilities for environmental claims associated with
these properties. Material indemnity claims may also arise with respect to
properties acquired by or from us. Additionally, as a result of the merger with
Prize, we are now responsible for any environmental liabilities Prize may have
had in the past or which may occur in the future from these properties. While we
do not anticipate incurring material costs in connection with environmental
compliance and remediation, we cannot guarantee that we will not incur material
costs.
Marketability of our oil and natural gas production may be affected by factors
beyond our control.
The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. Most of our natural gas is delivered through gathering
systems and pipelines that we do not own. Federal and state regulation of oil
and natural gas production and transportation, tax and energy policies, changes
in supply and demand and general economic conditions all could adversely affect
our ability to produce and market our oil and natural gas. Our business is
subject to operating hazards that could result in substantial losses.
The oil and natural gas business involves operating hazards such as well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental hazards and
risks, any of which could cause us substantial losses. In addition, we may be
liable for environmental damage caused by previous owners of property we own or
lease. As a result, we may face substantial liabilities to third parties or
governmental entities, which could reduce or eliminate funds available for
exploration, development or acquisitions or cause us to incur losses. An event
that is not fully covered by insurance--for example, losses resulting from
pollution and environmental risks, which are not fully insurable--could have a
material adverse effect on our financial condition and results of operations.
Exploratory drilling is an uncertain process with many risks.
Exploratory drilling involves numerous risks, including the risks that we will
not find any commercially productive natural gas or oil reservoirs. The cost of
drilling, completing and operating wells is often uncertain, and a number of
factors can delay or prevent drilling operations, including:
. unexpected drilling conditions;
. pressure or irregularities in formations;
. equipment failures or accidents;
. adverse weather conditions;
. compliance with governmental requirements; and
. shortages or delays in the availability of drilling rigs in the
delivery of equipment.
Our future drilling activity may not be successful, nor can we be sure that our
overall drilling success rate or our drilling success rate for activity within a
particular area will not decline. Unsuccessful drilling activities could have a
material effect on our results of operations and financial condition. Also, we
may not be able to obtain any options or lease rights in potential drilling
locations that we identify. Although we have identified numerous potential
drilling locations, we can not be sure that we will ever drill them or that we
will produce natural gas or oil from them or any other potential drilling
locations.
17
Our acquisitions involve certain risks.
We have grown primarily through acquisitions and intend to continue acquiring
oil and gas properties in the future. Although we review and analyze the
properties that we acquire, such reviews are subject to uncertainties. It
generally is not possible to review in detail every individual property involved
in an acquisition. Ordinarily, we focus our review on the higher-valued
properties. However, even a detailed review of all properties and records may
not reveal existing or potential problems. Economics dictate that we cannot
become sufficiently familiar with all the properties to assess fully their
deficiencies and capabilities. We do not always conduct inspections on every
well. Even when we do inspect a specific well, we cannot always detect potential
problems, such as mechanical integrity of equipment and environmental conditions
that may require significant remedial expenditures.
As the merger with Prize demonstrates, we have begun to focus our acquisition
efforts on larger packages of oil and gas properties. Acquisitions of larger oil
and gas properties may involve substantially higher costs and may pose
additional issues regarding operations and management. We cannot assure you that
we will be able to successfully integrate all of the oil and gas properties that
we acquire into our operations or that we will achieve desired profitability
objectives.
We are subject to substantial competition.
We encounter substantial competition in acquiring properties, drilling for new
reserves, marketing oil and gas, securing trained personnel and operating our
properties. Many competitors have financial and other resources that
substantially exceed our resources. Our competitors in acquisitions,
development, exploration and production include major oil companies, natural gas
utilities, independent power producers, numerous independents who are both
public and private, individual proprietors and others. Our competitors may be
able to pay more for desirable leases and may be able to evaluate, bid for and
purchase a greater number of properties or prospects than our financial or
personnel resources will permit.
Our business may be adversely affected if we lose our key personnel.
We depend greatly upon three key individuals within our management team: Gary C.
Evans, Richard R. Frazier and Charles R. Erwin. The loss of the services of any
of these individuals could materially impact our operations.
RISKS RELATED TO SUBSTANTIAL LEVERAGE
We have a significant amount of debt.
In connection with our merger with Prize, we issued $300 million of 9.6% senior
notes due 2012 and established a new credit facility with a borrowing base of
$300 million secured by the assets of the combined company. Proceeds from the
senior notes offering and borrowings under the new credit facility were used to
refinance the outstanding indebtedness under the existing senior credit
facilities of both Magnum Hunter and Prize, fund the cash component of the
merger consideration in the merger with Prize and pay costs and fees associated
with the merger. In connection with the divestiture of certain non-core oil and
gas properties, our current borrowing base has been reduced to $250 million. As
a result of the merger, the combination of our outstanding 10% senior notes due
2007, our new issuance of the 9.6% senior notes due 2012 and our new senior bank
credit facility, created outstanding long term debt of approximately $590
million as of March 21, 2003. Because we must dedicate a substantial portion of
our cash flow from operations to the payment of interest on our debt, that
portion of our cash flow is not available for other purposes. The covenants
contained in our new credit facility and the indentures relating to our two
issuances of senior notes require us to meet financial tests and limit our
ability to borrow additional funds or to acquire or dispose of assets. Also, our
ability to obtain additional financing in the future may be impaired by our
substantial leverage. Additionally, the senior, as opposed to subordinated,
status of our 10% senior notes due 2007 and our 9.6% senior notes due 2012, our
high debt to equity ratio, and the pledge of substantially all of our assets as
collateral for our new credit facility will, for the foreseeable future, make it
difficult for us to obtain financing on an unsecured basis or to obtain secured
financing other than "purchase money" indebtedness collateralized by the
acquired assets.
18
We may not be able to meet our capital requirements.
We will need to continue to make substantial capital expenditures for the
acquisition, enhancement, exploitation and production of oil and natural gas
reserves. Without successful enhancement, exploitation and acquisition
activities, our reserves and revenues will decline over time due to natural
depletion. Our oil and natural gas capital expenditures for the year 2003 are
budgeted at $100 million, which we intend to use for enhancement, exploitation
and drilling activities. We intend to finance our capital expenditures, other
than significant acquisitions, from internally generated funds provided by
operations and borrowings under our new credit facility. The timing of most of
our capital expenditures is discretionary, with no long-term capital
commitments. Consequently, we have a significant degree of flexibility to adjust
the amounts of our capital expenditures as circumstances may warrant. However,
in the long term, if our cash flow from operations and availability under our
new credit facility are not sufficient to satisfy capital expenditure
requirements, there can be no assurance that additional debt or equity financing
will be available to allow us to fund our continued growth.
Our new credit facility and the indentures governing our senior notes impose
restrictions on us that may limit the discretion of our management in operating
our business that, in turn, could impair our ability to repay our obligations
under the notes.
Our new credit facility and the indentures governing our senior notes contain
various restrictive covenants that limit our management's discretion in
operating our business. In particular, these covenants limit our ability to,
among other things:
. incur additional debt;
. make restricted payments (including paying dividends on, redeeming
or repurchasing our capital stock);
. make investments or acquisitions;
. grant liens on assets;
. sell our assets;
. engage in transactions with affiliates; and
. merge, consolidate or transfer substantially all of our assets.
Under some circumstances, including if we fail to meet certain financial tests,
the indentures governing our senior notes prohibit us from borrowing the full
amount of availability under our new credit facility.
Our new credit facility also requires us to maintain specified financial ratios
and satisfy some financial tests. Our ability to maintain or meet these
financial ratios and tests may be affected by events beyond our control,
including changes in general economic and business conditions, and we cannot
assure you that we will maintain or meet these ratios and tests or that the
lenders under the new credit facility will waive any failure to meet these
ratios or tests. A breach of any of these covenants could result in an event of
default under the new credit facility, in which case, the lenders could elect to
declare all amounts borrowed under the new credit facility, together with unpaid
accrued interest, to be immediately due and payable and to terminate all
commitments under the new credit facility.
RISKS RELATED TO MAGNUM HUNTER COMMON STOCK
The market price of our common stock and our ability to raise equity could be
adversely affected by sales of substantial amounts of common stock in the public
market or the perception that such sales could occur.
A substantial number of our shares are issuable upon the exercise of options and
warrants. A substantial number of shares will be available for sale by our
management and their affiliates under Rule 144 who collectively own
approximately 8% of our outstanding stock as of March 15, 2003.
In addition, we will have a significant number of shares that are freely
transferable without restriction. We had approximately 67,255,584 shares of
common stock issued and outstanding as of March 21, 2003. The possibility that
substantial amounts of common stock may be sold in the public market may
adversely affect prevailing and future market prices for our common stock and
could impair our ability to raise capital through the sale of equity securities
in the future.
19
We have never paid cash dividends on our common stock.
We have not previously paid any cash dividends on our common stock and we do not
anticipate paying cash dividends on our common stock in the foreseeable future.
We intend to reinvest all available funds for the development and growth of our
business. In addition, our new credit facility and the indentures governing our
10% senior notes due 2007 and our 9.6% senior notes due 2012, restrict the
payment of cash dividends on some types of securities.
We have outstanding preferred stock and have the ability to issue more.
Our common stock is subordinate to all outstanding classes of preferred stock in
the payment of dividends and other distributions made with respect to the common
stock, including distributions upon liquidation or dissolution of Magnum Hunter.
Our board of directors is authorized to issue up to 10,000,000 shares of
preferred stock without first obtaining stockholder approval, except in limited
circumstances. We have previously issued several series of preferred stock.
Although only the 1996 Series A Convertible Preferred Stock is currently
outstanding and is presently owned 100% by a wholly-owned subsidiary, we have
the ability to resell such securities to a third party. If we designate or issue
other series of preferred stock, it will create additional securities that will
have dividend and liquidation preferences over the common stock. If we issue
convertible preferred stock, a subsequent conversion may dilute the current
common stockholders' interest.
Anti-takeover provisions may affect your rights as a stockholder.
Our articles of incorporation and bylaws and Nevada law include provisions that
may encourage persons considering unsolicited tender offers or other unilateral
takeover proposals to negotiate with our board of directors rather than pursue
non-negotiated takeover attempts. These provisions include authorized "blank
check" preferred stock, restrictions, under some circumstances, on business
combinations with stockholders who own 10% or more of our common stock and
restrictions, under some circumstances, on a stockholder's ability to vote the
shares of our common stock it owns when it crosses specified thresholds of
ownership. Our ability to issue preferred stock may also delay or prevent a
change in control of Magnum Hunter without further stockholder action and may
adversely affect the rights and powers, including voting rights, of the holders
of common stock. Under some circumstances, the issuance of preferred stock could
depress the market price of our common stock.
In addition, in January 1998 our Board of Directors adopted a stockholder rights
plan. Under the stockholder rights plan, the rights initially represent the
right to purchase one one-hundredth of a share of 1998 Series A Junior
Participating Preferred Stock for $35.00 per share. The rights become
exercisable only if a person or a group acquires or commences a tender offer for
15% or more of our common stock, a so-called "acquiring person." The stockholder
rights plan was amended so that Natural Gas Partners V, L.P. would not be
considered an "acquiring person" by reason of the merger with Prize. Until these
rights become exercisable, they attach to and trade with our common stock. The
rights issued under the stockholder rights plan expire January 20, 2008.
In addition, a change of control, as defined under the indentures relating to
our senior notes, would entitle the holders of those notes to put those notes to
us under the indentures and would entitle the lenders to accelerate payment of
outstanding indebtedness under our new credit facility. Both of these events
could discourage takeover attempts by making such attempts more expensive and
requiring greater capital resources.
ITEM 2. DESCRIPTION OF PROPERTIES
OIL AND GAS RESERVES
General
All information set forth in this Form 10-K regarding estimated proved reserves,
related estimated future net cash flows and PV-10 of our oil and gas interests
is taken from reports prepared by:
(a) DeGolyer and MacNaughton of Dallas, Texas and Cawley Gillespie &
Associates, Inc. of Fort Worth, Texas, both independent petroleum
engineers with respect to our interests at December 31, 2002 (using oil
and gas prices in effect at December 31, 2002);
20
(b) DeGolyer and MacNaughton of Dallas, Texas and Cawley Gillespie &
Associates, Inc. of Fort Worth, Texas, both independent petroleum
engineers with respect to our interests at December 31, 2001 (using oil
and gas prices in effect at December 31, 2001); and
(c) Ryder Scott Company of Houston, Texas, DeGolyer and MacNaughton and
Cawley Gillespie & Associates, Inc., all independent petroleum engineers
with respect to our interests at December 31, 2000 (using oil and gas
prices in effect at December 31, 2000).
The estimates of these independent petroleum engineers were based upon their
review of production histories and other geological, economic, ownership and
engineering data we provided.
PV-10 is the present value of proved reserves which is an estimate of the
discounted future net cash flows from each of our properties at December 31,
2002, or as otherwise indicated. Net cash flow is defined as net revenues, after
deducting production and ad valorem taxes, future capital costs and operating
expenses, but before deducting federal income taxes. The future net cash flows
have been discounted at an annual rate of 10% to determine their "present
value." The present value is shown to indicate the effect of time on the value
of the revenue stream and should not be construed as being the fair market value
of the properties. Estimates have been made using constant oil and gas prices
and operating costs, at December 31, 2002, or as otherwise indicated.
The estimates of future net cash flows from proved reserves and their PV-10 are
made using oil and gas sales prices in effect as of the dates of such estimates
and are held constant throughout the life of the properties. Our estimates of
proved reserves, future net cash flows and PV-10 were estimated using the
following weighted average prices, before deduction of production taxes:
Prices Used in Reserve Reports at December 31,
------------------------------------------------
2002 2001 2000
------------------------------------------------
Gas (per Mcf) ............. $ 4.23 $ 2.53 $ 9.28
Oil (per Bbl) ............. $ 28.36 $ 16.95 $ 25.59
All reserves are evaluated at contract temperature and pressure which can affect
the measurement of gas reserves. Operating costs, development costs and certain
production related and ad valorem taxes were deducted in arriving at the
estimated future net cash flows. No provision was made for income taxes. The
estimates following this section set forth reserves considered to be
economically recoverable under normal operating methods and existing conditions
at the prices and operating costs prevailing at the dates indicated above. The
estimates of the PV-10 from future net cash flows differ from the standardized
measure of discounted future net cash flows set forth in the notes to our
Consolidated Financial Statements, which is calculated after provision for
future income taxes. There can be no assurance that these estimates are accurate
predictions of future net cash flows from oil and gas reserves or their present
value.
Proved reserves are estimates of oil and gas to be recovered in the future.
Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas will likely be different from those used in preparing
these reports. The amounts and timing of future operating and development costs
may also differ from those used. Accordingly, reserve estimates are often
different from the quantities of oil and gas that are ultimately recovered.
Except for the effect of changes in oil and gas prices, no major discovery or
other favorable or adverse event is believed to have caused a significant change
in these estimates of our proved reserves since December 31, 2002. No estimates
of proved reserves of oil and gas have been filed by the company with, or
included in any report to, any United States authority or agency (other than the
Securities and Exchange Commission) since January 1, 2001.
21
Company Reserves
The following tables set forth our estimated proved reserves of oil and gas and
the PV-10 thereof on an actual basis at December 31, 2002, 2001 and 2000.
ESTIMATED PROVED OIL AND NATURAL GAS RESERVES (a)
At December 31,
---------------------------------------
2002 2001 2000
----------- ----------- -----------
NET GAS RESERVES (Mcf):
Proved developed ............. 362,325,297 188,413,106 179,697,015
Proved undeveloped ........... 96,318,346 60,066,682 53,511,550
----------- ----------- -----------
Total proved gas reserves 458,643,643 248,479,788 233,208,565
=========== =========== ===========
NET OIL RESERVES (Bbl):
(including condensate and NGL)
Proved developed ............. 48,512,449 12,959,569 13,923,380
Proved undeveloped ........... 14,569,537 8,641,555 8,380,082
----------- ----------- -----------
Total proved oil reserves 63,081,986 21,601,124 22,303,462
----------- ----------- -----------
Total Proved Reserves (Mcfe) ........... 837,135,559 378,086,532 367,029,337
=========== =========== ===========
ESTIMATED PV-10 OF PROVED RESERVES (a)
At December 31,
------------------------------------------------------
2002 2001 2000
---------------- ---------------- ----------------
Estimated PV-10 (b) :
Proved developed ............. $ 1,065,997,065 $ 264,930,820 $ 829,688,640
Proved undeveloped ........... 180,443,353 46,939,305 269,843,116
---------------- ---------------- ----------------
Proved Reserves PV-10 (c) $ 1,246,440,418 $ 311,870,125 $ 1,099,531,756
================ ================ ================
- ----------
(a) Based upon reserve reports at December 31, 2002 and 2001 prepared
by D&M and Cawley Gillespie, and at December 31, 2000 prepared by
Ryder Scott, D&M and Cawley Gillespie.
(b) PV-10 differs from the standardized measure of discounted future
net cash flows set forth in the notes to the Consolidated
Financial Statements of the company, which is calculated after
provision for future income taxes.
(c) The standardized measure of discounted future net cash flows
related to proved oil and gas reserves at December 31, 2002, 2001
and 2000, respectively, were as follows: $969,809,000,
$305,693,000 and $804,923,000.
22
Significant Properties
On December 31, 2002, 100% of our proved reserves on a Bcfe basis were located
in the Mid-Continent region, the Permian Basin, Gulf Coast region and the Gulf
of Mexico. On such date, our properties included working interests in 4,947
gross (3,285 net) productive oil and gas wells.
The following table sets forth summary information with respect to our estimated
proved reserves of oil and gas at December 31, 2002.
PV-10 (a) PROVED RESERVES
-------------------------------------------------------------------------
NATURAL GAS
AMOUNT % OF OIL GAS EQUIVALENT
(IN THOUSANDS) TOTAL (Bbl) (Mcf) (Mcfe)
-------------------------------------------------------------------------
Mid-Continent region (b) $ 324,566 26.0 12,839,642 177,375,707 254,413,559
Permian Basin (b) ...... 545,759 43.8 43,845,282 152,783,310 415,855,002
Gulf Coast region (b) .. 148,834 12.0 2,924,362 66,183,948 83,730,120
Gulf of Mexico (b) ..... 227,281 18.2 3,472,700 62,300,678 83,136,878
-------------- ---------- ------------ ------------ ------------
Total ... $ 1,246,440 100% 63,081,986 458,643,643 837,135,559
============== ========== ============ ============ ============
- ----------
(a) PV-10 differs from the standardized measure of discounted future
net cash flows set forth in the notes to our Consolidated
Financial Statements, which is calculated after provision for
future income taxes.
(b) Based on reserve reports at December 31, 2002 prepared by D&M and
Cawley Gillespie.
OIL AND GAS PRODUCTION, PRICES AND COSTS
The following table shows the approximate net production attributable to our oil
and gas interests, the average sales price and the average production expense
attributable to our oil and gas production for the periods indicated. Production
and sales information relating to properties acquired or disposed of is
reflected in this table only since or up to the closing date of their respective
acquisition or sale and may affect the comparability of the data between the
periods presented.
YEAR ENDED DECEMBER 31,
2002 2001 2000
---------- ---------- ----------
Oil and gas production:
Oil (Mbbl) .......................... 3,875 1,410 1,298
Gas (MMcf) .......................... 47,683 24,861 19,579
Natural Gas Equivalents (MMcfe) ..... 70,933 33,322 27,368
Average sales price (a):
Before Hedge Contracts:
Oil (per Bbl) .................... $ 25.18 $ 23.64 $ 28.91
Gas (per Mcf) .................... 3.07 3.82 4.08
Natural Gas Equivalents (per Mcfe) 3.45 4.13 4.28
After Hedge Contracts:
Oil (per Bbl) .................... $ 24.04 $ 24.53 $ 22.95
Gas (per Mcf) .................... 3.10 3.96 3.90
Natural Gas Equivalents (per Mcfe) 3.40 3.99 3.88
Oil and gas production lifting costs (per Mcfe) $ 0.72 $ 0.61 $ 0.60
Production taxes and other costs (per Mcfe) (b) $ 0.40 $ 0.39 $ 0.46
- ----------
(a) Before deduction of production taxes and net of hedging results.
(b) Includes ad valorem taxes, insurance, bonds, company overhead and
net profits interest.
23
DRILLING ACTIVITY
The following table sets forth the results of our drilling activities during the
three fiscal years ended December 31, 2002, 2001 and 2000.
GROSS WELLS (a) NET WELLS (B)
------------------------------ -------------------------------------------------------
YEAR TYPE OF WELL TOTAL PRODUCING(c) DRY(d) TOTAL PRODUCING(c) DRY(d)
-------- --------------------- ----------- ---------------- ----------- ---------- ---------------- ---------
2002 Exploratory
Texas 2 1 1 1.3 1 0.3
Oklahoma 0 0 0 0 0 0
New Mexico 6 6 0 2.05 2.05 0
Other 21 16 5 6.24 4.82 1.42
Development
Texas 62 61 1 23.01 22.01 1
Oklahoma 3 2 1 0.26 0.13 0.13
New Mexico 16 16 0 5.20 5.20 0
Other 14 14 0 2.8 2.8 0
2001 Exploratory
Texas 2 1 1 1.3 1 0.3
Oklahoma 0 0 0 0 0 0
New Mexico 3 3 0 1.37 1.37 0
Other 10 8 2 4.39 3.68 0.71
Development
Texas 64 64 0 13.48 13.48 0
Oklahoma 3 2 1 0.89 0.39 0.5
New Mexico 13 13 0 7.69 7.69 0
Other 7 6 1 3.05 2.80 0.25
2000 Exploratory
Texas 13 12 1 2.82 2.51 0.31
Oklahoma 1 1 0 0.25 0.25 0
New Mexico 6 6 0 2.23 2.23 0
Other 16 15 1 6.13 5.63 0.50
Development
Texas 47 47 0 23.10 23.10 0
Oklahoma 1 1 0 0.50 0.50 0
New Mexico 2 2 0 1.18 1.18 0
Other 2 2 0 0.33 0.33 0
- ----------
(a) The number of gross wells is the total number of wells in which a
working interest is owned. Fluid injection wells for waterflood
and other enhanced recovery projects are not included as gross
wells.
(b) The number of net wells is the sum of fractional working interests
owned in gross wells expressed as whole numbers and fractions
thereof.
(c) A producing well is an exploratory or development well found to be
capable of producing either oil or gas in sufficient quantities to
justify completion as an oil or gas well.
(d) A dry well is an exploratory or development well that is not a
producing well.
24
OIL AND GAS WELLS
The following table sets forth the number of oil and natural gas wells in which
we had a working interest at December 31, 2002. All of these wells are located
in the United States.
PRODUCTIVE WELLS AS OF DECEMBER 31, 2002
---------------------------------------------------------------------------------
GROSS (a) NET (b)
---------------------------------------- ---------------------------------------
LOCATION OIL GAS TOTAL OIL GAS TOTAL
- ---------------------------------- ------------ ------------ ------------ ------------ ------------ -----------
Texas............................. 2,132 1,228 3,360 1,477.89 850.33 2,328.22
New Mexico........................ 328 386 714 234.59 261.72 496.31
Oklahoma.......................... 200 482 682 151.96 251.22 403.18
Louisiana......................... 24 23 47 15.76 12.67 28.43
Arkansas.......................... 62 1 63 2.65 0 2.65
Offshore Gulf of Mexico........... 5 59 64 0.63 23.91 24.54
Other............................. 1 16 17 0.01 2.14 2.15
------------ ------------ ------------ ------------ ------------ -----------
Total........................ 2,752 2,195 4,947 1,883.49 1,401.99 3,285.48
- ----------
(a) The number of gross wells is the total number of wells in which a
working interest is owned. Well counts include wells with multiple
completions.
(b) The number of net wells is the sum of fractional working interests
owned in gross wells expressed as whole numbers and fractions
thereof.
25
OIL AND GAS ACREAGE
The following table summarizes our developed and undeveloped leasehold acreage
at December 31, 2002.
DEVELOPED UNDEVELOPED
-------------------------------------- -----------------------------------
GROSS (a) NET (b) GROSS (a) NET (b)
------------------- ----------------- ----------------- ----------------
Kansas.............................. 10,377 6,873 480 480
Louisiana........................... 9,555 3,997 2,303 1,348
New Mexico.......................... 55,992 41,726 12,514 12,330
Oklahoma............................ 168,747 105,696 22,042 12,873
Texas............................... 454,422 361,848 136,785 86,001
Utah................................ 8,063 8,063 2,634 2,634
Wyoming............................. 25,775 25,555 2,720 2,720
Offshore Gulf of Mexico............. 193,903 75,666 440,490 239,119
Other............................... 10,934 4,908 3,790 1,169
------------------- ----------------- ----------------- ----------------
Total ........................ 937,768 634,332 623,758 358,674
- ----------
(a) The number of gross acres is the total number of acres in which a
working interest is owned.
(b) The number of net acres is the sum of fractional working interests
owned in gross acres expressed as whole numbers and fractions
thereof.
Substantially all of our interests are leasehold working interests or overriding
royalty interests (as opposed to mineral or fee interests) under standard
onshore oil and gas leases. As is customary in the industry, we generally
acquire oil and gas acreage without any warranty of title except as to claims
made by, through or under the transferor. Although we have title examined by a
landman or title attorney prior to acquisition of mineral acreage in those cases
in which the economic significance of the acreage justifies the cost, there can
be no assurance that losses will not result from title defects or from defects
in the assignment of leasehold rights. In certain instances, title opinions may
not be obtained if, in our judgment, it would be uneconomical or impractical to
do so.
ITEM 3. LEGAL PROCEEDINGS
No legal proceedings are pending other than ordinary routine litigation
incidental to our business, the outcome of which management believes will not
have a material adverse effect on the company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The company had no matters requiring a vote of security holders during the
fourth quarter of 2002.
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock began trading on the New York Stock Exchange on June 25, 2002,
under the symbol "MHR". Prior to trading on NYSE, our common stock traded on the
American Stock Exchange. The following table shows the quarterly high and low
sales price per share and the average daily trading volume for our common stock
for the periods indicated.
26
AVERAGE DAILY
TRADING VOLUME
HIGH LOW (SHARES)
--------------- ---------------- ---------------------
2002
First Quarter............................. $ 8.40 $ 6.60 497,037
Second Quarter............................ $ 7.99 $ 7.05 419,250
Third Quarter............................. $ 7.89 $ 4.70 214,508
Fourth Quarter............................ $ 6.54 $ 4.19 328,941
2001
First Quarter............................. $ 13.90 $ 10.11 128,456
Second Quarter............................ $ 12.48 $ 8.11 128,842
Third Quarter............................. $ 9.69 $ 7.70 108,418
Fourth Quarter............................ $ 11.30 $ 7.53 129,426
On March 21, 2003, the last reported sale price of our common stock on the New
York Stock Exchange was $5.58 per share. As of March 21, 2003, there were 3,534
record holders of Magnum Hunter common stock.
We have not previously paid any cash dividends on our Common Stock and do not
anticipate paying dividends on our Common Stock in the foreseeable future. It is
the present intention of management to utilize all available funds for the
development and growth of our business activities. Our existing credit facility
and our indentures related to our senior unsecured notes restrict the payment of
cash dividends on our securities.
The following table sets forth information with respect to the equity
compensation plans available to our directors, officers and employees as of
December 31, 2002:
EQUITY COMPENSATION PLAN
(A) (B) (C)
Number of Securities to be Number of securities
issued upon exercise of Weighted-Average exercise remaining available for
outstanding options and price of outstanding options future issuance under equity
Plan Category warrants and warrants compensation plans
- -------------------------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security holders 3,464,750 $ 6.76 30,250
Equity compensation plans
not approved by security
holders 1,501,200 $ 8.01 -
ITEM 6. SELECTED FINANCIAL DATA
The selected historical financial data sets forth our summary historical
consolidated financial data as of and for the years ended December 31, 2002,
2001, 2000, 1999 and 1998, which have been derived from the audited consolidated
financial statements and notes thereto. The selected historical financial data
is qualified in its entirety by, and should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the
27
financial statements and the notes thereto included elsewhere in this Form 10-K.
For additional information relating to our operations, see "Business" and
"Properties." Certain reclassifications have been made to the selected
historical financial data of the prior years, as well as to certain quarterly
financial data, to conform with the current presentation. All data is in
thousands, except per share data.
2002 2001 2000 1999 1998
------------ ------------ ------------ ------------ ------------
INCOME STATEMENT DATA:
Total operating revenues ................... $ 265,869 $ 152,806 $ 127,510 $ 69,626 $ 51,400
Total operating costs and expenses (a) ..... 197,000 104,755 77,181 54,514 94,414
------------ ------------ ------------ ------------ ------------
Operating profit (loss) .................... 68,869 48,051 50,329 15,112 (43,014)
Provision for impairment of investment (b) . (621) (7,123) - - -
Income (loss) before extraordinary loss .... 16,143 13,820 22,260 (6,826) (47,080)
Extraordinary loss from early extinguishment
of debt, net of taxes .................... (621) (304) - - -
Net Income (loss) .......................... 15,522 13,516 22,260 (6,826) (47,080)
Dividends applicable to preferred shares (c) - - (9,708) (4,509) (875)
Income (loss) applicable to common shares .. $ 15,522 $ 13,516 $ 12,552 $ (11,335) $ (47,955)
Income (loss) per common share before
extraordinary item
Basic (c) ............................... $ 0.26 $ 0.40 $ 0.60 $ (0.57) $ (2.27)
Diluted (c) ............................. $ 0.26 $ 0.37 $ 0.51 $ (0.57) $ (2.27)
Income (loss) per common share after
extraordinary item
Basic (c) ............................... $ 0.25 $ 0.39 $ 0.60 $ (0.57) $ (2.27)
Diluted (c) ............................. $ 0.25 $ 0.36 $ 0.51 $ (0.57) $ (2.27)
OTHER DATA:
Cash flow from operating activities ........ $ 83,403 $ 104,074 $ 49,466 $ 17,435 $ 13,688
Capital expenditures (d) ................... $ 141,046 $ 204,370 $ 60,830 $ 59,968 $ 70,187
- ----------
(a) Includes in 1998 the non-cash write-down of $42.745 million of oil
and gas properties in the full-cost pool due to the ceiling test
limitation and in 2001 a provision for loss of $3.156 million
related to the Enron bankruptcy.
(b) Includes in 2002 and 2001 a provision for $621 thousand and $2.142
million, respectively, for the impairment of available-for-sale
equity securities deemed by management to have suffered an other
than temporary impairment. The impairment was determined using a
quoted market price at December 31, 2001 of $0.86 per share. We
had previously reported losses in accumulated other comprehensive
income of $507,000 ($466,000 net of income tax benefit) through
December 31, 2001. Also included in 2001 was an impairment
provision of $4.981 million due to the bankruptcy of a privately
held company in which Magnum Hunter owned a minority interest and
had invested $4.528 million in equity securities and $453 thousand
in secured loans.
(c) Includes the effect in the year 2000 of the payment of $5.5
million fee paid upon redemption of $25.0 million (liquidation
value) of our 1999 Series A 8% Convertible preferred stock. The
fee was treated as a dividend, reducing income per common share,
basic and diluted, by $0.26 per share and $0.17 per share,
respectively, for the year 2000.
(d) Capital expenditures include cash expended for acquisitions plus
normal additions to oil and natural gas properties and other fixed
assets. It does not include the cost of property acquired through
the issuance of common stock.
28
2002 2001 2000 1999 1998
------------ ------------ ------------ ------------ ------------
BALANCE SHEET DATA:
Property, plant and equipment, net.... $ 1,001,609 $ 419,837 $ 260,532 $ 265,195 $ 228,436
Total assets ......................... 1,169,779 454,385 315,612 304,022 265,724
Total debt (a) ....................... 570,837 288,583 191,139 234,806 231,020
Stockholders' equity ................. $ 350,196 $ 117,974 $ 93,416 $ 51,552 $ 19,697
- ----------
(a) Consists of current notes payable and long-term debt, including
current maturities of long-term debt, and excluding production
payment liabilities of $114 thousand, $203 thousand, $359
thousand, $460 thousand, and $633 thousand as of December 31,
2002, 2001, 2000, 1999 and 1998, respectively. As of December 31,
2002, 2000 and 1999, $7.0 million, $20.6 million and $41.8
million, respectively, of the debt was non-recourse to the
company.
The following tables set forth unaudited summary financial results on a
quarterly basis for the two most recent years.
2002
----------------------------------------------------------
FIRST SECOND THIRD FOURTH
------------ ------------ ------------ ------------
Revenues ...................................... $ 43,124 $ 76,190 $ 72,833 $ 73,722
Depreciation, depletion and amortization ...... 15,096 23,542 24,309 23,521
Operating Profit .............................. 9,297 21,056 18,773 19,743
Provision for impairment of investment (a)..... - (621) - -
Net Income .................................... 7,446 2,251 2,746 3,079
Income per common share, basic (b)............. 0.18 0.03 0.04 0.05
Income per common share, diluted (b)........... $ 0.17 $ 0.03 $ 0.04 $ 0.04
2001
---------------------------------------------------------
FIRST SECOND THIRD FOURTH
------------ ------------ ------------ ------------
Revenues ...................................... $ 50,570 $ 39,344 $ 33,862 $ 29,030
Depreciation, depletion and amortization ...... 7,415 9,686 12,218 14,680
Operating Profit (Loss) ....................... 25,846 14,647 8,202 (644)
Provision for impairment of investment (a)..... - - - (7,123)
Net Income (Loss) ............................. 14,028 6,275 1,971 (8,758)
Income (Loss) per common share, basic (b)...... 0.41 0.18 0.06 (0.25)
Income (Loss) per common share, diluted (b).... $ 0.37 $ 0.17 $ 0.05 $ (0.24)
(a) Includes in 2002 and 2001 provisions for $621 thousand and $7.123
million, respectively, for the impairment of equity securities
deemed by management to have suffered an other than temporary
impairment. We had previously reported losses in accumulated other
comprehensive income of $507,000 ($466,000 net of income tax
benefit) through December 31, 2001. Also included in 2001 was an
impairment provision of $4.981
29
million due to the bankruptcy of a privately held company in which
Magnum Hunter owned a minority interest and had invested $4.528
million in equity securities and $453 thousand in secured loans.
(b) Loss per common share for the second and third quarters of 2002
were the same for basic and diluted due to the exclusion of
warrants and options whose effect were anti-dilutive.
ITEM 7. MANAGEMENT DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our
consolidated financial statements and the notes associated with them contained
elsewhere in this report. This discussion should not be construed to imply that
the results discussed herein will necessarily continue into the future or that
any conclusion reached herein will necessarily be indicative of actual operating
results in the future. Such discussion represents only the best present
assessment by management of the company.
Our results of operations are significantly affected by our ability to maintain
or increase oil and natural gas production through exploration and exploitation
activities. Fluctuations in oil and gas prices also significantly affect our
results of operations.
Successful merger and acquisition activities also have a large impact on our
results of operations by increasing proved reserves in our core areas which
allow us greater exploration and production potential paired with existing
operation and production expertise in these areas.
Effective September 1, 2000, we acquired a 5.5% net profits interest in the
Panoma production and gas gathering facilities for $3.5 million of our
restricted common stock. By acquiring this interest, we lowered our lease
operating expense, increased oil field services income, and reduced a permanent
burden on this property.
Effective July 1, 2001, we acquired proved and unproved oil and gas properties
located in Southeast New Mexico totaling approximately 41.8 Bcfe of reserves for
$31.6 million, net of purchase price adjustments. The transaction had an
effective date of July 1, 2001.
On March 15, 2002, we completed our merger with Prize Energy Corp. ("Prize"), a
publicly traded oil and gas production company engaged primarily in the
acquisition, enhancement, and exploitation of producing oil and gas properties.
The transaction has been accounted for as a purchase of Prize by the company in
accordance with the provisions of SFAS No. 141. Under the terms of the merger,
we distributed 2.5 shares of common stock plus $5.20 in cash for each Prize
share outstanding. The following summary, prepared on a pro forma basis,
presents the results of operations for the years ended December 31, 2002 and
2001 as if the acquisitions occurred as of the beginning of the respective
years. The pro forma information includes the effects of adjustments for
interest expense, depreciation, depletion and amortization, and income taxes:
30
(UNAUDITED)
----------------------------------
2002 2001
--------------- ---------------
(IN THOUSANDS, EXCEPT FOR
PER SHARE AMOUNTS)
Revenue ............................................. $ 292,872 $ 334,873
Total Operating Costs and Expenses .................. (219,575) (224,138)
--------------- ---------------
Operating Profit .................................... 73,297 110,735
Interest Expense and Other .......................... (59,202) (52,680)
--------------- ---------------
Income before Tax ................................... 14,095 58,055
Provision for Income Tax ............................ 513 (21,792)
Extraordinary loss from early extinguishment of debt (621) (304)
--------------- ---------------
Net Income .......................................... $ 13,987 $ 35,959
Net Income Per Common Share
Basic ............................................ $ 0.20 $ 0.52
Diluted .......................................... $ 0.20 $ 0.50
During 2000, 2001 and 2002, we realized proceeds of $43.8 million, $1.1 million,
and $96.0 million, respectively, from the sale of non-core oil and gas and other
properties.
The following table sets forth certain information with respect to our oil and
gas operations and our gas gathering, marketing and processing operations:
YEARS ENDED
2002 2001 2000
---------- ---------- ----------
Oil and Gas Operations
Production:
Oil (MBbls) ........................ 3,875 1,410 1,298
Gas (MMcf) ......................... 47,683 24,861 19,579
Oil and Gas (MMcfe) ................ 70,933 33,322 27,368
Equivalent Daily Rate (MMcfe/day) .. 194.3 91.3 74.8
Average Sale Prices (after hedging)
Oil (per Bbl) ...................... $ 24.04 $ 24.53 $ 22.95
Gas (per Mcf) ...................... 3.10 3.96 3.90
Oil and Gas (per Mcfe) ............. 3.40 3.99 3.88
Effect of hedging activities (per Mcfe) (0.05) 0.14 (0.41)
Lease Operating Expense (per Mcfe)
Lifting costs ...................... 0.72 0.61 0.60
Production tax and other costs ..... 0.40 0.39 0.46
Gross margin (per Mcfe) ............... $ 2.28 $ 2.99 $ 2.82
31
YEARS ENDED
2002 2001 2000
------------ ------------ -----------
Gas Gathering, Marketing and
Processing Operations
Throughput Volumes (Mcf per day)
Gathering ..................... 15,535 16,139 16,639
Processing .................... 22,811 13,257 16,506
Gross margin (in thousands)
Gathering (per Mcf throughput) $ 0.13 $ 0.04 $ 0.18
Processing (per Mcf throughput) $ 0.55 $ 0.27 $ 0.50
PERIOD TO PERIOD COMPARISONS
FOR THE YEARS ENDED DECEMBER 31, 2002 AND 2001
We reported net income of $15.5 million for the year ended December 31, 2002 as
compared to net income of $13.5 million for the same period in 2001, an increase
of 15%. The 2002 period results include a provision for impairment of
investments of $621 thousand and an extraordinary loss from early extinguishment
of debt (net of tax benefits) of $621 thousand. The 2001 period results include
a loss on Enron related assets of $3.2 million, a provision for impairment of
investments of $7.1 million, and an extraordinary loss from early extinguishment
of debt (net of tax benefits) of $304 thousand from the repurchase of $10.5
million of the Company's 10% Senior Notes. Total operating revenues increased
74% to $265.9 million in 2002 from $152.8 million in 2001 and operating profit
increased 44% to $68.9 million in 2002 from $48.0 million in 2001. A 15%
decrease in the price received for oil and gas sold (on a thousand cubic feet
equivalent, or Mcfe, basis), combined with a 113% increase in oil and gas
production (on a million cubic feet equivalent, or MMcfe, basis) in our oil and
gas exploration and production segment, was primarily responsible for the
improvement in revenues. The production increase was primarily due to the merger
with Prize. Total operating cost and expenses increased 88% to $197.0 million in
2002 from $104.8 million in 2001, principally due to higher depreciation,
depletion and amortization expense, lease operating expenses, and general
administrative expenses due to the merger with Prize. Income before income tax
decreased 33% to $14.9 million in 2002 from $22.4 million in 2001, primarily due
to higher interest expense and non cash hedging losses due to the Prize merger.
Income per common share- diluted was $0.25 per share in the 2002 period compared
to $0.36 per share in the 2001 period, a decrease of 31% due to a 68% increase
in diluted shares, principally as a result of the Prize merger. The effect of
the extraordinary loss in the 2002 and 2001 periods was $0.01 per share, basic
and diluted. No dividends were recorded in the 2002 or 2001 periods due to the
conversion of $25.0 million (liquidation value) of our 1999 Series A 8%
Convertible preferred stock on January 1, 2001 into approximately 4.8 million
shares of our common stock.
Oil and Gas Operations:
For the year ended December 31, 2002, we reported oil production of 3.9 MMbbls
(million barrels) and gas production of 47.7 MMcf (million cubic feet), which
represents an increase of 175% in oil and an increase of 92% in gas produced
from the comparable period in 2001. Our reported equivalent daily rate of
production on a million cubic feet per day basis (MMcfe/day) increased 113% to
194.3 MMcfe/day in the 2002 period from 91.3 MMcfe/day in the 2001 period. These
increases were primarily the result of the Prize merger and the success of our
drilling program offsetting normal production declines.
Prices realized in the 2002 period averaged $24.04 per barrel of oil and $3.10
per Mcf of gas. This represents a 15% decrease on a thousand cubic feet of gas
equivalent (Mcfe) basis over the 2001 period average realized prices of $24.53
per barrel of oil and $3.96 per Mcf of gas. The unit prices realized include the
effects of hedging. During the 2002 period, hedging decreased the average price
we received for oil by $1.14 per barrel and increased the average price we
received for gas by $0.03 per Mcf. Excluding the effects of hedging, oil prices
increased 7% and natural gas prices decreased 20% in 2002 from those received in
2001.
As a result of higher production levels, partially offset by lower realized
prices, oil and gas revenues increased 81% to $241.0 million in the 2002 period
compared to $133.1 million in the 2001 period.
32
For the 2002 period, oil and gas production lifting costs, on a unit of
production basis, were $0.72 per Mcfe as compared to $0.61 per Mcfe in the 2001
period, an increase of 18% due to the relatively higher cost per unit of the
Prize properties. Production tax and other costs were $0.40 per Mcfe in the 2002
period compared to $0.39 per Mcfe in the 2001 period, an increase of 3%
principally due to higher ad valorem taxes.
Gross margin for oil and gas operations for the 2002 period was $161.2 million,
or $2.28 per Mcfe, compared to $99.7 million, or $2.99 per Mcfe in the 2001
period, a decrease of 24% on a per unit of production basis, primarily as a
result of the decrease in oil and gas prices realized and the increase in
lifting costs per unit.
Gathering, Marketing and Processing Operations:
For the year ended December 31, 2002, our gathering system throughput was 15.5
MMcf per day versus 16.1 MMcf per day for the same period in 2001, a decline of
4% due to normal production declines behind the system. Gas processing
throughput was 22.8 MMcf per day in 2002 versus 13.3 MMcf per day in 2001, an
increase of 72%. Our reported processing throughput in the 2001 period was
reduced due to (i) the sale in September 2001 of a substantial ownership
interest in oil and gas properties supplying one of our plants, (ii) the
voluntary shutdown of two gas processing plants for approximately two months of
the 2001 period due to adverse processing economics as a result of high natural
gas prices and (iii) normal production declines on properties supplying the
plants. Our processing throughput in the 2002 period was increased due to the
acquisition of a processing plant in the merger with Prize.
Revenues from gathering, marketing and processing increased 16% to $20.8 million
in 2002 versus $17.9 million in 2001, primarily due to the acquisition of a
processing plant in the merger with Prize. The gross margin realized from
gathering, marketing and processing for 2002 was $5.7 million versus $1.8
million in 2001, an increase of 218%. Gathering margin was $0.13 per Mcf
gathered in 2002 versus $0.04 per Mcf in 2001 due to an increase in marketing
spreads. In the 2000 period, losses were incurred on pipeline imbalance
positions. Processing margin was $0.55 per Mcf in 2002 compared to $0.27 per Mcf
in 2001 due to more favorable processing economics because of the decline in
natural gas prices and the temporary shutdown of two plants for a portion of the
2001 period.
Oil Field Management Services Operations:
Revenues from oil field management services were $4.1 million in the 2002 period
versus $1.8 million in the 2001 period due to higher management and operations
services fees charged to third parties as a result of the Prize merger.
Operating costs increased to $2.5 million in 2002 from $1.3 million in 2001 due
to higher costs for labor and overhead. The gross margin for this segment in
2002 was $1.6 million versus $551 thousand in 2001, an increase of 194%.
Other Income and Expenses:
Depreciation and depletion expense was $86.5 million in the 2002 period versus
$44.0 million in the 2001 period, an increase of 97% due to higher production
levels as a result of the Prize merger. Depreciation and depletion on oil and
gas properties was $1.17 per Mcfe in 2002 versus $1.28 per Mcfe in 2001. This 9%
decrease in the equivalent unit cost was due primarily to the merger with Prize
which added proved reserves at a cost of approximately $0.84 per Mcfe.
General and administrative expense for 2002 increased 93% to $13.3 million from
$6.9 million in 2001. The principal cause of this increase was an increase in
salary, benefits and retirement plan expenses and an increase in our overall
headcount associated with the Prize merger. The numbers of employees at fiscal
year-end 2002 and 2001 were 221 and 105, respectively. We recorded equity in
earnings of affiliate of $792 thousand in 2002 versus income of $1.1 million in
2001, a 27% decrease, due to an operating loss recorded by one of the
affiliates. Other income was $452 thousand for 2002 versus $283 thousand in
2001, a 60% increase, due to an increase in interest income. We recognized a
$6.6 million loss in other non-cash hedging adjustments in 2002 versus a gain of
$52 thousand in 2001. In the 2002 period, $6.1 million relates to the
amortization of commodity hedge assets acquired in the Prize merger, while $500
thousand was due to recording hedge ineffectiveness. In the 2001 period, the $52
thousand gain was due to interest rate swaps.
33
We made provision for a $3.2 million loss on assets associated with the Enron
Corp. bankruptcy in the 2001 period. Of the total loss provision recorded,
approximately $2.5 million was related to accounts receivable for Enron for
physical gas sales and approximately $701 thousand was related to a receivable
from a natural gas commodity hedge in which Enron was the counterparty.
We had equity and debt investments in a privately held entity which declared
bankruptcy subsequent to December 31, 2001, and we provided an impairment charge
against earnings of $5.0 million at December 31, 2001. Additionally, we had an
investment in available-for-sale securities of another entity of $2.7 million at
December 31, 2001. Because of the deteriorating financial condition of this
entity, we reported an other than temporary impairment of $2.1 million as a
charge against earnings at December 31, 2001, based on the entity's reported
market value on that date. In 2002, this entity declared bankruptcy and we
recorded a further impairment of $621 thousand on this investment.
Interest expense was $47.9 million for 2002 versus $19.9 million for 2001, an
increase of 141%, primarily as a result of higher debt levels due to the Prize
merger. On March 15, 2002 we issued $300 million in 9.6% Senior unsecured notes
due in 2012. During the 2002 period, the interest rate on our Senior bank debt
was 4.0% versus 6.3% in 2001, a decline of 36%. The weighted average daily
balance of bank debt increased 96% to $182.9 million in 2002 from $93.3 million
in 2001. By December 31, 2002, the level of debt under our Senior bank revolving
credit line had been reduced to $125 million through sales of non-strategic oil
and gas properties. In addition, interest expense was reduced in the 2001 period
by $744 thousand as a result of interest rate derivatives versus an increase in
interest expense of $1.2 million from interest rate derivatives in the 2002
period.
We recorded an income tax benefit of $1.2 million in 2002 versus income tax
expense of $8.6 million in 2001. The 2002 period benefitted from a $7.1 million
reduction in the valuation allowance charged against deferred tax assets as a
result of the increased likelihood (due to the Prize merger) that the tax assets
generated from prior net operating losses will be realized in the future. The
2002 period was also impacted by a $2.3 million deferred tax provision from the
adjustment of goodwill due to sales of non-strategic oil and gas properties. The
effective tax rate for 2002 and 2001 was (8.1%) and 38%, respectively. The
variance in the effective tax rate from the statutory rate of 35% was due to the
release of the valuation allowance on our previously reserved deferred tax
assets in 2002.
FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000
We reported net income of $13.5 million for the year ended December 31, 2001 as
compared to net income of $22.3 million for the same period in 2000, a decrease
of 39%. The 2001 period results include a loss on Enron related assets of $3.2
million, a provision for impairment of investments of $7.1 million, and an
extraordinary loss from early extinguishment of debt of $304 thousand, net of
tax benefits, from the repurchase of $10.5 million of the Company's 10% Senior
Notes. Total operating revenues increased 20% to $152.8 million in 2001 from
$127.5 million in 2000 and operating profit decreased 5% to $48.1 million in
2001 from $50.3 million in 2000. A 3% increase in the price received for oil and
gas sold (on a thousand cubic feet equivalent, or Mcfe, basis), combined with a
22% increase in oil and gas production (on a million cubic feet equivalent, or
MMcfe, basis) in our oil and gas exploration and production segment was
primarily responsible for the improvement in revenues, while higher
depreciation, depletion and amortization expense and the Enron related loss were
primarily responsible for the increase in operating costs and expenses. Income
applicable to common shares was $13.5 million in the 2001 period versus $12.6
million in the 2000 period, an increase of 8%. Income per common share-diluted
was $0.36 per share in the 2001 period compared to $0.51 per share-diluted, in
the 2000 period, a decrease of 29% due to a 13% increase in diluted shares. The
effect of the extraordinary loss in the 2001 period was $0.01 per share, basic
and diluted. No dividends were recorded in the 2001 period due to the conversion
of $25.0 million (liquidation value) of our 1999 Series A 8% Convertible
preferred stock on January 1, 2001 into approximately 4.8 million shares of our
common stock. We had previously redeemed $25.0 million (liquidation value) of
the 1999 Series A 8% Convertible preferred stock in December 2000, and Bluebird
acquired 100% of our $10.0 million (liquidation value) in 1996 Series A
Convertible preferred stock during 2000.
Oil and Gas Operations:
For the year ended December 31, 2001, we reported oil production of 1.4 MMbbls
(million barrels) and gas production of 24,861 MMcf (million cubic feet), which
represents an increase of 9% in oil and an increase of 27% in gas produced from
the comparable period in 2000. Our reported equivalent daily rate of production
on a million cubic feet per day basis (MMcfe/day) increased 22% to 91.3
MMcfe/day in the 2001 period from 74.8 MMcfe/day in the 2000 period. These
increases were primarily the result of the success of our drilling program
offsetting normal production declines.
34
Prices realized in the 2001 period averaged $24.53 per barrel of oil and $3.96
per Mcf of gas. This represents a 3% increase on a thousand cubic feet of gas
equivalent (Mcfe) basis over the 2000 period average realized prices of $22.95
per barrel of oil and $3.90 per Mcf of gas. The unit prices realized include the
effects of hedging. During the 2001 period, hedging increased the average price
we received for oil by $0.89 per barrel and the average price we received for
gas by $0.14 per Mcf. Excluding the effects of hedging, oil prices declined 18%
and natural gas prices declined 6% in 2001 from those received in 2000.
As a result of higher realized prices and higher production levels, oil and gas
revenues increased 25% to $133.1 million in the 2001 period compared to $106.1
million in the 2000 period.
For the 2001 period, oil and gas production lifting costs, on a unit of
production basis, were $0.61 per Mcfe as compared to $0.60 per Mcfe in the 2000
period, an increase of 2%. Production tax and other costs were $0.39 per Mcfe in
the 2001 period compared to $0.46 per Mcfe in the 2000 period, a decline of 15%,
principally due to lower production taxes. Lower production taxes are a result
of lower oil and gas prices before the effect of hedge transactions and higher
production levels in the Gulf of Mexico on which no production taxes are levied.
Gross margin for oil and gas operations for the 2001 period was $99.7 million,
or $2.99 per Mcfe, compared to $77.1 million, or $2.82 per Mcfe in the 2000
period, an increase of 6% on a per unit of production basis, primarily as a
result of higher oil and gas prices realized and the increase in our daily unit
production rate.
Gathering, Marketing and Processing Operations:
For the year ended December 31, 2001, our gathering systems throughput was 16.1
MMcf per day versus 16.6 MMcf per day for the same period in 2000, a decline of
3% due to normal production declines behind the systems. Gas processing
throughput was 13.3 MMcf per day in 2001 versus 16.5 MMcf per day in 2000, a
decrease of 20%. Our reported processing throughput in the 2001 period was
reduced due to (i) the sale in September 2000 of a substantial ownership
interest in oil and gas properties supplying one of our plants, (ii) the
voluntary shutdown of two gas processing plants for approximately 1 1/2 months
of the 2001 period due to adverse processing economics as a result of high
natural gas prices and (iii) normal production declines on properties supplying
the plants.
Revenues from gathering, marketing and processing decreased 11% to $17.9 million
in 2001 versus $20.0 million in 2000, primarily due to a decline in natural gas
liquids prices and a decrease in throughput. Operating costs for the gathering,
marketing and processing segment increased 3% to $16.1 million in 2001 from
$15.7 million in 2000.
The gross margin realized from gathering, marketing and processing for 2001 was
$1.8 million versus $4.3 million in 2000, a decrease of 59%. Gathering margin
was $0.04 per Mcf gathered in 2001 versus $0.18 per Mcf in 2000 due to a
decrease in marketing spreads and losses incurred on pipeline imbalance
positions. Processing margin was $0.27 per Mcf in 2001 compared to $0.50 per Mcf
in 2000 due to less favorable processing economics because of the decline in
natural gas liquids prices and the temporary shutdown of two plants for a
portion of the 2001 period.
Oil Field Management Services Operations:
Revenues from oil field management services were $1.8 million in the 2001 period
versus $1.4 million in the 2000 period due to higher management and operations
services fees charged to third parties, primarily on offshore operations.
Operating costs increased to $1.3 million in 2001 from $903 thousand in 2000 due
to higher costs for labor and overhead. The gross margin for this segment in
2001 was $551 thousand versus $545 thousand in 2000, an increase of 1%.
Other Income and Expenses:
Depreciation and depletion expense was $44.0 million in the 2001 period versus
$25.6 million in the 2000 period, an increase of 72% due to higher production
levels and higher unit costs. Depreciation and depletion on oil and gas
properties was $1.28 per Mcfe in 2001 versus $0.89 per Mcfe in 2000. This 44%
increase in the equivalent unit cost was due primarily to an increase in
development costs associated with our exploration efforts in the Gulf of Mexico.
35
General and administrative expense for 2001 increased 13% to $6.9 million from
$6.1 million in 2000. The principal cause of this increase was an increase in
salary, benefits and retirement plan expenses and an increase in the Company's
overall headcount associated with its increased activity level. The number of
personnel employed by the company at fiscal year-end 2000 and 2001 were 95 and
105, respectively. We recorded equity in earnings of affiliate of $1.1 million
in 2001 versus income of $1.3 million in 2000, a 17% decrease, due to decreased
net earnings from gas marketing operations of the Company's 30% owned affiliate.
Other income was $283 thousand for 2001 versus $477 thousand in 2000, a 41%
decrease, due to a reduction in interest income. We recognized a gain from
non-cash hedging adjustments of $52 thousand in 2001 due to interest rate swaps
versus none in 2000.
We made provision for a $3.2 million loss on assets associated with the Enron
Corp. bankruptcy in the 2001 period. Of the total loss provision recorded,
approximately $2.5 million was related to accounts receivable for Enron for
physical gas sales and approximately $701 thousand was related to a receivable
from a natural gas commodity hedge in which Enron was the counterparty.
We had equity and debt investments in a privately held entity which declared
bankruptcy subsequent to December 31, 2001, and for which we provided an
impairment charge against earnings of $5.0 million at December 31, 2001.
Additionally, we had an investment in available-for-sale securities of another
entity of $2.7 million at December 31, 2001. Because of the deteriorating
financial condition of this entity, we reported an other than temporary
impairment of $2.1 million as a charge against earnings at December 31, 2001,
based on the entity's reported market value on that date.
Interest expense was $19.9 million for 2001 versus $22.3 million for 2000, a
decrease of 11%. During the 2001 period, the interest rate on our primarily
LIBOR-based bank debt was 6.3% versus 9.1% in 2000, a decline of 31%. The
weighted average daily balance of bank debt increased 17% to $93.3 million in
2001 from $79.7 million in 2000. We also benefitted in the 2001 period by the
repurchase of $10.5 million of our 10% Senior Notes in June, 2001. In addition,
interest expense was reduced in the 2001 period by $744 thousand as a result of
interest rate derivatives versus an increase in interest expense of $13 thousand
from interest rate derivatives in the 2000 period.
We recorded a total provision for income tax expense of $8.6 million in 2001
versus $7.6 million in 2000, an increase of 14%. We made no adjustment to the
valuation allowance charged against deferred tax assets in the 2001 period,
whereas the 2000 period benefitted from a $3.9 million reduction in the
valuation allowance charged against deferred tax assets. The effective tax rate
for 2001 and 2000 was 38% and 25%, respectively. The variances in the effective
tax rate from the statutory rate of 35% was due to state income taxes in 2001.
There were no dividends applicable to preferred stock in 2001 as compared to
$9.7 million for the 2000 period. The elimination of the dividend was due to the
purchase, redemption and conversion of all of our outstanding dividend paying
preferred stock not controlled by wholly-owned entities.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL. Net cash provided by operating activities in
2002, 2001 and 2000 was $83.4 million, $104.1 million and $49.5 million,
respectively. Our 2002 cash provided by operations was lower than the prior year
due to higher receivables balances at year end, large margins posted on our
hedged positions, and payments to reduce the balances of the liabilities
acquired in the Prize merger. These increases were partially offset by increased
cash flows from tax refunds and closed positions on hedging assets acquired in
the Prize merger. The substantial increase in our operating cash flows in 2001
over 2000 is primarily the result of higher net realized oil and gas prices and
higher production levels. In the 2001 period compared to the 2000 period, a
reduction in trade accounts receivable and an increase in trade accounts payable
balances also contributed to increased operating cash flows.
Our net working capital position at December 31, 2002 was a deficit of $31.0
million. At this date, we had $122 million available under our senior bank
facility. A large factor in our negative working capital position was the $42.8
million current derivative liability we recorded at December 31, 2002 on our
2003 hedged positions due to continued increases in commodities prices over our
hedged prices during the second, third and fourth quarters of 2002. This
liability was partially offset by approximately $15.5 million of current
deferred tax assets which will be released as our 2003 hedges are settled. If
actual commodities prices realized remain higher than our hedged prices during
2003, our resulting higher cash proceeds received on our
36
production will offset any actual amounts paid out related to this liability. We
announced a redemption of $30 million in principal on our 10% Senior Notes in
December 2002. The redemption occurred January 27, 2003, and the net redemption
was $27.6 million due to $2.4 million of redeemed bonds already owned by a
wholly-owned subsidiary of the company. Because we funded the redemption through
our Senior Credit Facility, there was no negative impact on our working capital
position at December 31, 2002 due to the redemption.
Our net working capital position at December 31, 2001 was a deficit of $23.6
million. On that date, we had available $5.0 million under our senior bank
credit facility. Several items contributed to the deficit in working capital,
including a delay in obtaining $11.2 million of sale and leaseback financing of
offshore production platforms until January 2002, the $3.2 million loss we
sustained as a result of the Enron bankruptcy, and the postponement of
negotiations for the expected $5.4 million sale of certain assets, also a result
of uncertainty in the marketplace caused by Enron. We also cancelled plans to
sell an interest in a recent Gulf of Mexico discovery for $10 million because of
falling oil and gas prices in the fourth quarter of 2001 and general market
uncertainties.
INVESTING ACTIVITIES. Net cash used in investing was $89.4 million during 2002
due to increased capital expenditures and the cash portion of the Prize merger.
See below for further discussion of our capital expenditures and the merger with
Prize. These expenditures were partially offset by proceeds received on sales of
properties.
Net cash used in investing activities was $204.0 million in the 2001 period. We
made capital expenditures of $204.4 million during 2001. Our capital
expenditures are discussed in further detail below. We received a distribution
of $1.6 million from NGTS, LLC, a 30% owned natural gas marketing affiliate
which we account for under the equity method. Additionally, we made an
investment in another 10% owned company of $2.5 million. This affiliate is
accounted for as a cost basis investment. We realized proceeds of $1.1 million
from sale of assets, received payments on promissory notes receivable totaling
$70 thousand and had a decrease in deposits of $50 thousand during the 2001
period.
In the 2000 period, net cash used in investing activities was $20.0 million,
which included proceeds from asset sales of $43.8 million, capital expenditures
of $60.8 million, a loan made for $1.4 million, repayments on a loan of $1.0
million and investment in unconsolidated affiliate of $2.6 million.
FINANCING ACTIVITIES. Net cash provided by financing activities was $6.3 million
for 2002. We received $300 million from issuing 9.6% Senior unsecured notes due
2012, and paid down Magnum Hunter debt of $30 million. We also paid off $246.8
million of long-term debt acquired in the Prize merger. Under our existing stock
repurchase programs, we have the authorization to purchase up to four million
shares. During 2002, we spent $18 million to purchase 2.7 million shares. At
December 31, 2002, we had authorization under existing programs to purchase an
additional 1.2 million shares.
We spent $3.7 million to purchase 532,400 shares for our KSOP plan and released
243,806 shares to KSOP participants at a cost of $1.3 million. At December 31,
2002, we had an outstanding loan of $4.9 million to our KSOP. The loan is
interest-free and due December 31, 2004.
We received $3.6 million from the exercise of employee stock options. At
December 31, 2002, we had 2.8 million exercisable options at a weighted average
exercise price of $6.04 per share; we had total options outstanding of 6 million
shares at a weighted average exercise price of $6.37 per share.
We amended and restated our Senior Credit Facility, increasing the borrowing
base from $160 million to $300 million and extending the expiration date to
March 2005. We used the amended Senior Credit Facility to pay off the old credit
facility balance of $155.7 million, pay off the outstanding Prize credit
facility and fund other merger-related costs. In connection with the divestiture
of certain non-core oil and gas properties, the borrowing base was reduced to
$250 million. At December 31, 2002, we had $122 million available under this
credit facility. On January 27, 2003, we used $31.5 million of these funds to
redeem $30 million in principal of our 10% bonds at 105% of par. We paid $12
million in fees during 2002 relating to our financing activities.
Our facility includes covenants, the most restrictive of which requires
maintenance of a minimum funded debt to EBITDA ratio, interest coverage ratio,
and tangible net worth, as specified in the loan agreement. We were not in
compliance with the funded debt to EBITDA ratio required under the covenants at
March 31, 2002. The lender provided us with a waiver
37
as of this date, and we negotiated a less restrictive funded debt to EBITDA
ratio for the next four successive quarters until March 31, 2003. We were in
compliance with the covenants for the remainder of the year and expect to be
able to comply with the revised covenants in the future.
Net cash provided by financing activities was $102.7 million in 2001. We
borrowed $262.5 million under our senior bank credit lines and $4.0 million
through vendor provided financing for offshore construction. We repaid
borrowings under our senior bank credit lines by $158.6 million, made payments
of $180 thousand on production payment and other loans and repurchased $10.5
million principal value of our 10% Senior Notes on the open market for $10.8
million. We received $5.8 million in cash from the issuance of common stock.
Cash dividends paid were $169 thousand in 2001. Due to the repayment of
Bluebird's bank debt, its cash is no longer restricted, which provided $1.8
million in cash. We paid $956 thousand for fees related to financing activities,
made a loan to stockholder of $300 thousand, received repayment of stockholder
loans of $360 thousand, made a loan to the ESOP of $898 thousand, received a
loan repayment from the ESOP of $1.1 million, and purchased treasury stock for
$1.0 million. With respect to the ESOP, and as required under Statement of
Position 93-6 "Employers' Accounting for Employee Stock Ownership Plans,"
compensation expense is recorded for shares committed to be released to
employees based on the fair market value of those shares when they are committed
to be released. The difference between cost and the fair market value of the
committed to be released shares is recorded in additional paid-in-capital.
Unreleased shares held by the ESOP are excluded from the calculation of earnings
per share.
In the 2000 period, net cash used in financing activities was $31.0 million. We
borrowed a total of $101.1 million under our senior bank credit lines of which
$11.5 million was attributable to Bluebird. We repaid borrowings under our
senior bank credit lines by $144.8 million, of which $32.7 million was
attributable to Bluebird. We received $60.0 million in cash from the issuance of
common and preferred stock, net of offering costs. We paid $534 thousand of fees
related to financing activities. We spent $25.0 million to redeem our 1999
Series A preferred stock, while Bluebird also spent $10.5 million to acquire
Magnum Hunter preferred and common stock. Cash dividends paid were $10.2 million
in 2000. We loaned the ESOP $1.6 million to purchase our common stock. Bluebird
had a net decrease in cash of $325 thousand.
BLUEBIRD'S AND CANVASBACK'S CAPITAL RESOURCES. On March 1, 2002, we created two
wholly-owned subsidiaries, collectively referred to as Canvasback. On March 15,
2002, Bluebird transferred all of its assets to Canvasback. Like Bluebird,
Canvasback is neither a guarantor of our 10% Senior Notes due 2007 or our 9.6%
Senior Notes due 2012, nor can it be included in calculations determining debt
compliance. During 2002, Canvasback purchased $12 million of Magnum Hunter
Resources, Inc. stock. Canvasback also had borrowings of $7 million, $5.8
million of which were used to purchase the same amount in face value of Magnum
Hunter Resources, Inc. 10% Senior Notes.
On May 17, 2001, Bluebird sold all of its proved and unproved oil and gas
properties, except for its investment in Tel Offshore Trust, and all of its
pipelines and other fixed asset property to Magnum Hunter Production, Inc., for
$17.7 million in cash and $10 million of our 1996 Series A Convertible preferred
stock. Bluebird used the cash to repay and retire its $17.7 million of debt
under its senior bank credit line. The effective date of the sale was May 1,
2001. On June 25, 2001, Bluebird purchased $4.7 million face value of Magnum
Hunter Resources, Inc. 10% Senior Notes on the open market. Bluebird remains an
unrestricted subsidiary under the Company's senior bank credit agreement. At
December 31, 2001, Bluebird had no capital spending plans or commitments and no
remaining debt or interest payment requirements.
MAGNUM HUNTER'S LIQUIDITY AND CAPITAL RESOURCES. The following discussion of
Magnum Hunter's capital resources refers to the company and its affiliates other
than Bluebird and Canvasback, whose capital resources were discussed separately
above. Internally generated cash flow and the borrowing capacity under its
senior bank credit line are our major sources of liquidity. From time to time,
we may also sell oil and gas properties in order to increase liquidity. In
addition, we may use other sources of capital, including the issuance of
additional debt securities or equity securities, as sources to fund acquisitions
or other specific needs. In the past, we have accessed both public and private
capital markets to provide liquidity for specific activities and general
corporate purposes.
In December 2000, Magnum Hunter used $10.0 million in cash to purchase 100% of
its 1996 Series A Convertible preferred stock outstanding from Bluebird. This
preferred stock was held by another 100% owned affiliate for possible re-issue
at a later date. Also in December 2000, we spent $30.5 million (including a
$5.5 million redemption premium)
38
to redeem 50% of its outstanding 1999 Series A 8% Convertible preferred stock.
In January, 2001 the remaining 50% of this preferred stock was converted by the
holder to our common stock at the conversion price of $5.25 per share. As a
result of the redemption of its 1999 Series A 8% Convertible preferred stock, we
saved $4.0 million in annual dividend payments. In May 2001, we reissued the
$10.0 million of its 1996 Series A Convertible preferred stock to Bluebird in
connection with the acquisition of Bluebird's oil and gas properties. We will
make dividend payments of $875 thousand annually to Bluebird, however, such
payments are eliminated under consolidated financial reporting.
On May 17, 2001, we closed on a new $225 million Senior Bank Credit Facility, of
which $160 million was available under the borrowing base at December 31, 2001.
The credit agreement provides for both "LIBOR" and "Base Rate" (Prime) interest
rate options. This new credit facility consolidated and replaced both Magnum
Hunter's and Bluebird's previous credit facilities. At December 31, 2001,
borrowings under this line were $155.0 million, leaving availability of $5.0
million on that date versus a deficit in working capital of $27.4 million
(excluding Bluebird). As described below, we entered into several courses of
action to remedy this working capital shortfall. On a semiannual basis, the
borrowing base is redetermined by the banks based on their review of our oil and
gas reserves. If the outstanding senior bank debt exceeds the redetermined
borrowing base, we must repay the excess.
On December 5, 2001, we announced that a distribution of one warrant for every
five shares of common stock owned on January 10, 2002. These warrants were
distributed on March 21, 2002. Each new warrant will entitle the holder to
purchase one share of common stock at $15. The warrants will expire three years
from the date of distribution unless extended by the board of directors.
On January 15, 2002, we entered into a sale-leaseback transaction on three newly
constructed offshore production platforms and associated pipelines that were
recently placed into service. We received a total of $11.2 million in new
funding which was used for general corporate purposes including a voluntary
reduction under our corporate bank revolving credit facility. The production
platforms are being leased from a syndicate group of lenders over a term of
three years and at a cost of funds of approximately 5.30% per annum, based on
current interest rates. This transaction is accounted for as a capital lease.
On March 15, 2002, we amended and restated our Senior Bank Credit Facility (the
"Facility") in conjunction with the merger with Prize. The amended facility
provided for total borrowings of $500 million, up from $225 million, and raised
the borrowing base limit from $160 million to $300 million.
Our facility includes covenants, the most restrictive of which requires
maintenance a minimum funded debt to EBITDA ratio, interest coverage ratio, and
tangible net worth, as specified in the loan agreement. We were not in
compliance with the funded debt to EBITDA ratio required under the covenants at
March 31, 2002. The lender provided us with a waiver as of this date, and we
negotiated a less restrictive funded debt to EBITDA ratio for the next four
successive quarters until March 31, 2003. We were in compliance with the
covenants for the remainder of the year and expect to be able to comply with the
revised covenants in the future.
Additionally, we amended and extended the expiration date of the Facility to
March 2005. After March 15, 2002, the Facility was used to i) fund the cash
component of the Prize merger, ii) pay certain costs associated with the merger,
and iii) for general corporate purposes. In connection with certain oil and gas
property divestitures, the borrowing base was reduced to $250 million on
September 3, 2002.
On March 15, 2002, we also completed a private placement of $300 million of
Senior Notes (the private placement) due 2012 that are unsecured. The Senior
Notes bear an annual interest rate of 9.6% due semi-annually, commencing
September 15, 2002.
With the funds provided by the new facility and the private placement of Senior
Notes, we repaid indebtedness under our old credit facility of $155.7 million,
repaid debt under Prize's previous credit agreement of $246.8 million, funded
the cash component of the merger consideration of $70.9 million, and paid
approximately $12.2 million for fees and expenses related to the merger. In
connection with the merger with Prize, we issued 34,062,963 shares of our common
stock to Prize shareholders, increasing our total shares outstanding by 96%.
On January 27, 2003, Magnum Hunter used $31.5 million in cash to redeem $30
million in aggregate principal amount of our outstanding 10% Senior Notes due
2007 at a redemption price of 105% of par. After the partial redemption, we have
$110 million of these Notes outstanding. We funded the redemption by borrowing
from our Facility.
39
Our internally generated cash flow, results of operations, and financing for our
operations are dependent on oil and gas prices. To the extent that oil and gas
prices decline, our earnings and cash flows may be adversely affected.
CAPITAL EXPENDITURES. For the year ended December 31, 2002, our total capital
expenditures for property, plant and equipment, exclusive of the Prize merger,
were $141 million. The following summarizes our capital expenditures by cost
component (in millions):
Oil & Gas Properties
-------------------------------------------------------------------------------
Other
Unproved Proved Property Total
---------- ---------- ---------- ----------
Acquisition Costs .... $ 6.7 $ 7.1 $ 1.4 $ 15.2
Exploration Costs .... - 34.3 - 34.3
- 91.5 - 91.5
Development Costs .... ---------- ---------- ---------- ----------
Total ........... $ 6.7 $ 132.9 $ 1.4 $ 141.0
For the year 2003, we have budgeted approximately $100 million for exploration
and development activities. We anticipate that the 2003 capital expenditure
budget will be funded by cash flow from operations and credit facility
utilization. We are not contractually obligated to proceed with any of our
material budgeted capital expenditures. The amount and allocation of future
capital expenditures will depend on a number of factors that are not entirely
within our control or ability to forecast, including drilling results, oilfield
costs, and changes in oil and gas prices. As a result, actual capital
expenditures may vary significantly from current expectations.
In the normal course of business, we review opportunities for the possible
acquisition of oil and gas reserves and activities related thereto. When
potential acquisition opportunities are deemed consistent with our growth
strategy, bids or offers in amounts and with terms acceptable to the company may
be submitted. It is uncertain whether any such bids or offers which we may
submit from time to time will be acceptable to the sellers. In the event of a
future significant acquisition, we may require additional financing in
connection therewith. We do not budget for acquisition expenditures.
The following summarizes the oil and gas properties acquired in the Prize merger
(in millions):
OIL AND GAS PROPERTIES
----------------------------------------------------------------------------------
OTHER
UNPROVED PROVED PROPERTY TOTAL
------------------- ------------------- ------------------- -------------------
Acquisition Costs $ 140,312 $ 453,834 $ 22,826 $ 616,972
40
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS. We have the following
contractual obligations as of December 31, 2002:
Payments Due by Period (in thousands)
------------------------------------------------------------------------
Less than 1 After 5
Contractual Obligations Total Year 1 - 3 Years 4 - 5 Years Years
- ----------------------------------- ------------ ------------ ------------ ------------ ------------
Long-Term Debt .................... $ 561,466$ - $ 132,000 $ - $ 429,466
Capital Leases .................... 9,371 1,865 4,490 834 2,182
Operating Leases .................. 8,453 2,017 3,818 749 1,869
------------ ------------ ------------ ------------ ------------
Total Contractual Obligations .. $ 579,290 $ 3,882 $ 140,308 $ 1,583 $ 433,517
We have no off balance sheet arrangements, special purpose entities or financing
partnerships. We have provided trade guarantees on behalf of our 30% owned
affiliate, NGTS in the amount of $4.1 million. In the event that NGTS was unable
to fulfill its obligations with certain vendors, we would be obligated for cash
payments of $4.1 million to these vendors. We have not recorded this as a
liability on our books at December 31, 2002 because we do not expect to have to
perform under these guarantees. The last of these guarantees expires in May
2003, and we do not intend to issue any additional guarantees on behalf of NGTS.
We have no other guarantees on behalf of any entities and do not intend to issue
any at this time.
CRITICAL ACCOUNTING POLICIES AND OTHER
Our financial statements are prepared in accordance with accounting principles
generally accepted in the United States of America. The reported financial
results and disclosures were determined using significant accounting policies,
practices and estimates as described below. We believe the reported financial
results are reliable and that the ultimate actual results will not differ
significantly from those reported.
The accompanying consolidated financial statements include the accounts of the
company and its subsidiaries. We consolidate on a pro rata basis our
approximately 38% as of December 31, 2002 ownership of TEL Offshore Trust. We
account for our investment in NGTS under the equity method. All significant
intercompany transactions and balances have been eliminated in consolidation.
Certain items in prior periods have been reclassified to conform with the
current presentation.
Magnum Hunter is a holding company with no significant assets or operations
other than our investments in our subsidiaries. Our wholly-owned subsidiaries,
except for Canvasback Energy, Inc. ("Canvasback"), are direct guarantors of our
10% senior notes and 9.6% senior notes, and have fully and unconditionally
guaranteed the notes on a joint and several basis. The guarantors comprise all
of the direct and indirect subsidiaries of the company (other than Canvasback),
and we have presented separate condensed consolidating financial statements and
other disclosures concerning each guarantor and Canvasback (See Note 16 to the
Consolidated Financial Statements). There is no restriction on the ability of
consolidated or unconsolidated subsidiaries, except for Canvasback, to transfer
funds to Magnum Hunter in the form of cash dividends and loans or advances.
Oil and Gas Properties
We use the full cost method of accounting for our investment in oil and gas
properties. Under the full cost method of accounting, all costs of acquisition,
exploration and development of oil and gas proved reserves are capitalized into
a "full cost pool" on a country-by-country basis as incurred, and properties in
the pool are depleted and charged to operations using the unit-of-production
method based on the ratio of current production to total proved oil and gas
reserves, as determined by independent petroleum engineers. To the extent that
such capitalized costs (net of accumulated depreciation, depletion and
amortization) less deferred taxes exceed the PV-10 of estimated future net cash
41
flow from proved reserves of oil and gas, and the lower of unamortized cost or
fair value of unproved properties after income tax effects, such excess costs
are charged to operations. Once incurred, a write-down of oil and gas properties
is not reversible at a later date even if oil or gas prices subsequently
increase. Our capitalized costs did not exceed the PV-10 limitation using prices
in effect at December 31, 2002. Significant downward revisions of quantity
estimates, declines in oil and gas prices, higher operating costs or additional
capital costs which are not offset by incremental increases in oil and gas
reserves or other factors could possibly result in write-down for impairment of
oil and gas properties in the future.
Reserve engineering is a subjective process that is dependent on the quality of
available data and on engineering and geological interpretation and judgment.
Reserve estimates are subject to change over time as additional information
becomes available.
Revenue Recognition
Revenues are recognized when title to the product transfers to purchasers. We
follow the "sales method" of accounting for revenue for oil and natural gas
production, so that we recognize sales revenue on all production sold to
purchasers, regardless of whether the sales are proportionate to our ownership
in the property. A receivable or liability is recognized only to the extent that
we have an imbalance on a specific property greater than the expected remaining
proved reserves. Ultimate revenues from the sales of oil and gas production is
not known with certainty until up to three months after production and title
transfer occur. Current revenues are accrued based on our expectation of actual
deliveries and actual prices received.
Inflation and Changes in Prices
Our results of operations and cash flow have been, and will continue to be,
affected by the volatility in oil and gas prices. Should we experience a
significant increase in oil and gas prices that is sustained over a prolonged
period, we would expect that there would also be a corresponding increase in oil
and gas finding costs, lease acquisition costs, and operating expenses.
We market oil and gas for our own account, which exposes us to the attendant
commodities risk. A significant portion of our gas production is currently sold
to a 30% owned affiliate, NGTS, LLC, or end-users either (i) on the spot market
on a month-to-month basis at prevailing spot market prices or (ii) under
long-term contracts based on current spot market prices. We normally sell our
oil under month-to-month contracts to a variety of purchasers.
Derivative Instruments
Our product price and interest hedging activities are described in Note 12 to
the consolidated financial statements. Periodically we enter into derivative
instruments such as futures, swaps and options contracts to reduce the adverse
effects of fluctuations in natural gas and crude oil prices. Under our risk
management policy, at inception, commodity hedge positions may not exceed 75% of
natural gas and 90% of crude oil current forecasted (18 months) commodity
production. For non-current (greater than 18 months) commodity production, at
inception, commodity hedge positions for natural gas and crude oil may not
exceed 75%. We also utilize financial derivative instruments to hedge the risk
associated with interest on our outstanding debt. Generally, the cash settlement
of all derivative instruments is recognized as income or expense in the period
in which the hedged transaction is recognized.
We adopted Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133),
as extended by SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000),
beginning January 1, 2001. SFAS No. 133 establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. It requires the
recognition of derivatives in the balance sheet and the measurement of those
instruments at fair value. Derivative instruments that are not hedges must be
adjusted to the fair value through net income (loss). Under the provisions of
SFAS 133, changes in the fair value of derivative instruments that are fair
value hedges are offset against changes in the fair value of the hedged assets,
liabilities, or firm commitments, through net income (loss). Changes in the fair
value of derivative instruments that are cash-flow hedges are recognized in
other comprehensive income (loss) until such time as the hedged items are
recognized in net income (loss). Ineffective portions of a derivative
instrument's change in fair value are immediately recognized in net income
(loss).
42
Goodwill
As a result of our merger with Prize, we currently have $50.7 million of
goodwill recorded on our books. Under SFAS No. 142, we will not amortize any of
the goodwill acquired in the merger. We will evaluate our goodwill for
impairment on an annual basis or whenever indicators or impairment exist. We
have completed the first of these impairment tests and determined that no
impairment exists. The annual impairment test requires management to make
significant estimates and judgments.
Recently Issued Statements
SFAS No. 142 - We adopted SFAS No. 142, "Goodwill and Other Intangible Assets",
beginning January 1, 2002. SFAS No. 142 requires, among other things, the
discontinuance of goodwill amortization. Any goodwill resulting from
acquisitions completed after June 30, 2001 will not be amortized.
In addition, SFAS No. 142 requires that we use a new method of testing goodwill
that could reduce the fair value of a reporting unit below its carrying value.
We completed an impairment test at December 31, 2002 and determined that no
adjustments for impairment were necessary. Any goodwill impairment loss will be
recorded in operations. We currently have goodwill of $50.7 million as a result
of our merger with Prize Energy Corp. on March 15, 2002. The adoption of SFAS
142 did not have an impact on our consolidated financial statements during 2002.
SFAS No. 143 - SFAS No. 143, "Accounting for Asset Retirement Obligations", will
be effective for us beginning January 1, 2003. SFAS No. 143 requires the
recognition of a fair value liability for any retirement obligation associated
with long-lived assets. The offset to any liability recorded is added to the
recorded asset where the additional amount is depreciated over the same period
as the long-lived asset for which the retirement obligation is established.
We have evaluated the impact of SFAS 143 and expect to record an after tax
earnings effect between a $500 thousand loss and a $1.5 million gain as a
cumulative effect of a change in accounting principle. Additionally, we expect
to record an asset retirement obligation liability between $30 million and $38
million and to provide an increase to net properties and equipment between $30
million and $38 million. The application of SFAS 143 in 2003 and future years
will result in the recognition of an accretion expense related to the discounted
liability for the asset retirement obligation and should not have a material
impact on our DD&A rate. There will be no impact on our cash flow as a result of
adopting SFAS 143.
SFAS No. 144 - SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets", was effective for us beginning January 1, 2002. SFAS No. 144
establishes a single accounting model, based on the framework established in
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of", for long-lived assets to be disposed of by
sale and resolves significant implementation issues related to SFAS No. 121. The
adoption of SFAS No. 144 did not have an impact on our consolidated financial
statements during 2002.
SFAS No. 145 - SFAS No. 145 "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections" was effective for
us beginning January 1, 2003. The Statement rescinds, updates, clarifies and
simplifies various existing accounting pronouncements. SFAS No. 145 rescinds
SFAS No. 4 "Reporting Gains and Losses from Extinguishment of Debt", which
required all gains and losses from extinguishment of debt to be aggregated and,
if material, classified as an extraordinary item, net of related income tax
effect. As a result, SFAS No. 145
43
will require the reclassification of extraordinary items for debt extinguishment
costs which do not meet the criteria described in APB Opinion No. 30 "Reporting
the Results of Operations - Reporting the Effects of Disposal of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions", as
to interest expense. We adopted this statement beginning January 1, 2003.
SFAS 146 - In July 2002, the FASB issued SFAS 146 "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
SFAS 146 supercedes EITF Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
certain costs incurred in a Restructuring)." Statement 146 is to be applied
prospectively to exit or disposal activities initiated after December 31, 2002.
SFAS No. 148 - The FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure, an amendment of FASB Statement No. 123",
in December 2002. SFAS provides alternative methods of transition for a
voluntary change to the fair value method of accounting for stock-based employee
compensation and amends the disclosure requirements of SFAS No. 123. We adopted
the disclosure provisions in 2002. We have no plans at this time to change our
method to the fair value based method from the intrinsic value method.
FIN No. 45 - "Guarantor's Accounting and Disclosure Requirements for
Guarantees", was issued in November 2002. This interpretation addresses the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under guarantees. It also clarifies the
requirements related to the recognition of a liability by a guarantor at the
inception of a guarantee for the obligations the guarantor has undertaken in
issuing that guarantee. We adopted this statement in January 2003. We have
provided additional disclosures on our existing guarantees. The adoption had no
impact on our financials at January 1, 2003.
Off Balance Sheet Arrangements
We have provided trade guarantees on behalf of our 30% owned affiliate, NGTS,
LLC. In the amount of $4.1 million. In the event that NGTS, LLC is unable to
fulfill its obligations with certain vendors, we would be obligated for cash
payments of $4.1 million to these vendors. We have not recorded this as a
liability on our books at December 31, 2002 because we do not expect to have to
perform under these guarantees. The last of these guarantees expires in May
2003, and we do not intend to issue any additional guarantees on behalf of NGTS.
We have no other guarantees on behalf of any entities and do not intend to issue
any at this time.
We had equity and debt investments in a privately held entity which declared
bankruptcy on March 4, 2002, and for which we recorded an impairment charge
against earnings of $5.0 million at December 31, 2001. We are not responsible
for any debts of this entity. We had an investment in available-for-sale
securities of another entity of $2.8 million at December 31, 2001. Because of
the deteriorating financial condition of this entity, we recorded an other than
temporary impairment of $2.1 million as a charge against earnings at December
31, 2001, and we recorded an additional impairment for the remaining carrying
value of this asset at June 30, 2002. We are not responsible for any debts of
this entity.
Other
At March 15, 2003, Magnum Hunter had 72% of our natural gas production and 65%
of our crude oil production hedged through December 31, 2003, and 40% of our
natural gas production and 9% of our crude oil production hedged for the
calendar year 2004. Unless we enter into additional hedging transactions, the
remainder of our hydrocarbon volumes will be sold at market prices. Future
commodity price declines will negatively impact future income and cash flow to
the extent of any production sold at market prices. These declines could
ultimately affect the quantity of proved oil and gas reserves and cost center
ceiling values. These results, individually or collectively, could result in
bank debt default and/or debt acceleration, restrict our ability to attract
qualified personnel or cause further industry consolidation. There is no
requirement from any of our lenders to hedge our products.
Our domestic operations are concentrated in the southwestern and midcontinent
regions of the United States and shallow water region of the Gulf of Mexico
offshore Texas and Louisiana. We currently have no operations outside of the
United States of America. We currently have nineteen wells which individually
produce 1.5 MMcfe per day or greater, but these are not concentrated in any one
field. We have no individual fields in which disruptions could materially reduce
our financial results.
44
FORWARD-LOOKING STATEMENTS. This Form 10-K and the information incorporated by
reference contain statements that constitute "forward-looking statements" within
the meaning of Section 27A of the Securities Act and Section 21E of the
Securities Exchange Act. The words "expect", "project", "estimate", "believe",
"anticipate", "intend", "budget", "plan", "forecast", "predict" and other
similar expressions are intended to identify forward-looking statements. These
statements appear in a number of places and include statements regarding our
plans, beliefs, or current expectations, including the plans, beliefs, and
expectations of our officers and directors.
When considering any forward-looking statement, you should keep in mind the risk
factors that could cause our actual results to differ materially from those
contained in any forward-looking statement. Important factors that could cause
actual results to differ materially from those in the forward-looking statements
herein include the timing and extent of changes in commodity prices for oil and
gas, operating risks and other risk factors as described in our Annual Report on
Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the
assumptions that support our forward-looking statements are based upon
information that is currently available and is subject to change. We
specifically disclaim all responsibility to publicly update any information
contained in a forward-looking statement or any forward-looking statement in its
entirety and therefore disclaim any resulting liability for potentially related
damages. All forward-looking statements attributable to Magnum Hunter Resources,
Inc. are expressly qualified in their entirety by this cautionary statement.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
Our operations are exposed to market risks primarily as a result of changes in
commodity prices and interest rates. We do not use derivative financial
instruments for speculative or trading purposes.
Energy swap agreements. We produce, purchase, and sell crude oil, natural gas,
condensate, and natural gas liquids. As a result, our financial results can be
significantly impacted as these commodity prices fluctuate widely in response to
changing market forces. We have previously engaged in oil and gas hedging
activities and intend to continue to consider various hedging arrangements to
realize commodity prices which we consider favorable and to reduce volatility.
We engage in futures contracts with certain of our oil and gas production
through various contracts ("Swap Agreements"). The primary objective of these
activities is to protect against significant decreases in price during the term
of the hedge.
The Swap Agreements provide for separate contracts tied to the New York
Mercantile Exchange ("NYMEX") light sweet crude oil futures and Henry Hub
natural gas futures, and to the Inside FERC natural gas index price postings
("Index"). We have contracts which contain specific contracted prices ("Swaps")
that are settled monthly based on the differences between the contract prices
and the specified Index prices for each month applied to the related contract
volumes. To the extent the Index exceeds the contract price, we pay the spread,
and to the extent the contract price exceeds the Index price, we receive the
spread. In addition, we have combined contracts which have agreed upon price
floors and ceilings ("Costless Collars"). When the Index price exceeds the
contract ceiling, we pay the spread between the ceiling and the Index price
applied to the related contract volumes. When the contract floor exceeds the
Index, we receive the spread between the contract floor and the Index price
applied to the related contract volumes.
To the extent we receive the spread between the contract floor and the Index
price applied to related contract volumes, we have a credit risk in the event of
nonperformance of the counterparty to the agreement. We do not anticipate any
material impact to our results of operations as a result of nonperformance by
these counterparties.
Due to hedge contracts acquired in the Prize merger, the company is
contractually obligated to a counter-party to provide a margin deposit in the
form of cash or bank letter of credit should the aggregate fair value of hedge
contracts held with the counter-party exceed a predetermined value. Margins
posted at December 31, 2002 totaled $8.6 million. The company has not and does
not intend to enter into any new hedging contracts with institutions that
require margin deposits.
45
At December 31, 2002, we had open contracts with the following terms:
Commodity Type Volume/Day Duration Wtd. Avg. Price
- ------------------------------------------------------------------------------------------------------
Natural Gas Swap 60,000 MMBTU Jan 03 - Jun 03 $3.01
Natural Gas Swap 10,000 MMBTU Jul 03 - Dec 03 $3.65
Natural Gas Collar 40,000 MMBTU Jan 03 - Jun 03 $3.06 - $4.30
Natural Gas Collar 90,000 MMBTU Jul 03 - Dec 03 $2.89 - $3.87
Natural Gas Collar 25,000 MMBTU Jan 04 - Dec 04 $3.20 - $4.52
Crude Oil Swap 1,000 BBL Jan 03 - Dec 03 $21.25
Crude Oil Collar 6,000 BBL Jan 03 - Dec 03 $23.00 - $27.00
Based on future market prices at December 31, 2002, the fair value of open
contracts to the company was a liability of $45.0 million. If future market
prices were to increase 10% from those in effect at December 31, 2002, the fair
value of our open contracts would be a liability of $66.1 million. If future
market prices were to decline 10% from those at December 31, 2002, the fair
value of our open contracts would be a liability of $24.2 million.
At inception, commodity hedge positions may not exceed 75% of natural gas and
90% of crude oil forecasted current (18 months) commodity production. For
non-current (greater than 18 months) commodity production, at inception,
commodity hedge positions for natural gas and crude oil may not exceed 75% at
inception. Unhedged portions of our natural gas and crude oil production will be
subject to market price fluctuations.
Interest Rate Swaps
On August 9, 2001, we entered into two interest rate swaps in order to shift a
portion of our variable rate bank debt to fixed rate debt. The following table
reflects the terms of these swaps.
Type Notional Amount Termination Date Pay Rate Receive Rate
- ------------------------- ------------------------- ---------------------- ------------------ -------------------------
Pay Fixed/Receive $50,000,000 8/23/03 4.25% Fixed 3 month
Variable LIBOR rate
(currently 1.42%)
The rate we receive will be reset every three months to exactly match the rate
we will pay on $50.0 million of our outstanding LIBOR-based bank debt.
Based on future market prices at December 31, 2002, the fair value of our open
interest rate swap contracts was a liability of $1.1 million. If future market
rates were to increase 10% or decrease 10% from those in effect at December 31,
2002, the fair value of our open contracts would have an immaterial change and
remain as a liability of $1.1 million.
Fixed and Variable Debt.
We use fixed and variable debt to partially finance budgeted expenditures. These
agreements expose us to market risk related to changes in interest rates.
The following table presents the carrying and fair value of our debt along with
average interest rates. Fair values are calculated as the net present value of
the expected cash flows of the financial instruments, except for the fixed rate
senior notes, which are valued at their last traded value before December 31,
2002.
46
Expected Maturity Dates
(in thousands) 2003 2004-2006 2007 2012 Total Fair Value
- -------------------------------------------------------------------------------------------------------------------
Variable Rate Debt:
Bank Debt with Recourse (a)......... $ - $ 125,000 $ - $ - $ 125,000 $ 125,000
Bank Debt without Recourse (b)...... $ - $ 7,000 $ - $ - $ 7,000 $ 7,000
Capital Lease Obligations (c)....... $ 1,865 $ 5,323 $ 2,183 $ - 9,371 $ 9,371
Fixed Rate Debt:
10% Senior Notes (d)................ $ - - $ 129,466 $ - $ 129,466 $ 133,350
9.6% Senior Notes................... $ - $ - $ - $ 300,000 $ 300,000 $ 318,750
- ------------------
(a) The weighted average interest rate on the bank debt with recourse at
December 31, 2002 is 3.3454%.
(b) The interest rate on the bank debt with recourse at December 31, 2002 is
5.931%.
(c) The weighted average interest rate on capital lease obligations at
December 31, 2002 is 5%.
(d) We announced the early redemption of $30 million in principal of the 10%
Notes in December 2002. We redeemed these Notes in January 2003;
$2,348,000 of the Notes redeemed were held by a wholly-owned subsidiary.
47
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND UNAUDITED SUPPLEMENTAL
INFORMATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Independent Auditors' Report................................................................................F-1
Financial Statements:
Consolidated Balance Sheets at December 31, 2002 and 2001................................................F-2
Consolidated Statements of Operations for the
Years Ended December 31, 2002, 2001 and 2000............................................................F-3
Consolidated Statements of Stockholders' Equity and Comprehensive Income for the
Years Ended December 31, 2002, 2001 and 2000............................................................F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2002, 2001 and 2000..................................................................F-6
Notes to Consolidated Financial Statements..................................................................F-7
Supplemental Information (Unaudited).......................................................................F-39
48
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
Magnum Hunter Resources, Inc.
We have audited the accompanying consolidated balance sheets of Magnum Hunter
Resources, Inc. and Subsidiaries ("the Company"), as of December 31, 2002 and
2001, and the related consolidated statements of operations, stockholders'
equity and comprehensive income (loss) and cash flows for each of the three
years in the period ended December 31, 2002. These consolidated financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Magnum Hunter
Resources, Inc. and Subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002, in conformity with accounting principles
generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 25, 2003
F-1
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS OF DOLLARS)
DECEMBER 31, DECEMBER 31,
2002 2001
------------ ------------
ASSETS
Current Assets
Cash and cash equivalents ............................................ $ 3069 $ 2,755
Restricted cash ...................................................... 682 -
Accounts receivable
Trade, net of allowance of $4,573 and $3,264, respectively 53,864 14,251
Due from affiliate ................................................. - 235
Notes receivable ..................................................... 2,496 -
Notes receivable from affiliate ...................................... 100 300
Income tax refund receivable ......................................... 9,966 300
Derivative assets, current ........................................... - 5,045
Deferred income taxes, current ....................................... 15,500 -
Deposits ............................................................. 8,856 -
Other current assets ................................................. 3,563 2,220
------------ ------------
Total Current Assets ............................................. 98,096 25,106
------------ ------------
Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved ........................................................... 165,676 18,653
Proved ............................................................. 1,053,426 556,766
Gas processing plants and pipelines .................................. 33,951 12,642
Other property ....................................................... 6,636 3,640
------------ ------------
Total Property, Plant and Equipment .................................. 1,259,689 591,701
Accumulated depreciation, depletion, amortization and impairment ... (258,080) (171,864)
------------ ------------
Net Property, Plant and Equipment .................................... 1,001,609 419,837
------------ ------------
Other Assets
Other assets ......................................................... 12,642 4,420
Investment in unconsolidated affiliates .............................. 6,722 5,022
Goodwill ............................................................. 50,710 -
------------ ------------
Total Assets ......................................................... $ 1,169,779 $ 454,385
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities ............................... 60,635 39,489
Suspended revenue payable ............................................ 9,118 2,154
Due to affiliates .................................................... 2,848 -
Derivative liabilities, current ...................................... 42,777 996
Accrued interest ..................................................... 10,327 1,957
Current income taxes payable ......................................... 1,549 -
Current maturities of long-term debt, with recourse .................. 1,865 73
Notes payable ........................................................ - 4,044
------------ ------------
Total Current Liabilities .......................................... 129,119 48,713
------------ ------------
Long-Term Liabilities
Long-term debt, with recourse, less current maturities ............... 561,972 284,466
Long-term debt, non recourse ......................................... 7,000 -
Production payment liability ......................................... 114 203
Derivative liabilities, noncurrent ................................... 3,316 1,531
Deferred income taxes payable ........................................ 118,062 1,498
Commitments and Contingencies (Note 10)
Stockholders' Equity
Preferred stock - $.001 par value; 10,000,000 shares
authorized, 216,000 designated as Series A; 80,000 issued
and outstanding, liquidation amount $0 .............................. - -
1,000,000 designated as 1996 Series A Convertible; 1,000,000
purchased and held for remarketing by subsidiary, liquidation
amount $10,000,000 .................................................. 1 1
50,000 designated as 1999 Series A 8% Convertible; none and
25,000 issued and outstanding, respectively, liquidation amount
$0 and $25,000,000, respectively .................................... - -
Common Stock - $.002 par value; 100,000,000 shares authorized,
71,707,897 and 36,588,097 shares issued, respectively ............... 143 73
Additional paid-in capital ........................................... 423,364 157,836
Accumulated other comprehensive income (loss) ........................ (26,902) 1,632
Accumulated deficit .................................................. (21,114) (36,636)
Receivable from stockholder .......................................... - (442)
Unearned common stock in ESOP, at cost (757,246 and
468,652 shares, respectively) ....................................... (4,888) (2,576)
------------ ------------
370,604 119,888
Treasury stock, at cost (3,168,013 and 441,813 shares
of common stock, respectively) ...................................... (20,408) (1,914)
------------ ------------
Total Stockholders' Equity ............................................. 350,196 117,974
------------ ------------
Total Liabilities and Stockholders' Equity ........................... $ 1,169,779 $ 454,385
============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE AND PER SHARE AMOUNTS)
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
------------ ------------ ------------
OPERATING REVENUES:
Oil and gas sales ..........................................$ 240,964 $ 133,083 $ 106,052
Gas gathering, marketing and processing .................... 20,809 17,895 20,010
Oil field services ......................................... 4,096 1,828 1,448
------------ ------------ ------------
Total Operating Revenues ............................... 265,869 152,806 127,510
------------ ------------ ------------
OPERATING COSTS AND EXPENSES:
Oil and gas production lifting costs ....................... 51,559 20,388 16,401
Production taxes and other costs ........................... 28,167 12,994 12,558
Gas gathering, marketing and processing .................... 15,100 16,101 15,685
Oil field services ......................................... 2,474 1,277 903
Depreciation, depletion and amortization ................... 86,468 43,999 25,556
Gain on sale of assets ..................................... (61) (58) (28)
Loss on Enron related assets ............................... - 3,156 -
General and administrative ................................. 13,293 6,898 6,106
------------ ------------ ------------
Total Operating Costs and Expenses ..................... 197,000 104,755 77,181
------------ ------------ ------------
Operating Profit ................................................ 68,869 48,051 50,329
Equity in earnings of affiliate ............................ 792 1,085 1,307
Other income ............................................... 452 283 477
Provision for impairment of investments .................... (621) (7,123) -
Non-cash hedging adjustments ............................... (6,626) 52 -
Interest expense ........................................... (47,935) (19,920) (22,298)
------------ ------------ ------------
Income before income tax ........................................ 14,931 22,428 29,815
Provision for income tax benefit (expense)
Current ................................................. - (178) (234)
Deferred ................................................ 1,212 (8,430) (7,321)
------------ ------------ ------------
Total provision for income tax benefit (expense) ....... 1,212 (8,608) (7,555)
------------ ------------ ------------
Income Before Extraordinary Loss ................................ 16,143 13,820 22,260
Extraordinary loss from early extinguishment of
debt, net of income tax benefit of
$379 and $186, respectively ................................ (621) (304) -
------------ ------------ ------------
Net Income ...................................................... 15,522 13,516 22,260
Dividends Applicable to Preferred Stock .................... - - (9,708)
------------ ------------ ------------
Income Applicable to Common Shares ..............................$ 15,522 $ 13,516 $ 12,552
============ ============ ============
INCOME PER COMMON SHARE - BASIC
Income Before Extraordinary Loss ...........................$ 0.26 $ 0.40 $ 0.60
Extraordinary Loss ......................................... (0.01) (0.01) -
------------ ------------ ------------
Income per Common Share - Basic .................................$ 0.25 $ 0.39 $ 0.60
============ ============ ============
INCOME PER COMMON SHARE - DILUTED
Income Before Extraordinary Loss ...........................$ 0.26 $ 0.37 $ 0.51
Extraordinary Loss ......................................... (0.01) (0.01) -
------------ ------------ ------------
Income per Common Share - Diluted ...............................$ 0.25 $ 0.36 $ 0.51
============ ============ ============
COMMON SHARES USED IN PER SHARE CALCULATION
Basic ...................................................... 61,493,428 34,819,614 20,856,854
============ ============ ============
Diluted .................................................... 62,513,548 37,108,976 32,834,270
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
FOR THE PERIODS ENDED DECEMBER 31, 2000 AND 2001 (THOUSANDS)
Additional
Preferred Common Treasury Paid in Accumulated
Stock Stock Stock Capital Deficit
---------- ---------- ---------- ---------- -----------
Balance at January 1, 2000 ................................. $ 1 $ 43 $ (3,631) $ 121,845 $ (62,560)
Purchase of 1996 Series A preferred by subsidiary .......... (10,035)
Redemption of 25 shares of 1999 Series A 8%
convertible preferred stock ............................... (25,000)
Purchase of 129 shares of treasury stock ................... (500)
Issuance of 529 shares of common stock and 127
shares of treasury stock pursuant to employee
stock option plan ......................................... 1 77 2,335
Issuance of 8,438 shares of common stock and 702
shares of treasury stock pursuant to the exercise
of warrants ............................................... 17 1,588 55,952
Issuance of 357 shares of treasury stock for property ...... 1,080 2,401
Costs associated with the release of shares from ESOP ...... 672
Deferred tax benefit on exercise of employee stock options.. 410
Dividends on preferred stock ............................... (9,852)
Net income ................................................. 22,260
Unrealized gain on investments .............................
Repayment of shareholder loan ..............................
143 Unearned shares in ESOP ................................
---------- ---------- ---------- ---------- -----------
Balance at December 31, 2000 ............................... $ 1 $ 61 $ (1,386) $ 148,580 $ (50,152)
Conversion of 25 shares of Series A 8% convertible
preferred stock into 4,762 shares of common stock ......... 10 (10)
Issuance of 1,068 shares of common stock and 56
shares of treasury stock pursuant to employee
stock option plan ......................................... 2 171 4,692
Deferred tax benefit on exercise of employee stock options.. 2,350
Contribution of 52 shares to 401(k) plan and other ......... 151
Issuance of 73 shares of treasury stock .................... 316 418
Purchase of 116 shares of treasury stock ................... (1,015)
Employee salary deferrals to ESOP representing 317 shares ..
Loan of 105 shares to ESOP ................................. 1,655
Net income ................................................. 13,516
Cumulative effect on prior years of a change in
accounting principle ......................................
Gain on hedges .............................................
Unrealized loss on investments .............................
Reclassification adjustment related to derivative assets ...
---------- ---------- ---------- ---------- -----------
Balance at December 31, 2001 ............................... $ 1 $ 73 $ (1,914) $ 157,836 $ (36,636)
========== ========== ========== ========== ===========
Accumulated
Receivable Unearned Other
from Shares in Comprehensive
Stockholder ESOP Income (Loss)
----------- --------- -------------
Balance at January 1, 2000 ................................. $ (795) $ (1,638) $ (1,713)
Purchase of 1996 Series A preferred by subsidiary ..........
Redemption of 25 shares of 1999 Series A 8%
convertible preferred stock ...............................
Purchase of 129 shares of treasury stock ...................
Issuance of 529 shares of common stock and 127
shares of treasury stock pursuant to employee
stock option plan .........................................
Issuance of 8,438 shares of common stock and 702
shares of treasury stock pursuant to the exercise
of warrants ...............................................
Issuance of 357 shares of treasury stock for property ......
Costs associated with the release of shares from ESOP ......
Deferred tax benefit on exercise of employee stock options .
Dividends on preferred stock ...............................
Net income .................................................
Unrealized gain on investments ............................. 1,247
Repayment of shareholder loan .............................. 353
143 Unearned shares in ESOP ................................ (1,142)
----------- --------- -------------
Balance at December 31, 2000 ............................... $ (442) $ 2,780) $ (466)
Conversion of 25 shares of Series A 8% convertible
preferred stock into 4,762 shares of common stock .........
Issuance of 1,068 shares of common stock and 56
shares of treasury stock pursuant to employee
stock option plan .........................................
Deferred tax benefit on exercise of employee stock options .
Contribution of 52 shares to 401(k) plan and other .........
Issuance of 73 shares of treasury stock ....................
Purchase of 116 shares of treasury stock ...................
Employee salary deferrals to ESOP representing 317 shares .. 1,102
Loan of 105 shares to ESOP ................................. (898)
Net income .................................................
Cumulative effect on prior years of a change in
accounting principle ...................................... (1,757)
Gain on hedges ............................................. 3,536
Unrealized loss on investments ............................. 466
Reclassification adjustment related to derivative assets ... (147)
----------- --------- -------------
Balance at December 31, 2001 ............................... $ (442) $ (2,576) $ 1,632
=========== ========= =============
Total Total
Stockholders' Comprehensive
Equity Income (Loss)
------------- -------------
Balance at January 1, 2000 ................................. $ 51,552 $
Purchase of 1996 Series A preferred by subsidiary .......... (10,035)
Redemption of 25 shares of 1999 Series A 8%
convertible preferred stock ............................... (25,000)
Purchase of 129 shares of treasury stock ................... (500)
Issuance of 529 shares of common stock and 127
shares of treasury stock pursuant to employee
stock option plan ......................................... 2,413
Issuance of 8,438 shares of common stock and 702
shares of treasury stock pursuant to the exercise
of warrants ............................................... 57,557
Issuance of 357 shares of treasury stock for property ...... 3,481
Costs associated with the release of shares from ESOP ...... 672
Deferred tax benefit on exercise of employee stock options . 410
Dividends on preferred stock ............................... (9,852)
Net income ................................................. 22,260 22,260
Unrealized gain on investments ............................. 1,247 1,247
Repayment of shareholder loan .............................. 353
143 Unearned shares in ESOP ................................ (1,142)
------------- -------------
Balance at December 31, 2000 ............................... $ 93,416 $ 23,507
=============
Conversion of 25 shares of Series A 8% convertible
preferred stock into 4,762 shares of common stock ......... - $
Issuance of 1,068 shares of common stock and 56
shares of treasury stock pursuant to employee
stock option plan ......................................... 4,865
Deferred tax benefit on exercise of employee stock options . 2,350
Contribution of 52 shares to 401(k) plan and other ......... 151
Issuance of 73 shares of treasury stock .................... 734
Purchase of 116 shares of treasury stock ................... (1,015)
Employee salary deferrals to ESOP representing 317 shares .. 1,102
Loan of 105 shares to ESOP ................................. 757
Net income ................................................. 13,516 13,516
Cumulative effect on prior years of a change in
accounting principle ...................................... (1,757) (1,757)
Gain on hedges ............................................. 3,536 3,536
Unrealized loss on investments ............................. 466 466
Reclassification adjustment related to derivative assets ... (147) (147)
------------- -------------
Balance at December 31, 2001 ............................... $ 117,974 $ 15,614
============= =============
F-4
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
FOR THE PERIOD ENDED DECEMBER 31, 2002
(thousands)
Additional
Preferred Common Treasury Paid in Accumulated
Stock Stock Stock Capital Deficit
--------- -------- ---------- ----------- -----------
Balance at December 31, 2001 ................................. $ 1 $ 73 $ (1,914) $ 157,836 $ (36,636)
Issuance of 34,063 shares of common stock and
warrants pursuant to Prize Energy Corp merger,
less fees ................................................... 68 260,454
Issuance of 985 shares of common stock pursuant
to employee stock option plan ............................... 2 3,627
Deferred tax benefit on exercise of
employee stock options ...................................... 859
Employer contribution of 158 shares to KSOP .................. 71
Exercise of warrants ......................................... 5
Purchase of warrants ......................................... (128)
Repayment of shareholder loan ................................
Issuance of 72 shares to KSOP for 2001 employer contribution . 601
Purchase of 2,726 shares of treasury stock ................... (18,494)
Employee salary deferrals to KSOP representing 86 shares ..... 39
Loan of 532 shares to KSOP ...................................
Net income ................................................... 15,522
Reclassification adjustment related to derivative contracts ..
Change in fair value of outstanding hedge positions ..........
Purchased hedge positions ....................................
Amortization of purchased hedge positions ....................
Unrealized loss on investments ...............................
Reclassification adjustment for loss on investments ..........
--------- -------- ---------- ----------- -----------
Balance at December 31, 2002 ................................. $ 1 $ 143 $ (20,408) $ 423,364 $ (21,114)
========= ======== ========== =========== ===========
Accumulated
Receivable Unearned Other
from Shares in Comprehensive
Stockholder ESOP Income (Loss)
----------- --------- -------------
Balance at December 31, 2001 ................................. $ (442) $ (2,576) $ 1,632
Issuance of 34,063 shares of common stock and
warrants pursuant to Prize Energy Corp merger,
less fees ...................................................
Issuance of 985 shares of common stock pursuant
to employee stock option plan ...............................
Deferred tax benefit on exercise of
employee stock options ......................................
Employer contribution of 158 shares to KSOP .................. 867
Exercise of warrants .........................................
Purchase of warrants .........................................
Repayment of shareholder loan ................................ 442
Issuance of 72 shares to KSOP for 2001 employer contribution..
Purchase of 2,726 shares of treasury stock ...................
Employee salary deferrals to KSOP representing 86 shares ..... 473
Loan of 532 shares to KSOP ................................... (3,652)
Net income ...................................................
Reclassification adjustment related to derivative contracts .. 2,762
Change in fair value of outstanding hedge positions .......... (32,593)
Purchased hedge positions .................................... (2,474)
Amortization of purchased hedge positions .................... 3,771
Unrealized loss on investments ............................... (323)
Reclassification adjustment for loss on investments .......... 323
----------- --------- -------------
Balance at December 31, 2002 ................................. $ - $ (4,888) $ (26,902)
=========== ========= =============
Total Total
Stockholders' Comprehensive
Equity Income (Loss)
------------- -------------
Balance at December 31, 2001 ................................. $ 117,974 $
Issuance of 34,063 shares of common stock and
warrants pursuant to Prize Energy Corp merger,
less fees ................................................... 260,522
Issuance of 985 shares of common stock pursuant
to employee stock option plan ............................... 3,629
Deferred tax benefit on exercise of
employee stock options ...................................... 859
Employer contribution of 158 shares to KSOP .................. 938
Exercise of warrants ......................................... 5
Purchase of warrants ......................................... (128)
Repayment of shareholder loan ................................ 442
Issuance of 72 shares to KSOP for 2001 employer contribution.. 601
Purchase of 2,726 shares of treasury stock ................... (18,494)
Employee salary deferrals to KSOP representing 86 shares ..... 512
Loan of 532 shares to KSOP ................................... (3,652)
Net income ................................................... 15,522 15,522
Reclassification adjustment related to derivative contracts .. 2,762 2,762
Change in fair value of outstanding hedge positions .......... (32,593) (32,593)
Purchased hedge positions .................................... (2,474) (2,474)
Amortization of purchased hedge positions .................... 3,771 3,771
Unrealized loss on investments ............................... (323) (323)
Reclassification adjustment for loss on investments .......... 323 323
------------- -------------
Balance at December 31, 2002 ................................. $ 350,196 $ (13,012)
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
FOR THE YEARS ENDED DECEMBER 31,
------------ ----------- -----------
2002 2001 2000
------------ ----------- -----------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income.................................................................... $ 15,522 $ 13,516 $ 22,260
Adjustments to reconcile net income to cash provided by
operating activities
Extraordinary loss........................................................ 621 304 -
Depreciation, depletion and amortization.................................. 86,468 43,999 25,556
Impairment of investments........................................ 621 7,123 -
Amortization of financing fees............................................ 2,037 1,192 1,318
Imputed interest on debt due to merger........................... 108 - -
Increase in allowance for doubtful accounts............................... 206 3,214 464
Deferred income taxes (benefits).......................................... (1,212) 8,430 7,321
Equity in income of unconsolidated affiliate.............................. (792) (1,085) (1,307)
Cost of shares released from ESOP suspense................................ 867 - 448
Excess of fair value over cost of shares released
from ESOP suspense...... 110 1,655 672
Gain on sale of assets.................................................... (61) (58) (28)
Other non-cash hedging adjustments........................................ 6,626 52 -
Changes in certain assets and liabilities, net of the
effect of acquisitions
Accounts and notes receivable........................................ (17,429) 12,849 (20,378)
Derivative assets........................................ 3,600 - -
Other current assets................................................. (9,314) (187) (737)
Accounts payable and accrued liabilities............................. (7,449) 13,604 13,827
Refund (payment) of income taxes..................................... 2,874 (534) 234
Minority interest liability.......................................... - - (184)
------------ ----------- -----------
Net Cash Provided By Operating Activities..................................... 83,403 104,074 49,466
------------ ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets.................................................. 95,988 1,124 43,770
Additions to property and equipment........................................... (141,046) (204,370) (60,830)
Cash paid in Prize merger net of cash acquired........................... (41,095) - -
Decrease in deposits and other assets......................................... 238 50 -
Loan made for promissory note receivable...................................... (2,596) - (1,370)
Payments received on promissory note receivable .............................. - 70 1,012
Distribution from unconsolidated affiliate.................................... 256 1,590 -
Investment in unconsolidated affiliate........................................ (1,165) (2,453) (2,590)
------------ ----------- -----------
Net Cash Used In Investing Activities......................................... (89,420) (203,989) (20,008)
------------ ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of long-term debt, note
payable, and production payment.............................................. 627,850 266,524 101,056
Fees paid related to financing activities..................................... (11,961) (956) (534)
Payments of principal on long-term debt and production payment................ (591,451) (169,557) (144,824)
Receipts from short-term notes receivable .................................... - 360 -
Loan repaid by (made to) stockholder.......................................... 742 (300) 353
Loan to ESOP.................................................................. (3,652) (898) (1,590)
Loan repaid from ESOP......................................................... 473 1,102 -
Proceeds from issuance of common and preferred stock, net of offering costs... 3,634 5,750 59,970
Purchase of 1996 Series A preferred stock by subsidiary....................... - - (10,035)
Redemption of 1999 Series A preferred stock................................... - - (25,000)
Purchase of warrants.......................................................... (128) - -
Purchase of treasury stock ................................................... (18,494) (1,015) (500)
Decrease (increase) in restricted cash for payment of notes payable .......... (682) 1,820 325
Dividends paid................................................................ - (169) (10,235)
------------ ----------- -----------
- -
Net Cash Provided By (Used In) Financing Activities........................... 6,331 102,661 (31,014)
------------ ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................... 314 2,746 (1,556)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR..................................... 2,755 9 1,565
------------ ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR........................................... $ 3,069 $ 2,755 $ 9
============ =========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND NATURE OF OPERATIONS
Magnum Hunter Resources, Inc. ("Magnum Hunter"), is incorporated under the laws
of the state of Nevada. The company and our subsidiaries are engaged in the
acquisition, operation and development of oil and gas properties, the gathering,
processing, transmission, and marketing of natural gas and natural gas liquids
and providing management and advisory consulting services on oil and gas
properties for third parties. In conjunction with the above activities, we own
and operate oil and gas properties in twelve states, predominantly in the
Southwest region of the United States. In addition, we own and operate three
gathering systems located in Texas and Oklahoma and own an interest in four
natural gas processing plants located in Texas, Oklahoma and Arkansas.
CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
Magnum Hunter and our existing wholly-owned subsidiaries, Gruy Petroleum
Management Co., Magnum Hunter Production, Inc., ConMag Energy Corporation,
Trapmar Properties, Inc., Hunter Gas Gathering, Inc. ("Hunter"), Canvasback
Energy, Inc. ("Canvasback"), Pintail Energy, Inc., Redhead Energy, Inc.
("Redhead"), Prize Operating Co., PEC (Delaware), Inc., Oklahoma Gas Processing,
Inc., and Prize Energy Resources, LP. We consolidate on a pro rata basis our
approximately 38% ownership of TEL Offshore Trust. We account for our
investments in Metrix Networks, Inc. and NGTS, LLC under the equity method. All
significant intercompany accounts and transactions have been eliminated in
consolidation. Certain reclassifications have been made to the consolidated
financial statements of the prior year to conform with the current presentation.
Magnum Hunter is a holding company with no significant assets or operations
other than our investments in our subsidiaries. Our wholly-owned subsidiaries,
except for Canvasback, are direct Guarantors of our 10% Senior Notes and 9.6%
Senior Notes ("Notes"), and have fully and unconditionally guaranteed the Notes
on a joint and several basis. The Guarantors comprise all of the direct and
indirect subsidiaries (other than Canvasback), and we have presented separate
condensed consolidating financial statements and other disclosures concerning
each Guarantor and Canvasback (See Note 16). Except for Canvasback, there is no
restriction on the ability of consolidated or unconsolidated subsidiaries to
transfer funds to Magnum Hunter in the form of cash dividends, loans, or
advances.
Bluebird Energy, Inc. ("Bluebird") was formed in December 1998. As part of the
capitalization of Bluebird, we contributed to Bluebird 1,840,271 units of TEL
Offshore Trust. Bluebird, was an "unrestricted subsidiary" as defined under
certain credit agreements, and was neither a guarantor of our 10% Senior Notes
due 2007, and our 9.6% Senior Notes due 2012, nor was it included in determining
compliance with certain financial covenants under our credit agreements.
On March 1, 2002, we created two unrestricted, wholly-owned subsidiaries,
Canvasback and Redhead. These two subsidiaries will be referred to as Canvasback
since Redhead is a wholly-owned subsidiary of Canvasback. On March 15, 2002,
Bluebird transferred all of its assets to Canvasback, which effectively
capitalized Canvasback. Upon completion of this transfer, Bluebird was merged
into Magnum Hunter Production, Inc. Canvasback is neither a guarantor of our 10%
Senior Notes due 2007, or our 9.6% Senior Notes due 2012; nor can it be included
in determining compliance with our debt covenants.
CASH AND CASH EQUIVALENTS
We consider all highly liquid debt instruments purchased with an original
maturity of three months or less to be cash equivalents. We have cash deposits
in excess of federally insured limits.
INVESTMENTS
We follow accounting procedures according to Statement of Financial Accounting
Standards ("SFAS") No. 115, "Accounting for Certain Investments in Debt and
Equity Securities." Under this standard, all of our equity securities
F-7
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
that have readily determinable fair values are classified as current or
non-current assets, available-for-sale and are measured at fair value.
Unrealized gains and losses for these investments are reported as comprehensive
income and included as a separate component of stockholders' equity. Realized
gains and losses are calculated based on the specific identification method.
At December 31, 2000, our available-for-sale securities were classified as
non-current assets and included in deposits and other assets. The securities had
a cost basis of $2,762,000, gross unrealized losses reported in accumulated
other comprehensive income of $507,000 ($466,000 net of income tax benefit) and
a fair market value of $2,255,000 based on the quoted market price. At December
31, 2001, we determined that the securities had suffered an other than temporary
impairment as a result of the deteriorating financial condition of the entity
and a steadily declining market value of the securities. As a result, at
December 31, 2001, we reported a provision for impairment of investments of
$2,142,000 as a charge against earnings and a reclassification in accumulated
other comprehensive income of $507,000 ($466,000 net of income tax). Due to
continued deterioration of the entity's financial condition and market value of
their stock, we recorded an impairment on this investment for its full carrying
value of $621,000 during 2002. At December 31, 2002, we carried no value for our
available-for-sale securities.
During 2000, we acquired a minority ownership interest in a privately held
entity that provides remote data collection and web-based monitoring services
for the company and other entities operating in the energy industry. The total
we invested in 2000 was $2.5 million, and the investment was carried at cost on
the balance sheet at December 31, 2000. During 2001, we made an additional
equity investment of $2 million as well as secured loans totaling $453,000,
including accrued interest. At December 31, 2001, our total equity investment of
$4,528,000 represented less than 10% of the entity's common equity. As a result
of the entity's inability to obtain additional anticipated equity financing from
third parties at the end of 2001, the entity subsequently declared bankruptcy.
We reported a provision for impairment of investments of $4,981,000 as a charge
against earnings at December 31, 2001.
ESOP
As required under Statement of Position 93-6 "Employers' Accounting for Employee
Stock Ownership Plans," compensation expense is recorded for shares committed to
be released to employees based on the fair market value of those shares when
they are committed to be released. The difference between cost and the fair
market value of the committed to be released shares is recorded in additional
paid-in-capital. Unreleased shares held by the ESOP are excluded from the
calculation of earnings per share.
SUSPENDED REVENUES
Suspended revenue interests represent oil and gas sales payable to third parties
largely on properties operated by the company. We distribute such amounts to
third parties upon receipt of signed division orders or resolution of other
legal matters.
OIL AND GAS PRODUCING OPERATIONS
Magnum Hunter follows the full-cost method of accounting for oil and gas
properties. Accordingly, all costs associated with acquisition, exploration and
development of oil and gas reserves, including directly related overhead costs,
are capitalized. Internal costs that directly relate to acquisition, exploration
and development activities that were capitalized totaled $600,000 for each of
the years ended December 31, 2002, 2001 and 2000, respectively. The balance of
capitalized costs included in oil and gas properties for the years ended
December 31, 2002 and 2001 were $3,879,000 and $3,279,000, respectively.
Management believes that the basis we use to determine the amount of internal
costs capitalized is appropriate.
All capitalized costs of oil and gas properties, including the estimated future
costs to develop proved reserves and estimated dismantlement and abandonment
costs, net of salvage values, are amortized on the unit-of-production method
using estimates of proved reserves. Costs directly associated with the
acquisition and evaluation of unproved properties are excluded from the
amortization base until the related properties are evaluated. Such unproved
properties are assessed
F-8
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
for impairment at least annually and any provision for impairment is transferred
to the full-cost amortization base. Sales of oil and gas properties, including
consideration received from sales or transfers of properties in connection with
partnerships, joint venture operations or drilling arrangements, are credited to
the full-cost pool unless the sale would have a significant effect on the
amortization rate. Abandonment of properties is accounted for as an adjustment
to capitalized costs with no loss recognized.
A summary of the unproved properties excluded from oil and gas properties being
amortized at December 31, 2002 and 2001, respectively, and the year in which
they were incurred follows:
December 31, 2002
(in thousands)
---------------------------------------------------
Prior 2000 2001 2002 Total
------- ------- -------- --------- ---------
Property Acquisition Costs..................$ 1,032 $ 320 $ 11,131 $ 150,583 $ 163,066
Exploration Costs........................... - - 2,610 - 2,610
------- ------- -------- --------- ---------
Total..................................$ 1,032 $ 320 $ 13,741 $ 150,583 $ 165,676
======= ======= ======== ========= =========
December 31, 2001
(in thousands)
-------------------------------------------------
Prior 1999 2000 2001 Total
------- ------- ------ --------- --------
Property Acquisition Costs..................$ 513 $ 1,464 $ 360 $ 12,226 $ 14,563
Exploration Costs........................... - - - 4,090 4,090
------- ------- ------ --------- --------
Total..................................$ 513 $ 1,464 $ 360 $ 16,316 $ 18,653
======= ======= ====== ======== ========
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves are established or impairment
determined. Pending determination of proved reserves attributable to the above
costs, we cannot assess the future impact on the amortization rate. The Prize
merger accounted for $140,312 thousand of the unproved property acquisition
costs in 2002.
The capitalized costs are subject to a "ceiling test," which generally limits
such costs less accumulated amortization and related deferred income taxes to
the aggregate of the estimated present value of future net revenues from proved
reserves discounted at ten percent (PV-10) based on current economic and
operating conditions less income tax effects related to the differences between
the book and tax basis of the oil and gas properties. The ceiling test is
performed on a quarterly basis. At December 31, 2001, the capitalized costs of
our oil and gas properties exceeded the PV-10 limitation using prices in effect
at December 31, 2001 by $75,984,000. However, no write-down for impairment of
oil and gas properties was required as a result of the increase in oil and gas
prices subsequent to December 31, 2001. We experienced no impairment in 2000 or
2002.
All costs relating to production activities are charged to expense as incurred.
Amortization expense per thousand cubic feet equivalent was $1.17, $1.28 and
$0.89 for the years ended December 31, 2002, 2001 and 2000, respectively.
F-9
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
DERIVATIVE INSTRUMENTS
Our product price and interest hedging activities are described in Note 12 to
the consolidated financial statements. Periodically we enter into derivative
instruments such as futures, swaps and options contracts to reduce the adverse
effects of fluctuations in natural gas and crude oil prices. Under our risk
management policy, at inception commodity hedge positions may not exceed 75% of
natural gas and 90% of crude oil current forecasted (18 months) commodity
production. For forecasted non-current (greater than 18 months) commodity
production, at inception, commodity hedge positions for both natural gas and
crude oil may not exceed 75%. We also utilize financial derivative instruments
to hedge the risk associated with interest on our outstanding debt. Generally,
the cash settlement of all derivative instruments is recognized as income or
expense in the period in which the hedged transaction is recognized.
We adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" (SFAS No. 133), as extended by SFAS No. 137 (June 1999) and amended
by SFAS No. 138 (June 2000), beginning January 1, 2001. SFAS No. 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
It requires the recognition of derivatives in the balance sheet and the
measurement of those instruments at fair value. Derivative instruments that are
not hedges must be adjusted to the fair value through net income (loss). Under
the provisions of SFAS No. 133, changes in the fair value of derivative
instruments that are fair value hedges are offset against changes in the fair
value of the hedged assets, liabilities, or firm commitments, through net income
(loss). Changes in the fair value of derivative instruments that are cash-flow
hedges are recognized in other comprehensive income (loss) until such time as
the hedged items are recognized in net income (loss). Ineffective portions of a
derivative instrument's change in fair value are immediately recognized in net
income (loss).
PIPELINES AND PROCESSING PLANT
Pipelines and processing plants are carried at cost. Depreciation is provided
using the straight-line method over an estimated useful life of 15 years. Gain
or loss on retirement or sale or other disposition of assets is included in
results of operations in the period of disposition. We review the carrying value
of pipelines and processing plants and other long-lived assets (other than oil
and gas assets accounted for under the full-cost method) for impairment whenever
events and circumstances indicate that the carrying value of an asset may not be
recoverable from the estimated future cash flows expected to result from its use
and eventual disposition. In cases where the undiscounted expected future cash
flows are less than the carrying value, an impairment loss is recognized equal
to an amount by which the carrying value exceeds the fair value of assets. The
fair value is determined using the discounted cash flows method.
OTHER PROPERTY
Other property and equipment are carried at cost. Depreciation is provided using
the straight-line method over estimated useful lives ranging from five to ten
years. Gain or loss on retirement or sale or other disposition of assets is
included in results of operations in the period of disposition.
OTHER OIL AND GAS RELATED SERVICES
Other oil and gas related services consist largely of fees earned from our
operation of oil and gas properties for third parties. Such fees are recognized
in the month the service is provided.
Magnum Hunter does not recognize income in connection with drilling, well
service or other services provided in connection with oil and gas properties in
which we hold an ownership or other economic interest to the extent of our
interest. Any proceeds received for services performed that are not recognized
as income are credited to the full cost pool.
F-10
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
STOCK COMPENSATION
At December 31, 2002, we had three stock-based employee compensation plans which
are described more fully in Note 13. We account for these plans under the
measurement and recognition principles of APB Opinion No. 25, "Accounting for
Stock Issued to Employees and Related Interpretations". Accordingly, we do not
reflect any stock-based compensation in net income because all options granted
under these plans had an exercise price equal to the market value of our stock
on the date or gant. The following table illustrates the effect on net income
and earnings per share if we had applied the fair value recognition provisions
of FASB Statement No. 123, "Accounting for Stock-Based Compensation", to
stock-based employee compensation (in thousands):
YEAR ENDED DECEMBER 31,
----------------------------------
2002 2001 2000
-------- -------- --------
Net income, as reported................................... $ 15,522 $ 13,516 $ 22,260
Deduct: Total stock-based employee compensation
determined under fair value based method for all
awards, net of related tax effects....................... (2,843) (2,417) (1,376)
-------- -------- --------
Pro forma net income...................................... $ 12,679 $ 11,099 $ 20,884
======== ======== ========
Earnings per share:
Basic-as reported.................................... $ 0.25 $ 0.39 $ 0.60
Basic-pro forma...................................... ======== ======== ========
$ 0.21 $ 0.32 $ 0.53
======== ======== ========
Diluted-as reported.................................. $ 0.25 $ 0.36 $ 0.51
Diluted-pro forma.................................... ======== ======== ========
$ 0.20 $ 0.29 $ 0.47
======== ======== ========
The company estimated the fair value of each stock based grant (options and
warrants) using the Black-Scholes option pricing method while using the
following weighted average assumptions:
2002 2001 2000
------------- ------------ -----------
Risk-free interest rate.................................... 3.68% 4.39% 5.75%
Expected life.............................................. 7.4 years 7.4 years 7.4 years
Expected volatility........................................ 49.5% 52.6% 56.0%
Dividend yield............................................. - - -
Weighted average fair value of options granted............. $ 3.17 $ 5.06 $ 6.03
INCOME TAXES
We file a consolidated federal income tax return. Income taxes are provided for
the tax effects of transactions reported in the financial statements and consist
of taxes currently due, if any, plus net deferred taxes related primarily to
differences between the basis of assets and liabilities for financial and income
tax reporting. Deferred tax assets and
F-11
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
liabilities represent the future tax return consequences of those differences
which will either be taxable or deductible when the assets and liabilities are
recovered or settled. Deferred tax assets include recognition of operating
losses that are available to offset future taxable income and tax credits that
are available to offset future income taxes. Valuation allowances are recognized
to limit recognition of deferred tax assets where appropriate. Such allowances
may be reversed when circumstances provide evidence that the deferred tax assets
will more likely than not be realized.
GOODWILL
As a result of our merger with Prize, we currently have $50.7 million of
goodwill recorded on our books. Under SFAS No. 142, we will not amortize any of
the goodwill acquired in the merger. We will evaluate our goodwill for
impairment on an annual basis or whenever indicators of impairment exist. We
have completed the first of these impairment tests and determined that no
impairment exists. The annual impairment test requires management to make
significant estimates and judgements.
NEW ACCOUNTING STANDARDS
SFAS No. 142 - We adopted SFAS No. 142, "Goodwill and Other Intangible Assets",
beginning January 1, 2002. SFAS No. 142 requires, among other things, the
discontinuance of goodwill amortization. Any goodwill resulting from
acquisitions completed after June 30, 2001 will not be amortized.
In addition, SFAS No. 142 requires that we use a new method of testing goodwill
that could reduce the fair value of a reporting unit below its carrying value.
We completed an impairment test at December 31, 2002 and determined that no
adjustments for impairment were necessary. Any goodwill impairment loss will be
recorded in operations. We currently have goodwill of $50.7 million as a result
of our merger with Prize Energy Corp. on March 15, 2002. The adoption of SFAS
No. 142 did not have an impact on our 2002 consolidated financial statements.
SFAS No. 143 - SFAS No. 143, "Accounting for Asset Retirement Obligations", will
be effective for the Company beginning January 1, 2003. SFAS No. 143 requires
the recognition of a fair value liability for any retirement obligation
associated with long-lived assets. The offset to any liability recorded is added
to the recorded asset where the additional amount is depreciated over the same
period as the long-lived asset for which the retirement obligation is
established.
We have evaluated the impact of SFAS No. 143 and expect to record an after tax
earnings effect between a $500 thousand loss and a $1.5 million gain as a
cumulative effect of a change in accounting principle. Additionally, we expect
to record an asset retirement obligation liability between $30 million and $38
million and to provide an increase to net properties and equipment between $30
million and $38 million. The application of SFAS No. 143 in 2003 and future
years will result in the recognition of an accretion expense related to the
discounted liability for the asset retirement obligation and should not have a
material impact on our DD&A rate. There will be no impact on our cash flow as a
result of adopting SFAS No. 143.
SFAS No. 144 - SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets", was effective for us beginning January 1, 2002. SFAS No. 144
establishes a single accounting model, based on the framework established in
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of", for long-lived assets to be disposed of by
sale and resolves significant implementation issues related to SFAS No. 121. The
adoption of SFAS No. 144 had no impact on our financials.
F-12
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
SFAS No. 145 - SFAS No. 145 "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections" was effective for
us beginning January 1, 2003. The Statement rescinds, updates, clarifies and
simplifies various existing accounting pronouncements. SFAS No. 145 rescinds
SFAS No. 4 "Reporting Gains and Losses from Extinguishment of Debt", which
required all gains and losses from extinguishment of debt to be aggregated and,
if material, classified as an extraordinary item, net of related income tax
effect. As a result, SFAS No. 145 will require the reclassification of
extraordinary items for debt extinguishment costs which do not meet the criteria
described in APB Opinion No. 30 "Reporting the Results of Operations - Reporting
the Effects of Disposal of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions", to interest expense. We adopted
this statement beginning January 1, 2003.
SFAS No. 146 - In July 2002, the FASB issued SFAS No. 146 "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS No. 146 requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
SFAS No. 146 supercedes EITF Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Benefits and Other Costs to Exit an Activity (including
certain costs incurred in a Restructuring)." SFAS No. 146 is to be applied
prospectively to exit or disposal activities initiated after December 31, 2002.
SFAS No. 148 - The FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure, an Amendment to FASB Statement No. 123",
in December 2002. SFAS No. 148 provides alternative methods of transition for a
voluntary change to the fair value method of accounting for stock-based employee
compensation and amends the disclosure requirements of SFAS No. 123. We adopted
the disclosure provisions in 2002. We have no plans at this time to change our
method to the fair value based method from the intrinsic value method.
FIN No. 45 - "Guarantor's Accounting and Disclosure Requirements for
Guarantees", was issued in November 2002. This interpretation addresses the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under guarantees. It also clarifies the
requirements related to the recognition of a liability by a guarantor at the
inception of a guarantee for the obligations the guarantor has undertaken in
issuing that guarantee. We adopted this statement in January 2003. We have
provided additional disclosures on our existing guarantees. The adoption had no
impact on our financials at January 1, 2003.
INCOME OR LOSS PER COMMON SHARE
Basic net income or loss per common share is computed by dividing the net income
or loss attributable to common stockholders by the weighted average number of
shares of common stock outstanding during the period. Diluted net income or loss
per common share is calculated in the same manner, but also considers the impact
to net income and common shares for the potential dilution from stock options,
stock warrants and any other outstanding convertible securities.
The following table reconciles the numerators and denominators used in the
computations of both basic and diluted EPS as required by SFAS No. 128,
"Earnings per Share":
F-13
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
FOR THE YEAR ENDED
--------------------------------------------------------------------------------------------
DECEMBER 31, 2002 DECEMBER 31, 2001
----------------------------------------- ---------------------------------------------
PER PER
INCOME SHARES SHARE INCOME SHARES SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT (NUMERATOR) (DENOMINATOR) AMOUNT
------------ ------------- -------- ------------ ------------- -------------
Income before Extraordinary Item $ 16,143,000 61,493,428$ 0.26 $ 13,820,000 34,819,614 $ 0.40
Less: Extraordinary Item ... (621,000) (0.01) (304,000) (0.01)
Net Income ...................... $ 15,522,000 $ 13,516,000
Less: Preferred Stock dividends - - -
------------ ------------ -------- ------------ ------------- -------------
BASIC EPS
Income available to
common stockholders ........... $ 15,522,000 61,493,428 $ 0.25 13,516,000 34,819,614 $ 0.39
Effect of dilutive securities
Warrants ...................... 34,606 212,512
Options ....................... 985,514 2,076,850
Convertible preferred stock ... -
------------ ------------ -------- ------------ ------------- -------------
DILUTED EPS
Income available to
common stockholders and
assumed conversions ........... $ 15,522,000 62,513,548 $ 0.25 $ 13,516,000 37,108,976 $ 0.36
============ ============= ======== ============ ============= =============
Add back: Extraordinary Item (621,000) $ (0.01) (304,000) (0.01)
Income before Extraordinary Item $ 16,143,000 $ 0.26 $ 13,820,000 $ 0.37
============ ============= ======== ============ ============= =============
FOR THE YEAR ENDED
----------------------------------------
DECEMBER 31, 2000
----------------------------------------
PER
INCOME SHARES SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
------------ -------------- --------
Income before Extraordinary Item $ 22,260,000 20,856,854 $ 1.07
Less: Extraordinary Item ... - -
Net Income ...................... $ 22,260,000
Less: Preferred Stock dividends (9,708,000) $ (0.47)
------------ -------------- --------
BASIC EPS
Income available to
common stockholders ........... 12,552,000 20,856,854 $ 0.60
Effect of dilutive securities
Warrants ...................... - 571,623
Options ....................... - 1,247,063
Convertible preferred stock ... 4,312,000 10,158,730
------------ -------------- --------
DILUTED EPS
Income available to
common stockholders and
assumed conversions ........... $ 16,864,000 32,834,270 $ 0.51
============ ============== ========
Add back: Extraordinary Item - -
Income before Extraordinary Item $ 16,864,000 $ 0.51
============ ============== ========
For the years ended December 31, 2002 and 2001, basic and diluted EPS
includes the effect of an extraordinary loss from early extinguishment of
debt of $621,000 and $304,000, or $(.01) per share, respectively.
At December 31, 2002, we had 7,873,206 warrants outstanding at a weighted
average exercise price of $14.32 per share, 6,044,800 options outstanding
at a weighted average price of $6.37 per share, and no outstanding
convertible preferred stock. Warrants totaling 7,838,600 shares and
options totaling 5,059,286 shares were excluded from the diluted net
income per share computation in 2002 because their exercise price
exceeded the average market price of our stock.
At December 31, 2001, we had 644,749 warrants outstanding at a weighted
average exercise price of $6.75 per share, 5,217,584 options outstanding
at a weighted average exercise price of $6.22 per share, and no
outstanding convertible preferred stock. Warrants totaling 432,237 shares
and options totaling 3,140,734 shares were excluded from the diluted net
income per share computation in 2001 as the exercise price exceeded the
average market price of our common stock.
At December 31, 2000, we had 644,749 warrants outstanding at a weighted
average exercise price of $6.75 per share, 4,702,400 options outstanding
at a weighted average exercise price of $4.97 per share, and 25,000
shares of preferred stock convertible to common stock at a weighted
average conversion price of $5.25 per share. Warrants totaling 73,126
shares and options totaling 3,455,337 shares were excluded from the
diluted net income per share computation in 2000 as the exercise price
exceeded the average market price of our common stock.
REVENUE RECOGNITION
Revenues are recognized when title to the product transfers to
purchasers. We follow the "sales method" of accounting for revenue for
oil and natural gas production, so that sales revenue is recognized on
all production sold to purchasers,
F-14
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
regardless of whether the sales are proportionate to our ownership in the
property. A receivable or liability is recognized only to the extent that we
have an imbalance on a specific property greater than the expected remaining
proved reserves. Ultimate revenues from the sales of oil and gas production is
not known with certainty until up to three months after production and title
transfer occur. Current revenues are accrued based on expectations of actual
deliveries and actual prices received.
INFLATION AND CHANGES IN PRICES
Our results of operations and cash flow have been, and will continue to be,
affected by the volatility in oil and gas prices. Should we experience a
significant increase in oil and gas prices that is sustained over a prolonged
period, we would expect that there would also be a corresponding increase in oil
and gas finding costs, lease acquisition costs, and operating expenses.
We market oil and gas for our own account, which exposes us to the attendant
commodities risk. A significant portion of our gas production is currently sold
to a 30% owned affiliate, NGTS, LLC, or end-users either (i) on the spot market
on a month-to-month basis at prevailing spot market prices or (ii) under
long-term contracts based on current spot market prices. We normally sell our
oil under month-to-month contracts to a variety of purchasers.
USE OF ESTIMATES AND CERTAIN SIGNIFICANT ESTIMATES
The preparation of our financial statements in conformity with accounting
principles generally accepted in the United States of America requires our
management to make estimates and assumptions that affect the amounts reported in
these financial statements and accompanying notes. Actual results could differ
from those estimates. Significant assumptions are required in the valuation of
proved oil and gas reserves, which, as described above, may affect the amount at
which oil and gas properties are recorded. It is at least reasonably possible
those estimates could be revised in the near term and those revisions could be
material.
TREASURY STOCK
We may repurchase shares of common stock in stock repurchase programs. Our
repurchases of shares of common stock are recorded as treasury stock at cost and
result in a reduction of Stockholders' Equity. When treasury shares are
reissued, we use a first-in first-out method and the difference between
repurchase cost and reissuance price is treated as an adjustment to paid-in
capital.
NOTE 2 - ACQUISITIONS AND DISPOSITIONS
Effective September 1, 2000, we acquired a 5.5% net profits interest in the
Panoma production and gas gathering facilities for $3.5 million of our
restricted common stock. By acquiring this interest, we lowered our lease
operating expense and increased oil field services income.
Effective April 1, 2000, we exchanged interests in certain onshore oil producing
properties for interests in certain offshore oil and gas producing properties
and production facilities located in the Gulf of Mexico in a tax free like-kind
exchange. The transaction did not have a material effect on reported production
in 2000, but we gained significantly increased exposure in an offshore area of
interest where we have been conducting exploration and development activities.
During 2000, we realized proceeds of $43.8 million from the sale of non-core oil
and gas and other properties, of which approximately $11.6 million was
attributable to Bluebird.
Effective July 1, 2001, we acquired proved oil and gas properties located in
Southeast New Mexico totaling approximately 41.8 Bcfe of reserves for $31.6
million, net of purchase price adjustments. The transaction had an effective
date of July 1, 2001.
F-15
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
On March 15, 2002, we merged with Prize, a publicly traded independent oil and
gas development and production company based in Grapevine, Texas. The
transaction was accounted for by us as a purchase of Prize in accordance with
the provisions of SFAS No. 141 "Business Combinations", which requires the use
of the purchase method of accounting for business combinations initiated and
completed after June 30, 2001. As a result of our merger with Prize, we acquired
oil and gas properties located in three of our core operating areas: the Permian
Basin of West Texas and Southeastern New Mexico, the onshore Gulf Coast area of
Texas and Louisiana and the Mid-Continent area of Oklahoma and the Texas
Panhandle. This allowed us to meet our goal of increasing reserves in geographic
regions similar to our own which allows us to achieve operating synergies and
production enhancements. Under the terms of the merger, we distributed 2.5
shares of common stock plus $5.20 in cash for each Prize share outstanding. The
purchase price, computed from the equity and cash consideration given at the
time of the merger, was allocated to the fair value of the net assets acquired.
The amount of purchase price in excess of the fair value of Prize's net assets
was assigned to goodwill. In accordance with SFAS No. 142 "Goodwill and Other
Intangible Assets", which we adopted on January 1, 2002, the goodwill realized
in the merger with Prize will not be amortized. However, future evaluations of
goodwill will be performed annually to determine whether any impairment has
occurred. We have not completed the final allocation of the purchase price to
the fair value of the specific assets and liabilities of Prize and the related
business integration plan. We expect that the ultimate purchase price
allocation, which will be made on or before March 31, 2003, may include
additional adjustments to the fair value of the specific assets and the carrying
values of certain liabilities. Accordingly, to the extent that such assessments
indicate that the fair value of certain assets and liabilities differ from their
preliminary purchase price allocation, such differences would adjust the amounts
allocated to the assets and liabilities and would change the amounts allocated
to goodwill. We do not intend to assign goodwill to our segments until the
purchase price allocation is finalized. The following table summarizes the total
assumed purchase price and related preliminary allocation to the net assets
acquired (000's) as of December 31, 2002:
Total Purchase Price:
Fair Value of 34,062,963 shares of Magnum Hunter
common stock............................................. . $ 257,175
Cash consideration.......................................... 70,851
Fair Value of Prize warrants................................ 3,416
------------
Total.................................................. $ 331,442
============
Net Preliminary Purchase Price Allocation:
Net purchase price.......................................... $ 331,442
Historical net assets acquired.............................. (148,272)
------------
Excess purchase price....................................... 183,170
Adjustment of proved oil and gas properties to fair value... (57,384)
Adjustment of unproved oil and gas properties to fair value. (139,395)
Adjustment of gas plant to fair value....................... (18,856)
Write-off of historical Prize deferred financing costs...... 2,363
Other fair value adjustments................................ 1,523
Imputed interest on debt due to merger...................... (108)
Additional deferred income taxes............................ 85,545
------------
Excess purchase price allocated to goodwill............ $ 56,858
============
During the third and fourth quarters of 2002, we divested of a number of
properties that were acquired in the Prize merger. Total proceeds received on
the Prize divestitures were approximately $93.3 million. In accordance with SFAS
No. 142,
F-16
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
we attached $6.1 million of goodwill to the divested properties. Proceeds (net
of goodwill) of approximately $87.2 million were applied against the full cost
pool. The remaining goodwill balance at December 31, 2002 was $50.7 million.
Also in accordance with SFAS No. 142, we performed a goodwill impairment test at
December 31, 2002. Test results showed no impairment of goodwill. The goodwill
acquired is not deductible for tax purposes.
Historical net assets acquired in the merger were as follows (in thousands):
Current assets............................... $ 78,440
Properties, plant and equipment, net......... 398,409
Other assets................................. 3,093
Current liabilities.......................... (42,626)
Long-term debt............................... (245,819)
Deferred income taxes........................ (40,677)
Other non-current liabilities................ (2,548)
-----------
Historical net assets acquired............... $ 148,272
===========
Changes to the carrying value of goodwill during the twelve months ended
December 31, 2002 are as follows (in thousands):
Balance at December 31, 2001................. $ -
Goodwill acquired............................ 52,902
Purchase price adjustments................... 3,956
Adjustment for divested properties........... (6,148)
------------
Balance at December 31, 2002................. $ 50,710
============
The following summary, prepared on a pro forma basis, presents the results of
operations for the years ended December 31, 2002 and 2001, as if the acquisition
of Prize occurred as of the beginning of the respective periods. The pro forma
information includes the effects of adjustments for interest expense,
depreciation, depletion and amortization, and income taxes. The pro forma
results are not necessarily indicative of what actually would have occurred if
the acquisition had been completed as of the beginning of each period presented,
nor are they necessarily indicative of future consolidated results. Prize was
included in our consolidated results of operations beginning March 1, 2002.
F-17
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
PRO FORMA RESULTS OF OPERATIONS
(Unaudited)
(in thousands of dollars, except for per share amounts)
YEAR ENDED
DECEMBER 31,
----------------------------
2002 2001
----------- ------------
Total Operating Revenues....................................... $ 292,872 $ 334,873
Total Operating Costs and Expenses............................. (219,575) (224,138)
----------- ------------
Operating Profit............................................... 73,297 110,735
Interest expense and other..................................... (59,202) (52,680)
----------- ------------
Income before income tax....................................... 14,095 58,055
Benefit (Provision) for income tax............................. 513 (21,792)
Extraordinary loss from early extinguishment of debt........... (621) (304)
----------- ------------
Net Income..................................................... $ 13,987 $ 35,959
=========== ============
Net Income Per Common Share....................................
Basic..................................................... $ 0.20 $ 0.52
=========== ============
Diluted................................................... $ 0.20 $ 0.50
=========== ============
NOTE 3 -- RELATED PARTY TRANSACTIONS
In conjunction with the acquisition of Hunter in December 1995, we assumed a
note receivable with a balance of $379,321 from an owner in an affiliated
limited liability company. The note provides for interest at 10 percent and had
a due date of December 31, 2000. The note was not paid by the due date, and we
have commenced legal proceedings in order to recover the amount due. The note is
fully reserved and secured by interest in a real estate joint venture.
At December 31, 2002 and 2001, our note receivable from the Magnum Hunter
Employee Stock Ownership Plan (ESOP) was $4,888,308 and $2,576,067,
respectively. The purpose of the loan is to allow the ESOP to purchase Magnum
Hunter Resources common stock on the open market. The loan is interest free, due
December 31, 2004 and is secured by shares of the company's common stock which
have not been earned by participants in the ESOP. At December 31, 2002 and 2001,
the number of unearned shares in the ESOP were 757,246 and 468,652,
respectively. The unearned shares and their corresponding costs were reflected
on our consolidated balance sheets as reductions to stockholders' equity.
During 1998, our Board of Directors authorized the acquisition of certain shares
of a publicly traded oil and gas company from Mr. Gary C. Evans, President and
Chief Executive Officer of the Company, at Mr. Evans' cost basis in such shares
of stock for purposes of a long-term investment. The shares were purchased for a
total of $442,019, and recorded as a receivable for stockholder. We had the
right to cause Mr. Evans to repurchase the shares back from Magnum Hunter at the
equivalent price that we purchased the shares from Mr. Evans. The value paid for
the shares was in excess of the publicly traded value of the shares on the
acquisition date by $159,481. Mr. Evans repurchased the shares for $442,019
during December 2002, eliminating the receivable from stockholder.
F-18
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
During December 1998, our Board of Directors authorized a loan of up to $300,000
be made available to Mr. Evans. During 1999, the Board of Directors authorized
additional borrowings by Mr. Evans, and the balance, including account interest
of $371,860, was classified as a receivable from stockholder at December 31,
1999. On January 7, 2000, Mr. Evans repaid $225,000 on the loan, leaving a
principal balance of $146,860. On April 17, 2000 Mr. Evans re-borrowed $100,000
under this loan, and on August 18, 2000, he repaid $258,731, including accrued
interest, bringing the balance to zero. On December 28, 2000, Mr. Evans borrowed
$294,938, which was included in notes receivable from affiliate. On January 15,
2001, Mr. Evans repaid $295,261, including accrued interest, bringing the
balance to zero. On April 16, 2001, the company loaned Mr. Evans $300,000, under
an authorization by the Board of Directors, on a note with an interest rate of
10% and due December 31, 2001, which was classified as a note receivable from
affiliate. During 2001 Mr. Evans repaid $328,931, including accrued interest,
bringing the principal and interest balance to zero.
On November 28, 2000, Mr. Matthew C. Lutz, then the Chairman and Executive Vice
President of the Company, borrowed $65,000 from the Company with the approval of
the Board of Directors. On January 15, 2001, Mr. Lutz repaid the loan, including
accrued interest.
There are no loans or extensions of credit to directors and executive officers
of Magnum Hunter as of December 31, 2002.
NOTE 4 -- DEBT
Notes payable and long-term debt at December 31, 2002 and 2001 consisted of the
following (in thousands):
2002 2001
------------ ------------
NOTES PAYABLE:
Notes payable to vendors, due 2002, 7% interest....................... $ - $ 4,044
LONG-TERM DEBT:
Bank debt under revolving credit agreements due May 17, 2004,
3.35% at December 31, 2002........................................... $ 125,000 $ 155,000
Bank debt under revolving credit agreements due March 7, 2004,
5.93% at December 31, 2002 (non recourse)............................ 7,000 -
Capital lease obligations............................................. 9,371 -
Senior unsecured notes, due June 1, 2007, 10%......................... 129,466 129,466
Senior unsecured notes, due March 15, 2012, 9.6%...................... 300,000 -
Other................................................................. - 73
------------ ------------
570,837 288,583
Less current portion.................................................. 1,865 4,117
------------ ------------
$ 568,972 $ 284,466
Total Long-Term Debt ============ ============
The following table presents the approximate annual maturities of debt :
(in thousands)
2003.................................................. $ 1,865
2004 ................................................. 133,999
2005.................................................. 2,491
2006.................................................. 834
Thereafter............................................ 431,648
--------------
Total........................................ $ 570,837
==============
F-19
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The 7% notes payable to vendors were paid in full on March 15, 2002. We had no
notes payable to vendors at December 31, 2002.
We have a Senior Bank Credit Facility ("Facility") which provides for total
borrowings of $500,000,000, on which our borrowing base was limited to
$250,000,000 at December 31, 2002. The level of the borrowing base is dependent
on the valuation of the assets pledged, primarily oil and gas reserve values.
The Facility includes covenants, the most restrictive of which requires
maintenance of a minimum funded debt to EBITDA ratio, interest coverage ratio,
and tangible net worth, as specified in the loan agreement. The bank group must
approve all dividends paid on common stock. The bank group has approved the
redemption of the 10% Senior Notes described below with no changes to our
borrowing base or line of credit. The credit agreement provides for both LIBOR
and "Base rate" (Prime) interest rate options. We had no borrowings outstanding
under the Base rate at December 31, 2002 and $125 million outstanding at LIBOR +
1.75%. We have interest rate hedges on $50 million in principal of these funds,
under which we pay 4.25% and receive LIBOR, effectively increasing our interest
on these borrowings to 6%. See Note 12 for additional information on these
hedges.
During 2002 we amended our Facility to provide for larger total borrowings as
well as a larger borrowing base in relation to the Prize merger. The amended
facility was treated as a new credit facility that we used to pay off the
borrowings under the original credit facility at March 15, 2002. Capitalized
debt issuance costs of $621 thousand, net of tax, were written off as an
extraordinary loss from early extinguishment of debt during the quarter ended
March 31, 2002. Borrowings under the new facility during 2002 were used to
i)fund the cash component of the merger with Prize, ii) pay certain costs
associated with the merger, and iii) for general corporate purposes. We were not
in compliance with the funded debt to EBITDA ratio required under the covenants
at March 31, 2002. The lenders provided us with a waiver as of this date and we
negotiated a less restrictive funded debt to EBITDA ratio for the next four
successive quarters until March 31, 2003. We were in compliance with the
covenants for the remainder of the year and expect to be able to comply with the
revised covenants in the future.
We also have a letter of credit posted against our borrowing base of $2.6
million. While we have no actual borrowings against this letter of credit, it
reduces our funds available under the borrowing base. At December 31, 2002 we
had $122 million available under this Facility. The letter of credit is posted
to Prize's former credit facility to cover a letter of credit they provided to a
property owner on Prize's behalf. The original letter of credit was posted to
cover any plugging and abandonment costs, as well as potential environmental
remediation costs after the property is plugged.
On March 15, 2002, Canvasback entered into a $10 million revolving credit
agreement with a financial institution. The credit agreement provides for both
LIBOR and prime based interest rate options. On June 30, 2002, we converted the
$5.8 million balance under this agreement to a term loan due on March 7, 2004.
Proceeds from the loan were used to purchase $5.8 million in 10% Senior Notes
which had been purchased by Magnum Hunter during 2001 and held for investment.
These 10% Senior Notes, along with $4.7 million in 10% Senior Notes contributed
to Canvasback from Bluebird, serve as the only collateral for this loan.
Canvasback may use additional available funds to purchase additional 10% Senior
Notes or Magnum Hunter treasury shares, to make an advance to an affiliate, or
to pay a dividend to an affiliate. We borrowed additional funds of $1.2 million
during the fourth quarter of 2002, increasing the balance to $7 million. This
loan is non-recourse to Magnum Hunter.
On January 15, 2002, we entered into a sale-leaseback transaction on three
newly-constructed production platforms and associated pipelines located in the
Gulf of Mexico that had already been placed into service. We received total
proceeds of $11.2 million in new funding which we used for general corporate
purposes. The production platforms are being leased from a syndicate group of
lenders over terms from three to five years at a cost of funds based on LIBOR,
yielding a weighted average rate of 5% at December 31, 2002.
On May 29, 1997, we completed a private placement of $140 million in unsecured
10% Senior Notes, due June 1, 2007. Interest is payable on these notes
semi-annually on June 1 and December 1. At December 31, 2002, Canvasback held
F-20
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
$10.5 million of these 10% Senior Notes. On December 26, 2002, we announced the
redemption of $30 million in aggregate principal amount of our 10% Senior Notes
at a redemption price of 105% of par. At the close of business on January 27,
2003, we paid the Holders of the redeemed Notes $31.5 million plus accrued and
unpaid interest of $467 thousand. Of the $30 million redeemed, Canvasback
received $2.3 million.
We completed a private placement of $300 million in unsecured 9.6% Senior Notes
on March 15, 2002. The 9.6% Senior Notes are due March 15, 2012, with interest
payable semi-annually on March 15 and September 15. We used the funds received
to i) retire outstanding indebtedness under the Prize commercial bank credit
facility, ii) pay fees related to the issuance of the new Senior Notes, and iii)
for general corporate purposes.
NOTE 5 -- PRODUCTION PAYMENT LIABILITY
In November, 1996, we entered into a production payment conveyance. We received
a production payment amount of $750,000 and agreed to make royalty payments of
up to 50% of the monthly net revenue proceeds received from certain oil and gas
properties. The balance owed under the conveyance was $114,462 and $203,000 at
December 31, 2002 and 2001, respectively. The production payment bears interest
at the rate of 13.5% per annum and is non-recourse.
NOTE 6 -- INCOME TAXES
We account for income taxes in accordance with SFAS No. 109, "Accounting for
Income Taxes", which requires the recognition of a liability or asset, net of a
valuation allowance, for the deferred tax consequences of all temporary
differences between the tax bases and the reported amounts of assets and
liabilities, and for the future benefit of operating loss carryforwards. The
following is a reconciliation of income tax expense reported in the statement of
operations (in thousands):
2002 2001 2000
-----------------------------------------------
Income tax expense (benefit) at statutory rates......... $ 5,226 $ 7,850 $ 10,191
State tax expense (benefit)............................. 403 818 829
Increase in operating loss and other carry-overs........ - (493) -
Change in valuation allowance........................... (7,100) - (3,875)
Other................................................... 259 433 410
----------- ------------ ------------
Tax expense (benefit)............................... $ (1,212) $ 8,608 $ 7,555
=========== ============ ============
F-21
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The tax effects of significant temporary differences and carryforwards are as
follows (in thousands):
DECEMBER 31,
2002 2001
-----------------------------
Property and equipment, including intangible drilling costs..... $ (169,499) $ (38,005)
Goodwill impairment on divested properties...................... (2,382) -
Other........................................................... (190) (41)
-----------------------------
Total deferred tax liability............................. (172,071) $ (38,046)
-----------------------------
Allowance for doubtful accounts................................. 3,825 3,125
Reserves........................................................ - 33
Depletion carryforwards......................................... 1,080 1,003
Derivative instruments.......................................... 18,910 (995)
Alternative minimum tax credit.................................. 143 98
Employee stock options.......................................... - 2,350
Operating loss and other carryforwards.......................... 45,464 38,034
Other........................................................... 87 -
-----------------------------
Total deferred tax assets................................ 69,509 43,648
-----------------------------
Valuation allowance............................................. - (7,100)
-----------------------------
Net Deferred Tax Liability............................... $ (102,562) $ (1,498)
============ ===========
Magnum Hunter and our subsidiaries have net operating loss carryforwards of
approximately $120,037,000 that expire, if unused, in years 2009 through 2022.
Current tax laws and regulations relating to specified changes in ownership
limit the utilization of our net operating loss and tax credit carryforwards. A
change in ownership of greater than 50% of a corporation within a three year
period causes the annual limitations to be placed in effect. Such a change is
deemed to have occurred February 3, 1999 in connection with the purchase of
preferred stock by ONEOK Resources Company, which has subsequently been either
redeemed or converted to common stock. Approximately $51,413,000 of the net
operating losses are subject to a limitation of $7,850,000 per year. We also
have $9,512,000 of net operating losses subject to a limitation of $3,691,000
per year as a result of the merger with Prize Energy Corp. on March 15, 2002. In
addition, we have depletion carryforwards of $2,851,000 with no expiration
period. A valuation allowance reduces deferred taxes based on the criteria set
forth in SFAS 109.
NOTE 7 -- STOCKHOLDERS' EQUITY
PREFERRED STOCK
Shares of preferred stock may be issued in such series, with such designations,
preferences, stated values, rights, qualifications or limitations as determined
solely by the Board of Directors. Of the 10,000,000 shares of $.001 par value
preferred stock we are authorized to issue, 216,000 shares have been designated
as Series A Preferred Stock,1,000,000 shares have been designated as 1996 Series
A Convertible Preferred Stock and 50,000 shares have been designated as 1999
Series A 8% Convertible Preferred Stock. Thus, 8,734,000 preferred shares have
been authorized for issuance but have not been issued nor have the rights of
these preferred shares been designated. No dividends can be paid on the common
stock until the dividend requirements of the preferred shares have been
satisfied. The preferred shareholders are not entitled to vote except on those
matters in which the consent of the holders of preferred stock is specifically
required by Nevada law. If we were to liquidate prior to payment of the full
dividend requirements on the preferred stock, the preferred stock would receive
a liquidation preference from the liquidation proceeds. On liquidation, holders
of all
F-22
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
series of the preferred stock would be entitled to receive the par value, $.001
per share, in preference to the common stock shareholders.
Dividend payments and preferential rights to Series A preferred shareholders are
tied to wells that have been plugged and abandoned. The liquidation value of the
Series A Preferred Stock is $216.
On December 23, 1996, we issued 1,000,000 shares of new Series A Preferred
Stock, known as the 1996 Series A Convertible Preferred Stock, in a private
placement, resulting in net proceeds after offering costs of $9,280,000.
Dividends of $438,000 and $875,000 and were declared in 2000 and 1999,
respectively. On June 30, 2000 the holders of the 1996 Series A Convertible
Preferred Stock agreed to exchange the convertible preferred securities for
900,000 warrants to purchase restricted common shares of our stock at an
exercise price of $5.25 per share with an expiration date of June 3, 2003 and
payment of $10,000,000. The convertible preferred shares are currently listed as
issued but held by Canvasback as of December 31, 2002.
On February 3, 1999, we sold 50,000 shares of our 1999 Series A 8% Convertible
Preferred Stock for $50 million in a private placement. The preferred stock had
a liquidation value of $50 million and was convertible into our common stock at
$5.25 per share. Dividends on the preferred stock were payable in cash at the
rate of 8% per annum and were cumulative. We used the net proceeds from the
transaction, approximately $46.3 million, to repay senior bank debt. Dividends
of $3,874,000 were declared in 2000; $169,000 of the dividends were paid in
January 2001. On December 7, 2000, we redeemed 25,000 shares of the Preferred
stock for a cash payment of $30,540,000, which included a redemption premium of
$5,540,000. The redemption premium was included in dividends applicable to
preferred stock in our consolidated statement of operations and comprehensive
income in 2000.
WARRANTS
The following is a summary of warrant activity for the periods ended December
31, 2002, 2001 and 2000:
2002 2001 2000
------------------------ ---------------------- -------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
NUMBER OF EXERCISE NUMBER OF EXERCISE NUMBER OF EXERCISE
WARRANTS PRICE WARRANTS PRICE WARRANTS PRICE
---------- -------- --------- -------- ---------- ---------
Outstanding - Beginning of Year..... 644,749 $ 6.75 644,749 $ 6.75 10,608,150 $ 6.49
Issued.............................. 11,500,270 12.80 - - 900,000 5.25
Exercised........................... (578) 9.12 - - (9,413,136) 6.37
Redeemed............................ - - - - (1,429,265) 0.01
Expired............................. (4,271,235) - - - (21,000) -
---------- -------- --------- -------- ----------- ---------
Outstanding - End of Year........... 7,873,206 $ 14.32 644,749 $ 6.75 644,749 $ 6.75
========== ======== ========= ======== =========== =========
The new warrants in 2000 were issued in connection with a redemption of 1996
Series A Convertible Preferred Stock.
On November 27, 2000, the Board of Directors allowed a total of 644,749 warrants
held by certain key officers and
F-23
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
directors with an exercise price of $6.50 per share and an expiration date of
June 30, 2000, to be exchanged for an equal number of new warrants with an
exercise price of $6.75 per share expiring on December 31, 2003. The exercise
price of the new warrants was fair market value on the date of the new grant.
On December 5, 2001, we announced that a distribution of one warrant for every
five shares of common stock owned on January 10, 2002. 7,228,457 warrants were
distributed on March 21, 2002. Each new warrant entitles the holder to purchase
one share of common stock at $15. The warrants will expire three years from the
date of distribution, unless extended by our board of directors.
We also converted outstanding Prize warrants into Magnum Hunter stock warrants
pursuant to the merger (see Note 2). We distributed 4,271,813 of these warrants
on March 15,2002, at a weighted average exercise price of $9.09. These warrants
expired in June and November 2002.
COMMON STOCK
We have a Shareholder Rights Plan, under which the Rights initially represent
the right to purchase one one-hundredth of a share of 1998 Series A Junior
Participating Preferred Stock for $35.00 per one one-hundredth of a share. The
Rights become exercisable only if a person or a group acquires or commences a
tender offer for 15% or more of our common stock. Until they become exercisable,
the Rights attach to and trade with our common stock. The Rights expire January
20, 2008.
In April 2000, we announced a stock repurchase program which allowed the company
or our affiliates to repurchase up to an additional 5% of our outstanding common
stock. During May 2000, Bluebird purchased 129,032 shares at a cost of
approximately $500,000 under this program. On June 11, 2001, we terminated this
program and announced a new program to allow for repurchase of an additional one
million shares of our common stock. Under this program, Bluebird purchased
115,950 shares at cost of $1,015,000 during 2001. On October 2002, we announced
a similar program to allow for an additional 3 million shares to be repurchased.
Under these two programs, Bluebird, Canvasback and Magnum Hunter Production
bought 2,726,200 shares at a cost of $18,493,421 during 2002. Approximately 1.2
million shares remain available for repurchase under our existing programs.
On December 22, 2000, we acquired a 5.5% net profits interest in the Panoma
properties by issuing 356,966 shares of restricted common stock at a value of
$3,480,418.
On March 15, 2002, we issued 34,062,963 shares at a value of $257,175,375
pursuant to our merger with Prize. See Note 2 for further discussion on the
Prize merger.
We issued 656,392, 1,124,616 and 983,834 shares pursuant to employee stock
option exercises for proceeds of $2,413,336, $4,865,000 and $3,627,354 during
2000, 2001 and 2002, respectively. Upon the exercise of warrants, we issued
9,140,408 and 578 shares for proceeds of $57,556,569 and $5,271 during 2000 and
2002, respectively. Of the shares issued for warrants in 2000, 177,272 shares
were issued in a cashless exercise and 164,946 shares were issued for warrants
exercised by our KSOP.
Our KSOP purchased 118,916 (excluding the 164,946 obtained by exercise of
warrants), 105,450 and 532,400 shares at costs of $519,948, $890,095 and
$3,652,386 during 2000, 2001 and 2002, respectively. During the same periods,
the KSOP released shares totaling 141,095, 346,084 and 243,806 to participants.
During 2001 and 2002, we made new loans to the KSOP of $890,095 and $3,652,386,
and the KSOP repaid loan amounts of $1,100,645 and $1,340,145, respectively.
Additionally, we contributed 52,479 shares to our 401(K) plan in 2001. Of the
2002 repayments, $866,614 represented our contribution of 157,659 shares to the
KSOP plan.
We issued 72,900 shares to the public in 2001 for net proceeds of $734,000.
F-24
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
NOTE 8 -- SUPPLEMENTAL CASH FLOW INFORMATION
During 2002, we contributed 157,659 shares valued at $866,614 to our KSOP plan.
Interest paid on our outstanding indebtedness was $48,407,782. Tax paid in 2002
was $666,252. We also completed the Prize merger by issuing 34,062,963 shares of
common stock valued at $257,175,375 and 4,271,813 warrants valued at $3,415,983.
During 2001, we contributed 52,479 shares valued at $151,000 to our 401(K) plan.
In accordance with SFAS No. 115, we increased the carrying costs of our
marketable investments by $507,000 ($466,000 after income tax expense). Interest
paid on our outstanding indebtedness during 2001 was $19,037,000. Tax paid in
2001 was $716,000.
During 2000, we purchased oil and gas properties by issuing 356,966 restricted
common shares valued at $3,480,418. In accordance with SFAS No. 115, we
increased the carrying costs of our marketable investments by $2,006,986
($1,246,840 after income tax expense). Interest paid on our outstanding
indebtedness during 2000 was $21,661,000. We paid no taxes in 2000.
NOTE 9 -- ENVIRONMENTAL ISSUES
Being engaged in the oil and gas exploration and development business, we may
become subject to certain liabilities as they relate to environmental clean up
of well sites or other environmental restoration procedures as they relate to
the drilling of oil and gas wells and the operation thereof. In our acquisition
of existing or previously drilled well bores, we may not be aware of what
environmental safeguards were taken at the time such wells were drilled or
during the time that such wells were operated. Should it be determined that a
liability exists with respect to any environmental clean-up or restoration, the
liability to cure such a violation would most likely fall upon the company. In
certain acquisitions, we have received contractual warranties that no such
violations exist, while in other acquisitions, we have waived our rights to
pursue a claim for such violations from the selling party. No claim has been
made nor has a claim been asserted. We are not aware of the existence of any
material liability relating to any environmental clean-up, restoration or the
violation of any rules or regulations relating thereto.
NOTE 10 -- COMMITMENTS AND CONTINGENCIES
We have certain lease agreements for the use of office space, office equipment,
and vehicles. The Las Colinas office space lease extends through November 2005
with an option to renew the lease for a three year term, and the Grapevine
office lease extends through December 2005. The various office equipment leases
extend until 2004. The various vehicle leases extend until 2012. The leases have
been classified as operating leases. The following is a schedule by years of
future minimum lease payments required under the operating lease agreements:
Year Ended December 31:
2003............................................... $ 2,017,259
2004............................................... 1,972,236
2005............................................... 1,845,687
2006............................................... 749,260
2007............................................... 528,119
Thereafter......................................... 1,340,405
--------------
Total Minimum Payments Required............... $ 8,452,966
==============
Rental expense was $1,481,727, $739,661 and $717,636, for 2002, 2001 and 2000,
respectively.
F-25
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
We have provided trade guarantees on behalf of our 30% owned affiliate, NGTS, in
the amount of $4.1 million. In the event that NGTS is unable to fulfill its
obligations with certain vendors, we would be obligated for cash payments of
$4.1 million to these vendors. We have not recorded this as a liability on our
books at December 31, 2002 because we do not expect to have to perform under
these guarantees. The last of these guarantees expires in May 2003, and we do
not intend to issue any additional guarantees on behalf of NGTS. We have no
other guarantees on behalf of any entities and do not intend to issue any.
NOTE 11 -- FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK
Financial instruments that subject Magnum Hunter to credit risk consist
principally of accounts and notes receivable. The receivables are primarily from
companies in the oil and gas business or from individual oil and gas investors.
These parties are primarily located in the Southwestern region of the United
States. No single receivable is considered to be sufficiently material as to
constitute a concentration. During the year ended December 31, 2002 we recorded
$206 thousand in additional allowances for doubtful accounts. During the year
ended December 31, 2001, we recorded an addition to the allowance for doubtful
accounts of $3,214,000, including $3,156,000 related to Enron. We do not
ordinarily require collateral, but in the case of receivables for joint
operations, we often have the ability to offset amounts due against the
participant's share of production from the related property. We believe the
allowance for doubtful accounts at December 31, 2002 is adequate.
To the extent we receive the spread between the contract floor and the index
price applied to related contract volumes, we have a credit risk in the event of
nonperformance of the counterparty to the agreement. We do not anticipate any
material impact to our results of operations as a result of nonperformance by
such parties.
Management estimates the market values of notes receivable and payable based on
expected cash flows. At December 31, 2002 and 2001, we provided a reserve for
the carrying value of a note receivable of $1,620,000 and $1,620,000,
respectively. After establishing this reserve, management believes those market
values approximate carrying values at December 31, 2002 and 2001. The market
values of equity investments are based upon quoted market prices (see Note 1).
At December 31, 2002, the fair value of our debt was equal to its carrying
value, except for the 9.6% and 10% Senior Notes. The fair value of the 10%
Senior Notes was $133.4 million and the fair value of the 9.6% Notes was $318.8
million.
NOTE 12 -- COMMODITY DERIVATIVES AND HEDGING ACTIVITIES
Crude Oil and Natural Gas Hedges
Periodically, we enter into futures, options, and swap contracts to mitigate the
effects of significant fluctuations in crude oil and gas prices. At December 31,
2002, we had open contracts with the following terms:
Commodity Type Volume/Day Duration Wtd. Avg. Price
----------- ------ ------------ --------------- ---------------
Natural Gas Swap 60,000 MMBTU Jan 03 - Jun 03 $3.01
Natural Gas Swap 10,000 MMBTU Jul 03 - Dec 03 $3.65
Natural Gas Collar 40,000 MMBTU Jan 03 - Jun 03 $3.06 - $4.30
Natural Gas Collar 90,000 MMBTU Jul 03 - Dec 03 $2.89 - $3.87
Natural Gas Collar 25,000 MMBTU Jan 04 - Dec 04 $3.20 - $4.52
Crude Oil Swap 1,000 BBL Jan 03 - Dec 03 $21.25
Crude Oil Collar 6,000 BBL Jan 03 - Dec 03 $23.00 - $27.00
F-26
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
At December 31, 2002, based on future market prices, the fair value of our open
commodity derivative contracts were as follows (in thousands):
Derivative Liabilities
-------------------------------------------------------
Natural gas collars.................................... $ 22,159
Natural gas swaps...................................... 17,905
Crude oil collars...................................... 2,879
Crude oil swaps........................................ 2,060
--------
Total commodity derivative liabilities................. $ 45,003
========
In conjunction with the Prize merger in March 2002, we acquired ten natural gas
derivative contracts for the periods April 2002 through December 2004. We also
acquired seven crude oil derivative contracts for the periods March 2002 through
December 2003. We recorded a hedge asset of $7.6 million to reflect the fair
value of this contract at the merger date. In June 2002, we closed one of the
derivative contracts procured in the Prize merger, realizing proceeds of $3.6
million, which were charged against hedge assets. Consequently, the net hedge
balance of $4.0 million will be amortized as a charge to other non-cash hedging
adjustments over the remaining life of the derivative contracts.
At December 31, 2002, we had four crude oil derivatives and thirteen natural gas
derivatives which are categorized in the tables above. The fair value of these
derivatives was $45.0 million, recognized as derivative liabilities. For the
year ended December 31, 2002, the income statement includes a loss of $4.4
million related to crude oil derivatives and a gain of $1.2 million related to
natural gas derivatives, including amounts reclassified out of other
comprehensive income. The income statement also includes a non-cash hedging
ineffectiveness loss of $557 thousand related to crude oil and natural gas
derivatives and a non-cash loss of $6.1 million related to the amortization of
hedge contract acquired in the Prize merger. The remaining amortization amounts
relating to hedge contracts acquired in the Prize merger that will be
reclassified into the income statement in 2003 and 2004 are a $1.3 million gain
and a $0.8 million gain, respectively. It is estimated at this time that $25.4
million of other comprehensive income loss will be reclassified to the income
statement during the next 12 months.
Net gains (losses) related to crude oil and natural gas derivative transactions
for the years ended December 31, 2002, 2001 and 2000 were ($9.9 million), $4.6
million and (11.2 million), respectively.
Interest Rate Swaps
On August 9, 2001, we entered into two interest rate swaps in order to shift a
portion of our variable rate bank debt to fixed rate debt. The following table
reflects the terms of these swaps.
Type Notional Amount Termination Date Pay Rate Receive Rate
----------------- --------------- ---------------- ----------- ---------------
Pay Fixed/Receive $ 50,000,000 8/23/03 4.25% Fixed 3 month
Variable LIBOR rate
(currently 1.42%)
The rate we receive will be reset every three months to match exactly the rate
we will pay on $50.0 million of our outstanding LIBOR-based bank debt.
F-27
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Our total fixed rate debt outstanding at December 31, 2002 was approximately
$429.5 million. Based on future market rates at December 31, 2002, the fair
value of open contracts was a liability of $1.1 million.
Net gains (losses) related to interest rate derivative transactions for the
years ended December 31, 2002, 2001 and 2000 were $1.2 million, $744 thousand,
and ($13 thousand), respectively.
NOTE 13 -- STOCK COMPENSATION PLANS
We have three stock compensation plans for our employees and directors, (i) the
Magnum Hunter Resources 401(k) Employee Stock Ownership Plan, (the "KSOP"), (ii)
the Magnum Hunter Resources, Inc. 1996 Incentive Stock Option Plan (the "1996
Option Plan"), and (iii) the Magnum Hunter Resources, Inc. 2002 Incentive Stock
Option Plan (the "2002 Option Plan"). In addition, we have made non-incentive
stock option grants in 2002, 2001 and 2000.
KSOP
We established an ESOP and a related trust in 1996 as a long-term benefit for
our employees. On January 1, 2001, the ESOP was merged with the 401(k) plan to
form the KSOP. Under terms of the KSOP, eligible participants may choose to make
elective deferred contributions of not less than 1% or more than 15% of their
annual compensation, limited in combination with the 401(k) plan to the maximum
allowable per year by the Internal Revenue Code. Company contributions to the
KSOP are made on a discretionary basis. It is also our intent to invest all
employer contributions in our common stock. All employees who have reached the
age of 21 and have one year of service, are eligible to participate in the plan.
Shares purchased by the KSOP with loans from the company are released to
participants as company contributions and participant salary deferrals are made
and the related loans are repaid. We have no repurchase obligations with respect
to released shares.
During 2000, we loaned the KSOP $1,592,098 to purchase 118,916 shares of our
common stock on the open market at an average price of $4.37 per share and to
exercise 164,946 warrants at a price of $6.50 per share. On December 8, 2000, we
contributed $448,454 to the KSOP as a discretionary contribution under the Plan.
The KSOP then repaid that portion of its outstanding loan and shares were
allocated among the Plan participants.
During 2001, we loaned the KSOP $890,095 to purchase 105,450 shares of our
common stock on the open market at an average price of $8.44 per share. During
2001, employees purchased 346,084 shares of the KSOP's unreleased shares at an
average price of $3.18 per share through salary deferrals and transfers from the
401(k). Employee purchases totaled $1,100,651, which the KSOP used to repay that
portion of its outstanding loan, and 346,084 shares were allocated among the
Plan participants.
During 2002, we loaned the KSOP $3,652,386 to purchase 532,400 shares of our
common stock on the open market at an average price of $6.86 per share. During
2002, employees purchased 86,147 shares of the KSOP's unreleased shares at an
average price of $5.50 per share through salary deferrals. Employee purchases
totaled $473,531 which the KSOP used to repay that portion of its outstanding
loan, and 86,147 shares were allocated among the Plan participants. We
contributed $866,614 to the KSOP in December 2002 as a discretionary
contribution under the Plan. The KSOP then repaid that portion of its
outstanding loan and 157,659 shares were allocated among participants.
The KSOP loan is interest-free and due December 31, 2004. The loan was secured
by 757,246 shares and 468,652 shares of our common stock at December 31, 2002
and 2001, respectively.
As required under Statement of Position 93-6 "Employers' Accounting for Employee
Stock Ownership Plans," compensation expense is recorded for shares committed to
be released to employees based on the fair market value of those shares when
they are committed to be released. The difference between cost and the fair
market value of the committed to be released shares is recorded in additional
paid-in-capital. Unreleased shares held by the KSOP are excluded from the
calculation of earnings per share.
F-28
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The KSOP shares are summarized as follows:
December 31,
2002 2001
----------- -----------
Allocated shares...................... 796,731 573,416
Unreleased shares..................... 757,246 468,652
----------- -----------
Total ESOP shares.................. 1,553,977 1,042,068
=========== ===========
Fair value of unreleased shares....... $ 4,081,556 $ 3,889,812
The ESOP expense for the years ending December 31, 2002, 2001 and 2000 was
$997,115, $1,655,835 and $1,119,942, respectively.
STOCK OPTION PLANS
Incentive Stock Option Plan
We established this plan beginning April 1, 1996. It is governed by Section 422
of the Internal Revenue Code, and Section 16(b) of the Securities Exchange Act
of 1934. This stock option plan covers 1,200,000 shares of our common stock.
Eligibility is limited to employees and directors of Magnum Hunter and our
subsidiaries. The actual selection of grantees is made by the Board of
Directors. The term of the individual option grants, while at the discretion of
the Board, was five years. All options granted in 1996 were fully vested and
exercisable when granted. The exercise price was fair market value at the date
of each grant.
Non-Incentive Stock Option Grants
During 2000, the Board granted 1,536,000 new stock options to employees at a
weighted average price of $7.89 per share, all of which vested 20% at the date
of grant, with the balance vesting an additional 20% per year on the anniversary
date over the next four years, and with a weighted average term of 9.9 years.
The exercise price was the fair market value on the date of grant.
During 2001, the Board granted 1,655,500 new stock options to employees at a
weighted average price of $8.48 per share, of which 20% vested at the date of
grant, with the balance vesting an additional 20% per year on the anniversary
date over the next four years, with a weighted average term of 9.9 years. The
exercise price was the fair market value on the date of the grant.
During 2002, the Board granted 2,059,750 new stock options to employees at a
weighted average price of $5.61 per share, of which 20% vested at the date of
grant, with the balance vesting an additional 20% per year on the anniversary
date, with a weighted average term of 9.9 years. The exercise price was the fair
market value on the date of grant.
F-29
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The following is a summary of stock option activity under the Option Plans:
2002 2001 2000
------------------------ ------------------------ ------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- ---------- ---------- ---------- ---------- ----------
Outstanding - Beginning of Year ... 5,217,584 $ 6.22 4,702,400 $ 4.97 3,866,092 $ 3.57
Granted ........................... 2,059,750 5.61 1,655,500 8.48 1,536,000 7.89
Exercised ......................... (983,834) 3.71 (1,124,616) 4.33 (656,392) 3.67
Cancelled ......................... (248,700) 7.47 (15,700) 6.59 (43,300) 3.32
---------- ---------- ---------- ---------- ---------- ----------
Outstanding - End of Year ......... 6,044,800 $ 6.37 5,217,584 $ 6.22 4,702,400 $ 4.97
========== ========== ========== ========== ========== ==========
Exercisable - End of Year ......... 2,775,770 $ 6.04 2,531,724 $ 5.14 2,730,460 $ 4.31
========== ========== ========== ========== ========== ==========
The following is a summary of stock options outstanding at December 31, 2002:
WEIGHTED AVERAGE
NUMBER OF OPTIONS REMAINING CONTRACTUAL NUMBER OF
EXERCISE PRICE OUTSTANDING LIFE (YEARS) EXERCISABLE OPTIONS
- ---------------------------- ----------------- --------------------- -------------------
$ 2.50..................... 972,950 1.93 812,720
3.75..................... 22,500 1.43 22,500
5.01..................... 70,000 9.74 14,000
5.20..................... 15,000 9.58 3,000
5.23..................... 6,500 9.75 1,300
5.25..................... 45,000 0.53 45,000
5.36..................... 50,000 9.72 10,000
5.38..................... 1,688,750 9.69 337,750
5.82..................... 3,000 9.66 600
6.625.................... 16,000 2.56 9,600
6.6875................... 2,400 2.58 1,800
7.51..................... 20,000 9.30 4,000
7.55..................... 163,500 9.21 32,700
7.57..................... 15,000 9.42 3,000
7.87..................... 5,000 9.22 1,000
7.9375................... 1,451,200 7.94 873,600
8.44..................... 1,433,000 8.95 573,200
8.50..................... 20,000 8.67 8,000
9.3125................... 20,000 2.97 12,000
11.08.................... 20,000 7.25 8,000
12.00.................... 5,000 3.05 2,000
----------------- --------------------- -------------------
6,044,800 6.47 2,775,770
================= ===================== ===================
F-30
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
We adopted the disclosures only portion of SFAS No. 123 as it continues to
follow the provisions of APB No. 25, which is the intrinsic value method of
accounting for stock-based compensation. See Note 1 for disclosure of pro forma
earnings assuming adoption of SFAS No. 123.
NOTE 14 -- EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND
CHANGE-IN-CONTROL ARRANGEMENTS
Mr. Gary C. Evans, Mr. Richard R. Frazier, Mr. Chris Tong, Mr. R. Douglas Cronk
and Mr. Charles R. Erwin each have employment agreements with the company. Mr.
Evans' agreement terminates January 1, 2006 and continues thereafter on a year
to year basis and provides for a salary of $300,000 per annum unless increased
by the Board. Mr. Evans' salary for the year 2003 is $405,000. Mr. Frazier's
agreement terminates January 1, 2006 and continues thereafter on a year to year
basis and provides for a salary of $175,000 per annum unless increased by the
Board. Mr. Frazier's salary for the year 2003 is $250,000. Mr. Tong's agreement
terminates January 1, 2006 and continues thereafter on a year to year basis and
provides for a salary of $190,000 per annum unless increased by the Board. Mr.
Tong's salary for the year 2003 is $190,000. Mr. Cronk's agreement terminates
January 1, 2006 and continues thereafter on a year to year basis and provides
for a salary of $167,500 per annum unless increased by the Board. Mr. Cronk's
salary for the year 2003 is $167,500. Mr. Erwin's agreement terminates January
1, 2006 and continues thereafter on a year to year basis and provides for a
salary of $185,000 per annum unless increased by the Board. Mr. Erwin's salary
for the year 2003 is $185,000. All of the agreements provide that the same
benefits supplied to other company employees shall be available to these
employees. The employment agreements also contain, among other things, covenants
by these employees that in the event of termination, he will not compete with
the company in certain geographical areas or hire any employees of the company
for a period of two years after cessation of employment.
In addition, all of the agreements contain a provision that upon a
change-in-control of the company and the employee's position is terminated or
the employee leaves for "good cause", the employee is entitled to receive,
immediately in one lump sum, certain compensation. In the case of Mr. Evans and
Mr. Frazier, the employee shall receive three times the employee's current base
salary and bonus plus any other compensation received by him in the last fiscal
year. In the case of Mr. Tong, Mr. Cronk and Mr. Erwin, the employee shall
receive two times the employee's base salary plus bonus and any other
compensation received by him in the last fiscal year. Also, any medical, dental
and group life insurance covering the employee and his dependents shall continue
until the earlier of (i) 12 months after the change-in-control or (ii) the date
the employee becomes a participant in the group insurance benefit program of a
new employer. We also have key man life insurance on Mr. Evans in the amount of
$12,000,000.
NOTE 15 - SEGMENT DATA
We have three reportable segments. The Exploration and Production segment is
engaged in exploratory drilling and acquisition, production, and sale of crude
oil, condensate, and natural gas. The Gas Gathering, Marketing and Processing
segment is engaged in the gathering and compression of natural gas from the
wellhead, the purchase and resale of natural gas which it gathers, and the
processing of natural gas liquids. The Oil Field Services segment is engaged in
the managing and operation of producing oil and gas properties for interest
owners.
Our reportable segments are strategic business units that offer different
products and services. They are managed separately because each business
requires different technology and marketing strategies. The Exploration and
Production segment has six geographic areas that are aggregated. The Gas
Gathering, Marketing and Processing segment includes the activities of the three
gathering systems and four natural gas liquids processing plants in two
geographic areas that are aggregated. The Oil Field Services segment has six
geographic areas that are aggregated. The reason for aggregating the segments,
in each case, was due to the similarity in nature of the products, the
production processes, the type of customers, the method of distribution, and the
regulatory environments.
The accounting policies of the segments are the same as those described in Note
1 - Summary of Significant Accounting Policies. We evaluate performance based on
profit or loss from operations before income taxes. The accounting for
intersegment sales and transfers is done as if the sales or transfers were to
third parties, that is, at current market prices.
F-31
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Segment data for the three years ended December 31, 2002, 2001 and 2000 are as
follows (in thousands):
Gas Gathering,
Exploration & Marketing & Oil Field
2002: Production Processing Services All Other Elimination Consolidated
- --------------------------------------------- -------------- -------------- ----------- ----------- ----------- ------------
Revenue from external customers ............. $ 240,963 $ 20,809 $ 4,097 $ - $ - $ 265,869
Intersegment revenues ....................... 1,647 14,052 14,128 (29,827) -
Depreciation, depletion, amortization and
impairment .................................. 82,950 2,066 507 945 - 86,468
Segment profit (loss) ....................... 78,288 3,643 1,115 (14,177) 68,869
Equity earnings of affiliates ............... 792 792
Interest expense ............................ (47,935) (47,935)
Provision for non-cash impairment of
investments ................................. (621) (621)
Other income (loss) ......................... (6,174) (6,174)
------------
Income before income taxes .................. $ 14,931
Deferred income tax benefit ................. 1,212 1,212
Extraordinary loss .......................... (621) (621)
------------
Net income .................................. $ 15,522
============
Capital expenditures (net of asset sales) ... $ 643,683 $ 21,309 $ 843 $ 2,153 $ 667,988
Gas Gathering,
Exploration & Marketing & Oil Field
2001: Production Processing Services All Other Elimination Consolidated
- --------------------------------------------- -------------- -------------- ----------- ----------- ----------- ------------
Revenue from external customers ............. $ 133,083 $ 17,895 $ 1,828 $ - $ - $ 152,806
Intersegment revenues ....................... - 19,253 6,233 - (25,486) -
Depreciation, depletion, amortization and
impairment................................... 42,703 883 394 19 43,999
Segment profit (loss) ....................... 56,998 725 (2,851) (6,821) 48,051
Equity earnings (losses) of affiliates ...... 1,085 1,085
Interest expense ............................ (19,920) (19,920)
Provision for non-cash impairment of
investments ................................. (7,123) (7,123)
------------
Other income ................................ 335 335
Income before income taxes .................. $ 22,428
Current income tax provision ................ (178) (178)
Deferred income tax provision ............... (8,430) (8,430)
Extraordinary loss .......................... (304) (304)
------------
Net income .................................. $ 13,516
============
Capital expenditures (net of asset sales) ... $ 202,063 $ 61 $ 326 $ 855 $ 203,305
F-32
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Gas Gathering,
Exploration & Marketing & Oil Field
2000: Production Processing Services All Other Elimination Consolidated
- --------------------------------------------- -------------- -------------- ----------- ----------- ----------- ------------
Revenue from external customers ............. $ 106,052 $ 20,010 $ 1,448 $ - $ - $ 127,510
Intersegment revenues ....................... - 20,218 6,128 (26,346) -
Depreciation, depletion, amortization and
impairment................................... 24,350 876 304 26 25,556
Segment profit (loss) ....................... 52,743 3,422 (1,274) (4,562) 50,329
Equity earnings (losses) of affiliates ...... 1,307 1,307
Interest expense ............................ (22,298) (22,298)
Other income ................................ 477 477
------------
Income before income taxes .................. $ 29,815
Current income tax provision ................ (234) (234)
Deferred income tax provision ............... (7,321) (7,321)
Net income .................................. $ 22,260
============
Capital expenditures (net of asset sales) ... $ 20,279 $ 119 $ 495 $ - $ 20,893
Gas Gathering,
Exploration & Marketing & Oil Field
Production Processing Services All Other Elimination Consolidated
-------------- -------------- ----------- ----------- ----------- ------------
As of December 31, 2002
- -----------------------
Segment assets .............................. $ 1,043,531 $ 31,147 $ 26,794 $ 68,307 $ 1,169,779
Equity subsidiary investments ............... 6,722 6,722
As of December 31, 2001
- -----------------------
Segment assets .............................. $ 423,018 $ 15,884 $ 8,675 $ 6,808 $ 454,385
Equity subsidiary investments ............... 5,022 - 5,022
NOTE 16 -- CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
The company and its subsidiaries, except Canvasback and certain inconsequential
subsidiaries, are direct Guarantors of our 10% Senior Notes and 9.6% Senior
Notes, and have fully and unconditionally guaranteed the Notes on a joint and
several basis. In addition to not being a guarantor of our 10% Senior Notes and
9.6% Senior Notes, Canvasback cannot be included in determining compliance with
certain financial covenants under our credit agreements. Management has
determined that separate financial statements relating to the Guarantors are not
material to investors. Condensed consolidating balance sheets for Magnum Hunter
Resources, Inc. and subsidiaries as of December 31, 2002 and 2001 and condensed
consolidating statements of operations and cash flows for the years ended
December 31, 2002, 2001 and 2000 are as follows:
F-33
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES CONDENSED
CONSOLIDATING BALANCE SHEETS
December 31, 2002
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Canvasback Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
ASSETS
Current assets............................... $ 110,584 $ 4,036 $ (16,524) $ 98,096
Property and equipment
(using full cost accounting)................ 994,766 6,843 - 1,001,609
Investment in subsidiaries
(equity method)............................. 15,598 - (15,598) -
Investment in Parent......................... - 39,563 (39,563) -
Other assets................................. 69,345 729 - 70,074
------------------ ---------------- ------------ ---------------
Total Assets.............................. $ 1,190,293 $ 51,171 $ (71,685) $ 1,169,779
================== ================ ============ ===============
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.......................... $ 129,092 $ 16,551 $ (16,524) $ 129,119
Long-term liabilities........................ 681,809 19,189 (10,534) 690,464
Shareholders' equity......................... 379,392 15,431 (44,627) 350,196
------------------ ---------------- ------------ ---------------
Total Liabilities and Stockholders' Equity $ 1,190,293 $ 51,171 $ (71,685) $ 1,169,779
================== ================ ============ ===============
F-34
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES CONDENSED
CONSOLIDATING BALANCE SHEETS
DECEMBER 31, 2001
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
ASSETS
Current assets............................... $ 21,196 $ 3,910 $ - $ 25,106
Property and equipment
(using full cost accounting)................ 412,720 7,117 - 419,837
Investment in subsidiaries
(equity method)............................. 14,963 - (14,963) -
Investment in Parent......................... - 15,750 (15,750) -
Other assets................................. 9,442 - - 9,442
------------------ ---------------- ------------ ---------------
Total Assets.............................. $ 458,321 $ 26,777 $ (30,713) $ 454,385
================== ================ ============ ===============
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.......................... $ 48,561 $ 152 $ - $ 48,713
Long-term liabilities........................ 280,736 11,662 (4,700) 287,698
Shareholders' equity......................... 129,024 14,963 (26,013) 117,974
------------------ ---------------- ------------ ---------------
Total Liabilities and Stockholders' Equity $ 458,321 $ 26,777 $ (30,713) $ 454,385
================== ================ ============ ===============
F-35
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES CONDENSED
CONSOLIDATING STATEMENT OF OPERATIONS
Year Ended December 31, 2002
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Canvasback Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
Revenues..................................... $ 264,152 $ 1,717 $ - $ 265,869
Expenses..................................... 249,974 964 - 250,938
------------------ ---------------- ------------------------------
Income (loss) before......................... 14,178 753 - 14,931
Equity in net earnings of subsidiaries...... 468 - (468) -
------------------ ---------------- ------------------------------
Income (loss) before income taxes............ 14,646 753 (468) 14,931
Income tax provision......................... 1,497 (285) - 1,212
------------------ ---------------- ------------------------------
Income before extraordinary loss............. 16,143 468 (468) 16,143
Extraordinary Loss........................... (621) - - (621)
------------------ ---------------- ------------------------------
Net Income (Loss)........................... $ 15,522 $ 468 $ (468) $ 15,522
================== ================ ============ ===============
Year Ended December 31, 2001
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
Revenues..................................... $ 128,572 $ 24,445 $ (211) $ 152,806
Expenses..................................... 118,265 12,324 (211) 130,378
------------------ ---------------- ------------------------------
Income (loss) before......................... 10,307 12,121 - 22,428
Equity in net earnings of subsidiaries...... 7,530 - (7,530) -
------------------ ---------------- ------------------------------
Income (loss) before income taxes............ 17,837 12,121 (7,530) 22,428
Income tax provision......................... (4,017) (4,591) - (8,608)
------------------ ---------------- ------------ ---------------
Net Income (Loss)........................... $ 13,820 $ 7,530 $ (7,530) $ 13,820
================== ================ ============ ===============
F-36
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Year Ended December 31, 2000
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
Revenues..................................... $ 83,048 $ 44,772 $ (310) $ 127,510
Expenses..................................... 72,375 25,250 70 97,695
------------------ ---------------- ------------ ---------------
Income (loss) before 10,673 19,522 (380) 29,815
Equity in net earnings of subsidiaries...... 12,272 - (12,272) -
------------------ ---------------- ------------ ---------------
Income (loss) before income taxes............ 22,945 19,522 (12,652) 29,815
Income tax provision......................... (305) (7,250) - (7,555)
------------------ ---------------- ------------ ---------------
Net Income (Loss)........................... $ 22,640 $ 12,272 $ (12,652) $ 22,260
================== ================ ============ ===============
F-37
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES CONDENSED
CONSOLIDATING STATEMENT OF CASH FLOWS
Year Ended December 31, 2002
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Canvasback Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
Cash flow from operating activities.......... $ 63,522 $ 19,881 $ - $ 83,403
Cash flow used by investing activities....... (85,398) (4,022) - (89,420)
Cash flow used by financing activities....... 23,686 (16,673) (682) 6,331
------------------ ---------------- ------------ ---------------
Net increase (decrease) in cash.............. 1,810 (814) (682) 314
Cash at beginning of period.................. 730 2,025 - 2,755
------------------ ---------------- ------------ ---------------
Cash at end of period........................ $ 2,540 $ 1,211 $ (682) $ 3,069
================== ================ ============ ===============
Year Ended December 31, 2001
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
Cash flow from operating activities.......... $ 89,712 $ 14,362 $ - $ 104,074
Cash flow used by investing activities....... (225,745) 40,334 (18,578) (203,989)
Cash flow used by financing activities....... 138,574 (54,491) 18,578 102,661
------------------ ---------------- ------------ ---------------
Net increase (decrease) in cash.............. 2,541 205 - 2,746
Cash at beginning of period.................. (1,811) 1,820 - 9
------------------ ---------------- ------------ ---------------
Cash at end of period........................ $ 730 $ 2,025 $ - $ 2,755
================== ================ ============ ===============
Year Ended December 31, 2000
- ----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------------------------------- ------------------ ---------------- ------------ ---------------
Cash flow from operating activities.......... $ 21,909 $ 27,557 $ - $ 49,466
Cash flow used by investing activities....... (13,501) (6,507) - (20,008)
Cash flow used by financing activities....... (9,964) (21,375) 325 (31,014)
------------------ ---------------- ------------ ---------------
Net increase (decrease) in cash.............. (1,556) (325) 325 (1,556)
Cash at beginning of period.................. 1,565 2,145 (2,145) 1,565
------------------ ---------------- ------------ ---------------
Cash at end of period........................ $ 9 $ 1,820 $ (1,820) $ 9
================== ================ ============ ===============
F-38
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)
Proved oil and gas reserves consist of those estimated quantities of crude oil,
natural gas and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Estimates of petroleum reserves have been made by independent engineers and
company employees. These estimates include reserves in which we hold an economic
interest under production-sharing and other types of operating agreements. These
estimates do not include probable or possible reserves. The estimated net
interests in Proved Reserves are based upon subjective engineering judgments and
may be affected by the limitations inherent in such estimation. The process of
estimating reserves is subject to continual revision as additional information
becomes available as a result of drilling, testing, reservoir studies and
production history. There can be no assurance that such estimates will not be
materially revised in subsequent periods. The revisions of previous estimates of
our proved oil and gas reserves were primarily due to changes in commodity
prices at December 31, 2000, 2001 and 2002 that impacted whether such reserves
were economically recoverable. The impact of price changes disproportionately
affects our long life reserves because of the more gradual decline curve of the
applicable production.
Estimated quantities of proved oil and gas reserves were as follows:
GAS
OIL (THOUSAND
(BARRELS) CUBIC FEET)
---------- -----------
DECEMBER 31, 2000
Proved Reserves............................ 22,303,000 233,208,000
Proved Developed Reserves.................. 13,923,000 179,697,000
DECEMBER 31, 2001
Proved Reserves............................ 21,601,000 248,480,000
Proved Developed Reserves.................. 12,960,000 188,413,000
DECEMBER 31, 2002
Proved Reserves............................ 63,082,000 458,644,000
Proved Developed Reserves.................. 48,512,000 362,325,000
The changes in proved reserves for the years ended December 31, 2000, 2001 and
2002 were as follows:
GAS
OIL (THOUSAND
(BARRELS) CUBIC FEET)
----------- -----------
Reserves at December 31, 1999................. 25,534,000 230,000,000
Purchase of minerals-in-place................. 1,000 2,203,000
Sale of minerals-in-place..................... (3,095,000) (21,966,000)
Extensions and discoveries.................... 1,777,000 35,009,000
Production.................................... (1,298,000) (19,579,000)
Revisions of estimates........................ (616,000) 7,541,000
----------- -----------
Reserves at December 31, 2000................. 22,303,000 233,208,000
=========== ===========
Purchase of minerals-in-place................. 1,794,000 25,349,000
Sale of minerals-in-place..................... (67,000) (577,000)
Extensions and discoveries.................... 1,178,000 27,088,000
Production.................................... (1,410,000) (24,864,000)
Revisions of estimates........................ (2,197,000) (11,724,000)
----------- -----------
F-39
GAS
OIL (THOUSAND
(BARRELS) CUBIC FEET)
----------- -----------
Reserves at December 31, 2001................. 21,601,000 248,480,000
=========== ===========
Purchase of minerals-in-place................. 45,650,000 275,873,000
Sale of minerals-in-place..................... (4,621,000) (75,034,000)
Extensions and discoveries.................... 2,986,000 53,939,000
Production.................................... (4,050,000) (46,487,000)
Revisions of estimates........................ 1,516,000 1,873,000
----------- -----------
Reserves at December 31, 2002................. 63,082,000 458,644,000
=========== ===========
The aggregate amounts of capitalized costs relating to oil and gas producing
activities and the related accumulated depreciation, depletion, amortization and
impairment as of December 31, 2002, 2001 and 2000 were as follows:
2002 2001 2000
-----------------------------------------------------
Unproved oil and gas properties ........ $ 165,676,000 $ 18,653,000 $ 5,534,000
Proved properties ...................... 1,053,426,000 556,766,000 367,822,000
--------------- --------------- ---------------
Gross Capitalized Costs ................ 1,219,102,000 575,419,000 373,356,000
Accumulated depreciation, depletion,
amortization and impairment
(250,515,000) (167,487,000) (124,720,000)
--------------- --------------- ---------------
Net Capitalized Costs ......... $968,587,00 $ 407,932,000 $ 248,636,000
=============== =============== ===============
Costs incurred in oil and gas producing activities, both capitalized and
expensed, during the years ended December 31, 2002, 2001 and 2000 were as
follows:
2002 2001 2000
-----------------------------------------------------
Property acquisition costs
Proved properties ................... $ 460,908,000 $ 36,069,000 $ 7,806,000
Unproved properties ................. 147,024,000 12,226,000 1,080,000
Exploration costs ...................... 34,310,000 37,711,000 32,521,000
Development costs ...................... 91,521,000 117,107,000 22,234,000
--------------- --------------- ---------------
Total Costs Incurred .......... $ 733,763,000 $ 203,113,000 $ 63,641,000
=============== =============== ===============
F-40
Results of operations from oil and gas producing activities for the years ended
December 31, 2002, 2001 and 2000 were as follows:
2002 2001 2000
--------------- --------------- ---------------
Oil and gas production revenue ......... $ 240,964,000 $ 133,083,000 $ 106,052,000
Production costs ....................... (79,726,000) (33,382,000) (28,959,000)
Depreciation, depletion, amortization
and impairment ........................ (83,028,000) (42,703,000) (24,350,000)
Income taxes ........................... (27,374,000) (19,949,000) (18,460,000)
--------------- --------------- ---------------
Results of Operations for Producing
Activities ............................ $ 50,836,000 $ 37,049,000 $ 34,283,000
=============== =============== ===============
The standardized measure of discounted estimated future net cash flows related
to proved oil and gas reserves at December 31, 2002, 2001 and 2000 were as
follows:
2002 2001 2000
--------------------------------------------------------------
Future cash inflows .............................. $ 3,728,575,000 $ 998,101,000 $ 2,685,776,000
Future development costs ......................... (178,961,000) (94,950,000) (84,158,000)
Future production costs .......................... (1,159,303,000) (367,526,000) (559,596,000)
------------------ ------------------ ------------------
Future net cash flows, before income tax ......... 2,390,311,000 535,625,000 2,042,022,000
Future income taxes .............................. (619,850,000) (28,299,000) (607,407,000)
------------------ ------------------ ------------------
Future Net Cash Flows ............................ 1,770,461,000 507,326,000 1,434,615,000
10% annual discount .............................. (800,652,000) (201,633,000) (629,692,000)
------------------ ------------------ ------------------
Standardized Measure of Discounted
Future Net Cash Flows (a) ....................... $ 969,809,000 $ 305,693,000 $ 804,923,000
================== ================== ==================
The primary changes in the standardized measure of discounted estimated future
net cash flows for the years ended December 31, 2002, 2001 and 2000 were as
follows:
2002 2001 2000
--------------------------------------------------------------
Purchases of minerals-in-place ................... $ 737,736,000 $ 35,257,000 $ 16,040,000
Sales of minerals-in-place ....................... (85,460,000) (2,614,000) (33,981,000)
Extensions, discoveries and improved
recovery, less related costs .................... 167,334,000 33,623,000 208,966,000
Sales of oil and gas produced,
net of production costs ......................... (161,238,000) (99,701,000) (77,093,000)
Development costs incurred during the period ..... 91,521,000 117,107,000 22,231,000
Revision of prior estimates:
Net change in prices and costs ................ 154,738,000 (858,125,000) 552,634,000
Change in quantity estimates .................. 18,007,000 (88,279,000) 1,524,000
Accretion of discount ............................ 30,569,000 80,492,000 31,562,000
Net change in income taxes ....................... (289,091,000) 283,010,000 (232,576,000)
------------------ ------------------ ------------------
Net Change .............................. $ 664,116,000 $ (499,230,000) $ 489,307,000
================== ================== ==================
F-41
Estimated future cash inflows are computed by applying year-end prices of oil
and gas to year-end quantities of Proved Reserves. Estimated future development
and production costs are determined by estimating the expenditures to be
incurred in developing and producing the proved oil and gas reserves at the end
of the year, based on year-end costs and assuming continuation of existing
economic conditions. Estimated future income tax expense is calculated by
applying year-end statutory tax rates to estimated future pre-tax net cash flows
related to proved oil and gas reserves, less the tax basis of the properties
involved.
The assumptions used to compute the standardized measure are those prescribed by
the Financial Accounting Standards Board and as such, do not necessarily reflect
our expectations of actual revenues to be derived from those reserves nor their
present worth. The limitations inherent in the reserve quantity estimation
process are equally applicable to the standardized measure computations since
these estimates are the basis for the valuation process.
F-42
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
49
PART III
ITEM 10. DIRECTORS AND OFFICERS OF THE REGISTRANT
The following table sets forth the directors, executive officers and other
significant employees, their ages, and all offices and positions within the
company. Our Bylaws divide the Board of Directors into three (3) classes of
directors serving staggered three-year terms, with one class to be elected at
each annual meeting.
NAME AGE TITLE
- -------------------------------- --- --------------------------------------------------------------------
Gary C. Evans................... 45 Chairman, President and Chief Executive Officer
Richard R. Frazier.............. 56 Executive Vice President and Chief Operating Officer
Chris Tong...................... 46 Senior Vice President and Chief Financial Officer
R. Douglas Cronk................ 56 Senior Vice President of Operations of Magnum Hunter Production,
Inc. and Gruy
Charles R. Erwin................ 56 Senior Vice President of Exploration of Magnum Hunter Production,
Inc. and Gruy
M. Bradley Davis................ 43 Senior Vice President - Capital Markets & Corporate Development
Morgan F. Johnston.............. 42 Senior Vice President, General Counsel and Secretary
David S. Krueger................ 53 Vice President and Chief Accounting Officer
Gregory L. Jessup............... 49 Vice President Land - Offshore of Magnum Hunter Production, Inc. and
Gruy
Richard S. Farrell.............. 45 Vice President Land - Onshore of Magnum Hunter Production, Inc. and
Gruy
David M. Keglovits.............. 51 Vice President and Controller
Earl Krieg, Jr. ................ 49 Vice President of Engineering of Magnum Hunter Production, Inc. and
Gruy
Howard M. Tate.................. 35 Vice President of Finance
Gerald W. Bolfing............... 74 Director
Jerry Box....................... 64 Director
James R. Latimer, III........... 57 Director
Matthew C. Lutz................. 68 Director
John H. Trescot, Jr............. 78 Director
James E. Upfield................ 82 Director
Gary C. Evans has served as President, Chief Executive Officer and a director of
Magnum Hunter Resources, Inc. since December 1995 and Chairman and Chief
Executive Officer of all of the Magnum Hunter subsidiaries since their formation
or acquisition. In 1985, Mr. Evans formed the predecessor company, Hunter
Resources, Inc., that was merged into and formed Magnum Hunter some ten years
later. From 1981 to 1985, Mr. Evans was associated with the Mercantile Bank of
Canada where he held various positions including Vice President and Manager of
the Energy Division of the Southwestern United States. From 1978 to 1981, he
served in various capacities with National Bank of Commerce (now BancTexas,
N.A.) including Credit Manager and Credit Officer. Mr. Evans serves on the Board
of Directors of Novavax, Inc., a NASDAQ listed pharmaceutical company. He
additionally serves on the board of three private Texas-based companies that
Magnum Hunter owns various minority interests in, including (i) Swanson
Consulting Services, Inc., a geological consulting firm; (ii) NGTS, LLC, a
natural gas marketing company and (iii) Metrix Networks, Inc., a company that
provides web-enabled automation to the oil and natural gas industry. He also
serves as a Trustee of TEL Offshore Trust, a NASDAQ listed oil and gas trust of
which Magnum Hunter owns an approximate 38% interest.
50
OFFICERS
Richard R. Frazier has served as Executive Vice President and Chief Operating
Officer of Magnum Hunter since January 1, 2003. He also has served as President
and Chief Operating Officer of Magnum Hunter Production, Inc. and Gruy since
January 1994. From 1977 to 1993, Mr. Frazier was employed by Edisto Resources
Corporation in Dallas, serving as Executive Vice President Exploration and
Production from 1983 to 1993, where he had overall responsibility for its
property acquisition, exploration, drilling, production, gas marketing and
engineering functions. From 1972 to 1976, Mr. Frazier served as District
Production Superintendent and Petroleum Engineer with HNG Oil Company (now Enron
Oil & Gas Company) in Midland, Texas. Mr. Frazier's initial employment, from
1968 to 1971, was with Amerada Hess Corporation as a petroleum engineer involved
in numerous projects in Oklahoma and Texas. Mr. Frazier graduated in 1970 from
the University of Tulsa with a Bachelor of Science Degree in Petroleum
Engineering. He is a registered Professional Engineer in Texas and a member of
the Society of Petroleum Engineers and many other professional organizations.
Chris Tong has served as Senior Vice President and Chief Financial Officer since
August 1997. Previously, Mr. Tong was Senior Vice President of Finance of Tejas
Acadian Holding Company and its subsidiaries including Tejas Gas Corp., Acadian
Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries
of Tejas Gas Corporation. In January 1998, Tejas Gas Corporation was acquired by
Shell Oil. Mr. Tong held these positions since August 1996, and served in other
treasury positions with Tejas beginning August 1989. He was also responsible for
managing Tejas' property and liability insurance. From 1980 to 1989, Mr. Tong
served in various energy lending capacities with Canadian Imperial Bank of
Commerce, Post Oak Bank, and Bankers Trust Company in Houston, Texas. Prior to
his banking career, Mr. Tong also served over a year with Superior Oil Company
as a Reservoir Engineering Assistant. He additionally serves on the board of two
private Texas-based companies that Magnum Hunter owns various minority interests
in, including (i) NGTS, LLC, a natural gas marketing company and (ii) Metrix
Networks, Inc., a company that provides web-enabled automation to the oil and
natural gas industry. Mr. Tong is a summa cum laude graduate of the University
of Southwestern Louisiana with a Bachelor of Arts degree in Economics and a
minor in Mathematics.
R. Douglas Cronk has served as Senior Vice President of Operations for Magnum
Hunter Production, Inc. and Gruy since December 1998. He served as Vice
President of Operations for the two companies since May 1996 at which time the
company acquired from Mr. Cronk, Rampart Petroleum, Inc., based in Abilene,
Texas. Rampart had been an active operating and exploration company in the north
central and west Texas region since 1983. Prior to the formation of Rampart, Mr.
Cronk was an independent oil and gas consultant in Houston, Texas for
approximately two years. From 1974 to 1981, Mr. Cronk held various positions
with subsidiaries of Deutsch Corporation of Tulsa, Oklahoma, including Southland
Drilling and Production where he became Vice President of Drilling and
Production. Mr. Cronk is a Chemical Engineer graduate from the University of
Tulsa.
Charles R. Erwin has served as Senior Vice President of Exploration for Magnum
Hunter Production, Inc. and Gruy Petroleum Management Co. since July 2000. He
became Vice President of Exploration for Magnum Hunter Production, Inc. and Gruy
Petroleum Management Co. in January 2000. Mr. Erwin initially served as Manager
of Exploration for Gruy Petroleum Management Co. beginning May of 1999. Mr.
Erwin received a Masters in Geology from the University of Wisconsin -
Milwaukee. He has 27 years experience in the oil and gas industry. Prior to Gruy
Petroleum Management Co., Mr. Erwin worked for Enserch Exploration for 22 years,
holding various positions including Exploration Manager - East Texas,
Exploration Manager - Texas and Louisiana Gulf Coast and Director Exploration
Offshore and International.
M. Bradley Davis has served as Senior Vice President - Capital Markets &
Corporate Development since September 2002. Mr. Davis has 21 years of experience
and direct involvement in all facets of the energy industry, including nine
years as a Senior Equity Research Analyst, specializing in the small-to-mid
capitalization independent exploration and production sector. Previously, Mr.
Davis was Senior Vice President and Senior Energy Analyst for SWS Securities
(formerly Southwest Securities), a Dallas, Texas based full-service investment
banking firm. Mr. Davis also has been affiliated as a Senior Energy Analyst with
CIBC World Markets, BT. Alex Brown, Williams MacKay Jordan and Fitch Investors
Service. Mr. Davis' professional background also includes ten years as an energy
corporate finance specialist with The Bank of New York and Texas Commerce
Bancshares. Mr. Davis began his career in the management training program of an
internationally focused
51
offshore drilling contractor. A native of Odessa, Texas, Mr. Davis received his
Bachelor of Arts degree from Baylor University in 1981, majoring in Business
Administration and Political Science (International Relations).
Morgan F. Johnston has served as Senior Vice President, General Counsel and
Secretary since January 1, 2003. He previously served as the Company's Vice
President and General Counsel since April 1997. He also served as the Company's
Secretary since May 1, 1996. Mr. Johnston was in private practice as a sole
practitioner from May 1, 1996 to April 1, 1997, specializing in corporate and
securities law. From February 1994 to May 1996, Mr. Johnston served as general
counsel for Millennia, Inc. and Digital Communications Technology Corporation,
two American Stock Exchange listed companies. He also previously served as
securities counsel for Motel 6 L.P., a New York Stock Exchange listed company.
Mr. Johnston graduated cum laude from Texas Tech Law School in May 1986 and was
also a member of the Texas Tech Law Review. He is licensed to practice law in
the State of Texas. He is a member of the American Society of Corporate
Secretaries and a member of the Texas General Counsel Forum.
David S. Krueger has served as Vice President and Chief Accounting Officer of
the Company since January 1997. Mr. Krueger acted as Vice President-Finance of
Cimarron Gas Holding Co., a gas processing and natural gas liquids marketing
company in Tulsa, Oklahoma, from April 1992 until January 1997. He served as
Vice President/Controller of American Central Gas Companies, Inc., a gas
gathering, processing and marketing company from May 1988 until April 1992. From
1974 to 1986, Mr. Krueger served in various managerial capacities for Southland
Energy Corporation. From 1971 to 1973, Mr. Krueger was a staff accountant with
Arthur Andersen LLP. Mr. Krueger, a certified public accountant, graduated from
the University of Arkansas with a B.S./B.A. degree in Business Administration
and earned his M.B.A. from the University of Tulsa.
Gregory L. Jessup has been Vice President Land - Offshore for Magnum Hunter
Production, Inc., a wholly-owned subsidiary of the Company and Gruy since April
17, 1998. Mr. Jessup joined the Company as Land Manager on May 1, 1997. From
1982 until joining the company, Mr. Jessup served as Land Manager of Ken
Petroleum Corporation of Dallas, managing its Land and Regulatory Department as
well as managing its crude oil marketing business. During his tenure as Land
Manager, Mr. Jessup has been actively involved in all phases of land operations,
including negotiations, acquisitions, and administration. Mr. Jessup holds a
Bachelor of Business Administration degree in Management from Texas Tech
University and is a Certified Professional Landman.
Richard S. Farrell serves as Vice President Land - Onshore for Magnum Hunter
Production, Inc., a wholly-owned subsidiary of the company, and Gruy since March
2002. Mr. Farrell oversees a staff responsible for all of the corporation's
onshore land, A & D, administrative and some litigation functions. Prior to
Magnum Hunter, Mr. Farrell served as Land Manager, then Vice President - Land
for Prize Energy Resources Corp. from July 1999 until March 2000. From 1996
until joining Prize Energy Resources Corp., he was the Sr. Division Landman and
Team Leader for the South Texas Business Unit of Pioneer Natural Resources USA,
Inc. Prior to that time, he held various land related positions in both large
and small oil companies, including Vice President - Land for Rancho Resources
Corporation (an independent oil and gas exploration company) and as Executive
Vice President for its parent company, Solaris Energy Corporation. Mr. Farrell
earned his Bachelor's Degree in marketing from the University of Richmond, where
he also was honored with designation into Who's Who in American College
Students.
David M. Keglovits has served as Vice President and Controller of the Company
and its subsidiaries since 1999. Prior to 1999, Mr. Keglovits served as Vice
President and Controller of Gruy. Mr. Keglovits joined Gruy in March 1977 as an
accountant before holding the positions of Assistant Controller and Controller.
From December 1974 to December 1976, Mr. Keglovits was employed by Bell
Helicopter International in its financial management office in Tehran, Iran. Mr.
Keglovits was graduated with honors from the University of Texas at Austin with
a B.B.A. in Accounting.
Earl Krieg, Jr. has served as Manager of Engineering for Gruy Petroleum
Management Co. since May of 1999. Mr. Krieg became Vice President of Engineering
for Magnum Hunter Production, Inc. and Gruy in January 2000. Mr. Krieg was
employed by The Wiser Oil Company for the five years prior to joining the
Company in various capacities, including Manager of Operations and Manager of
Secondary Recovery. Mr. Krieg has 26 years experience in various reservoir
engineering, operations, acquisitions and management roles with Chevron, General
Crude, Edisto and, most recently, The Wiser Oil Company. Mr. Krieg is a
Registered Professional Engineer in Texas and was an officer in the Society of
Petroleum Evaluation Engineers in 1989. Mr. Krieg graduated from Texas A&M
University in 1975 with a B.S. degree in petroleum engineering.
Howard M. Tate has served as Vice President of Finance for the company since
April 15, 2002. From 1999 until joining Magnum Hunter, Mr. Tate had been at
Marine Drilling Companies, Inc., and its successor Pride International, Inc.,
located in Houston, Texas, where Mr. Tate last served as Treasurer. During the
period from September 1995 until August 1999,
52
Mr. Tate served as Director - Corporate Finance and other various treasury
department positions with Tejas Energy, LLC (formerly Tejas Gas Corporation) and
from January 1991 through September 1995, he worked as a Senior Project Finance
Analyst with Tenneco Gas. Mr. Tate holds a Bachelor of Science degree in
Accounting and Finance from Oklahoma State University and a Master of Business
Administration from the University of Houston.
DIRECTORS
Gerald W. Bolfing has been a director of Magnum Hunter since December 1995. Mr.
Bolfing was appointed a director of Hunter Resources, Inc. in August 1993. He is
an investor in the oil and gas business and a past officer of one of Hunter's
former subsidiaries. From 1962 to 1980, Mr. Bolfing was a partner in Bolfing
Food Stores in Waco, Texas. Mr. Bolfing was involved in American Service Company
in Atlanta, Georgia from 1964 to 1965, and was active with Cable Advertising
Systems, Inc. of Kerrville, Texas from 1978 to 1981. He joined a Hunter
subsidiary in the well servicing business in 1981 where he remained active until
its divestiture in 1992. Mr. Bolfing is on the board of directors of Capital
Marketing Corporation of Hurst, Texas.
Jerry Box has served as a director of Magnum Hunter since March 1999. From
February 1998 to March 1999, he served in the position of president and chief
operating officer and as a director of Oryx Energy Company, now owned by Kerr
McGee Corporation. From December 1995 to February 1998, he was executive vice
president and chief operating officer of Oryx. From December 1994 through
November 1995, he served as executive vice president, exploration and production
of Oryx. Previously, he served as senior vice president, exploration and
production of Oryx. Mr. Box attended Louisiana Tech University, where he
received B.S. and M.S. degrees in geology, and is also a graduate of the Program
for Management Development at the Harvard University Graduate School of Business
Administration. Mr. Box served as an officer in the U.S. Air Force from 1961 to
1966. Mr. Box is a former member of the Policy Committee of the U.S. Department
of the Interior's Outer Continental Shelf Advisory Board, past chairman and
vice-chairman of the American Petroleum Institute's Exploration Affairs
subcommittee, a former president of the Dallas Petroleum Club and a member of
the Independent Petroleum Association of America.
James R. Latimer, III was a director of Prize from October 2000 until the merger
with Magnum Hunter when he was elected to our board of directors. Over the past
eight years, Mr. Lattimer has been the chairman and chief executive officer of
Explore Horizons, Incorporated, a privately held exploration and production
company based in Dallas, Texas. Previously, Mr. Lattimer was co-head of the
regional office of what is now The Prudential Capital Group in Dallas, Texas,
which handled energy and other financing for The Prudential Insurance Company.
In addition, Mr. Lattimer's prior experience has included senior executive
positions with several private energy companies, consulting with the firm of
McKinsey & Co., service as an officer in the United States Army Signal Corps.,
and several directorships. Mr. Lattimer received a B.A. degree in economics from
Yale University and an M.B.A. from Harvard University. He is a Chartered
Financial Analyst.
Matthew C. Lutz retired as chairman of Magnum Hunter on September 1, 2001 after
having served in that capacity since March 1997, and after having previously
served as vice chairman of Magnum Hunter from December 1995 to March 1997. Mr.
Lutz also previously served as executive vice president of Magnum Hunter from
December 1995 to September 2001. Mr. Lutz held similar positions with Hunter
Resources, Inc. from September 1993 until October 1996. From 1984 through 1992,
Mr. Lutz was senior vice president of exploration and a director of Enserch
Exploration, Inc., with responsibility for its worldwide oil and gas exploration
and development program. Prior to joining Enserch, Mr. Lutz spent 28 years with
Getty Oil Company. He advanced through several technical, supervisory and
managerial positions, which gave him various responsibilities, including
exploration, production, lease acquisition, administration and financial
planning.
John H. Trescot, Jr. has served as a director of Magnum Hunter since June 1997.
Mr. Trescot is the principal of AWA Management Corporation, a consulting firm
specializing in project evaluation. Mr. Trescot began his professional career as
an engineer with Shell Oil Company. Later, Mr. Trescot joined Hudson Pulp &
Paper Corp. (now a part of Georgia-Pacific Corp.), where he served 19 years in
various positions in woodlands and pulp and paper, advancing to the position of
senior vice president for its Southern Operations. Mr. Trescot then became vice
president of The Charter Company, a multi-billion dollar corporation with
operations in oil, communications and insurance. In 1979, Mr. Trescot became the
chief executive officer of JARI, a timber, pulp and mining operation in the
Amazon Basin of Brazil. During 1982-89, while he was the chief executive officer
of TOT Drilling Corp., TOT drilled many deep wells in West Texas and New Mexico
for major and independent oil companies. Mr. Trescot served as an officer in the
United States Navy. Mr. Trescot received his BME degree from Clemson University
and his M.B.A. from Harvard University.
53
James E. Upfield has served as a director of Magnum Hunter since December 1995.
Mr. Upfield was appointed a director of Hunter Resources, Inc., in August 1992.
Mr. Upfield is chairman of Temtex Industries, Inc., a public company based in
Dallas, Texas, that produces consumer hard goods and building materials. In
1969, Mr. Upfield served on a select Presidential Committee overseeing postal
operations of the United States of America. He later accepted the responsibility
for the Dallas region, which encompassed Texas and Louisiana. From 1959 to 1967,
Mr. Upfield was president of Baifield Industries, Inc. and its predecessor, a
company he founded in 1949 which merged with Baifield in 1963. Baifield was
engaged in prime government contracts for military systems and sub-systems in
the production of high-strength, light-weight metal products.
ITEM 11. EXECUTIVE COMPENSATION
The following table contains information with respect to all cash compensation
we paid or accrued during the past three fiscal years to our Chief Executive
Officer and each person serving as an executive officer on December 31, 2002.
LONG-TERM COMPENSATION
------------------------------
ANNUAL COMPENSATION AWARDS PAYOUT
--------------------- ---------- -------
Name, Other Number
Principal Annual Restricted Options LTP All Other
Position Year Salary Bonus Compensation (a) Stock SARs Payouts Compensation
- ----------------------------------------------------------------------------------------------------------------------------
Gary C. Evans 2002 $ 375,000 -(d) $ 7,500 - 250,000 - $ 35,827(b)
Chairman, President and 2001 $ 350,000 $ 425,000 $ 7,500 - 300,000 - $ 33,240(b)
CEO 2000 $ 300,000 $ 400,000 $ 7,500 - 300,000 - $ 32,788(b)
Richard R. Frazier 2002 $ 205,000 -(d) $ 6,000 - 140,000 - 16,750(c)
Executive V.P. and 2001 $ 190,000 $ 150,000 $ 6,000 - 125,000 - 12,613(c)
Chief Operating Officer 2000 $ 175,000 $ 125,000 $ 6,000 - 100,000 - 12,855(c)
Chris Tong 2002 $ 175,000 -(d) $ 6,000 - 90,000 - 16,750(c)
Senior V.P. and 2001 $ 165,000 $ 100,000 $ 6,000 - 75,000 - 12,613(c)
Chief Financial Officer 2000 $ 160,000 $ 65,000 $ 6,000 - 40,000 - 12,553(c)
R. Douglas Cronk 2002 $ 150,000 -(d) $ 6,000 - 90,000 - 16,750(c)
Senior V.P. of Magnum 2001 $ 138,000 $ 75,000 $ 6,000 - 75,000 - 12,613(c)
Hunter Production, Inc. 2000 $ 122,500 $ 65,000 $ 6,000 - 50,000 - 12,855(c)
Charles R. Erwin 2002 $ 155,000 -(d) $ 6,000 - 125,000 - 16,750(c)
Senior V.P. of Magnum 2001 $ 145,000 $ 125,000 $ 6,000 - 100,000 - 10,947(c)
Hunter Production, Inc. 2000 $ 113,423 $ 125,000 $ 5,100 - 100,000 - 12,855(c)
- ----------
(a) Consists of a vehicle allowance paid to the employee.
(b) Consists of compensation for acting as an individual Trustee for the
TEL Offshore Trust and employer contributions to the KSOP Plan.
(c) Consists of employer contributions to the KSOP Plan.
(d) 2002 bonuses were not earned or paid until March 2003.
54
OPTION/SAR GRANTS IN LAST FISCAL YEAR
Potential realizable
Individual Grants value at assumed annual Alternative to
rates of stock price (f) and (g):
appreciation for option grant date
term value
- ---------------------------------------------------------------------------------------------------------------------------------
Name Number of Percent of total Exercise or base Expiration 5% ($) 10% ($) Grant date
securities options/SARs price ($/Sh) date present value*
underlying granted to $
Options/SARs employees in
granted (#) fiscal year
(a) (b) (c) (d) (e) (f) (g) (f)*
- ---------------------------------------------------------------------------------------------------------------------------------
Gary C. Evans 250,000 7% $ 5.38 9/06/12 $ 755,000
Richard R. Frazier 140,000 4% $ 5.38 9/06/12 $ 422,800
Charles R. Erwin 125,000 4% $ 5.38 9/06/12 $ 377,500
R. Douglas Cronk 90,000 3% $ 5.38 9/06/12 $ 271,800
Chris Tong 90,000 3% $ 5.38 9/06/12 $ 271,800
* The Black-Scholes method was used to determine the value of the option grants.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FY-END OPTION/SAR VALUES
Number of securities
underlying unexercised Value of unexercised in-
options/SARs at fiscal the-money options/SARs
year-end (#) at fiscal year-end ($)
Shares acquired on Value Exercisable/ Exercisable/
Name exercise (#) Realized ($) unexercisable unexercisable
(a) (b) (c) (d) (e)
- ----------------------------------------------------------------------------------------------------------------
Gary C. Evans - - 550,000 / 550,000 $718,500 / $286,500
Richard R. Frazier 100,000 $ 203,500 238,000 / 252,000 $ 60,960 / $150,090
Charles R. Erwin - - 137,000 / 204,000 $ 55,650 / $ 70,800
R. Douglas Cronk 56,334 $ 155,045 89,000 / 148,000 $ 68,370 / $ 78,990
Chris Tong 138,200 $ 309,828 116,000 / 144,000 $162,060 / $ 78,990
Compensation of Directors
We have seven individuals who serve as directors, six of which are independent.
One director receives compensation with respect to his services and in his
capacities as an executive officer of the company, and no additional
compensation has historically been paid for his services as a director. The
other six directors were not employees at December 31, 2002, and receive no
compensation for their services as directors other than as stated below. For
fiscal year 2002, independent directors received a $20,000 retainer for being a
board member and (i) prior to September 23, 2002, received $1,500 per meeting
attended and $500 per committee meeting attended and (ii) subsequent to
September 23, 2002, received $1,000 per regular and committee meeting attended .
In addition, for the fiscal year 2002 each independent director was granted
stock options to acquire 10,000 shares of our common stock at an exercise price
not less than the market price of the common stock on the date of grant.
Finally, all chairpersons of our board of directors' committees received an
annual retainer of $2,500 for acting
55
as chairman of his respective committee. For fiscal year 2003, independent
directors will receive a $20,000 retainer (pro- rated) for being a board member
and, in addition, will receive $1,000 per meeting attended and $1,000 per
committee meeting attended. Other than the compensation stated herein, we have
not entered into any arrangement, including consulting contracts, in
consideration of the director's service on the board.
Employment Contracts and Termination of Employment and Change-in-Control
Arrangements
Mr. Gary C. Evans, Mr. Richard R. Frazier, Mr. Chris Tong, Mr. R. Douglas Cronk
and Mr. Charles R. Erwin each have employment agreements with the company. Mr.
Evans' agreement terminates January 1, 2006 and continues thereafter on a year
to year basis and provides for a salary of $300,000 per annum, unless increased
by the Board. Mr. Evans' salary for the year 2003 is $405,000. Mr. Frazier's
agreement terminates January 1, 2006 and continues thereafter on a year to year
basis and provides for a salary of $175,000 per annum unless increased by the
Board. Mr. Frazier's salary for the year 2003 is $250,000. Mr. Tong's agreement
terminates January 1, 2006 and continues thereafter on a year to year basis and
provides for a salary of $190,000 per annum, unless increased by the Board. Mr.
Tong's salary for the year 2003 is $190,000. Mr. Cronk's agreement terminates
January 1, 2006 and continues thereafter on a year to year basis and provides
for a salary of $167,500 per annum, unless increased by the Board. Mr. Cronk's
salary for the year 2003 is $167,500. Mr. Erwin's agreement terminates January
1, 2006 and continues thereafter on a year to year basis and provides for a
salary of $185,000 per annum unless increased by the Board. Mr. Erwin's salary
for the year 2003 is $185,000. All of the agreements provide that the same
benefits supplied to other company employees shall be available to the employee.
The employment agreements also contain, among other things, covenants by the
employee that in the event of termination, he will not compete with the company
in certain geographical areas or hire any of our employees for a period of two
years after cessation of employment.
In addition, all of the agreements contain a provision that upon a change in
control, the employee's position is terminated, or the employee leaves for "good
cause", the employee is entitled to receive immediately, in one lump sum,
certain compensation. In the case of Mr. Evans and Mr. Frazier, the employee
shall receive three times the employee's current base salary and bonus plus any
other compensation received by him in the last fiscal year. In the case of Mr.
Tong, Mr. Cronk and Mr. Erwin, the employee shall receive two times the
employee's current base salary and bonus plus any other compensation received by
him in the last fiscal year. Also, any medical, dental and group life insurance
covering the employee and his dependents shall continue until the earlier of (i)
12 months after the change in control or (ii) the date the employee becomes a
participant in the group insurance benefit program of a new employer. We also
have key man life insurance on Mr. Evans in the amount of $12,000,000.
56
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 15, 2003,
regarding the share ownership of the Company by (i) each person known to the
Company to be the beneficial owner of more than 5% of the outstanding shares of
Common Stock of the Company, (ii) each director, (iii) the Company's Chief
Executive Officer and the four other most highly compensated executive officers
of the Company, and (iv) all directors and executive officers of the Company, as
a group. None of the directors or executive officers named below, as of March
15, 2003, owned any shares of the Company's Series A Preferred Stock or its 1996
Series A Convertible Preferred Stock. The business address of each officer and
director listed below is: c/o Magnum Hunter Resources, Inc., 600 East Las
Colinas Blvd., Suite 1100, Irving, Texas 75039.
COMMON STOCK
BENEFICIALLY OWNED
-----------------------------------
PERCENT
NAME NUMBER OF SHARES OF CLASS (m)
- ---------------------------------------------------------- ------------------- -------------
Directors and Executive Officers
Gary C. Evans ......................................... 3,541,303(a) 5%
Richard R. Frazier..................................... 366,290(b) *
Chris Tong............................................. 166,133(c) *
Charles R. Erwin....................................... 137,000(d) *
R. Douglas Cronk....................................... 99,000(e) *
Gerald W. Bolfing...................................... 524,152(f) *
Jerry Box ............................................. 58,335(g) *
James R. Latimer, III.................................. 4,204(h) *
Matthew C. Lutz........................................ 375,969(i) *
John H. Trescot, Jr.................................... 148,604(j) *
James E. Upfield 152,292(k) *
All directors and executive officers as a group
(13 persons).......................................... 5,659,282 8%
Beneficial owners of 5 percent or more
(excluding persons named above)
Natural Gas Partners V, L.P.
125 E. John Carpenter Freeway, Suite 600
Irving, TX 75062......................................... 13,317,052(l) 19%
- ------------
*Less than one percent.
(a) Includes 550,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 790,151 common
stock purchase warrants which are currently exercisable. Also includes
17,024 shares held in the name of Jacquelyn Evelyn Enterprises, Inc., a
corporation whose sole shareholder is Mr. Evans' wife. Mr. Evans
disclaims any ownership in such securities other than those in which he
has an economic interest.
(b) Includes 238,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 175 common stock
purchase warrants which are currently exercisable.
(c) Includes 116,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(d) Includes 137,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(e) Includes 89,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
Also includes 10,000 common stock purchase warrants which are currently
exercisable.
(f) Includes 25,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 151,142 common
stock purchase warrants which are currently exercisable.
(g) Includes 41,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. (h) Includes 2,000 shares of
common stock issuable upon the exercise of certain currently
exercisable options.
(i) Includes 248,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
Also includes 49,641 common stock purchase warrants which are currently
exercisable.
(j) Includes 21,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 4,833 shares held
in the name of Nancy J. Trescot, Mr. Trescot's wife.
(k) Includes 21,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 15,848 common
stock purchase warrants which are currently exercisable.
57
(l) Based on Schedule 13G filed by Natural Gas Partners V, L.P. on March
15, 2002.
(m) Percentage is calculated on the number of shares outstanding plus those
shares deemed outstanding under Rule 13d- 3(d)(1) under the Exchange
Act.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Our Board of Directors authorized a loan of up to $371,860 be made available to
Gary C. Evans, President and Chief Executive Officer, as part of his
compensation package. The balance outstanding at December 31, 1999, was $371,860
and bears interest at 10%. On January 7, 2000 Mr. Evans repaid $225,000 on the
loan, leaving a principal balance of $146,860. On April 17, 2000, Mr. Evans
re-borrowed $100,000 under this loan, and on August 18, 2000, he repaid
$258,731, including accrued interest, bringing the balance to zero. On December
28, 2000, Mr. Evans borrowed $294,938, which was the balance owed to the Company
on December 31, 2000 and included in notes receivable from affiliate. On January
15, 2001, Mr. Evans repaid $295,261, including accrued interest, bringing the
balance to zero. On April 16, 2001, Mr. Evans borrowed $300,000 pursuant to a
loan approved by the Company's Board of Directors for the payment of deferred
income taxes. Subsequent to December 31, 2001, Mr. Evans repaid the loan in
full, including accrued interest, bringing the balance to zero.
On November 28, 2000, Mr. Matthew C. Lutz, Chairman and Executive Vice
President, borrowed $65,000 with the approval of the Board of Directors. On
January 15, 2001, Mr. Lutz repaid the loan, including accrued interest.
During 1998, we acquired certain shares of a publicly traded oil and gas company
from Mr. Gary C. Evans at Mr. Evans' cost basis in such shares of stock. The
shares were purchased for a total of $442,019. We have the right through
December 31, 2002, to cause Mr. Evans to repurchase the shares back at the
equivalent price that the company purchased the shares from Mr. Evans. In
December 2002, Mr. Evans repurchased the shares for $442,019, bringing the
balance to zero.
There are no loans or extensions of credit to directors and executive officers
of Magnum Hunter as of December 31, 2002.
ITEM 14. CONTROLS AND PROCEDURES
Our chief executive officer and chief financial officer have reviewed and
evaluated the effectiveness of our disclosure controls and procedures [as
defined in Rules 240.13a-14(c) and 15(d)-14(c) promulgated under the Securities
Exchange Act of 1934] as of a date within ninety days before the filing of this
annual report. Based on that review and evaluation, which included inquiries
made to certain of our other employees, the chief executive officer and chief
financial officer have concluded that our current disclosure controls and
procedures, as designed and implemented, are reasonably adequate to ensure that
they are provided with material information relating to the company required to
be disclosed in the annual reports we file or submit under the Securities
Exchange Act of 1934. There have not been any significant changes in our
internal controls or in other factors that could significantly affect these
controls subsequent to the date of their evaluation. There were no significant
deficiencies or material weaknesses and, therefore, we took no corrective
actions.
58
GLOSSARY
As used in this document:
. "Mcf" means thousand cubic feet;
. "MMcf" means million cubic feet;
. "Bcf" means billion cubic feet;
. "Bbl" means barrel;
. "MBbls" means thousand barrels;
. "MMBbls" means million barrels;
. "BOE" means barrel of oil equivalent;
. "MMBOE" means million barrels of oil equivalent;
. "Btu" or "British Thermal Unit" means the quantity of heat required to
raise the temperature of one pound of water by one degree Fahrenheit;
. "MMBtu" means million British Thermal Units;
. "Mcfe" means thousand cubic feet of natural gas equivalent;
. "MMcfe" means million cubic feet of natural gas equivalent; and
. "Bcfe" means billion cubic feet of natural gas equivalent.
Natural gas equivalents and crude oil equivalents are determined using the ratio
of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids. All estimates of reserves, unless otherwise noted, are reported on a
"net" basis. Information regarding production, acreage and numbers of wells is
set forth on a gross basis, unless otherwise noted.
. "Proved reserves" means the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes
in existing prices provided only by contractual arrangements, but
not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility
is supported by either actual production or conclusive
formation test. The area of a reservoir considered proved
includes:
(A) that portion delineated by drilling and defined by
gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled,
but which can be reasonably judged as economically
productive on the basis of available geological and
engineering data. In the absence of information on
fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was
based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs
but is classified separately as "indicated
additional reserves";
(B) crude oil, natural gas, and natural gas liquids, the
recovery of which is subject to reasonable doubt
because of uncertainty as to geology, reservoir
characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids,
that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids,
that may be recovered from oil shales, coal,
gilsonite and other such sources.
. "PV-10" means the pre-tax present value of estimated future net
revenues computed by applying current prices of oil and gas
reserves (with consideration of price changes only to the extent
provided by contractual arrangements) to estimated future
production of proved oil and gas reserves, less estimated future
expenditures
59
(based on current costs) to be incurred in developing and
producing the proved reserves computed using a discount factor of
10% and assuming continuation of existing economic conditions.
. "Proved developed oil and gas reserves" means reserves that can
be expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
"proved developed reserves" only after testing by a pilot project
or after the operation of an installed program has confirmed
through production response that increased recovery will be
achieved.
. "Proved undeveloped reserves" means reserves that are expected to
be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for recompletion. Reserves on undrilled acreage shall be limited
to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
. "Reserve Life" is an estimate of the productive life of a proved
reservoir and for purposes of this document is calculated by
dividing the proved reserves (on an Mcfe basis) at the end of the
period by historical production volumes for the prior 12 months.
. "Standardized Measure of Discounted Future Net Cash Flows" means
PV-10 after income taxes.
60
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements
Independent Auditors' Report....................................................................F-1
Financial Statements:
Consolidated Balance Sheets at December 31, 2002 and 2001...............................F-2
Consolidated Statements of Operations and Comprehensive Income
for the Years Ended December 31, 2002, 2001 and 2000..............................F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2002, 2001 and 2000...................................F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2002, 2001 and 2000.........................................F-5
Notes to Consolidated Financial Statements......................................................F-6
Supplemental Information (Unaudited)...........................................................F-30
2. Financial Statement Schedule
We have included on page 64 of this Annual Report on Form 10-K Financial
Statement Schedule II, Valuation and Qualifying Accounts.
61
(a) Exhibits
Number Description of Exhibit
- -----------------------------
3.1 & 4.1 Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-18, File No. 33-
30298-D).
3.2 & 4.2 Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year
ended December 31, 1990).
3.3 & 4.3 Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on
Form SB-2, File No. 33-66190).
3.4 & 4.4 Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement on
Form S-3, File No. 333-30453).
3.5 & 4.5 Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year
ended December 31, 2001).
3.6 & 4.6 By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File No. 33-
66190).
3.7 & 4.7 Amendment to By-Laws (Incorporated by reference to Registration Statement on Form S-4, File No. 333-
76774).
3.8 & 4.8 Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated
December 26, 1996, filed January 3, 1997).
3.9 & 4.9 Amendment to Certificate of Designation for 1996 Series A Convertible Preferred Stock (Incorporated by
reference to Registration Statement on Form S-3,, File No. 333-30453).
4.10 Form of Warrant Agreement by and between Magnum Hunter Resources, Inc. and American Stock Transfer
& Trust Company, as warrant agent (Incorporated by reference to Registration Statement on Form S-3, File
No. 333-82552).
4.11 Form of Warrant Agreement by and between Midland Resources, Inc. and Stock Transfer Company of
America, Inc., as warrant agent, dated November 1, 1990 (Incorporated by reference to Registration
Statement on Form S-3, File No. 333-83376).
4.12 Form of Warrant Agreement by and between Vista Energy Resources, Inc. and American Stock Transfer &
Trust Company, as warrant agent, dated October 28, 1998 (Incorporated by reference to Registration
Statement on Form S-3, File No. 333-83376).
4.13 Indenture dated May 29, 1997 between Magnum Hunter Resources, Inc., the subsidiary guarantors named
therein and First Union National Bank of North Carolina, as Trustee (Incorporated by reference to
Registration Statement on Form S-4, File No. 333-2290).
4.14 Supplemental Indenture dated January 27, 1999 between Magnum
Hunter Resources, Inc., the subsidiary guarantors named therein
and First Union National Bank of North Carolina, as Trustee
(Incorporated by reference to Form 10-K for the fiscal year-end
December 31, 1998 filed April 14, 1999).
4.15 Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form S-4, File
No. 333-2290).
4.16 Indenture, dated March 15, 2002, between Magnum Hunter Resources, Inc., the subsidiary guarantors
named therein and Bankers Trust Company, as Trustee (Incorporated by reference to Form 10-K for the
year ended December 31, 2001).
4.17 Shareholder Rights Agreement dated as of January 6, 1998 by and
between Magnum Hunter Resources, Inc. And Securities Transfer
Corporation, as Rights Agent (Incorporated by reference to Form
8-K dated January 7, 1998, filed January 9, 1998).
10.1 Fourth Amended and Restated Credit Agreement, dated March 15, 2002, between Magnum Hunter
Resources, Inc. And Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the year
ended December 31, 2001).
10.2 Amendment to Fourth Amended and Restated Credit Agreement (Incorporated by reference to Form 10-Q
for the period ended September 30, 2002).
10.3 Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-K for the fiscal year-end
December 31, 1999, filed March 30, 2000).
10.4 Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-K for the fiscal year-
end December 31, 1999, filed March 30, 2000).
10.5* Employment Agreement for Chris Tong.
10.6* Employment Agreement for R. Douglas Cronk.
10.7* Employment Agreement for Charles Erwin.
10.8 Purchase and Sale Agreement, dated February 27, 1997 among Burlington Resources Oil and Gas
Company, Glacier Park Company and Magnum Hunter Production, Inc. (Incorporated by reference to Form
8-K, dated April 30, 1997, filed May 12, 1997).
62
10.9 Purchase and Sale Agreement between Magnum Hunter Resources, Inc.,
NGTS, et al, dated December 17, 1997 (Incorporated by reference to
Form 8-K, dated December 17, 1997, filed December 29, 1997).
10.10 Purchase and Sale Agreement dated November 25, 1998 between Magnum
Hunter Production, Inc. And Unocal Oil Company of California
(Incorporated by reference to Form 10-K for the fiscal year-end
December 31, 1998, filed April 14, 1999).
10.11 Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by reference
to Form 10-Q/A for the period ended June 30, 2000, filed November 30, 2000).
21 Subsidiaries of the Registrant (Incorporated by reference to Form 10-K for the period ended December 31,
2001.
23.1* Consent of Deloitte & Touche LLP
99.1* Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002 signed by Gary C. Evans
99.2* Certification pursuant to Section 906 of Sarbanes-Oxley Act of 2002 signed by Chris Tong
99.3* Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Gary C. Evans
99.4* Certification pursuant to Section 302 of Sarbanes-Oxley Act of 2002, signed by Chris Tong
*Filed herewith
63
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
Magnum Hunter Resources, Inc.
We have audited the consolidated financial statements of Magnum Hunter
Resources, Inc. and Subsidiaries (the "Company") as of December 31, 2002 and
2001, and for each of the three years in the period ended December 31, 2002, and
have issued our report thereon dated March 25, 2003; such consolidated financial
statements and report are included elsewhere in this Annual Report on Form 10-K.
Our audits also included the financial statement schedule of Magnum Hunter
Resources, Inc. and Subsidiaries, listed in Item 15. This financial statement
schedule is the responsibility of the Company's management. Our responsibility
is to express an opinion based on our audits. In our opinion, such financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 25, 2003
64
MAGNUM HUNTER RESOURCES, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 2002
(in thousands)
ADDITIONS
-----------------------------
BALANCE AT CHARGED TO BALANCE AT END
BEGINNING OF COSTS AND CHARGED TO OTHER OF
CLASSIFICATION YEAR EXPENSES ACCOUNTS (1) DEDUCTIONS (2) YEAR
- --------------------------------------------- ------------- ----------- ----------------- ---------------- ---------------
YEAR ENDED DECEMBER 31, 2002
Allowance for Doubtful Accounts on
Trade Accounts Receivable............. 3,264 206 1,103 4,573
Reserve on Current Portion of Long-term
Notes Receivable...................... 1,620 - 1,620
Reserve on Investment in
Unconsolidated Affiliate.............. 4,527 - 4,527
YEAR ENDED DECEMBER 31, 2001
Allowance for Doubtful Accounts on Trade
Accounts Receivable................... 50 3,214 - - 3,264
Reserve on Current Portion of Long-term
Notes Receivable..................... 1,170 450 - - 1,620
Reserve on Investment in
Marketable Securities................. - 2,142 (2,142) -
Reserve on Investment in
Unconsolidated Affiliate.............. - 4,527 - - 4,527
YEAR ENDED DECEMBER 31, 2000
Allowance for Doubtful Accounts on
Trade Accounts Receivable............. 166 80 (196) 50
Reserve on Current Portion of
Long-term Notes Receivable............ 790 384 (4) 1,170
- ----------
(1) Allowance acquired in Prize merger
(2) Write-offs
65
SIGNATURES
Pursuant to the requirements of the Section 13 or 15 (d) of the Securities and
Exchange Act of 1934, the Company has duly caused this Form 10-K to be signed on
its behalf by the undersigned, thereunto duly authorized.
MAGNUM HUNTER RESOURCES, INC.
By: /s/ Gary C. Evans March 28, 2003
---------------------------------------
Gary C. Evans, Chairman, President
and Chief Executive Officer
In accordance with the Exchange Act, this Form 10-K has been signed below by the
following persons on behalf of the Company and in the capacities and on the
dates indicated.
Signature Title Date
- --------------------------- --------------------------- --------------
/s/ Gary C. Evans Chairman, President and March 28, 2003
- --------------------------- Chief Executive Officer
Gary C. Evans
/s/ Chris Tong Senior Vice President and March 28, 2003
- --------------------------- Chief Financial Officer
Chris Tong
/s/ Morgan F. Johnston Sr. Vice President, General March 28, 2003
- --------------------------- Counsel and Secretary
Morgan F. Johnston
/s/ David S. Krueger Vice President and March 28, 2003
- --------------------------- Chief Accounting Officer
David S. Krueger
/s/ Gerald W. Bolfing Director March 28, 2003
- ---------------------------
Gerald W. Bolfing
/s/ Jerry Box Director March 28, 2003
- ---------------------------
Jerry Box
/s/ James R. Latimer, III Director March 28, 2003
- ---------------------------
James R. Latimer, III
/s/ Matthew C. Lutz Director March 28, 2003
- ---------------------------
Matthew C. Lutz
/s/ John H. Trescot, Jr. Director March 28, 2003
- ---------------------------
John H. Trescot, Jr.
/s/ James E. Upfield Director March 28, 2003
- ---------------------------
James E. Upfield
66