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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.