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, 2001
[ ] 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.
(Exact name of registrant as specified in its charter)
Nevada 87-0462881
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039
--------------------------------------------------------------
(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
------------------- -----------------------------------------
Common Stock ($.002 par value) American 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 disclosure 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. [ ]
As of March 15, 2002, the aggregate market value of voting stock held by
non-affiliates, computed by reference to the closing price as reported by the
American Stock Exchange, was $343,891,333.
The number of shares outstanding of the registrant's common stock at March
15, 2002 was 70,065,447.
TABLE OF CONTENTS
Securities and Exchange Commission
Item Number and Description
PART I
Item 1. Business...............................................................................................1
The Company...........................................................................................1
Business Strategy ....................................................................................3
Properties ...........................................................................................4
Development and Exploration Activities ...............................................................7
Gathering and Processing of Gas ......................................................................8
Marketing of Production ..............................................................................9
Petroleum Management and Consulting Services ........................................................10
Competition..........................................................................................10
Regulation ..........................................................................................10
Employees ...........................................................................................13
Facilities ..........................................................................................13
Risk Factors.........................................................................................14
Item 2. Description of Properties.............................................................................22
Oil and Gas Reserves ................................................................................22
Oil and Gas Production, Prices and Costs ............................................................25
Drilling Activity ...................................................................................26
Oil and Gas Wells ...................................................................................27
Oil and Gas Acreage .................................................................................27
Item 3. Legal Proceedings.....................................................................................28
Item 4. Submission of Matters to a Vote of Security Shareholders..............................................28
PART II
Item 5. Market for Common Equity and Related Stockholder Matters..............................................28
Item 6. Selected Financial Data...............................................................................29
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..............................................47
Item 8. Financial Statements and Supplementary Data...........................................................F-1
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.....................................................49
Item 11. Executive Compensation.................................................................................54
Item 12. Security Ownership of Certain Beneficial Owners and Management.........................................57
Item 13. Certain Relationships and Related Transactions.........................................................58
Glossary...............................................................................................59
Item 14. 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:
o benefits, effects or results of the merger with Prize Energy Corp.
("Prize);
o cost reductions, operating efficiencies or synergies and the integration
of operations in connection;
o with the merger with Prize;
o future stock market valuations;
o tax and accounting treatment of the merger and the warrants offering;
o repayment of debt;
o business strategies;
o expansion and growth of operations after the merger with Prize; and
o 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:
o general economic and business conditions;
o prices of crude oil, natural gas and natural gas liquids and industry
expectations about future prices;
o the business opportunities, or lack of opportunities, that may be
presented to and pursued by us;
o the ability to integrate our operations with Prize; and
o 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
Magnum Hunter Resources, Inc., a Nevada corporation ("Magnum Hunter" or the
"Company"), 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, the Permian
Basin and the Gulf of Mexico/Gulf Coast. Management of the Company has
implemented a business strategy that emphasizes acquisitions of long-lived
proved reserves with significant exploitation and development opportunities
where the Company generally could control the operations of the properties. As
part of this strategy, from 1996 through 2001, the Company 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"). In
addition to its focus on selected exploratory drilling prospects in the Gulf of
Mexico as described below, the Company intends to continue to concentrate its
efforts on additional producing property acquisitions strategically located
within its geographic area of operations. The Company also intends to continue
to develop its substantial inventory of drilling and workover opportunities
located onshore. The Company has identified over 358 development drilling
locations (including both production and injection wells) and workover
opportunities on its properties to which Proved reserves have been attributed,
substantially all of which are low-risk in-fill drilling opportunities.
In 1998, the Company 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 31, 2002, the Company owned approximately 36% of the units of beneficial
ownership in TEL.
Additionally, the Company owns over 480 miles of gas gathering systems and
a 50% or greater ownership interest in three natural gas processing plants that
are located adjacent to certain Company-owned and operated producing properties
located in the states of Texas, Oklahoma and Arkansas.
At December 31, 2001, the Company had an interest in 3,241 wells and had
estimated Proved reserves of 378 Bcfe with a PV-10 of $311.9 million.
Approximately70% of these reserves were Proved developed reserves: 31% were
attributable to the Mid-Continent Region, 33% were attributable to the Permian
Basin, and 36% were attributable to the Gulf of Mexico/Gulf Coast region. At
December 31, 2001, the Company's Proved reserves had an estimated Reserve Life
of approximately 11.3 years and were 66% natural gas. The Company serves as
operator for approximately 70% of its properties, based on the gross number of
producing wells in which the Company owns an interest and 75% of its properties,
based upon the year-end PV-10 value.
As a result of its property acquisitions and successful drilling activities
during 2001, the Company has achieved growth as described below:
o Proved reserves increased 3% to 378 Bcfe at year- end 2001 from 367 Bcfe
at year-end 2000; and
o Average daily production increased 22% to 91,292 MMcfe during fiscal 2001
from 74,777 MMcfe in fiscal 2000. The Company had an exit rate of approximately
100 MMcfe at year-end 2001.
Recent Activities
Merger with Prize Energy Corp. 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.
The merger resulted in an exchange of 2.5 shares of Magnum Hunter common
stock and $5.20 in cash for each share of Prize common stock, with the
stockholders of Prize becoming stockholders of Magnum Hunter. As a result of the
merger, we became owned approximately 52% by our then current stockholders and
48% by the former stockholders of Prize, without taking into account subsequent
stock sales and the options and warrants that remained outstanding at the time
of the merger.
In connection with our merger with Prize, we issued $300 million of 9.6%
unsecured senior notes due 2012 and established a new senior bank credit
facility with a borrowing base of $300 million secured by the assets of the
combined company. Proceeds from the senior notes offering and initial borrowings
under the new senior bank credit facility were used to refinance the outstanding
indebtedness under the existing senior bank 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.
Magnum Hunter Warrants Offering.
We have distributed to our stockholders of record on January 10, 2002,
warrants to purchase 7,228,457 shares of our common stock at an exercise price
of $15.00 per share and expiring three years from the date of distribution. The
warrant distribution occurred on or about March 21, 2002 and the warrants are
traded on the American Stock Exchange. The stockholders and warrantholders of
Prize did not receive any of these warrants in the merger or otherwise.
2
Recent Commodity Hedging Transactions. Periodically, we enter into
commodity price hedging transactions to reduce the effects of fluctuations in
crude oil and natural gas prices. At March 31, 2002, Magnum Hunter had 72% of
its natural gas production and 69% of its crude oil production hedged through
December 31, 2002. None of these hedges were with Enron, which recently filed
for bankruptcy.
Business Strategy
Our overall strategy is to increase our reserves, production, cash flow and
earnings utilizing a properly balanced program of:
o selective exploration;
o the exploitation and development of acquired properties; and
o strategic acquisitions of additional proved reserves.
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 shorter-lived, higher output production to our reserve
mix. The continued use of 3-D seismic information as a tool in our exploratory
drilling in the Gulf of Mexico will be significant. We have recently 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.
As a result of the merger with Prize, we now have a substantial inventory
of over 1,000 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 75% 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 its net operating margin.
3
Expansion of Gas Gathering and Processing Operations. We have implemented
several programs to expand and increase the efficiency of our gas gathering
systems and gas processing plants. We will consider opportunities to acquire or
develop additional gas gathering and processing facilities that are primarily
associated with our current production.
Properties
The Company's major properties are located in three core areas: (i) the
Mid-Continent Region, (ii) the Permian Basin and (iii) the Gulf of Mexico/Gulf
Coast.
Mid-Continent Region
The Company's properties located in the Mid-Continent region were acquired
principally from Burlington, Spirit 76 and Vastar. The Company has received an
engineering evaluation from DeGolyer and MacNaughton ("D&M") and Cawley
Gillespie & Associates, Inc. ("Cawley Gillespie"), independent petroleum
engineers engaged by the Company to evaluate the Company's properties, on the
net reserves in the Mid-Continent Region. According to D&M and Cawley Gillespie,
as of December 31, 2001, the Mid-Continent properties had Proved reserves of
5.147 MMBbl of oil and 109.556 Bcf of natural gas, or on a Natural Gas
Equivalent basis, 140.44 Bcfe. D&M and Cawley Gillespie further estimated the
PV-10 for the Mid-Continent properties to be $97.011 million as of December 31,
2001. The Proved reserves are located principally in the Ardmore Basin in south
central Oklahoma, in the Oklahoma/Texas panhandle and in Southwestern Arkansas.
Approximately 78% of the estimated reserves are natural gas and 22% are oil
located on approximately 235,083 net mineral leasehold acres in twelve counties
in Oklahoma, five counties in Texas and two counties in Arkansas. Total net
daily production from the Mid-Continent properties for the month of December
2001 was approximately 24.2 million cubic feet of natural gas production and 944
barrels of oil. The Company's wholly-owned subsidiary, Gruy Petroleum Management
Co., is the operator of approximately 89% of the wells located in the
Mid-Continent region.
The major fields in the Mid-Continent Region are the Panoma, Cumberland,
Walnut Bend and Madill.
Panoma. The Panoma Properties currently consist of approximately 599
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 2001, net production natural gas sales were approximately
9.5 MMcf/d, which excludes liquids processed from this natural gas stream
through the Company's gas processing facility located adjacent to these fields,
known as the McLean Plant.
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. The
Company has an interest in a total of 120 wells, with working interests varying
from 17% to 100%. The Company operates all but nine of these wells. For the
month of December 2001, gross production from the field averaged 5,720 Mcf/d and
183 Bbl/d (or 3,955 Mcf/d and 127 Bbl/d net to the Company). December 2001
production was reduced due to a nine day pipeline shutdown owned and operated by
a third party.
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 104 active producing wells and 34
active injection wells. The Company's working interest ownership in the wells is
approximately 93%. For the month of December 2001, gross production from the
wells averaged 170 Mcf/d and 756 Bbl/d (or 140 Mcf/d and 617 Bbl/d net to the
Company).
4
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
59 active producing wells. The Company's working interest ownership in the wells
varies from 41% to 100%. For the month of December 2001, gross production from
the wells averaged 1,393 Mcf/d and 67 Bbl/d (or 948 Mcf/d and 46 Bbl/d net to
the Company). December 2001 production was reduced due to a nine day pipeline
shutdown owned and operated by a third party.
Permian Basin
The Company owns certain oil and gas properties consisting of 25 field
areas in west Texas and 22 field areas in southeast New Mexico (the "Permian
Basin Properties"). The primary producing formations include the Yates, Seven
Rivers and Queen in Lea and Eddy Counties, New Mexico; the Atoka in the Brunson
Ranch Field in Loving County, Texas; the Clearfork in the Westbrook Field in
Mitchell County, Texas; and the San Andres in the Levelland/Slaughter Field in
Cochran County, Texas. The Permian Basin Properties include 1,574 producing oil
and gas wells on approximately 134,212 net acres. One of the Company's
subsidiaries, Gruy, serves as operator on approximately 53% of the wells on the
Permian Basin Properties. Management believes the Permian Basin Properties will
continue to provide significant opportunities for exploitation and development
opportunities of both oil and gas through workovers and recompletions, enhanced
recovery projects and in-fill drilling. For example, the Company has identified
more than 102 possible sites in the Westbrook Field (4.1 MMBbl of Proved
reserves) and opportunities for tertiary recovery using carbon dioxide injection
in the Levelland-Slaughter Field (1.5 MMBbl of Proved reserves).
According to D&M and Cawley Gillespie, as of December 31, 2001, the Permian
Basin Properties had Proved reserves of 12.635 MMBbl of oil and 77.9 Bcf of gas,
or on a Natural Gas Equivalent basis, 153.72 Bcfe. D&M and Cawley Gillespie
further estimated the PV-10 for the Permian Basin Properties to be $102.78
million as of December 31, 2001.
The major fields in the Permian Basin are the Westbrook,
Levelland/Slaughter and Southeast New Mexico.
Westbrook. The Westbrook Field covers 45 square miles of the Permian Basin
in Mitchell County, Texas and produces from the Clearfork formation at a depth
of approximately 3,200 feet. The Company owns three principal properties in the
Westbrook Field, being the Southwest Westbrook Unit, the Morrison "G" Lease and
the North Westbrook Unit. There are currently 284 active producing wells. The
Company's working interest ownership in the wells varies from 0.02% to 100%. For
the month of December 2001, gross production from the wells averaged 1,212
Bbl/d.
Most of the leases and units in the field had waterflood projects initiated
in the 1960's and those projects are still active. The Company has continued
waterflood enhancement operations on the Southwest Westbrook Unit and the
Morrison "G" Lease in 2001.
Levelland/Slaughter. The Levelland and Slaughter Fields consist of 164wells
located in Cochran County, Texas that produce from the San Andres formation at a
depth of 5,000 feet. The Company owns five principal properties in the Levelland
and Slaughter Fields, being the TLB Unit, the Veal Lease, the NW Slaughter Unit,
the Starnes Lease and the Magnum Levelland Unit. There are currently 93 active
producing wells. The Company's working interest ownership in the wells varies
from 6% to 100%. For the month of December 2001, gross production from the wells
averaged 306 Mcf/d and 513 Bbl/d (or 84 Mcf/d and 266 Bbl/d net to the Company).
Discovered in the 1930's, all five properties have been actively
waterflooded since the 1970's. While the projects are mature, additional
drilling and waterflood enhancement opportunities are available. No Proved
undeveloped reserves were assigned by D&M to either the TLB Unit or the Veal
Lease. Proved undeveloped reserves were assigned by D&M to the NW Slaughter Unit
in contemplation of a carbon dioxide injection project which is planned in the
future for that property. The operator of an adjacent property has been
injecting carbon dioxide for a number of years and has enhanced production.
5
Southeast New Mexico Properties. The Southeast New Mexico Properties
consist of approximately 410 wells in Lea and Eddy Counties, New Mexico. The Lea
County properties include the Rhodes, Jalmat, Monument, Langlie Mattix, Eumont
and Eunice Fields. The fields produce from the Yates, Seven Rivers, Queen and
other formations at depths generally shallower than 3,000 feet. Additionally,
the Company owns interests in approximately 33 wells that produce from the
Morrow formation in Eddy County, New Mexico where an increased density program
is ongoing. The Morrow formation is found at approximately 11,500 feet. We
participated in the drilling of 7 wells in 2001 and have budgeted to drill an
additional 20 wells in 2002. For the Southeast New Mexico properties,
approximately 37 proved undeveloped locations have been identified by the
Company's third-party petroleum engineering consultants.
Gulf of Mexico/Gulf Coast
The Company owns properties both offshore Gulf of Mexico and onshore Gulf
Coast.
The Company has received an engineering evaluation from DeGolyer and
MacNaughton on the net reserves in the Gulf of Mexico/Gulf Coast. According to
D&M, as of December 31, 2001, the Gulf of Mexico/Gulf Coast properties had
Proved reserves of 3.818 MMBbl of oil and 61.016 Bcf of natural gas, or on a
Natural Gas Equivalent basis, 83.93 Bcfe. D&M further estimated the PV-10 for
the Gulf of Mexico properties to be $112.074 million as of December 31, 2001.
Approximately 73% of the estimated reserves are natural gas and 27% are oil
located on approximately 170,250 net mineral leasehold acres. Total net daily
production from the Gulf of Mexico properties for the month of December 2001 was
approximately 23.2 million cubic feet of natural gas production and 1,569
barrels of oil.
Offshore Gulf of Mexico. On March 27, 1998, the Company acquired
approximately 40% beneficial ownership interest in TEL Offshore Trust, a trust
created under the laws of the state of Texas pursuant to a cash tender offer for
an aggregate purchase price of approximately $10.4 million. 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. As of
March 31, 2002, the Company owned approximately 36% of the units of beneficial
ownership in TEL. TEL produced a total of approximately .52 Bcfe in calendar
2001 net to the Company and the Company received distributions from the
partnership totaling $2.8 million during 2001.
The Company entered the Gulf of Mexico as a working interest participant in
new exploratory drilling on the shallow water shelf in May 1999. By the end of
2001, this program achieved a result of 34 completed wells in 39 attempts.
Proved reserves have been assigned in 26 offshore blocks representing the
discoveries. Seventeen of these successes are producing approximately 40 million
cubic feet of natural gas equivalent per day net to the Company as of the end of
March 2002. Seven additional new discoveries are scheduled to commence
production during the remainder of 2002 and will add substantially to existing
daily net production rates. The Company currently owns an interest in 87 blocks
in the Gulf of Mexico ranging from 12.5% to 100% and will add to this lease
inventory as the Company was the high bidder on 41 additional lease blocks at
the March 2002 offshore lease sale. The Company plans to participate in ten new
exploratory offshore drilling projects in 2002. Over 470 blocks of 3-D seismic
coverage are providing the basis for new prospect generation internally.
Additionally, alliances with other offshore operators provides access to
additional high- quality drilling opportunities.
Onshore Gulf Coast. Other onshore Gulf Coast properties are located in the
Mossy Grove prospect in Walker County, Texas, the Giddings Field, the First Shot
Field and the Clinton Field. Other than the Clinton Field, which produces from a
vertical well, these properties are typically producing from horizontal legs of
vertical wells in these fields.
Gas Processing Plants
McLean Plant. In January 1997, the Company complemented its 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 million cubic feet per day. For the
month of December 2001, throughput of the plant averaged 14,725 million cubic
feet per day with processed liquids of 895 barrels per day.
6
Madill Plant. In December 1999, the Company 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 the Company's 50%
partner, Carrera Gas Gathering Co., L.L.C., of Tulsa, Oklahoma who subsequently
paid 50% of the purchase price. The acquisition includes over 130 miles of gas
gathering pipelines. This modern cryogenic plant has3,350 horsepower of high
speed compression and has gas processing capacity of approximately 18 million
cubic feet per day. For the month of December 2001, throughput of the plant
averaged 10.7 million cubic feet per day of natural gas with processed liquids
of 480 barrels per day.
Walker Creek Plant. In conjunction with the Vastar acquisition, the Company
acquired an approximate 59% ownership interest and became the operator of the
Walker Creek Plant and associated gathering system. In 2000, the Company sold a
44.2% interest in the Walker Creek Plant to Mallard Hunter L.P. 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 processing capacity of 12 million cubic feet per day. For the month of
December 2001, throughput of the plant averaged 6,320 MMcf/d with processed
liquids of 310 Bbl/d.
Development and Exploration Activities
Overview
The Company presently intends to continue to focus its efforts on
exploration, property acquisitions and its substantial inventory of exploitation
and development drilling projects.
The Company seeks to minimize its overhead and capital expenditures by
subcontracting the drilling, redrilling and workover of wells to independent
drilling contractors and by outsourcing other services. The Company typically
compensates its drilling subcontractors on a turnkey (fixed price), footage or
day-rate basis depending on the Company's assessment of risk and cost
considerations on each individual project.
Development Drilling
The Company's development strategy focuses on maximizing the value and
productivity of its oil and gas asset base through development drilling and
enhanced recovery projects. The Company has budgeted approximately $55 million
for exploitation and development activities for 2002 with $26 million of such
budget allocated to the Company's proved undeveloped reserves. The Company has
identified 358 development drilling locations (including both production and
injection wells) and workover opportunities on its properties to which Proved
reserves have been attributed. In exploiting its producing properties, the
Company relies upon its in-house technical staff of petroleum engineering and
geological professionals and utilizes the services of outside consultants on a
selective basis.
Mid-Continent Region. The Company believes 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 develop drilling will bring the spacing down to a more
efficient 160 acres per well.
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. The Company has 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 2002.
7
Additional Mid-Continent development drilling, recompletion activities and
improvements to existing waterflood operations will focus on the Walnut Bend
Field in Cooke County, Texas and the Madill Field in Marshall County, Oklahoma.
Permian Basin Properties. In evaluating the Permian Basin Properties, the
Company has identified over 180 drilling locations including production and
injection wells. Primary development focus will be on the 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 ten
new wells are scheduled to be drilled in the Westbrook Field in 2002.
Exploratory Drilling
The Company spent $ 37.7 million of its $154.8 million 2001 capital budget
on exploratory drilling and related land and geophysical costs. Fifteen offshore
exploratory wells were drilled in 2001 of which 13 were completed as producing
wells providing the Company with a 87% success rate. The most significant change
in strategy occurred when the Company entered the Gulf of Mexico as a working
interest owner in new exploratory drilling on the shallow water shelf in May
1999. This new program yielded 34 completions in 39 attempts by the end of 2001
and as the Proved reserves associated with these new wells are developed, they
are projected to add significant cash flow. Production from its 17 offshore
blocks was approximately 40 MMcfe/d net to the Company as of the end of March
2002. Six new platforms scheduled to commence production in 2002 should add
substantially to these levels. The Company owns an interest ranging from 12.5%
to 100% in 87 offshore blocks and expects to add significantly to the number of
OCS blocks in 2002 as the Company was the high bidder on 41 additional blocks in
the March 2002 lease sale. An aggressive drilling program will continue in 2002.
The onshore exploration program remains active. Drilling in New Mexico in
2001 and early 2002 has resulted in seven new Morrow gas wells with working
interests ranging from 12.5% to 100%. Per well production has ranged from one
million to five million cubic feet of natural gas 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.
In West Texas, 13 consecutive producing wells have been drilled during the
past year in the Goldsmith Area. Occidental Petroleum Corporation is the
operator and the Company owns a 25% - 35% working interest in a 30,000 acre area
of mutual interest. The latest well tested over 500 Bbl/d (100 Bbl/d net to the
Company). Twenty two proved undeveloped locations remain to be drilled and over
65 drill sites are identified as a result of activity in the Goldsmith Area.
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 three gas processing plants. Gruy operates
all of the gas gathering systems and one 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 its gas gathering systems, the Company has emphasized operating
efficiency and overhead management and introduced a program which ties
throughput costs to volume transported rather than to compression capacity. The
Company believes that its 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.
8
The Panoma system, the largest of the Company's gas gathering systems,
consists of approximately 446 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, 2001,
gas throughput for the Panoma gas gathering system was approximately 15,618 MMcf
per day. 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. The Company, which operates approximately 599 of the approximately 645
wells connected to the Panoma system, is also actively seeking to add new wells
to such system through acquisition, development or arrangements with third party
producers.
Effective January 1997, the Company purchased a 50% ownership interest in
the McLean Gas Plant, a gas processing facility located adjacent to the
Company's Panoma 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 per day. For the month of December 2001,
throughput was approximately 14,725 MMcf per day with processed liquids of 895
barrels per day. The Company acquired its 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 behalf of the Company.
In December 1999, the Company 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 the Company's 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 million cubic feet per day. For the
month of December 2001, throughput of the plant was approximately 10,730 MMcf
per day of natural gas with processed liquids of 480 barrels per day.
In conjunction with the Vastar acquisition, the Company acquired
approximately 59% ownership interest and became the operator of the Walker Creek
Plant and associated gathering system. In 2000, the Company sold a 44.2%
interest in the Walker Creek Plant to Mallard Hunter L.P. 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 million cubic feet per day. For the month of December
2001, throughput of the plant was approximately 6,320 MMcf/d with processed
liquids of 310 Bbl/d.
Marketing of Production
The Company markets all of its gas production as well as gas it purchases
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 its
own account exposes the Company to the attendant commodities risk which the
Company attempts to mitigate through various financial hedges. The Company
normally sells its own oil under month-to-month contracts with a variety of
crude oil purchasers. Oil is usually sold for the Company's own account through
the services of Enmark Services, a marketing agent in Dallas, Texas. While the
Company has historically been able to sell oil above posted prices, it is also
exposed to the commodities risk inherent in short-term contracts which the
Company attempts to mitigate through various financial hedges. For a discussion
of the Company's hedging activities, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Liquidity and Capital
Resources - Hedging Activity" and Note 13 to the Company's Consolidated
Financial Statements.
In December 1997, Hunter Gas Gathering, Inc. acquired a thirty percent
(30%) membership interest in NGTS, LLC, 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, 2001, NGTS marketed approximately 26% of the Company's natural gas
under short term contracts. The balance of the Company's
9
production is marketed through other marketing companies or
gatherer/processors.
The market for oil and natural gas produced by the Company depends on
factors beyond its 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
The Company acquired Gruy in December 1995. Gruy, which conducts operations
for both the Company 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 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 the
Company's 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 the Company's business segments, see Note 16
to the Company's consolidated financial statements.
Competition
The oil and gas industry is highly competitive. Competitors of the Company
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, the Company frequently encounters competition in the acquisition of
oil and gas properties and gas gathering systems, and in its 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 the Company's 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.
Regulation
General Federal and State Regulation
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. The Company cannot predict the impact of these or future
legislative or regulatory initiatives.
Regulation of Natural Gas and Oil Exploration and Production
The Company's 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
10
operations. The Company's 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 the Company can produce from its
wells and may limit the number of wells or the locations at which the Company
can drill. The regulatory burden on the oil and gas industry increases the
Company's costs of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently expanded, amended and
reinterpreted, the Company is 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 natural gas, NGLs, crude oil or condensate by the Company.
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 regulatory
bodies and the courts. The Company cannot predict when or if any such proposals
might become effective and their effect, if any, on the Company's 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. Federal, State or Indian Leases The Company's 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
The Company's exploration, development, and production of oil and gas,
including its 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. The Company's 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. The Company also is subject to
regulations governing the handling, transportation, storage, and disposal of
naturally occurring radioactive materials that are found in its 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.
11
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, the
Company's 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. The Company generates 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 the Company's
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 the Company's properties by previous
owners and operators, materials from these operations remain on some of the
properties and in some instances require remediation. In addition, in certain
instances the Company has agreed to indemnify sellers of producing properties
from whom the Company has acquired reserves against certain liabilities for
environmental claims associated with such properties. While the Company does not
believe that costs to be incurred by the Company 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 the Company's routine oil and gas
operations, surface spills and leaks, including casing leaks, of oil or other
materials occur, and the Company incurs costs for waste handling and
environmental compliance. Moreover, the Company is able to control directly the
operations of only those wells for which it acts as the operator. Management
believes that the Company is in substantial compliance with applicable
environmental laws and regulations.
It is not anticipated that the Company will be required in the near future
to expend amounts that are material in relation to its total capital
expenditures program by reason of environmental laws and regulations, but
inasmuch as such laws and regulations are frequently changed, the Company is
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 the Company will not otherwise incur material expenses in
connection with environmental laws and regulations in the future.
12
Employees
At December 31, 2001, the Company had 105 full-time employees of which 13
were management, 36 were administrative and 56 were field personnel. None of the
Company's employees are represented by a union. Management considers its
relations with employees to be good.
Facilities
The Company 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 October 2004. The Company owns field offices and production yards in
Shamrock and Gainesville, Texas, Cumberland, Oklahoma and Taylor, Arkansas. The
Company also leases field production offices in Midland and Abilene, Texas,
Hobbs, New Mexico and Oklahoma City and Madill, Oklahoma.
13
RISK FACTORS
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%
unsecured 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 consideration in the merger with Prize and pay costs and fees
associated with the merger. As a result of the merger, the combination of our
outstanding 10.00% 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 $634.9 million as of March 31, 2002. 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 outstanding issues 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 additional
financing on an unsecured basis, or to obtain secured financing other than
"purchase money" indebtedness collateralized by the acquired assets.
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. The Company's oil and natural gas capital expenditures for the year
2002 are budgeted at $115 million, which the Company intends to use for
enhancement, exploitation and exploration 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 and timing 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:
o incur additional debt;
o make restricted payments (including paying dividends on, redeeming or
repurchasing our capital stock);
o make certain investments or acquisitions;
14
o grant liens on assets;
o sell our assets;
o engage in transactions with affiliates; and
o 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 senior bank credit facility, together
with unpaid accrued interest, to be immediately due and payable and to terminate
all commitments under the new senior bank credit facility.
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, including the properties we acquired in the merger with Prize,
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:
o relatively minor changes in the supply of, and demand for, oil and gas;
o market uncertainty both domestically and worldwide; and
o 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 natural 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.
15
At December 31, 2000, NYMEX prices were $26.80 per Bbl for oil and $9.78
per Mcf for gas. At December 31, 2001, NYMEX prices were $19.78 per Bbl for oil,
a decline of 26% from year-end 2000, and $2.72 per Mcf for gas, a decline of 72%
from year-end 2000. Our capitalized costs exceeded the PV-10 limitation
utilizing commodity prices in effect at December 31, 2001 under the full cost
method of accounting. However, no writedown for impairment of our oil and gas
properties is required, due to higher oil and gas prices that have been recorded
in the market subsequent to December 31, 2001.
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, 2001. 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:
o the timing of both production and related expenses;
o changes in consumption levels; and
o 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.
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 due to natural depletion. 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.
16
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 complete 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 time 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
naturally 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 injection wells and the spacing of both producing and injection
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 31, 2002,
Magnum Hunter had 72% of its natural gas production and 69% of its crude oil
production hedged through December 31, 2002. The hedging activities of the
combined 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 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,
17
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 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.
18
RISKS ASSOCIATED WITH OUR MERGER WITH PRIZE
We may not achieve the expected benefits of the merger.
The merger was intended to achieve specific goals. The likelihood of
achieving those goals represented the subjective judgment of our senior
management and board of directors. Some of those goals may not be achieved or,
if achieved, may not be achieved in the time frame in which they were expected.
Whether the combined company will actually realize these anticipated benefits
depends on future events and circumstances beyond the control of the combined
company, including the following:
o A decline in economic conditions in general or in the oil and gas
industry in particular could cause our combined company to fail to meet the
expectations of our board of directors for revenue, earnings and cash flow.
o Differing opinions of securities analysts and investors regarding the
prospects for our combined company's business and our future financial condition
could reduce the likelihood that our combined company will enjoy the hoped-for
increase in stock market valuation multiples relative to the stock market
valuation multiples of smaller competitors.
o The other risk factors discussed below may prevent the achievement of the
believed advantages of the merger.
Because of these and other factors, it is possible that our combined
company will not realize some or all of the expected benefits of the merger.
We may face difficulties in integrating the operations of Magnum Hunter
and Prize.
Before the merger, Magnum Hunter and Prize operated separately. Magnum
Hunter's management team has no experience in running the combined business. We
may not be able to integrate all of the operations of Magnum Hunter and Prize
within the time frame anticipated and without an unexpected loss of key
employees, customers or suppliers, a loss of revenues, an increase in operating
or other costs or other difficulties. In addition, we may not be able to realize
all of the operating efficiencies, synergies, cost savings or other benefits
originally anticipated from the merger. Any unexpected costs or delays incurred
in connection with the integration could have an adverse effect on our business,
results of operations or financial condition.
As a result of the merger with Prize, our risk profile is different from that of
Magnum Hunter and Prize before the merger.
We were relatively more active in onshore exploration and in offshore
exploration and production than Prize, which did not engage in these activities.
As a result, the combined company will have a different risk profile than either
company had before the merger.
The combined company's oil and gas business involves a variety of operating
risks, including unexpected formations or pressures, uncontrollable flows of
oil, gas, brine or well fluids into the environment (including groundwater
contamination), blowouts, fires, explosions, pollution, marine hazards and other
risks, any of which could cause personal injuries, loss of life, damage to
properties and substantial losses. Although we carry, and will continue to carry
insurance at levels that we believe are reasonable, we will not be fully insured
against all risks. We will not carry business interruption insurance except on
rare occasions. Losses and liabilities arising from uninsured or under-insured
events could materially affect the combined company's financial condition and
operations.
19
The price of our common stock may decline as a result of the merger with Prize.
The number of issued shares of Magnum Hunter common stock increased
substantially as a result of the merger with Prize, from 35,972,484 shares on
March 1, 2002 to 70,065,447 shares as of March 15, 2002. If holders of a
significant number of these new shares elect not to retain their shares, the
market price of our common stock may vary sharply or decline for reasons
unrelated to the financial performance of the combined company.
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 35% of our outstanding stock as of March 15, 2002.
In addition, we will have a significant number of shares that are freely
transferable without restriction. We had approximately 70,065,447 shares of
common stock issued and outstanding as of March 15, 2002. 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.
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 resale 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.
20
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., one of the Selling
Stockholders, 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.
21
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 the Company's 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 the Company's interests at December 31, 2001 (using oil and gas
prices in effect at December 31, 2001),
(b) Ryder Scott Company of Houston, Texas, DeGolyer and MacNaughton and
Cawley Gillespie & Associates, Inc., all independent petroleum engineers with
respect to the Company's interests at December 31, 2000 (using oil and gas
prices in effect at December 31, 2000), and
(c) Ryder Scott Company and Pollard, Gore and Harrison of Austin, Texas,
both independent petroleum engineers with respect to the Company's interests at
December 31, 1999 (using oil and gas prices in effect at December 31, 1999).
The estimates of these independent petroleum engineers were based upon
their review of production histories and other geological, economic, ownership
and engineering data provided by the Company.
PV-10 is the present value of Proved reserves which is an estimate of the
discounted future net cash flows from each of the Company's properties at
December 31, 2001, or as otherwise indicated. Net cash flow is defined as net
revenues less, 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, as of December 31, 2001, 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. The
Company's 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,
-----------------------------------------------------
2001 2000 1999
-----------------------------------------------------
Gas (per Mcf)...... $2.53 $9.28 $2.25
Oil (per Bbl)...... $17.19 $25.59 $24.03
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 the
Consolidated Financial Statements of the Company, 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.
22
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 the Company's Proved reserves since December 31,
2001. 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.
23
Company Reserves
The following tables set forth the estimated Proved reserves of oil and gas
of the Company and the PV-10 thereof on an actual basis at December 31, 2001,
2000 and 1999.
Estimated Proved Oil and Natural Gas Reserves (a)
At December 31,
--------------------------------------------
2001 2000 1999
--------------------------------------------
Net gas reserves (Mcf):
Proved developed............... 188,413,106 179,697,015 184,954,732
Proved undeveloped............. 60,066,682 53,511,550 45,044,794
--------------------------------------------
Total proved gas reserves.... 248,479,788 233,208,565 229,999,526
============================================
Net oil reserves (Bbl):
(including condensate and NGL)
Proved developed............... 12,959,569 13,923,380 16,299,585
Proved undeveloped............. 8,641,555 8,380,082 9,234,165
--------------------------------------------
Total proved oil reserves.... 21,601,124 22,303,462 25,533,750
============================================
Total Proved Reserves (Mcfe)........ 378,086,532 367,029,337 383,202,026
============================================
Estimated PV-10 of Proved Reserves (a)
At December 31,
-----------------------------------------------
2001 2000 1999
-----------------------------------------------
Estimated PV-10 (b) :
Proved developed............. $ 264,930,820 $ 829,688,640 $ 282,481,193
Proved undeveloped .......... 46,939,305 269,843,116 87,609,991
-----------------------------------------------
Proved Reserves PV-10 (c).. $ 311,870,125 $1,099,526,756 $ 370,091,184
===============================================
------------ (a) Based upon reserve reports at December 31, 2001 prepared
by D&M and, Cawley Gillespie, at December 31, 2000 prepared by Ryder Scott, D&M
and Cawley Gillespie and at December 31, 1999 prepared by Ryder Scott and PG&H.
(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, 2001, 2000 and 1999, respectively,
were as follows: $305,693,000, $804,923,000 and $315,616,000.
24
Significant Properties
On December 31, 2001, 100% of the Company's Proved reserves on a Bcfe basis
were located in the Mid- Continent Area, the Permian Basin Region and the Gulf
of Mexico/Gulf Coast. On such date, the Company's properties included working
interests in 3,241 gross (1,835 net) productive oil and gas wells.
The following table sets forth summary information with respect to the
Company's estimated Proved reserves of oil and gas at December 31, 2001.
PV-10 (a) Proved Reserves
------------------------------------------------------------------------------
Natural Gas
Amount % of Oil Gas Equivalent
(in thousands) Total (Bbl) (Mcf) (Bcfe)
-------------------------------------------- --------------- ---------------
Mid-Continent Area (b)............... $ 97,011 31% 5,147,280 109,556,265 140.44
Permian Basin Region (b)............. 102,785 33% 12,635,526 77,907,306 153.72
Gulf Coast/Gulf of Mexico (b) ....... 112,074 36% 3,818,318 61,016,217 83.93
------------------------------------------------------------------------------
Total ........................ $ 311,870 100% 21,601,124 248,479,788 378.09
------------------------------------------------------------------------------
- ----------
(a) 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.
(b) Based on reserve reports at December 31, 2001 prepared by D&M and
Cawley Gillespie.
Oil and Gas Production, Prices and Costs
The following table shows the approximate net production attributable to
the Company's oil and gas interests, the average sales price and the average
production expense attributable to the Company's 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,
2001 2000 1999
--------------------------------------------------------
Oil and gas production:
Oil (Mbbl)...................................... 1,410 1,298 1,307
Gas (MMcf)...................................... 24,861 19,579 19,026
Natural Gas Equivalents (MMcfe)................. 33,322 27,368 26,868
Average sales price (a):
Before Hedge Contracts:
Oil (per Bbl)................................ $ 23.64 $ 28.91 $ 17.55
Gas (per Mcf)................................ 3.82 4.08 2.16
Natural Gas Equivalents (per Mcfe)........... 4.13 4.28 2.38
After Hedge Contracts:
Oil (per Bbl)................................ $ 24.53 $ 22.95 $ 15.01
Gas (per Mcf)................................ 3.96 3.90 2.16
Natural Gas Equivalents (per Mcfe)........... 3.99 3.88 2.26
Oil and gas production lifting costs (per Mcfe) .. $ 0.61 $ 0 .60 $ 0.57
Production taxes and other costs (per Mcfe) (b)... $ 0.39 $ 0 .46 $ 0.30
- ----------
(a) Before deduction of production taxes and net of hedging results.
(b) Includes ad valorem taxes, insurance, bonds, company overhead and net
profits interest.
25
Drilling Activity
The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 2001, 2000 and 1999.
Gross Wells (a) Net Wells (b)
Year Type of Well Total Producing (c) Dry (d) Total Producing (c) Dry (d)
---- ------------ ----- ------------- ------- ----- ------------- -------
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 4.31 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 6.12 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
1999 Exploratory
Texas 6 5 1 2.77 2.46 0.31
Oklahoma 1 1 0 0.18 0.18 0
New Mexico 0 0 0 0 0 0
Other 7 5 2 2.38 1.88 0.50
Development
Texas 10 10 0 9.14 9.14 0
Oklahoma 3 1 2 3.00 1.00 2
New Mexico 3 3 0 2.34 2.34 0
Other 1 1 0 0.25 0.25 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.
26
Oil and Gas Wells
The following table sets forth the number of oil and natural gas wells in
which the Company had a working interest at December 31, 2001. All of these
wells are located in the United States.
Productive Wells
As of December 31, 2001
Gross (a) Net (b)
Location Oil Gas Total Oil Gas Total
- -------- --- --- ----- --- --- -----
Texas...................... 1,487 736 2,223 597.30 526.43 1,123.73
Offshore Texas ............ 0 4 4 0 1 1
Oklahoma................... 120 270 390 107.68 182.57 290.25
Mississippi................ 1 0 1 1 0 1
New Mexico................. 201 353 554 132.53 17.34 149.87
Offshore Louisiana......... 0 44 44 0 20.72 20.72
Arkansas................... 25 0 25 15.23 0 15.23
--------------------------------------------------------------------------------------
Total............. 1,834 1,407 3,241 853.75 981.30 1,835.05
- ----------
(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.
Oil and Gas Acreage
The following table summarizes the Company's developed and undeveloped
leasehold acreage at December 31, 2001.
Developed Undeveloped
--------- -----------
Gross (a) Net (b) Gross (a) Net (b)
--------- ------- --------- -------
Offshore.................. 174,044 71,816 240,346 112,328
Texas..................... 268,600 217,490 73,150 26,100
Oklahoma.................. 102,500 73,496 6,600 19,259
Mississippi............... 528 452 0 0
New Mexico................ 56,517 44,800 0 0
Louisiana................. 0 0 4,160 1,000
-------------------------------------------------------------------------------
Total .............. 602,189 408,054 324,256 158,687
===============================================================================
- ----------
(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 the Company's 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, the
27
Company generally acquires oil and gas acreage without any warranty of
title except as to claims made by, through or under the transferor. Although the
Company has 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 the Company's
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 the Company's 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 2001.
PART II
Item 5. Market for Common Equity and Related Stockholder Matters.
Our common stock is listed on the American Stock Exchange under the symbol
"MHR." 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.
Average Daily
Trading Volume
High Low (Shares)
2001
First Quarter .............. $ 13.90 $ 10.11 128,456
Second Quarter.............. $ 12.48 $ 8.11 128,842
Third Quarter .............. $ 9.69 $ 7.70 108,418
Fourth Quarter.............. $ 11.30 $ 7.53 129,426
2000
First Quarter .............. $ 4.06 $ 2.56 34,688
Second Quarter.............. $ 6.63 $ 3.38 45,703
Third Quarter .............. $ 9.13 $ 5.88 80,593
Fourth Quarter ............. $ 10.81 $ 6.50 106,183
On April 10, 2002 the last reported sale price of our common stock on the
American Stock Exchange was $7.59 per share. As of April 11, 2002, there were
3,279 record holders of Magnum Hunter common stock.
The Company has not previously paid any cash dividends on its Common Stock
and does not anticipate paying dividends on its Common Stock in the foreseeable
future. It is the present intention of management to utilize all available funds
for the development and growth of the Company's business activities. The Company
may not pay any dividends on Common Stock unless and until all dividend rights
on outstanding Preferred Stock have been satisfied. The Company's existing
credit facility restricts the payment of cash dividends on the Company's
securities.
28
Item 6. Selected Financial Data
The selected historical financial data sets forth our summary historical
consolidated financial data as of and for the years ended December 31, 2001,
2000, 1999, 1998 and 1997, which have been derived from the audited consolidated
financial statements and notes thereto. The selected historical financial data
is qualified in its entirety by, and should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements and the notes thereto included
elsewhere in this Form 10-K. For additional information relating to our
operations, see "Business" and "Properties." Certain reclassifications have been
made to the selected historical financial data of the prior years, as well as to
certain quarterly financial data, to conform with the current presentation. All
data is in thousands, except per share data.
1997 1998 1999 2000 2001
-------- -------- --------- -------- ---------
Income Statement Data:
Total operating revenues.......................... $ 48,834 $ 51,400 $ 69,626 $127,510 $152,806
Total operating costs and expenses (a)............ 38,833 94,414 54,514 77,181