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 77,181 104,755
------- -------- -------- -------- --------
Operating profit (loss)........................... 10,001 (43,014) 15,112 50,329 48,051
Provision for impairment of investment (b)........ - - - - (7,123)
Income (loss) before extraordinary loss........... (2,128) (47,080) (6,826) 22,260 13,820
Extraordinary loss from early extinguishment
of debt, net of taxes .......................... (1,384) - - - (304)
Net Income (loss) ................................ (3,512) (47,080) (6,826) 22,260 13,516
Dividends applicable to preferred shares (c)...... (875) (875) (4,509) (9,708) -
Income (loss) applicable to common shares......... $ (4,387) $(47,955) $(11,335) $ 12,552 $ 13,516
Income (loss) per common share before
extraordinary item
Basic (c)...................................... $ (0.21) $ (2.27) $ (0.57) $ 0.60 $ 0.40
Diluted (c).................................... $ (0.21) $ (2.27) $ (0.57) $ 0.51 $ 0.37
Income (loss) per common share after
extraordinary item
Basic (c)...................................... $ (0.30) $ (2.27) $ (0.57) $ 0.60 $ 0.39
Diluted (c).................................... $ (0.30) $ (2.27) $ (0.57) $ 0.51 $ 0.36
Other Data:
EBITDA (d)........................................ $ 22,740 $ 22,112 $ 37,538 $ 76,362 $ 92,333
Capital expenditures (e).......................... $160,059 $ 70,187 $ 59,968 $ 64,311 $204,370
Cash flow from operations......................... $ 5,652 $ 13,688 $ 17,435 $ 49,466 $104,074
- --------
(a) Includes in 1998 the non-cash write-down of $42.745 million of oil and
gas properties in the full-cost pool due to the ceiling test limitation and in
2001 a provision for loss of $3.156 million related to the Enron bankruptcy.
(b) Includes in 2001 a provision for $2.142 million for the impairment of
available-for-sale equity securities deemed by management to have suffered an
other than temporary impairment. The impairment was determined using a quoted
market price at December 31, 2001 of $0.86 per share. The Company had previously
reported losses in accumulated other comprehensive income of $507,000 ($466,000
net of income tax benefit) through December 31, 2000. Also included in 2001 was
an impairment provision of $4.981 million due to the bankruptcy of a privately
held company in which Magnum Hunter owned a minority interest and had invested
$4.528 million in equity securities and $453 thousand in secured loans.
(c) Includes the effect in the year 2000 of the payment of $5.5 million fee
paid upon redemption of $25.0 million (liquidation value) of the Company's 1999
Series A 8% Convertible preferred stock. The fee was treated as a dividend,
reducing income per common share, basic and diluted, by $0.26 per share and
$0.17 per share, respectively, for the year 2000.
(d) EBITDA is defined as income (loss) before income taxes and minority
interest, plus the sum of depletion and depreciation, provision for asset
impairment, and interest expense. EBITDA is not a measure of cash flow as
determined by generally accepted accounting principles. The Company has included
information concerning EBITDA because EBITDA is a measure used by certain
investors in determining the Company's historical ability to service its
indebtedness. EBITDA should not be considered as an alternative to, or more
meaningful than, net income or cash flows as determined in accordance with
generally accepted accounting principles or as an indicator of the Company's
operating performance or liquidity. This measure may not be comparable to
similarly titled measures reported by other companies.
29
(e) Capital expenditures include cash expended for acquisitions plus normal
additions to oil and natural gas properties and other fixed assets.
Additionally, the year 2000 amount includes the cost of property acquired
through the issuance of common stock with a fair market value of $3.481 million
on the acquisition date.
1997 1998 1999 2000 2001
----------- ----------- ----------- ----------- -----------
Balance Sheet Data:
Property, plant and equipment, net................. $ 221,259 $ 228,436 $ 265,195 $ 260,532 $ 419,837
Total assets....................................... 251,069 265,724 304,022 315,612 454,385
Total debt (a)..................................... 161,543 231,020 234,806 191,139 288,583
Stockholders' equity............................... $ 72,152 $ 19,697 $ 51,552 $ 93,416 $ 117,974
- -----------
(a) Consists of current notes payable and long-term debt, including current
maturities of long-term debt, and excluding production payment liabilities of
$743 thousand, $633 thousand, $460 thousand, $359 thousand and $203 thousand as
of December 31, 1997, 1998, 1999, 2000 and 2001, respectively. As of December
31, 2000 and 1999, $20.6 million and $41.8 million, respectively, of the debt
was non-recourse to the Company.
The following table sets forth unaudited summary financial results on a
quarterly basis for the two most recent years.
2001
----------------------------------------------------------------
First Second Third Fourth
-------------- --------------- -------------- ---------------
Revenues........................................... $ 50,754 $ 39,930 $ 33,571 $ 28,551
Depreciation, depletion and amortization........... 7,415 9,686 12,218 14,680
Net Operating Profit (Loss)........................ 26,030 15,233 7,911 (1,123)
Provision for impairment of investment (a)......... - - - (7,123)
Net Income (Loss).................................. 14,028 6,275 1,971 (8,758)
Income (Loss) per common share, basic (b).......... $ 0.41 $ 0.18 $ 0.06 $ (0.25)
Income (Loss) per common share, diluted (b)........ $ 0.37 $ 0.17 $ 0.05 $ (0.25)
2000
----------------------------------------------------------------
First Second Third Fourth
-------------- --------------- -------------- ---------------
Revenues........................................... $ 25,393 $ 28,286 $ 30,689 $ 43,142
Depreciation, depletion and amortization........... 5,971 5,566 5,398 8,621
Net Operating Profit............................... 8,139 10,847 13,244 18,099
Net Income......................................... 1,580 3,528 4,874 12,278
Income per common share, basic (c)................. $ 0.02 $ 0.13 $ 0.20 $ 0.24
Income per common share, diluted (c)............... $ 0.02 $ 0.12 $ 0.15 $ 0.19
(a) Includes in 2001 a provision for $2.142 million for the impairment of
available-for-sale equity securities deemed by management to have suffered an
other than temporary impairment. The Company had previously reported losses in
accumulated other comprehensive income of $507,000 ($466,000 net of income tax
benefit) through December 31, 2000. Also included in 2001 was an impairment
provision of $4.981 million due to the bankruptcy of a privately held company in
which Magnum Hunter owned a minority interest and had invested $4.528 million in
equity securities and $453 thousand in secured loans.
30
(b) Loss per common share for the fourth quarter of 2001 was the same for
basic and diluted due to the exclusion of warrants and options whose effect were
anti-dilutive.
(c) Includes the effect in the fourth quarter of 2000 of the payment of a
$5.5 million fee paid upon redemption of $25 million (liquidation value) of the
Company's 1999 Series A 8% Convertible preferred stock. The fee was treated as a
dividend, reducing income per common share, basic and diluted by $0.22 per share
and $0.15 per share, respectively, for the fourth quarter of 2000.
31
Item 7. Management Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
The following discussion and analysis should be read in conjunction with
the Company's consolidated financial statements and the notes associated with
them contained elsewhere in this report. This discussion should not be construed
to imply that the results discussed herein will necessarily continue into the
future or that any conclusion reached herein will necessarily be indicative of
actual operating results in the future. Such discussion represents only the best
present assessment by management of the Company.
The Company's results of operations have been significantly affected by our
success in acquiring oil and gas properties and our ability to maintain or
increase oil and natural gas production through exploration and exploitation
activities. Fluctuations in oil and gas prices have also significantly affected
the results of operations.
On December 31, 1998, the Company through its newly formed 100% owned
subsidiary, Bluebird, acquired from Spirit Energy 76 ("Spirit 76") natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
in the total amount of $25 million. The effective date of the acquisition was
December 31, 1998. As part of the capitalization of Bluebird, the Company
contributed 1,840,271 units of TEL Offshore Trust. Bluebird, as an "unrestricted
subsidiary" as defined under certain credit agreements, is neither a guarantor
of the Company's 10% Senior Notes due 2007 nor can it be included in determining
compliance with certain financial covenants under the Company's credit
agreements.
On June 8, 1999, the Company and Bluebird acquired oil and gas reserves and
related assets from Vastar including interests in 476 wells, a gas processing
plant and two gas gathering systems located in the states of Texas, Oklahoma and
Arkansas in the total amount of $32.5 million. The effective date of the
acquisition was April 1, 1999.
On December 1, 1999 Bluebird acquired a 50% ownership interest in the
Madill gas processing plant and associated gathering system located in Marshall
and Bryan counties, Oklahoma in the total amount of $8.4 million. The effective
date of the acquisition was November 1, 1999.
Effective September 1, 2000 the Company acquired a 5.5% net profits
interest in the Panoma production and gas gathering facilities for $3.5 million
of the Company's restricted common stock. By acquiring this interest, the
Company lowered its lease operating expense, increased oil field services
income, and reduced a permanent burden on this property.
Effective April 1, 2000 the Company exchanged interests with another oil
and gas company in certain onshore oil producing properties for interests in
certain offshore oil and gas producing properties and production facilities
located in the Gulf of Mexico in a tax free like-kind exchange. The transaction
did not have a material effect on reported production in 2000, but the Company
gained significantly increased exposure in an offshore area of interest where it
continues to conduct active exploration and development activities.
During 2000, we realized proceeds of $43.8 million from the sale of
non-core oil and gas and other properties, of which approximately $11.6 million
was attributable to Bluebird.
Effective July 1, 2001, the Company acquired proved and unproved oil and
gas properties located in Southeast New Mexico totaling approximately 41.8 Bcfe
of reserves for $31.6 million, net of purchase price adjustments. The
transaction had an effective date of July 1, 2001.
On December 18, 2001, the Company announced a merger with Prize Energy
Corp. (Prize), an independent oil and gas development and production company.
The merger was completed on March 15, 2002. The transaction has been accounted
for as a purchase of Prize by the Company in accordance with the provisions of
FAS 141. Under the terms of the merger, the Company has distributed 2.5 shares
of common stock plus $5.20 in cash for each Prize share outstanding. The
following summary, prepared on a pro forma basis, presents the results of
operations for the years ended December 31, 2001 and 2000 as if the acquisitions
had occurred as of the beginning of the respective years. The pro forma
information includes the effects of adjustments for interest expense,
depreciation, depletion and amortization, and income taxes:
32
(Unaudited)
2001 2000
--------------------------------------------
(in thousands, except for per share amounts)
--------------------------------------------
Revenue.............................................. $ 334,873 $ 276,999
Total Operating Costs and Expenses................... (224,138) (172,320)
-------------------- -------------------
Operating Profit..................................... 110,735 104,679
Interest Expense and Other........................... (52,680) (48,178)
-------------------- -------------------
Income before Tax.................................... 58,055 56,501
Provision for Income Tax............................. (21,792) (17,429)
Extraordinary loss from early extinguishment of debt. (304) -
-------------------- -------------------
Net Income........................................... 35,959 39,072
Dividends Applicable to Preferred Stock.............. - (10,167)
-------------------- -------------------
Net Income Applicable to Common Stock................ 35,959 28,905
==================== ===================
Net Income Per Common Share
Basic............................................. $ 0.52 $ 0.53
==================== ===================
Diluted........................................... $ 0.50 $ 0.50
==================== ===================
The following table sets forth certain information with respect to our oil
and gas operations and our gas gathering, marketing and processing operations:
Years Ended
2001 2000 1999
Oil and Gas Operations -----------------------------------------------
- -----------------------------------------------
Production:
Oil (MBbls)................................. 1,410 1,298 1,307
Gas (MMcf).................................. 24,861 19,579 19,026
Oil and Gas (MMcfe)......................... 33,322 27,368 26,868
Equivalent Daily Rate (MMcfe/day)........... 91.3 74.8 73.6
Average Sale Prices (after hedging)
Oil (per Bbl)............................... $ 24.53 $ 22.95 $ 15.01
Gas (per Mcf)............................... 3.96 3.90 2.16
Oil and Gas (per Mcfe)...................... 3.99 3.88 2.26
Effect of hedging activities (per Mcfe)........ 0.14 (0.41) (0.12)
Lease Operating Expense (per Mcfe)
Lifting costs............................... 0.61 0.60 0.57
Production tax and other costs.............. 0.39 0.46 0.30
Gross margin (per Mcfe)........................ $ 2.99 $ 2.82 $ 1.39
Gas Gathering, Marketing and
Processing Operations
- -----------------------------------------------
Throughput Volumes (Mcf per day)
Gathering................................... 16,139 16,639 18,536
Processing.................................. 13,257 16,506 21,510
Gross margin (in thousands)....................
Gathering (per Mcf throughput).............. 0.04 0.18 0.14
Processing (per Mcf throughput)............. 0.27 0.50 0.16
33
Period to Period Comparisons
For the Years Ended December 31, 2001 and 2000
We reported net income of $13.5 million for the year ended December 31,
2001 as compared to net income of $22.3 million for the same period in 2000, a
decrease of 39%. The 2001 period results include a loss on Enron related assets
of $3.2 million, a provision for impairment of investments of $7.1 million, and
an extraordinary loss from early extinguishment of debt of $304 thousand, net of
tax benefits, from the repurchase of $10.5 million of the Company's 10% Senior
Notes. Total operating revenues increased 20% to $152.8 million in 2001 from
$127.5 million in 2000 and operating profit decreased 5% to $48.0 million in
2001 from $50.3 million in 2000. A 3% increase in the price received for oil and
gas sold (on a thousand cubic feet equivalent, or Mcfe, basis), combined with a
22% increase in oil and gas production (on a million cubic feet equivalent, or
MMcfe, basis) in our oil and gas exploration and production segment was
primarily responsible for the improvement in revenues, while higher
depreciation, depletion and amortization expense and the Enron related loss were
primarily responsible for the increase in operating costs and expenses. Income
applicable to common shares was $13.5 million in the 2001 period versus $12.6
million in the 2000 period, an increase of 8%. Income per common share-diluted
was $0.36 per share in the 2001 period compared to $0.51 per share-diluted, in
the 2000 period, a decrease of 29% due to a 13% increase in diluted shares. The
effect of the extraordinary loss in the 2001 period was $0.01 per share, basic
and diluted. No dividends were recorded in the 2001 period due to the conversion
of $25.0 million (liquidation value) of our 1999 Series A 8% Convertible
preferred stock on January 1, 2001 into approximately 4.8 million shares of our
common stock. We had previously redeemed $25.0 million (liquidation value) of
the 1999 Series A 8% Convertible preferred stock in December, 2000 and Bluebird
acquired 100% of our $10.0 million (liquidation value) in 1996 Series A
Convertible preferred stock during 2000.
Oil and Gas Operations:
For the year ended December 31, 2001, we reported oil production of 1.4
MMbbls (million barrels) and gas production of 24,861 MMcf (million cubic feet),
which represents an increase of 9% in oil and an increase of 27% in gas produced
from the comparable period in 2000. Our reported equivalent daily rate of
production on a million cubic feet per day basis (MMcfe/day) increased 22% to
91.3 MMcfe/day in the 2001 period from 74.8 Mmcfe/day in the 2000 period. These
increases were primarily the result of the success of our drilling program
offsetting normal production declines.
Prices realized in the 2001 period averaged $24.53 per barrel of oil and
$3.96 per Mcf of gas. This represents a 3% increase on a thousand cubic feet of
gas equivalent (Mcfe) basis over the 2000 period average realized prices of
$22.95 per barrel of oil and $3.90 per Mcf of gas. The unit prices realized
include the effects of hedging. During the 2001 period, hedging increased the
average price we received for oil by $0.89 per barrel and the average price we
received for gas by $0.14 per Mcf. Excluding the effects of hedging, oil prices
declined 18% and natural gas prices declined 6% in 2001 from those received in
2000.
As a result of higher realized prices and higher production levels, oil and
gas revenues increased 25% to $133.0 million in the 2001 period compared to
$106.1 million in the 2000 period.
For the 2001 period, oil and gas production lifting costs, on a unit of
production basis, were $0.61 per Mcfe as compared to $0.60 per Mcfe in the 2000
period, an increase of 2%. Production tax and other costs were $0.39 per Mcfe in
the 2001 period compared to $0.46 per Mcfe in the 2000 period, a decline of 15%,
principally due to lower production taxes. Lower production taxes are a result
of lower oil and gas prices before the effect of hedge transactions and higher
production levels in the Gulf of Mexico on which no production taxes are levied.
Gross margin for oil and gas operations for the 2001 period was $99.7
million, or $2.99 per Mcfe, compared to $77.1 million, or $2.82 per Mcfe in the
2000 period, an increase of 6% on a per unit of production basis, primarily as a
result of higher oil and gas prices realized and the increase in our daily unit
production rate.
34
Gathering, Marketing and Processing Operations:
For the year ended December 31, 2001, our gathering systems throughput was
16.1 MMcf per day versus 16.6 MMcf per day for the same period in 2000, a
decline of 3% due to normal production declines behind the systems. Gas
processing throughput was 13.3 MMcf per day in 2001 versus 16.5 MMcf per day in
2000, a decrease of 20%. Our reported processing throughput in the 2001 period
was reduced due to (i) the sale in September 2000 of a substantial ownership
interest in oil and gas properties supplying one of our plants, (ii) the
voluntary shutdown of two gas processing plants for approximately 1 1/2 months
of the 2001 period due to adverse processing economics as a result of high
natural gas prices and (iii) normal production declines on properties supplying
the plants.
Revenues from gathering, marketing and processing decreased 11% to $17.9
million in 2001 versus $20.0 million in 2000, primarily due to a decline in
natural gas liquids prices and a decrease in throughput. Operating costs for the
gathering, marketing and processing segment increased 3% to $16.1 million in
2001 from $15.7 million in 2000.
The gross margin realized from gathering, marketing and processing for 2001
was $1.8 million versus $4.3 million in 2000, a decrease of 59%. Gathering
margin was $0.04 per Mcf gathered in 2001 versus $0.18 per Mcf in 2000 due to a
decrease in marketing spreads and losses incurred on pipeline imbalance
positions. Processing margin was $0.27 per Mcf in 2001 compared to $0.50 per Mcf
in 2000 due to less favorable processing economics because of the decline in
natural gas liquids prices and the temporary shutdown of two plants for a
portion of the 2001 period.
Oil Field Management Services Operations:
Revenues from oil field management services were $1.8 million in the 2001
period versus $1.4 million in the 2000 period due to higher management and
operations services fees charged to third parties, primarily on offshore
operations. Operating costs increased to $1.3 million in 2001 from $903 thousand
in 2000 due to higher costs for labor and overhead. The gross margin for this
segment in 2001 was $551 thousand versus $545 thousand in 2000, an increase of
1%.
Other Income and Expenses:
Depreciation and depletion expense was $44.0 million in the 2001 period
versus $25.6 million in the 2000 period, an increase of 72% due to higher
production levels and higher unit costs. Depreciation and depletion on oil and
gas properties was $1.28 per Mcfe in 2001 versus $0.89 per Mcfe in 2000. This
44% increase in the equivalent unit cost was due primarily to an increase in
development costs associated with our exploration efforts in the Gulf of Mexico.
General and administrative expense for 2001 increased 13% to $6.9 million
from $6.1 million in 2000. The principal cause of this increase was an increase
in salary, benefits and retirement plan expenses and an increase in the
Company's overall headcount associated with its increased activity level. The
number of personnel employed by the Company at fiscal year-end 2000 and 2001
were 95 and 105, respectively. We recorded equity in earnings of affiliate of
$1.1 million in 2001 versus income of $1.3 million in 2000, a 17% decrease, due
to decreased net earnings from gas marketing operations of the Company's 30%
owned affiliate. Other income was $283 thousand for 2001 versus $477 thousand in
2000, a 41% decrease, due to a reduction in interest income.
We made provision for a $3.2 million loss on assets associated with the
Enron Corp. bankruptcy in the 2001 period. Of the total loss provision recorded,
approximately $2.5 million was related to accounts receivable for Enron for
physical gas sales and approximately $701 thousand was related to a receivable
from a natural gas commodity hedge in which Enron was the counterparty.
35
The Company had equity and debt investments in a privately held entity
which declared bankruptcy subsequent to December 31, 2001, and for which the
Company provided an impairment charge against earnings of $5.0 million at
December 31, 2001. Additionally, the Company had an investment in
available-for-sale securities of another entity of $2.8 million at December 31,
2001. Because of the deteriorating financial condition of this entity, the
Company reported an other than temporary impairment of $2.1 million as a charge
against earnings at December 31, 2001, based on the entity's reported market
value on that date.
Interest expense was $19.9 million for 2001 versus $22.3 million for 2000,
a decrease of 11%. During the 2001 period, the interest rate on our primarily
LIBOR-based bank debt was 6.3% versus 9.1% in 2000, a decline of 31%. The
weighted average daily balance of bank debt increased 17% to $93.3 million in
2001 from $79.7 million in 2000. We also benefitted in the 2001 period by the
repurchase of $10.5 million of our 10% Senior Notes in June, 2001. In addition,
interest expense was reduced in the 2001 period by $744 thousand as a result of
interest rate derivatives versus an increase in interest expense of $13 thousand
from interest rate derivatives in the 2000 period.
We recorded a total provision for income tax expense of $8.6 million in
2001 versus $7.6 million in 2000, an increase of 14%. We made no adjustment to
the valuation allowance charged against deferred tax assets in the 2001 period,
whereas the 2000 period benefitted from a $3.9 million reduction in the
valuation allowance charged against deferred tax assets.
There were no dividends applicable to preferred stock in 2001 as compared
to $9.7 million for the 2000 period. The elimination of the dividend was due to
the purchase, redemption and conversion of all of the Company's outstanding
dividend paying preferred stock not controlled by wholly-owned entities.
For the Years Ended December 31, 2000 and 1999
We reported record net income of $22.3 million for the year ended December
31, 2000 versus a net loss of $6.8 million for the same period in 1999. Total
operating revenues increased 83% to $127.5 million and operating profit
increased 233% to $50.3 million in 2000. A 72% increase in the price received
for oil and gas sold (on a thousand cubic feet equivalent, or Mcfe, basis),
combined with a 2% increase in oil and gas production (on a million cubic feet
equivalent, or MMcfe, basis) in our oil and gas exploration and production
segment was primarily responsible for these results. We also reported
significant increases in revenues and gross operating margins from our gas
gathering, marketing and processing and oil field services segments in 2000
compared to 1999 due to improved product prices and processing economics and an
increase in customers for whom we are providing operations services. Income
applicable to common shares was $12.6 million in 2000 versus a loss applicable
to common shares of $11.3 million in 1999. Income per common share - basic was
$0.60 per share and income per common share - diluted was $0.51 per share in
2000 compared to a loss applicable to common shares of $0.57 per share, both
basic and diluted, in 1999. Income per share in 2000 includes the effect of a
$5.5 million non-recurring fee paid upon redemption of $25.0 million
(liquidation value) of our 1999 Series A 8% Convertible preferred stock. The fee
was treated as a dividend, which reduced income per common share, basic and
diluted, by $0.26 per share and $0.17 per share, respectively, for the year
2000.
Oil and Gas Operations:
For the year 2000, we reported oil production of 1,298 Mbbls (thousand
barrels) and gas production of 19,579 MMcf (million cubic feet), which
represents a decline of 1% in oil and an increase of 3% in gas produced from
1999. Our reported equivalent daily rate of production on a million cubic feet
per day basis (MMcfe/day) increased 2% to 74.8 MMcfe/day in 2000. The reported
production in 2000 was impacted by the sale of certain non-core oil and gas
properties which took effect in June and September 2000. Excluding the
production of these properties from both periods, our underlying oil production
increased 13% and our underlying gas production increased 11% in 2000 compared
to 1999,with the underlying equivalent daily rate of production increasing 11%
to 68.5 MMcfe/day .
36
These increases were the result of a full year of production from the
properties acquired from Vastar being included in 2000 as well as the success of
our drilling program offsetting normal production declines.
The increase in oil and gas prices was the most significant factor
affecting the increase in net income in 2000. Prices realized in 2000 averaged
$22.95 per barrel of oil and $3.90 per Mcf of gas. This represents a 72%
increase on a thousand cubic feet of gas equivalent (Mcfe) basis over 1999
average realized prices of $15.01 per barrel of oil and $2.16 per Mcf of gas.
The unit prices realized include the effects of commodity hedging.
From time to time, we enter into various commodity hedging contracts in
order to reduce our exposure to the possibility of declining oil and gas prices.
During 2000, commodity hedging reduced the average price we received for oil by
$5.96 per barrel and for gas by $0.18 per Mcf. During 2000, we had approximately
19% of our natural gas production and 73% of our oil production hedged.
Beginning January 1, 2000 we had approximately 14% of our expected natural gas
production hedged for 2001 at a weighted average price using cost-less collars
of $4.50 to $6.15 per Mcf and we had approximately 45% of our expected crude oil
production for the first six months of 2001 hedged at a weighted average price
using cost-less collars of $25.00 to $34.73 per barrel.
Primarily as a result of higher realized prices, oil and gas revenues
increased 75% to $106.1 million in 2000 compared to $60.7 million in 1999.
Lease operating expenses consist of two components, lifting costs and
production tax and other costs. For 2000, lifting costs, on a unit of production
basis, were $0.60 per Mcfe as compared to $0.57 per Mcfe in 1999, an increase of
5%. This increase in lifting costs per unit was due to a general increase in
costs of labor, materials and field services stimulated by higher prices for oil
and natural gas. Production tax and other costs were $0.46 per Mcfe in 2000
compared to $0.30 per Mcfe in 1999, an increase of 53%. This was principally due
to an increase of $0.10 per Mcfe in production taxes, which are a function of
higher oil and gas prices, and an increase in company overhead charged to oil
and gas operations of $0.04 per Mcfe due principally to higher labor and benefit
costs.
Our gross margin for oil and gas operations (oil and gas revenues less
lease operating expenses) for 2000 was $77.1 million, or $2.82 per Mcfe,
compared to $37.1 million, or $1.39 per Mcfe in 1999, an increase of 102% on a
per unit of production basis, primarily as a result of higher oil and gas
prices.
Gathering, Marketing and Processing Operations:
For 2000, our gathering system throughput was 16.6 MMcf per day versus 18.5
MMcf per day in 1999, a decline of 10% due to the sale of a gathering system in
June 1999 and to normal production declines behind the system. Gas processing
throughput was 16.5 MMcf per day in 2000 versus 21.5 MMcf per day in 1999, a
decrease of 23%. During December 1999, we completed recoupment of our original
investment in the McLean gas processing plant. As a result, our share of
operating income and plant throughput reverted to 50% from the 100% applicable
during the recoupment period. The decline in reported throughput at McLean was
partially offset by our acquisition of a 50% interest in the Madill gas
processing plant in December 1999. Also, our reported throughput at another
plant was reduced beginning June 2000 due to the sale of an interest in oil and
gas properties supplying the plant.
Revenues from gathering, marketing and processing increased 144% to $20.0
million in 2000 versus $8.2 million in 1999. Of this increase, $8.4 million was
due to the acquisition of the Madill plant. Also, we received significantly
higher prices for natural gas and plant products sold in 2000 compared to 1999.
Natural gas prices increased 85% while the price received for natural gas
liquids increased 62%. The effect of price increases was seen at the McLean
plant, where our revenues declined only 14% despite the 50% decline in our
operating interest due to reversion.
Operating costs for the gathering, marketing and processing segment
increased 166% to $15.7 million in 2000 from $5.9 million in 1999. A substantial
portion of this increase was due to the acquisition of the Madill plant. Our
37
net share of costs at the McLean plant declined only 19% despite the
reversion to a 50% operating interest due to higher natural gas prices affecting
the cost of plant throughput. Higher natural gas prices also affected the cost
of gas marketed.
The gross margin realized from gathering, marketing and processing for 2000
was $4.3 million versus $2.3 million in 1999, an increase of 87%. Gathering
margin was $0.18 per Mcf in 2000 versus $0.14 in 1999 due to an increase in
marketing spreads. Processing margin was $0.50 per Mcf in 2000 compared to $0.16
per Mcf in 1999 due to higher prices for plant products and better processing
economics.
Oil Field Services Operations:
Revenues from oil field services were $1.4 million in 2000 versus $768
thousand in 1999 due to an increase in customers for whom we provided operations
services. Operating costs increased to $903 thousand in 2000 from $350 thousand
in 1999 due to higher costs for labor and overhead. The gross margin for this
segment in 2000 was $545 thousand versus $418 thousand in 1999, an increase of
30%.
Other Income and Expenses:
Depreciation and depletion expense was $25.6 million in 2000 versus $22.1
million in 1999. Depreciation and depletion on oil and gas properties was $0.89
per Mcfe in 2000 versus $0.79 per Mcfe in 1999. This 13% increase in the
equivalent unit cost was due to an increase in development costs associated with
our exploration efforts in the Gulf of Mexico. Depreciation expense for the
gathering, marketing and processing segment increased by $230 thousand in 2000
due to the Madill plant acquisition.
For 2000, we recorded a gain on sale of $28 thousand versus a gain on sale
of $272 thousand in 1999. The gain on sale in both periods relates to the sale
of property other than oil and gas properties. Since we use the full cost method
of accounting for oil and gas properties, proceeds from the sale of those
properties are applied to the full cost pool and no gain or loss is recognized.
General and administrative expense for 2000 increased 110% to $6.1 million from
$2.9 million in 1999. The principal cause of this increase was a $3.1 million
increase in salary, benefits and retirement plan expenses as a result of higher
headcount, year-end incentive bonuses, and ESOP expense resulting from
appreciation in the Company's stock price. The difference between the stock
value on the contribution date and the stock value when purchased must be
expensed at the date the contribution is made to the ESOP. We recorded equity in
earnings of affiliate of $1.3 million in 2000 versus a loss of $103 thousand in
1999. This increase was due to increased net earnings from gas marketing
operations of the affiliate. Other income was $477 thousand for 2000 versus $354
thousand in 1999. The increase was caused by an increase in interest income.
Interest expense was $22.3 million for 2000 versus $22.1 million for 1999.
During most of 2000, the interest rate on our LIBOR-based bank debt and an
interest rate swap were higher than in 1999. This was offset by a decrease in
outstanding LIBOR-based bank debt in the latter part of 2000 due to reducing
debt from cash raised from the sale of non-core oil and gas properties and the
exercise of warrants and options for our common stock.
We recorded a total provision for income tax expense of $7.6 million in
2000 versus none in 1999. The year 2000 provision included a $234 thousand
current provision due to alternative minimum tax regulations. The provision for
deferred income tax expense of $7.3 million in 2000 reflects a reduction of $3.9
million in the valuation allowance charged against our deferred tax asset. We
made this reduction in the valuation allowance in 2000 after consideration of
current production levels, current expectations regarding near-term oil and gas
prices, current commodity hedging positions, anticipated capital expenditures,
the estimated reversal of book and tax temporary differences, available
tax-planning strategies and expectations regarding future taxable income. The
valuation allowance reduces the deferred tax asset to an amount that is more
likely than not to be realized based on the factors previously discussed. No
income tax benefit was provided in 1999 because of uncertainty at that time in
our ability to realize additional tax benefits on our net operating losses in
the future.
38
Dividends applicable to preferred stock were $9.7 million for 2000 versus
$4.5 million in 1999. The dividends in 2000 included the $5.5 million premium
(non-recurring) on redemption of $25.0 million (liquidation value) of our 1999
Series A 8% Convertible preferred stock.
Liquidity and Capital Resources
CASH FLOW AND WORKING CAPITAL. Net cash provided by operating activities
during 2001, 2000 and 1999 was $104.1 million, $49.5 million and $17.4 million,
respectively. The substantial increase in our operating cash flows in 2001 over
2000 and 2000 over 1999 is primarily the result of higher net realized oil and
gas prices and higher production levels. In the 2001 period compared to the 2000
period, a reduction in trade accounts receivable and an increase in trade
accounts payable balances also contributed to increased operating cash flows.
Our net working capital position at December 31, 2001 was a deficit of
$23.6 million. On that date, we had available $5.0 million under our senior bank
credit facility. Several items contributed to the deficit in working capital,
including a delay in obtaining $11.2 million of sale and leaseback financing of
offshore production platforms until January 2002, the $3.2 million loss we
sustained as a result of the Enron bankruptcy, and the postponement of
negotiations for the expected $5.4 million sale of certain assets, also a result
of uncertainty in the marketplace caused by Enron. We also cancelled plans to
sell an interest in a recent Gulf of Mexico discovery for $10 million because of
falling oil and gas prices in the fourth quarter of 2001 and general market
uncertainties. Subsequent to December 31, 2001, several actions taken by
management eliminated this deficit in working capital. See "Magnum Hunter's
Liquidity and Capital Resources" later in this discussion for a more complete
description of these actions.
INVESTING ACTIVITIES. Net cash used in investing activities was $204.0
million in the 2001 period. We made capital expenditures of $204.4 million
during 2001. Our capital expenditures are discussed in further detail below. We
received a distribution of $1.6 million from NGTS, LLC, a 30% owned natural gas
marketing affiliate which we account for under the equity method. Additionally,
we made an investment in another 10% owned company of $2.5 million. This
affiliate is accounted for as an investment. We realized proceeds of $1.1
million from sale of assets, received payments on promissory notes receivable
totaling $70 thousand and had a decrease in deposits of $50 thousand during the
2001 period.
In the 2000 period, net cash used in investing activities was $20.0
million, which included proceeds from asset sales of $43.8 million, capital
expenditures of $60.8 million, a loan made for $1.4 million, repayments on a
loan of $1.0 million and investment in unconsolidated affiliate of $2.6 million.
In 1999, net cash used in investing activities was $58.5 million, which
included proceeds from asset sales of $1.5 million and capital expenditures of
$60.0 million.
FINANCING ACTIVITIES. Net cash provided by financing activities was $102.7
million in 2001. We borrowed $262.5 million under our senior bank credit lines
and $4.0 million through vendor provided financing for offshore construction. We
repaid borrowings under our senior bank credit lines by $158.6 million, made
payments of $180 thousand on production payment and other loans and repurchased
$10.5 million principal value of our 10% Senior Notes on the open market for
$10.8 million. We received $5.8 million in cash from the issuance of common
stock. Cash dividends paid were $169 thousand in 2001. Due to the repayment of
Bluebird's bank debt, its cash is no longer restricted, which provided $1.8
million in cash. We paid $956 thousand for fees related to financing activities,
made a loan to stockholder of $300 thousand, received repayment of stockholder
loans of $360 thousand, made a loan to the ESOP of $898 thousand, received a
loan repayment from the ESOP of $1.1 million, and purchased treasury stock for
$1.0 million. With respect to the ESOP, and as required under Statement of
Position 93-6 "Employers' Accounting for Employee Stock Ownership Plans,"
compensation expense is recorded for shares committed to be released to
employees based on the fair market value of those shares when they are committed
to be
39
released. The difference between cost and the fair market value of the
committed to be released shares is recorded in additional paid-in-capital.
Unreleased shares held by the ESOP are excluded from the calculation of earnings
per share.
In the 2000 period, net cash used in financing activities was $31.0
million. We borrowed a total of $101.1 million under our senior bank credit
lines of which $11.5 million was attributable to Bluebird. We repaid borrowings
under our senior bank credit lines by $144.8 million, of which $32.7 million was
attributable to Bluebird. We received $60.0 million in cash from the issuance of
common and preferred stock, net of offering costs. We paid $534 thousand of fees
related to financing activities. We spent $25.0 million to redeem our 1999
Series A preferred stock, while Bluebird also spent $10.5 million to acquire
Magnum Hunter preferred and common stock. Cash dividends paid were $10.2 million
in 2000. We loaned the ESOP $1.6 million to purchase our common stock. Bluebird
had a net decrease in cash of $325 thousand.
In 1999, net cash provided by financing activities was $37.7 million. We
borrowed a total of $106.8 million under our senior bank credit lines, of which
$46.3 million was attributable to Bluebird. We repaid borrowings under our
senior bank credit lines by $103.2 million, of which $30.5 million was
attributable to Bluebird. We realized proceeds from issuance of common and
preferred stock of $46.3 million, net of offering costs. We also paid fees
related to financing activities of $1.6 million, paid a short term note of $2
million, loaned the ESOP $759 thousand, loaned a shareholder $123 thousand,
purchased treasury stock for $1.7 million and paid preferred dividends of $4.2
million. Bluebird had a net increase in cash of $1.7 million.
BLUEBIRD'S CAPITAL RESOURCES. On May 17, 2001, Bluebird sold all of its
proved and unproved oil and gas properties, except for its investment in Tel
Offshore Trust, and all of its pipelines and other fixed asset property to
Magnum Hunter Production, Inc., for $17.7 million in cash and $10 million of our
1996 Series A Convertible preferred stock. Bluebird used the cash to repay and
retire its $17.7 million of debt under its senior bank credit line. The
effective date of the sale was May 1, 2001. On June 25, 2001, Bluebird purchased
$4.7 million face value of Magnum Hunter Resources, Inc. 10% Senior Notes on the
open market. Bluebird remains an unrestricted subsidiary under the Company's
senior bank credit agreement. At December 31, 2001, Bluebird had no capital
spending plans or commitments and no remaining debt or interest payment
requirements.
MAGNUM HUNTER'S LIQUIDITY AND CAPITAL RESOURCES. The following discussion
of Magnum Hunter's capital resources refers to the Company and its affiliates
other than Bluebird, whose capital resources were discussed separately above.
Internally generated cash flow and the borrowing capacity under its senior bank
credit line are the Company's major sources of liquidity. From time to time, the
Company may also sell oil and gas properties in order to increase liquidity. In
addition, the Company may use other sources of capital, including the issuance
of additional debt securities or equity securities, as sources to fund
acquisitions or other specific needs. In the past, the Company has accessed both
public and private capital markets to provide liquidity for specific activities
and general corporate purposes.
In December 2000, the Company used $10.0 million in cash to purchase 100%
of its 1996 Series A Convertible preferred stock outstanding from Bluebird. This
preferred stock was held by another 100% owned affiliate for possible re-issue
at a later date. Also in December 2000, the Company spent $30.5 million
(including a $5.5 million redemption premium) to redeem 50% of its outstanding
1999 Series A 8% Convertible preferred stock. In January, 2001 the remaining 50%
of this preferred stock was converted by the holder to the Company's common
stock at the conversion price of $5.25 per share. As a result of the redemption
of its 1999 Series A 8% Convertible preferred stock, the Company saved $4.0
million in annual dividend payments. In May 2001, the Company reissued the $10.0
million of its 1996 Series A Convertible preferred stock to Bluebird in
connection with the acquisition of Bluebird's oil and gas properties. The
Company will make dividend payments of $875 thousand annually to Bluebird,
however, such payments are eliminated under consolidated financial reporting.
40
On May 17, 2001, the Company closed on a new $225 million Senior Bank
Credit Facility, of which $160 million was available under the borrowing base at
December 31, 2001. The credit agreement provides for both "LIBOR" and "Base
Rate" (Prime) interest rate options. This new credit facility consolidated and
replaced both the Company's and Bluebird's previous credit facilities. At
December 31, 2001, borrowings under this line were $155.0 million, leaving
availability of $5.0 million on that date versus a deficit in working capital of
$27.4 million (excluding Bluebird). As described below, the Company entered into
several courses of action to remedy this working capital shortfall. On a
semiannual basis, the borrowing base is redetermined by the banks based on their
review of the Company's oil and gas reserves. If the outstanding senior bank
debt exceeds the redetermined borrowing base, the Company must repay the excess.
On December 5, 2001, the Company announced that a distribution of one
warrant for every five shares of common stock owned on January 10, 2002. These
warrants were distributed on March 21, 2002. Each new warrant will entitle the
holder to purchase one share of common stock at $15. The warrants will expire
three years from the date of distribution.
On January 15, 2002, the Company entered into a sale-leaseback transaction
on three newly constructed offshore production platforms and associated
pipelines that were recently placed into service. The Company received a total
of $11.2 million in new funding which was used for general corporate purposes
including a voluntary reduction under the Company's corporate bank revolving
credit facility. The production platforms are being leased from a syndicate
group of lenders over a term of three years and at a cost of funds of
approximately 5.30% per annum, based on current interest rates. This transaction
will be accounted for as a capital lease.
On March 15, 2002, the Company amended and restated its Senior Bank Credit
Facility (the facility) in conjunction with the merger with Prize. The amended
facility provides for total borrowings of $500 million, up from $225 million,
and raises the borrowing base limit from $160 million to $300 million. On March
15, 2002, the Company borrowed $185.6 million against the facility, leaving
$114.4 million of excess credit line for working capital and other corporate
purposes.
On March 15, 2002, the Company also completed a private placement of $300
million of Senior Notes (the private placement) due 2012 that are unsecured.
Interest on the Senior Notes bear an annual rate of 9.6% due semi-annually,
commencing September 15, 2002.
With the funds provided by the new facility and the private placement of
Senior Notes, the Company repaid indebtedness under its old credit facility of
$155.7 million, repaid debt under Prize's previous credit agreement of $246.8
million, funded the cash component of the merger consideration of $70.9 million,
and paid other fees and expenses related to the merger, facility and private
placement of approximately $12.2 million. In connection with the merger with
Prize, the Company issued 34,062,963 shares of its common stock to Prize
shareholders, increasing its total shares outstanding by 96%. Also in connection
with the merger with Prize, 11,811,073 Prize warrants remain outstanding and are
exercisable at $9.12 for up to a total of 4,218,241 shares of the Company's
common stock. These warrants expire in November 2002. Additionally, 150,000
Prize warrants remain outstanding and are exercisable at $6.38 for up to 53,573
shares of the Company's common stock. These warrants expire in June 2002.
The Company's internally generated cash flow, results of operations, and
financing for its operations are dependent on oil and gas prices. To the extent
that oil and gas prices decline, the Company's earnings and cash flows may be
adversely affected.
CAPITAL EXPENDITURES. For the year ended December 31, 2001, the Company's
total capital expenditures for property, plant and equipment were $204.4
million. The following summarizes the Company's capital expenditures by cost
component (in millions):
41
Oil & Gas Properties
------------------------------ Other
Unproved Proved Property Total
------------- ------------- ------------ -------------
Acquisition Costs $ 12.2 $ 36.1 $ 1.3 $ 49.6
Exploration Costs 4.1 33.6 - 37.7
Development Costs - 117.1 - 117.1
------------- ------------- ------------ -------------
Total $ 16.3 $ 186.8 $ 1.3 $ 204.4
Acquisition costs include $4.8 million for unproved and $26.8 million for
proved reserves in the Mallon acquisition and $5.8 million for the purchase of
additional proved reserves in South Timbalier block 264. As of December 31,
2001, the Company had total unproved oil and gas property costs of $18.7
million, consisting of $14.7 million of property acquisition costs and $4.0
million of exploration costs.
For the year 2002, the Company has budgeted approximately $115 million for
exploration and development activities, including $40 million on properties
acquired in the Prize merger. We anticipate that the 2002 capital expenditure
budget will be funded by cash flow from operations and credit facility
utilization. The Company is not contractually obligated to proceed with any of
its material budgeted capital expenditures. The amount and allocation of future
capital expenditures will depend on a number of factors that are not entirely
within the Company's control or ability to forecast, including drilling results,
oilfield costs, and changes in oil and gas prices. As a result, actual capital
expenditures may vary significantly from current expectations.
In the normal course of business, the Company reviews opportunities for the
possible acquisition of oil and gas reserves and activities related thereto.
When potential acquisition opportunities are deemed consistent with the
Company's growth strategy, bids or offers in amounts and with terms acceptable
to the Company may be submitted. It is uncertain whether any such bids or offers
which may be submitted by the Company from time to time will be acceptable to
the sellers. In the event of a future significant acquisition, the Company may
require additional financing in connection therewith. The Company does not
budget for acquisition expenditures.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS. We have the following
contractual obligations as of December 31, 2001:
Payments Due by Period (in thousands)
Contractual Obligations Total Less than 1 1 - 3 Years 4 - 5 Years After 5 Years
Year
- ------------------------------- ---------------- ---------------- --------------- --------------- ---------------
Long-Term Debt $ 284,539 $ 73 $ 155,000 $ 129,466 $ -
Notes Payable 4,044 4,044 - - -
Operating Leases 3,732 1,037 2,576 119 -
---------------- ---------------- --------------- --------------- ---------------
Total Contractual Obligations $ 292,315 $ 5,154 $ 157,576 $ 129,585 $ -
We have commercial commitments in the form of guarantees on a several basis
to trade creditors of our 30% owned affiliate, NGTS, LLC. The total amount
committed as of December 31, 2001 is $11,040,000. The guarantees expire up to
one year from the dates of original issuance.
42
Critical Accounting Policies and Other
Our financial statements are prepared in accordance with accounting
principles generally accepted in the United States of America. The reported
financial results and disclosures were determined using significant accounting
policies, practices and estimates as described below. We believe the reported
financial results are reliable and that the ultimate actual results will not
differ significantly from those reported.
The accompanying consolidated financial statements include the accounts of
the Company and its subsidiaries. The Company consolidates on a pro rata basis
its approximately 39%, as of at December 31, 2001, ownership of TEL Offshore
Trust. The Company accounts for its investment in NGTS, LLC under the equity
method. All significant intercompany transactions and balances have been
eliminated in consolidation. Certain items in prior periods have been
reclassified to conform with the current presentation.
The Company is a holding company with no significant assets or operations
other than its investments in its subsidiaries. The wholly-owned subsidiaries of
the Company, except for Bluebird Energy, Inc. ("Bluebird"), are direct
guarantors of the Company's 10% senior notes and have fully and unconditionally
guaranteed the notes on a joint and several basis. The guarantors comprise all
of the direct and indirect subsidiaries of the Company (other than Bluebird),
and the Company has presented separate condensed consolidating financial
statements and other disclosures concerning each guarantor and Bluebird (See
Note 17 to the Consolidated Financial Statements). There is no restriction on
the ability of consolidated or unconsolidated subsidiaries to transfer funds to
the Company in the form of cash dividends, and, except for Bluebird, loans or
advances.
Oil and Gas Properties
The Company uses the full cost method of accounting for its investment in
oil and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and gas proved reserves are
capitalized into a "full cost pool" on a country-by-country basis as incurred,
and properties in the pool are depleted and charged to operations using the
unit-of-production method based on the ratio of current production to total
proved oil and gas reserves, as determined by independent petroleum engineers.
To the extent that such capitalized costs (net of accumulated depreciation,
depletion and amortization) less deferred taxes exceed the PV-10 of estimated
future net cash flow from proved reserves of oil and gas, and the lower of
unamortized cost or fair value of unproved properties after income tax effects,
such excess costs are charged to operations. Once incurred, a write- down of oil
and gas properties is not reversible at a later date even if oil or gas prices
subsequently increase. The Company's capitalized costs exceeded the PV-10
limitation utilizing prices in effect at December 31, 2001 by $76 million.
However, no writedown for impairment of oil and gas properties was required as a
result of the increase in oil and gas prices subsequent to December 31, 2001.
Significant downward revisions of quantity estimates, declines in oil and gas
prices, higher operating costs or additional capital costs which are not offset
by incremental increases in oil and gas reserves or other factors could possibly
result in a write-down for impairment of oil and gas properties in the future.
Reserve engineering is a subjective process that is dependent on the
quality of available data and on engineering and geological interpretation and
judgment. Reserve estimates are subject to change over time as additional
information becomes available.
Revenue Recognition
Revenues are recognized when title to the product transfers to purchasers.
We follow the "sales method" of accounting for revenue for oil and natural gas
production, so that we recognize sales revenue on all production sold to
purchasers, regardless of whether the sales are proportionate to our ownership
in the property. A receivable or liability is recognized only to the extent that
we have an imbalance on a specific property greater than the expected remaining
proved reserves. Ultimate revenues from the sales of oil and gas production is
not known with certainty
43
until up to three months after production and title transfer occur. Current
revenues are accrued based on our expectation of actual deliveries and actual
prices received.
Inflation and Changes in Prices
The results of operations and cash flow of the Company have been, and will
continue to be, affected by the volatility in oil and gas prices. Should the
Company experience a significant increase in oil and gas prices that is
sustained over a prolonged period, it would expect that there would also be a
corresponding increase in oil and gas finding costs, lease acquisition costs,
and operating expenses.
The Company markets oil and gas for its own account, which exposes the
Company to the attendant commodities risk. A significant portion of the
Company's gas production is currently sold to a 30% owned affiliate, NGTS, LLC,
or end-users either (i) on the spot market on a month-to-month basis at
prevailing spot market prices or (ii) under long-term contracts based on current
spot market prices. The Company normally sells its oil under month-to-month
contracts to a variety of purchasers.
Hedging
Periodically the Company enters into futures, options, and swap contracts
to reduce the adverse effects of fluctuations in crude oil and gas prices and
interest rates. It is the policy of the Company to not enter into any such
commodity hedging arrangements which cause the Company's aggregate commodity
hedge position to exceed 75% of the oil and gas production during the projected
next 12 months. We also utilize financial derivative instruments to hedge the
risk associated with interest on our outstanding debt. Generally, the cash
settlement of all derivative instruments is recognized as income or expense in
the period in which the hedged transaction is recognized. The Company's
accounting of the fair value of derivative instruments is discussed below.
New Accounting Standards
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133), as extended by
SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000), was effective
for the Company beginning January 1, 2001. SFAS No. 133 establishes accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of derivatives in the balance sheet and the measurement of those
instruments at fair value. Derivative instruments that are not hedges must be
adjusted to the fair value through net income (loss). Under the provisions of
SFAS 133, changes in the fair value of derivative instruments that are fair
value hedges are offset against changes in the fair value of the hedged assets,
liabilities, or firm commitments, through net income (loss). Changes in the fair
value of derivative instruments that are cash-flow hedges are recognized in
other comprehensive income (loss) until such time as the hedged items are
recognized in net income (loss). Ineffective portions of a derivative
instrument's change in fair value are immediately recognized in net income
(loss).
The Company was obligated to four crude oil derivatives, one natural gas
derivative, and one interest rate derivative on January 1, 2001. The Company
determined that the interest rate derivative did not qualify for hedge treatment
as defined within SFAS No. 133. The crude oil and natural gas derivatives
qualified as cash-flow hedges.
At January 1, 2001, all derivatives within the Company were identified
pursuant to SFAS No. 133 requirements, and the Company designated, documented
and assessed all hedging relationships. Adoption of this accounting standard
resulted in the recognition of $179 thousand of a derivative asset related to
the interest rate derivative and an increase in the carrying value of long-term
debt with recourse of $179 thousand. In June, 2001 the Company terminated its
position in this derivative. For the year ended December 31, 2001, the Company
recognized a gain of $980 thousand as a reduction of interest expense for this
derivative.
44
With respect to the cash-flow hedges, at the accounting change transition,
the Company recorded a derivative asset of $648 thousand related to the crude
oil derivatives with a cumulative effect increase to other comprehensive income
of $403 thousand (net of income taxes) and a derivative liability of $3.5
million related to the natural gas derivatives with a cumulative effect decrease
to other comprehensive income of $2.2 million (net of income taxes).
In May, 2001, the Company entered into additional costless collars for
crude oil for the periods July 2001 through December 2001. In August, 2001, the
Company entered into a swap transaction for natural gas for the periods
September 2001 through November 2001 and interest rate swaps (receive
variable/pay fixed) on $50 million of its variable rate bank debt for the period
August 2001 through August 2003. These crude oil, natural gas and interest rate
derivatives qualify as cash flow hedges.
At December 31, 2001, the Company had no crude oil derivatives, and its
natural gas derivatives had a fair value of $3.6 million, recognized as
derivative assets of $5.1 million and derivative liabilities of $1.5 million.
The Company recognized a liability of $1.0 million on its interest rate
derivatives. For the year ended December 31, 2001, the income statement includes
a gain of $1.3 million related to the crude oil derivatives, a gain of $3.4
million related to the natural gas derivatives and a loss of $204 thousand on
interest rate derivatives, net of amounts reclassified out of other
comprehensive income. The Company expects that the remaining balance in other
comprehensive income related to the natural gas derivatives at December 31,
2001, will be reclassified into the income statement within the next eighteen
months and for the interest rate derivatives, within the next twenty months.
Recently Issued Statements
SFAS No. 141 - SFAS No. 141, "Business Combinations", is effective for the
Company beginning July 1, 2001. SFAS No. 141 requires the use of the purchase
method of accounting for business combinations initiated and completed after
June 30, 2001 and eliminates the use of the pooling-of-interests method. The
adoption of SFAS No. 141 as of July 1, 2001 did not have an impact on our
consolidated financial statements.
SFAS No. 142 - SFAS No. 142, "Goodwill and Other Intangible Assets", will
be effective for the Company beginning January 1, 2002. SFAS No. 142 requires,
among other things, the discontinuance of goodwill amortization. Any goodwill
resulting from acquisitions completed after June 30, 2001 will not be amortized.
In addition, SFAS No. 142 requires the Company to complete a transitional
goodwill impairment test within six months from the date of adoption and
establishes a new method of testing goodwill that could reduce the fair value of
a reporting unit below its carrying value. Any goodwill impairment loss during
the transition period will be recognized as the cumulative effect of a change in
accounting principle. Subsequent impairments will be recorded in operations. The
adoption of SFAS No. 142 will not have a material impact on our consolidated
financial statements.
SFAS No. 143 - SFAS No. 143, "Accounting for Asset Retirement Obligations",
will be effective for the Company beginning January 1, 2003. SFAS No. 143
requires the recognition of a fair value liability for any retirement obligation
associated with long-lived assets. The offset to any liability recorded is added
to the recorded asset where the additional amount is depreciated over the same
period as the long-lived asset for which the retirement obligation is
established. SFAS No. 143 also requires additional disclosures. We are in the
process of evaluating the impact of the provisions of SFAS No. 143.
SFAS No. 144 - SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets", will be effective for the Company beginning January 1, 2002.
SFAS No. 144 establishes a single accounting model, based on the framework
established in SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of", for long-lived assets to be
disposed of by sale and resolves significant implementation issues related to
SFAS No. 121. We are in the process of evaluating the impact of the provisions
of SFAS No. 144.
45
Off Balance Sheet Arrangements
We have no off balance sheet arrangements, special purpose entities or
financing partnerships. We have agreed to provide guarantees on a several basis
to trade creditors of our 30% owned affiliate, NGTS, LLC. The upper limit of
liability we have agreed to guarantee is $15 million. At December 31, 2001, the
aggregate amount of our guarantees for NGTS, LLC was $11,040,000.
The Company had equity and debt investments in a privately held entity
which declared bankruptcy subsequent to December 31, 2001, and for which the
Company provided an impairment charge against earnings of $5.0 million at
December 31, 2001. The Company is not responsible for any debts of this entity.
The Company had an investment in available-for-sale securities of another entity
of $2.8 million at December 31, 2001. Because of the deteriorating financial
condition of this entity, the Company reported an other than temporary
impairment of $2.1 million as a charge against earnings at December 31, 2001.
The Company is not responsible for any debts of this entity.
Other
Our hedging activity has resulted in gas revenue that reflects
approximately 60% of our gas sales volumes realized at fixed prices. The
remainder of our hydrocarbon volumes are sold at market prices. Future commodity
price declines will negatively impact future income and cash flow to the extent
of any production sold at market prices. These declines could ultimately affect
the quantity of proved oil and gas reserves and cost center ceiling values.
These results, individually or collectively, could result in bank debt default
and/or debt acceleration, restrict our ability to attract qualified personnel or
cause further industry consolidation. There are no requirements from any of the
Company's lenders to hedge our products.
Our domestic operations are concentrated in the southwestern and
midcontinent regions of the United States and shallow water region of the Gulf
of Mexico offshore Texas and Louisiana. We currently have no operations outside
of the United States of America. We currently have eighteen wells which
individually produce 1.5 MMcfe per day or greater, but these are not
concentrated in any one field. We have no individual fields in which disruptions
could reduce our financial results.
FORWARD-LOOKING STATEMENTS. This Form 10-K and the information incorporated
by reference contain statements that constitute "forward-looking statements"
within the meaning of Section 27A of the Securities Act and Section 21E of the
Securities Exchange Act. The words "expect", "project", "estimate", "believe",
"anticipate", "intend", "budget", "plan", "forecast", "predict" and other
similar expressions are intended to identify forward- looking statements. These
statements appear in a number of places and include statements regarding our
plans, beliefs, or current expectations, including the plans, beliefs, and
expectations of our officers and directors.
When considering any forward-looking statement, you should keep in mind the
risk factors that could cause our actual results to differ materially from those
contained in any forward-looking statement. Important factors that could cause
actual results to differ materially from those in the forward-looking statements
herein include the timing and extent of changes in commodity prices for oil and
gas, operating risks and other risk factors as described in our Annual Report on
Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the
assumptions that support our forward-looking statements are based upon
information that is currently available and is subject to change. We
specifically disclaim all responsibility to publicly update any information
contained in a forward- looking statement or any forward-looking statement in
its entirety and therefore disclaim any resulting liability for potentially
related damages.
All forward-looking statements attributable to Magnum Hunter Resources,
Inc. are expressly qualified in their entirety by this cautionary statement.
46
Item 7A. Qualitative and Quantitative Disclosure About Market Risk
The Company's operations are exposed to market risks primarily as a result
of changes in commodity prices and interest rates. The Company does not use
derivative financial instruments for speculative or trading purposes.
Energy swap agreements. The Company produces, purchases, and sells crude
oil, natural gas, condensate, and natural gas liquids. As a result, the
Company's financial results can be significantly impacted as these commodity
prices fluctuate widely in response to changing market forces. The Company has
previously engaged in oil and gas hedging activities and intends to continue to
consider various hedging arrangements to realize commodity prices which it
considers favorable and to reduce volatility. The Company engages in futures
contracts with certain of its oil and gas production through various contracts
("Swap Agreements"). The primary objective of these activities is to protect
against significant decreases in price during the term of the hedge.
The Swap Agreements provide for separate contracts tied to the New York
Mercantile Exchange ("NYMEX") light sweet crude oil and the Inside FERC natural
gas index price posting ("Index"). The Company has contracts which contain
specific contracted prices ("Swaps") that are settled monthly based on the
differences between the contract prices and the specified Index prices for each
month applied to the related contract volumes. To the extent the Index exceeds
the contract price, the Company pays the spread, and to the extent the contract
price exceeds the Index price, the Company receives the spread. In addition, the
Company has combined contracts which have agreed upon price floors and ceilings
("Costless Collars"). To the extent the Index price exceeds the contract
ceiling, the Company pays the spread between the ceiling and the Index price
applied to the related contract volumes. To the extent the contract floor
exceeds the Index, the Company receives the spread between the contract floor
and the Index price applied to the related contract volumes.
To the extent the Company receives the spread between the contract floor
and the Index price applied to related contract volumes, the Company has a
credit risk in the event of nonperformance of the counterparty to the agreement.
The Company does not anticipate any material impact to its results of operations
as a result of nonperformance by such parties.
At December 31, 2001, the Company had the following open contracts:
Type Volume/Day Duration Wtd. Avg. Price
----------- ------------ ------------ ------------------
Gas
- -------
Swap...... 60,000 MMBtu Jan 02 - Dec 02 $ 2.87
Swap...... 50,000 MMBtu Jan 03 - Jun 03 $ 2.88
Based on future market prices at December 31, 2001, the fair value of open
contracts to the Company was a net asset of $3.6 million. If future market
prices were to increase 10% from those in effect at December 31, 2001, the fair
value of open contracts to the Company would decrease in value to a net
liability of $4.5 million. If future market prices were to decline 10% from
those in effect at December 31, 2001, the fair value of the open contracts to
the Company would increase to a net asset of $11.6 million.
The Company currently intends to commit no more than 75% of its daily
production on a Bcfe basis to such arrangements at any point in time. A portion
of the Company's oil and natural gas production will be subject to price
fluctuations unless the Company enters into additional hedging transactions.
47
Interest Rate Swaps
On June 30, 1999, the Company entered into two interest rate swaps in order
to shift a portion of the fixed rate bond debt to floating rate debt, to
capitalize on what was perceived as a market overreaction to pending interest
rate increases by the Federal Reserve, and to effectively lower interest rate
expense over the following twelve months. On June 1, 2000, one of the interest
rate swaps terminated. The Company terminated the remaining interest rate swap
in June, 2001.
On August 9, 2001, the Company entered into two interest rate swaps in
order to shift a portion of its variable rate bank debt to fixed rate debt. The
following table reflects the terms of these swaps.
Type Notional Amount Termination Date Pay Rate Receive Rate
------ --------------- ---------------- -------------- ----------------
Pay Fixed/Receive Variable $50,000,000 8/23/03 4.25 % Fixed 3 month
LIBOR rate
currently 2.195%
The rate the Company receives will be reset every three months to exactly
match the rate the Company will pay on $50.0 million of its outstanding
LIBOR-based bank debt.
Based on future market prices at December 31, 2001, the fair value of open
interest rate swap contracts to the Company was a liability of $1.0 million. If
future market rates were to increase 10% from those in effect at December 31,
2001, the fair value of open contracts to the Company would be a liability of
$864 thousand. If future market rates were to decline 10% from those in effect
at December 31, 2001, the fair value of the open contracts to the Company would
be a liability of $1.2 million.
Fixed and Variable Debt.
The Company uses fixed and variable debt to partially finance budgeted
expenditures. These agreements expose the Company to market risk related to
changes in interest rates.
The following table presents the carrying and fair value of the Company's
debt along with average interest rates. Fair values are calculated as the net
present value of the expected cash flows of the financial instruments, except
for the fixed rate senior notes, which are valued at their last traded value
before December 31, 2001.
Expected Maturity Dates
(in thousands) 2002 2003 2004-2006 2007 Total Fair Value
--------- ---------- ---------- --------- ---------- -----------
Variable Rate Debt:
Bank Debt with Recourse (a)...... $ - $ 155,000 $ - $ - $ 155,000 $ 155,000
Fixed Rate Debt:
Senior Notes (b)................. $ - $ - $ - $129,466 $ 129,466 $ 130,113
Other............................ $ 73 $ - $ - $ - $ 73 $ 73
Notes Payable - Current (c)...... $ 4,044 $ - $ - $ - $ 4,044 $ 4,044
- --------------------
(a) The weighted average interest rate on the bank debt with recourse at
December 31, 2001 is 4.71%.
(b) The interest rate on the senior notes is a fixed 10%.
(c) The interest rate on notes payable - current is a fixed 7%.
48
Item 8. Consolidated Financial Statements and Unaudited Supplemental Information
Index to Consolidated Financial Statements
Page
Independent Auditors' Report...........................................................................F-1
Financial Statements:
Consolidated Balance Sheets at December 31, 2001and 2000.......................................F-2
Consolidated Statements of Operations and Comprehensive Income for the
Years Ended December 31, 2001, 2000 and 1999...........................................F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2001, 2000 and 1999..........................................F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2001, 2000 and 1999................................................F-5
Notes to Consolidated Financial Statements.............................................................F-6
Supplemental Information (Unaudited)..................................................................F-30
ii
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
Magnum Hunter Resources, Inc.
We have audited the accompanying consolidated balance sheets of Magnum
Hunter Resources, Inc. and Subsidiaries as of December 31, 2001, and 2000, and
the related consolidated statements of operations and comprehensive income,
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2001. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Magnum
Hunter Resources, Inc. and Subsidiaries as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States of America.
Deloitte & Touche LLP
Dallas, Texas
March 22, 2002
F-1
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
December 31, December 31,
2001 2000
--------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents..................................................$ 2,755 $ 9
Restricted cash .......................................................... - 1,820
Accounts receivable
Trade, net of allowance of $3,264 and $50, respectively............... 14,251 30,442
Due from affiliates................................................... 235 107
Notes receivable from affiliate............................................ 300 377
Current portion of long-term notes receivable, net of allowance of $1,170.. - 50
Income tax refund receivable............................................... 300 -
Derivative assets, current................................................. 5,045 -
Prepaid and other.......................................................... 2,220 2,033
--------------------------------------------
Total Current Assets................................................. 25,106 34,838
--------------------------------------------
Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved............................................................. 18,653 5,534
Proved............................................................... 556,766 367,822
Pipelines.................................................................. 12,642 12,581
Other property............................................................. 3,640 2,459
--------------------------------------------
Total Property, Plant and Equipment........................................ 591,701 388,396
Accumulated depreciation, depletion, amortization and impairment..... (171,864) (127,864)
--------------------------------------------
Net Property, Plant and Equipment.......................................... 419,837 260,532
--------------------------------------------
Other Assets
Deposits and other assets.................................................. 4,420 6,570
Investment in unconsolidated affiliates, net of allowance
of $453 and $0, respectively............................................. 5,022 8,054
Deferred tax asset ........................................................ - 5,618
--------------------------------------------
Total Assets.............................................................. $ 454,385 $ 315,612
=============================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities.....................................$ 41,446 $ 27,094
Dividends payable.......................................................... - 169
Suspended revenue payable.................................................. 2,154 3,201
Derivative liabilities, current............................................ 996 -
Current income taxes payable............................................... - 234
Current maturities of long-term debt, with recourse........................ 73 19
Notes payable.............................................................. 4,044 -
--------------------------------------------
Total Current Liabilities............................................ 48,713 30,717
--------------------------------------------
Long-Term Liabilities
Long-term debt, with recourse, less current maturities..................... 284,466 170,520
Long-term debt, non recourse, less current maturities...................... - 20,600
Production payment liability............................................... 203 359
Derivative liabilities, noncurrent......................................... 1,531 -
Deferred income taxes payable.............................................. 1,498 -
Commitments and Contingencies (Note 11)
Stockholders' Equity
Preferred stock - $.001 par value; 10,000,000 shares authorized, 216,000
designated as Series A; 80,000 issued and outstanding, liquidation
amount $0................................................................ - -
1,000,000 designated as 1996 Series A Convertible; 1,000,000 purchased
and held for remarketing by subsidiary, liquidation amount $10,000,000.. 1 1
50,000 designated as 1999 Series A 8% Convertible; none and 25,000
issued and outstanding, respectively, liquidation amount $0 and
$25,000,000, respectively............................................... - -
Common Stock - $.002 par value; 100,000,000 shares authorized,
36,588,097 and 30,705,398 shares issued, respectively.................... 73 61
Additional paid-in capital................................................. 157,836 148,580
Accumulated other comprehensive income (loss).............................. 1,632 (466)
Accumulated deficit........................................................ (36,636) (50,152)
Receivable from stockholder................................................ (442) (442)
Unearned common stock in ESOP, at cost (468,652 and 680,282 shares,
respectively)............................................................. (2,576) (2,780)
--------------------------------------------
119,888 94,802
Treasury stock, at cost (441,813 and 455,063 shares of common stock,
respectively)............................................................. (1,914) (1,386)
--------------------------------------------
Total Stockholders' Equity................................................. 117,974 93,416
--------------------------------------------
Total Liabilities and Stockholders' Equity.................................$ 454,385 $ 315,612
============================================
The accompanying notes are an integral part of these consolidated financial statements.
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Operations and Comprehensive Income
(in thousands of dollars, except for share and per share amounts)
For the Years Ended
December 31,
-----------------------------------------------------
2001 2000 1999
-----------------------------------------------------
Operating Revenues:
Oil and gas sales.......................................... $ 133,083 $ 106,052 $ 60,673
Gas gathering, marketing and processing.................... 17,895 20,010 8,185
Oil field services......................................... 1,828 1,448 768
-----------------------------------------------------
Total Operating Revenues............................. 152,806 127,510 69,626
-----------------------------------------------------
Operating Costs and Expenses:
Oil and gas production lifting costs....................... 20,388 16,401 15,431
Production taxes and other costs........................... 12,994 12,558 8,144
Gas gathering, marketing and processing.................... 16,101 15,685 5,870
Oil field services......................................... 1,277 903 350
Depreciation, depletion and amortization................... 43,999 25,556 22,072
Gains on sale of assets.................................... (58) (28) (272)
Loss on Enron related assets............................ 3,156 - -
General and administrative................................. 6,898 6,106 2,919
-----------------------------------------------------
Total Operating Costs and Expenses................... 104,755 77,181 54,514
-----------------------------------------------------
Operating Profit.............................................. 48,051 50,329 15,112
Equity in earnings (loss) of affiliate..................... 1,085 1,307 (103)
Other income............................................... 283 477 354
Provision for impairment of investments................. (7,123) - -
Minority interest in subsidiary loss.................... - - (86)
Interest expense........................................... (19,868) (22,298) (22,103)
-----------------------------------------------------
Income (loss) before income tax............................... 22,428 29,815 (6,826)
Provision for income tax expense
Current................................................. (178) (234) -
Deferred................................................ (8,430) (7,321) -
-----------------------------------------------------
Total provision for income tax expense............... (8,608) (7,555) -
-----------------------------------------------------
Income (Loss) Before Extraordinary Loss....................... 13,820 22,260 (6,826)
Extraordinary loss from early extinguishment of debt,
net of income tax benefit of $186................... (304) - -
-----------------------------------------------------
Net Income (Loss)............................................. 13,516 22,260 (6,826)
Dividends Applicable to Preferred Stock.................... - (9,708) (4,509)
-----------------------------------------------------
Income (Loss) Applicable to Common Shares..................... $ 13,516 $ 12,552 $ (11,335)
=====================================================
Comprehensive Income (Loss):
Net Income (Loss)........................................ $ 13,516 $ 22,260 $ (6,826)
Other Comprehensive Income (Loss), net of tax
Cumulative effect on prior years of a change in
accounting principle.................................... (1,757) - -
Gain on derivatives........................................ 3,536 - -
Reclassification adjustment related to derivative assets... (147) - -
Unrealized Gain (Loss) on investments...................... 466 1,247 (405)
-----------------------------------------------------
Comprehensive Income (Loss)................................... $ 15,614 $ 23,507 $ (7,231)
=====================================================
Income (Loss) per Common Share - Basic
Income (Loss) Before Extraordinary Loss.................... $ 0.40 $ 0.60 $ (0.57)
Extraordinary Loss......................................... (0.01) - -
-----------------------------------------------------
Income (Loss) per Common Share - Basic $ 0.39 $ 0.60 $ (0.57)
=====================================================
Income (Loss) per Common Share - Diluted
Income (Loss) Before Extraordinary Loss.................... $ 0.37 $ 0.51 $ (0.57)
Extraordinary Loss......................................... (0.01) - -
-----------------------------------------------------
Income (Loss) per Common Share - Diluted $ 0.36 $ 0.51 $ (0.57)
=====================================================
Common Shares Used in Per Share Calculation
Basic ..................................................... 34,819,614 20,856,854 19,743,738
=====================================================
Diluted ................................................... 37,108,976 32,834,270 19,743,738
=====================================================
The accompanying notes are an integral part of these consolidated financial statements.
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity
For the Periods Ended December 31, 2001, 2000 and 1999
(dollars in thousands)
Additional
Preferred Stock Common Stock Treasury Stock Paid-In
Shares Amount Shares Amount Shares Amount Capital
------------------------------------------------------------------------------
Balance at December 31, 1998....................... 1,080,000 $ 1 21,738,320 $ 43 (1,054,507) $ (1,909) $ 80,032
Issuance of 1999 Series A preferred, net of
offering costs................................. 50,000 - 46,260
Fees paid on issuance of warrants................ (133)
Common Stock contributed to 401(k) plan ......... 41,115 - 123
Exercise of employees' common stock options ..... 102,145 - 74
Costs associated with release of shares from ESOP (2)
Purchase of treasury stock ...................... (601,472) (1,722)
Dividends declared on preferred stock ........... (4,509)
Net loss ........................................
Unrealized loss on investment ...................
Loan to stockholder..............................
Unearned shares in ESOP..........................
--------------------------------------------------------------------------------
Balance at December 31, 1999....................... 1,130,000 $ 1 21,738,320 $ 43 (1,512,719) $ (3,631) $ 121,845
Purchase of 1996 Series A preferred by subsidiary (10,035)
Redemption of 1999 Series A 8% convertible
preferred stock................................ (25,000) (25,000)
Purchase of treasury stock....................... (129,032) (500)
Exercise of employees' common stock options...... 528,942 1 127,450 77 2,335
Exercise of warrants, net of expenses............ 8,438,136 17 702,272 1,588 55,952
Issuance of common stock for property............ 356,966 1,080 2,401
Costs associated with release of shares from ESOP 672
Deferred tax benefit on exercise of employee
stock options.................................. 410
Net income.......................................
Dividends on preferred stock.....................
Unrealized gain on investment....................
Repayment of stockholder loan....................
Unearned shares in ESOP..........................
--------------------------------------------------------------------------------
Balance at December 31, 2000....................... 1,105,000 $ 1 30,705,398$ 61 (455,063) $ (1,386) $ 148,580
Conversion of 1999 Series A 8% convertible
preferred stock................................ (25,000) 4,761,904 10 (10)
Exercise of employees' common stock options...... 1,068,316 2 56,300 171 4,692
Deferred tax benefit on exercise of employee
stock options.................................. 2,350
Common stock contributed to 401(k) plan and other 52,479 - 151
Issuance of common stock from treasury........... 72,900 316 418
Purchase of treasury stock....................... (115,950) (1,015)
Net income.......................................
Cumulative effect on prior years of a change in
accounting principle...........................
Gain on hedges...................................
Reclassification adjustment related to
derivative assets..............................
Unrealized gain on investments...................
Employee salary deferrals to ESOP................ 1,655
Loan to ESOP.....................................
--------------------------------------------------------------------------------
Balance at December 31, 2001....................... 1,080,000 $ 1 36,588,097 $ 73 (441,813) $ (1,914) $ 157,836
================================================================================
Accumulated Other Receivable Unearned Shares in
Comprehensive Accumulated from ESOP
Income (Loss) Deficit Stockholder Shares Amount
-------------------------------------------------------------------------
Balance at December 31, 1998....................... $ (1,308) $ (55,734) $ (672) (250,423) $ (756)
Issuance of 1999 Series A preferred, net of
offering costs.................................
Fees paid on issuance of warrants................
Common Stock contributed to 401(k) plan .........
Exercise of employees' common stock options .....
Costs associated with release of shares from ESOP
Purchase of treasury stock ......................
Dividends declared on preferred stock ...........
Net loss ........................................ (6,826)
Unrealized loss on investment ................... (405)
Loan to stockholder.............................. (123)
Unearned shares in ESOP.......................... (287,092) (882)
-------------------------------------------------------------------------
Balance at December 31, 1999....................... $ (1,713) $ (62,560) $ (795) (537,515) $(1,638)
Purchase of 1996 Series A preferred by subsidiary
Redemption of 1999 Series A 8% convertible
preferred stock................................
Purchase of treasury stock.......................
Exercise of employees' common stock options......
Exercise of warrants, net of expenses............
Issuance of common stock for property............
Costs associated with release of shares from ESOP
Deferred tax benefit on exercise of employee
stock options..................................
Net income....................................... 22,260
Dividends on preferred stock..................... (9,852)
Unrealized gain on investment.................... 1,247
Repayment of stockholder loan.................... 353
Unearned shares in ESOP.......................... (142,767) (1,142)
-------------------------------------------------------------------------
Balance at December 31, 2000....................... $ (466) $ (50,152) $ (442) (680,282) $(2,780)
Conversion of 1999 Series A 8% convertible
preferred stock................................
Exercise of employees' common stock options......
Deferred tax benefit on exercise of employee
stock options..................................
Common stock contributed to 401(k) plan and other
Issuance of common stock from treasury...........
Purchase of treasury stock.......................
Net income....................................... 13,516
Cumulative effect on prior years of a change in
accounting principle........................... (1,757)
Gain on hedges................................... 3,536
Reclassification adjustment related to
derivative assets.............................. (147)
Unrealized gain on investments................... 466
Employee salary deferrals to ESOP................ 317,080 1,102
Loan to ESOP..................................... (105,450) (898)
-------------------------------------------------------------------------
Balance at December 31, 2001....................... $ 1,632 $ (36,636) $ (442) (468,652) $(2,576)
=========================================================================
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(in thousands)
For the Years Ended
December 31,
-------------------------------------------------
2001 2000 1999
-------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income (loss)............................................................. $ 13,516 $ 22,260 $ (6,826)
Adjustments to reconcile net income (loss) to cash
provided by operating activities
Extraordinary loss...................................................... 304 - -
Depreciation, depletion and amortization................................ 43,999 25,556 22,072
Impairment of investments............................................... 7,123 - -
Amortization of financing fees.......................................... 1,192 1,318 2,091
Increase in allowance for doubtful accounts............................. 3,214 464 -
Deferred income taxes................................................... 8,430 7,321 -
Equity in (income) loss of unconsolidated affiliate..................... (1,085) (1,307) 103
Minority interest expense............................................... - - 86
Cost of shares released from ESOP suspense.............................. - 448 151
Excess of fair value over cost of shares released from ESOP suspense.... 1,655 672 (2)
Gain on sale of assets.................................................. (58) (28) (272)
Change in fair value of derivatives..................................... 162 - -
Changes in certain assets and liabilities
Accounts and notes receivable................................... 12,849 (20,378) (4,660)
Other current assets............................................ (187) (737) 281
Accounts payable and accrued liabilities........................ 13,494 13,827 4,411
Current income taxes payable.................................... (534) 234 -
Minority interest liability..................................... - (184) -
-------------------------------------------------
Net Cash Provided By Operating Activities..................................... 104,074 49,466 17,435
-------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets.................................................. 1,124 43,770 1,499
Additions to property and equipment........................................... (204,370) (60,830) (59,968)
Decrease in deposits and other assets......................................... 50 - -
Loan made for promissory note receivable...................................... - (1,370) -
Payments received on promissory note receivable .............................. 70 1,012 -
Distribution from unconsolidated affiliate.................................... 1,590 - -
Investment in unconsolidated affiliate........................................ (2,453) (2,590) -
-------------------------------------------------
Net Cash Used In Investing Activities......................................... (203,989) (20,008) (58,469)
-------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of long-term debt, note payable, and
production payment.......................................................... 266,524 101,056 106,800
Fees paid related to financing activities..................................... (956) (534) (1,603)
Payments of principal on long-term debt and production payment................ (169,557) (144,824) (103,186)
Payment of short-term notes payable .......................................... - - (2,000)
Receipts from short-term notes receivable .................................... 360 - -
Loan repaid by (made to) stockholder.......................................... (300) 353 (123)
Loan to ESOP.................................................................. (898) (1,590) (759)
Loan repaid from ESOP......................................................... 1,102 - -
Payment of fees on issuance of warrants and preferred stock................... - - (133)
Proceeds from issuance of common and preferred stock, net of offering costs... 5,750 59,970 46,334
Purchase of 1996 Series A preferred stock by subsidiary....................... - (10,035) -
Redemption of 1999 Series A preferred stock................................... - (25,000) -
Purchase of treasury stock ................................................... (1,015) (500) (1,722)
Decrease (increase) in restricted cash for payment of notes payable .......... 1,820 325 (1,686)
Dividends paid................................................................ (169) (10,235) (4,176)
-------------------------------------------------
Net Cash Provided By (Used In) Financing Activities........................... 102,661 (31,014) 37,746
-------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................ 2,746 (1,556) (3,288)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.................................. 9 1,565 4,853
-------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR........................................ $ 2,755 $ 9 $ 1,565
=================================================
The accompanying notes are an integral part of these consolidated financial statements.
F-5
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Nature of Operations
Magnum Hunter Resources, Inc. (the "Company"), is incorporated under the
laws of the state of Nevada. The Company and its subsidiaries are engaged in the
acquisition, operation and development of oil and gas properties, the gathering,
processing, transmission, and marketing of natural gas and natural gas liquids
and providing management and advisory consulting services on oil and gas
properties for third parties. In conjunction with the above activities, the
Company owns and operates oil and gas properties in six states, predominantly in
the Southwest region of the United States. In addition, the Company owns and
operates two gathering systems located in Texas and Oklahoma and owns an
interest in three natural gas processing plants located in Texas, Oklahoma and
Arkansas.
Consolidation
The accompanying consolidated financial statements include the accounts of
the Company and its existing wholly-owned subsidiaries, Bluebird Energy, Inc.
("Bluebird"), Gruy Petroleum Management Company ("Gruy"), Hunter Gas Gathering,
Inc., Inesco Corporation, Magnum Hunter Production, Inc., Midland Hunter
Petroleum Limited Liability Company and SPL Gas Marketing, Inc. The Company
consolidates on a pro rata basis its approximately 39% ownership of TEL Offshore
Trust. The Company accounts for its investment in NGTS, LLC under the equity
method. All significant intercompany accounts and transactions have been
eliminated in consolidation. Certain reclassifications have been made to the
consolidated financial statements of the prior year to conform with the current
presentation.
The Company is a holding company with no significant assets or operations
other than its investments in its subsidiaries. The wholly-owned subsidiaries of
the Company, except for Bluebird, are direct Guarantors of the Company's 10%
Senior Notes and have fully and unconditionally guaranteed the Notes on a joint
and several basis. The Guarantors comprise all of the direct and indirect
subsidiaries of the Company (other than Bluebird), and the Company has presented
separate condensed consolidating financial statements and other disclosures
concerning each Guarantor and Bluebird (See Note 17). There is no restriction on
the ability of consolidated or unconsolidated subsidiaries to transfer funds to
the Company in the form of cash dividends, and, except for Bluebird, loans or
advances.
Bluebird was formed in December 1998. As part of the capitalization of
Bluebird, the Company contributed to Bluebird 1,840,271 units of TEL Offshore
Trust. Bluebird, as an "unrestricted subsidiary" as defined under certain credit
agreements, is neither a guarantor of the Company's 10% Senior Notes due 2007
nor can it be included in determining compliance with certain financial
covenants under the Company's credit agreements.
Cash and Cash Equivalents
The Company considers all highly liquid debt instruments purchased with a
maturity of three months or less to be cash equivalents. The Company has cash
deposits in excess of federally insured limits.
Restricted Cash
Prior to May, 2001, the cash balance of Bluebird was classified as
restricted cash as a result of a credit agreement entered into between Bluebird
and certain banks. Under this credit agreement, cash funds of Bluebird were not
permitted to be commingled with Magnum Hunter or its other subsidiaries or
affiliates and could not be dividended or loaned to Magnum Hunter or its other
subsidiaries or affiliates, but were required to be used to satisfy the cash
requirements of Bluebird, including the payment of Bluebird's outstanding
borrowings. During May 2001, Bluebird sold certain oil and gas properties to
Magnum Hunter Production, Inc. and used a portion of the proceeds received to
repay all outstanding debt and to terminate the credit agreement.
F-6
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Investments
The Company follows accounting procedures according to Statement of
Financial Accounting Standards ("SFAS") No. 115, Accounting for Certain
Investments in Debt and Equity Securities. Under this standard, the equity
securities held by the Company that have readily determinable fair values are
classified as current or non-current assets, available-for-sale and are measured
at fair value. Unrealized gains and losses for these investments are reported as
comprehensive income and included as a separate component of stockholders'
equity. Realized gains and losses are calculated based on the specific
identification method.
At December 31, 2000, the Company's available-for-sale securities were
classified as non-current assets and included in deposits and other assets. The
securities had a cost basis of $2,762,000, gross unrealized losses reported in
accumulated other comprehensive income of $507,000 ($466,000 net of income tax
benefit) and had a fair market value of $2,255,000 based on the quoted market
price. At December 31, 2001, the Company determined that the securities had
suffered an other than temporary impairment as a result of the deteriorating
financial condition of the entity and a steadily declining market value of the
securities. As a result, at December 31, 2001, the Company reported a provision
for impairment of investments of $2,142,000 as a charge against earnings and a
reclassification in accumulated other comprehensive income of $507,000 ($466,000
net of income tax).
During 2000, the Company acquired a minority ownership interest in a
privately held entity that provides remote data collection and web-based
monitoring services for the company and other entities operating in the energy
industry. The total invested by the Company in 2000 was $2.5 million, and the
investment was carried at cost on the balance sheet at December 31, 2000. During
2001, the Company made an additional equity investment of $2 million as well as
secured loans totaling $453,000, including accrued interest. At December 31,
2001, the Company's total equity investment of $4,528,000 represented less than
10% of the entity's common equity. As a result of the entity's inability to
obtain additional anticipated equity financing from third parties at the end of
2001, the entity subsequently declared bankruptcy. The Company reported a
provision for impairment of investments of $4,981,000 as a charge against
earnings at December 31, 2001.
ESOP
As required under Statement of Position 93-6 "Employers' Accounting for
Employee Stock Ownership Plans," compensation expense is recorded for shares
committed to be released to employees based on the fair market value of those
shares when they are committed to be released. The difference between cost and
the fair market value of the committed to be released shares is recorded in
additional paid-in-capital. Unreleased shares held by the ESOP are excluded from
the calculation of earnings per share.
Suspended Revenues
Suspended revenue interests represent oil and gas sales payable to third
parties largely on properties operated by the Company. The Company distributes
such amounts to third parties upon receipt of signed division orders or
resolution of other legal matters.
Oil and Gas Producing Operations
Magnum Hunter follows the full-cost method of accounting for oil and gas
properties. Accordingly, all costs associated with acquisition, exploration and
development of oil and gas reserves, including directly related overhead costs,
are capitalized. Internal costs that directly relate to acquisition, exploration
and development activities that were capitalized totaled $600,000 for each of
the years ended December 31, 2001, 2000 and 1999, respectively. The balance of
capitalized costs included in oil and gas properties for the years ended
December 31, 2001 and 2000 were $3,279,000 and $2,679,000, respectively.
Management believes that the basis it uses to determine the amount of internal
costs capitalized is appropriate.
All capitalized costs of oil and gas properties, including the estimated
future costs to develop proved reserves and estimated dismantlement and
abandonment costs, net of salvage values, are amortized on the
unit-of-production method using estimates of proved reserves. Costs directly
associated with the acquisition and evaluation of unproved properties are
excluded from the amortization base until the related properties are evaluated.
Such unproved properties are assessed for impairment at least annually and any
provision for impairment is transferred to the full-cost amortization base.
Sales of oil and gas properties, including consideration received from sales or
transfers of properties in connection with partnerships, joint venture
operations or drilling arrangements, are credited to the full-cost pool unless
the sale would have a significant effect on the amortization rate. Abandonment
of properties is accounted for as an adjustment to capitalized costs with no
loss recognized.
F-7
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
A summary of the unproved properties excluded from oil and gas properties
being amortized at December 31, 2001 and 2000, respectively, and the year in
which they were incurred follows:
December 31, 2001
Incurred In
(in thousands)
------------------------------------------------
1998 1999 2000 2001 Total
---- ---- ---- ------- -------
Property Acquisition Costs... $ 513 $1,464 $ 360 $12,226 $14,563
Exploration Costs............ - - - 4,090 4,090
------------------------------------------------
Total................... $ 513 $1,464 $ 360 $16,316 $18,653
================================================
December 31, 2000
Incurred In
(in thousands)
-------------------------------------------------
Prior 1998 1999 2000 Total
----- ---- ---- ------ --------
Property Acquisition Costs.. $ - $ 1,397 $1,485 $1,080 $3,962
Exploration Costs........... - - - 1,572 1,572
-------------------------------------------------
Total.................. $ - $ 1,397 $1,485 $2,652 $5,534
=================================================
Costs are transferred into the amortization base on an ongoing basis as the
projects are evaluated and proved reserves are established or impairment
determined. Pending determination of proved reserves attributable to the above
costs, the Company cannot assess the future impact on the amortization rate.
The capitalized costs are subject to a "ceiling test," which generally
limits such costs less accumulated amortization and related deferred income
taxes to the aggregate of the estimated present value of future net revenues
from proved reserves discounted at ten percent based on current economic and
operating conditions less income tax effects related to the differences between
the book and tax basis of the oil and gas properties. The ceiling test is
performed on a quarterly basis. At December 31, 2001, the Company's capitalized
costs of its oil and gas properties exceeded the PV-10 limitation using prices
in effect at December 31, 2001 by $75,984,000. However, no write-down for
impairment of oil and gas properties was required as a result of the increase in
oil and gas prices subsequent to December 31, 2001. The Company experienced no
impairment in 2000 or 1999.
All costs relating to production activities are charged to expense as
incurred.
Amortization expense per thousand cubic feet equivalent was $1.28, $0.89
and $0.79 for the years ended December 31, 2001, 2000 and 1999, respectively.
Derivative Instruments
The Company's product price and interest hedging activities are described
in Note 13 to the consolidated financial statements. Periodically the Company
enters into futures, options, and swap contracts to reduce the adverse effects
of fluctuations in crude oil and gas prices on anticipated future oil and gas
production. It is the policy of the Company to not enter into any such
arrangements which cause the Company's aggregate hedge position to exceed 75% of
the oil and gas production during the projected next 12 months. We also utilize
financial derivative instruments to hedge the risk associated with interest on
our outstanding debt. Generally, the cash settlement of all derivative
instruments is recognized as income or expense in the period in which the hedged
transaction is recognized.
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133), as extended by
SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June 2000), was effective
for the Company beginning January 1, 2001. SFAS No. 133 establishes accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of derivatives in the balance sheet and the measurement of those
instruments at fair value. Derivative instruments that are not hedges must be
adjusted to the fair value through net income (loss). Under the provisions of
SFAS 133, changes in the fair value of derivative instruments that are fair
value hedges are offset against changes in the fair value of the hedged assets,
liabilities, or firm commitments, through net income (loss). Changes in the fair
value of derivative instruments that are cash-flow hedges are recognized in
other
F-8
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
comprehensive income (loss) until such time as the hedged items are
recognized in net income (loss). Ineffective portions of a derivative
instrument's change in fair value are immediately recognized in net income
(loss).
The Company was obligated to four crude oil derivatives, one natural gas
derivative, and one interest rate derivative on January 1, 2001. The Company
determined that the interest rate derivative did not qualify for hedge treatment
as defined within SFAS No. 133. The crude oil and natural gas derivatives
qualified as cash-flow hedges.
At January 1, 2001, all derivatives within the Company were identified
pursuant to SFAS No. 133 requirements, and the Company designated, documented
and assessed all hedging relationships. Adoption of this accounting standard
resulted in the recognition of $179 thousand of a derivative asset related to
the interest rate derivative and an increase in the carrying value of long-term
debt with recourse of $179 thousand. In June, 2001 the Company terminated its
position in this derivative. For the year ended December 31, 2001, the Company
recognized a gain of $980 thousand as a reduction of interest expense for this
derivative.
With respect to the cash-flow hedges, at the accounting change transition,
the Company recorded a derivative asset of $648 thousand related to the crude
oil derivatives with a cumulative effect increase to other comprehensive income
of $403 thousand (net of income taxes) and a derivative liability of $3.5
million related to the natural gas derivatives with a cumulative effect decrease
to other comprehensive income of $2.2 million (net of income taxes).
In May, 2001, the Company entered into additional costless collars for
crude oil for the periods July 2001 through December 2001. In August, 2001, the
Company entered into a swap transaction for natural gas for the periods
September 2001 through November 2001 and interest rate swaps (receive
variable/pay fixed) on $50 million of its variable rate bank debt for the period
August 2001 through August 2003. These crude oil, natural gas and interest rate
derivatives qualify as cash flow hedges.
At December 31, 2001, the Company had no crude oil derivatives, and its
natural gas derivatives had a fair value of $3.6 million, recognized as
derivative assets of $5.1 million and derivative liabilities of $1.5 million.
The Company recognized a liability of $1.0 million on its interest rate
derivatives. For the year ended December 31, 2001, the income statement includes
a gain of $1.3 million related to the crude oil derivatives, a gain of $3.4
million related to the natural gas derivatives and a loss of $204 thousand on
interest rate derivatives, net of amounts reclassified out of other
comprehensive income. The Company expects that the remaining balance in other
comprehensive income related to the natural gas derivatives at December 31, 2001
will be reclassified into the income statement within the next eighteen months
and for the interest rate derivatives within the next twenty months.
Pipelines and Processing Plant
Pipelines and processing plant are carried at cost. Depreciation is
provided using the straight-line method over an estimated useful life of 15
years. Gain or loss on retirement or sale or other disposition of assets is
included in results of operations in the period of disposition. The Company
reviews the carrying value of pipelines and processing plant and other
long-lived assets (other than oil and gas assets accounted for under the
full-cost method) for impairment whenever events and circumstances indicate that
the carrying value of an asset may not be recoverable from the estimated future
cash flows expected to result from its use and eventual disposition. In cases
where the undiscounted expected future cash flows are less than the carrying
value, an impairment loss is recognized equal to an amount by which the carrying
value exceeds the fair value of assets.
Other Property
Other property and equipment are carried at cost. Depreciation is provided
using the straight-line method over estimated useful lives ranging from five to
ten years. Gain or loss on retirement or sale or other disposition of assets is
included in results of operations in the period of disposition.
Other Oil and Gas Related Services
Other oil and gas related services consist largely of fees earned from the
Company's operation of oil and gas properties for third parties. Such fees are
recognized in the month the service is provided.
Magnum Hunter does not recognize income in connection with drilling, well
service or other services provided in connection with
F-9
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
oil and gas properties in which the Company holds an ownership or other
economic interest to the extent of the Company's interest. Any proceeds received
for services performed that are not recognized as income are credited to the
full cost pool.
Income Taxes
The Company files a consolidated federal income tax return. Income taxes
are provided for the tax effects of transactions reported in the financial
statements and consist of taxes currently due, if any, plus net deferred taxes
related primarily to differences between the basis of assets and liabilities for
financial and income tax reporting. Deferred tax assets and liabilities
represent the future tax return consequences of those differences which will
either be taxable or deductible when the assets and liabilities are recovered or
settled. Deferred tax assets include recognition of operating losses that are
available to offset future taxable income and tax credits that are available to
offset future income taxes. Valuation allowances are recognized to limit
recognition of deferred tax assets where appropriate. Such allowances may be
reversed when circumstances provide evidence that the deferred tax assets will
more likely than not be realized.
New Accounting Standards
SFAS No. 141 - SFAS No. 141, "Business Combinations", is effective for the
Company beginning July 1, 2001. SFAS No. 141 requires the use of the purchase
method of accounting for business combinations initiated and completed after
June 30, 2001 and eliminates the use of the pooling-of-interests method. As of
July 1, 2001, the adoption of SFAS No. 141 did not have an impact on the
Company's consolidated financial statements.
SFAS No. 142 - SFAS No. 142, "Goodwill and Other Intangible Assets", will
be effective for the Company beginning January 1, 2002. SFAS No. 142 requires,
among other things, the discontinuance of goodwill amortization. Any goodwill
resulting from acquisitions completed after June 30, 2001 will not be amortized.
In addition, SFAS No. 142 requires the Company to complete a transitional
goodwill impairment test within six months from the date of adoption and
establishes a new method of testing goodwill that could reduce the fair value of
a reporting unit below its carrying value. Any goodwill impairment loss during
the transition period will be recognized as the cumulative effect of a change in
accounting principle. Subsequent impairments will be recorded in operations. The
adoption of SFAS No. 142 will not have a material impact on the Company's
consolidated financial statements.
SFAS No. 143 - SFAS No. 143, "Accounting for Asset Retirement Obligations",
will be effective for the Company beginning January 1, 2003. SFAS No. 143
requires the recognition of a fair value liability for any retirement obligation
associated with long- lived assets. The offset to any liability recorded is
added to the recorded asset where the additional amount is depreciated over the
same period as the long-lived asset for which the retirement obligation is
established. SFAS No. 143 also requires additional disclosures. The Company is
in the process of evaluating the impact of the provisions of SFAS No. 143.
SFAS No. 144 - SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets", will be effective for the Company beginning January 1, 2002.
SFAS No. 144 establishes a single accounting model, based on the framework
established in SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of", for long-lived assets to be
disposed of by sale and resolves significant implementation issues related to
SFAS No. 121. The Company is in the process of evaluating the impact of the
provisions of SFAS No. 144.
Income or Loss Per Common Share
Basic net income or loss per common share is computed by dividing the net
income or loss attributable to common stockholders by the weighted average
number of shares of common stock outstanding during the period. Diluted net
income or loss per common share is calculated in the same manner, but also
considers the impact to net income and common shares for the potential dilution
from stock options, stock warrants and any other outstanding convertible
securities.
The following table reconciles the numerators and denominators used in the
computations of both basic and diluted EPS as
F-10
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
required by SFAS No. 128, "Earnings per Share":
For the Year Ended For the Year Ended For the Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
-----------------------------------------------------------------------------------------------------
Per Per Per
Income Shares Share Income Shares Share Loss Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------------------------------------------------------------------------------------------------
Income (Loss) before
Extraordinary Item........ $13,820,000 34,819,614 $0.40 $22,260,000 20,856,854 $1.07 $ (6,826,000) 19,743,738 $(0.34)
Net Income (Loss).............. (304,000) (0.01) - - - -
Less: Preferred Stock
dividends............... $13,516,000 $22,260,000 $ (6,826,000)
Net Income (Loss).............. $22,260,000 $ (6,826,000)
Less: Preferred Stock
dividends........... - - (9,708,000) $(0.47) (4,509,000) $(0.23)
----------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available to
common stockholders....... $13,516,000 34,819,614 $0.39 12,552,000 20,856,854 $0.60 (11,335,000) 19,743,738 $(0.57)
Effect of dilutive securities
Warrants.................... 212,512 - 571,623 - -
Options..................... 2,076,850 - 1,247,063 - -
Convertible preferred stock. - 4,312,000 10,158,730 - -
Diluted EPS
Income (Loss) available to
common stockholders and -----------------------------------------------------------------------------------------------------
assumed conversions...... $13,516,000 37,108,976 $0.36 $16,864,000 32,834,270 $0.51 $(11,335,000) 19,743,738 $(0.57)
=====================================================================================================
Add back: Extraordinary
Item.................. (304,000) (0.01) - - - -
----------------------------------------------------------------------------------------------------
Income (Loss) before
Extraordinary Item...... $13,820,000 $0.37 $16,864,000 $0.51 $(11,335,000) $(0.57)
=====================================================================================================
For the year ended December 31, 2001, basic and diluted EPS includes the
effect of an extraordinary loss from early extinguishment of debt of $304,000,
or $(.01) per share.
At December 31, 2001, the Company had outstanding 644,749 warrants at a
weighted average price of $6.75 per share, 5,217,584 options at a weighted
average exercise price of $6.22 per share, and no outstanding convertible
preferred stock. Warrants totaling 432,237 shares and options totaling 3,140,734
shares were excluded from the diluted net income per share computation in 2001
as the exercise price exceeded the average market price of the Company's common
stock.
At December 31, 2000, the Company had outstanding 644,749 warrants at a
weighted average price of $6.75 per share, 4,702,400 options at a weighted
average exercise price of $4.97 per share, and 25,000 shares of preferred stock
convertible to common stock at a weighted average conversion price of $5.25 per
share. Warrants totaling 73,126 shares and options totaling 3,455,337 shares
were excluded from the diluted net income per share computation in 2000 as the
exercise price exceeded the average market price of the Company's common stock.
At December 31, 1999, the Company had outstanding 10,583,149 warrants at a
weighted average price of $6.49 per share, 3,866,092 options at a weighted
average exercise price of $3.57 per share, and 1,050,000 shares of preferred
stock convertible to common stock at a weighted average conversion price of
$5.25 per share. The warrants, options and preferred stock were not included in
the computation of diluted earnings per share in 1999 since the Company incurred
a net loss for the year and any effect would have been anti-dilutive.
Revenue Recognition
Revenues are recognized when title to the product transfers to purchasers.
The Company follows the "sales method" of accounting for revenue for oil and
natural gas production, so that sales revenue is recognized on all production
sold to purchasers, regardless of whether the sales are proportionate to the
Company's ownership in the property. A receivable or liability is recognized
only to the extent that we have an imbalance on a specific property greater than
the expected remaining proved reserves. Ultimate revenues from the sales of oil
and gas production is not known with certainty until up to three months after
production and title transfer occur. Current revenues are accrued based on
expectations of actual deliveries and actual prices received.
F-11
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Inflation and Changes in Prices
The results of operations and cash flow of the Company have been, and will
continue to be, affected by the volatility in oil and gas prices. Should the
Company experience a significant increase in oil and gas prices that is
sustained over a prolonged period, it would expect that there would also be a
corresponding increase in oil and gas finding costs, lease acquisition costs,
and operating expenses.
The Company markets oil and gas for its own account, which exposes the
Company to the attendant commodities risk. A significant portion of the
Company's gas production is currently sold to a 30% owned affiliate, NGTS, LLC,
or end-users either (i) on the spot market on a month-to-month basis at
prevailing spot market prices or (ii) under long-term contracts based on current
spot market prices. The Company normally sells its oil under month-to-month
contracts to a variety of purchasers.
Use of Estimates and Certain Significant Estimates
The preparation of the Company's financial statements in conformity with
accounting principles generally accepted in the United States of America
requires the Company's management to make estimates and assumptions that affect
the amounts reported in these financial statements and accompanying notes.
Actual results could differ from those estimates. Significant assumptions are
required in the valuation of proved oil and gas reserves, which as described
above may affect the amount at which oil and gas properties are recorded. It is
at least reasonably possible those estimates could be revised in the near term
and those revisions could be material.
Treasury Stock
The Company may repurchase shares of common stock in stock repurchase
programs. The Company's repurchases of shares of common stock are recorded as
Treasury Stock at cost and result in a reduction of Stockholders' Equity. When
treasury shares are reissued, the Company uses a first-in first-out method and
the difference between repurchase cost and reissuance price is treated as an
adjustment to paid-in capital.
NOTE 2 -- ACQUISITIONS AND DISPOSITIONS
On June 10, 1999, the Company and Bluebird acquired from Vastar Resources,
Inc., interest in oil and gas reserves producing from 476 wells, a gas
processing plant and two gas gathering systems located in the states of Texas,
Oklahoma and Arkansas for a purchase price of $32.5 million after purchase price
adjustments. The effective date of the transaction was April 1, 1999.
On December 1, 1999, Bluebird acquired a 50% interest in the Madill Gas
Processing Plant and associated gas gathering system from Dynegy Inc. for a
purchase price of $4.1 million after purchase price adjustments. The effective
date of the transaction was November 1, 1999.
The following summary, prepared on a pro forma basis, presents the results
of operations for the year ended December 31, 1999 as if the acquisitions
occurred as of the beginning of the year. The pro forma information includes the
effects of adjustments for increased general and administrative expense,
interest expense, depreciation, depletion and income taxes:
(Unaudited)
--------------------------
(in thousands, except for
per share amounts)
--------------------------
Revenue.............................................. $ 73,104
Net Income (Loss) Applicable to Common Stock......... (12,022)
Net Income (Loss) Per Common Share
Basic.............................................. $ (0.61)
Diluted............................................ $ (0.61)
Effective September 1, 2000 the Company acquired a 5.5% net profits
interest in the Panoma production and gas gathering facilities for $3.5 million
of the Company's restricted common stock. By acquiring this interest, the
Company lowered its lease operating expense and increased oil field services
income.
F-12
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Effective April 1, 2000 the Company exchanged interests in certain onshore
oil producing properties for interests in certain offshore oil and gas producing
properties and production facilities located in the Gulf of Mexico in a tax free
like-kind exchange. The transaction did not have a material effect on reported
production in 2000, but the Company gained significantly increased exposure in
an offshore area of interest where it has been conducting exploration and
development activities.
During 2000, the Company realized proceeds of $43.8 million from the sale
of non-core oil and gas and other properties, of which approximately $11.6
million was attributable to Bluebird.
Effective July 1, 2001, the Company acquired proved oil and gas properties
located in Southeast New Mexico totaling approximately 41.8 Bcfe of reserves for
$31.6 million, net of purchase price adjustments. The transaction had an
effective date of July 1, 2001.
NOTE 3 -- NOTES RECEIVABLE
At December 31, 2000, the balance of a note receivable, net of allowance of
$1,170,000, was $50,000. During 2001, the Company received a payment of $50,000
to apply against this note.
NOTE 4 -- RELATED PARTY TRANSACTIONS
In conjunction with the acquisition of Hunter in December 1995, the Company
assumed a note receivable with a balance of $379,321 from an owner in an
affiliated limited liability company. The note provides for interest at 10
percent and had a due date of December 31, 2000. The note was not paid by the
due date, and the Company has commenced legal proceedings in order to recover
the amount due. The note is secured by interest in a real estate joint venture.
At December 31, 2001 and 2000, the Company's note receivable from the
Magnum Hunter Employee Stock Ownership Plan (ESOP) was $2,576,000 and
$2,780,000, respectively. The purpose of the loan is to allow the ESOP to
purchase Magnum Hunter Resources common stock on the open market. The loan is
interest free, due December 31, 2004 and is secured by shares of the Company's
common stock which have not been earned by participants in the ESOP. At December
31, 2001 and 2000, the number of unearned shares in the ESOP were 468,652 and
680,282, respectively. The unearned shares and their corresponding costs were
reflected on the consolidated balance sheets of the Company as reductions to
stockholders' equity.
During 1998, the Company's Board of Directors authorized the acquisition of
certain shares of a publicly traded oil and gas company from Mr. Gary C. Evans,
President and Chief Executive Officer of the Company, at Mr. Evans' cost basis
in such shares of stock for purposes of a long-term investment. The shares were
purchased for a total of $442,019. The Company has the right to cause Mr. Evans
to repurchase the shares back from the Company at the equivalent price that the
Company purchased the shares from Mr. Evans. The value paid for the shares was
in excess of the publicly traded value of the shares on the acquisition date by
$159,481. For accounting purposes, the purchase price of the shares was treated
as a receivable from stockholder and has been shown as a reduction to
stockholders' equity at December 31, 2001, 2000 and 1999.
During December 1998, the Company's Board of Directors authorized a loan of
up to $300,000 be made available to Mr. Evans, as part of his 1998 compensation
package and to exercise certain stock options. A total of $230,000 was drawn
under the loan and was outstanding at December 31, 1998. During the year ended
December 31, 1999, the Company advanced an additional $188,000 and was repaid
$65,000, leaving a balance due the Company, including accrued interest, of
$371,860 at December 31, 1999, which was authorized by the Board of Directors.
The unpaid principal amount of these loans was classified as a loan to
stockholder at December 31, 1999 and 1998 and as a reduction to stockholders'
equity. On January 7, 2000, Mr. Evans repaid $225,000 on the loan, leaving a
principal balance of $146,860. On April 17, 2000 Mr. Evans re-borrowed $100,000
under this loan, and on August 18, 2000, he repaid $258,731, including accrued
interest, bringing the balance to zero. On December 28, 2000, Mr. Evans borrowed
$294,938, which was the balance owed to the Company on December 31, 2000 and
included in notes receivable from affiliate. On January 15, 2001, Mr. Evans
repaid $295,261, including accrued interest, bringing the balance to zero. On
April 16, 2001, the Company loaned Mr. Evans $300,000, under an authorization by
the Board of Directors, on a note with an interest rate of 10% and due December
31, 2001. At year end, this loan was classified as a note receivable from
affiliate. Subsequent to year end, Mr. Evans repaid $328,931, including accrued
interest, bringing the principal and interest balance to zero.
F-13
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On November 28, 2000, Mr. Matthew C. Lutz, then the Chairman and Executive
Vice President of the Company, borrowed $65,000 from the Company with the
approval of the Board of Directors. On January 15, 2001, Mr. Lutz repaid the
loan, including accrued interest.
NOTE 5 -- DEBT
Notes payable and long-term debt at December 31, 2001 and 2000 consisted of
the following:
2001 2000
(in thousands)
----------------------------------
Notes Payable:
Note payable to vendor, due January 31, 2002, interest at 7% payable
on due date (a)........................................................ $ 2,532 $ -
Note payable to vendor, due February 28, 2002, interest at 7% payable
on due date (a)............................................................ 1,512 -
------------------------------------
Total Notes Payable......................................... $ 4,044 $ -
====================================
Long-Term Debt, with recourse to the Company:
Banks
Revolving promissory note, collateralized by pipeline and oil and gas
properties, due April 30, 2003 (effective rate of 4.7% and 8.5% at
December 31, 2001 and 2000, respectively) (b)....................... $155,000 $ 30,500
Other
Senior notes, unsecured, due June 1, 2007, interest at 10% payable
semi-annually on June 1 and December 1................................... 140,000 140,000
Less: Notes re-purchased and held in treasury (10,534) -
------------------------------------
Net Senior notes outstanding 129,466 140,000
------------------------------------
Other...................................................................... 73 39
------------------------------------
Total Long-Term Debt, with recourse $284,539 $ 170,539
73 19
Less Current Portion...................................... -----------------------------------
Long-Term Debt, with recourse..................................... $284,466 $ 170,520
====================================
Long-Term Debt, non recourse to the Company:
Banks
Revolving promissory note, collateralized by pipeline and oil and gas properties
and 1,840,270 units of TEL Offshore Trust, due June 7,
2002 (effective rate of 9.48% at December 31, 2000) (c)................ $ - $ 20,600
----------------- ---------------
Total Long-Term Debt, non recourse................................ $ - $ 20,600
================== ==============
F-14
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Maturities of long-term debt based on contractual requirements for the
years ending December 31, are as follows:
(in thousands)
2002.................................. 73
2003.................................. 155,000
2004 to 2006.......................... -
2007.................................. 129,466
------------------
Total........................ $ 284,539
==================
(a) The due dates on the notes payable to vendors was extended to March 15,
2002. On that date, both notes were paid off.
(b) The revolving promissory note to the banks is a borrowing under a
$225,000,000 line of credit on which there existed a borrowing base of
$160,000,000 at December 31, 2001. The level of the borrowing base is dependent
on the valuation of the assets pledged, primarily oil and gas reserve values.
The line of credit includes covenants, the most restrictive of which requires
maintenance of a current ratio, interest coverage ratio, and tangible net worth,
as specified in the loan agreement. The bank group must approve all dividends
paid on common stock. The credit agreement provides for both "LIBOR" and "Base
Rate" (Prime) interest rate options. At December 31, 2001, the amounts borrowed
at these rates were:
(in thousands)
LIBOR + 2.5% (total of 4.64%)................ $ 145,000
Base Rate (Prime) + 1.0% (total of 5.75%).... 10,000
--------------------
Total................................. $ 155,000
====================
(c) The revolving promissory note to the banks was borrowing under a
$75,000,000 line of credit on which there existed a borrowing base of
$42,000,000 at December 31, 2000. The level of the borrowing base was dependent
on the valuation of the assets pledged, primarily oil and gas reserves, natural
gas processing plants, and units of Tel Offshore Trust. On May 17, 2001, the
loan under this line of credit was repaid in full and the line of credit was
terminated.
NOTE 6 -- PRODUCTION PAYMENT LIABILITY
In November, 1996, the Company entered into a production payment
conveyance. The Company received a production payment amount of $750,000 and
agreed to make royalty payments of up to 50% of the monthly net revenue proceeds
received from certain oil and gas properties. The balance owed under the
conveyance was $203,000 and $359,000 at December 31, 2001 and 2000,
respectively. The production payment bears interest at the rate of 13.5% per
annum and is non-recourse to the Company.
NOTE 7 -- INCOME TAXES
The Company accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes", which requires the recognition of a liability or
asset, net of a valuation allowance, for the deferred tax consequences of all
temporary differences between the tax bases and the reported amounts of assets
and liabilities, and for the future benefit of operating loss carryforwards. The
following is a reconciliation of income tax expense reported in the statement of
operations:
2001 2000 1999
(in thousands)
-----------------------------------------------------
Income tax expense (benefit) at statutory rates......... $ 7,850 $ 10,191 $ (2,352)
State tax expense (benefit)............................. 818 829 (193)
Increase in operating loss and other carryovers......... (493) - -
Change in valuation allowance........................... - (3,875) 2,315
Other................................................... 433 410 230
-----------------------------------------------------
Tax expense...................................... $ 8,608 $ 7,555 $ -
=====================================================
F-15
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The tax effects of significant temporary differences and carryforwards are
as follows:
December 31,
--------------------------------------------
2001 2000
(in thousands)
--------------------------------------------
Property and equipment, including intangible drilling costs........... $ (38,005) $ (18,855)
Derivative instruments................................................ (995) -
Other................................................................. (41) -
---------------------------------------------
Total deferred tax liability................................. $ (39,041) $ (18,855)
Allowance for doubtful accounts....................................... 3,125 577
Reserves.............................................................. 33 33
Depletion carryforwards............................................... 1,003 510
Alternative minimum tax credit........................................ 98 234
Employee stock options................................................ 2,350 -
Operating loss and other carryforwards................................ 38,034 30,219
--------------------------------------------
Total deferred tax assets.................................... 44,643 31,573
--------------------------------------------
Valuation allowance................................................... (7,100) (7,100)
--------------------------------------------
Net Deferred Tax Asset (Liability)........................... $ (1,498) $ 5,618
=============================================
The Company and its subsidiaries have net operating loss carryforwards of
approximately $105,912,000 that expire, if unused, in years 2009 through 2021.
Current tax laws and regulations relating to specified changes in ownership
limit the utilization of the Company's net operating loss and tax credit
carryforwards. A change in ownership of greater than 50% of a corporation within
a three year period causes the annual limitations to be placed in effect. Such a
change is deemed to have occurred February 3, 1999 in connection with the
purchase of preferred stock by ONEOK Resources Company, which has subsequently
been either redeemed or converted to common stock. Approximately $556,000 of the
net operating losses are subject to a limitation of $556,000 per year and
$50,857,000 are subject to a limitation of $7,850,000 per year. In addition, the
Company has depletion carryforwards of $2,648,000 with no expiration period. A
valuation allowance reduces deferred taxes based on the criteria set forth in
SFAS 109.
NOTE 8 -- STOCKHOLDERS' EQUITY
Preferred Stock
Shares of preferred stock may be issued in such series, with such
designations, preferences, stated values, rights, qualifications or limitations
as determined solely by the Board of Directors. Of the 10,000,000 shares of
$.001 par value preferred stock the Company is authorized to issue, 216,000
shares have been designated as Series A Preferred Stock,1,000,000 shares have
been designated as 1996 Series A Convertible Preferred Stock and 50,000 shares
have been designated as 1999 Series A 8% Convertible Preferred Stock. Thus,
8,734,000 preferred shares have been authorized for issuance but have not been
issued nor have the rights of these preferred shares been designated. No
dividends can be paid on the common stock until the dividend requirements of the
preferred shares have been satisfied. The preferred shareholders are not
entitled to vote except on those matters in which the consent of the holders of
preferred stock is specifically required by Nevada law. If the Company were to
liquidate prior to payment of the full dividend requirements on the preferred
stock, the preferred stock would receive a liquidation preference from the
liquidation proceeds. On liquidation, holders of all series of the preferred
stock would be entitled to receive the par value, $.001 per share, in preference
to the common stock shareholders.
Dividend payments and preferential rights to Series A preferred
shareholders are tied to wells that have been plugged and abandoned. The
liquidation value of the Series A Preferred Stock is $216.
On December 23, 1996, the Company issued 1,000,000 shares of new Series A
preferred stock, known as the 1996 Series A Convertible Preferred Stock, in a
private placement, resulting in net proceeds to the Company after offering costs
of $9,280,000. Dividends of $438,000 and $875,000 and were declared in 2000 and
1999, respectively. On June 30, 2000 the holders of the 1996 Series A
Convertible Preferred stock agreed to exchange the convertible preferred
securities for 900,000 warrants to purchase restricted common shares of the
Company's stock at an exercise price of $5.25 per share with an expiration date
of June 3, 2003 and payment of $10,000,000. The convertible preferred shares are
currently listed as issued but held by Bluebird as of December 31, 2001.
F-16
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On February 3, 1999, the Company sold 50,000 shares of its 1999 Series A 8%
Convertible Preferred Stock for $50 million in a private placement. The
Preferred Stock had a liquidation value of $50 million and was convertible into
the Company's Common Stock at $5.25 per share. Dividends on the Preferred Stock
were payable in cash at the rate of 8% per annum and were cumulative. The
Company used the net proceeds from the transaction, approximately $46.3 million,
to repay senior bank debt. Dividends of $3,874,000 and $3,634,000 were declared
in 2000 and 1999, respectively. $169,000 of the 2000 dividends were paid in
January 2001. On December 7, 2000, the Company redeemed 25,000 shares of the
Preferred stock for a cash payment of $30,540,000, which included a redemption
premium of $5,540,000. The redemption premium was included in dividends
applicable to preferred stock in the Company's consolidated statement of
operations and comprehensive income in 2000.
Warrants
The following is a summary of warrant activity for the periods ended
December 31, 2001, 2000 and 1999:
2001 2000 1999
------------------------------------------------------------------------------------------------
Number of Weighted Number of Weighted Number of Weighted
Warrants Average Warrants Average Warrants Average
Exercise Price Exercise Price Exercise Price
-------------- ------------------------------- -------------------------------------------------
Outstanding - Beginning of 644,749 $ 6.75 10,608,150 $ 6.49 156,000 $ 4.62
Year
Issued - 900,000 5.25 10,512,150 6.50
Exercised - (9,413,136) 6.37 -
Redeemed - (1,429,264) 0.01 -
Expired - (21,000) - (60,000) -
-------------- ------------------------------- -------------------------------------------------
Outstanding - End of Year 644,749 $ 6.75 644,749 $ 6.75 10,608,150 $ 6.49
The new warrants in 1999 were issued in connection with a redemption of
1996 Series A Convertible Preferred Stock and 1999 Series A 8% Convertible
Stock.
The new warrants in 2000 were issued in connection with a redemption of
1996 Series A Convertible Preferred Stock.
On November 27, 2000, the Board of Directors allowed a total of 644,749
warrants held by certain key officers and directors of the Company, with an
exercise price of $6.50 per share and an expiration date of June 30, 2000, to be
exchanged for an equal number of new warrants with an exercise price of $6.75
per share expiring on December 31, 2003. The exercise price of the new warrants
was fair market value on the date of the new grant.
On December 5, 2001, the Company announced that a distribution of one
warrant for every five shares of common stock owned on January 10, 2002. These
warrants were distributed on March 21, 2002. Each new warrant will entitle the
holder to purchase one share of common stock at $15. The warrants will expire
three years from the date of distribution.
Common Stock
The Company has a Shareholder Rights Plan, under which the Rights initially
represent the right to purchase one one-hundredth of a share of 1998 Series A
Junior Participating Preferred Stock for $35.00 per one one-hundredth of a
share. The Rights become exercisable only if a person or a group acquires or
commences a tender offer for 15% or more of the Company's common stock. Until
they become exercisable, the Rights attach to and trade with the Company's
common stock. The Rights expire January 20, 2008.
On February 17, 1999, the Company revised its previously announced stock
repurchase program to spend up to $4 million without a share limitation. During
1999, the Company repurchased 601,472 shares of its common stock for $1.7
million. Additionally
F-17
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
in 1999, 41,115 shares of the Company's common stock were contributed to
the 401(k) plan, 102,145 shares were issued upon exercise of employee stock
options, 338,900 shares were purchased by the ESOP and 51,808 shares were
released by the ESOP to participants.
In April 2000, the Company announced a stock repurchase program whereby the
Company or its affiliates were authorized to repurchase up to an additional 5%
of the Company's outstanding common stock. In May 2000, Bluebird purchased
129,032 shares of the Company's common stock for approximately $500,000. On
December 22, 2000 the Company acquired a 5.5% net profits interest in the Panoma
properties and gas gathering system for $3,480,418 through the issuance of
356,966 of restricted common stock. Additionally in 2000, shares totaling
656,392 were issued upon exercise of employee stock options for net proceeds of
$2,413,336; shares totaling 9,140,408 were issued upon exercise of warrants
(including 177,272 shares issued in a cashless exercise and 164,946 shares
exercised by the Company's ESOP) for net proceeds of $57,556,569; shares
totaling 118,916 were purchased by the ESOP (other than the 164,946 obtained by
exercise of warrants) for $519,948; and shares totaling 141,095 were released by
the ESOP to participants.
Effective January 1, 2001, the holder of the Company's remaining $25
million principal amount of Magnum Hunter 1999 Series A 8% convertible preferred
stock converted into 4,761,904 common shares. On June 11, 2001, the Company
announced a stock repurchase program to repurchase up to one million shares of
the Company's common stock. Through December 31, 2001, Bluebird had repurchased
115,950 shares under this program for $1,015,000. Additionally in 2001, shares
totaling 1,124,616 were issued upon exercise of employee stock options for net
proceeds of $4,865,000; shares totaling 52,479 were contributed to the Company's
401(K) plan; shares totaling 72,900 were issued to the public for net proceeds
of $734,000; shares totaling 317,080 were released by the KSOP to participants;
$1,094,000 of KSOP loans were repaid to the Company; and the Company loaned the
KSOP $890,000 to purchase 105,450 shares.
NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION
During 2001, the Company contributed 52,479 shares valued at $151,000 to
the Company's 401(K) plan. In accordance with SFAS 115, the Company wrote-up the
carrying costs of its marketable investments by $507,000 ($466,000 after income
tax expense). Interest paid on the Company's outstanding indebtedness during
2001 was $19,037,000. Tax paid in 2001 was $716,000.
During 2000, the Company purchased oil and gas properties by issuing
356,966 restricted common shares valued at $3,480,418. In accordance with SFAS
115, the Company wrote-up the carrying costs of its marketable investments by
$2,006,986 ($1,246,840 after income tax expense). Interest paid on the Company's
outstanding indebtedness during 2000 was $21,661,000. The Company paid no taxes
in 2000.
During 1999, the Company contributed 41,115 shares valued at $123,000 to
the Company's 401(k) plan. In accordance with SFAS 115, the Company wrote down
the carrying costs of its marketable investments by $617,000. Interest paid on
the Company's outstanding indebtedness during 1999 was $19,773,000. The Company
paid no taxes in 1999.
NOTE 10 -- ENVIRONMENTAL ISSUES
Being engaged in the oil and gas exploration and development business, the
Company may become subject to certain liabilities as they relate to
environmental clean up of well sites or other environmental restoration
procedures as they relate to the drilling of oil and gas wells and the operation
thereof. In the Company's acquisition of existing or previously drilled well
bores, the Company may not be aware of what environmental safeguards were taken
at the time such wells were drilled or during the time that such wells were
operated. Should it be determined that a liability exists with respect to any
environmental clean-up or restoration, the liability to cure such a violation
would most likely fall upon the Company. In certain acquisitions, the Company
has received contractual warranties that no such violations exist, while in
other acquisitions, the Company has waived its rights to pursue a claim for such
violations from the selling party. No claim has been made nor has a claim been
asserted, nor is the Company aware of the existence of any material liability
which the Company may have, as it relates to any environmental clean-up,
restoration or the violation of any rules or regulations relating thereto.
F-18
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 11 -- COMMITMENTS AND CONTINGENCIES
The Company has certain lease agreements for the use of office space,
office equipment, and vehicles. The office space lease extends through November
2005 with an option to renew the lease for a three year term. The various office
equipment leases extend until 2004. The various vehicle leases extend until
2006. The leases have been classified as operating leases. The following is a
schedule by years of future minimum lease payments required under the operating
lease agreements:
Year Ended December 31:
2002................................... $1,037,425
2003................................... 949,484
2004................................... 890,714
2005................................... 735,318
2006................................... 119,035
Thereafter............................. -
--------------------
Total Minimum Payments Required....... $3,731,976
====================
Rental expense was $582,305, $717,636 and $367,000, for 2001, 2000 and
1999, respectively.
The Company's existing Revolving Loan Agreement with certain banks permit
guarantees of NGTS, LLC's indebtedness, not to exceed $4,000,000, and trade
payables or letters of credit for the purchase of natural gas not to exceed an
aggregate of $15,000,000 on behalf of NGTS, LLC. As of December 31, 2001 and
2000, there was no NGTS, LLC debt outstanding that the Company guaranteed.
NOTE 12 -- FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK
Financial instruments that subject the Company to credit risk consist
principally of accounts and notes receivable. The receivables are primarily from
companies in the oil and gas business or from individual oil and gas investors.
These parties are primarily located in the Southwestern regions of the United
States. No single receivable is considered to be sufficiently material as to
constitute a concentration. During the year ended December 31, 2001, the Company
provided an addition to the allowance for doubtful accounts of $3,214,000,
including $3,156,000 related to Enron. The Company does not ordinarily require
collateral, but in the case of receivables for joint operations, the Company
often has the ability to offset amounts due against the participant's share of
production from the related property. The Company believes the allowance for
doubtful accounts at December 31, 2001 is adequate.
To the extent the Company receives the spread between the contract floor
and the Index price applied to related contract volumes, the Company has a
credit risk in the event of nonperformance of the counterparty to the agreement.
The Company does not anticipate any material impact to its results of operations
as a result of nonperformance by such parties.
Management estimates the market values of notes receivable and payable
based on expected cash flows. At December 31, 2001 and 2000, the Company had
provided a reserve for the carrying value of a note receivable of $1,170,000 and
$790,000, respectively. After establishing this reserve, management believes
those market values approximate carrying values at December 31, 2001 and 2000.
The market values of equity investments are based upon quoted prices (see Note
1). At December 31, 2001, the fair value of the Company's debt was equal to its
carrying value, except for the 10% Senior Notes. The fair value of the 10%
Senior Notes was $130,113,000.
NOTE 13 -- COMMODITY DERIVATIVES AND HEDGING ACTIVITIES
Crude Oil and Natural Gas Hedges
Periodically, the Company enters into futures, options, and swap contracts
to mitigate the effects of significant fluctuations in crude oil and gas prices.
At December 31, 2001, the Company had the following open contracts:
Type Volume/Day Duration Wtd. Avg. Price
------------- ---------------- -------------- ------------------
Gas
- ------
Swap....... 60,000 MMBtu Jan 02 - Dec 02 $ 2.87
Swap....... 50,000 MMBtu Jan 03 - Jun 03 $ 2.88
F-19
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Based on future market prices at December 31, 2001, the fair value of open
contracts to the Company was a net asset of $3.6 million.
Net gains (losses) related to crude oil and natural gas derivative
transactions for the years ended December 31, 2001, 2000 and 1999 were
$4,629,000, $(11,179,000) and $(3,232,000), respectively.
Interest Rate Swaps
On June 30, 1999, the Company entered into two interest rate swaps in order
to shift a portion of its fixed rate bond debt to floating rate debt, to
capitalize on what was perceived as a market overreaction to pending interest
rate increases by the Federal Reserve, and to effectively lower interest rate
expense over the following twelve months. On June 1, 2000, one of the interest
rate swaps terminated. The Company terminated the remaining interest rate swap
in June, 2001.
On August 9, 2001, the Company entered into two interest rate swaps in
order to shift a portion of its variable rate bank debt to fixed rate debt. The
following table reflects the terms of these swaps.
Type Notional Amount Termination Date Pay Rate Receive Rate
------ --------------- ---------------- -------- ------------
Pay Fixed/Receive Variable $50,000,000 8/23/03 4.25 % Fixed 3 month
LIBOR rate
currently 2.195%
The rate the Company receives will be reset every three months to exactly
match the rate the Company will pay on $50.0 million of its outstanding
LIBOR-based bank debt.
The Company's total fixed rate debt outstanding at December 31, 2001 was
approximately $129.5 million.
Based on future market rates at December 31, 2001, the fair value of open
contracts to the Company was a liability of $1.0 million.
Net gains (losses) related to interest rate derivative transactions for the
years ended December 31, 2001, 2000 and 1999 were $744,000, $(13,000), and
$209,000, respectively.
NOTE 14 -- STOCK COMPENSATION PLANS
The Company has three stock compensation plans for its employees and
directors, (i) the Magnum Hunter Resources 401(k) Employee Stock Ownership Plan,
(the "KSOP"), (ii) the Magnum Hunter Resources, Inc. 1996 Incentive Stock Option
Plan (the "1996 Option Plan"), and (iii) the Magnum Hunter Resources, Inc. 2001
Incentive Stock Option Plan (the "2001 Option Plan"). In addition, the Company
has made non-incentive stock option grants in 2001, 2000 and 1999.
KSOP
The Company established an ESOP and a related trust in 1996 as a long-term
benefit for its employees. On January 1, 2001, the ESOP was merged with the
401(k) plan to form the KSOP. Under terms of the KSOP, eligible participants may
choose to make elective deferred contributions of not less than 1% or more than
15% of their annual compensation, limited in combination with the 401(k) plan to
the maximum allowable per year by the Internal Revenue Code. Company
contributions to the KSOP are made on a discretionary basis. It is also the
Company's intent to invest all contributions in the Company's Common Stock. All
employees who have reached the age of 21 and with one year of service are
eligible to participate in the plan. Shares purchased by the KSOP with loans
from the Company are released to participants as Company contributions and
participant salary deferrals are made and the related loans are repaid. The
Company has no repurchase obligations with respect to released shares.
F-20
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
During 1999, the Company loaned the KSOP $1,030,365 to purchase 338,900
shares of the Company's Common Stock on the open market at an average price of
$3.04 per share. At December 31, 1999, the Company contributed $150,782 to the
KSOP as a discretionary contribution under the plan. The KSOP then repaid that
portion of its outstanding loan from the Company and 51,808 shares were
allocated among the plan participants.
During 2000, the Company loaned the KSOP $1,592,098 to purchase 118,916
shares of the Company's common stock on the open market at an average price of
$4.37 per share and to exercise 164,946 warrants at a price of $6.50 per share.
On December 8, 2000, the Company contributed $448,454 to the KSOP as a
discretionary contribution under the plan. The KSOP then repaid that portion of
its outstanding loan from the Company and shares were allocated among the plan
participants.
During 2001, the Company loaned the KSOP $890,095 to purchase 105,450
shares of the Company's common stock on the open market at an average price of
$8.44 per share. During 2001, employees purchased 346,084 shares of the KSOP's
unreleased shares of $3.18 per share through salary deferrals and transfers from
the 401(k). Employer purchases totaled $1,100,651, which the KSOP used to repay
that portion of its outstanding loan from the Company, and 346,084 shares were
allocated among the Plan participants. The loan is interest free and is due
December 31, 2004. The loan was secured by 468,652 shares and 680,282 shares of
the Company's common stock at December 31, 2001 and 2000, respectively.
As required under Statement of Position 93-6 "Employers' Accounting for
Employee Stock Ownership Plans," compensation expense is recorded for shares
committed to be released to employees based on the fair market value of those
shares when they are committed to be released. The difference between cost and
the fair market value of the committed to be released shares is recorded in
additional paid-in-capital. Unreleased shares held by the KSOP are excluded from
the calculation of earnings per share.
The KSOP shares are summarized as follows:
December 31,
2001 2000
-------------------------------------------
Allocated shares 573,416 256,336
Unreleased shares 468,652 680,282
---------- -----------
Total ESOP shares 1,042,068 936,618
========== ===========
Fair value of unreleased shares $ 3,889,812 $ 8,163,384
The ESOP expense for the years ending December 31, 2001, 2000 and 1999 was
$1,655,835, $1,119,942 and $148,948, respectively.
Stock Option Plans
Incentive Stock Option Plan
The Company established this plan beginning April 1, 1996. It is governed
by Section 422 of the Internal Revenue Code, and Section 16(b) of the Securities
Exchange Act of 1934. This stock option plan covers 1,200,000 shares of the
Company's common stock. Eligibility is limited to employees and directors of the
Company and its subsidiaries. The actual selection of grantees is made by the
Board of Directors. The term of the individual option grants, while at the
discretion of the Board, has historically been for a term of five years. All
options granted in 1996 were fully vested and exercisable when granted. The
exercise price was fair market value at the date of each grant.
F-21
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Non-Incentive Stock Option Grants
During 1999, the Board granted 1,306,650 new stock options to employees at
an average price of $2.69 per share, of which 108,000 were fully vested
immediately and the remaining 1,198,650 stock options vested 20% at the date of
grant, with the balance vesting an additional 20% per year on the anniversary
date over the next four years. Additionally, the expiration date of 300,000
options previously granted to two former officers of Magnum Petroleum, Inc. was
modified to extend the expiration date from January 5, 2000 to January 5, 2002.
During 2000, the Board granted 1,536,000 new stock options to employees at
a weighted average price of $7.89 per share, all of which vested 20% at the date
of grant, with the balance vesting an additional 20% per year on the anniversary
date over the next four years, and with a weighted average term of 9.9 years.
The exercise price was the fair market value on the date of grant.
During 2001, the Board granted 1,655,500 new stock options to employees at
a weighted average price of $8.48 per share, of which 20% vested at the date of
grant, with the balance vesting an additional 20% per year on the anniversary
date over the next four years, with a weighted average term of 9.9 years. The
exercise price was the fair market value on the date of the grant.
The following is a summary of stock option activity under the Option Plans:
2001 2000 1999
------------------------------------------------------------------------------------------
Weighted Weighted Weighted
Number of Average Number of Average Number of Average
Warrants Exercise Price Warrants Exercise Price Warrants Exercise Price
-------------------------------------------------------------------------------------------
Outstanding - Beginning of Year.... 4,702,400 $ 4.97 3,866,092 $ 3.57 2,661,587 $ 3.90
Granted............................ 1,655,500 8.48 1,536,000 7.89 1,306,650 2.69
Exercised.......................... (1,124,616) 4.33 (656,392) 3.67 (102,145) .76
Cancelled.......................... (15,700) 6.59 (43,300) 3.32 - -
------------------------------------------------------------------------------------------
Outstanding - End of Year.......... 5,217,584 $ 6.22 4,702,400 $ 4.97 3,866,092 $ 3.57
========= ========== ========= ========== ========= ==========
Exercisable - End of Year.......... 2,531,724 $ 5.14 2,730,460 $ 4.31 2,787,172 $ 3.94
========= ========== ========= ========== ========= ==========
The following is a summary of stock options outstanding at December 31,
2001:
Weighted
Average
Number of Remaining
Options Contractual Life Number of
Exercise Price Outstanding (Years) Exercisable Options
- ----------------------------------------------------------------------------------------------------------------
$ 2.50.......................... 1,083,450 3.0 617,290
3.4375........................ 6,000 3.2 -
3.75.......................... 881,034 1.0 881,034
5.25.......................... 80,000 2.1 80,000
5.375......................... 5,000 0.3 5,000
6.625......................... 20,000 3.6 7,400
6.6875........................ 2,400 3.6 600
7.9375........................ 1,536,700 8.9 611,800
8.44.......................... 1,538,000 9.9 307,600
8.50.......................... 20,000 9.7 4,000
9.3125........................ 20,000 3.9 8,000
11.08......................... 20,000 8.9 8,000
12.00......................... 5,000 4.1 1,000
--------------------------------------------------------------------------
5,217,584 6.5 2,531,724
==========================================================================
The Company adopted the disclosures only portion of SFAS No. 123 as it
continues to follow the provisions of APB No. 25, which is the intrinsic value
method of accounting for stock-based compensation.
F-22
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On a pro forma basis, the effect of stock based compensation (options and
warrants) had the Company adopted Statement No. 123 is as follows:
Year Ended December 31,
2001 2000 1999
---------------------------------------------------------
Net Income (Loss) Applicable to Common Stock:
As reported........................................... $ 13,516,000 $ 12,552,000 $ (11,335,000)
Pro Forma................................................ 8,311,000 6,800,000 (13,313,000)
Basic Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ .39 $ 0.60 $ (0.57)
Pro Forma................................................ .24 0.33 (0.67)
Diluted Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ .37 $ 0.51 $ (0.57)
Pro Forma................................................ .23 0.30 (0.67)
Weighted average grant date fair value..................... $ 8,379,000 $ 9,259,000 $ 1,978,000
The Company estimated the fair value of each stock based grant (options and
warrants) using the Black-Scholes option pricing method while using the
following weighted average assumptions:
2001 2000 1999
-------------------------------------------
Risk-free interest rate......... 4.39% 5.75% 5.875%
Expected life................... 7.4 years 7.4 years 4.4 years
Expected volatility............. 52.6% 56.0% 53.0%
Dividend yield.................. - - -
NOTE 15 -- EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND
CHANGE-IN-CONTROL ARRANGEMENTS
Mr. Gary C. Evans, Mr. Richard R. Frazier, Mr. Chris Tong, Mr. R. Douglas
Cronk and Mr. Charles R. Erwin each have employment agreements with the Company.
Mr. Evans' agreement terminates January 1, 2006 and continues thereafter on a
year to year basis and provides for a salary of $300,000 per annum unless
increased by the Board. Mr. Evans' salary for the year 2002 is $375,000. Mr.
Frazier's agreement terminates January 1, 2006 and continues thereafter on a
year to year basis and provides for a salary of $175,000 per annum unless
increased by the Board. Mr. Frazier's salary for the year 2002 is $205,000. Mr.
Tong's agreement terminates January 1, 2004 and continues thereafter on a year
to year basis and provides for a salary of $160,000 per annum unless increased
by the Board. Mr. Tong's salary for the year 2002 is $175,000. Mr. Cronk's
agreement terminates January 1, 2004 and continues thereafter on a year to year
basis and provides for a salary of $122,500 per annum unless increased by the
Board. Mr. Cronk's salary for the year 2002 is $150,000. Mr. Erwin's agreement
terminates January 1, 2004 and continues thereafter on a year to year basis and
provides for a salary of $105,000 per annum unless increased by the Board. Mr.
Erwin's salary for the year 2002 is $155,000. All of the agreements provide that
the same benefits supplied to other Company employees shall be available to the
employee. The employment agreements also contain, among other things, covenants
by the employee that in the event of termination, he will not compete with the
Company in certain geographical areas or hire any employees of the Company for a
period of two years after cessation of employment.
In addition, all of the agreements contain a provision that upon a
change-in-control of the Company and the employee's position is terminated or
the employee leaves for "good cause", the employee is entitled to receive,
immediately in one lump sum, certain compensation. In the case of Mr. Evans and
Mr. Frazier, the employee shall receive three times the employee's base salary,
bonus for the last fiscal year and any other compensation received by him in the
last fiscal year. In the case of Mr. Tong, Mr. Cronk and Mr. Erwin, the employee
shall receive the employee's base salary, bonus for the last fiscal year and any
other compensation received by him in the last fiscal year multiplied by two.
Also, any medical, dental and group life insurance covering the employee and his
F-23
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
dependents shall continue until the earlier of (i) 12 months after the
change-in-control or (ii) the date the employee becomes a participant in the
group insurance benefit program of a new employer. The Company also has key man
life insurance on Mr. Evans in the amount of $12,000,000.
NOTE 16 - SEGMENT DATA
The Company has three reportable segments. The Exploration and Production
segment is engaged in exploratory drilling and acquisition, production, and sale
of crude oil, condensate, and natural gas. The Gas Gathering, Marketing and
Processing segment is engaged in the gathering and compression of natural gas
from the wellhead, the purchase and resale of natural gas which it gathers, and
the processing of natural gas liquids. The Oil Field Services segment is engaged
in the managing and operation of producing oil and gas properties for interest
owners.
The Company's reportable segments are strategic business units that offer
different products and services. They are managed separately because each
business requires different technology and marketing strategies. The Exploration
and Production segment has six geographic areas that are aggregated. The Gas
Gathering, Marketing and Processing segment includes the activities of the two
gathering systems and three natural gas liquids processing plants in two
geographic areas that are aggregated. The Oil Field Services segment has six
geographic areas that are aggregated. The reason for aggregating the segments,
in each case, was due to the similarity in nature of the products, the
production processes, the type of customers, the method of distribution, and the
regulatory environments.
The accounting policies of the segments are the same as those described in
Note 1 - Summary of Significant Accounting Policies. The Company evaluates
performance based on profit or loss from operations before income taxes. The
accounting for intersegment sales and transfers is done as if the sales or
transfers were to third parties, that is, at current market prices.
Segment data for the three years ended December 31, 2001, 2000 and 1999 are
as follows (in thousands):
Gas Gathering,
Exploration & Marketing & Oil Field
2001: Production Processing Services All Other Elimination Consolidated
----- ---------------------------------------------------------------------------------------
Revenue from external customers......... $ 133,083 $17,895 $ 1,828 $ - $ - $ 152,806
Intersegment revenues.................... - 19,253 6,233 - (25,486) -
Depreciation, depletion, amortization and
impairment............................... 42,703 883 394 19 43,999
Segment profit (loss).................. 56,998 725 (2,851) (6,821) 48,051
Equity earnings (losses) of affiliates... 1,085 1,085
Interest expense......................... (19,868) (19,868)
Provision for non-cash impairment of
investments.............................. (7,123) (7,123)
Other income............................. 283 283
-------------------
Income before income taxes............... $ 22,428
Current income tax provision............. (178) (178)
Deferred income tax provision............ (8,430) (8,430)
Extraordinary loss....................... (304) (304)
-------------------
Net income............................... $ 13,516
===================
Capital expenditures (net of asset sales) $ 202,063 $ 61 $ 326 $ 855 $ $ 203,305
F-24
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Gas Gathering,
Exploration & Marketing & Oil Field
2000: Production Processing Services All Other Elimination Consolidated
----- ---------------------------------------------------------------------------------------
Revenue from external customers......... $ 106,052 $ 20,010 $ 1,448 $ - $ - $ 127,510
Intersegment revenues.................... - 20,218 6,128 (26,346) -
Depreciation, depletion, amortization and
impairment............................... 24,350 876 304 26 25,556
Segment profit (loss).................. 52,743 3,422 (1,274) (4,562) 50,329
Equity earnings (losses) of affiliates... 1,307 1,307
Interest expense......................... (22,298) (22,298)
Other income............................. 477 477
-----------------
Income before income taxes............... $ 29,815
Current income tax provision............. (234) (234)
Deferred income tax provision............ (7,321) (7,321)
-----------------
Net income............................... $ 22,260
=================
Capital expenditures (net of asset sales) $ 20,279 $ 119 $ 495 $ - $ 20,893
Gas Gathering,
Exploration & Marketing & Oil Field
1999: Production Processing Services All Other Elimination Consolidated
----- ---------------------------------------------------------------------------------------
Revenue from external customers......... $ 60,673 $ 8,185 $ 768 $ - $ - $ 69,626
Intersegment revenues.................... - 14,135 6,164 - (20,299) -
Depreciation, depletion, amortization and
impairment............................... 21,176 646 233 17 22,072
Segment profit (loss).................. 15,960 1,858 (605) (2,101) 15,112
Equity earnings (losses) of affiliates... (103) (103)
Interest expense......................... (22,103) (22,103)
Other income............................. 354 354
-----------------
Loss before income taxes................. - $ (6,740)
Deferred income tax benefit.............. - -
Minority interest........................ (86) (86)
-----------------
Net loss................................. $ (6,826)
=================
Capital expenditures (net of asset sales) $ 54,877 $ 3,331 $ 410 $ - $ 58,618
Gas Gathering,
Exploration & Marketing & Oil Field
Production Processing Services All Other Elimination Consolidated
-------------------------------------------------------------------------------------
As of December 31, 2001
Segment assets............................ $ 423,018 $ 15,884 $ 8,675 $ 6,808 $ 454,385
Equity subsidiary investments............. 5,022 5,022
As of December 31, 2000
Segment assets............................ $ 270,195 $ 20,561 $ 16,154 $ 8,702 $ 315,612
Equity subsidiary investments............. 8,054 8,054
F-25
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 17 -- CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
The Company and its subsidiaries, except Bluebird and certain
inconsequential subsidiaries (Inesco Corporation, SPL Gas Marketing, Inc. and
Midland Hunter Petroleum Limited Liability Company) are direct Guarantors of the
Company's 10% Senior Notes and have fully and unconditionally guaranteed the
Notes on a joint and several basis. Bluebird was formed in December 1998 and
first reported results of operations in fiscal 1999. In addition to not being a
guarantor of the Company's 10% Senior Notes, it cannot be included in
determining compliance with certain financial covenants under the Company's
credit agreements. Management has determined that separate financial statements
relating to the Guarantors are not material to investors. Condensed
consolidating balance sheets for Magnum Hunter Resources, Inc. and subsidiaries
as of December 31, 2001and 2000 and condensed consolidating statements of
operations and cash flows for the years ended December 31, 2001, 2000 and 1999
are as follows:
Magnum Hunter Resources, Inc. and Subsidiaries
Condensed Consolidating Balance Sheets
December 31, 2001
- -----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------
ASSETS
Current assets.............................. $ 21,196 $ 3,910 $ - $ 25,106
Property and equipment
(using full cost accounting).............. 412,720 7,117 - 419,837
Investment in subsidiaries
(equity method)............................ 14,963 - (14,963) -
Investment in Parent........................ - 15,750 (15,750) -
Other assets................................ 9,442 - - 9,442
----------------------------------------------------------------------------
Total Assets............................. $ 458,321 $ 26,777 $ (30,713) $ 454,385
============================================================================
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities......................... $ 48,561 $ 152 $ - $ 48,713
Long-term liabilities....................... 280,736 11,662 (4,700) 287,698
Shareholders' equity........................ 129,024 14,963 (26,013) 117,974
----------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $ 458,321 $ 26,777 $ (30,713) $ 454,385
============================================================================
December 31, 2000
- -----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------
ASSETS
Current assets.............................. $ 33,556 $ 6,894 $ (5,612) $ 34,838
Property and equipment
(using full cost accounting).............. 208,115 52,417 - 260,532
Investment in subsidiaries
(equity method)............................ 25,574 - (25,574) -
Other assets................................ 27,173 319 (7,250) 20,242
----------------------------------------------------------------------------
Total Assets............................. $ 294,418 $ 59,630 $ (38,436) $ 315,612
============================================================================
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities......................... $ 30,123 $ 6,206 $ (5,612) $ 30,717
Long-term liabilities....................... 170,879 27,850 (7,250) 191,479
Shareholders' equity........................ 93,416 25,574 (25,574) 93,416
----------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $ 294,418 $ 59,630 $ (38,436) $ 315,612
============================================================================
F-26
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Statement of Operations
Year Ended December 31, 2001
- -----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- -------------------- ----------------------------------------------------------------------------
Revenues................................. $ 128,572 $ 24,445 $ (211) $ 152,806
Expenses................................... 118,265 12,324 (211) 130,378
----------------------------------------------------------------------------
Income (loss) before 10,307 12,121 - 22,428
Equity in net earnings of subsidiaries.... 7,530 - (7,530) -
----------------------------------------------------------------------------
Income (loss) before income taxes.......... 17,837 12,121 (7,530) 22,428
Income tax provision....................... (4,017) (4,591) - (8,608)
----------------------------------------------------------------------------
Income before extraordinary loss........... 13,820 13,820
Extraordinary Loss......................... (304) (304)
Net Income (Loss)........................ $ 13,516 $ 7,530 $ (7,530) $ 13,516
============================================================================
Year Ended December 31, 2000
- -----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- -------------------- ----------------------------------------------------------------------------
Revenues................................... $ 83,048 $ 44,772 $ (310) $ 127,510
Expenses................................... 72,375 25,250 70 97,695
---------------------------------------------------------------------------
Income (loss) before 10,673 19,522 (380) 29,815
Equity in net earnings of subsidiaries.... 12,272 - (12,272) -
---------------------------------------------------------------------------
Income (loss) before income taxes.......... 22,945 19,522 (12,652) 29,815
Income tax provision....................... (305) (7,250) - (7,555)
---------------------------------------------------------------------------
Net Income (Loss)........................ $ 22,640 $ 12,272 $(12,652) $ 22,260
===========================================================================
Year Ended December 31, 1999
- -----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- -------------------- ----------------------------------------------------------------------------
Revenues................................... $ 53,189 $ 16,847 $ (410) $ 69,626
Expenses................................... 62,184 14,678 (410) 76,452
----------------------------------------------------------------------------
Income (loss) before (8,995) 2,169 - (6,826)
Equity in net earnings of subsidiaries.... 2,169 - (2,169) -
----------------------------------------------------------------------------
Income (loss) before income taxes.......... (6,826) 2,169 (2,169) (6,826)
Income tax provision....................... - - - -
----------------------------------------------------------------------------
Net Income (Loss)........................ $ (6,826) $ 2,169 $ (2,169) $ (6,826)
============================================================================
F-27
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Magnum Hunter Resources, Inc. and Subsidiaries Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2001
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities......... $ 89,712 $ 14,362 $ - $104,074
Cash flow used by investing activities...... (225,745) 40,334 (18,578) (203,989)
Cash flow used by financing activities...... 138,574 (54,491) 18,578 102,661
-----------------------------------------------------------------------
Net increase (decrease) in cash............. 2,541 205 - 2,746
Cash at beginning of period................. (1,811) 1,820 - 9
-----------------------------------------------------------------------
Cash at end of period....................... $ 730 $ 2,025 $ - $ 2,755
=======================================================================
Year Ended December 31, 2000
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities......... $ 21,909 $ 27,557 $ - $ 49,466
Cash flow used by investing activities...... (13,501) (6,507) - (20,008)
Cash flow used by financing activities...... (9,964) (21,375) 325 (31,014)
---------------------------------------------------------------------------
Net increase (decrease) in cash............. (1,556) (325) 325 (1,556)
Cash at beginning of period................. 1,565 2,145 (2,145) 1,565
---------------------------------------------------------------------------
Cash at end of period....................... $ 9 $ 1,820 $(1,820) $ 9
===========================================================================
Year Ended December 31, 1999
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities......... $ 6,202 $ 11,233 $ - $ 17,435
Cash flow used by investing activities...... (34,668) (25,209) 1,408 (58,469)
Cash flow used by financing activities...... 25,178 15,662 (3,094) 37,746
-------------------------------------------------------------------------
Net increase (decrease) in cash............. (3,288) 1,686 (1,686) (3,288)
Cash at beginning of period................. 4,853 459 (459) 4,853
-------------------------------------------------------------------------
Cash at end of period....................... $ 1,565 $ 2,145 $ (2,145) $ 1,565
=========================================================================
NOTE 18 - SUBSEQUENT EVENTS
On January 15, 2002, the Company entered into a sale-leaseback transaction
on three newly constructed offshore production platforms and associated
pipelines that were recently placed into service. The Company received a total
of $11.2 million in new funding which was used for general corporate purposes
including a voluntary reduction under the Company's corporate bank revolving
credit facility. The production platforms are being leased from a syndicate
group of lenders over a term of three years and at a cost of funds of
approximately 5.30% per annum, based on current interest rates. The transaction
will be accounted for as a capital lease.
On March 15, 2002, the Company merged with Prize Energy Corp.(Prize), an
independent oil and gas development and production company. The transaction was
accounted for as a purchase of Prize by the Company in accordance with the
provisions of FAS 141. Under the terms of the merger, the Company distributed
2.5 shares of
F-28
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
common stock plus $5.20 in cash for each Prize Energy share outstanding.
The following table summarizes the total assumed purchase price and related
preliminary allocation to the net assets acquired (in thousands). The Company
has not completed a final allocation of the purchase price to the fair values of
the assets and liabilities of Prize and the related business integration plan.
The Company expects that the ultimate purchase price allocation may include
additional adjustments to the fair values of assets and the carrying values of
certain liabilities. Accordingly, to the extebt that such assessments indicate
that the fair values of the assets and liabilities differ from their preliminary
purchase price allocation, such differences would adjust the amounts allocated
to the assets and liabilities and would change the amounts allocated to
goodwill.
Total Purchase Price:
Fair Value of 34,062,963 shares of Magnum Hunter common stock $ 256,153
issued based on a price of $7.52 per share at March 15, 2002
(assuming exercise of outstanding Prize stock options).............
Cash consideration................................................... 70,851
Fair value of Prize warrants......................................... 5,568
Severance payments................................................... 8,000
Estimated Magnum Hunter transaction related costs.................... 1,400
----------------
Total............................................................. $ 341,972
================
Net Preliminary Purchase Price Allocation:
Net purchase price................................................... $ 341,972
Historical net assets acquired....................................... (162,970)
----------------
Excess purchase price................................................ 179,002
Adjustment of proved oil and gas properties to fair value............ (26,230)
Adjustment of unproved oil and gas properties to fair value.......... (113,000)
Write-off of historical Prize deferred financing costs............... 2,300
Additional deferred income taxes..................................... 48,787
----------------
Excess purchase price allocated to goodwill....................... $ 90,859
================
The following summary, prepared on a pro forma basis, presents the results
of operations for the years ended December 31, 2001 and 2000 as if the
acquisition of Prize occurred as of the beginning of the respective years. The
pro forma information includes the effects of adjustments for interest expense,
depreciation, depletion and amortization, and income taxes:
(Unaudited)
-----------------------------------------------
2001 2000
(in thousands, except for per share amounts)
-----------------------------------------------
Revenue.............................................. $ 334,873 $ 276,999
Total Operating Costs and Expenses................... (224,138) (172,320)
-------------------- -------------------
Operating Profit..................................... 110,735 104,679
Interest Expense and Other........................... (52,680) (48,178)
-------------------- -------------------
Income before Tax.................................... 58,055 56,501
Provision for Income Tax............................. (21,792) (17,429)
Extraordinary loss from early extinguishment of debt. (304) -
-------------------- -------------------
Net Income........................................... 35,959 39,072
Dividends Applicable to Preferred Stock.............. - (10,167)
-------------------- -------------------
Net Income Applicable to Common Stock................ 35,959 28,905
==================== ===================
Net Income Per Common Share
Basic............................................. $ 0.52 $ 0.53
==================== ===================
Diluted........................................... $ 0.50 $ 0.50
==================== ===================
The Company amended and restated its Senior Bank Credit Facility (the
facility) in conjunction with the merger with Prize. The amended facility
provides for total borrowings of $500 million, up from $225 million, and raises
the borrowing base limit from $160 million to $300 million. After March 15,
2002, the facility was used to retire outstanding indebtedness under the Prize
commercial bank credit facility, fund the cash component of the merger
consideration payable to the Prize shareholders, pay costs associated with the
merger, and for general corporate purposes.
On March 15, 2002, the Company also completed a private placement of $300
million of unsecured Senior Notes due 2012. Interest on the Senior Notes bear an
annual rate of 9.6% due semi-annually, commencing September 15, 2002.
On December 5, 2001, the Company announced that a distribution of one
warrant for every five shares of common stock owned on January 10, 2002. These
warrants were distributed on March 21, 2002. Each new warrant will entitle the
holder to purchase one share of common stock at $15. The warrants will expire
three years from the date of distribution.
F-29
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)
Proved oil and gas reserves consist of those estimated quantities of crude
oil, natural gas and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Estimates of petroleum reserves have been made by independent engineers and
Company employees. These estimates include reserves in which the Company holds
an economic interest under production-sharing and other types of operating
agreements. These estimates do not include probable or possible reserves. The
estimated net interests in Proved Reserves are based upon subjective engineering
judgments and may be affected by the limitations inherent in such estimation.
The process of estimating reserves is subject to continual revision as
additional information becomes available as a result of drilling, testing,
reservoir studies and production history. There can be no assurance that such
estimates will not be materially revised in subsequent periods. The revisions of
previous estimates of the Company's proved oil and gas reserves were primarily
due to changes in commodity prices at December 31, 1999, 2000 and 2001 that
impacted whether such reserves were economically recoverable. The impact of
price changes disproportionately affects the Company's long life reserves
because of the more gradual decline curve of the applicable production.
Estimated quantities of proved oil and gas reserves of the Company were as
follows:
Gas
Oil (Thousand
(Barrels) Cubic Feet)
--------------------------------------
December 31, 1999
Proved Reserves..................... 25,534,000 230,000,000
Proved developed reserves........... 16,300,000 184,955,000
December 31, 2000
Proved Reserves..................... 22,303,000 233,208,000
Proved developed reserves........... 13,923,000 179,697,000
December 31, 2001
Proved Reserves..................... 21,601,000 248,480,000
Proved developed reserves........... 12,960,000 188,413,000
F-30
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
(Unaudited)
The changes in Proved Reserves for the years ended December 31, 1999, 2000
and 2001 were as follows:
Gas
Oil (Thousand
(Barrels) Cubic Feet)
-----------------------------------
Reserves at December 31, 1998........... 17,349,000 219,060,000
Purchase of minerals-in-place........... 3,123,000 15,990,000
Sale of minerals-in-place............... (21,000) (197,000)
Extensions and discoveries.............. 164,000 6,068,000
Production.............................. (1,311,000) (19,041,000)
Revisions of estimates.................. 6,230,000 8,120,000
-----------------------------------
Reserves at December 31, 1999........... 25,534,000 230,000,000
Purchase of minerals-in-place........... 1,000 2,203,000
Sale of minerals-in-place............... (3,095,000) (21,966,000)
Extensions and discoveries.............. 1,777,000 35,009,000
Production.............................. (1,298,000) (19,579,000)
Revisions of estimates.................. (616,000) 7,541,000
-----------------------------------
Reserves at December 31, 2000........... 22,303,000 233,208,000
-----------------------------------
Purchase of minerals-in-place........... 1,794,000 25,349,000
Sale of minerals-in-place............... (67,000) (577,000)
Extensions and discoveries.............. 1,178,000 27,088,000
Production.............................. (1,410,000) (24,864,000)
Revisions of estimates.................. (2,197,000) (11,724,000)
-----------------------------------
Reserves at December 31, 2001........... 21,601,000 248,480,000
-----------------------------------
The aggregate amounts of capitalized costs relating to oil and gas
producing activities and the related accumulated depreciation, depletion,
amortization and impairment as of December 31, 2001, 2000 and 1999 were as
follows:
2001 2000 1999
----------------------------------------------------
Unproved oil and gas properties................................ $ 18,653,000 $ 5,534,000 $ 3,567,000
Proved properties.............................................. 556,766,000 367,822,000 349,510,000
----------------------------------------------------
Gross Capitalized Costs........................................ 575,419,000 373,356,000 353,077,000
Accumulated depreciation, depletion, amortization and impairment (167,487,000) (124,720,000) (100,370,000)
----------------------------------------------------
Net Capitalized Costs................................ $ 407,932,000 $ 248,636,000 $ 252,707,000
====================================================
Costs incurred in oil and gas producing activities, both capitalized and
expensed, during the years ended December 31, 2001, 2000 and 1999 were as
follows:
2001 2000 1999
-----------------------------------------------
Property acquisition costs
Proved properties........................ $ 36,069,000 $ 7,806,000 $ 34,478,000
Unproved properties...................... 12,226,000 1,080,000 1,912,000
Exploration costs.......................... 37,711,000 32,521,000 6,835,000
Development costs.......................... 117,107,000 22,234,000 12,176,000
-----------------------------------------------
Total Costs Incurred............. $ 203,113,000 $ 63,641,000 $ 55,401,000
===============================================
F-31
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
(Unaudited)
Results of operations from oil and gas producing activities for the years
ended December 31, 2001, 2000 and 1999 were as follows:
2001 2000 1999
-------------------------------------------------
Oil and gas production revenue........................................ $ 133,083,000 $ 106,052,000 $ 60,673,493
Production costs...................................................... (33,382,000) (28,959,000) (23,575,241)
Depreciation, depletion, amortization and impairment.................. (42,703,000) (24,350,000) (21,176,428)
Income taxes.......................................................... (19,949,000) (18,460,000) (5,572,638)
-------------------------------------------------
Results of Operations for Producing Activities $ 37,049,000 $ 34,283,000 $ 10,349,186
=================================================
The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 2001, 2000 and 1999 were
as follows:
2001 2000 1999
------------------------------------------------------
Future cash inflows............................................. $ 998,101,000 $ 2,685,776,000 $ 1,102,673,000
Future development costs........................................ (94,950,000) (84,158,000) (52,600,000)
Future production costs......................................... (367,526,000) (559,596,000) (362,365,000)
------------------------------------------------------
Future net cash flows, before income tax........................ 535,625,000 2,042,022,000 687,708,000
Future income taxes............................................. (28,299,000) (607,407,000) (131,500,000)
------------------------------------------------------
Future Net Cash Flows........................................... 507,326,000 1,434,615,000 556,208,000
10% annual discount............................................. (201,633,000) (629,692,000) (240,592,000)
------------------------------------------------------
Standardized Measure of Discounted Future Net Cash Flows (a) $ 305,693,000 $ 804,923,000 $ 315,616,000
======================================================
The primary changes in the standardized measure of discounted estimated
future net cash flows for the years ended December 31, 2001, 2000 and 1999 were
as follows:
2001 2000 1999
------------------------------------------------------
Purchases of minerals-in-place................................. $ 35,257,000 $ 16,040,000 $ 45,321,000
Sales of minerals-in-place..................................... (2,614,000) (33,981,000) (168,000)
Extensions, discoveries and improved recovery, less related costs 33,623,000 208,966,000 8,398,000
Sales of oil and gas produced, net of production costs......... (99,701,000) (77,093,000) (37,098,000)
Development costs incurred during the period................... 117,107,000 22,231,000 12,176,000
Revision of prior estimates:
Net change in prices and costs............................... (858,125,000) 552,634,000 118,271,000
Change in quantity estimates................................. (88,279,000) 1,524,000 36,937,000
Accretion of discount.......................................... 80,492,000 31,562,000 17,615,000
Net change in income taxes..................................... 283,010,000 (232,576,000) (61,984,000)
-------------------------------------------------------
Net Change.................................... $(499,230,000) $ 489,307,000 $ 139,468,000
=======================================================
Estimated future cash inflows are computed by applying year-end prices of
oil and gas to year-end quantities of Proved Reserves. Estimated future
development and production costs are determined by estimating the expenditures
to be incurred in developing and producing the proved oil and gas reserves at
the end of the year, based on year-end costs and assuming continuation of
existing economic conditions. Estimated future income tax expense is calculated
by applying year-end statutory tax rates to estimated future pre-tax net cash
flows related to proved oil and gas reserves, less the tax basis of the
properties involved.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and as such, do not
necessarily reflect the Company's expectations of actual revenues to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process are equally applicable to the standardized
measure computations since these estimates are the basis for the valuation
process.
F-32
Item 9. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure.
None.
PART III
Item 10. Directors, Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act
The following table sets forth the directors, executive officers and other
significant employees of the Company, their ages, and all offices and positions
with the Company. Each director is elected for a period of one year and
thereafter serves until his successor is duly elected by the stockholders of the
Company and qualifies.
Name Age Title
Gary C. Evans................... 44 Chairman, President and Chief Executive Officer
Richard R. Frazier.............. 55 President and Chief Operating Officer of Magnum Hunter
Production, Inc. and Gruy
Chris Tong...................... 45 Senior Vice President and Chief Financial Officer
R. Douglas Cronk ............... 55 Senior Vice President of Operations of Magnum Hunter Production, Inc.
and Gruy
Morgan F. Johnston.............. 41 Vice President, General Counsel and Secretary
David S. Krueger................ 52 Vice President and Chief Accounting Officer
Michael P. McInerney ........... 60 Vice President, Corporate Development & Investor Relations
Charles R. Erwin................ 55 Senior Vice President of Exploration of Magnum Hunter Production, Inc.
and Gruy
Gregory L. Jessup............... 48 Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits.............. 50 Vice President and Controller
Craig Knight.................... 45 Vice President of Operations of Hunter Gas Gathering, Inc.
Earl Krieg, Jr. ................ 48 Vice President of Engineering of Magnum Hunter Production, Inc. and
Gruy
Gerald W. Bolfing............... 73 Director
Jerry Box....................... 63 Director
Robert Kelley................... 56 Director
Jim Kneale...................... 50 Director
James R. Latimer, III........... 55 Director
Matthew C. Lutz................. 68 Director
John H. Trescot, Jr............. 77 Director
James E. Upfield................ 81 Director
Gary C. Evans has served as President, Chief Executive Officer and a
director of Magnum Hunter Resources, Inc. since December 1995 and Chairman and
Chief Executive Officer of all of the Magnum Hunter subsidiaries since their
formation or acquisition. In 1985, Mr. Evans formed the predecessor company,
Hunter Resources, Inc., that was merged into and formed Magnum Hunter some ten
years later. From 1981 to 1985, Mr. Evans was associated with the Mercantile
Bank of Canada where he held various positions including Vice President and
Manager of the Energy Division of the Southwestern United States. From 1978 to
1981, he served in various capacities with National Bank of Commerce (now
BancTexas, N.A.) including Credit Manager and Credit Officer. Mr. Evans serves
on the Board of Directors of Novavax, Inc., an American Stock Exchange listed
pharmaceutical company. He additionally serves on the board of three private
Texas-based companies that Magnum Hunter owns various minority interests in,
49
including(i) Swanson Consulting Services, Inc., a geological consulting
firm; (ii) NGTS, LLC, a natural gas marketing company and (iii) Aurion
Technologies, Inc., a company that provides web-enabled automation to the oil
and natural gas industry. He also serves as a Trustee of TEL Offshore Trust, an
OTC listed oil and gas trust of which Magnum Hunter owns an approximate 36%
interest.
Officers
Richard R. Frazier has served as President and Chief Operating Officer of
Magnum Hunter Production, Inc. and Gruy since January 1994. From 1977 to 1993,
Mr. Frazier was employed by Edisto Resources Corporation in Dallas, serving as
Executive Vice President Exploration and Production from 1983 to 1993, where he
had overall responsibility for its property acquisition, exploration, drilling,
production, gas marketing and engineering functions. From 1972 to 1976, Mr.
Frazier served as District Production Superintendent and Petroleum Engineer with
HNG Oil Company (now Enron Oil & Gas Company) in Midland, Texas. Mr. Frazier's
initial employment, from 1968 to 1971, was with Amerada Hess Corporation as a
petroleum engineer involved in numerous projects in Oklahoma and Texas. Mr.
Frazier graduated in 1970 from the University of Tulsa with a Bachelor of
Science Degree in Petroleum Engineering. He is a registered Professional
Engineer in Texas and a member of the Society of Petroleum Engineers and many
other professional organizations.
Chris Tong has served as Senior Vice President and Chief Financial Officer
since August 1997. Previously, Mr. Tong was Senior Vice President of Finance of
Tejas Acadian Holding Company and its subsidiaries including Tejas Gas Corp.,
Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned
subsidiaries of Tejas Gas Corporation. In January 1998, Tejas Gas Corporation
was acquired by Shell Oil. Mr. Tong held these positions since August 1996, and
served in other treasury positions with Tejas beginning August 1989. He was also
responsible for managing Tejas' property and liability insurance. From 1980 to
1989, Mr. Tong served in various energy lending capacities with Canadian
Imperial Bank of Commerce, Post Oak Bank, and Bankers Trust Company in Houston,
Texas. Prior to his banking career, Mr. Tong also served over a year with
Superior Oil Company as a Reservoir Engineering Assistant. Mr. Tong is a summa
cum laude graduate of the University of Southwestern Louisiana with a Bachelor
of Arts degree in Economics and a minor in Mathematics.
R. Douglas Cronk has served as Senior Vice President of Operations for
Magnum Hunter Production, Inc. and Gruy since December 1998. He served as Vice
President of Operations for the two companies since May 1996 at which time the
Company acquired from Mr. Cronk Rampart Petroleum, Inc., based in Abilene,
Texas. Rampart had been an active operating and exploration company in the north
central and west Texas region since 1983. Prior to the formation of Rampart, Mr.
Cronk was an independent oil and gas consultant in Houston, Texas for
approximately two years. From 1974 to 1981, Mr. Cronk held various positions
with subsidiaries of Deutsch Corporation of Tulsa, Oklahoma, including Southland
Drilling and Production where he became Vice President of Drilling and
Production. Mr. Cronk is a Chemical Engineer graduate from the University of
Tulsa.
Charles R. Erwin has served as Senior Vice President of Exploration for
Magnum Hunter Production, Inc. and Gruy Petroleum Management Co. since July
2000. He became Vice President of Exploration for Magnum Hunter Production, Inc.
and Gruy Petroleum Management Co. in January 2000. Mr. Erwin initially served as
Manager of Exploration for Gruy Petroleum Management Co. beginning May of 1999.
Mr. Erwin received a Masters in Geology from the University of Wisconsin -
Milwaukee. He has 27 years experience in the oil and gas industry. Prior to Gruy
Petroleum Management Co., Mr. Erwin worked for Enserch Exploration for 22 years
holding various positions including Exploration Manager - East Texas,
Exploration Manager - Texas and Louisiana Gulf Coast and Director Exploration
Offshore and International.
Morgan F. Johnston has served as Vice President and General Counsel since
April 1997 and has served as the Company's Secretary since May 1, 1996. Mr.
Johnston was in private practice as a sole practitioner from May 1, 1996 to
April 1, 1997, specializing in corporate and securities law. From February 1994
to May 1996, Mr. Johnston served as general counsel for Millennia, Inc.
(formerly known as SOI Industries, Inc.) and Digital Communications
50
Technology Corporation, two American Stock Exchange listed companies. He
also served as general counsel to Halter Capital Corporation, a private
consulting firm from August 1991 to May 1996. For the two years prior to August
1991 he was securities counsel for Motel 6 L.P., a New York Stock Exchange
listed company. Mr. Johnston graduated cum laude from Texas Tech Law School in
May 1986 and was also a member of the Texas Tech Law Review. He is licensed to
practice law in the State of Texas.
David S. Krueger has served as Vice President and Chief Accounting Officer
of the Company since January 1997. Mr. Krueger acted as Vice President-Finance
of Cimarron Gas Holding Co., a gas processing and natural gas liquids marketing
company in Tulsa, Oklahoma, from April 1992 until January 1997. He served as
Vice President/ Controller of American Central Gas Companies, Inc., a gas
gathering, processing and marketing company from May 1988 until April 1992. From
1974 to 1986, Mr. Krueger served in various managerial capacities for Southland
Energy Corporation. From 1971 to 1973, Mr. Krueger was a staff accountant with
Arthur Andersen LLP. Mr. Krueger, a certified public accountant, graduated from
the University of Arkansas with a B.S./B.A. degree in Business Administration
and earned his M.B.A. from the University of Tulsa.
Michael P. McInerney has served as Vice President, Corporate Development &
Investor Relations of the Company since October 1997. Prior to joining the
Company, Mr. McInerney owned Energy Advisors, Inc., an energy consulting firm,
from June 1993 until October 1997. Mr. McInerney was employed from 1981 until
June 1993 by Triton Energy Corporation, an independent energy company, where his
responsibilities included investor relations, acquisitions and corporate
planning. Before joining Triton Energy Corporation, Mr. McInerney served nine
years in various financial management positions with American Natural Resources
Company, a gas transmission and distribution corporation. Mr. McInerney
graduated from the University of Michigan with a B.B.A.
Gregory L. Jessup has been Vice President of Land for Magnum Hunter
Production, Inc., a wholly-owned subsidiary of the Company and Gruy since April
17, 1998. Mr. Jessup joined the Company as Land Manager on May 1, 1997. From
1982 until joining the Company, Mr. Jessup served as Land Manager of Ken
Petroleum Corporation of Dallas managing its Land and Regulatory Department as
well as managing its crude oil marketing business. During his tenure as Land
Manager, Mr. Jessup has been actively involved in all phases of land operations,
including negotiations, acquisitions, and administration. Mr. Jessup holds a
Bachelor of Business Administration degree in Management from Texas Tech
University and is a Certified Professional Landman.
David M. Keglovits has served as Vice President and Controller of the
Company and its subsidiaries since 1999. Prior to 1999. Mr. Keglovits served as
Vice President and Controller of Gruy. Mr. Keglovits joined Gruy in March 1977
as an accountant before holding the positions of Assistant Controller and
Controller. From December 1974 to December 1976, Mr. Keglovits was employed by
Bell Helicopter International in its financial management office in Tehran,
Iran. Mr. Keglovits was graduated with honors from the University of Texas at
Austin with a B.B.A. in Accounting.
Craig Knight has served as Vice President of Operations for Hunter Gas
Gathering, Inc. since March 1998. Prior to joining the Company Mr. Knight was
employed by MidCon Corp. and its affiliates since 1979 in various capacities.
From 1995 to his departure from MidCon he served as the Sr. Business Manager,
Gathering and Processing for MidCon Gas Products Corp. where he managed MidCon's
gathering and processing activities in the Panhandle and Permian Basin regions
of Texas. From 1992 -1994, he served as an account manager of the Electric Power
Sector Start-up Group for MidCon Gas Services Corp and as Manager - West Region
for MidCon Marketing Corp. Mr. Knight graduated from Texas Tech University with
a B.S. in Engineering Technology with Construction Specialty. He also received
his M.B.A. in Executive Programs from University of Houston in 1989.
Earl Krieg has served as Manager of Engineering for Gruy Petroleum
Management Co. since May of 1999. Mr. Krieg became Vice President of Engineering
for Magnum Hunter Production, Inc. and Gruy in January 2000. Mr. Krieg was
employed by The Wiser Oil Company for the five years prior to joining the
Company in various capacities including Manager of Operations and Manager of
Secondary Recovery. Mr. Krieg has 26 years experience in various reservoir
engineering, operations, acquisitions and management roles with Chevron, General
Crude, Edisto and most recently The Wiser Oil Company. Mr. Krieg is a Registered
Professional Engineer in Texas and was an officer in the Society of Petroleum
Evaluation Engineers in 1989. Mr. Krieg graduated from Texas A&M University in
1975 with a B.S. degree in petroleum engineering.
51
Directors
Gerald W. Bolfing has been a director of Magnum Hunter since December 1995.
Mr. Bolfing was appointed a director of Hunter Resources, Inc. in August 1993.
He is an investor in the oil and gas business and a past officer of one of
Hunter's former subsidiaries. From 1962 to 1980, Mr. Bolfing was a partner in
Bolfing Food Stores in Waco, Texas. Mr. Bolfing was involved in American Service
Company in Atlanta, Georgia from 1964 to 1965, and was active with Cable
Advertising Systems, Inc. of Kerrville, Texas from 1978 to 1981. He joined a
Hunter subsidiary in the well servicing business in 1981 where he remained
active until its divestiture in 1992. Mr. Bolfing is on the board of directors
of Capital Marketing Corporation of Hurst, Texas.
Jerry Box has served as a director of Magnum Hunter since March 1999. From
February 1998 to March 1999, he served in the position of president and chief
operating officer and as a director of Oryx Energy Company, now owned by Kerr
McGee Corporation. From December 1995 to February 1998, he was executive vice
president and chief operating officer of Oryx. From December 1994 through
November 1995, he served as executive vice president, exploration and production
of Oryx. Previously, he served as senior vice president, exploration and
production of Oryx. Mr. Box attended Louisiana Tech University, where he
received B.S. and M.S. degrees in geology, and is also a graduate of the Program
for Management Development at the Harvard University Graduate School of Business
Administration. Mr. Box served as an officer in the U. S. Air Force from 1961 to
1966. Mr. Box is a former member of the Policy Committee of the U. S. Department
of the Interior's Outer Continental Shelf Advisory Board, past chairman and
vice-chairman of the American Petroleum Institute's Exploration Affairs
subcommittee, a former president of the Dallas Petroleum Club and a member of
the Independent Petroleum Association of America.
Robert Kelley was a director of Prize from May 2001 until the merger. He is
currently president of Kellco Investments Inc., a private investment company.
From 1986 through October 2000, Mr. Kelley served as president and chief
executive officer of Noble Affiliates, Inc., an independent energy company with
domestic and international exploration and production operations. From 1992
through April 2001, Mr. Kelley also served as chairman of the board of Noble
Affiliates, and he was a director of Noble Affiliates from 1986 through April
2001. He held various financial and operational positions with Noble Affiliates
and its subsidiaries from 1975 until his election as president in 1986. Mr.
Kelley also serves as a director of OGE Energy Corp., the parent company of OG&E
Electric Services, Oklahoma's largest electric utility; Enogex, Inc., a natural
gas pipeline, processing and energy marketing business; Lone Star Technologies,
Inc., a leading manufacturer of oilfield tubular products; and Continental
Resources, Inc., a privately held exploration and production company active
primarily in the Rocky Mountain and Mid-Continent regions of the United States.
Mr. Kelley received his B.B.A from the University of Oklahoma in 1973 and is a
certified public accountant.
Jim Kneale has served as a director of Magnum Hunter since September 2000.
Mr. Kneale is currently employed by ONEOK, Inc., as senior vice president, chief
financial officer and treasurer and has been such since January 2001. He is
responsible for the finance, tax and accounting, internal audit and risk control
functions for ONEOK. Mr. Kneale joined ONEOK in 1981 as vice president of ONEOK
Drilling Company. He became vice president of Energy Companies of ONEOK later in
1981 and was named vice president of accounting for Oklahoma Natural Gas
Company, a division of ONEOK, Inc., in 1992. Mr. Kneale became vice president of
the Tulsa District of Oklahoma Natural Gas in 1994, vice president for ONEOK
Resources in 1996, and president of Oklahoma Natural Gas in 1997. He was elected
to the chief financial officer position in 1999. Mr. Kneale is a member of the
American Institute of Certified Public Accountants and the Oklahoma Society of
CPAs. Mr. Kneale serves on the board of directors of the YMCA of Greater Tulsa,
the Tulsa Boys' Home, Tulsa Community College Foundation, and the Advisory Board
of the Oklahoma Blood Institute. A certified public accountant, Mr. Kneale
received his accounting degree from West Texas A&M University in 1973.
James R. Latimer, III was a director of Prize from October 2000 until the
merger. Over the past eight years, Mr. Latimer has been the chairman and chief
executive officer of Explore Horizons, Incorporated, a privately held
exploration and production company based in Dallas, Texas. Previously, Mr.
Latimer was co-head of the regional office of what is now The Prudential Capital
Group in Dallas, Texas, which handled energy and other financing for The
Prudential Insurance Company. In addition, Mr. Latimer's prior experience has
included senior executive positions with several
52
private energy companies, consulting with the firm of McKinsey & Co.,
service as an officer in the United States Army Signal Corps., and several
directorships. Mr. Latimer received a B.A. degree in economics from Yale
University and an M.B.A. from Harvard University. He is a Chartered Financial
Analyst.
Matthew C. Lutz retired as chairman of Magnum Hunter on September 1, 2001
after having served in that capacity since March 1997 and after having
previously served as vice chairman of Magnum Hunter from December 1995 to March
1997. Mr. Lutz also previously served as executive vice president of Magnum
Hunter from December 1995 to September 2001. Mr. Lutz held similar positions
with Hunter Resources, Inc. from September 1993 until October 1996. From 1984
through 1992, Mr. Lutz was senior vice president of exploration and a director
of Enserch Exploration, Inc., with responsibility for its worldwide oil and gas
exploration and development program. Prior to joining Enserch, Mr. Lutz spent 28
years with Getty Oil Company. He advanced through several technical, supervisory
and managerial positions which gave him various responsibilities including
exploration, production, lease acquisition, administration and financial
planning.
John H. Trescot, Jr. has served as a director of Magnum Hunter since June
1997. Mr. Trescot is the principal of AWA Management Corporation, a consulting
firm specializing in financial evaluations for companies and entities such as
the Overseas Private Investment Corp. Mr. Trescot began his professional career
as an engineer with Shell Oil Company. Later, Mr. Trescot joined Hudson Pulp &
Paper Corp. (now a part of Georgia-Pacific Corp.) where he served 19 years in
various positions in woodlands and pulp and paper, advancing to the position of
senior vice president for its Southern Operations. Mr. Trescot then became vice
president of The Charter Company, a multi- billion dollar corporation with
operations in oil, communications and insurance. In 1979, Mr. Trescot became the
chief executive officer of JARI, a timber, pulp and mining operation in the
Amazon Basin of Brazil. During 1982-89, while he was the chief executive officer
of TOT Drilling Corp., TOT drilled many deep wells in West Texas and New Mexico
for major and independent oil companies. Mr. Trescot received his BME degree
from Clemson University and his M.B.A. from Harvard University.
James E. Upfield has served as a director of Magnum Hunter since December
1995. Mr. Upfield was appointed a director of Hunter Resources, Inc., in August
1992. Mr. Upfield is chairman of Temtex Industries, Inc., a public company based
in Dallas, Texas, that produces consumer hard goods and building materials. In
1969, Mr. Upfield served on a select Presidential Committee overseeing postal
operations of the United States of America. He later accepted the responsibility
for the Dallas region, which encompassed Texas and Louisiana. From 1959 to 1967,
Mr. Upfield was president of Baifield Industries, Inc. and its predecessor, a
company he founded in 1949 which merged with Baifield in 1963. Baifield was
engaged in prime government contracts for military systems and sub-systems in
the production of high-strength, light-weight metal products.
53
Item 11. Executive Compensation.
The following table contains information with respect to all cash
compensation paid or accrued by the Company during the past three fiscal years
to the Company's Chief Executive Officer and each person serving as an executive
officer of the Company on December 31, 2001.
Long Term Compensation
Annual Compensation Awards Payout
(a) (b) (c) (d) (e) (f) (g) (h) (i)
Name, Other Number
Principal Annual Restricted Options LTP All Other
Position Year Salary Bonus Compensation (a) Stock SARs Payouts Compensation
-------- ---- ------ ----- ------------- ----- ---- ------- ------------
Gary C. Evans 2001 $350,000 $425,000 $ 7,500 - - - $20,627 (b)
Chairman, President and 2000 $300,000 $400,000 $ 7,500 - - - $19,933 (b)
CEO 1999 $250,000 $250,000 $ 7,500 - - - $19,342 (b)
Richard R. Frazier 2001 $190,000 $150,000 $ 6,000 - - - -
President of 2000 $175,000 $125,000 $ 6,000 - - - -
Magnum Hunter 1999 $150,000 $ 75,000 $ 4,200 - - - -
Production, Inc.
Chris Tong 2001 $165,000 $100,000 $ 6,000 - - - -
Senior Vice President & 2000 $160,000 $ 65,000 $ 6,000 - - - -
Chief Financial Officer 1999 $150,000 $ 35,000 $ 6,000 - - - -
R. Douglas Cronk 2001 $138,000 $ 75,000 $ 6,000 - - - -
Senior V.P. of Magnum 2000 $122,500 $ 65,000 $ 6,000 - - - -
Hunter Production, Inc. 1999 $115,000 $ 25,000 $ 4,200 - - - -
Charles R. Erwin (c) 2001 $145,000 $125,000 $ 6,000 - - - -
Senior V.P. of Magnum 2000 $113,423 $125,000 $ 5,100 - - - -
Hunter Production, Inc. 1999 $ 90,000 $ 7,500 - - - - -
- ---------------------
(a) Other compensation consists of a vehicle allowance paid to the
employee.
(b) Mr. Evans receives compensation for acting as an individual Trustee for
the TEL Offshore Trust.
(c) Mr. Erwin was hired in May 1999.
54
Option/SAR Grants in Last Fiscal Year
Alternative to
Potential realizable value at (f) and (g):
assumed annual rates of stock grant date
Individual Grants price appreciation for option termvalue
- -------------------------------------------------------------------------------- ----------------------------- -------------
Name Number of Percent of total Exercise or base Expiration 5% ($) 10% ($) Grant date
securities options/SARs price ($/Sh) date present value
underlying granted to $
Options/SARs employees in
granted (#) fiscal year
(a) (b) (c) (d) (e) (f) (g) (f) *
- ------------------- -------------- --------------- -------------- ------------ --------------- ------------- -------------
Gary C. Evans 300,000 19.0% $8.44 12/12/11 $1,518,000
Richard R. Frazier 125,000 7.9% $8.44 12/12/11 632,500
Charles R. Erwin 100,000 6.3% $8.44 12/12/11 506,000
R. Douglas Cronk 75,000 4.7% $8.44 12/12/11 379,500
Chris Tong 75,000 4.7% $8.44 12/12/11 379,500
* The Company used the Black-Scholes method to determine the value of the
option grants.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of securities Value of unexercised in-
underlying unexercised the-money options/SARs
options/SARs at fiscal at fiscal year-end ($)
year-end (#)
Shares acquired on Value Exercisable/ Exercisable/
Name exercise (#) Realized ($) unexercisable unexercisable
(a) (b) (c) (d) (e)
- ---------------------------------------------------------------- ---------------------------------------------------
Gary C. Evans 150,000 $570,000 330,000 / 420,000 $913,500 / $645,250
Richard R. Frazier 100,000 $393,000 240,000 / 210,000 $904,500 / $311,750
Charles R. Erwin - - 68,000 / 148,000 $ 60,900 / $ 68,150
R. Douglas Cronk 76,666 $525,579 91,334 / 112,000 $304,819 / $138,475
Chris Tong 11,800 $ 74,398 202,200 / 108,000 $820,790 / $136,300
Compensation of Directors
The Company has nine individuals who serve as directors, eight of which are
independent. One director receives compensation with respect to his services and
in his capacities as an executive officer of the Company and no additional
compensation has historically been paid for his services to the Company as a
director. The other eight directors of the Company were not employees of the
Company at December 31, 2001 and receive no compensation for their services as
directors other than as stated below. For fiscal year 2001, independent
directors received a $15,000 retainer for being a board member and in addition
received $1,500 per meeting attended and $500 per committee meeting attended. In
addition, for the fiscal year 2001 each independent director was granted stock
options to acquire 15,000 shares of the Company's common stock at an exercise
price not less than the market price
55
of the common stock on the date of grant. For fiscal year 2002, independent
directors will receive a $15,000 retainer (pro-rated) for being a board member
and in addition will receive $1,500 per meeting attended and $500 per committee
meeting attended. Other than the compensation stated herein, the Company has not
entered into any arrangement, including consulting contracts, in consideration
of the director's service on the board.
Employment Contracts and Termination of Employment and Change-in-Control
Arrangements
Mr. Gary C. Evans, Mr. Richard R. Frazier, Mr. Chris Tong, Mr. R. Douglas
Cronk and Mr. Charles R. Erwin each have employment agreements with the Company.
Mr. Evans' agreement terminates January 1, 2006 and continues thereafter on a
year to year basis and provides for a salary of $300,000 per annum unless
increased by the Board. Mr. Evans' salary for the year 2002 is $375,000. Mr.
Frazier's agreement terminates January 1, 2006 and continues thereafter on a
year to year basis and provides for a salary of $175,000 per annum unless
increased by the Board. Mr. Frazier's salary for the year 2002 is $205,000. Mr.
Tong's agreement terminates January 1, 2004 and continues thereafter on a year
to year basis and provides for a salary of $160,000 per annum unless increased
by the Board. Mr. Tong's salary for the year 2002 is $175,000. Mr. Cronk's
agreement terminates January 1, 2004 and continues thereafter on a year to year
basis and provides for a salary of $122,500 per annum unless increased by the
Board. Mr. Cronk's salary for the year 2002 is $150,000. Mr. Erwin's agreement
terminates January 1, 2004 and continues thereafter on a year to year basis and
provides for a salary of $105,000 per annum unless increased by the Board. Mr.
Erwin's salary for the year 2002 is $155,000. All of the agreements provide that
the same benefits supplied to other Company employees shall be available to the
employee. The employment agreements also contain, among other things, covenants
by the employee that in the event of termination, he will not compete with the
Company in certain geographical areas or hire any employees of the Company for a
period of two years after cessation of employment.
In addition, all of the agreements contain a provision that upon a
change-in-control of the Company and the employee's position is terminated or
the employee leaves for "good cause", the employee is entitled to receive,
immediately in one lump sum, certain compensation. In the case of Mr. Evans and
Mr. Frazier, the employee shall receive three times the employee's base salary,
bonus for the last fiscal year and any other compensation received by him in the
last fiscal year. In the case of Mr. Tong, Mr. Cronk and Mr. Erwin, the employee
shall receive the employee's base salary, bonus for the last fiscal year and any
other compensation received by him in the last fiscal year multiplied by two.
Also, any medical, dental and group life insurance covering the employee and his
dependents shall continue until the earlier of (i) 12 months after the
change-in-control or (ii) the date the employee becomes a participant in the
group insurance benefit program of a new employer. The Company also has key man
life insurance on Mr. Evans in the amount of $12,000,000.
56
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth certain information as of March 15, 2002,
regarding the share ownership of the Company by (i) each person known to the
Company to be the beneficial owner of more than 5% of the outstanding shares of
Common Stock of the Company, (ii) each director, (iii) the Company's Chief
Executive Officer and the four other most highly compensated executive officers
of the Company, and (iv) all directors and executive officers of the Company, as
a group. None of the directors or executive officers named below, as of march
15, 2002, owned any shares of the Company's Series A Preferred Stock or its 1996
Series A Convertible Preferred Stock. The business address of each officer and
director listed below is: c/o Magnum Hunter Resources, Inc., 600 East Las
Colinas Blvd., Suite 1100, Irving, Texas 75039.
Common Stock
Beneficially Owned
Number of Percent
Name Shares of Class (m)
Directors and Executive Officers
Gary C. Evans .......................................... 3,026,073 (a) 4.3%
Richard R. Frazier...................................... 363,115 (b) *
Chris Tong.............................................. 210,133 (c) *
R. Douglas Cronk ....................................... 145,102 (d) *
Charles R. Erwin........................................ 68,000 (e) *
Gerald W. Bolfing....................................... 467,349 (f) *
Jerry Box............................................... 48,335 (g) *
Robert Kelley........................................... 7,195 *
Jim Kneale ............................................. 10,000 (h) *
James R. Latimer, III .................................. 2,195 *
Matthew C. Lutz......................................... 746,729 (i) *
John H. Trescot, Jr..................................... 120,056 (j) *
James E. Upfield....................................... 142,392 (k) *
All directors and executive officers as a group
(13 persons)............................................ 5,356,674 7.4%
Beneficial owners of 5 percent or more
(excluding persons named above)
ONEOK Resources Company
100 W. Fifth Street
Tulsa, OK 74103-4298 ................................... 7,936,507 11.3%
Natural Gas Partners V, L.P.
125 E. John Carpenter Freeway, Suite 600
Irving, TX 75062........................................ 13,417,052 (l) 19.1%
- ------------
* Less than one percent.
(a) Includes 330,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 494,921 common stock
purchase warrants which are currently exercisable. Also includes 17,024 shares
held in the name of Jacquelyn Evelyn Enterprises, Inc., a corporation whose sole
shareholder is Mr. Evans' wife. Mr. Evans disclaims any ownership in such
securities other than those in which he has an economic interest.
(b) Includes 240,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(c) Includes 196,200 shares of common stock issuable upon the exercise of
certain currently exercisable options.
57
(d) Includes 91,334 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(e) Includes 68,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(f) Includes 15,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 84,339 common stock
purchase warrants which are currently exercisable.
(g) Includes 31,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(h) Includes 9,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(i) Includes 523,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 49,641 common stock
purchase warrants which are currently exercisable.
(j) Includes 11,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(k) Includes 11,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. Also includes 15,848 common stock
purchase warrants which are currently exercisable.
(l) Based on Schedule 13G filed by Natural Gas Partners V, L.P. on March
15, 2002.
(m) Percentage is calculated on the number of shares outstanding plus those
shares deemed outstanding under Rule 13d-3(d)(1) under the Exchange Act.
Item 13. Certain Relationships and Related Transactions.
The Company's Board of Directors authorized a loan of up to $371,860 be
made available to Gary C. Evans, President and Chief Executive Officer of the
Company, as part of his compensation package. The balance outstanding at
December 31, 1999 was $371,860 and bears interest at 10%. On January 7, 2000 Mr.
Evans repaid $225,000 on the loan, leaving a principal balance of $146,860. On
April 17, 2000 Mr. Evans re-borrowed $100,000 under this loan, and on August 18,
2000 he repaid $258,731, including accrued interest, bringing the balance to
zero. On December 28, 2000 Mr. Evans borrowed $294,938, which was the balance
owed to the Company on December 31, 2000 and included in notes receivable from
affiliate. On January 15, 2001 Mr. Evans repaid $295,261, including accrued
interest, bringing the balance to zero. On April 16, 2001, Mr. Evans borrowed
$300,000 pursuant to a loan approved by the Company's Board of Directors for the
payment of deferred income taxes. Subsequent to December 31, 2001, Mr. Evans
repaid the loan in full, including accrued interest, bringing the balance to
zero.
On November 28, 2000, Mr. Matthew C. Lutz, Chairman and Executive Vice
President of the Company, borrowed $65,000 from the Company with the approval of
the Board of Directors. On January 15, 2001, Mr. Lutz repaid the loan, including
accrued interest.
During 1998, the Company acquired certain shares of a publicly traded oil
and gas company from Mr. Gary C. Evans at Mr. Evans' cost basis in such shares
of stock. The shares were purchased for a total of $442,019. The Company has the
right through December 31, 2002 to cause Mr. Evans to repurchase the shares back
from the Company at the equivalent price that the Company purchased the shares
from Mr. Evans.
58
GLOSSARY
As used in this document:
"Mcf" means thousand cubic feet;
"MMcf" means million cubic feet;
"Bcf" means billion cubic feet;
"Bbl" means barrel;
"MBbls" means thousand barrels;
"MMBbls" means million barrels;
"BOE" means barrel of oil equivalent;
"MMBOE" means million barrels of oil equivalent
"Btu" or "British Thermal Unit" means the quantity of heat required to
raise the temperature of one pound of water by one degree Fahrenheit;
"MMBtu" means million British Thermal Units;
"Mcfe" means thousand cubic feet of natural gas equivalent;
"MMcfe" means million cubic feet of natural gas equivalent; and
"Bcfe" means billion cubic feet of natural gas equivalent.
Natural gas equivalents and crude oil equivalents are determined using the
ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural
gas liquids. All estimates of reserves, unless otherwise noted, are reported on
a "net" basis. Information regarding production, acreage and numbers of wells is
set forth on a gross basis, unless otherwise noted.
"Proved reserves" means the estimated quantitie of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes
(A) that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
59
(A) oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";
(B) crude oil, natural gas, and natural gas liquids, the recovery of which
is subject to reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be recovered
from oil shales, coal, gilsonite and other such sources.
"PV-10" means the pre-tax present value of estimated future net revenues
computed by applying current prices of oil and gas reserves (with consideration
of price changes only to the extent provided by contractual arrangements) to
estimated future production of proved oil and gas reserves, less estimated
future expenditures (based on current costs) to be incurred in developing and
producing the proved reserves computed using a discount factor of 10% and
assuming continuation of existing economic conditions.
"Proved developed oil and gas reserves" means reserves that can be expected
to be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
"Proved undeveloped reserves" means reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
"Reserve Life" is an estimate of the productive life of a proved reservoir
and for purposes of this document is calculated by dividing the proved reserves
(on an Mcfe basis) at the end of the period by historical production volumes for
the prior 12 months.
"Standardized Measure of Discounted Future Net Cash Flows" means PV-10
after income taxes.
60
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this report:
1. Financial Statements
Independent Auditors' Report...........................................................................F-1
Financial Statements:
Consolidated Balance Sheets at December 31, 2001 and 2000......................................F-2
Consolidated Statements of Operations and Comprehensive Income
for the Years Ended December 31, 2001, 2000 and 1999..............................F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2001, 2000 and 1999..........................................F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2001, 2000 and 1999................................................F-5
Notes to Consolidated Financial Statements.............................................................F-6
Supplemental Information (Unaudited)..................................................................F-30
2. Financial Statement Schedule
We have included on page 64 of this Annual Report on Form 10-K Financial
Statement Schedule II, Valuation and Qualifying Accounts.
61
3. Exhibits
Number Description of Exhibit
3.1 & 4.1 Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-18, File
No. 33-30298-D)
3.2 & 4.2 Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for
the year ended December 31, 1990)
3.3 & 4.3 Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration
Statement on Form SB-2, File No. 33-66190)
3.4 & 4.4 Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration
Statement on Form S-3, File No. 333-30453)
3.5 & 4.5 * Articles of Amendment to Articles of Incorporation
3.6 & 4.6 By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File
No. 33-66190)
3.7 & 4.7 Amendment to By-Laws (Incorporated by reference to Registration Statement on Form S-4, File
No. 333-76774)
3.8 & 4.8 Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K
dated December 26, 1996, filed January 3, 1997)
3.9 & 4.9 Amendment to Certificate of Designations for 1996 Series A Convertible Preferred Stock
(Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453)
4.10 Form of Warrant Agreement by and between Magnum Hunter Resources, Inc. and American Stock
Transfer & Trust Company, as warrant agent (Incorporated by reference to Registration Statement
on Form S-3, File No. 333-82552)
4.11 Form of Warrant Agreement by and between Midland Resources, Inc. and Stock Transfer
Company of America, Inc., as warrant agent, dated November 1, 1990 (Incorporated by reference to
Registration Statement on Form S-3, File No. 333-83376)
4.12 Form of Warrant Agreement by and between Vista Energy Resources, Inc. and American Stock
Transfer & Trust Company, as warrant agent, dated October 28, 1998 (Incorporated by reference to
Registration Statement on Form S-3, File No. 333-83376)
4.13 Indenture dated May 29, 1997 between Magnum Hunter Resources, the subsidiary guarantors
named therein and First Union National Bank of North Carolina, as Trustee (Incorporated by
reference to Registration Statement on Form S-4, File No. 333-2290)
4.14 Supplemental Indenture dated January 27, 1999 between Magnum Hunter Resources, the
subsidiary guarantors named therein and First Union National Bank of North Carolina, as Trustee
(Incorporated by reference to Form 10-K for the fiscal year-end December 31, 1998 filed April 14,
1999)
4.15 Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form
S-4, File No. 333-2290)
4.16 * Indenture, dated March 15, 2002, 2002, between Magnum Hunter Resources, Inc., the subsidiary
guarantors named therein and Bankers Trust Company, as Trustee.
4.17 Shareholder Rights Agreement dated as of January 6, 1998 by and between Magnum Hunter
Resources, Inc. and Securities Transfer Corporation, as Rights Agent (Incorporated by reference
to Form 8-K dated January 7, 1998, filed January 9, 1998)
10.1 * Fourth Amended and Restated Credit Agreement, dated March 15, 2002, between Magnum Hunter
Resources, Inc. and Bankers Trust Company, et al.
10.2 Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-K for the fiscal
year-end December 31, 1999 filed March 30, 2000)
10.3 Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-K for the
fiscal year-end December 31, 1999 filed March 30, 2000)
10.4 * Employment Agreement for Chris Tong
10.5 * Employment Agreement for R. Douglas Cronk
10.6 * Employment Agreement for Charles Erwin
62
10.7 Purchase and Sale Agreement, dated February 27, 1997 among
Burlington Resources Oil and Gas Company, Glacier Park Company
and Magnum Hunter Production, Inc. (Incorporated by reference
to Form 8-K, dated April 30, 1997, filed May 12, 1997)
10.8 Purchase and Sale Agreement between Magnum Hunter Resources, Inc. , NGTS, et al., dated
December 17, 1997 (Incorporated by reference to Form 8-K, dated December 17, 1997, filed
December 29, 1997)
10.9 Purchase and Sale Agreement dated November 25, 1998 between Magnum Hunter Production, Inc.
and Unocal Oil Company of California (Incorporated by reference to Form 10-K for the fiscal year-
end December 31, 1998 filed April 14, 1999)
10.10 Stock Purchase Agreement dated February 3, 1999 between ONEOK Resources Company and
Magnum Hunter Resources, Inc. (Incorporated by reference to Form 8-K, dated February 3, 1999,
filed February 11, 1999)
10.11 Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by
reference to Form 10-Q/A for the period ended June 30, 2000 filed November 30, 2000)
21* Subsidiaries of the Registrant
23* Consent of Deloitte and Touche LLP
* Filed herewith.
(B) Form 8-K's - None.
63
Independent Auditors' Report
Board of Directors and Stockholders
Magnum Hunter Resources, Inc.
We have audited the consolidated financial statements of Magnum Hunter
Resources, Inc. and Subsidiaries as of December 31, 2001 and 2000, and for each
of the three years in the period ended December 31, 2001, and have issued our
report thereon dated March 22, 2002; such report is included elsewhere in this
Annual Report on Form 10-K. Our audits also included the consolidated financial
statement schedule of Magnum Hunter Resources, Inc. and Subsidiaries, listed in
Item 14. This consolidated financial statement schedule is the responsibility of
the Company's management. Our responsibility is to express an opinion based on
our audits. In our opinion, such consolidated financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as a
whole, presents fairly, in all material respects, the information set forth
therein.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 22, 2002
64
Valuation and Qualifying Accounts
($ in thousands)
For the year ended December 31, 2001:
Balance at Additions
Beginning of Charged to Deductions Balance at
Description Period Expenses Writeoffs end
of Period
- --------------------------------------------- ------------------ ---------------- ----------------- -----------------
Accounts receivable, trade $ 50 $ 3,214 $ - $ 3,264
Current portion of long-term notes 1,170 - - 1,170
receivable
Investment in unconsolidated affiliate - 453 - 453
For the year ended December 31, 2000:
Balance at Additions
Beginning of Charged to Deductions Balance at
Description Period Expenses Writeoffs end
of Period
- --------------------------------------------- ------------------ ---------------- ----------------- -----------------
Accounts receivable, trade $ 166 $ 80 $ (196) $ 50
Current portion of long-term notes 790 384 (4) 1,170
receivable
65
SIGNATURES
Pursuant to the requirements of the Section 13 or 15 (d) of the Securities
and Exchange Act of 1934, the Company has duly caused this Form 10-K to be
signed on its behalf by the undersigned, thereunto duly authorized.
MAGNUM HUNTER RESOURCES, INC.
By: /s/ Gary C. Evans April 12, 2002
---------------------------------------------
Gary C. Evans, Chairman, President
& CEO
In accordance with the Exchange Act, this Form 10-K has been signed below
by the following persons on behalf of the Company and in the capacities and on
the dates indicated.
Signature Title Date
/s/ Gary C. Evans Chairman, President April 12, 2002
- ------------------------------------- Chief Executive Officer
Gary C. Evans
/s/ Chris Tong Senior Vice President and April 12, 2002
- --------------------------------------- Chief Financial Officer
Chris Tong
/s/ David S. Krueger Vice President and April 12, 2002
- ----------------------------------- Chief Accounting Officer
David S. Krueger
/s/ Morgan F. Johnston Vice President, General Counsel April 12, 2002
- ------------------------------- and Secretary
Morgan F. Johnston
/s/ Gerald W. Bolfing Director April 12, 2002
- -----------------------------------
Gerald W. Bolfing
/s/ Matthew C. Lutz Director April 12, 2002
- -----------------------------------
Matthew C. Lutz
/s/ John H. Trescot, Jr. Director April 12, 2002
- -----------------------------------
John H. Trescot, Jr.
/s/ James E. Upfield Director April 12, 2002
- ------------------------------------
James E. Upfield
66