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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the fiscal year ended December 31, 2000
[ ] 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
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State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039
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(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (972) 401-0752
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
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 20, 2001, 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 $272,795,355.
The number of shares outstanding of the registrant's common stock at March
20, 2001 was 35,399,739.
TABLE OF CONTENTS
Securities and Exchange Commission
Item Number and Description
PART I
Item 1. Business............................................................1
The Company........................................................1
Business Strategy .................................................2
Properties ........................................................3
Development and Exploration Activities ............................7
Gathering and Processing of Gas ...................................9
Marketing of Production ..........................................10
Petroleum Management and Consulting Services .....................10
Competition.......................................................11
Regulation .......................................................11
Employees ........................................................13
Facilities .......................................................13
Risk Factors......................................................13
Item 2. Description of Properties..........................................19
Oil and Gas Reserves .............................................19
Oil and Gas Production, Prices and Costs .........................22
Drilling Activity ................................................23
Oil and Gas Wells ................................................24
Oil and Gas Acreage ..............................................24
Item 3. Legal Proceedings..................................................25
Item 4. Submission of Matters to a Vote of Security Shareholders...........25
PART II
Item 5. Market for Common Equity and Related Stockholder Matters...........25
Item 6. Selected Financial Data............................................26
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................28
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.........37
Item 8. Financial Statements and Supplementary Data.......................F-1
Item 9. Change in and Disagreements with Accountants on Accounting
and Financial Disclosure.........................................39
PART III
Item 10. Directors and Executive Officers of the Registrant..................39
Item 11. Executive Compensation..............................................44
Item 12. Security Ownership of Certain Beneficial Owners and Management......47
Item 13. Certain Relationships and Related Transactions......................48
Glossary............................................................49
Item 14. Exhibits, Financial Statement Schedule and Reports on Form 8-K......52
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Form 10-K under "Item 1. Business," "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and elsewhere in this Form 10-K constitute "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21B of the Securities Exchange Act of 1934, as amended. All
statements, other than statements of historical facts, included in this Form
10-K that address activities, events or developments that Magnum Hunter
Resources, Inc. and its subsidiaries (collectively, the "Company") expects,
projects, believes or anticipates will or may occur in the future, including
such matters as oil and gas reserves, future drilling and operations, future
production of oil and gas, future net cash flows, future capital expenditures
and other such matters, are forward-looking statements. Such forward-looking
statements involve known and unknown risks, uncertainties and other factors
which may cause the actual results, performance or achievements of the Company
to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. Such factors include,
among others, the following: the volatility of oil and gas prices, the Company's
drilling results, the Company's ability to replace reserves, the availability of
capital resources, the reliance upon estimates of proved reserves, operating
hazards and uninsured risks, competition, government regulation, the ability of
the Company to implement its business strategy and other factors referenced in
this Form 10-K.
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 Coast/Gulf of Mexico. In December 1995, the Company
consummated the acquisition of all of the subsidiaries of Hunter Resources,
Inc., a Pennsylvania corporation, and the management of Hunter Resources, Inc.
assumed operating control of the Company. The new management team implemented a
business strategy that emphasized 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 1999, the Company acquired properties from
Burlington Resources Inc. ("Burlington"), Spirit Energy 76 ("Spirit 76"), a
business unit of Union Oil Company of California, and Vastar Resources, Inc.
("Vastar"). 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 in its geographic area of operations and on its
substantial inventory of exploration, exploitation and development drilling
opportunities. The Company also has identified over 237 development drilling
locations (including both production and injection wells) 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 approximately a 40% beneficial ownership
interest in TEL Offshore Trust ("TEL"), 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 in the shallow waters in the Gulf of
Mexico.
Additionally, the Company owns over 480 miles of gas gathering systems and
a 50% or greater ownership interest in three 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, 2000, the Company had an interest in 3,043 wells and had
estimated Proved Reserves of 367 Bcfe with a PV-10 of $1.1 billion.
Approximately 72% of these reserves were Proved Developed Reserves and 45% were
attributable to the Mid-Continent Region, 45% were attributable to the Permian
Basin, and 10% were attributable to the Gulf Coast/Gulf of Mexico Region. At
December 31, 2000, the Company's Proved Reserves had an estimated Reserve Life
of approximately 14 years and were 63.5% natural gas. The Company serves as
operator for approximately 71% of its properties, based on the gross number of
producing wells in which the Company owns an interest and 81% of its properties,
based upon the year-end PV-10 value.
As a result of its property acquisitions and successful drilling activities
during 2000, the Company has achieved growth as described below:
o After taking into account the Company's divestitures in 2000, Proved
Reserves increased 7% to 367.0 Bcfe at year- end 2000 from 341.1 Bcfe at
year-end 1999;
o PV-10 increased 197% to $1.1 billion at year-end 2000 from $370.1 million
at year-end 1999; and
o Average daily production increased 2% to 74.8 MMcfe during fiscal 2000
from 73.6 MMcfe in fiscal 1999. The Company had an exit rate of approximately 82
MMcfe at year-end 2000.
Recent Activities
Federal Lease Sale. The Company was the high bidder on 45 separate lease
blocks at the Central Gulf of Mexico Federal Lease sale held March 28, 2001. The
Company bid the majority of the blocks with a 25% - 50% working interest in
partnership with other companies, including Remington Oil and Gas Corporation,
Chieftain International, Inc. and The Wiser Oil Company. These blocks are
generally located in less than 150 feet of water and near existing
infrastructure.
Strategic Alliance. On May 23, 2000, the Company and GE Capital Structured
Finance Group formed a new partnership, Mallard Hunter LP, to acquire certain
oil and gas reserves from two of the Company's subsidiaries. The Company, which
is the general partner, received an initial 1% interest in the limited
partnership. The Company's partner received an initial 99% interest as a limited
partner in the limited partnership for an initial capital contribution of
approximately $22.9 million. The limited partnership thereafter purchased
approximately 20 billion cubic feet equivalent of proved producing reserves from
the Company's subsidiaries for approximately $23.2 million, which represented
99% of the value of such reserves (the Company having contributed 1% of the
value for its 1% interest in the limited partnership). The reserves were
approximately 60% oil and 40% natural gas. The Company used the net proceeds
received from the limited partnership to reduce commercial bank indebtedness on
its two existing credit lines. At such time as the limited partner has received
distributions from the limited partnership equal to its $22.9 million initial
capital contribution, any subsequent capital contributions and an interest
component, the Company's and the limited partner's interests in the limited
partnership will thereafter be 35% and 65%, respectively.
Divestiture of Properties. On August 31, 2000, the Company sold non-core
natural gas reserves associated with 107 producing wells in the Sonora area of
West Texas to Louis Dreyfus Natural Gas Corp., a major operator and producer of
natural gas in the Sawyer (Canyon) Field. The sales price was $15.75 million,
before post-closing adjustments, and had a July 1, 2000 effective date. These
properties were originally acquired by Magnum Hunter in May 1997 from Burlington
Resources, Inc. Proceeds from the sale were used to reduce the Company's
commercial bank indebtedness.
Business Strategy
The Company's objective is to increase its reserves, production, cash flow
and earnings utilizing a program of (i) a selective exploration program; (ii)
exploitation and development of acquired properties, and (iii) strategic
acquisitions of Proved Reserves.
The following are key elements of the Company's strategy:
2
Exploration. The Company is participating in drilling Gulf of Mexico
exploratory wells in an effort to add shorter- lived, higher output production
to its reserve mix. The use of 3-D seismic as a tool in its exploratory drilling
in the Gulf of Mexico has to date been highly effective. The Company also
attempts to align itself with active Gulf of Mexico industry partners who have
similar philosophies and goals with respect to a "fast track" program in placing
new production online. This typically involves drilling wells near existing
infrastructure such as production platforms, facilities and pipelines. The
Company also has an active onshore exploration program concentrated in its
various areas of operation.
Exploitation and Development of Existing Properties. The Company has a
substantial inventory of exploitation projects including development drilling,
workovers and recompletions. The Company seeks to maximize the value of its
properties through development activities including in-fill drilling,
waterflooding and other enhanced recovery techniques.
Property Acquisitions. Although the Company has an extensive inventory of
exploitation and development opportunities, it continues to pursue strategic
acquisitions which fit its objectives of having Proved Reserves with development
potential and operating control.
Management of Operating Costs. The Company emphasizes strict cost controls
in all aspects of its business and seeks to operate its properties wherever
possible. By operating approximately 71% of its properties (81% of its PV-10
value), the Company is generally able to control direct operating and drilling
costs as well as to manage the timing of development and exploration activities.
Expansion of Gas Gathering, Processing and Marketing Operations. The
Company has implemented several programs to expand and increase the efficiency
of its gas gathering systems and gas processing plants. The Company owns over
56% and markets directly and indirectly approximately 88% of the natural gas
that moves through its gas gathering systems and, therefore, benefits from any
cost and productivity improvements. In December 1997, the Company acquired a 30%
interest in NGTS, LLC ("NGTS"), a natural gas marketing company marketing gas
for third parties in the amount of approximately 375 MMcf per day as of December
31, 2000. At December 31, 2000, NGTS marketed approximately 30% of the Company's
natural gas. The Company will consider opportunities to acquire or develop
additional gas gathering and processing facilities that are associated with its
current production.
Properties
The Company's major properties are located in three areas: (i) the
Mid-Continent Region, (ii) the Permian Basin and (iii) the Gulf Coast/Gulf of
Mexico.
Mid-Continent Region
The Company's properties located in the Mid-Continent Region were acquired
principally from Burlington, Spirit 76 and Vastar.
On June 28, 1996, the Company purchased from Burlington interests in 520
gas wells in the Texas Panhandle and western Oklahoma, all of which are operated
by the Company, and an associated 427 mile gas gathering system (the "Panoma
Properties"). As of year-end 2000, the Company had drilled an additional 90
wells and net production was approximately 12.5 million cubic feet of natural
gas per day. The net purchase price for this acquisition in 1996, after certain
purchase price adjustments, was $34.7 million, funded by borrowings under the
Company's previous senior credit facility. Gruy is the operator of the gas
gathering system and the wells that were previously operated by Burlington.
On December 31, 1998 the Company acquired from Spirit 76 natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
producing approximately 11 million cubic feet of natural gas equivalent per day
net to the Company. The purchase price was approximately $25 million after
certain purchase price adjustments including preferential rights exercised by
third parties and other customary adjustments.
3
In June 1999, the Company acquired Vastar's interest in 476 wells, a gas
processing plant and two gas gathering systems located in the states of Texas,
Oklahoma and Arkansas. The total purchase price was $32.5 million, after
purchase price adjustments, including an April 1, 1999 effective date. The
reserves and related assets are located in the Walnut Bend Field in North
Central Texas, the Madill Field in Southern Oklahoma, and the Walker Creek Field
in Southwestern Arkansas. The Company's working interests in the three fields
range from 19% to 100%. For December 2000, the three fields generated net sales
of approximately 816 barrels per day of liquids and 3 million cubic feet per day
of natural gas production (total 8 million cubic feet equivalents per day).
The Company has received an engineering evaluation from Ryder Scott Company
("Ryder Scott") 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 Ryder
Scott and Cawley Gillespie, as of December 31, 2000, the Mid-Continent
properties had Proved Reserves of 8 MMBbl of oil and 119 Bcf of natural gas, or
on a Natural Gas Equivalent basis, 166 Bcfe. Ryder Scott and Cawley Gillespie
further estimated the PV-10 for the Mid-Continent properties to be $505 million
as of December 31, 2000. The Proved Reserves are located principally in the
Ardmore Basin in south central Oklahoma, in the Oklahoma/Texas panhandle and in
Southwestern Arkansas. Approximately 71% of the estimated reserves are natural
gas and 29% are oil located on approximately 88,000 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 2000 was approximately 23 million cubic feet of natural gas
production and 980 barrels of oil. Approximately 91% of the Proved Reserves were
classified Proved Developed Reserves as of December 31, 2000. The Company's
wholly-owned subsidiary, Gruy, is the operator of 89% or 663 of the 743 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 561
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 2000, net production was approximately 12.5 MMcf/d.
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 potential exists for additional wells 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 118
wells, with working interests varying from 17.2% to 100%. The Company operates
all but nine of these wells. For the month of December 2000, gross production
from the field averaged 6,367 Mcf/d and 199 Bbl/d.
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 30
active injection wells. The Company's working interest ownership in the wells is
approximately 91%. For the month of December 2000, gross production from the
wells averaged 232 Mcf/d and 846 Bbl/d.
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
62 active producing wells. The Company's working interest ownership in the wells
varies from 50% to 100%. For the month of December 2000, gross production from
the wells averaged 2,211 Mcf/d and 83 Bbl/d.
4
Permian Basin
On April 30, 1997 the Company acquired from Burlington, effective as of
January 1, 1997, 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"), for a net purchase price of $133.8 million after adjustments
aggregating $9.7 million. 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 1,706
producing oil and gas wells on approximately 65,000 gross acres (56,600 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 100 possible sites
in the Westbrook Field (4.7 MMBbl of Proved Reserves) and opportunities for
tertiary recovery using carbon dioxide injection in the Levelland-Slaughter
Field (1.2 MMBbl of Proved Reserves).
According to Ryder Scott and Cawley Gillespie, as of December 31, 2000, the
Permian Basin Properties had Proved Reserves of 13 MMBbl of oil and 84 Bcf of
gas, or on a Natural Gas Equivalent basis, 159 Bcfe. Ryder Scott and Cawley
Gillespie further estimated the PV-10 for the Permian Basin Properties to be
$392 million as of December 31, 2000. Approximately 65% of the Proved Reserves
were classified as Proved Developed Reserves as of December 31, 2000. See
"Properties - Oil and Gas Reserves."
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 298 active producing wells. The
Company's working interest ownership in the wells varies from 0.02% to 100%. For
the month of December 2000, net production from the wells averaged 391 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 2000.
Levelland/Slaughter. The Levelland and Slaughter Fields consist of 186
wells 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 97 active producing wells. The Company's working interest ownership in
the wells varies from 6% to 100%. For the month of December 2000, gross
production from the wells averaged 503 Mcf/d and 538 Bbl/d.
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 Ryder Scott to either the TLB Unit or the
Veal Lease. Proved Undeveloped Reserves were assigned by Ryder Scott 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 successfully
enhanced production.
Southeast New Mexico Properties. The Southeast New Mexico Properties
consist of approximately 430 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
5
generally shallower than 3,000 feet. Additionally, the Company owns
interests in approximately 20 wells that produce from the Morrow formation in
Eddy County, New Mexico where a current increased density program is ongoing.
The Morrow formation is found at approximately 11,500 feet. We participated in
the drilling of 7 wells in 2000 and has budgeted to drill an additional 11 wells
in 2001. For the Southeast New Mexico properties, approximately 27 proved
undeveloped locations have been identified by the Company's third-party
petroleum engineering consultants.
Gulf Coast/Gulf of Mexico
The Company owns properties both onshore Gulf Coast and offshore Gulf of
Mexico.
Onshore Gulf Coast
The Company owns various ownership interests in five horizontal wells in
the Mossy Grove prospect in Walker County, Texas. The interests which the
Company owns in these three wells range from a 25% to a 65% working interest.
The field produces from the Glen Rose formation at a depth of approximately
12,000 feet. The initial discovery was completed in July 1998 with the latest
two wells being drilled in 2000 and 2001. The Company owns an average of a 25%
working interest in a 36,000 acre lease block surrounding the producing wells. A
sixth well is currently being drilled in which the Company owns a 25% working
interest. RME Petroleum, a wholly-owned subsidiary of Anadarko Petroleum
Corporation, is the operator of the drilling phase for this well and owns the
remaining 75% working interest. The Company operates all of the field
production. For the month of December 2000, gas production from the three
producing wells was approximately 3,700 Mcf/d. Additional development drilling
is planned in this field in future years.
Other onshore Gulf Coast properties are located in 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.
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. TEL produced a total of approximately
0.832 Bcfe in calendar 2000.
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
2000, this program achieved a result of 16 new discoveries in 20 separate fault
block attempts. Seven of these successes are producing approximately 25 million
cubic feet of natural gas equivalent per day net to the Company as of the end of
February 2001. Ten additional new discoveries (one of which was discovered in
2001) are scheduled to commence production during the remainder of 2001 and will
add substantially to existing daily net production rates. The Company currently
owns an interest in over 35 blocks in the Gulf of Mexico ranging from 12.5% to
100% with expectations of adding to this lease inventory at the March 2001
offshore lease sale. See "Recent Activities". The Company plans to participate
in 10-12 new exploratory offshore drilling projects in 2001. Over 300 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.
The Company has received an engineering evaluation from Ryder Scott and
DeGoyler and MacNaughton ("D&M"), independent petroleum engineers engaged by the
Company to evaluate the Company's properties, on the net reserves in the Gulf of
Mexico. According to Ryder Scott and D&M, as of December 31, 2000, the Gulf of
Mexico properties had Proved Reserves of 1.9 MMBbl of oil and 31 Bcf of natural
gas, or on a Natural Gas Equivalent basis, 42 Bcfe. Ryder Scott and D&M further
estimated the PV-10 for the Gulf of Mexico properties to be $203 million as of
December 31, 2000. Approximately 73% of the estimated reserves are natural gas
and 27% are oil located on approximately 430,040 net mineral leasehold acres.
Total net daily production from the Gulf of Mexico properties for the month of
December 2000 was approximately 13 million cubic feet of natural gas production
and 189 barrels of oil.
6
Gas Processing Plants
McLean Plant
On January 1, 1997, the Company complemented its Panoma acquisition by
purchasing for $2.5 million 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 2000, throughput of the plant averaged 13.3 million cubic feet
per day with processed liquids of 867 barrels per day.
Madill Plant
On December 1, 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 for approximately $8.4
million. 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 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 2000,
throughput of the plant averaged 11.9 million cubic feet per day of natural gas
with processed liquids of 680 barrels per day. See "Gathering and Processing of
Gas."
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. 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 2000,
throughput of the plant averaged 8.6 MMcf/d with processed liquids of 411 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 $51 million
for exploitation and development activities for 2001 with $28 million of such
budget allocated to the Company's proved undeveloped reserves. The Company spent
$4.1 million, $1.4 million and $7.9 million, respectively, developing its proved
undeveloped reserves for the years ended 2000, 1999 and 1998. The Company has
identified 237 development drilling locations (including both production and
injection wells) 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.
7
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.
In-fill development has been underway in the fields with 101 wells having been
drilled and completed during the last four years. The westernmost field has now
been developed with 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 to complete development of
the shallow gas on 160-acre spacing. One well was drilled and several
recompletions were successfully performed in 2000. Additional drilling and
recompletions are budgeted in 2001.
Additional Mid-Continent development, drilling and recompletion activities
will focus on the Walnut Bend Field in Cooke County, Texas and the Morrison
Ranch Field in Roberts County, Texas.
Permian Basin Properties. In evaluating the Permian Basin Properties, the
Company has identified over 200 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 29
wells are for 2001.
Onshore Gulf Coast. The Company owns various ownership interests in five
horizontal wells in the Mossy Grove prospect in Walker County, Texas. The
interests which the Company owns in these three wells range from a 25% to a 65%
working interest. The field produces from the Glen Rose formation at a depth of
approximately 12,000 feet. The initial discovery was completed in July 1998 with
the latest two wells being drilled in 2000 and 2001. The Company owns an average
of a 25% working interest in a 36,000 acre lease block surrounding the producing
wells. A sixth well is currently being drilled in which the Company owns a 25%
working interest. RME Petroleum, a wholly-owned subsidiary of Anadarko Petroleum
Corporation, is the operator of the drilling phase for this well and owns the
remaining 75% working interest. The Company operates all of the field
production. For the month of December 2000, gas production from the three
producing wells was approximately 3,700 Mcf/d. Additional development drilling
is planned in this field in future years.
Exploratory Drilling
The Company spent $40 million of its $60 million 2000 capital budget on
exploratory drilling and related land and geophysical costs. Sixteen exploratory
wells were drilled in 2000 of which 15 were successful providing the Company
with a 94% 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 16 new discoveries in 20 attempts by the end of 2000 and is expected to
continue to add significantly to reserves and cash flow as these new properties
are put on production. Currently, production from seven new offshore platforms
is approximately 25 MMcfe/d net to the Company. Ten new platforms scheduled to
commence production in 2001 should add substantially to these levels. The
Company owns an interest ranging from 12.5% to 100% in over 40 offshore blocks
and expects to add significantly to the number of OCS blocks in 2001. See
"Recent Events". An aggressive drilling program will continue in 2001.
The onshore exploration program also continues to meet with success.
Drilling in New Mexico in 2000 and early 2001 has resulted in six new Morrow gas
wells with working interests ranging from 50% to 90%. Per well production is
expected to range from 1 million to 8 million cubic feet of natural gas per day.
A new shallow zone oil discovery is producing over 70 Bbl/d. Over 30 locations
remain to be drilled as a follow-up to this activity in New Mexico.
8
In West Texas, 12 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 350 Bbl/d and over 25 locations
remain to be drilled.
A new discovery in the Texas Panhandle 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. and Bluebird Energy, Inc., both wholly-owned
subsidiaries of the Company, own 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 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.
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 year end 2000, gas
throughput for the Panoma gas gathering system was approximately 14.8 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 500 of the approximately 585
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 1, 1997, the Company purchased for $2.5 million 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
2000, throughput was approximately 13.3 MMcf 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 December 1, 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 2000, throughput of the plant was approximately 11.9 million
cubic feet per day of natural gas with processed liquids of 680 barrels per day.
9
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. On May 24, 2000, the Company sold a 44.2%
interest in the Walker Creek Plant to Mallard Hunter L.P., the Company's new
partnership discussed in Recent Activities - Strategic Alliance on page 2. 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 2000, throughput of the plant was approximately 8.6 MMcf/d
with processed liquids of 411 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 62% of our volume) or (ii) at market responsive prices under
multi-year contracts (approximately 38% 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, a subsidiary of Natural Gas Transmission
Services, Inc. ("NGTS, Inc."). NGTS assumed all of NGTS Inc.'s operations as of
December 1, 1997. The Company acquired its interest in NGTS for consideration of
$4.35 million.
NGTS is a Dallas-based natural gas marketing and trading company with
operations concentrated in the western two-thirds of the country. In fiscal
2000, NGTS reported total revenues of approximately $522 million. NGTS is
presently marketing approximately 375 million cubic feet of natural gas per day.
In fiscal 1999, NGTS reported total revenues of approximately $277 million. For
1998, the Company and its gas gathering subsidiary, Hunter Gas Gathering, Inc.,
dedicated substantially all of its natural gas production to NGTS for marketing.
As of December 31, 2000, NGTS marketed approximately 30% of the Company's
natural gas under short term contracts. The balance of the Company's 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 44-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.
10
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 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.
11
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.
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.
12
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.
Employees
At December 31, 2000, the Company had 95 full-time employees of which 29
were management, 33 were administrative and 33 were field employees. 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 and Taylor, Arkansas. The Company also leases
field production offices in Midland and Abilene, Texas, Hobbs, New Mexico and
Oklahoma City, Oklahoma.
Risk Factors
Risks Related to Substantial Leverage
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We have a significant amount of debt
We are highly leveraged, with outstanding long-term debt of approximately
$191 million compared to stockholders' equity of $93.4 million as of December
31, 2000. Our level of indebtedness affects our future operations. Because we
must dedicate a substantial portion of our cash flow from operations to the
payment of interest on our debt, the cash flow is not available for other
purposes. The covenants contained in our credit facilities require us to meet
certain 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, our
high debt to equity ratio, and the pledge of substantially all of our assets as
collateral for our primary credit facility will, for the foreseeable future,
make it difficult for us to obtain financing on an unsecured basis or to obtain
secured financing other than certain "purchase money" indebtedness
collateralized by the acquired assets.
13
To service our indebtedness, we will require a significant amount of cash
While we reported operating profits for fiscal years 2000 and 1999, we
reported an operating loss for fiscal 1998, and at December 31, 2000, we had an
accumulated deficit of $50.2 million. Our ability to meet our financial
covenants and to make scheduled payments of principal and interest to repay our
indebtedness depends upon our operating results and our ability to obtain
financing. However, we cannot be certain that our business will generate
sufficient cash flow from operations or that future bank credit will be
available in an amount sufficient to enable us to service our indebtedness or
make necessary capital expenditures. In such event, we would need to obtain such
financing from the sale of equity securities, other debt financing or the sale
of certain of the Company's properties. We cannot predict whether any such
financing will be available on terms acceptable to us. If we are not able to
secure such financing, we may not be able to continue to implement our business
strategy.
Despite our current indebtedness levels, we still may be able to incur more debt
Our primary credit facility limits our borrowings to a borrowing base
amount determined by the lenders, in their sole discretion, based upon a variety
of factors, including the amount of indebtedness that our oil and gas reserves
and other assets can adequately support. As of December 31, 2000, we had $22.5
million of borrowing available under the borrowing base for our current credit
facility. Our subsidiary Bluebird Energy, Inc. has a non-recourse revolving
credit facility which, as of December 31, 2000, had $21.4 million of borrowing
available. A significant decline in oil or gas prices below their current levels
could materially adversely affect the availability of funds under our credit
facility.
We must maintain certain financial ratios
Our primary credit facility also requires us to satisfy certain financial
ratios in the future. One covenant requires that we maintain a ratio of funded
indebtedness divided by the sum of funded indebtedness plus equity (the "Debt to
Capitalization Ratio") of not more than 0.80 to 1.0. At December 31, 2000, we
had a Debt to Capitalization Ratio of 0.58 to 1.0. Another covenant requires us
to maintain a ratio of Consolidated EBITDA to Interest Expense (as defined in
our primary credit facility agreements) of not less than 2.00 to 1.0 for the
calendar quarters ending September 30, 2000 and thereafter. We had a ratio of
Consolidated EBITDA to Interest Expense of 3.99 to 1.0 as of December 31, 2000.
The Consolidated EBITDA to Interest Expense ratio is very sensitive to oil and
gas price levels, and a lowering of product prices in the future might
jeopardize our compliance with this ratio. We are considering several
alternatives to reduce this risk, including the acquisition or drilling of
higher cash flow producing properties (shorter reserve life) to somewhat offset
our long-lived reserve base or monetizing certain of our non-strategic assets.
If we fail to satisfy these covenants or any of the other covenants in our
credit facilities, that failure would constitute an event of default thereunder
and, subject to certain grace periods, may permit the lenders to accelerate the
indebtedness then outstanding under the applicable credit facility and demand
immediate repayment thereof.
Our Business Is Dependent on Conditions in the Oil and Gas Industry
- -------------------------------------------------------------------
Our revenues, profitability and the carrying value of our oil and gas
properties depend substantially upon prevailing prices of, and demand for, oil
and gas and the costs of acquiring, finding, developing and producing reserves.
Oil and gas prices also substantially affect our ability to maintain or increase
our borrowing capacity, to repay current or future indebtedness, and to obtain
additional capital on attractive terms. Historically, the markets for oil and
gas have been volatile and are likely to continue to be volatile in the future.
Prices for oil and gas fluctuate widely in response to:
o relatively minor changes in the supply of, and demand for, oil and gas;
o market uncertainty; and
o a variety of additional factors, all of which are beyond our control.
14
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. Our
production is predominantly weighted toward gas, making our earnings and cash
flow more sensitive to gas price fluctuations. Also, our ability to market our
production depends in part upon the availability, proximity and capacity of
gathering systems, pipelines and processing facilities. Volatility in oil and
gas prices could affect our ability to market our production through such
systems, pipelines or facilities. Currently, we sell substantially all our gas
production to gas marketing firms or end users either on the spot market on a
month-to-month basis at prevailing spot market prices or under long-term
contracts based on current spot market prices. An affiliate of ONEOK Inc. has
the right to market the undedicated natural gas we sell in the state of Oklahoma
until February 2004 or such earlier date as ONEOK affiliates cease to own a
specified percentage of our equity securities. At December 31, 2000, ONEOK was
marketing production from 38 wells for a total of 2,634 Mcf/d.
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. As a result
of the severe decline in oil and gas prices in 1998, we recognized a non-cash
impairment of oil and gas properties of $42.7 million at December 31, 1998
pursuant to such "ceiling" test in the full cost method of accounting. Certain
subsequent improvements in pricing reduced the amount of such charge. Without
the benefit of these pricing improvements, we would have incurred an impairment
of $81.2 million. Once incurred, a write-down of oil and gas properties is not
reversible at a later date even if oil and gas prices increase.
You Should Not Place Undue Reliance on Our Reserve Data Because
They Are Estimates
- ----------------------------------------------------------------
This annual report contains estimates of our oil and gas reserves and the
future net cash flows from those reserves that were prepared or audited by
independent petroleum consultants. There are numerous uncertainties inherent in
estimating quantities of proved reserves of oil and gas and in projecting future
rates of production and the timing of development expenditures, including many
factors beyond our control. The estimates in this annual report rely on various
assumptions, including, for example, constant oil and gas prices, operating
expenses, capital expenditures and the availability of funds, and, therefore,
are 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. Additionally, we
may have to revise our reserves based upon actual production performance,
results of future development and exploration, prevailing oil and gas prices and
other factors, many of which are beyond our control.
You should not construe the present value of proved reserves referred to in
this annual report as the current market value of the estimated proved reserves
of oil and gas attributable to our properties. In accordance with Securities and
Exchange Commission requirements, we have based the estimated discounted future
net cash flows from proved reserves on prices and costs as of the date of the
estimate, whereas 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 using a 10% discount as required by the Securities and Exchange Commission
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,
supply and demand for oil and gas, prevailing oil and gas prices and other
factors.
15
Maintaining Reserves And Revenues in The Future Depends on Successful
Exploration And Development
- -----------------------------------------------------------------------
Our future success depends upon our ability to find or acquire additional
oil and gas reserves that are economically recoverable. Unless we successfully
explore or develop or acquire properties containing proved reserves, our proved
reserves will generally decline as we produce them. The decline rate varies
depending upon reservoir characteristics and other factors. Our future oil and
gas reserves and production, and, therefore, cash flow and income, depend
greatly upon our success in exploiting our current reserves and acquiring or
finding additional reserves. We cannot assure that our planned development
projects and acquisition activities will result in significant additional
reserves or that we will successfully drill productive wells at economic returns
to replace our current and future production.
Our 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.
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 that we will be able to successfully integrate
all of the oil and gas properties that we acquire into our operations or will
achieve desired profitability objectives.
Risks Associated With Exploration And Development
- --------------------------------------------------
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 recently expanded and plan to increase our capital expenditures on our
exploration efforts, which involve a higher degree of risk than our development
activities. It is possible that we will not obtain any commercial production or
that drilling and completion costs will exceed the value of production. The cost
of drilling, completing and operating wells is often uncertain. Numerous
factors, including title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of equipment,
may curtail, delay or cancel drilling operations. Furthermore, completion of a
well does not assure a profit on the investment or a recovery of drilling,
completion and operating costs.
We conduct waterflood projects and other secondary recovery operations
Secondary recovery operations involve certain risks, especially the use of
waterflooding techniques, and drilling activities in general. Our inventory of
development prospects includes waterflood projects. With respect to our
properties located in the Permian Basin, we have identified significant
potential expenditures related to further developing existing waterfloods.
Waterflooding involves significant capital expenditures and uncertainty as to
the total amount of recoverable secondary reserves. In waterflood operations,
there is generally a delay between the initiation of water injection into a
formation containing hydrocarbons and any increase in production. The operating
cost per unit of production of waterflood projects is generally higher during
the initial phases of such projects due to the purchase of injection water and
related costs. Costs are also higher during the later stages of the life of the
project as crude oil production declines. The degree of success, if any, of any
secondary recovery program depends on a large number of
16
factors, including the amount of primary production, the porosity and
permeability of the formation, the technique used, the location of injector
wells and the spacing of both producing and injector wells.
We Are Subject to Casualty Risks in Our Onshore And Offshore Activities
- -------------------------------------------------------------------------
Our 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 insurance at levels that we believe are
reasonable, we are not fully insured against all risks. We do not carry business
interruption insurance except on rare occasion. Losses and liabilities arising
from uninsured or under-insured events could materially affect our financial
condition and operations.
We Hedge Our Oil And Gas Production
- -----------------------------------
As of December 31, 2000, we had hedged approximately (i) 15% of our gas
production through December 31, 2001, and (ii) 65% of our oil production through
June 30, 2001. These hedges have in the past involved fixed price arrangements
and other price arrangements at a variety of prices, floors and caps. We have in
the past and may in the future enter into oil and gas futures contracts, options
and swaps. Our hedging activities, while intended to reduce our 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
could fail to perform. Additionally, the fixed price sales and hedging contracts
limit the benefits we 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
management of waste, protection of water, air quality, the discharge of
materials into the environment, and 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 certain circumstances, impose
retroactive, strict, and joint and several liability, potentially resulting in
liability for environmental damage regardless of negligence or fault. From time
to time, we have agreed to indemnify sellers of producing properties against
certain liabilities for environmental claims associated with such properties. We
cannot assure that new laws or regulations, or modifications of or new
interpretations of existing laws and regulations, will not increase
substantially the cost of compliance or adversely affect our oil and gas
operations and financial condition. Material indemnity claims may also arise
with respect to properties acquired by or from us. 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.
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
17
substantially exceed our resources. Our competitors in acquisitions,
development, exploration and production include major oil companies, natural gas
utilities, numerous independents, 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: Gary C.
Evans, Matthew C. Lutz and Richard R. Frazier. The loss of the services of any
one of these individuals could materially impact our operations.
Shares Eligible For Future Sale; Absence of Dividends
- ------------------------------------------------------
The market price of our common stock could be adversely affected by sales
of substantial amounts of common stock in the public market or the perception
that such sales could occur
We are authorized to issue up to 100,000,000 shares of common stock. As of
March 20, 2001, 35,399,739 shares were issued and outstanding, and 4,938,449
shares were reserved for issuance upon the exercise of certain outstanding
warrants and options. Issuing additional shares of common stock pursuant to such
outstanding options and warrants would reduce the proportionate ownership and
voting rights of the common stock then outstanding. Our existing management and
their affiliates own 2,974,780 shares of common stock that may in the future be
sold in compliance with Rule 144 adopted under the Securities Act of 1933. In
addition, our primary credit facility contains a debt to capitalization ratio
covenant requiring us to maintain a ratio of .80 to 1.0. The possibility that
substantial amounts of common stock may be sold in the public market may
adversely affect prevailing and future market prices for the 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 the common stock and do
not anticipate paying dividends on the common stock in the foreseeable future.
We intend to reinvest all available funds for the development of our business.
In addition, we cannot pay any dividends on the common stock unless and until we
pay all dividend rights on outstanding preferred stock which have in the past
been paid on a timely basis. Our primary credit facility and the indenture
governing our 10% Senior Notes due 2007 also restrict the payment of cash
dividends on certain securities.
Preferred Stock; Anti-takeover Provisions
- ------------------------------------------
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 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 shareholder approval, except in limited
circumstances. We have previously issued several series of preferred stock,
although only the 1996 Series A Convertible Preferred Stock and the 1999 Series
A 8% Convertible Preferred Stock, are currently outstanding. The holders of the
1996 Series A Convertible Preferred Stock currently have the right to appoint
one additional member to the Board of Directors and upon certain circumstances,
up to 75% of our Board. The holders of the 1999 Series A 8% Convertible
Preferred Stock currently have the right to nominate two members of our Board,
and, subject to the rights of the 1996 Series A Convertible Preferred Stock
holders, upon certain circumstances have the right to nominate additional
directors. 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 shareholders' interest.
18
Certain anti-takeover provisions may affect your rights as a stockholder
Our Articles of Incorporation and Bylaws include certain 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 and the availability of authorized but unissued common
stock. In addition, on January 9, 1998, we adopted a shareholder rights plan.
Under the shareholder 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 one one-hundredth of a share. The rights become
exercisable only if a person or a group acquires or commences a tender offer for
15% or more of our common stock. Until they become exercisable, these rights
attach to and trade with our common stock. The rights issued under the
shareholder rights plan expire January 20, 2008. Issuing preferred stock may
delay or prevent a change in control of Magnum Hunter without further
shareholder action and may adversely affect the rights and powers, including
voting rights, of the holders of common stock. In certain circumstances, the
issuance of preferred stock could depress the market price of the common stock.
In addition, a change of control, as defined under the 10% Senior Notes
indenture, would entitle the holders of our 10% Senior Notes due 2007 to put
those notes to Magnum Hunter under the indenture governing such notes and the
lenders to accelerate payment of outstanding indebtedness under our credit
facility. Both of these events could discourage takeover attempts by making such
attempts more expensive.
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 Ryder Scott Company of
Houston, Texas, Cawley Gillespie & Associates, Inc. of Fort Worth, Texas and
DeGoyler and MacNaughton of Dallas, Texas, 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 by Ryder Scott Company and Pollard,
Gore and Harrison of Austin, Texas for 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, 2000, 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. As
required by rules of the Securities and Exchange Commission, 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. In accordance with Commission rules, estimates have been made
using constant oil and gas prices and operating costs, at December 31, 2000, or
as otherwise indicated.
19
In accordance with Commission guidelines, 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,
------------------------------------------------
2000 1999 1998
------------------------------------------------
Gas (per Mcf).................. $ 9.28 $2.25 $2.12
Oil (per Bbl).................. $25.59 $24.03 $9.42
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.
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,
2000. 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 Commission) since January 1, 2000.
20
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, 2000,
1999 and 1998.
Estimated Proved Oil and Natural Gas Reserves (a)
At December 31,
----------------------------------------------
2000 1999 1998
----------------------------------------------
Net gas reserves (Mcf):
Proved developed............ 179,697,015 184,954,732 174,987,374
Proved undeveloped.......... 53,511,550 45,044,794 44,072,300
----------------------------------------------
Total proved gas reserves. 233,208,565 229,999,526 219,059,674
==============================================
Net oil reserves (Bbl):
(including condensate and NGL)
Proved developed............ 13,923,380 16,299,585 9,474,591
Proved undeveloped.......... 8,380,082 9,234,165 7,874,050
----------------------------------------------
Total proved oil reserves. 22,303,462 25,533,750 17,348,641
==============================================
Total Proved Reserves (Mcfe)..... 367,029,337 383,202,026 323,151,521
==============================================
Estimated PV-10 of Proved Reserves (a)
At December 31,
---------------------------------------------
2000 1999 1998
---------------------------------------------
Estimated PV-10 (b) :
Proved developed............ $ 829,683,640 $ 282,481,193 $ 160,984,895
Proved undeveloped ......... 269,843,116 87,609,991 18,424,052
---------------------------------------------
Proved Reserves PV-10 (c). $1,099,526,756 $ 370,091,184 $ 179,408,947
=============================================
- ------------
(a) Based upon reserve reports at December 31, 2000 prepared by Ryder
Scott, Cawley Gillespie and D&M and at December 31, 1999 and December 31, 1998
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, 2000, 1999 and 1998, respectively,
were as follows: $804,923,000, $315,616,000 and $176,148,000.
Significant Properties
On December 31, 2000, 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
Coast/Gulf of Mexico. On such date, the Company's properties included working
interests in 3,043 gross (1,720 net) productive oil and gas wells.
21
The following table sets forth summary information with respect to the
Company's estimated Proved Reserves of oil and gas at December 31, 2000.
PV-10 (a) Proved Reserves
----------------------------------------------------------------------------
Natural Gas
Amount % of Oil Gas Equivalent
(in thousands) Total (Bbl) (Mcf) (Bcfe)
-------------------------------------------- --------------- ---------------
Mid-Continent Area (b)............... 505,186 45% 7,959,245 118,558,470 166.31
Permian Basin Region (b)............. 391,532 36% 12,474,315 83,869,110 158.72
Gulf Coast/Gulf of Mexico (c) ....... 202,809 19% 1,869,902 30,780,985 42.00
----------------------------------------------------------------------------
Total......................... 1,099,527 100% 22,303,462 233,208,565 367.03
============================================================================
- ----------
(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, 2000 prepared by Ryder Scott
and Cawley Gillespie.
(c) Based on reserve reports at December 31, 2000 prepared by Ryder Scott
and D&M.
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,
2000 1999 1998
---------------------------------------------------------
Oil and gas production:
Oil (Mbbl)...................................... 1,298 1,307 1,141
Gas (MMcf)...................................... 19,579 19,026 14,119
Natural Gas Equivalents (MMcfe)................. 27,368 26,868 20,965
Average sales price (a):
Before Hedge Contracts:
Oil (per Bbl)................................ $ 28.91 $ 17.55 $ 11.79
Gas (per Mcf)................................ 4.08 2.16 1.90
Natural Gas Equivalents (per Mcfe)........... 4.28 2.38 1.92
After Hedge Contracts:
Oil (per Bbl)................................ $ 22.95 $ 15.01 $ 12.67
Gas (per Mcf)................................ 3.90 2.16 2.02
Natural Gas Equivalents (per Mcfe)........... 3.88 2.26 2.05
Oil and gas production lifting costs (per Mcfe) .. .60 .57 .68
Production taxes and other costs (per Mcfe) (b)... $ .46 $ .30 $ .31
- ----------
(a) Before deduction of production taxes and net of hedging results.
(b) Includes ad valorem taxes, insurance, bonds, company overhead and net
profits interest.
22
Drilling Activity
The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 2000, 1999 and 1998.
Gross Wells (a) Net Wells (b)
Year Type of Well Total Producing (c) Dry (d) Total Producing (c) Dry (d)
---- ------------ ----- ------------- ------- ----- ------------- -------
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
1998 Exploratory
Texas 5 4 1 3.25 2.64 0.61
Oklahoma 0 0 0 0 0 0
New Mexico 1 1 0 .05 .05 0
Other 0 0 0 0 0 0
Development
Texas 79 79 0 74.4 74.4 0
Oklahoma 0 0 0 0 0 0
New Mexico 5 5 0 5 5 0
Other 0 0 0 0 0 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.
23
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, 2000. All of these
wells are located in the United States.
Productive Wells
As of December 31, 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Gross (a) Net (b)
Location Oil Gas Total Oil Gas Total
- -------- --- --- ----- --- --- -----
Texas...................... 1,374 745 2,119 702 491 1,193
Offshore Texas ............ 0 3 3 0 1 1
Oklahoma................... 140 275 415 84 164 248
Mississippi................ 1 0 1 0 0 0
New Mexico................. 148 282 430 73 167 240
California................. 5 0 5 1 0 1
Offshore Louisiana......... 0 24 24 0 9 9
Arkansas................... 46 0 46 28 0 28
---------------------------------------------------------------------------------------------------------
Total............. 1,714 1,329 3,043 888 832 1,720
=========================================================================================================
- ----------
(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, 2000.
Developed Undeveloped
--------- -----------
Gross (a) Net (b) Gross (a) Net (b)
--------- ------- --------- -------
Offshore........................... 80,320 31,040 113,360 32,110
Texas.............................. 260,000 215,000 75,000 40,000
Oklahoma........................... 100,000 72,000 7,000 3,400
Mississippi........................ 528 452 - -
New Mexico......................... 42,000 36,000 - -
California......................... 509 38 - -
-------------------------------------------------------------------------------------
Total ....................... 483,357 354,530 195,360 75,510
=====================================================================================
- ----------
(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.
24
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 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 2000.
PART II
Item 5. Market for Common Equity and Related Stockholder Matters.
The Common Stock of the Company has been listed on the American Stock
Exchange since March 8, 1996. The Common Stock has been listed under the ticker
symbol "MHR" since March 18, 1997, prior to which time it was listed under the
ticker symbol "MPM." At March 20, 2001, there were 3,319 stockholders of record.
Average Daily
Trading Volume
High Low (Shares)
-------------------------------------------------
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
1999
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . .$ 3.19 $ 2.50 53,351
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.19 $ 2.75 45,792
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . .$ 4.25 $ 3.19 25,211
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3.94 $ 2.50 46,576
On March 20, 2001, the last reported sale price of the Company's Common
Stock on the American Stock Exchange was $11.88 per share.
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 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.
25
Item 6. Selected Financial Data
The selected historical financial data sets forth summary historical
consolidated financial data of the Company as of and for the years ended
December 31, 2000, 1999, 1998, 1997, and 1996, which have been derived from the
Company's 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 the Company's 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.
1996 1997 1998 1999 2000
---------- ---------- ---------- ------------ -------------
Income Statement Data:
Total operating revenues.......................... $16,412 $ 48,834 $ 51,400 $ 69,626 $127,510
Total operating costs and expenses (a)............ 13,541 38,833 94,414 54,514 77,181
-------------------------------------------------------------------------
Operating profit (loss)........................... 2,871 10,001 (43,014) 15,112 50,329
Income (loss) before extraordinary loss........... 509 (2,128) (47,080) (6,826) 22,260
Extraordinary loss from early extinguishment
of debt, net of taxes .......................... - (1,384) - - -
Net Income (loss) ................................ 509 (3,512) (47,080) (6,826) 22,260
Dividends applicable to preferred shares (b)...... (406) (875) (875) (4,509) (9,708)
Income (loss) applicable to common shares......... $ 103 $ (4,387) $(47,955) $(11,335) $ 12,552
Income (loss) per common share before
extraordinary item
Basic (b)...................................... $ 0.01 $ (0.21) $ (2.27) $ (0.57) $ 0.60
Diluted (b).................................... $ 0.01 $ (0.21) $ (2.27) $ (0.57) $ 0.51
Income (loss) per common share after
extraordinary item
Basic (b)...................................... $ 0.01 $ (0.30) $ (2.27) $ (0.57) $ 0.60
Diluted (b).................................... $ 0.01 $ (0.30) $ (2.27) $ (0.57) $ 0.51
Other Data:
EBITDA (c)........................................ $ 6,166 $ 22,740 $ 22,112 $ 37,538 $ 76,362
Capital expenditures (d).......................... $41,471 $160,059 $ 70,187 $ 59,968 $ 64,311
- --------
(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.
(b) 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.
(c) EBITDA is defined as income (loss) before income taxes and minority
interest, plus the sum of depletion and depreciation 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.
(d) 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.
26
1996 1997 1998 1999 2000
--------- --------- ----------- ----------- ------------
Balance Sheet Data:
Working capital (deficiency)....................... $ 2,279 $ 2,610 $ (1,203) $ (1,314) $ 4,121
Property, plant and equipment, net................. 73,648 221,259 228,436 265,195 260,532
Total assets....................................... 83,072 251,069 265,724 304,022 315,612
Total debt (a)..................................... 38,766 161,543 231,020 234,806 191,139
Stockholders' equity............................... $ 35,154 $ 72,152 $ 19,697 $ 51,552 $ 93,416
- -----------
(a) Consists of long-term debt, including current maturities of long-term
debt, and excluding production payment liabilities of $937 thousand, $743
thousand, $633 thousand, $460 thousand and $359 thousand as of December 31,
1996, 1997, 1998, 1999 and 2000, respectively. As of December 31, 2000, 1999 and
1998, $20.6 million, $41.8 million and $26.0 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.
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 (a)................. $ 0.02 $ 0.13 $ 0.20 $ 0.24
Income per common share, diluted (a)............... $ 0.02 $ 0.12 $ 0.15 $ 0.19
1999
---------------------------------------------------------------
First Second Third Fourth
-------------- -------------- ------------- ----------------
Revenues........................................... $ 13,105 $ 15,359 $ 19,864 $ 21,298
Depreciation, depletion and amortization........... 5,148 5,467 5,768 5,689
Net Operating Profit............................... 1,266 2,539 5,539 5,768
Net Income (Loss).................................. (4,962) (2,340) 213 263
Loss per common share, basic....................... $ (0.29) $ (0.18) $ (0.05) $ (0.05)
Loss per common share, diluted..................... $ (0.29) $ (0.18) $ (0.05) $ (0.05)
(a) 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.
27
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. 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.
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. 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 and increased oil field services
income.
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 is conducting exploration 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.
28
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
2000 1999 1998
--------------------------------------------
Oil and Gas Operations
- --------------------------------------------------------------------------------
Reported Production:
Oil (MBbls)...................... 1,298 1,307 1,141
Gas (MMcf)....................... 19,579 19,026 14,119
Oil and Gas (MMcfe).............. 27,368 26,868 20,965
Equivalent Daily Rate (MMcfe/day) 74.8 73.6 57.4
Underlying Production (*):
Oil (MBbls)...................... 1,175 1,041 871
Gas (MMcf)....................... 18,008 16,187 12,399
Oil and Gas (MMcfe).............. 25,059 22,436 17,625
Equivalent Daily Rate (MMcfe/day) 68.5 61.5 48.3
(*) Adjusted for the sale of properties in June and September 2000.
Average Sale Prices (after hedging)
Oil (per Bbl).................... $ 22.95 $ 15.01 $ 12.67
Gas (per Mcf).................... 3.90 2.16 2.02
Oil and Gas (per Mcfe)........... 3.88 2.26 2.05
Effect of hedging activities (per Mcfe) (0.41) (0.12) 0.13
Lease Operating Expense (per Mcfe)
Lifting costs.................... 0.60 0.57 0.68
Production tax and other costs... 0.46 0.30 0.31
Gross margin (per Mcfe)............. $ 2.82 $ 1.39 $ 1.06
Gas Gathering, Marketing and
Processing Operations
- --------------------------------------------------------------------------------
Throughput Volumes (Mcf per day)
Gathering........................ 16,639 18,536 20,775
Processing....................... 16,506 21,510 15,668
Gross margin (in thousands).........
Gathering (per Mcf throughput)... 0.18 0.14 0.11
Processing (per Mcf throughput).. 0.50 0.16 0.07
Period to Period Comparisons
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 a record $127.5 million and operating profit
increased 233% to a record $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 record 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.
29
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 . 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 hedging.
From time to time, we enter into various hedging contracts in order to
reduce our exposure to the possibility of declining oil and gas prices. During
2000, 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 have 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 have 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.
30
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 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 hedging positions, anticipated
31
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. 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.
For the Years Ended December 31, 1999 and 1998
We reported a net loss of $6.8 million for the year ended December 31, 1999
versus a net loss of $47.1 million for the same period in 1998. Total operating
revenues increased 35% to $69.6 million in 1999 from $51.4 million in 1998. A
10% increase in the price realized for oil and gas on an Mcfe basis combined
with a 28% increase in oil and gas production on an MMcfe basis was primarily
responsible for the increase in total operating revenues. We reported an
operating profit of $15.1 million in 1999 versus an operating loss of $43.0
million in 1998. In 1998 we recognized an impairment of $42.7 million to our oil
and gas properties due to a severe decline in oil and gas prices. No impairment
provision was necessary in 1999. We also saw significant improvements in our
daily production rates, prices and gross margins for our oil and gas operations
as well as improvements in our gas gathering, marketing and processing
operations in 1999 versus 1998. Loss applicable to common shares was $11.3
million in 1999 versus $48.0 million in 1998. Loss per common share was $0.57
per share, basic and diluted, in 1999 versus $2.27 per share, basic and diluted
in 1998.
Oil and Gas Operations:
For the year 1999, we reported oil production of 1,307 Mbbls (thousand
barrels) and gas production of 19,026 MMcf (million cubic feet), which
represents a 15% increase in oil volume and a 35% increase in gas volume over
1998. The reported production in 1999 was impacted by the acquisition in
December 1998 of the Spirit 76 properties and in June 1999 of the Vastar
properties.
Prices received for oil and gas improved in 1999 over the depressed levels
experienced in 1998. The oil price realized in 1999 after the effects of hedging
was $15.01 per barrel versus the hedge adjusted price of $12.67 in 1998. The
hedge adjusted price for gas realized in 1999 was $2.16 per Mcf versus $2.02 in
1998. This represents a 10% increase on a thousand cubic feet of gas equivalent
(Mcfe) basis in 1999 versus 1998. In 1999, hedging reduced the average oil price
realized by $2.54 per barrel and had no effect on the average gas price
realized. On an equivalent unit basis, hedging reduced our sales price by $0.12
per Mcfe in 1999 and increased our sale price by $0.13 per Mcfe in 1998.
As a result of an increase in both production volumes and oil and gas
prices realized, oil and gas revenues increased 39% to $60.7 million in 1999
versus $43.6 million in 1998.
Lifting costs were $15.4 million in 1999, an 8% increase over 1998. On a
per unit of production basis, lifting costs decreased 16% to $0.57 per Mcfe due
primarily to the acquisition of properties with lower average lifting costs.
Production taxes and other costs were $8.1 million in 1999, a 27% increase over
1998, while on a per unit of production basis, these costs decreased 3% to $0.30
per Mcfe.
For 1999, our gross margin from oil and gas operations increased 62% to
$37.1 million compared to $22.9 million in 1998, principally due to increases in
production and prices. On a per unit of production basis, the margin increased
31% to $1.39 per Mcfe in 1999 from $1.06 per Mcfe in 1998.
32
Gas Gathering, Marketing and Processing Operations:
For 1999, our gathering system throughput was 18.5 MMcf per day versus 20.8
MMcf per day in 1998, an 11% decrease due primarily to the sale of a gathering
system in 1999. Gas processing throughput was 21.5 MMcf per day in 1999
versus15.7 MMcf per day in 1998, a 37% increase due to the Vastar and Madill
acquisitions.
For 1999, the gross margin we realized from gathering, marketing and
processing operations was $2.3 million, a 92% increase over the 1998 gross
margin of $1.2 million. Revenues were $8.2 million in 1999, an 18% increase over
1998 revenues of $7.0 million due to the Madill plant and Vastar acquisitions
and an improvement in product prices. Operating costs were $5.9 million in 1999,
a 2% increase over 1998 costs of $5.8 million. The gross margin from gathering
was $0.14 per Mcf in 1999, a 27% increase over 1998. Gas processing gross
margins increased 129% to $0.16 per Mcf in 1999 over $0.07 per Mcf in 1998 due
to substantially improved processing economics.
Oil Field Services:
Revenues from oil field services and international sales were $768 thousand
in 1999, a 13% decrease from revenues of $881 thousand in 1998, principally due
to a decrease in oil field management services provided to third parties.
Operating costs were $350 thousand in 1999, a $117 thousand decrease over 1998.
The gross operating margin from these activities was $418,000 in 1999 versus
$414,000 in the 1998 period.
Other Income and Expenses:
Depreciation and depletion expense was $22.1 million in 1999 versus $21.8
million in 1998. Depreciation and depletion on oil and gas properties was $0.79
per Mcfe in 1999 versus $1.00 per Mcfe in 1998, a decrease of 21%. The
improvement in rates was partly due to the impairment write-down of $42.7
million to oil and gas properties in 1998. Without the benefit of improvements
in pricing subsequent to December 31, 1998 we would have incurred an impairment
of $81.2 million. While this write-down is not recoverable if prices increase,
it has the effect of lowering our future depletion rates.
We recorded a gain on sale of $272 thousand in 1999 versus a loss on sale
of $52 thousand in 1998. General and administrative expense for 1999 decreased
3% to $2.9 million from $3.0 million in 1998. We recorded equity in loss of
affiliate of $103 thousand in 1999 versus a loss of $116 thousand in 1998,
relating to the operations of our affiliate engaged in natural gas marketing
operations. Other income was $354 thousand in 1999 versus $624 thousand in 1998
due to a decrease in interest income.
Interest expense increased 21% to $22.1 million in 1999 from $18.2 million
in 1998 due to increased levels of borrowing under our revolving credit lines
and an increase in floating interest rates.
We recorded a benefit for deferred income taxes of $13.7 million in 1998
versus no tax benefit in 1999. The benefit was recorded in 1998 based on the
expectation of or utilizing net operating loss carryovers generating this
benefit in future years. No benefit was recorded in 1999 due to the uncertainty
of utilizing additional loss carryovers due to annual limitations on their use
caused by changes in ownership of our common stock.
Dividends on preferred stock were $4.5 million in 1999 versus $875 thousand
in 1998. The increase was due to the issuance of $50.0 million of Series A 8%
Convertible preferred stock in 1999.
Liquidity and Capital Resources
CASH FLOW AND WORKING CAPITAL. Net cash provided by operating activities in
2000, 1999 and 1998 was $49.5 million, $17.4 million and $13.7 million,
respectively. The substantial increase in our operating cash flows in 2000 over
1999 and 1999 over 1998 is primarily the result of higher realized oil and gas
prices. Our net working capital position at December 31, 2000 was $4.1 million.
On that date, Magnum Hunter also had available $22.5 million under its senior
bank credit line, and Bluebird had $21.4 million available under its senior bank
credit line.
33
INVESTING ACTIVITIES. Net cash used in investing activities was $20.0
million in 2000. We realized proceeds of $43.8 million from the sale of non-core
assets during the year, of which approximately $11.6 million was attributable to
Bluebird. Both the Company and Bluebird used these proceeds to repay senior bank
indebtedness. We made cash capital expenditures of $60.8 million under our
capital budget during 2000, of which $19.1 million was attributable to Bluebird.
Our capital expenditures are discussed in further detail below. Additionally, we
made investments in two unconsolidated affiliates totaling $2.6 million and
advanced funds totaling $1.4 million under promissory notes receivable. We
received payments on promissory notes receivable totaling $1.0 million during
the year 2000.
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.
In 1998 we used $74.0 million in investing activities, including $70.2
million for capital expenditures and $3.9 million for other assets. We also
realized $359 thousand in proceeds from sale of assets and made a $332 thousand
loan for a promissory note receivable.
FINANCING ACTIVITIES. Net cash used in financing activities was $31.0
million in 2000. 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 $2.0
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.
In 1998, net cash provided by financing activities was $62.1 million. We
borrowed a total of $80.0 million under our senior bank credit lines, of which
$26.0 million was attributable to Bluebird. We repaid borrowings under our
senior bank credit lines by $10.6 million, of which none was attributable to
Bluebird. We also paid a short term note of $2.7 million, loaned the ESOP $879
thousand, loaned a shareholder $480 thousand, purchased treasury stock for $1.9
million and paid preferred dividends of $875 thousand. Bluebird had a net
increase in cash of $1.9 million.
BLUEBIRD'S CAPITAL RESOURCES. Internally generated cash flow and the
borrowing capacity under its senior bank credit line are Bluebird's major
sources of liquidity. From time to time, Bluebird may also sell properties in
order to increase liquidity. During 2000, Bluebird realized proceeds of $11.6
million from property sales.
On May 23, 2000, Bluebird's commercial banks agreed to allow it to acquire
100% of Magnum Hunter's 1996 Series A convertible preferred stock at liquidation
value, or $10 million, and to purchase up to $500 thousand of Magnum Hunter's
common stock. On December 7, 2000 the convertible preferred and the common stock
were sold to Magnum Hunter Production, Inc. for cash proceeds of $10.5 million.
The proceeds were used to pay down Bluebird's senior credit line. At December
31, 2000 Bluebird's senior credit line borrowing base was set at $42.0 million
and borrowings under the senior credit line were $20.6 million, leaving
availability of $21.4 million at that date. On February 28, 2001 the borrowing
base was reduced to $37.0 million. We believe that this bank credit line, along
with cash flow from operations, provides Bluebird with sufficient liquidity to
meet interest payments as well as carry out its capital spending budget plans
through 2001.
34
MAGNUM HUNTER'S 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 source of liquidity. From time to time, the Company may
also sell properties in order to increase liquidity. During 2000, the Company
realized proceeds of $32.2 million from property sales. 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.
During the year 2000, the Company realized $60.0 million in net proceeds
from the issuance of its common stock, including $57.6 million from the exercise
of both its publically traded and privately held warrants and $2.4 million from
the exercise of employee stock options.
In December 2000 the Company used $10.0 million to purchase all of its 1996
Series A Convertible preferred stock outstanding from Bluebird. This preferred
stock was held by an 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 to the Company's common stock by the holder at the
conversion price of $5.25 per share. As a result of these preferred stock
transactions, the Company no longer has any dividend paying preferred stock
outstanding, which will result in annual savings of approximately $4.9 million
in dividends paid.
The Company's borrowing base under its senior bank credit line was $53.0
million at December 31, 2000 and its borrowings under this line were $30.5
million on that date, leaving availability of $22.5 million on that date. 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.
The Company's internally generated cash flow, results of operations, and
financing for its operations are dependent on oil and gas prices. As a result of
substantial increases in oil and gas prices in 2000 versus 1999, our earnings
and cash flows in 2000 have been materially increased compared to 1999. To the
extent that oil and gas prices decline, the Company's earnings and cash flows
may be adversely affected. However, the Company believes that its cash flow from
operations, existing working capital and availability under its senior bank
credit line will be sufficient to meet interest payments and to fund the capital
expenditure budget for the year 2001.
CAPITAL EXPENDITURES. During 2000, the Company's total capital expenditures
were $64.3 million. Of the total, $8.9 million was for property acquisition
costs, of which $3.5 million (paid in restricted common stock) was spent to
acquire a net profits interest in certain properties. Exploration activities
accounted for $32.5 million, development activities accounted for $22.2 million,
and additions to other assets accounted for $700 thousand of the capital
expenditures. As of December 31, 2000 the Company had total unproved oil and gas
property costs of $5.5 million, consisting of property acquisition costs of $3.9
million and exploratory costs of $1.6 million.
For the year 2001, the Company has budgeted approximately $85 million for
exploration and development activities. The Company is not contractually
obligated to proceed with any of its 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 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.
35
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.
Inflation and Changes in Prices
During 2000, the Company experienced substantial increase in prices for oil
and gas compared to the previous year. 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. Periodically the Company enters into
futures, options, and swap contracts to reduce the effects of fluctuations in
crude oil and gas prices. It is the policy of the Company not to enter into any
such arrangements which exceed 75% of the Company's oil and gas production
during the next 12 months.
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 NGTS, LLC 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. The Company
normally sells its oil under month-to-month contracts to a variety of
purchasers.
New Accounting Standard
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), is 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.
All derivatives within the Company have been identified pursuant to SFAS
No. 133 requirements, and the Company has designated, documented, and assessed
hedging relationships. The Company was obligated to four crude oil derivatives,
one natural gas derivative, and one interest rate derivative on January 1, 2001.
The Company has determined that the interest rate derivative will not qualify
for treatment as a fair value hedge as defined in the Statement. As a result,
the derivative asset or liability related to the interest rate derivative must
be recorded at fair value on the Company's balance sheet with an effect to
income. The crude oil and natural gas derivatives qualify as cash-flow hedges,
which require the Company to record the derivative assets or liabilities at
their fair value on its balance sheet with an offset in other comprehensive
income. Future hedge ineffectiveness on the cash-flow hedges will be recorded in
earnings.
Adoption of this accounting standard as of January 1, 2001 resulted in the
recognition of $179 thousand of derivative assets and $2.8 million of derivative
liabilities with a cumulative effect increase to income of $111 thousand after
tax and with a cumulative effect decrease to other comprehensive income of
approximately $1.8 million after-tax for the transition adjustment as of January
1, 2001.
36
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. The
Company engages in futures contracts with certain of its production through
various contracts ("Swap Agreements"). The primary objective of these activities
is to protect against 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 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, 2000, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
--------------- --------------------- --------------------- ----------------------
Oil
- ------
Collar......... 30,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $33.50
Collar......... 15,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $34.35
Collar......... 15,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $35.50
Collar......... 15,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $36.80
Gas
- ------
Collar......... 300,000 MMBtu Jan 01 - Dec 01 Floor - $ 4.50
Cap - $ 6.15
Based on future market prices at December 31, 2000, the fair value of open
contracts to the Company was a liability of $2.8 million. If future market
prices were to increase 10% from those in effect at December 31, 2000, the fair
value of open contracts to the Company would be a liability of $3.7 million. If
future market prices were to decline 10% from those in effect at December 31,
2000, the fair value of the open contracts to the Company would be a liability
of $1.7 million.
The Company currently intends to commit no more than 75% of its 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.
37
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 following table reflects the terms of the remaining
swap.
Type Notional Amount Termination Date Pay Rate Receive Rate
- ----------------------------- ------------------- ------------------ ------------------ --------------------
Pay Variable/Receive Fixed $50,000,000 06/01/02 LIBOR + 3.34% 10% fixed
through 05/31/00
LIBOR + 3.69%
from 06/01/00 to
06/01/02
Based on future market rates at December 31, 2000, the fair value of open
contracts to the Company was an asset of $179,000. If future market rates were
to increase 10% from those in effect at December 31, 2000, the fair value of
open contracts to the Company would be a liability of $314,000. If future market
rates were to decline 10% from those in effect at December 31, 2000, the fair
value of the open contracts to the Company would be an asset of $603,000.
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 in
2000.
Expected Maturity Dates
(in thousands) 2001 2002 2003 2004-2006 2007 Total Fair Value
-------- -------- --------- --------- -------- --------- ----------
Variable Rate Debt:
Bank Debt with Recourse (a)... $ - $ - $ 30,500 $ - $ $ 30,500 $ 30,500
Bank Debt without Recourse (b) $ - $ 20,600 $ - $ - $ $ 20,600 $ 20,600
Fixed Rate Debt:
Senior Notes (c).............. $ - $ - $ - $ - $140,000 $ 140,000 $ 138,600
Bank Debt with Recourse (d)... $ 19 $ 19 $ 1 $ - $ - $ 39 $ 39
- ------------
(a) The average interest rate on the bank debt with recourse is 8.52%.
(b) The average interest rate on the bank debt without recourse is 9.48%.
(c) The interest rate on the senior notes is a fixed 10%.
(d) The interest rate on the bank debt is a fixed 7.9%.
38
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, 2000 and 1999............F-2
Consolidated Statements of Operations and Comprehensive Income for the
Years Ended December 31, 2000, 1999 and 1998................F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2000, 1999 and 1998................F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2000, 1999 and 1998......................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, 2000, and 1999, 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, 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
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, 2000 and 1999, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States of America.
Deloitte & Touche LLP
Dallas, Texas
March 20, 2001
F-1
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
December 31, December 31,
2000 1999
----------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents.................................................. $ 9 $ 1,565
Restricted cash ........................................................... 1,820 2,145
Accounts receivable
Trade, net of allowance of $50 and $166, respectively................. 30,442 10,203
Due from affiliates................................................... 107 48
Notes receivable from affiliate............................................ 377 398
Current portion of long-term notes receivable, net of allowance of $1,170
and $790, respectively.................................... 50 57
Prepaid and other.......................................................... 2,033 1,296
----------------------------------------------------
Total Current Assets................................................. 34,838 15,712
----------------------------------------------------
Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved............................................................. 5,534 3,567
Proved............................................................... 367,822 349,510
Pipelines.................................................................. 12,581 12,462
Other property............................................................. 2,459 1,964
----------------------------------------------------
Total Property, Plant and Equipment........................................ 388,396 367,503
Accumulated depreciation, depletion, amortization and impairment..... (127,864) (102,308)
----------------------------------------------------
Net Property, Plant and Equipment.......................................... 260,532 265,195
----------------------------------------------------
Other Assets
Deposits and other assets.................................................. 6,570 5,663
Investment in unconsolidated affiliates.................................... 8,054 4,163
Deferred tax asset ........................................................ 5,618 13,289
----------------------------------------------------
$ 315,612 $ 304,022
Total Assets...............................................................====================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities..................................... $ 27,094 $ 15,111
Dividends payable.......................................................... 169 552
Suspended revenue payable.................................................. 3,201 1,357
Current income taxes payable............................................... 234 -
Current maturities of long-term debt, with recourse........................ 19 6
----------------------------------------------------
Total Current Liabilities............................................ 30,717 17,026
----------------------------------------------------
Long-Term Liabilities
Long-term debt, with recourse, less current maturities..................... 170,520 193,000
Long-term debt, non recourse, less current maturities...................... 20,600 41,800
Production payment liability............................................... 359 460
Minority interest.......................................................... - 184
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 at December 31, 2000, 1,000,000
issued and outstanding at December 31, 1999, liquidation
amount $10,000,000....................................................... 1 1
50,000 designated as 1999 Series A 8% Convertible; 25,000 and 50,000
issued and outstanding, respectively, liquidation amount $25,000,000 and
$50,000,000, respectively................................................ - -
Common Stock - $.002 par value; 100,000,000 shares authorized,
30,705,398 and 21,738,320 shares issued, respectively................ 61 43
Additional paid-in capital................................................. 148,580 121,845
Accumulated other comprehensive loss....................................... (466) (1,713)
Accumulated deficit........................................................ (50,152) (62,560)
Receivable from stockholder................................................ (442) (795)
Unearned common stock in ESOP, at cost (680,282 and 537,515 shares,
respectively)............................................................ (2,780) (1,638)
----------------------------------------------------
94,802 55,183
Treasury stock, at cost (455,063 and 1,512,719 shares of
common stock, respectively).............................................. (1,386) (3,631)
----------------------------------------------------
Total Stockholders' Equity................................................. 93,416 51,552
----------------------------------------------------
Total Liabilities and Stockholders' Equity................................. $ 315,612 $ 304,022
====================================================
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Operations and Comprehensive Income
(in thousands of dollars, except for per share amounts)
For the Years Ended
December 31,
----------------------------------------------------------------------
2000 1999 1998
----------------------------------------------------------------------
Operating Revenues:
Oil and gas sales.......................................... $ 106,052 $ 60,673 $ 43,565
Gas gathering, marketing and processing.................... 20,010 8,185 6,954
Oil field services......................................... 1,448 768 881
----------------------------------------------------------------------
Total Operating Revenues............................. 127,510 69,626 51,400
----------------------------------------------------------------------
Operating Costs and Expenses:
Oil and gas production lifting costs....................... 16,401 15,431 14,265
Production taxes and other costs........................... 12,558 8,144 6,417
Gas gathering, marketing and processing.................... 15,685 5,870 5,750
Oil field services......................................... 903 350 467
Depreciation, depletion and amortization................... 25,556 22,072 21,757
Provision for non-cash impairment of oil and gas reserves.. - - 42,745
(Gains) losses on sale of assets........................... (28) (272) 52
General and administrative................................. 6,106 2,919 2,961
----------------------------------------------------------------------
Total Operating Costs and Expenses................... 77,181 54,514 94,414
----------------------------------------------------------------------
Operating Profit (Loss)....................................... 50,329 15,112 (43,014)
Equity in earnings (loss) of affiliate..................... 1,307 (103) (116)
Other income............................................... 477 354 624
Interest expense........................................... (22,298) (22,103) (18,207)
----------------------------------------------------------------------
Income (loss) before income tax and minority interest......... 29,815 (6,740) (60,713)
Provision for income tax (expense) benefit
Current................................................. (234) - -
Deferred................................................ (7,321) - 13,670
----------------------------------------------------------------------
Total provision for income (tax) benefit............. (7,555) - 13,670
----------------------------------------------------------------------
Income (loss) before minority interest........................ 22,260 (6,740) (47,043)
Minority interest in subsidiary loss....................... - (86) (37)
----------------------------------------------------------------------
Net Income (Loss)............................................. 22,260 (6,826) (47,080)
Dividends Applicable to Preferred Stock.................... (9,708) (4,509) (875)
----------------------------------------------------------------------
Income (Loss) Applicable to Common Shares..................... $ 12,552 $ (11,335) $ (47,955)
======================================================================
Net Income (Loss)............................................. $ 22,260 $ (6,826) $ (47,080)
Other Comprehensive Income (Loss), net of tax
Unrealized Gain (Loss) on Investments...................... 1,247 (405) (1,308)
----------------------------------------------------------------------
Comprehensive Income (Loss)................................... $ 23,507 $ (7,231) $ (48,388)
======================================================================
Income (Loss) per Common Share - Basic........................ $ 0.60 $ (0.57) $ (2.27)
======================================================================
Income (Loss) per Common Share - Diluted...................... $ 0.51 $ (0.57) $ (2.27)
======================================================================
Common Shares Used in Per Share Calculation
Basic ..................................................... 20,856,854 19,743,738 21,151,442
======================================================================
Diluted ................................................... 32,834,270 19,743,738 21,151,442
======================================================================
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity
For the Periods Ended December 31, 2000, 1999 and 1998
(dollars in thousands)
Preferred Stock Common Stock Treasury Stock
Shares Amount Shares Amount Shares Amount
----------------------------------------------------------------------
Balance at December 31, 1997 .................. 1,080,000 $ 1 21,738,320 $ 43 (538,633) $ (1)
Common Stock contributed to 401(k) plan ..... 12,813 -
Exercise of employees' common stock options . 96,913 -
Purchase of treasury stock .................. (625,600) (1,908)
Dividends declared on preferred stock .......
Net loss.....................................
Unrealized loss on investment ...............
Loan to stockholder..........................
Unearned shares in ESOP......................
----------------------------------------------------------------------
Balance at December 31, 1998................... 1,080,000 $ 1 21,738,320 $ 43 (1,054,507) $ (1,909)
----------------------------------------------------------------------
Issuance of 1999 Series A 8% Convertible
stock, net of offering costs .............. 50,000 -
Fees paid on issuance of warrants............
Common Stock contributed to 401(k) plan ..... 41,115 -
Exercise of employees' common stock options . 102,145 -
Costs associated with release of shares
from ESOP..................................
Purchase of treasury stock .................. (601,472) (1,722)
Dividends declared on preferred stock .......
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)
Purchase of 1996 Series A convertible
preferred stock by subsidiary..............
Redemption of 1999 Series A 8% convertible
preferred stock...................... (25,000)
Purchase of treasury stock................... (129,032) (500)
Exercise of employees' common stock options.. 528,942 1 127,450 77
Exercise of warrants, net of expenses........ 8,438,136 17 702,272 1,588
Issuance of common stock for property........ 356,966 1,080
Costs associated with release of shares
from ESOP..................................
Deferred tax benefit on exercise of employee
stock options........................
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)
======================================================================
Additional Accumulated Other Receivable Unearned Shares in
Paid-In Comprehensive Accumulated from ESOP
Capital Income (Loss) Deficit Stockholder Shares Amount
-------------------------------------------------------------------------------------
Balance at December 31, 1997 .................. $ 80,763 $ - $ (8,654) $ - - $ -
Common Stock contributed to 401(k) plan ..... 66
Exercise of employees' common stock options . 78
Purchase of treasury stock ..................
Dividends declared on preferred stock ....... (875)
Net loss..................................... (47,080)
Unrealized loss on investment ............... (1,308)
Loan to stockholder.......................... (672)
Unearned shares in ESOP...................... (250,423) (756)
-------------------------------------------------------------------------------------
Balance at December 31, 1998................... $ 80,032 $ (1,308) $ (55,734) $ (672) (250,423) $ (756)
-------------------------------------------------------------------------------------
Issuance of 1999 Series A 8% Convertible
stock, net of offering costs .............. 46,260
Fees paid on issuance of warrants............ (133)
Common Stock contributed to 401(k) plan ..... 123
Exercise of employees' common stock options . 74
Costs associated with release of
shares from ESOP........................... (2)
Purchase of treasury stock ..................
Dividends declared on preferred stock ....... (4,509)
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................... $ 121,845 $ (1,713) $ (62,560) $ (795) (537,515) $(1,638)
Purchase of 1996 Series A convertible
preferred stock by subsidiary.............. (10,035)
Redemption of 1999 Series A 8% convertible
preferred stock...................... (25,000)
Purchase of treasury stock...................
Exercise of employees' common stock options.. 2,335
Exercise of warrants, net of expenses........ 55,952
Issuance of common stock for property........ 2,401
Costs associated with release of
shares from ESOP........................... 672
Deferred tax benefit on exercise of employee
stock options........................ 410
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................... $ 148,580 $ (466) $ (50,152) $ (442) (680,282) $(2,780)
=====================================================================================
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,
-------------------------------------------------
2000 1999 1998
-------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net income (loss)............................................................... $ 22,260 $ (6,826) $ (47,080)
Adjustments to reconcile net income (loss) to cash
provided by operating activities
Depreciation, depletion and amortization.................................. 25,556 22,072 21,757
Impairment of oil and gas properties ..................................... - - 42,745
Amortization of financing fees............................................ 1,318 2,091 793
Increase in allowance for doubtful accounts............................... 464 - 591
Deferred income taxes..................................................... 7,321 - (13,670)
Equity in (income) loss of unconsolidated affiliate....................... (1,307) 103 116
Minority interest expense................................................. - 86 37
Cost of shares released from ESOP......................................... 448 151 123
Excess of fair value over cost of shares released from ESOP............... 672 (2) -
(Gain) Loss on sale of assets............................................. (28) (272) 52
Other..................................................................... - - (83)
Changes in certain assets and liabilities
Accounts and notes receivable.................................... (20,378) (4,660) 6,859
Other current assets............................................. (737) 281 (278)
Accounts payable and accrued liabilities......................... 13,827 4,411 1,726
Current income taxes payable..................................... 234 - -
Minority interest liability...................................... (184) - -
-------------------------------------------------
Net Cash Provided By Operating Activities....................................... 49,466 17,435 13,688
-------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets.................................................... 43,770 1,499 359
Additions to property and equipment............................................. (60,830) (59,968) (70,187)
Increase in deposits and other assets........................................... - - (3,878)
Loan made for promissory note receivable........................................ (1,370) - (332)
Payments received on promissory note receivable ................................ 1,012 - 28
Investment in unconsolidated affiliate.......................................... (2,590) - -
-------------------------------------------------
Net Cash Used In Investing Activities........................................... (20,008) (58,469) (74,010)
-------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of long-term debt and production payment............. 101,056 106,800 80,000
Fees paid related to financing activities....................................... (534) (1,603) -
Payments of principal on long-term debt and production payment.................. (144,824) (103,186) (10,633)
Payment of short-term notes payable ............................................ - (2,000) (2,699)
Loan repaid by (made to) stockholder............................................ 353 (123) (480)
Loan to ESOP.................................................................... (1,590) (759) (879)
Payment of fees on issuance of warrants and preferred stock..................... - (133) -
Proceeds from issuance of common and preferred stock, net of offering costs..... 59,970 46,334 78
Purchase of 1996 Series A preferred stock by subsidiary......................... (10,035) - -
Redemption of 1999 Series A preferred stock..................................... (25,000) - -
Purchase of treasury stock ..................................................... (500) (1,722) (1,908)
Decrease (increase) in restricted cash for payment of notes payable ............ 325 (1,686) (459)
Dividends paid.................................................................. (10,235) (4,176) (875)
-------------------------------------------------
Net Cash (Used In) Provided By Financing Activities............................. (31,014) 37,746 62,145
-------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS............................... (1,556) (3,288) 1,823
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR..................................... 1,565 4,853 3,030
-------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR........................................... $ 9 $ 1,565 $ 4,853
=================================================
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, SPL Gas Marketing, Inc. The Company
consolidates on a pro rata basis its approximately 41% 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). Except for Bluebird, there
is no restriction on the ability of consolidated or unconsolidated subsidiaries
to transfer funds to the Company in the form of cash dividends, loans, or
advances.
Bluebird was formed in December 1998, for the purpose of acquiring certain
assets of Spirit 76 (see "Acquisitions"). 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
Restricted cash is the cash balance of Bluebird. Cash funds of Bluebird are
not permitted to be commingled with funds of Magnum Hunter or its other
subsidiaries or affiliates. Such funds cannot be dividended or loaned to Magnum
Hunter or its other subsidiaries or affiliates but must be used to satisfy the
cash requirements of Bluebird, including payment of Bluebird's outstanding
borrowings.
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.
At December 31, 2000 and 1999, the Company's available-for-sale securities
were classified as non-current assets and included in deposits and other assets.
At December 31, 2000, 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.
At December 31, 1999, the securities had a cost basis of $2,762,000, gross
unrealized losses reported in accumulated other comprehensive income of
$2,514,000 ($1,713,000 net of income tax benefit) and had a fair market value of
$248,000.
During 2000, the Company acquired a minority ownership interest in a
privately held company that provides remote data collection and web-based
monitoring services for 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.
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, 2000, 1999 and 1998, respectively. The balance of
capitalized costs included in oil and gas properties for the years ended
December 31, 2000 and 1999 were $2,679,000 and $2,079,000, 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, 2000 and the year in which they were incurred
follows:
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, 1998, the Company wrote down the
costs of its oil and gas properties by $42,745,000, pursuant to the ceiling
limitation, using certain improvements in pricing experienced after year- end.
The effect of this write-down was a non-cash charge to earnings of $42,745,000
and an increase in accumulated depreciation, depletion, amortization and
impairment for the same amount. Without the benefit of improvements in pricing
after December 31, 1998, the Company would have incurred an impairment of
$81,154,000. The Company experienced no impairment in 1999 or 2000.
All costs relating to production activities are charged to expense as
incurred.
Amortization expense per thousand cubic feet equivalent was $0.89, $0.79
and $1.00 for the years ended December 31, 2000, 1999 and 1998, respectively.
Derivative Instruments
The Company's product price and interest hedging activities are described
in Note 13 to the consolidated financial statements. The Company enters into
swaps, futures, options and other derivative contracts to hedge the impact of
market fluctuations in gas and oil prices on anticipated future oil and gas
production. The Company is exposed to price risk related to its future oil and
gas production and enters into these instruments to manage this exposure. The
Company hedges only those anticipated future transactions for which the
significant characteristics and expected terms are identified and are probable
of occurring. The Company defers the impact of changes in the market value of
the contracts that serve as hedges until the related transaction is completed.
Any derivative instruments that do not meet this criteria are marked-to-market.
The Company does not hold or issue derivative instruments for trading purposes.
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.
F-8
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 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 Standard
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), is 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.
All derivatives within the Company have been identified pursuant to SFAS
No. 133 requirements, and the Company has designated, documented, and assessed
hedging relationships. The Company was obligated to four crude oil derivatives,
one natural gas derivative, and one interest rate derivative on January 1, 2001.
The Company has determined that the interest rate derivative will not qualify
for treatment as a fair value hedge as defined in the Statement. As a result,
the derivative asset or liability related to the interest rate derivative must
be recorded at fair value on the Company's balance sheet with an offset to
income. The crude oil and natural gas derivatives qualify as cash-flow hedges,
which require the Company to record the derivative assets or liabilities at
their fair value on its balance sheet with an offset in other comprehensive
income. Future hedge ineffectiveness on the cash-flow hedges will be recorded in
earnings.
Adoption of this accounting standard as of January 1, 2001 resulted in the
recognition of $179,000 of derivative assets and $2.8 million of derivative
liabilities with a cumulative effect increase to income of $111 thousand after
tax and with a cumulative effect decrease to other comprehensive income of $1.8
million after-tax for the transition adjustment as of January 1, 2001.
F-9
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Income or Loss Per Common Share
Basic net income or loss per common share is computed by dividing the net
income or loss attributable to common stockholders by the weighted average
number of shares of common stock outstanding during the period. Diluted net
income or loss per common share is calculated in the same manner, but also
considers the impact to net income and common shares for the potential dilution
from stock options, stock warrants and any other outstanding convertible
securities.
The following table reconciles the numerators and denominators used in the
computations of both basic and diluted EPS as required by SFAS No. 128,
"Earnings per Share":
For the Year Ended For the Year Ended For the Year Ended
December 31, 2000 December 31, 1999 December 31, 1998
-----------------------------------------------------------------------------------------------------
Per Per Per
Income Shares Share Loss Shares Share Loss Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------------------------------------------------------------------------------------------------
Net Income (Loss).............. $22,260,000 $ (6,826,000) $(47,080,000)
Less: Preferred Stock
dividendse.......... (9,708,000) (4,509,000) (875,000)
----------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available to
common stockholders....... 12,552,000 20,856,854 $0.60 (11,335,000) 19,743,738 $(0.57) (47,955,000) 21,151,442 $(2.27)
Effect of dilutive securities
Warrants.................... - 571,623 - - - -
Options..................... - 1,247,063 - - - -
Convertible preferred stock. 4,312,000 10,158,730 - - - -
Diluted EPS
Income (Loss) available to
common stockholders and -----------------------------------------------------------------------------------------------------
assumed conversions...... $16,864,000 32,834,270 $0.51 $(11,335,000) 19,743,738 $(0.57) $(47,955,000) 21,151,442 $(2.27)
=====================================================================================================
The warrants, options, and convertible preferred stock were not included in
the computation of diluted earnings per share in 1999 and 1998 since the Company
incurred a net loss for the year and any effect would be anti-dilutive. At
December 31, 2000, 73,126 shares of stock under warrants and 3,455,337 shares of
stock under options were excluded from the diluted net income per share
computation as the exercise price exceeded the average market price of the
Company's common stock. At December 31, 1998, the Company had outstanding
141,000 warrants at a weighted average exercise price of $4.75 per share,
2,661,587 options at a weighted average exercise price of $3.90 per share, and
1,000,000 shares of preferred stock convertible to common stock at $5.25 per
share. At December 31, 1999, the Company had outstanding 10,583,149 warrants at
a weighted average exercise 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. At December 31, 2000, the Company had outstanding
644,749 warrants at a weighted average exercise 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.
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.
F-10
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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
On January 28, 1998, the Company commenced a cash purchase offer for Units
of TEL Offshore Trust. Previous to the offer, the Company owned 161,500 Units
representing 3.4% of the Units outstanding. As amended, the offer was to
purchase between forty percent (40%) and sixty percent (60%) of the Trust's
outstanding Units at $5.50 per Unit. On March 27, 1998, the Company purchased
1,745,353 Units pursuant to the tender offer and, together with the Units it
previously owned, was the owner of approximately 40% of the total number of
Units outstanding for an aggregate of $10.4 million. After purchasing additional
units in 1999 and 2000, the Company owned 1,948,571 units, or approximately 41%
of the units outstanding.
On December 31, 1998, the Company (through its wholly-owned subsidiary,
Bluebird) acquired from Spirit 76 natural gas reserves and associated assets in
producing fields located in Oklahoma and Texas. The net purchase price was
approximately $25 million after certain purchase price adjustments including
preferential rights exercised by third parties and other customary adjustments.
On June 10, 1999, the Company and Bluebird acquired from Vastar Resources,
Inc. oil and gas reserve interests in 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 years ended December 31, 1999 and 1998 as if the
acquisitions occurred as of the beginning of the respective years. The pro forma
information includes the effects of adjustments for increased general and
administrative expense, interest expense, depreciation, depletion and income
taxes:
(Unaudited)
---------------------------------
1999 1998
---- ----
(in thousands, except for per share amounts)
--------------------------------------------
Revenue............................ $ 73,104 $ 77,181
Net Income (Loss) Applicable
to Common Stock.................. (12,022) (44,911)
Net Income (Loss) Per Common Share
Basic........................... $ (0.61) $ (2.12)
Diluted.......................... $ (0.61) $ (2.12)
NOTE 3 -- NOTES RECEIVABLE
On September 30, 1997, the Company sold its investment in securities
available-for-sale to an unrelated entity for $483,500. Prior to the sale, this
entity owed the Company $92,610. The total amount owed was secured by a note
payable to the Company with interest at 10% per annum and principal installments
of $50,000 per month commencing November 5, 1997, with final payment due
November 5, 1998. The note is collateralized by shares of an American Stock
Exchange listed company and by shares of the Company held by the entity. After
making the payment due November 5, 1997, the entity was unable to continue
making further payments. The net carrying value of the note, at December 31,
1997 was $350,016. During 1998, the Company made further advances of $290,525 to
this entity, and at December 31, 1998 an additional allowance provision of
$590,525 was made. The carrying value of the note, net of allowance, at December
31, 2000 and 1999 was $50,016. Subsequent to December 31, 2000, the Company
received a payment of $50,000 to apply against this note.
F-11
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 4 -- RELATED PARTY TRANSACTIONS
In conjunction with the acquisition of Hunter, the Company assumed a note
receivable with a balance of $379,321 at December 31, 1999 and 1998, from an
owner in an affiliated limited liability company. The note provides for interest
at 10 percent and has 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, 2000 and 1999, the Company's note receivable from the
Magnum Hunter Employee Stock Ownership Plan (ESOP) was $2,780,000 and
$1,638,000, 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, 2000 and 1999, the number of unearned shares in the ESOP were 680,282 and
537,515, 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, 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 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.
F-12
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 5 -- DEBT
Notes payable and long-term debt at December 31, 2000 and 1999 consisted of
the following:
2000 1999
(in thousands)
-----------------------------------
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 8.52% at
December 31, 2000) (a)................................................... $ 30,500 $ 53,000
Note payable to bank collateralized by vehicle, payable in monthly
installments of $1,753 including interest at 7.9% through
January 2003............................................................. 39 -
Other
Senior notes, unsecured, due June 1, 2007, interest at 10% payable
semi-annually on June 1 and December 1................................... 140,000 140,000
Notes payable, non-interest bearing and uncollateralized, payable in
monthly installments of $1,000 through July 1, 2000...................... - 6
------------------------------------
Total Long-Term Debt, with recourse............................... $ 170,539 $ 193,006
Less Current Portion...................................... 19 6
Long-Term Debt, with recourse..................................... $ 170,520 $ 193,000
====================================
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) (b)....................... $ 20,600 $ 41,800
------------------------------------
Total Long-Term Debt, non recourse................................ $ 20,600 $ 41,800
====================================
F-13
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)
2001................................................................. $ 19
2002................................................................. 20,619
2003................................................................. 30,501
2004 to 2006......................................................... -
2007................................................................. 140,000
-----------
Total....................................................... $ 191,139
===========
(a) The revolving promissory note to the banks is a borrowing under a
$125,000,000 line of credit on which there existed a borrowing base of
$53,000,000 at December 31, 2000. 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, 2000, the amounts borrowed
at these rates were:
(in thousands)
LIBOR + 1.75% (total of 8.39%).................................... $ 28,000
Base Rate (Prime) + .50% (total of 10.00%)........................ 2,500
--------------
Total...................................................... $ 30,500
==============
(b) The revolving promissory note to the banks is a 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 is dependent
on the valuation of the assets pledged, primarily oil and gas reserves, natural
gas processing plants, and units of Tel Offshore Trust. On December 1, 2000, the
line of credit was amended to automatically increase from $38,500,000 to
$42,000,000 until February 28, 2001, at which time it reduced to $37,000,000.
The line of credit includes covenants, the most restrictive of which requires
maintenance of a current ratio and an interest coverage ratio, and restrictions
on upstream loans, dividends and commingling of funds. The credit agreement
provides for both "LIBOR" and "Base Rate" (Prime) interest rate options. At
December 31, 2000 the amounts borrowed at these rates were:
(in thousands)
LIBOR + 2.75% (total of 9.44%)....................................$ 20,000
Base Rate (Prime) + 1.25% (total of 10.75%)....................... 600
--------------
Total......................................................$ 20,600
==============
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 $359,000 and $460,000 at December 31, 2000 and 1999,
respectively. The production payment bears interest at the rate of 13.5% per
annum and is non-recourse to the Company.
F-14
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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:
2000 1999 1998
(in thousands)
--------------------------------------------------------
Income tax expense (benefit) at statutory rates......... $ 10,191 $ (2,352) $ (21,263)
State tax expense (benefit)............................. 829 (193) (1,747)
Change in valuation allowance........................... (3,875) 2,315 8,370
Other................................................... 410 230 -
--------------------------------------------------------
Tax expense (benefit)............................ $ 7,555 $ - $ (14,640)
========================================================
The tax effects of significant temporary differences and carryforwards are
as follows:
December 31,
--------------------------------------
2000 1999
(in thousands)
--------------------------------------
Property and equipment, including intangible drilling costs........... $ (18,855) $ (12,325)
--------------------------------------
Total deferred tax liability................................. $ (18,855) $ (12,325)
--------------------------------------
Allowance for doubtful accounts....................................... 577 425
Reserves.............................................................. 33 33
Property and equipment, including intangible drilling costs........... - 1,984
Depletion carryforwards............................................... 510 196
Alternative minimum tax credit........................................ 234 -
Operating loss and other carryforwards................................ 30,219 33,951
--------------------------------------
Total deferred tax assets.................................... 31,573 36,589
--------------------------------------
Valuation allowance................................................... (7,100) (10,975)
--------------------------------------
Net Deferred Tax Asset (Liability)........................... $ 5,618 $ 13,289
======================================
The following deferred tax benefits were excluded from the benefit for
deferred income tax in the Consolidated Statement of Operations and
Comprehensive Income at December 31, 1998: Equity in Earnings of Affiliate,
$71,000; Minority Interest in Subsidiary Earnings, $23,000; and Unrealized Loss
on Investments, $801,000.
The Company and its subsidiaries have net operating loss carryforwards of
approximately $79,504,000 that expire, if unused, in years 2001 through 2019.
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. Approximately $1,274,000
of the net operating losses are subject to a limitation of $718,000 per year and
$50,139,000 are subject to a limitation of $7,850,000 per year. In addition, the
Company has depletion carryforwards of $2,056,000 with no expiration period. A
valuation allowance reduces deferred taxes based on the criteria set forth in
SFAS 109.
F-15
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 925,000 shares have
been designated as Series B Preferred Stock, 625,000 shares have been designated
as Series C 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, 7,184,000 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.
Holders of the Series A Preferred Stock are entitled to receive dividends
only to the extent that funds are available from the West Dilley Prospect. Such
dividends are limited to $7.50 per share, in the aggregate. Dividend payments to
Series A preferred shareholders are based on fifty percent (50%) of the net
operating revenue received by the working interest owners of the West Dilley
Prospect. Due to no production from the well located on this prospect, the
Company shut this well in and therefore is no longer producing the property. The
Series A dividends are not cumulative except for unpaid amounts due from this
calculation. No dividends have been paid on the Series A preferred stock and
there is no aggregate annual dividend requirement for the Series A preferred
stock.
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. The shares have a stated and liquidation value of $10 per share
and pay a fixed annual cumulative dividend of eight and three quarters percent
(8.75%) payable quarterly in arrears beginning December 31, 1996. The shares are
convertible into shares of common stock at a conversion price of $5.25 per
share. Dividends of $438,000, $875,000 and $875,000 and were declared in 2000,
1999 and 1998, 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 stock was
transferred to a wholly-owned subsidiary of the Company with the intent of
possibly re-marketing the preferred stock to a third party in the future if
deemed necessary. As a result of the exchange, the Company reduced its dividends
to preferred stockholders by $144,000 in 2000.
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 has a liquidation value of $50 million and is convertible into
the Company's Common Stock at $5.25 per share. Dividends on the Preferred Stock
are payable in cash at the rate of 8% per annum and are 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. 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.
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. The Series A preferred
shareholders would receive an amount equal to the lesser of the proceeds from
the liquidation of the West Dilley Prospect or the remaining unpaid dividend.
The 1996 Series A Convertible Preferred Stock would receive an amount of $10 per
share. 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.
F-16
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Warrants
In January 1996, 60,000 warrants were issued at an exercise price of $3.375
per share with an expiration date of January 1999. None of these warrants were
exercised in 1999 and they expired unexercised. In connection with the receipt
of a production payment, in October 1996 the Company issued 25,000 warrants with
an exercise price of $5.18, 25,000 warrants with an exercise price of $5.65 and
25,000 warrants with an exercise price of $6.13, all expiring October 2001. All
of these warrants were exercised on October 17, 2000, resulting in net proceeds
to the Company of $424,000.
In January 1997, 21,000 warrants were issued at a exercise price of $4.50
per share, expiring January 1, 2000, in connection with services rendered by a
non-employee. The warrants were not exercised in 1999 and expired unexercised in
January 2000.
In July 1999, the Company issued a total of 10,512,150 warrants on the
basis of one warrant for every three common shares owned, .63492 warrants for
every share of 1996 Series A Convertible Preferred Stock owned and 63.492
warrants for every s hare of 1999 Series A 8% Convertible Stock owned. The
warrants had an exercise price of $6.50 per share, an expiration date of June
30, 2002 and were redeemable by the Company at any time prior to expiration at
$0.01 per share. The warrants were publicly traded on the American Stock
Exchange. On October 17, 2000, 3,174,600 of the warrants were exercised,
resulting in net proceeds to the Company of $20,634,900. On October 26, 2000,
the Company announced that it would redeem the remaining 7,337,550 warrants if
they were not exercised by December 5, 2000. As a result of the redemption
notice, 5,263,536 warrants were exercised, including 164,946 by the Company's
ESOP, and a total of 1,429,264 warrants were redeemed by the Company for $0.01
per share, resulting in net proceeds of $33,206,707 after redemptions. 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 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 June 30, 2000, the holders of the Company's 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 30, 2003
and payment of $10,000,000. A provision of the exchange agreement allowed the
Company to require the exercise of the warrants if the closing price of the
Company's common stock was above $7.50 per share for fifteen consecutive days
subsequent to June 30, 2000. On October 5, 2000 a total of 450,000 warrants were
exercised for cash, resulting in net proceeds to the Company of $2,362,500. On
the same date, the remaining 450,000 warrants were exercised using a cashless
exercise feature, resulting in the issuance of 177,272 shares of common stock.
At December 31, 2000 the Company had a total of 644,749 warrants issued and
outstanding.
Warrants issued to non-employees are valued based on the fair market value
of the equity instrument issued determined by using the Black-Scholes pricing
model, if a quoted market price is not available. The measurement date for
warrants issued in exchange for goods and services is established as the earlier
of the date at which a performance commitment is reached or the date at which
the counterparty's performance is complete.
F-17
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Common Stock
On January 9, 1998, the Company adopted a Shareholder Rights Plan. Under
the 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 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 September 8, 1998, the Company announced a stock repurchase program for
up to one million shares of the Company's common stock in the open market or
privately negotiated transactions, to be completed before April 30, 1999 at a
value not to exceed $4 million in the aggregate. Through December 31, 1998, the
Company had repurchased 625,600 shares for $1.9 million under this program.
Additionally in 1998, 12,813 shares of the Company's common stock were
contributed to the 401(k) plan, 96,913 shares were issued upon exercise of
employee stock options, 291,300 shares were purchased by the ESOP and 40,877
shares were released by the ESOP to participants.
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 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 $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 shares of
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.
NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION
During 2000, the Company purchased oil and gas properties by issuing
356,966 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 in 2000 was $21,661,000.
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 in
1999 was $19,773,000.
During 1998, the Company contributed 12,813 shares valued at $66,000 to the
Company's 401(k) plan. The Company acquired certain oil and gas properties in
exchange for notes and accounts receivable totaling $1,903,000. In accordance
with SFAS 115, the Company wrote- down the carrying costs of its marketable
investments by $2,304,000 ($1,429,000 after income tax benefit). Interest paid
in 1998 was $17,089,187.
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
F-18
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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.
NOTE 11 -- COMMITMENTS AND CONTINGENCIES
The Company has certain lease agreements for the use of office space and
office equipment. 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 2003. 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:
2001........................................................... $ 719,822
2002........................................................... 718,346
2003........................................................... 638,884
2004........................................................... 630,716
2005........................................................... 557,366
Thereafter..................................................... -
----------------
Total Minimum Payments Required............................... $3,265,134
Rental expense was $717,636, $367,000 and $327,934, for 2000, 1999, and
1998, respectively.
In December, 1997, the Company amended its Revolving Loan Agreement with
certain banks to permit guarantees of NGTS, LLC's debt, 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, 2000 and 1999, 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. 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, 2000 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, 2000 and 1999, 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, 2000 and 1999.
The market values of equity investments are based upon quoted prices (see Note
1). At December 31, 2000, 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 $138,600,000.
F-19
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 2000, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
--------------- --------------------- --------------------- ---------------------
Oil
- ------
Collar......... 30,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $33.50
Collar......... 15,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $34.35
Collar......... 15,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $35.50
Collar......... 15,000 Bbl Jan 01 - Jun 01 Floor - $25.00
Cap - $36.80
Gas
- ------
Collar......... 300,000 MMBtu Jan 01 - Dec 01 Floor - $ 4.50
Cap - $ 6.15
Based on future market prices at December 31, 2000, the fair value of open
contracts to the Company was a liability of $2.8 million.
Net gains (losses) related to crude oil and natural gas derivative
transactions for the years ended December 31, 2000, 1999 and 1998 were
$(11,179,000), $(3,232,000) and $2,739,000, respectively.
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 next twelve months. On June 1, 2000, one of the interest rate
swaps terminated. The following table reflects the terms of the remaining swap.
Type Notional Amount Termination Date Pay Rate Receive Rate
- ----------------------------- ------------------- ------------------ ------------------ --------------------
Pay Variable/Receive Fixed $50,000,000 06/01/02 LIBOR + 3.34% 10% fixed
through 05/31/00
LIBOR + 3.69%
from 06/01/00 to
06/01/02
The Company's total fixed rate debt at December 31, 2002 was approximately
$140 million.
Based on future market rates at December 31, 2000, the fair value of open
contracts to the Company was an asset of $179,000.
Net gains (losses) related to interest rate derivative transactions for the
years ended December 31, 2000, 1999 and 1998 were $(13,000), $209,000 and none,
respectively.
F-20
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 14 -- STOCK COMPENSATION PLANS
The Company adopted in 1996 two stock compensation plans for its employees
and directors, (i) the Magnum Hunter Resources Employee Stock Ownership Plan,
(the "ESOP"), and (ii) the Magnum Hunter Resources, Inc. 1996 Incentive Stock
Option Plan (the "Option Plan"). In addition, the Company has made non-incentive
stock option grants in 2000, 1999 and 1998.
ESOP
The Company established an ESOP and a related trust in 1996 as a long-term
benefit for its employees. Under terms of the ESOP, eligible participants may
elect 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 ESOP 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 ESOP with loans
from the Company are released to participants as Company contributions are made
and the related loans are repaid. The Company has no repurchase obligations with
respect to released shares.
During 1998, the Company loaned the ESOP $878,997 to purchase 291,300
shares of the Company's Common Stock on the open market at an average price of
$3.02 per share. At December 31, 1998, the Company contributed $123,345 to the
ESOP as a discretionary contribution under the plan. The ESOP then repaid that
portion of its outstanding loan from the Company and 40,877 shares were
allocated among the plan participants.
During 1999, the Company loaned the ESOP $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
ESOP as a discretionary contribution under the plan. The ESOP 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 ESOP $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 ESOP as a
discretionary contribution under the plan. The ESOP then repaid that portion of
its outstanding loan from the Company and 141,095 shares were allocated among
the plan participants. The loan is interest free and is due December 31, 2004.
The loan was secured by 680,282 shares and 537,515 shares of the Company's
common stock at December 31, 2000 and 1999, 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 ESOP are excluded
from the calculation of earnings per share.
The ESOP shares are summarized as follows:
December 31,
2000 1999
-------------------------- -----------------------
Allocated shares 256,336 115,241
Unreleased shares 680,282 537,515
------- -------
Total ESOP shares 936,618 652,756
======= =======
Fair value of unreleased shares $ 8,163,384 $ 1,545,356
The ESOP expense for the years ending December 31, 2000, 1999 and 1998 was
$1,119,942, $148,948 and $122,631, respectively.
F-21
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 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 5 years. All options granted in
1996 were fully vested and exercisable when granted. The exercise price was fair
market value at the date of grant.
Non-Incentive Stock Option Grants
During 1997, the Board granted 1,440,000 options to employees and
directors, 1,240,000 of which were fully vested and 200,000 of which vest over
five years. The term of the individual option grants were for five years. The
exercise price was fair market value on the date of grant.
During 1998, the Board granted 220,000 new options to employees at an
average price of $5.89. All options were fully vested on the date of grant and
were for a term of five years. On December 14, 1998 the Board repriced 1,590,000
options to employees and directors from an average of $5.96 per share to $3.75
per share, the fair market value on that date.
During 1999, the Board granted 1,306,650 new options to employees at an
average price of $2.69, of which 108,000 vested immediately and 1,198,650 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 was modified to
extend the expiration date from January 5, 2000 to January 5, 2002.
During 2000, the Board granted 1,536,000 new options to employees at a
weighted average price of $7.89, 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.
The following is a summary of stock option activity under the Option Plans:
2000 1999 1998
----------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
----------------------------------------------------------------------------------
Outstanding - Beginning of Year.... 3,866,092 $ 3.57 2,661,587 $ 3.90 2,538,500 $ 5.00
Granted............................ 1,536,000 7.89 1,306,650 2.69 220,000 5.89
Exercised.......................... (656,392) 3.67 (102,145) .73 (96,913) .81
Canceled........................... (43,300) 3.32 - - - -
Repriced - previous................ - - - - (1,590,000) 5.96
Repriced - new..................... - - - - 1,590,000 3.75
---------------------------------------------------------------------------------
Outstanding - End of Year.......... 4,702,400 $ 4.97 3,866,092 $ 3.57 2,661,587 $ 3.90
========= ========== ========= ========== ========= ==========
Exercisable - End of Year.......... 2,730,460 $ 4.31 2,787,172 $ 3.94 2,501,587 $ 3.91
========= ========== ========= ========== ========= ==========
F-22
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The following is a summary of stock options outstanding at December 31,
2000:
Weighted
Average
Number of Remaining
Options Contractual Life Number of
Exercise Price Outstanding (Years) Exercisable Options
-----------------------------------------------------------------------
$ 2.50.......................... 1,143,800 4.0 440,660
2.875......................... 3,000 3.0 3,000
3.4375........................ 8,000 4.2 -
3.75.......................... 1,040,600 2.0 1,000,600
4.375......................... 23,000 1.0 23,000
4.50.......................... 843,000 1.0 843,000
5.25.......................... 110,000 3.1 110,000
5.375......................... 5,000 1.3 5,000
6.625......................... 21,000 4.6 4,200
7.9375........................ 1,505,000 9.9 301,000
-----------------------------------------------------------------------
4,702,400 4.9 2,730,460
=======================================================================
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.
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,
2000 1999 1998
---------------------------------------------------------
Net Income (Loss) Applicable to Common Stock:
As reported.............................................. $ 12,552,000 $(11,335,000) $(47,955,000)
Pro Forma................................................ 6,800,000 (13,313,000) (49,160,000)
Basic Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ 0.60 $ (0.57) $ (2.27)
Pro Forma................................................ 0.33 (0.67) (2.32)
Diluted Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ 0.51 $ (0.57) $ (2.27)
Pro Forma................................................ 0.30 (0.67) (2.32)
Weighted average grant date fair value..................... $ 9,259,000 $ 1,978,000 $ 1,205,000
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:
2000 1999 1998
----------------------------------------------------------
Risk-free interest rate......... 5.75% 5.875% 5.5%
Expected life................... 7.4 years 4.4 years 4.1 years
Expected volatility............. 56.0% 53.0% 57.0%
Dividend yield.................. - - -
F-23
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 15 -- EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND
CHANGE-IN-CONTROL ARRANGEMENTS
Mr. Gary C. Evans, Mr. Matthew C. Lutz, 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, 2005 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
2001 is $350,000. Mr. Lutz's agreement terminates January 1, 2005 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. Lutz's salary for the year 2001 is
$245,000. Mr. Frazier's agreement terminates January 1, 2005 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 2001 is
$190,000. Mr. Tong's agreement terminates January 1, 2003 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 2001 is
$165,000. Mr. Cronk's agreement terminates January 1, 2003 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 2001 is
$138,000. Mr. Erwin's agreement terminates January 1, 2003 and continues
thereafter on a year to year basis and provides for a salary of $125,000 per
annum unless increased by the Board. Mr. Erwin's salary for the year 2001 is
$145,000. 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, Mr.
Lutz 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 and Mr. Cronk, 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.
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.
F-24
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Segment data for the three years ended December 31, 2000, 1999 and 1998 are
as follows (in thousands):
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)
477
Other income............................. 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
F-25
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Gas Gathering,
Exploration & Marketing & Oil Field
1998: Production Processing Services All Other Elimination Consolidated
----- ----------------------------------------------------------------------------------
Revenue from external customers......... $ 43,565 $ 6,954 $ 881 $ - $ - $ 51,400
Intersegment revenues.................... - 12,569 4,561 - (17,130) -
Depreciation, depletion, amortization and
impairment............................... 63,681 652 148 21 64,502
Segment profit (loss).................. (42,953) 521 1,465 (2,047) (43,014)
Equity earnings (losses) of affiliates... (116) (116)
Interest expense......................... (18,207) (18,207)
Other income............................. 624 624
-------------
Loss before income taxes................. $ (60,713)
Deferred income tax benefit.............. 13,670 13,670
Minority interest........................ (37) (37)
-------------
Net loss................................. $ (47,080)
=============
Capital expenditures (net of asset sales) $ 70,294 $ (35) $ 740 $ 38 $ 71,037
Gas Gathering,
Exploration & Marketing & Oil Field
Production Processing Services All Other Elimination Consolidated
---------------------------------------------------------------------------------
As of December 31, 2000
Segment assets............................ $ 270,195 $ 20,561 $ 16,154 $ 8,702 $ 315,612
Equity subsidiary investments............. 8,054
As of December 31, 1999
Segment assets............................ $ 278,652 $ 12,416 $ 4,252 $ 8,702 $ 304,022
Equity subsidiary investments............. 4,163 4,163
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 financial information for Magnum Hunter Resources, Inc. and
subsidiaries as of December 31, 2000 and 1999 and for the years ended December
31, 2000 and 1999 is as follows:
F-26
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Magnum Hunter Resources, Inc. and Subsidiaries
Condensed Consolidating Balance Sheets
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
==========================================================================
December 31, 1999
- -------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------
ASSETS
Current assets.............................. $ 14,572 $ 3,741 $ (2,601) $ 15,712
Property and equipment
(using full cost accounting).............. 211,159 54,036 - 265,195
Investment in subsidiaries
(equity method)............................ 13,302 - (13,302) -
Other assets................................ 22,605 510 - 23,115
-------------------------------------------------------------------------
Total Assets............................. $ 261,638 $ 58,287 $ (15,903) $ 304,022
=========================================================================
LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities......................... $ 16,442 $ 3,185 $ (2,601) $ 17,026
Long-term liabilities....................... 193,644 41,800 235,444
Shareholders' equity........................ 51,552 13,302 (13,302) 51,552
--------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $ 261,638 $ 58,287 $ (15,903) $ 304,022
==========================================================================
F-27
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, 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-28
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, 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 provided 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 EVENT
Effective January 1, 2001 the holder of the remaining 25,000 shares of the
Company's 1999 Series A 8% Convertible preferred stock converted those shares
into 4,761,904 shares of the Company's common stock.
F-29
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
(Unaudited)
Proved oil and gas reserves consist of those estimated quantities of crude
oil, 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 reserves were primarily due to
changes in commodity prices at December 31, 1998, 1999 and 2000 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, 1998
Proved Reserves.................. 17,349,000 219,060,000
Proved developed reserves........ 9,475,000 174,987,000
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
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, 1998, 1999
and 2000 were as follows:
Gas
Oil (Thousand
(Barrels) Cubic Feet)
---------------------------------
Reserves at December 31, 1997............. 20,946,000 207,776,000
Purchase of minerals-in-place............. 1,363,000 39,535,000
Sale of minerals-in-place................. (4,000) -
Extensions and discoveries................ 279,000 12,091,000
Production................................ (1,141,000) (14,119,000)
Revisions of estimates.................... (4,094,000) (26,223,000)
---------------------------------
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
---------------------------------
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, 2000, 1999 and 1998 were as
follows:
2000 1999 1998
----------------------------------------------------
Unproved oil and gas properties................................ $ 5,534,000 $ 3,567,000 $ 1,655,000
Proved properties.............................................. 367,822,000 349,510,000 296,545,000
----------------------------------------------------
Gross Capitalized Costs........................................ 373,356,000 353,077,000 298,200,000
Accumulated depreciation, depletion, amortization and impairment (124,720,000) (100,370,000) (79,194,000)
----------------------------------------------------
Net Capitalized Costs................................ $ 248,636,000 $ 252,707,000 $ 219,006,000
====================================================
Costs incurred in oil and gas producing activities, both capitalized and
expensed, during the years ended December 31, 2000, 1999 and 1998 were as
follows:
2000 1999 1998
-----------------------------------------------
Property acquisition costs
Proved properties................................................. $ 7,806,000 $ 34,478,000 $ 36,620,000
Unproved properties............................................... 1,080,000 1,912,000 1,138,000
Exploration costs................................................... 32,521,000 6,835,000 4,696,000
Development costs................................................... 22,234,000 12,176,000 27,840,000
-----------------------------------------------
Total Costs Incurred...................................... $ 63,641,000 $ 55,401,000 $ 70,294,000
===============================================
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, 2000, 1999 and 1998 were as follows:
2000 1999 1998
------------------------------------------------
Oil and gas production revenue..................................... $ 106,052,000 $ 60,673,493 $ 43,564,728
Production costs................................................... (28,959,000) (23,575,241) (20,682,187)
Depreciation, depletion, amortization and impairment............... (24,350,000) (21,176,428) (63,102,795)
Income taxes....................................................... (18,460,000) (5,572,638) 14,077,089
------------------------------------------------
Results of Operations for Producing Activities $ 34,283,000 $ 10,349,186 $(26,143,165)
================================================
The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 2000, 1999 and 1998 were
as follows:
2000 1999 1998
-----------------------------------------------------
Future cash inflows............................................. $ 2,685,776,000 $ 1,102,673,000 $ 625,819,000
Future development costs........................................ (84,158,000) (52,600,000) (48,656,000)
Future production costs......................................... (559,596,000) (362,365,000) (229,566,000)
-----------------------------------------------------
Future net cash flows, before income tax........................ 2,042,022,000 687,708,000 347,597,000
Future income taxes............................................. (607,407,000) (131,500,000) (25,671,000)
-----------------------------------------------------
Future Net Cash Flows........................................... 1,434,615,000 556,208,000 321,926,000
10% annual discount............................................. (629,692,000) (240,592,000) (145,778,000)
-----------------------------------------------------
Standardized Measure of Discounted Future Net Cash Flows (a) $ 804,923,000 $ 315,616,000 $ 176,148,000
=====================================================
(a) The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 2000 after giving effect
to all applicable hedging contracts was $794,680,000.
The primary changes in the standardized measure of discounted estimated
future net cash flows for the years ended December 31, 2000, 1999 and 1998 were
as follows:
2000 1999 1998
-------------------------------------------------------
Purchases of minerals-in-place................................. $ 16,040,000 $ 45,321,000 $ 46,389,000
Sales of minerals-in-place..................................... (33,981,000) (168,000) (9,000)
Extensions, discoveries and improved recovery, less related costs 208,966,000 8,398,000 10,837,000
Sales of oil and gas produced, net of production costs......... (77,093,000) (37,098,000) (22,883,000)
Development costs incurred during the period................... 22,231,000 12,176,000 27,840,000
Revision of prior estimates:
Net change in prices and costs............................... 552,634,000 118,271,000 (76,286,000)
Change in quantity estimates................................. 1,524,000 36,937,000 (55,991,000)
Accretion of discount.......................................... 31,562,000 17,615,000 16,977,000
Net change in income taxes..................................... (232,576,000) (61,984,000) 59,502,000
-------------------------------------------------------
Net Change.................................... $ 489,307,000 $ 139,468,000 $ 6,376,000
=======================================================
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
F-32
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
(Unaudited)
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-33
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................... 43 Director, President and Chief Executive Officer
Matthew C. Lutz................. 66 Chairman of the Board and Executive Vice President
Richard R. Frazier.............. 54 President and Chief Operating Officer of Magnum Hunter
Production, Inc. and Gruy
Chris Tong...................... 44 Senior Vice President and Chief Financial Officer
R. Douglas Cronk . . . . . . . . 54 Senior Vice President of Operations of Magnum Hunter Production, Inc.
and Gruy
Morgan F. Johnston.............. 40 Vice President, General Counsel and Secretary
David S. Krueger................ 51 Vice President and Chief Accounting Officer
Michael McInerney . . . . . . . 59 Vice President, Corporate Development & Investor Relations
Charles R. Erwin................ 53 Senior Vice President of Exploration of Magnum Hunter Production, Inc.
and Gruy
Gregory L. Jessup............... 47 Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits.............. 49 Vice President and Controller
Craig Knight.................... 44 Vice President of Operations of Hunter Gas Gathering, Inc.
Earl Krieg, Jr. ................ 47 Vice President of Engineering of Magnum Hunter Production, Inc. and
Gruy
Gerald W. Bolfing............... 72 Director
Jerry Box....................... 62 Director
Jim Kneale...................... 49 Director
David L. Kyle................... 48 Director
Oscar C. Lindemann.............. 78 Director
John H. Trescot, Jr............. 75 Director
James E. Upfield................ 80 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,
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 42% interest.
39
Matthew C. Lutz has served as Chairman since March 1997 after having served
as Vice Chairman of the Company since December 1995. Mr. Lutz has also served as
Executive Vice President since December 1995. Mr. Lutz held similar positions
with Hunter from September 1993 until October 1996. From 1984 through 1992, Mr.
Lutz was Senior Vice President of Exploration and on the Board of Directors of
Enserch Exploration, Inc. with responsibility for such company's 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.
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.
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 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.
40
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.
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.
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.
41
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 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.
Gerald W. Bolfing has been a director of the Company since December 1995.
Mr. Bolfing was appointed a director of Hunter 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. During this time, he also joined 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 the Company since March 1999. From
February 1998 to March 1999 he served in the position of President, Chief
Operating Officer and Director of Oryx Energy Company ("Oryx"). 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.
Jim Kneale has served as a director of the Company since September 2000.
Mr. Kneale is currently employed by ONEOK, Inc., as senior vice president since
January 18, 2001 and is responsible for the finance, tax and accounting, risk
management 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 in 1992. Mr. Kneale became vice president of Tulsa
District 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. He is a graduate of
Leadership Oklahoma and Leadership Tulsa and is a Leadership Tulsa Paragon Award
winner. 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.
David L. Kyle has served as a director of the Company since February 1999.
Mr. Kyle is currently employed by ONEOK Inc., as its President and Chief
Operating Officer. Mr. Kyle was employed by Oklahoma Natural Gas Company, a
division of ONEOK Inc., in 1974 as an engineer trainee. He served in a number of
positions prior to being elected Vice President of Gas Supply in September 1986,
and Executive Vice President in May 1990. He was elected President in September
1994. He was elected President of ONEOK Inc. effective September 1997. He has
the management responsibility for all of the unregulated companies of ONEOK,
Inc. He received a B.S. degree in industrial engineering and management from
Oklahoma State University in 1974. He received an MBA degree in 1987 from The
University of Tulsa, and is a graduate of the Advanced Management Program at
Harvard Business School.
42
Oscar C. Lindemann has served as a director of the Company since December
1995. Mr. Lindemann was previously a director of Hunter, having been appointed
in November 1995. Mr. Lindemann has over 40 years experience in the financial
industry. Mr. Lindemann began his banking career with the Texas Bank and Trust
in Dallas, Texas in 1951. He served the bank until 1977 in many capacities,
including Chief Executive Officer and Chairman of the Board. Since leaving Texas
Bank and Trust, he has served as Vice Chairman of both the United National Bank
and the National Bank of Commerce, also in Dallas. Mr. Lindemann has also served
as a consultant to the banking industry. He retired from commercial banking in
1987. Mr. Lindemann is a former President of the Texas Bankers Association, and
a former state representative to the American Bankers Association. He was a
Founding Director and Board Member of VISA, and a member of the Reserve City
Bankers Association. He has served as an instructor at both the Southwestern
Graduate School of Banking at Southern Methodist University and the School of
Banking of the South at Louisiana State University.
John H. Trescot, Jr. has served as a director of the Company 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
OPIC (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, 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 owned by billionaire D.K. Ludwig. 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. He
is a bank director and multi-engine pilot. Mr. Trescot received his BME degree
from Clemson University and his MBA from the Harvard Business School.
James E. Upfield has served as a director of the Company since December
1995. Mr. Upfield was appointed a director of Hunter in August 1992. Mr. Upfield
is Chairman of Temtex Industries, Inc. based in Dallas, Texas, a public company
that produces consumer hard goods and building materials. In 1969, Mr. Upfield
served on a select Presidential Committee serving 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. ("Baifield") 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.
43
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, 2000.
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 2000 $300,000 $400,000 $ 7,500 - - - $19,933 (b)
President and CEO 1999 $250,000 $250,000 $ 7,500 - - - $19,342 (b)
1998 $250,000 $300,000 - - - - -
Matthew C. Lutz 2000 $175,000 $300,000 $ 8,400 - - - -
Executive V.P. and 1999 $150,000 $125,000 $ 6,000 - - - -
Chairman 1998 $156,000 $100,000 - - - - -
Richard R. Frazier 2000 $175,000 $125,000 $ 6,000 - - - -
President of 1999 $150,000 $ 75,000 $ 4,200 - - - -
Magnum Hunter 1998 $154,200 $ 50,000 - - - - -
Production, Inc.
Chris Tong 2000 $160,000 $ 65,000 $ 6,000 - - - -
Senior Vice President & 1999 $150,000 $ 35,000 $ 6,000 - - - -
Chief Financial Officer 1998 $156,000 $ 30,000 - - - - -
R. Douglas Cronk 2000 $122,500 $ 65,000 $ 6,000 - - - -
Senior V.P. of Magnum 1999 $115,000 $ 25,000 $ 4,200 - - - -
Hunter Production, Inc. 1998 $104,200 $ 20,000 - - - - -
Charles R. Erwin (c) 2000 $113,423 $125,000 $ 5,100 - - - -
Senior V.P. of Magnum 1999 $ 90,000 $ 7,500 - - - - -
Hunter Production, Inc. 1998 - - - - - - -
- ---------------------
(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.
44
Option/SAR Grants in Last Fiscal Year
Potential realizable value at Alternative to
assumed annual rates of stock (f) and (g):
price appreciation for option grant date
Individual Grants term value
- -------------------------------------------------------------------------------- ----------------------------- -------------
Name Number of Percent of total Exercise or base Expiration 5% ($) 10% ($) Grant date
securities options/SARs price ($/Sh) date present value
underlying granted to $
Options/SARs employees in
granted (#) fiscal year
(a) (b) (c) (d) (e) (f) (g) (f)
- ------------------- -------------- --------------- -------------- ------------ --------------- ------------- -------------
Gary C. Evans 300,000 19% $7.9375 12/08/10 1,697,460
Matthew C. Lutz 200,000 13% $7.9375 12/08/10 1,131,640
Richard R. Frazier 100,000 6% $7.9375 12/08/10 565,820
Charles R. Erwin 100,000 6% $7.9375 12/08/10 565,820
R. Douglas Cronk 50,000 3% $7.9375 12/08/10 282,910
Chris Tong 40,000 3% $7.9375 12/08/10 226,328
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of securities Value of unexercised in-
underlying unexercised the-money options/SARs
options/SARs at fiscal at fiscal year-end ($)
year-end (#)
Shares acquired on Value Exercisable/ Exercisable/
Name exercise (#) Realized ($) unexercisable unexercisable
(a) (b) (c) (d) (e)
- ----------------------------------------------------------------------------------------------------------------------
Gary C. Evans 500,000 $1,375,000 310,000 / 290,000 $1,949,850 / $1,935,900
Matthew C. Lutz - - 575,000 / 250,000 $3,873,250 / $1,207,500
Richard R. Frazier - - 270,000 / 155,000 $1,809,400 / $ 292,050
Charles R. Erwin 14,000 $ 103,840 24,000 / 92,000 $ 90,690 / $ 329,520
R. Douglas Cronk - - 82,000 / 73,000 $ 527,045 / $ 389,130
Chris Tong - - 161,000 / 89,000 $1,028,972 / $ 503,840
Compensation of Directors
The Company has nine individuals who serve as directors, seven of which are
independent. Two of these directors receive compensation with respect to their
services and in their capacities as executive officers of the Company and no
additional compensation has historically been paid for their services to the
Company as directors. The other seven directors of the Company are not employees
of the Company and receive no compensation for their services as directors other
than as stated below. For fiscal years 1999 and 2000, independent directors
received a $10,000 retainer for being a board member and in addition received
$1,000 per meeting attended. Each new independent director added to the board in
fiscal year 1999 was granted an option to acquire 25,000 shares of the Company's
common stock at an exercise price not less than the market price of the common
stock on the date of grant. In addition, for the fiscal years 1999 and 2000 each
independent director was granted stock options to acquire 10,000 and 15,000
shares, respectively,
45
of the Company's common stock at an exercise price not less than the market
price of the common stock on the date of grant. For fiscal year 2001,
independent directors will receive a $15,000 retainer 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. Matthew C. Lutz, 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, 2005 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
2001 is $350,000. Mr. Lutz's agreement terminates January 1, 2005 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. Lutz's salary for the year 2001 is
$245,000. Mr. Frazier's agreement terminates January 1, 2005 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 2001 is
$190,000. Mr. Tong's agreement terminates January 1, 2003 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 2001 is
$165,000. Mr. Cronk's agreement terminates January 1, 2003 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 2001 is
$138,000. Mr. Erwin's agreement terminates January 1, 2003 and continues
thereafter on a year to year basis and provides for a salary of $125,000 per
annum unless increased by the Board. Mr. Erwin's salary for the year 2001 is
$145,000. 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, Mr.
Lutz 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 and Mr. Cronk, 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.
46
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth certain information as of February 28, 2001,
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 February
28, 2001, 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 (o)
Directors and Executive Officers
Gary C. Evans .......................................... 2,856,073 (a) 7.8%
Matthew C. Lutz......................................... 833,229 (b) 2.3%
Richard R. Frazier...................................... 333,115 (c) *
Chris Tong.............................................. 169,933 (d) *
R. Douglas Cronk ....................................... 135,768 (e) *
Charles R. Erwin........................................ 24,000 (f) *
Gerald W. Bolfing....................................... 457,799 (g) 1.2%
Jerry Box............................................... 40,902 (h) *
Oscar C. Lindemann...................................... 43,902 (i) *
John H. Trescot, Jr..................................... 125,479 (j) *
James E. Upfield....................................... 124,392 (k) *
David L. Kyle .......................................... 45,342 (l) *
Jim Kneale ............................................. 4,000 (m) *
All directors and executive officers as a group
(13 persons)............................................ 5,193,934 13.8%
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 22.4%
Janus Capital Corporation
100 Fillmore St., Suite 300
Denver, CO. 80206...................................... 1,505,475 (n) 4.2%
- ------------
* Less than one percent.
(a) Includes 310,000 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 575,000 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.
(c) Includes 270,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
47
(d) Includes 160,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(e) Includes 82,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(f) Includes24,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(g) Includes 17,000 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.
(h) Includes 23,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(i) Includes 17,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(j) Includes 42,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(k) Includes 3,000 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) Includes 28,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(m) Includes 3,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(n) Based on Schedule 13G filed by Janus Capital Corporation on February
15, 2001.
(o) 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% and is due December 31,
2000. 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 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, 2001 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.
48
GLOSSARY
The terms defined in this glossary are used throughout this Form 10-K.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.
Bbl/d. One barrel of oil or other liquid hydrocarbons per day.
Bcf. One billion cubic feet of gas.
Bcf/d. One billion cubic feet of gas per day.
Bcfe. One billion cubic feet of Natural Gas Equivalents converting one Bbl
of oil to six Mcf of gas.
Btu. British Thermal Unit, the quantity of heat required to raise one pound
of water by one degree Fahrenheit.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
Gross Acres or Gross Wells. The total acres or wells, as the case may be,
in which a working interest is owned.
In-fill Well. A well drilled between known producing wells to better
exploit the reservoir.
Mbbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet of Natural Gas Equivalents converting one Bbl
of oil to six Mcf of gas.
Mcfe/d. Mcfe per day.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBtu. One million Btu.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet of Natural Gas Equivalents converting one Bbl
of oil to six Mcf of gas.
MMcf/d. One million cubic feet of gas per day.
Natural Gas Equivalent. The amount of gas having the same Btu content as a
given quantity of oil, with one Bbl of oil being converted to six Mcf of gas.
49
Net Acres or Net Wells. The sum of the fractional working interests owned
in gross acres or gross wells.
Net Revenue Interest. A share of the Working Interest that does not bear
any portion of the expense of drilling and completing a well and that represents
the holder's share of production after satisfaction of all royalty, overriding
royalty, oil payments and other nonoperating interests.
Productive Well. A well that is producing oil or gas or that is capable of
production in paying quantities.
Non-Producing Reserves. Proved Developed Reserves that consist of (i)
Proved Reserves from wells which have been completed and tested but are not
producing due to lack of market or minor completion problems which are expected
to be corrected and/or (ii) Proved Reserves currently behind-the-pipe in
existing wells and which are expected to be productive due to both the well log
characteristics and analogous production in the immediate vicinity of the wells.
Producing Reserves. Proved Developed Reserves that can be expected to be
recovered from currently producing zones under the continuation of present
operating methods.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e. prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (A) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil
that may become available form 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.
Proved Undeveloped Reserves. 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.
PV-10. The present value of Proved Reserves is an estimate of the
discounted future net cash flows from each of the properties at December 31,
2000, 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. As required by
rules of the Commission, 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. In
accordance with Commission rules, estimates have been made using constant oil
and gas prices and operating costs, at December 31, 2000, or as
50
otherwise indicated.
Recompletion. The completion for production of an existing wellbore in a
different formation or producing horizon from that in which the well was
previously completed.
Reserve Life. The estimated productive life of a proved reservoir based
upon the economic limit of such reservoir producing hydrocarbons in paying
quantities assuming certain price and cost parameters. For purposes of this Form
10-K, reserve life is calculated by dividing the Proved Reserves (on an Mcfe
basis) at the end of the period by projected production volumes for the next 12
months.
Royalty Interest. An interest in an oil and gas property entitling the
owner to a share of oil and gas production free of cost of production.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains Proved Reserves.
Working Interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
51
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, 2000 and 1999.......F-2
Consolidated Statements of Operations and Comprehensive Income
for the Years Ended December 31, 2000, 1999 and 1998..........F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2000, 1999 and 1998..................F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2000, 1999 and 1998........................F-5
Notes to Consolidated Financial Statements..............................F-6
Supplemental Information (Unaudited)...................................F-30
2. Financial Statement Schedule
We have included on page 55 of this Annual Report on Form 10-K Financial
Statement Schedule II, Valuation and Qualifying Accounts.
52
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 By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File
No. 33-66190)
3.6 & 4.6 Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated
December 26, 1996, filed January 3, 1997)
3.7 & 4.7 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)
3.8 & 4.8 Certificate of Designation for 1999 Series A 8% Convertible Preferred Stock (Incorporated by reference to
Form 8-K, dated February 3, 1999, filed February 11, 1999)
4.9 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)
4.10 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)
4.11 Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form S-4, File
No. 333-2290)
10.1 Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum Hunter Resources, Inc.
and Bankers Trust Company, et al. (Incorporated by reference to Registration Statement on Form S-4, File
No. 333-2290)
10.2 First Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
Hunter Resources, Inc. and Bankers Trust Company, et al. (Incorporated by reference to Registration
Statement on Form S-4, File No. 333-2290)
10.3 Second Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the
fiscal year-end December 31, 1998 filed April 14, 1999)
53
10.4 Third Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the
fiscal year-end December 31, 1998 filed April 14, 1999)
10.5 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)
10.6 Employment Agreement for Matthew C. Lutz (Incorporated by reference to Form 10-K for the fiscal year-
end December 31, 1999 filed March 30, 2000)
10.7 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)
10.8 Stock Purchase Agreement among Magnum Hunter Resources, Inc. and Trust Company of the West and TCW Asset Management
Company, in the capacities described herein, TCW Debt and Royalty Fund IVB and TCW Debt and Royalty Fund IVC,
dated as of December 6, 1996 (Incorporated by reference to Form 8-K dated December 26, 1996,
filed January 3, 1997)
10.9 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)
10.10 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)
10.11 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)
10.12 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)
10.13 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
* Filed herewith.
(B) Form 8-K's - None.
54
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, 2000 and 1999, and for each
of the three years in the period ended December 31, 2000, and have issued our
report thereon dated March 20, 2001. Such financial statements and report are
included in your Annual Report on Form 10-K, and are incorporated herein by
reference. Our audits also included the financial statement schedule of Magnum
Hunter Resources, Inc. listed in the accompanying index at Item 14. This
financial statement schedule is the responsibility of the Company's management.
Our responsibility is to express an opinion based on our audits. In our opinion,
such financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Dallas, Texas
March 20, 2001
55
Valuation and Qualifying Accounts
($ in thousands)
For the year ended December 31, 2000:
Balance at Additions
Beginning of Charged to Deductions Balance at end
Description Period Expenses Writeoffs of Period
- --------------------------------------------- ------------------ ---------------- ----------------- -----------------
Accounts receivable, trade $ 166 $ 80 $ (196) $ 50
Current portion of long-term notes 790 384 (4) 1,170
receivable
For the year ended December 31, 1999:
Balance at Additions
Beginning of Charged to Deductions Balance at end
Description Period Expenses Writeoffs of Period
- --------------------------------------------- ------------------ ---------------- ----------------- -----------------
Accounts receivable, trade $ 166 $ - $ - $ 166
Current portion of long-term notes 790 - - 790
receivable
56
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/A to be
signed on its behalf by the undersigned, thereunto duly authorized.
MAGNUM HUNTER RESOURCES, INC.
/s/Gary C. Evans
By: __________________________ March 30, 2001
Gary C. Evans, President & CEO
In accordance with the Exchange Act, this Form 10-K/A 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
______________________ Director, President March 30, 2001
Gary C. Evans Chief Executive Officer
/s/Matthew C. Lutz
______________________ Chairman of the Board and March 30, 2001
Matthew C. Lutz Executive Vice President of
Exploration and Business
Development
/s/Chris Tong
______________________ Senior Vice President and March 30, 2001
Chris Tong Chief Financial Officer
/s/David S. Krueger
______________________ Vice President and March 30, 2001
David S. Krueger Chief Accounting Officer
/s/Morgan F. Johnston
______________________ Vice President, General Counsel March 30, 2001
Morgan F. Johnston and Secretary
/s/Gerald W. Bolfing
______________________ Director March 30, 2001
Gerald W. Bolfing
/s/Oscar C. Lindemann
______________________ Director March 30, 2001
Oscar C. Lindemann
/s/John H. Trescot, Jr.
______________________ Director March 30, 2001
John H. Trescot, Jr.
/s/James E. Upfield
______________________ Director March 30, 2001
James E. Upfield
57