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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, 1999
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the transition period from __________ to
___________ .
Commission File No. 1-12508
MAGNUM HUNTER RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Nevada 87-0462881
State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (972) 401-0752
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class Name of each exchange on which registered
Common Stock ($.002 par value) American Stock Exchange
------------------------------ -----------------------
Common Stock Purchase Warrants 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 27, 2000, 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 $60,993,489.
The number of shares outstanding of the registrant's common stock at March
27, 2000 was 20,243,601.
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 ............................8
Gathering and Processing of Gas ...................................9
Marketing of Production ..........................................10
Petroleum Management and Consulting Services .....................11
Competition.......................................................11
Regulation .......................................................11
Employees ........................................................15
Facilities .......................................................15
Risk Factors......................................................15
Item 2. Description of Properties..........................................22
Oil and Gas Reserves .............................................22
Oil and Gas Production, Prices and Costs .........................24
Drilling Activity ................................................25
Oil and Gas Wells ................................................26
Oil and Gas Acreage ..............................................26
Item 3. Legal Proceedings..................................................27
Item 4. Submission of Matters to a Vote of Security Shareholders...........27
PART II
Item 5. Market for Common Equity and Related Stockholder Matters...........28
Item 6. Selected Financial Data............................................29
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................31
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...........38
Item 8. Financial Statements and Supplementary Data.........................42
Item 9. Change in and Disagreements with Accountants on Accounting
and Financial Disclosure.........................................43
PART III
Item 10. Directors and Executive Officers of the Registrant..................43
Item 11. Executive Compensation..............................................48
Item 12. Security Ownership of Certain Beneficial Owners and Management......50
Item 13. Certain Relationships and Related Transactions......................51
Glossary............................................................52
Item 14. Exhibits and Reports on Form 8-K....................................54
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 exploitation and development drilling opportunities.
The Company has identified over 700 development drilling locations (including
both production and injection wells) on its properties, 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, 1999, the Company had an interest in 3,100 wells and had
estimated Proved Reserves of 383.2 Bcfe with an SEC PV-10 of $370.1 million.
Approximately 74% of these reserves were Proved Developed Producing Reserves and
48% were attributable to the Mid-Continent Region, 47% were attributable to the
Permian Basin, and 5% were attributable to the Gulf Coast/Gulf of Mexico Region.
At December 31, 1999, the Company's Proved Reserves had an estimated Reserve
Life of approximately 14 years and were 60% natural gas. The Company serves as
operator for approximately 73% of its properties, based on the gross number of
producing wells in which the Company owns an interest and 89% of its properties,
based upon the year-end SEC PV-10 value.
As a result of its property acquisitions and successful drilling activities
during 1999, the Company has achieved growth as described below:
o Proved Reserves increased 19% to 383.2 Bcfe at year end 1999 from 323.2
Bcfe at year end 1998;
o SEC PV-10 increased 106% to $370.1 million at year end 1999 from $179.4
million at year end 1998; and
o Average daily production increased 28% to 73.7 MMcfe during fiscal 1999
from 57.4 MMcfe in fiscal 1998
Recent Acquisition
In June 1999, Magnum Hunter closed the acquisition of oil and gas reserves
and related assets from Vastar. The acquisition included 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 56-100%. The three fields currently generate net sales of
approximately 930 barrels per day of liquids and 5.9 million cubic feet per day
of natural gas production (total 11.5 million cubic feet equivalents per day).
Magnum Hunter's wholly-owned subsidiary, Gruy Petroleum Management Co. ("Gruy"),
is the operator of all of the wells and related assets.
Business Strategy
The Company's objective is to increase its reserves, production, cash flow
and earnings utilizing a program of (i) exploitation and development of acquired
properties, (ii) a selective exploration program and (iii) strategic
acquisitions of Proved Reserves.
The following are key elements of the Company's strategy:
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.
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. The Company also has an active onshore exploration program
concentrated in its various areas of operation.
2
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 73% of its properties (89% of its SEC 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.
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.
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
70% and markets directly and indirectly approximately 91% 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 350 MMcf per day as of
December 31, 1999. NGTS currently markets approximately 53% 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 (470 of which are operated
by the Company) and an associated 427 mile gas gathering system (the "Panoma
Properties"). As of year-end 1999, the Company had drilled an additional 85
wells and net production was approximately 13 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.
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 56-100%. The three fields generate net sales of approximately 930
barrels per day of liquids and 5.9 million cubic feet per day of natural gas
production (total 11.5 million cubic feet equivalents per day).
3
The Company has received an engineering evaluation from Ryder Scott Company
("Ryder Scott"), 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, as of December 31, 1999, the Mid-Continent
properties had Proved Reserves of 8.7 MMBbl of oil and 131.8 Bcf of natural gas,
or on a Natural Gas Equivalent basis, 184.1 Bcfe. Ryder Scott further estimated
the SEC PV-10 for the Mid-Continent properties to be $174.4 million as of
December 31, 1999 based on prices of $25.60 per Bbl of oil and $2.305 per Mcf of
natural gas. The Proved Reserves are located principally in the Ardmore Basin in
south central Oklahoma, in the Oklahoma/Texas panhandle and in Southwestern
Arkansas. Approximately 72% of the estimated reserves are natural gas and 28%
are oil located on approximately 50,000 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 is approximately 29
million cubic feet of natural gas production and 700 barrels of oil.
Approximately 87% of the Proved Reserves were classified Proved Developed
Producing Reserves as of December 31, 1999. The Company has engaged its Houston
based geological affiliate, Swanson Consulting Services, Inc., to conduct an
evaluation of the most prospective undeveloped properties located in one of the
fields acquired. The Company's wholly-owned subsidiary, Gruy, has become the
operator of 89% or 655 of the 735 wells located in the Mid-Continent Region.
The major fields in the Mid-Continent Region are the Panoma, Cumberland,
Caddo, Hitchcock ,Walnut Bend, Madill and Walker Creek.
Panoma. The Panoma Properties currently consist of approximately 560
natural gas wells in the West Panhandle, East Panhandle, and South Erick Fields
along a corridor 65 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.
Current net production is approximately 13 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 128
wells, with working interests varying from 17.2% to 100%. The Company operates
all but nine of these wells. The latest available gross production from the
field averaged 6,000 Mcf/d and 250 Bbl/d.
Caddo. The Caddo Field is located in Carter County, Oklahoma. It was
discovered in 1939 and currently produces gas from various shallow reservoirs,
such as the Goddard, Sycamore, Woodford, Hunton, and Viola, at depths ranging
from 2,200' to 4,200'. Initially all of these reservoirs were produced
separately; however, today, many are commingled down-hole. The Company operates
14 wells with a 100% working interest. The latest available gross production
from the wells averaged 2,100 Mcf/d.
Hitchcock. The Hitchcock Field is located in Blaine County, Oklahoma. It
was discovered in 1965 and produces gas from the Morrow formation at depths
ranging from 8,000' to 8,200'. Original development in this field was based on
640-acre spacing. Recent drilling activity has focused on in-fill locations in
the Morrow. The Company currently has interest in 15 wells, with working
interest varying from 12.5% to 87.5%, and operates four of these wells. The
latest available gross production from the wells averaged 3,000 Mcf/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 39
active injection wells. The Company's working interest ownership in the wells
varies from 85.7% to 100%. The latest available gross production from the wells
averaged 180 Mcf/d and 800 Bbl/d.
4
Madill. The Madill Field is located in Marshall County in Southern
Oklahoma. The first production from this field occurred in 1906 and produces
primarily gas from various shallow reservoirs, such as the Sycamore, Woodford,
Viola and Bromide at depths ranging from 3,750' to 5,700'. There are currently
56 active producing wells. The Company's working interest ownership in the wells
varies from 32.7% to 100%. The latest available gross production from the wells
averaged 2,300 Mcf/d and 100 Bbl/d.
Walker Creek. The Walker Creek Field is located in Southwestern Arkansas in
Lafayette and Columbia Counties. This field was discovered in March of 1968. The
field produces from the Smackover formation at an average depth of 10,800' and
covers 14,840 gross acres. There are currently 29 active producing wells. The
Company's working interest ownership in the wells and the associated gas
processing plant is 57.21%. The latest available gross production from the wells
averaged 9,000 Mcf/d and 400 Bbl/d. The gas processing plant strips
approximately 380 barrels per day of additional liquids from the gas stream.
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; the San Andres in the Levelland/Slaughter Field
in Cochran County, Texas; and the Canyon Sand in Sutton County, Texas. The
Permian Basin Properties include 1,792 producing oil and gas wells on
approximately 113,810 gross acres (82,175 net acres). One of the Company's
subsidiaries, Gruy, serves as operator on approximately 55% 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.
According to Ryder Scott and Pollard, Gore and Harrison ("PG&H"),
independent petroleum engineers engaged by the Company to evaluate certain of
the Company's properties, as of December 31, 1999, the Permian Basin Properties
had Proved Reserves of 15.8 MMBbl of oil and 84.5 Bcf of gas, or on a Natural
Gas Equivalent basis, 179.6 Bcfe. Ryder Scott further estimated the SEC PV-10
for the Permian Basin Properties to be $169.8 million as of December 31, 1999
based on prices of $25.60 per Bbl of oil and $2.305 per Mcf of gas at December
31, 1999. Approximately 56% of the Proved Reserves were classified as Proved
Developed Producing reserves as of December 31, 1999. See "Properties - Oil and
Gas Reserves." Based on the $133.8 million adjusted purchase price and Proved
Reserves of 186.9 Bcfe as of April 30, 1997, the Company paid approximately
$0.72 per Mcfe for the Permian Basin Properties.
The major fields in the Permian Basin are the Westbrook,
Levelland/Slaughter, Lea County Shallow Properties and the Brunson Ranch.
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 following table sets forth information
regarding three properties in the Westbrook Field:
Gross Oil
Well Working Net Revenue Production
Property Operator Count Interest Interest (Bbl/d)
- ------------------------------------------------------------------------------------------------------------------------------------
Southwest Westbrook Unit............... Company 135 89.9% 77.5% 420
Morrison "G" Lease..................... Company 12 100.0% 87.5% 16
North Westbrook Unit................... Third Party 206 2.0% 2.8% (a) 1,200
(a) Includes an overriding Royalty Interest.
5
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 initiated
waterflood enhancement operations on the Southwest Westbrook Unit and the
Morrison "G" Lease in the first quarter of 2000.
Levelland/Slaughter. The Levelland and Slaughter Fields consist of 174
wells located in Cochran County, Texas that produce from the San Andres
formation at a depth of 5,000 feet. The interests acquired in the Permian Basin
Acquisition include the following three properties in the Levelland and
Slaughter Fields:
Gross Oil
Well Working Net Revenue Production
Property Operator Count Interest Interest (Bbl/d)
- ------------------------------------------------------------------------------------------------------------------------------------
TLB Unit............................... Company 20 100.0% 87.3% 75
Veal Lease............................. Company 52 100.0% 87.1% 190
NW Slaughter Unit...................... Company 83 74.8% 62.8% 265
Discovered in the 1930's, all three 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 to successfully enhance
production.
Lea County Shallow Properties. The Lea County Shallow Properties consist of
approximately 300 wells in Lea County, New Mexico which are in the Rhodes,
Jalmat, Monument, Langlie Mattix, Eumont and Eunice Fields. The fields produce
from the Yates, Seven Rivers, Queen and other formations at depths generally
shallower than 3,000 feet. Production is generally high Btu gas, which produces
into low pressure gathering systems. At year-end approximately 15 proved
undeveloped locations were identified and the Company anticipates that numerous
additional recompletion, stimulation, workover or development drilling
opportunities will result from detailed geological and engineering studies that
are in progress.
Brunson Ranch. The Brunson Ranch Field consists of four wells located in
Loving County, Texas in the deep Delaware Basin geological province of the
Permian Basin. The wells are currently producing a total of approximately 4.2
MMcf of gas per day from the Atoka formation at a depth of approximately 16,000
feet. Undeveloped potential exists on the properties through redrilling the
Atoka formation, sidetracking certain existing wells, and completing such wells
using technology designed for high bottom hole pressure conditions.
Gulf Coast/Gulf of Mexico
The Company owns properties both onshore Gulf Coast and offshore Gulf of
Mexico.
Onshore Gulf Coast
The Company owns interests in three 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 and a confirmation to this discovery,
located 3.5 miles southwest, was completed at year-end 1998. The third well was
drilled in 1999. The Company owns an average of a 25% working interest in a
36,000 acre lease block surrounding the producing wells. A fourth well is
currently being drilled in which the Company owns a 25% working interest. Union
Pacific Resources Corporation is the operator of the drilling phase for this
well and owns the remaining 75% working interest. Current gas production from
the three producing wells is approximately 2,000 Mcf/d. Additional development
drilling is planned in this field during 2000, if the Company can continue to
reduce the drilling costs of each well.
6
Other onshore Gulf Coast properties are located in the Giddings Field, the
First Shot Field and the Clinton Field. 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 1.2
Bcfe in 1999.
In May 1999, the Company entered the Gulf of Mexico as a working interest
participant in new exploratory drilling on the shallow water shelf. This new
program yielded four new discoveries in six attempts in 1999 and is expected to
continue to add significantly to reserves and cash flow as these successes are
put on production. Initial sales from one of the Company's 1999 discoveries
commenced in February 2000. This well, on Vermillion Block 84 in the Gulf of
Mexico, is currently flowing at a rate of approximately 16 million cubic feet of
natural gas and 1,000 barrels of condensate per day from one of two major pay
intervals. Production from other Gulf of Mexico successes is scheduled to
commence during 2000 and into 2001. The Company owns an interest in 34 blocks in
the Gulf of Mexico with working interest generally at the 25% level.
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 2,000 horsepower of high speed compression and a gas processing
capacity of approximately 23 million cubic feet per day. Current throughput of
the plant is approximately 16.5 million cubic feet per day with processed
liquids of 1,150 barrels per day. The Company received 100% of the net profits
from the McLean Gas Plant until it recouped the $2.5 million purchase price,
after which time it receives 50% of the net profits. At December 31, 1999, the
Company had recouped its initial investment.
Dynegy 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.
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. Current
throughput of the plant is approximately 13 million cubic feet per day of
natural gas with processed liquids of 900 barrels per day. The effective date of
the acquisition was November 1, 1999. See "Gathering and Processing of Gas."
Walker Creek Plant
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. 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. Current throughput of the plant is
approximately 9 MMcf/d with processed liquids of 380 Bbl/d. The effective date
of the acquisition was April 1, 1999 with assumption of operations on June 1,
1999.
7
Development and Exploration Activities
Overview
The Company presently intends to continue to focus its efforts on property
acquisitions, its substantial inventory of exploitation and development
activities and selected exploratory drilling prospects.
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 $10.0 million
for exploitation and development activities for 2000. The Company has identified
over 700 development drilling locations (including both production and injection
wells) on its properties. In exploiting its producing properties, the Company
relies upon its in-house technical staff of petroleum engineering and geological
professionals and utilizes the services of outside consultants on a selective
basis.
Mid-Continent Region. The Company believes that developmental drilling can
continue to enhance the value of the Panoma Properties, which produce from the
Brown Dolomite and Granite Wash formations in the Texas Panhandle and western
Oklahoma. The easternmost fields are developed on 160 acre spacing because the
original spacing of 640 acres proved inadequate to drain reserves efficiently.
In-fill development has been underway in the fields with 85 wells having been
completed during the last three years. The westernmost field has now been
effectively developed with 320 acre spacing.
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, Hunton, and Viola. These formations are predominantly gas productive
and are produced commingled. Potential exists for three additional wells to
complete development of the shallow gas on 160-acre spacing. The first well is
scheduled to be drilled in April 2000. The Company will have a 50% working
interest in the well. Additional potential exists in revamping water injection
and production from the oil zones, and development drilling utilizing 3-D
seismic which has been obtained covering the field area.
Permian Basin Properties. In evaluating the Permian Basin Properties, the
Company has identified over 300 drilling locations including production and
injection wells. Engineering and geological studies are being initiated to more
precisely identify specific development locations. The Lea County Shallow
Properties consist of approximately 300 wells in Lea County, New Mexico which
are in the Rhodes, Jalmat, Monument, Langlie Mattix, Eumont and Eunice Fields.
These fields produce from the Yates, Seven Rivers, Queen and other formations at
depths generally shallower than 3,000 feet. Production is generally high Btu
gas, which produces into low pressure gathering systems. At year-end
approximately 15 proved undeveloped locations were identified and the Company
anticipates that numerous additional recompletion, stimulation, workover or
development drilling opportunities will result from detailed geological and
engineering studies which are planned. During 1999, the Company drilled 5
successful wells in the Sawyer Canyon Field in the Sonora area located in Sutton
County, Texas. The Company owns an interest in 160 wells in this area which
consists of the Sawyer Canyon Field, the Sonora Canyon Field and the
Phyllis-Sonora Field. Production from all fields is from a series of tight
canyon-age gas sands.
Onshore Gulf Coast. During 1999, the Company drilled a third horizontal
well in the Mossy Grove Prospect in Walker County, Texas. This well produces
from the Glen Rose formation at a depth of approximately 12,000 feet
8
and is currently producing approximately 1,000 Mcf/d. A fourth well is currently
being drilled in which the Company owns a 25% working interest. This well is
anticipated to be completed in April 2000. Union Pacific Resources Corporation
is the operator of the drilling phase for this well and owns the remaining 75%
working interest. Additional development drilling is planned in this field
during 2000, with as many as 12 additional wells if drilling costs and reserve
estimates appear favorable.
The Company recently reentered a 100% owned well in the First Shot Field in
Gonzales County, Texas and also drilled a new Austin Chalk lateral leg that was
successful. Current production is 230 barrels of oil per day. Similar re-drills
are planned in the Giddings Field during the next couple of years.
Exploratory Drilling
The Company spent $9 million of its $60 million 1999 capital budget on
exploratory drilling and related land and geophysical costs. Fourteen
exploratory wells were drilled in 1999 of which 11 were successful providing the
Company with a 79% 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 four new discoveries in six attempts in 1999 and is expected to
continue to add significantly to reserves and cash flow as these new properties
are put on production. Initial production from one of the Company's 1999
discoveries commenced in February 2000. This well, on Vermillion Block 84 in the
Gulf of Mexico, is currently flowing at a rate of approximately 16 million cubic
feet of natural gas and 1,000 barrels of condensate per day from one of two pay
intervals. Two additional wells have been approved to continue development of
the block. Production from other Gulf of Mexico discoveries are scheduled to
commence during 2000 and into 2001 with additional drilling planned to fully
develop these new discoveries. The Company owns an interest in 34 separate
blocks in the Gulf of Mexico with ownership generally at the 25% level.
The onshore exploration program also continues to meet with success. A new
discovery on the Bobcat project in Hockley County, Texas has been completed
producing at an initial rate in excess of 200 Bbl/d. The Company owns a 25%
working interest in this well and in the 3-D controlled project where some 15
exploratory prospects have been identified. The Company has leased approximately
15,000 mineral acres for this project. A new exploratory well is scheduled to
commence by mid-year 2000 to further evaluate this area. The Company also owns a
34% working interest in a recent discovery operated by Occidental Petroleum
Corporation in Ector County, Texas. Additional development drilling is scheduled
to offset this well which was completed producing 80 Bbl/d and 100 Mcf/d.
Also in West Texas, a deeper zone discovery in an older field was completed
flowing at over 300 Bbl/d. The Company owns a 27% working interest in this well
and plans to continue development of this area with participation in at least
four additional wells.
The Company has a significant inventory of exploration prospects both
onshore and offshore and is actively generating and evaluating other projects
for future exploration activity. The recent acquisition of 3-D seismic data
covering over 300 blocks in the Gulf of Mexico will assist in continuing to
build a substantial, high-quality prospect inventory.
Gathering and Processing of Gas
Hunter Gas Gathering, Inc., a wholly-owned subsidiary of the Company, owns
three gas gathering systems located in Oklahoma, Texas and Arkansas, none of
which are subject to regulation by the Federal Energy Regulatory Commission
("FERC"), and an approximate 50% ownership interest in three gas processing
plants. Gruy operates one of the gas gathering systems and one of the gas
processing plants. In July 1999, the Company sold a small gathering system
located in East Texas that accounted for less than 4% of the Company's total gas
gathering throughput for an approximate $200,000 gain.
9
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.
The Panoma system, the largest of the Company's gas gathering systems,
consists of approximately 442 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 1999, gas
throughput for the Panoma gas gathering system was approximately 16.8 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 496 of the approximately 586
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. Current throughput is
approximately 16.5 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. Current
throughput of the plant is approximately 13 million cubic feet per day of
natural gas with processed liquids of 900 barrels per day. The effective date of
the acquisition was November 1, 1999.
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. 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. Current throughput of the plant is
approximately 9 MMcf/d with processed liquids of 380 Bbl/d. The effective date
of the acquisition was April 1, 1999 with assumption of operations on June 1,
1999.
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 month-to-month basis contracts at prevailing spot market prices or
(ii) at negotiated prices under long-term contracts. 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.
10
In December 1997, Hunter Gas Gathering, Inc. acquired a thirty percent
(30%) membership interest in NGTS, a newly formed 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 five year old natural gas marketing and trading company with
operations concentrated in the western two-thirds of the country. In fiscal
1999, NGTS reported total revenues of approximately $277 million. NGTS is
presently marketing approximately 350 million cubic feet of natural gas per day.
As of December 1, 1997, the Company and its gas gathering subsidiary, Hunter Gas
Gathering, Inc., dedicated substantially all of its natural gas production to
NGTS for marketing. The balance of the Company's production is dedicated to
either ONEOK or various third parties through gas processing agreements.
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 40-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.
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
The Company's oil and gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Because such rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
laws.
11
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells, and the regulation
of spacing, plugging and abandonment of such wells. Many states restrict
production to the market demand for oil and gas. Some states have enacted
statutes prescribing ceiling prices for gas sold within their states.
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the
past, the federal government has regulated the wellhead price of natural gas.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was
enacted, which amended the NGPA to remove wellhead price controls on all
domestic natural gas as of January 1, 1993. While sales by producers of natural
gas, and all sales of oil, condensate and natural gas liquids, can currently be
made at uncontrolled market prices, Congress could re-enact price controls in
the future.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that have had a major impact on natural gas pipeline
operations, services and rates and thus have significantly altered the marketing
and price of natural gas. Commencing in April 1992, the FERC issued Order Nos.
636, 636-A and 636-B (collectively, "Order No. 636"), which, among other things,
require each interstate pipeline company to "restructure" to provide
transportation separate or "unbundled" from the sale of gas and to make
available on an open and nondiscriminatory basis numerous constituent services
(such as gathering services, storage services, firm and interruptible
transportation services) and to adopt a new ratemaking methodology to determine
appropriate rates for those services. To the extent the pipeline company or its
sales affiliate makes gas sales as a merchant in the future, it does so in
direct competition with all other sellers pursuant to private contracts;
however, pipeline companies and their affiliates were not required to remain
"merchants" of gas and several of the interstate pipeline companies have become
"transporters" only. Following the conclusion of individual restructuring
proceedings for each interstate pipeline pursuant to Oder No. 636, the FERC has
approved, with modifications, all of the restructuring plans implementing Order
No. 636 on every interstate pipeline.
On July 16, 1996, the Court of Appeals for the District of Columbia Circuit
(D.C. Circuit) issued its opinion on review of Order No. 636. The opinion upheld
most elements of Order No. 636 including the unbundling of sales and
transportation services, curtailment of pipeline capacity, implementation of the
capacity release program and the mandatory imposition of straight-fix-variable
("SFV") rate design for interstate pipeline companies. The D.C. Circuit did
remand certain aspects of Order No. 636 to the FERC for further explanation
including, inter alia, the FERC's decision to exempt pipelines from sharing in
gas supply realignment ("GSR") costs caused by restructuring; FERC's selection
of a 20 year matching cap for the right-of-first-refusal mechanism; the FERC's
restriction on the entitlement of no-notice transportation service to only those
customers receiving bundled sales service at the time of restructuring; and
FERC's determination that pipelines should focus on individual customers, rather
than customer classes, in mitigating the effects of SFV rate design. On May 12,
1997, the United States Supreme Court denied certiorari of the D.C. Circuit's
decision.
On February 27, 1997, the FERC issued its order on remand ("Order No.
636-C"). The order reaffirmed the holding of Order No. 636 that pipelines should
be entitled to recover 100% of their prudently incurred GSR costs. Moreover, the
FERC determined since Order No. 636, the average length of transportation
contracts was substantially less than 20 years. Thus, FERC reduced the contract
matching cap for the right-of-first-refusal mechanism to five years. In light of
the varied post-restructuring experience with no-notice service, the FERC also
decided to no longer limit a pipeline's no-notice service to its bundled sales
customers at the time of restructuring. Finally, the FERC reaffirmed that
pipelines should focus on individual customers, rather than customer classes, in
mitigating the effects of SFV rate design. On May 28, 1998, FERC denied requests
for rehearing of Order No. 636-C. Appeals of individual pipeline restructuring
orders are still pending before the D.C. Circuit.
12
On May 31, 1995, the FERC issued a policy statement on how interstate
natural gas pipelines can recover the costs of new pipeline facilities. The
policy statement focused on whether projects would be priced on rolled-in basis
(rolling in the expansion costs with the existing facilities) or on an
incremental basis (establishing separate cost of services and separate rates for
the existing and expansion facilities). The policy statement established a
presumption in favor of rolled-in rates when the rate increase to existing
customers from rolling in the new facilities is 5% or less. In the policy
statement, the FERC contemplated that the resolution of pricing methodology
would take place in individual proceedings based on the facts and circumstances
of the project. The Company cannot predict what action the FERC will take in the
individual proceedings.
In October 1992, Congress passed the Energy Policy Act of 1992 ("Energy
Policy Act"). The Energy Policy Act deemed petroleum pipeline rates in effect
for the 365-day period ending on the date of enactment of the Energy Policy Act
or that were in effect on the 365th day preceding enactment and had not been
subject to complaint, protest or investigation during the 365-day period to be
just and reasonable under the Interstate Commerce Act. The Energy Policy Act
also provides that complaints against such rates may only by filed under the
following limited circumstances: (i) a substantial change has occurred since
enactment in either the economic circumstances or the nature of the services
which were a basis for the rate; (ii) the complainant was contractually barred
from challenging the rate prior to enactment; or (iii) the rate is unduly
discriminatory or preferential. The Energy Policy Act further required FERC to
issue rules establishing a simplified and generally applicable ratemaking
methodology for petroleum pipelines proceedings. On October 22, 1993, the FERC
responded to the Energy Policy Act directive by issuing Order No. 561, which
adopts a new indexing rate methodology for petroleum pipelines. Under the new
regulations, which were effective January 1, 1995, petroleum pipelines are able
to change their rates within prescribed ceiling levels that are tied to the
Producer Price Index for Finished Goods, minus one percent. Rate increases made
pursuant to the index will be subject to protest, but such protest must show
that the portion of the rate increase resulting from application of the index is
substantially in excess of the pipeline's increase in costs. The new indexing
methodology can be applied to any existing rate, even if the rate is under
investigation. If such rate is subsequently adjusted, the ceiling level
established under the index must be likewise adjusted.
In Order No. 561, FERC said that as a general rule pipeliners must utilize
the index methodology to change their rates. FERC indicated, however, that it
was retaining cost of service ratemaking, market-based rates, and settlements as
alternatives to the indexing approach. A cost of service methodology will also
continue to be used to determine just and reasonable initial rates for new
services. A pipeline can also follow a cost of service approach when seeking to
increase its rates above index levels for uncontrollable circumstances. A
pipeline can seek to charge market-based rates if it can establish that it lacks
market power. Finally, a pipeline can establish rates pursuant to settlement if
agreed upon by all current shippers.
On May 10, 1996, the D.C. Circuit affirmed Order No. 561. The Court held
that by establishing a general indexing methodology along with limited
exceptions to index rates, FERC had reasonably balanced its dual
responsibilities of ensuring just and reasonable rates and streamlining
ratemaking through generally applicable procedures.
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,
13
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.
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.
Notwithstanding the Company's lack of control over wells owned by the Company
but operated by others, the failure of the operator to comply with applicable
environmental regulations may, in certain circumstances, be attributable to the
Company. The Company currently expects to spend approximately $400,000 over the
next five years in connection with remediation and environmental compliance,
including $75,000 in 2000 and $75,000 in 2001.
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.
14
Employees
At December 31, 1999, the Company had 89 full-time employees of which 25
were management, 31 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
We have a significant amount of debt
We are highly leveraged, with outstanding long-term debt of approximately
$234.8 million compared to stockholders' equity of $53.6 million as of December
31, 1999. 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.
To service our indebtedness, we will require a significant amount of cash
While we reported an operating profit for fiscal 1999, we reported an
operating loss for fiscal 1998, and at December 31, 1999, we had an accumulated
deficit of $62.5 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, 1999, we had $7.0
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, 1999, had $3.2 million of borrowing
available. However, as of March 30, 2000, Bluebird has $200,000 of borrowing
capacity available under its credit facility. A significant decline in oil or
gas prices below their current levels could materially adversely affect the
availability of funds under our credit facility.
15
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, 1999, we
had a Debt to Capitalization Ratio of 0.67 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
o 1.50 to 1.0 for the calendar quarters ending September 30, 1999 through
December 31, 2000;
o 1.75 to 1.0 for the calendar quarters ending March 31, 2000 through June
30, 2000; and
o 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 1.52 to 1.0 as of
December 31, 1999. 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.
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. ONEOK is currently marketing
production from five wells for a total of 375 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
16
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.
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
17
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 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.
18
We Hedge Our Oil And Gas Production
As of December 31, 1999, we had hedged approximately (i) 16% of our gas
production through December 31, 2000, and (ii) 63% of our oil production through
December 31, 2000. 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
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.
19
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 15, 2000, 20,243,601 shares were issued and outstanding, and 15,269,663
shares were reserved for issuance upon the conversion of shares of our preferred
stock and upon the exercise of certain outstanding warrants and options. We also
reserve 10,512,149 shares for issuance upon exercise of the warrants issued in
June 1999. Issuing additional shares of common stock pursuant to such conversion
rights, outstanding warrants, options and warrants would reduce the
proportionate ownership and voting rights of the common stock then outstanding.
Our existing management and their affiliates own 2,403,644 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.
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
20
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.
General Business Risks
"Year 2000" Readiness
Beginning in 1998, the Company was involved in a program to be "Year 2000"
ready. The program involved reviews of major business, financial and other
information systems, including equipment with embedded microprocessors,
development of specific plans for modification or replacement of date-sensitive
software or microprocessors, execution of such plans and the testing of such
systems to ensure their "Year 2000" readiness. Included within the scope of the
program were contacts with key suppliers and customers to determine their "Year
2000" readiness in order to ensure a steady flow of goods and services to the
Company and continuity with respect to customer service. As a result of this
program, there were no significant occurrences of Year 2000-related failures.
Additionally, the Company does not anticipate that any significant subsequent
events will occur.
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21
Item 2. Description of Properties
Oil and Gas Reserves
General
All information set forth in this Form 10-K regarding estimated Proved
Reserves, related estimated future net cash flows and SEC PV-10 of the Company's
oil and gas interests is taken from reports prepared by Ryder Scott Company of
Houston, Texas and Pollard, Gore & Harrison of Austin, Texas, both independent
petroleum engineers with respect to the Company's interests at December 31, 1999
(using oil and gas prices in effect at December 31, 1999) and December 31, 1998.
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.
SEC 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, 1999, 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, 1999, or
as otherwise indicated.
In accordance with Commission guidelines, the estimates of future net cash
flows from Proved Reserves and their SEC 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 SEC PV-10 were estimated using the following
weighted average prices, before deduction of production taxes:
Prices used in Reserve Reports at
December 31,
---------------------------------------
1999 1998
---------------------------------------
Gas (per Mcf)............................ $2.25 $2.12
Oil (per Bbl)............................ $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 SEC 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
22
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,
1999. 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, 1999.
Company Reserves
The following tables set forth the estimated Proved Reserves of oil and gas
of the Company and the SEC PV-10 thereof on an actual basis at December 31, 1999
and 1998.
Estimated Proved Oil and Natural Gas Reserves (1)
At December 31,
--------------------------------
1999 1998
--------------------------------
Net gas reserves (Mcf):
Proved developed producing.............. 178,393,622 173,220,374
Proved developed non-producing.......... 6,561,110 1,767,000
Proved undeveloped...................... 45,044,794 44,072,300
--------------------------------
Total proved gas reserves............. 229,999,526 219,059,674
--------------------------------
Net oil reserves (Bbl):
(including condensate and NGL)
Proved developed producing.............. 15,684,726 9,015,703
Proved developed non-producing.......... 614,859 458,888
Proved undeveloped...................... 9,234,165 7,874,050
--------------------------------
Total proved oil reserves............. 25,533,750 17,348,641
--------------------------------
Total Proved Reserves (Mcfe)................. 383,202,026 323,151,521
--------------------------------
Estimated SEC PV-10 of Proved Reserves (a)
At December 31,
--------------------------------
1999 1998
--------------------------------
Estimated SEC PV-10 (b) :
Proved developed producing ............ $ 269,445,091 $ 156,629,617
Proved developed non-producing ........ 13,036,102 4,355,278
Proved undeveloped .................... 87,609,991 18,424,052
--------------------------------
Total Proved Reserves................ $ 370,091,184 $ 179,408,947
--------------------------------
- -----------
(a) Based upon reserve reports at December 31, 1999 and December 31, 1998
prepared by Ryder Scott and PG&H.
(b) SEC 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.
23
Significant Properties
On December 31, 1999, 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 3,100 gross (1,797 net) productive oil and gas wells.
The following table sets forth summary information with respect to the
Company's estimated Proved Reserves of oil and gas at December 31, 1999.
SEC PV-10 (a) Proved Reserves
----------------------------------------------------------------------------
Natural Gas
Amount % of Oil Gas Equivalent
(in thousands) Total (Bbl) (Mcf) (Bcfe)
-------------------------------------------- --------------- ---------------
Mid-Continent Area (b)............... $174,419 47 8,721,097 131,813,000 184.14
Permian Basin Region (b)(c).......... $169,845 46 15,846,808 84,484,000 179.56
Gulf Coast/Gulf of Mexico (b) ...... $25,827 7 965,845 13,703,000 19.50
-----------------------------------------------------------------------------
Total ........................ $370,091 100 25,533,750 230,000,000 383.20
-----------------------------------------------------------------------------
- ----------
(a) SEC 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 a reserve report at December 31, 1999 prepared by
Ryder Scott.
(c) Based on reserve reports at December 31, 1999 prepared by PG&H.
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,
1999 1998
---------------------------
Oil and gas production:
Oil (Mbbl)..................................... 1,307 1,141
Gas (MMcf)..................................... 19,026 14,119
Natural Gas Equivalents (MMcfe)................ 26,868 20,965
Average sales price (a):
Oil (per Bbl).................................. $ 15.01 $ 12.67
Gas (per Mcf).................................. 2.16 2.02
Natural Gas Equivalents (per Mcfe)............. 2.26 2.05
Oil and gas production lifting costs (per Mcfe) . .57 .68
Production taxes and other costs (per Mcfe) (b).. $ .30 $ .31
- ----------
(a) Before deduction of production taxes and net of hedging results for
the two years ended December 31, 1999.
(b) Includes ad valorem taxes, insurance, bonds, company overhead and net
profits interest.
24
Drilling Activity
The following table sets forth the results of the Company's drilling
activities during the two fiscal years ended December 31, 1999 and 1998.
Gross Wells (a) Net Wells (b)
Year Type of Well Total Producing (c) Dry (d) Total Producing (c) Dry (d)
---- ------------ ----- ------------- ------- ----- ------------- -------
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.
25
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, 1999. All of these
wells are located in the United States.
Productive Wells
As of December 31, 1999
Gross (a) Net (b)
Location Oil Gas Total Oil Gas Total
- -------- --- --- ----- --- --- -----
Texas...................... 1,372 834 2,206 690 590.00 1,280.00
Offshore Texas ............ 0 1 1 0 0.25 0.25
Oklahoma................... 139 274 413 83 164.00 247.00
Mississippi................ 2 0 2 2 0.00 2.00
New Mexico................. 148 274 422 73 164.00 237.00
California................. 5 0 5 1 0.00 1.00
Offshore Louisiana......... 0 5 5 0 1.88 1.88
Arkansas................... 46 0 46 28 0.00 28.00
---------------------------------------------------------------------------------------------------------
Total ............ 1,712 1,338 3,100 877 920.13 1,797.13
---------------------------------------------------------------------------------------------------------
- ----------
(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, 1999.
Developed Undeveloped
Gross (a) Net (b) Gross (a) Net (b)
Offshore........................... 35,760 11,440 52,280 11,100
Texas.............................. 257,138 210,398 74,381 39,365
Oklahoma........................... 97,637 71,351 6,582 3,302
Mississippi........................ 80 80 0 0
New Mexico......................... 41,437 35,439 0 0
California......................... 509 38 0 0
-------------------------------------------------------------------------------------------------
Total ....................... 432,561 328,746 133,243 53,767
-------------------------------------------------------------------------------------------------
- ----------
(a) The number of gross acres is the total number of acres in which a
working interest is owned.
(b) The number of net acres is the sum of fractional working interests
owned in gross acres expressed as whole numbers and fractions
thereof.
Substantially all of the Company's interests are leasehold working
interests or overriding royalty interests (as opposed to mineral or fee
interests) under standard onshore oil and gas leases. As is customary in the
industry, the Company generally acquires oil and gas acreage without any
warranty of title except as to claims made by, through
26
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 1999.
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27
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 15, 2000, there were 3,452 stockholders of record.
Average Daily
Trading Volume
High Low (Shares)
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
1998
First Quarter ............. $5.50 $3.88 85,139
Second Quarter ............ $7.94 $5.13 210,992
Third Quarter ............. $6.88 $3.00 118,228
Fourth Quarter............. $4.38 $2.75 133,437
On March 28, 2000, the last reported sale price of the Company's Common
Stock on the American Stock Exchange was $4.00 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.
The Company's Common Stock Purchase Warrants have been listed on the
American Stock Exchange since July 19, 1999. The Common Stock Purchase Warrants
have been listed under the ticker symbol "MHR.WS" . At March 15, 2000, there
were 3,279 warrant holders of record.
Average Daily
Trading Volume
High Low (Shares)
1999
Third Quarter ............. $1.06 $0.31 15,842
Fourth Quarter ............ $0.44 $0.19 6,911
On March 28, 2000, the last reported sale price of the Company's Common
Stock Purchase Warrants on the American Stock Exchange was $0.69 per share.
28
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, 1999, 1998, 1997, 1996 and 1995, 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.
1995 1996 1997 1998 1999
---------- ---------- ---------- ---------- -------------
Income Statement Data:
Total operating revenues.......................... $ 649 $16,412 $48,834 $51,400 $ 69,626
Total operating costs and expenses (a)............ 1,692 13,541 38,801 94,414 54,516
------------------------------------------------------------------------
Operating profit (loss)........................... (1,043) 2,871 10,033 (43,014) 15,110
Net income (loss) before extraordinary loss....... (968) 509 (2,108) (47,080) (6,828)
Extraordinary loss from early extinguishment
of debt, net of taxes .......................... - - (1,384) - -
Net Income (loss) ................................ (968) 509 (3,492) (47,080) (6,828)
Dividends applicable to preferred shares.......... (617) (406) (875) (875) (4,509)
-------------------------------------------------------------------------
Income (loss) applicable to common shares......... $(1,585) $ 103 $(4,367) $(47,955) $(11,337)
-------------------------------------------------------------------------
Income (loss) per common share before
extraordinary item
Basic.......................................... $ (0.28) $ 0.01 $ (0.21) $ (2.26) $ (0.56)
Diluted........................................ $ (0.28) $ 0.01 $ (0.21) $ (2.26) $ (0.56)
Income (loss) per common share after
extraordinary item
Basic.......................................... $ (0.28) $ 0.01 $ (0.30) $ (2.26) $ (0.56)
Diluted........................................ $ (0.28) $ 0.01 $ (0.30) $ (2.26) $ (0.56)
Other Data:
EBITDA (b)........................................ $ (545) $ 6,166 $ 22,772 $ 22,112 $ 37,536
Capital expenditures (c).......................... $ 1,244 $41,471 $160,059 $ 70,187 $ 59,968
- --------
(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) EBITDA is defined as net 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.
(c) Capital expenditures include cash expended for acquisitions plus normal
additions to oil and natural gas properties and other fixed assets.
29
1995 1996 1997 1998 1999
--------- --------- ----------- ----------- ------------
Balance Sheet Data:
Working capital (deficiency)....................... $ (916) $ 2,279 $ 2,610 $ (723) $ (810)
Property, plant and equipment, net................. 36,405 73,648 221,259 228,436 265,195
Total assets....................................... 40,065 83,072 251,069 267,142 306,110
Total debt (a)..................................... 9,612 38,766 161,543 231,020 234,806
Stockholders' equity............................... $24,496 $35,154 $ 72,140 $ 20,992 $ 53,640
- -----------
(a) Consists of long-term debt, including current maturities of long-term
debt, and excluding production payment liabilities of $288 thousand,
$937 thousand, $743 thousand, $633 thousand and $460 thousand as of
December 31, 1995, 1996, 1997, 1998 and 1999, respectively. As of
December 31, 1999 and 1998, $41.8 million and $26 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.
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 5,766
Net Income (Loss).................................. (4,962) (2,340) 213 261
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)
1998
-----------------------------------------------------------------
First Second Third Fourth
-------------- -------------- ------------- ----------------
Revenues........................................... $ 12,753 $ 13,261 $ 13,580 $ 11,806
Depreciation, depletion and amortization........... 3,875 4,941 4,805 8,136
Write-down of oil and gas properties............... - - - 42,745
Net Operating Profit (Loss)........................ 1,295 1,260 891 (46,460)
Net Loss........................................... (1,747) (1,915) (2,272) (41,146)
Loss per common share, basic....................... $ (0.09) $ (0.10) $ (0.12) $ (1.96)
Loss per common share, diluted..................... $ (0.09) $ (0.10) $ (0.12) $ (1.96)
30
Item 7. Management Discussion and Analysis of Financial Condition and
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.
In April 1997, the Company purchased the Permian Basin Properties from
Burlington for a net purchase price of $133.8 million after purchase price
adjustments of $9.7 million. These properties consisted of approximately 1,852
producing oil and gas wells and associated acreage in west Texas and southeast
New Mexico. This acquisition substantially increased the Company's cash flow and
inventory of exploitation, development and exploration opportunities.
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 for $10.4 million pursuant to the tender offer and, together
with the Units it previously owned, became the owner of approximately 40% of the
total number of Units outstanding for an aggregate consideration of $10.4
million.
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. The net purchase price was approximately $25 million after certain
purchase price adjustments, including preferential rights exercised by third
parties and other customary adjustments. 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. To finance the Spirit 76
acquisition, Bluebird borrowed $26 million under a bridge loan facility with
several banks. The bridge loan was replaced on June 7, 1999 with permanent
financing from banks providing for a revolving credit facility of $75 million
with an initial borrowing base of $41.5 million, due June 7, 2002 with interest
rates based upon either "LIBOR" or "Base Rate" (Prime). The loan is non-recourse
to the Company. In addition to retiring the bridge loan, a portion of the
proceeds from the permanent financing was used to finance the acquisition of
properties from Vastar Resources, Inc. ("Vastar") discussed below.
On February 3, 1999, the Company sold $50 million of its Convertible
Preferred Stock 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 indebtedness.
On June 8, 1999, the Company acquired oil and gas reserves and related
assets from Vastar for a total purchase price of $32.5 million after purchase
price adjustments. The effective date of the acquisition was April 1, 1999. The
acquisition included Vastar's interest 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, the Company acquired 50% ownership interest in the
Madill Gas Processing Plant and associated gathering system from Dynegy
Midstream Services, L.P., a wholly-owned subsidiary of Dynegy, Inc. This modern
cryogenic plant includes 3,350 horsepower of high-speed compression and has
gas-processing capacity of approximately 18,000 Mcf/d. The facilities are
located in Marshall and Bryan counties, Oklahoma. The effective date of the
acquisition was November 1, 1999.
31
The Company uses the full cost method of accounting for its investment in
oil and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and gas reserves are capitalized
into a "full cost pool" as incurred, and properties in the pool are depleted and
charged to operations using the unit-of-production method based on the ratio of
current production to total proved oil and gas reserves. To the extent that such
capitalized costs (net of accumulated depreciation, depletion and amortization)
less deferred taxes exceed the SEC PV-10 of estimated future net cash flow from
Proved Reserves of oil and gas, and the lower of cost or fair value of unproved
properties after income tax effects, such excess costs are charged to
operations. Once incurred, a write-down of oil and gas properties is not
reversible at a later date even if oil or gas prices increase. Due primarily to
the severe decline in world crude oil and natural gas prices experienced in
1998, the Company recognized a non-cash impairment of oil and gas properties of
$42.7 million at December 31, 1998 pursuant to the ceiling limitation required
by the full cost method of accounting, using certain improvements in pricing
experienced after the end of the period. Without the benefit of improvements in
pricing subsequent to December 31, 1998, the Company would have incurred an
impairment of $81.2 million. The Company's SEC PV-10 property valuation at
December 31, 1999 exceeded the capitalized cost at that date. Significant
downward revisions of quantity estimates or declines in oil and gas prices which
are not offset by other factors could possibly result in write-down for
impairment of oil and gas properties in the future.
Results of Operations For the Years Ended 1999 and 1998
As discussed above, the Company acquired the Spirit 76 Properties in
December 1998, the Vastar properties in June 1999 and the Madill Gas Plant in
December 1999. Unless otherwise stated, the increases in the 1999 period over
the 1998 period were substantially a result of these acquisitions and the
increases in daily oil and gas production associated with the Company's
successful drilling operations.
Oil and gas sales were $60.7 million in 1999, a 39% increase over 1998
sales of $43.6 million. In 1999, the Company sold 1,307 MBbl of oil and 19,026
MMcf of gas which represents a 15% increase in oil and a 35% increase in gas
volume over the prior year. The price received for oil was $15.01 per Bbl and
for gas was $2.16 per Mcf in 1999, representing an 18% increase in oil price and
a 7% increase in gas price. Oil and gas production lifting costs increased 8% to
$15.4 million in 1999 from 1998. The gross operating margin from oil and gas
production was $37.1 million in 1999, a 62% increase over 1998. On an equivalent
unit basis, the gross margin was $1.39 per Mcfe in 1999 versus $1.06 in 1998, a
31% increase. The sales price per Mcfe was $2.26 in 1999 versus $2.05 in 1998, a
10% increase. Production lifting costs decreased 16% to $0.57 per Mcfe in 1999
from $0.68 per Mcfe in 1998. Production tax and other costs decreased 3% to
$0.30 per Mcfe in 1999 from $0.31 per Mcfe in 1998. Total equivalent units sold
increased 28% to 26.9 Bcfe in 1999 from 21.0 Bcfe in 1998.
Gas gathering, marketing, and processing revenues were $8.2 million in
1999, an 18% increase from 1998. Gross operating margin was $2.3 million in 1999
versus $1.2 million in 1998, an 92% increase. Total gathering system throughput
decreased 11% to 18.5 MMcf per day in 1999 compared with 20.8 MMcf per day in
1998, principally due to the sale of a gathering system. Gas plant processing
throughput was 21.5 MMcf per day in 1999 versus 15.7 MMcf per day in 1998, a 37%
increase due to the Vastar and Madill acquisitions. Gross operating margin from
gathering operations was $0.14 per Mcf of throughput in 1999 versus $0.11 per
Mcf in 1998, a 27% increase. The gross operating margin from gas processing was
$0.16 per Mcf of throughput in 1999 versus $0.07 per Mcf in 1998, a 129%
increase resulting from substantially improved processing economics.
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.
Depreciation and depletion expense increased 1% to $22.1 million in 1999
from $21.8 million in 1998. Depletion expense on oil and gas production in 1999
was $21.2 million, or $.79 per Mcfe, versus $20.9 million, or $1.00 per Mcfe in
1998, principally due to the write-down of the value of its oil and gas full
cost pool by $42.7 million in 1998 versus none in 1999. This write-down was the
result of the low oil and gas prices experienced by all producers
32
in December 1998. Without the benefit of improvements in pricing subsequent to
December 31, 1998, the Company 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 the Company's future depletion rates. The Company had a gain
on sale of assets of $272 thousand in 1999, principally from the sale of a gas
gathering system, versus a loss on sale of assets of $52 thousand in 1998.
General and administrative expense decreased 2% to $2.9 million in 1999 from
$3.0 million in 1998.
Operating profit increased to $15.1 million in 1999 versus a loss of $43.0
million in 1998. Equity in earnings of affiliate, net of income tax, was a loss
of $103 thousand in 1999 versus a loss of $116 thousand reported in 1998. Other
income decreased 43% to $354 thousand in 1999 versus $624 thousand in 1998.
Interest expense increased to $22.1 million in 1999 from $18.2 million in 1998,
an increase of 21%, due to increased levels of borrowing under the Company's
revolving credit lines and an increase in floating interest rates. The Company
incurred a net loss before income tax and minority interest of $6.7 million in
1999, versus a net loss of $60.7 million in 1998. The Company provided for no
deferred income tax benefit in 1999 versus a deferred income tax benefit of
$13.7 million in 1998. The Company reported a net loss in 1999 of $6.8 million,
versus a net loss of $47.1 million in 1998.
The Company accrued $4.5 million in dividends on its preferred stock in
1999 compared to $875 thousand in 1998. The increase in dividends was due to the
sale of $50 million of its convertible preferred stock in 1999. The Company
reported net loss to common shareholders of $11.3 million, or $.56 per share in
1999 versus $48.0 million, or $2.26 per share in 1998.
Results of Operations For the Years Ended 1998 and 1997
As discussed above, the Company acquired the Permian Basin Properties in
April 1997, and its interest in TEL in March 1998. Unless otherwise stated, the
increases in the 1998 period over the 1997 period were substantially a result of
these acquisitions and the increases in daily oil and gas production associated
with the Company's successful drilling operations.
Oil and gas sales were $43.6 million in 1998, a 26% increase over sales of
$34.6 million in 1997. In 1998, the Company sold 1,140,762 Bbl of oil, a 55%
increase, and 14,119 MMcf of gas, a 47% increase over the prior year. The price
received for oil was $12.67 per Bbl and for gas was $2.02 per Mcf in 1998,
representing a 28% decrease in oil price from $17.70 per Bbl in 1997 and a 10%
decrease in gas price from $2.24 per Mcf in 1997. Oil and gas production lifting
costs increased 81% to $14.3 million in 1998 from $7.9 million in 1997. The
gross operating margin from oil and gas production was $22.9 million in 1998, a
5% increase over the gross operating margin of $21.8 million in 1997. On an
equivalent unit basis, the gross margin was $1.06 per Mcfe in 1998 versus $1.55
in 1997, a 32% decrease. The sales price per Mcfe was $2.05 in 1998 versus $2.46
in 1997, a 17% decrease. Production lifting costs increased 21% to $0.68 per
Mcfe in 1998 from $0.56 per Mcfe in 1997. Production tax and other costs
decreased 11% to $0.31 per Mcfe in 1998 from $0.35 per Mcfe in 1997. Total
equivalent units sold increased 49% to 21 Bcfe in 1998 from 14 Bcfe in 1997.
Gas gathering, marketing, and processing revenues were $7.0 million in the
1998 period, a 32% decrease from revenues of $10.3 million in 1997. Gross
operating margin was $1.2 million in 1998 versus $2.4 million in 1997, a 50%
decrease. Total gathering system throughput increased 1% to 20.8 MMcf per day in
1998 compared with 20.5 MMcf per day in 1997. Gas plant processing throughput
was 15.7 MMcf per day in 1998 versus 14.9 MMcf per day. Gross operating margin
from gathering operations was $0.11 per Mcf of throughput in 1998 versus $0.22
per Mcf in 1997, a 48% decrease. The gross operating margin from gas processing
was $0.07 per Mcf of throughput in 1998 versus $0.20 per Mcf in 1997, a 67%
decrease.
Revenues from oil field services and international sales were $881 thousand
in 1998, a 78% decrease from revenues of $4.0 million in 1997, principally due
to a decrease in sales in Hunter Butcher International, L.L.C. ("Hunter
Butcher") in the amount of $3.1 million. Operating costs were $467 thousand in
1998, a $3.3 million decrease over 1997, also principally due to Hunter Butcher.
The gross operating margin from these activities was $414,000 in 1998 versus
$223,000 in the 1997 period.
33
Depreciation and depletion expense increased 76% to $21.8 million in 1998
from $12.4 million in 1997 due to the acquisitions and to loss of reserves as a
result of year-end commodity prices. Depletion expense on oil and gas production
in 1998 was $20.9 million, or $1.00 per Mcfe, in 1998 versus $11.6 million, or
$0.82 per Mcfe in 1997. The Company wrote-down the value of its oil and gas full
cost pool by $42.7 million in 1998 versus none in 1997. This write-down was the
result of the low oil and gas prices experienced by all producers in December
1998. Without the benefit of improvements in pricing subsequent to December 31,
1998, the Company would have incurred an impairment of $81.2 million. While this
write-down is not recoverable if prices increase, it should have the effect of
lowering the Company's future depletion rates. General and administrative
expense increased 26% to $3.0 million in 1998 from $2.4 million in 1997, due to
increased staffing and other costs as a result of the acquisitions, increased
activity levels of the Company and the provision for doubtful accounts on a note
receivable.
Operating profit decreased $52.6 million to a loss of $43.0 million in 1998
versus a profit of $9.6 million in 1997. Equity in earnings of affiliate, net of
income tax, was a loss of $116,000 in 1998 versus a profit of $6,000 reported in
1997. Other income decreased 25% to $572,000 in 1998 versus $762,000 in 1997 due
to gain on sale of marketable securities in 1997 which did not occur in 1998.
Interest expense increased to $18.2 million in 1998 from $13.8 million in 1997,
an increase of 32%, due to increased levels of borrowing under the Company's
revolving credit lines and the Notes. The Company incurred a net loss before
income tax and minority interest of $60.7 million in 1998, versus a net loss of
$3.4 million in 1997, principally due to the write-down of oil and gas reserves,
lower oil and gas prices and higher interest expense. The Company provided for a
deferred income tax benefit of $13.7 million on this loss in 1998 versus a
deferred income tax benefit of $1.3 million in 1997. After recording a $37,000
minority interest loss in Hunter Butcher, the Company reported a net loss in
1998 before extraordinary item of $47.1 million, or $2.26 per common share,
versus a minority interest loss of $19,000 and a net loss before extraordinary
item of $2.1 million, or $0.21 per common share in 1997.
The Company realized an extraordinary loss of $1.4 million ($0.09 per
common share) as required under Accounting Principles Board ("APB") Statement
No. 26 and Statement of Financial Standards ("SFAS") No. 4, from the early
extinguishment of bank debt in 1997 and none in 1998. The net loss in 1997,
after the extraordinary charge, applicable to common shareholders was $4.4
million ($0.30 per common share) in 1997 compared to a net loss of $48.0 million
($2.26 per common share) in 1998. The Company accrued $875,000 in dividends on
its preferred stock in both years 1998 and 1997.
Liquidity and Capital Resources
The Company has three principal operating sources of cash: (i) sales of oil
and gas, (ii) revenues from gas gathering, processing, and marketing, and (iii)
revenues from petroleum management and consulting services. The Company's cash
flow is highly dependent upon oil and gas prices. Decreases in the market price
of oil and gas could result in reductions of both cash flow and the borrowing
base under the Company's Credit Facility, which would result in decreased funds
available, including funds for capital expenditures.
In September 1998, the Company announced a stock repurchase program of up
to one million shares at a cost not to exceed $4 million. At December 31, 1998,
the Company had repurchased 625,600 shares for approximately $1.9 million. In
February 1999, the program was revised to remove the share limitation discussed
above. In 1999, the Company has purchased an additional 601,472 shares for
approximately $1.7 million.
In December 1998, the Company's 100% owned subsidiary, Bluebird, acquired
for approximately $25 million, certain natural gas reserves and related assets
from Spirit 76. Additionally, the Company capitalized Bluebird with 1,840,271
units of TEL Offshore Trust. To finance the Spirit 76 acquisition, Bluebird
borrowed $26 million under a bridge loan facility with several banks. The bridge
loan was replaced on June 7, 1999 with permanent financing from banks providing
for a revolving credit facility of $75 million with an initial borrowing base of
$41.5 million, due three years from the date of closing with interest rates
based upon either "LIBOR" or "Base Rate" (Prime). The loan is non-recourse to
the Company. In addition to retiring the bridge loan, a portion of the proceeds
from the permanent financing was used to finance the acquisition of properties
from Vastar discussed below.
34
In December 1998, the Company announced a letter of intent for a strategic
alliance with ONEOK Resources Company, to include the purchase by this company
of $50 million of the Company's Convertible Preferred Stock. In February 1999,
this transaction was consummated. 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 beginning August of
1999 at the rate of 8% per annum and are cumulative. The net proceeds of $46.3
million received from the sale of Preferred Stock was used to repay senior bank
indebtedness.
On June 8, 1999, the Company acquired oil and gas reserves and related
assets from Vastar for a total purchase price of $32.5 million after purchase
price adjustments. The effective date of the acquisition was April 1, 1999. The
acquisition included Vastar's interest 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, the Company, through its wholly-owned subsidiary
Bluebird, acquired 50% ownership interest in the Madill Gas Processing Plant and
associated gathering system from Dynegy Midstream Services, L.P., a wholly-owned
subsidiary of Dynegy, Inc. This modern cryogenic plant includes 3,350 horsepower
of high-speed compression and has gas-processing capacity of approximately
18,000 Mcf/d. The facilities are located in Marshall and Bryan counties,
Oklahoma. The effective date of the acquisition was November 1, 1999.
In connection with the Madill Gas Plant acquisition, Bluebird's banks
increased the borrowing base under the credit agreement to $45.0 million
effective November 30, 1999, subject to a provision to automatically reduce the
borrowing base to $41.5 million on March 31, 2000, with further reductions to
the borrowing base of $2.0 million to occur on June 30, 2000 and each subsequent
quarter-end. Effective March 27, 2000, the banks suspended the various
requirements of the November 30, 1999 adjustment to the borrowing base and
established a current borrowing base for Bluebird of $43.5 million. The banks
agreed to redetermine the borrowing base and the need to reimplement the other
requirements of the November 30, 1999 adjustment upon the earlier of May 15,
2000 or the consummation or termination of a proposed sale of oil and gas
properties. The Company believes that this agreement, along with cash flow from
operations, provides Bluebird with sufficient liquidity to meet interest
payments as well as to carry out its capital spending plans in the year 2000.
The Company's borrowing base under its revolving credit line with banks was
$60,000,000 at December 31, 1999, providing $7,000,000 of additional borrowing
capacity at that date. The Company believes that this availability, along with
cash flow from operations, is sufficient to meet interest and dividend
requirements in 2000 as well as to carry out its capital spending needs.
For 1999, the Company had a net decrease in cash of $3.3 million. The
Company's operating activities provided net cash of $17.3 million. The Company
used $59.2 million in investing activities, principally for additions to
property and equipment. Financing activities provided $38.6 million of cash,
principally from the aggregate proceeds from the issuance of preferred stock of
$46.3 million. The Company also paid $4.2 million in cash dividends on preferred
stock.
For 1998, the Company had a net increase in cash of $1.8 million. The
Company's operating activities provided net cash of $13.7 million, principally
from operating income before depreciation, depletion, write-down of oil and gas
properties and deferred tax benefit, as well as a reduction in accounts
receivable and an increase in accounts payable. The Company used $75.4 million
in investing activities for additions to property and equipment and other
investments. Cash flow from financing activities were $63.5 million, consisting
of proceeds from issuance of long-term debt of $80 million, the payment of
principal on long and short-term debt of $13.3 million, the purchase of treasury
stock for $1.9 million and other uses, including the payment of $875 thousand in
dividends on preferred stock.
For 1997, the Company had a net increase in cash of $1.3 million. The
Company's operating activities provided net cash of $5.7 million, principally
from operating income before depreciation, depletion, and deferred taxes,
reduced by a net increase in accounts receivable over accounts payable. The
Company used $168.3 million in investing activities, principally for additions
to property and equipment of $160.1 million. Financing activities provided
$164.0 million of cash, principally from the aggregate proceeds from the
issuance of long-term debt of $352.5 million, less
35
principal payments of $229.9 million on this debt, as well as proceeds from
issuance of common stock of $41.7 million and proceeds from short-term notes
payable of $2.7 million. The Company also paid $678,000 in dividends on
preferred stock.
Capital Requirements
For fiscal 2000, the Company has budgeted approximately $25 million for
development and exploration activities, including approximately $15 million for
participation in exploration and development projects in the shallow water area
of the Gulf of Mexico. 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.
On June 8, 1999, the Company's borrowing base under its revolving credit
line was reduced from $65 million to $60 million as a result of the December 31,
1998 reserve engineering report.
Based upon the Company's anticipated level of operations, the Company
believes that cash flow from operations together with the availability under the
Credit Facility (approximately $7.0 million available as of December 31, 1999)
will be adequate to meet its anticipated requirements for working capital,
capital expenditures and scheduled interest and dividend payments for the
foreseeable future.
In addition, the Company's wholly-owned subsidiary, Bluebird, has
availability under its own credit facility (non-recourse to the Company) of
approximately $3.2 million at December 31, 1999 after the borrowing base
increased to $45.0 million on November 30, 1999. However, this increase was
subject to a provision to automatically reduce the borrowing base to $41.5
million on March 31, 2000, with further reductions to the borrowing base of $2.0
million to occur on June 30, 2000 and each subsequent quarter-end. Effective
March 27, 2000, the banks suspended the various requirements of the November 30,
1999 adjustment to the borrowing base and established a current borrowing base
for Bluebird of $43.5 million. The banks agreed to redetermine the borrowing
base and the need to reimplement the other requirements of the November 30, 1999
adjustment upon the earlier of May 15, 2000 or the consummation or termination
of a proposed sale of oil and gas properties. The Company believes that this
agreement, along with cash flow from operations, provides Bluebird with
sufficient liquidity to meet interest payments as well as to carry out its
capital spending plans in the year 2000.
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.
Inflation and Changes in Prices
During 1999, the Company experienced an increase in prices for oil (18%)
and for natural gas (7%) 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.
36
The Company markets oil and gas for its own account, which exposes the
Company to the attendant commodities risk. A substantial 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.
Hedging Activity
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 natural gas
prices. At December 31, 1999, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
--------------- --------------------- --------------------- ---------------------
Oil
- ------
Swap........... 30,000 Bbl Jan 00 - Dec 00 $17.60
Collar......... 30,000 Bbl Jan 00 - Mar 00 Floor - $18.00
Cap - $22.65
Collar......... 30,000 Bbl Jan 00 - Mar 00 Floor - $18.00
Cap - $23.87
Collar......... 30,000 Bbl Apr 00 - Jun 00 Floor - $18.00
Cap - $24.50
Collar......... 30,000 Bbl Apr 00 - Jun 00 Floor - $18.00
Cap - $26.00
Collar......... 30,000 Bbl Jul 00 - Sep 00 Floor - $18.00
Cap - $24.00
Collar......... 30,000 Bbl Jul 00 - Sep 00 Floor - $18.00
Cap - $24.65
Gas
- ------
Collar......... 300,000 MMBtu Jan 00 - Mar 00 Floor - $ 2.00
Cap - $ 2.32
Collar ........ 300,000 MMBtu Apr 00 - Oct 00 Floor - $ 1.80
Cap - $ 2.25
Swap........... 100,000 MMBtu Jan 00 - Mar 00 $ 2.86
Collar ........ 100,000 MMBtu Jan 00 - Mar 00 Floor - $ 2.62
Cap - $ 3.82
Purchased
Call........... 100,000 MMBtu Feb 00 - Mar 00 $ 2.86
Net gains or losses related to derivative transactions for the years ended
December 31, 1999, 1998 and 1997 were $(3,232,000), $2,739,000 and $(1,537,000),
respectively. At December 31, 1999, the unrealized loss from derivative
transactions was $3,812,000.
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 next twelve months.
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
Pay Fixed/Receive Variable $50,000,000 06/01/00 9.16% fixed LIBOR + 3.34%
The pay variable/receive fixed swap has an early termination provision
granting the counterparty the right to terminate the swap on June 1, 2000, in
exchange for a fee payment to the Company of $125,000. As a result of these two
swaps, the Company saved approximately $209,000 in interest expense during the
year ended December 31, 1999. The unrealized savings in interest expense at
December 31, 1999 calculated through May 31, 2000 was approximately $175,000.
Thereafter, the economic impact depends on whether or not LIBOR rates increase
significantly.
Year 2000 Compliance
Beginning in 1998, the Company was involved in a program to be "Year 2000"
ready. The program involved reviews of major business, financial and other
information systems, including equipment with embedded microprocessors,
development of specific plans for modification or replacement of date-sensitive
software or microprocessors, execution of such plans and the testing of such
systems to ensure their "Year 2000" readiness. Included within the scope of the
program were contacts with key suppliers and customers to determine their "Year
2000" readiness in order to ensure a steady flow of goods and services to the
Company and continuity with respect to customer service. As a result of this
program, there were no significant occurrences of Year 2000-related failures.
Additionally, the Company does not anticipate that any significant subsequent
events will occur.
Recently Issued Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, which established a new model for accounting
for derivatives and hedging activities. SFAS No. 133, which will be effective
for the Company's fiscal year 2001, requires that all derivatives be recognized
in the balance sheet as either assets or liabilities and measured at fair value.
The Statement also requires that changes in fair value be reported in earnings
unless specific hedge accounting criteria are met. The Company is currently
evaluating the effect of the adoption of the Statement on its consolidated
financial position and results of operations.
Item 7A. Qualitative and Quantitative Disclosure About Market Risk
Energy swap agreements. The Company engages in futures contracts with
certain of its production through various contracts ("Swap Agreements"). The
Company considers these contracts to be hedging activities and, as such, monthly
settlements on these contracts are reflected in oil and gas sales. In order to
consider these contracts as hedges, (i) the Company must designate the contract
as a hedge of future production and (ii) the contract must reduce the Company's
exposure to the risk of changes in prices. Changes in the market value of
contracts treated as hedges are not recognized in income until the hedged item
is also recognized in income. If the above criteria are not met, the Company
will record the market value of the contract at the end of the month and
recognize a related gain or loss.
38
Proceeds received or paid relating to terminated contracts or contracts that
have been sold are amortized over the original contract period and reflected in
oil and gas sales. The Company enters into hedging activities in order to secure
an acceptable future price relating to a portion of future production. 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, 1999, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
-------------------- ---------------------- ----------------------- -------------------
Oil
- ------
Swap................ 30,000 Bbl Jan 00 - Dec 00 $17.60
Collar.............. 30,000 Bbl Jan 00 - Mar 00 Floor - $18.00
Cap - $22.65
Collar.............. 30,000 Bbl Jan 00 - Mar 00 Floor - $18.00
Cap - $23.87
Collar.............. 30,000 Bbl Apr 00 - Jun 00 Floor - $18.00
Cap - $24.50
Collar.............. 30,000 Bbl Apr 00 - Jun 00 Floor - $18.00
Cap - $26.00
Collar.............. 30,000 Bbl Jul 00 - Sep 00 Floor - $18.00
Cap - $24.00
Collar.............. 30,000 Bbl Jul 00 - Sep 00 Floor - $18.00
Cap - $24.65
Gas
- ------
Collar.............. 300,000 MMBtu Jan 00 - Mar 00 Floor - $2.00
Cap - $2.32
Collar ............. 300,000 MMBtu Apr 00 - Oct 00 Floor - $1.80
Cap - $2.25
Swap................ 100,000 MMBtu Jan 00 - Mar 00 $2.86
Collar ............. 100,000 MMBtu Jan 00 - Mar 00 Floor - $2.62
Cap - $3.82
Purchased Call...... 100,000 MMBtu Feb 00 - Mar 00 $2.86
39
Based on future market prices at December 31, 1999, the fair value of the
open contracts was $(3,812,000). If future market prices were to increase 10%
from those in effect at December 31, 1999, the fair value of the open contracts
would be $(6,360,000). If future market prices were to decline 10% from those in
effect at December 31, 1999, the fair value of the open contracts would be
$(1,755,000).
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.
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.
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
Pay Fixed/Receive Variable $50,000,000 06/01/00 9.16% fixed LIBOR + 3.34%
The pay variable/receive fixed swap has an early termination provision
granting the counterparty the right to terminate the swap on June 1, 2000, in
exchange for a fee payment to the Company of $125,000. As a result of these two
swaps, the Company saved approximately $209,000 in interest expense during the
year ended December 31, 1999. The unrealized savings in interest expense at
December 31, 1999 calculated through May 31, 2000 was approximately $175,000.
Thereafter, the economic impact depends on whether or not LIBOR rates increase
significantly.
Based on future market prices at December 31, 1999, the fair value of the
open contracts was $(536,000). If future market rates were to increase 10% from
those in effect at December 31, 1999 the fair value of the contracts would be
$(984,000). If future market rates were to decline 10% from those in effect at
December 31, 1999 the fair value of the open contracts would be $(88,000).
[Rest of page intentionally left blank]
40
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.
Expected Maturity Dates
(in thousands) 2000 2001 2002 2003 2004-2006 2007 Total Fair Value
-------- -------- --------- ------- --------- -------- --------- ---------
Variable Rate Debt:
Bank Debt with Recourse (a)... $ - $ - $ - $53,000 $ - $ - $ 53,000 $ 53,000
Bank Debt without Recourse (b) $ - $ - $41,800 $ - $ - $ - $ 41,800 $ 41,800
Fixed Rate Debt:
Senior Notes (c).............. $ - $ - $ - $ - $ - $140,000 $140,000 $119,000
Other (d)..................... $ 6 $ - $ - $ - $ - $ - $ 6 $ 6
- ------------
(a) The average interest rate on the bank debt with recourse is 8.15%.
(b) The average interest rate on the bank debt without recourse is 9.23%.
(c) The interest rate on the senior notes is a fixed 10%.
(d) The other notes are non-interest bearing.
[Rest of page intentionally left blank]
41
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, 1999 and 1998.......F-2
Consolidated Statements of Operations and Comprehensive Income
for the Years Ended December 31, 1999, 1998 and 1997........F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1999, 1998 and 1997...........F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1999, 1998 and 1997.................F-5
Notes to Consolidated Financial Statements..............................F-6
Supplemental Information (Unaudited)...................................F-28
42
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, 1999, and 1998, and
the related statements of operations and comprehensive income, stockholders'
equity, and cash flows for the three years ended December 31, 1999. 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, 1999 and 1998, and
the results of their operations and its cash flows for the three years ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States of America.
Deloitte & Touche LLP
Dallas, Texas
March 28, 2000
F-1
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
December 31, December 31,
1999 1998
-----------------------------------------
ASSETS
Current Assets
Cash and cash equivalents................................................ $ 1,565 $ 4,853
Restricted cash ......................................................... 2,145 459
Accounts receivable
Trade, net of allowance of $166 for 1999 and 1998................... 10,203 5,686
Due from affiliates................................................. 48 310
Notes receivable from affiliate.......................................... 902 747
Current portion of long-term notes receivable, net of allowance of $790
for 1999 and 1998....................................... 57 57
Prepaid and other........................................................ 1,296 1,577
------------------------------------------
Total Current Assets............................................... 16,216 13,689
------------------------------------------
Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved........................................................... 3,567 1,655
Proved............................................................. 349,510 296,545
Pipelines................................................................ 12,462 9,131
Other property........................................................... 1,964 1,554
------------------------------------------
Total Property, Plant and Equipment...................................... 367,503 308,885
Accumulated depreciation, depletion, amortization and impairment... (102,308) (80,449)
------------------------------------------
Net Property, Plant and Equipment........................................ 265,195 228,436
------------------------------------------
Other Assets
Deposits and other assets................................................ 5,698 6,644
Investment in unconsolidated affiliate................................... 4,163 4,266
Deferred tax asset ...................................................... 13,351 13,351
Long-term notes receivable, net of imputed interest...................... 1,487 756
------------------------------------------
$ 306,110 $267,142
Total Assets ------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities................................... $ 15,111 $ 11,821
Dividends payable........................................................ 552 219
Suspended revenue payable................................................ 1,357 359
Current maturities of long-term debt, with recourse...................... 6 13
Notes payable............................................................ - 2,000
------------------------------------------
Total Current Liabilities.......................................... 17,026 14,412
------------------------------------------
Long-Term Liabilities
Long-term debt, with recourse, less current maturities................... 193,000 205,007
Long-term debt, non recourse, less current maturities.................... 41,800 26,000
Production payment liability............................................. 460 633
Minority interest........................................................ 184 98
Commitments and Contingencies (Notes 10 and 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
issued and outstanding, liquidation amount $10,000,000............. 1 1
50,000 designated as 1999 Series A 8% Convertible; 50,000 and none
issued and outstanding, respectively, liquidation amount $50,000,000 - -
Common Stock - $.002 par value; 100,000,000 shares authorized,
21,738,320 shares issued............................................ 43 43
Additional paid-in capital............................................... 121,815 80,000
Accumulated other comprehensive (loss)................................... (2,046) (1,429)
Accumulated deficit...................................................... (62,542) (55,714)
----------------------------------------
57,271 22,901
Treasury stock, at cost (1,512,719 and 1,054,507 shares of common stock,
respectively)................................................................. (3,631) (1,909)
----------------------------------------
Total Stockholders' Equity.................................................... 53,640 20,992
----------------------------------------
Total Liabilities and Stockholders' Equity.................................... $ 306,110 $267,142
----------------------------------------
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,
----------------------------------------------------------------------
1999 1998 1997
----------------------------------------------------------------------
Operating Revenues:
Oil and gas sales.......................................... $ 60,673 $ 43,565 $ 34,569
Gas gathering, marketing and processing.................... 8,185 6,954 10,297
Oil field services and international sales................. 768 881 3,968
----------------------------------------------------------------------
Total Operating Revenues............................. 69,626 51,400 48,834
----------------------------------------------------------------------
Operating Costs and Expenses:
Oil and gas production lifting costs....................... 15,431 14,265 7,901
Production taxes and other costs........................... 8,144 6,417 4,911
Gas gathering, marketing and processing.................... 5,870 5,750 7,909
Oil field services and international sales................. 350 467 3,745
Depreciation, depletion and amortization................... 22,072 21,757 12,363
Provision for non-cash impairment of oil and gas reserves.. - 42,745 -
(Gains) losses on sale of assets........................... (272) 52 (386)
General and administrative................................. 2,921 2,961 2,358
----------------------------------------------------------------------
Total Operating Costs and Expenses................... 54,516 94,414 38,801
----------------------------------------------------------------------
Operating Profit (Loss)....................................... 15,110 (43,014) 10,033
Equity in earnings (loss) of affiliate, net of income tax.. (103) (116) 6
Other income............................................... 354 624 376
Interest expense........................................... (22,103) (18,207) (13,788)
----------------------------------------------------------------------
Net Loss before income tax and minority interest.............. (6,742) (60,713) (3,373)
Benefit for deferred income tax............................ - 13,670 1,284
----------------------------------------------------------------------
Net Loss before minority interest............................. (6,742) (47,043) (2,089)
Minority interest in subsidiary (loss)..................... (86) (37) (19)
----------------------------------------------------------------------
Net Loss Before Extraordinary Loss............................ (6,828) (47,080) (2,108)
Extraordinary Loss From Early Extinguishment of Debt, net of
tax benefit of $848........................................... - - (1,384)
----------------------------------------------------------------------
Net Loss...................................................... (6,828) (47,080) (3,492)
Dividends Applicable to Preferred Stock.................... (4,509) (875) (875)
----------------------------------------------------------------------
Loss Applicable to Common Shares.............................. $ (11,337) $ (47,955) $ (4,367)
----------------------------------------------------------------------
Net Loss...................................................... $ (6,828) $ (47,080) $ (3,492)
Other Comprehensive Loss, net of tax
Sale of Investment Shares.................................. - - (51)
Unrealized Loss on Investments............................. (617) (1,429) -
----------------------------------------------------------------------
Comprehensive Loss............................................ $ (7,445) $ (48,509) $ (3,543)
----------------------------------------------------------------------
Loss per Common Share - Basic
Before Extraordinary Loss.................................. $ (0.56) $ (2.26) $ (0.21)
Extraordinary Loss......................................... - - (0.09)
----------------------------------------------------------------------
After Extraordinary Loss................................... $ (0.56) $ (2.26) $ (0.30)
----------------------------------------------------------------------
Loss per Common Share - Diluted
Before Extraordinary Loss.................................. $ (0.56) $ (2.26) $ (0.21)
Extraordinary Loss......................................... - - (0.09)
----------------------------------------------------------------------
After Extraordinary Loss................................... $ (0.56) $ (2.26) $ (0.30)
----------------------------------------------------------------------
Common Shares Used in Per Share Calculation
Basic ..................................................... 20,172,062 21,189,516 14,535,805
----------------------------------------------------------------------
Diluted ................................................... 20,172,062 21,189,516 14,535,805
----------------------------------------------------------------------
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, 1999, 1998 and 1997
(dollars in thousands)
Preferred Stock Common Stock Treasury Stock
Shares Amount Shares Amount Shares Amount
---------------------------------------------------------------------------------
Balance at December 31, 1996....................... 1,080,000 $ 1 14,252,822 $ 29 (544,495) $ (1)
Common stock contributed to 401(k) plan.......... 13,556 -
Exercise of employees' common stock options...... 89,242 -
Issuance of common stock for services............ 1,000 -
Issuance of warrants for services................
Issuance and costs from exercise of warrants..... 896,256 2 100,000 -
Issuance of common stock to acquire oil and gas
properties................................. 16,306 -
Issuance of common stock, net of offering costs.. 6,500,000 12
Return of common stock held as collateral to
treasury............................... (125,000) -
Costs associated with issuance of preferred stock
Dividends declared on preferred stock............
Net loss.........................................
Sale of investment shares........................
---------------------------------------------------------------------------------
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 .................
---------------------------------------------------------------------------------
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 -
Purchase of treasury stock ...................... (601,472) (1,722)
Dividends declared on preferred stock ...........
Net loss ........................................
Unrealized (loss) on investment .................
---------------------------------------------------------------------------------
Balance at December 31, 1999....................... 1,130,000 $ 1 21,738,320 $ 43 (1,512,719) $(3,631)
---------------------------------------------------------------------------------
Additional Accumulated Other
Paid-In Comprehensive Accumulated
Capital Income (Loss) Deficit
---------------------------------------------------------------------------------
Balance at December 31, 1996....................... $ 40,216 $ 51 $ (5,142)
Common stock contributed to 401(k) plan.......... 59
Exercise of employees' common stock options...... 269
Issuance of common stock for services............ 4
Issuance of warrants for services................ 34
Issuance and costs from exercise of warrants..... 5,277
Issuance of common stock to acquire oil and gas
properties................................. 90
Issuance of common stock, net of offering costs.. 36,161
Return of common stock held as collateral to
treasury...............................
Costs associated with issuance of preferred stock (505)
Dividends declared on preferred stock............ (875)
Net loss......................................... (3,492)
Sale of investment shares........................ (51)
---------------------------------------------------------------------------------
Balance at December 31, 1997 ...................... $ 80,731 $ - $ (8,634)
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 ................. (1,429)
---------------------------------------------------------------------------------
Balance at December 31, 1998....................... $ 80,000 $ (1,429) $ (55,714)
---------------------------------------------------------------------------------
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
Purchase of treasury stock ......................
Dividends declared on preferred stock ........... (4,509)
Net loss ........................................ (6,828)
Unrealized (loss) on investment ................. (617)
---------------------------------------------------------------------------------
Balance at December 31, 1999....................... $ 121,815 $ (2,046) $ (62,542)
---------------------------------------------------------------------------------
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,
-------------------------------------------------
1999 1998 1997
-------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net Loss........................................................................ $ (6,828) $ (47,080) $ (3,492)
Adjustments to reconcile net loss to cash provided by operating activities
Extraordinary loss........................................................... - - 1,384
Depreciation, depletion and amortization..................................... 22,072 21,757 12,363
Write-down of oil and gas properties ........................................ - 42,745 -
Amortization of financing fees............................................... 2,091 793 508
Increase in reserve for doubtful accounts.................................... - 591 322
Deferred income taxes........................................................ - (13,670) (1,284)
Equity in unconsolidated affiliate........................................... 103 116 (6)
Minority interest............................................................ 86 37 19
(Gain) Loss on sale of assets................................................ (272) 52 (386)
Other........................................................................ - (83) 93
Changes in certain assets and liabilities
Accounts and notes receivable............................................. (4,660) 6,859 (8,295)
Other current assets...................................................... 281 (278) (1,247)
Accounts payable and accrued liabilities.................................. 4,411 1,849 5,673
-------------------------------------------------
Net Cash Provided By Operating Activities....................................... 17,284 13,688 5,652
-------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets.................................................... 1,499 359 593
Additions to property and equipment............................................. (59,968) (70,187) (160,059)
Increase in deposits and other assets........................................... - (3,878) (6,159)
Loan made for promissory note receivable........................................ (731) (1,691) (237)
Payments received on promissory note receivable ................................ - 28 256
Other long-term investments..................................................... - - (361)
Investment in unconsolidated affiliate.......................................... - - (2,362)
-------------------------------------------------
Net Cash Used In Investing Activities........................................... (59,200) (75,369) (168,329)
-------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of long-term debt and production payment............. 106,800 80,000 352,500
Fees paid related to financing activities....................................... (1,603) - (1,800)
Proceeds from short-term notes payable.......................................... - - 2,699
Payments of principal on long-term debt and production payment.................. (103,186) (10,633) (229,917)
Payment of short-term notes payable ............................................ (2,000) (2,699) -
Payment of fees on issuance of warrants and preferred stock..................... (133) - (505)
Proceeds from issuance of common and preferred stock, net of offering costs..... 46,334 78 41,721
Purchase of treasury stock ..................................................... (1,722) (1,908) -
Increase in segregated funds for payment of notes payable ...................... (1,686) (459) -
Dividends paid.................................................................. (4,176) (875) (678)
-------------------------------------------------
Net Cash Provided By Financing Activities....................................... 38,628 63,504 164,020
-------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................... (3,288) 1,823 1,343
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD................................... 4,853 3,030 1,687
-------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD......................................... $ 1,565 $ 4,853 $ 3,030
-------------------------------------------------
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 is 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, Hunter Gas Gathering, Inc.,
Inesco Corporation, Magnum Hunter Production, Inc., Midland Hunter Petroleum
Limited Liability Company, SPL Gas Marketing, Inc. and its 51% owned subsidiary,
Hunter Butcher International Limited Liability Company. The Company consolidates
on a pro rata basis its 40% 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 inconsequential
subsidiaries), 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 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 the Company or its other subsidiaries or
affiliates.
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, 1999 and 1998, the Company's available for sale securities
were classified as non-current assets and included in deposits and other assets.
At December 31, 1999, the securities had an amortized cost basis of $2,954,000,
gross unrealized loss reported in other comprehensive income of $2,921,000
($2,046,000 net of income tax benefit) and fair market value of $283,000. At
December 31, 1998, the securities had an amortized cost basis of $2,954,000,
gross unrealized loss reported in other comprehensive income of $2,304,000
($1,429,000 net of income tax benefit) and a fair market value of $650,000.
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
The Company follows the full-cost method of accounting for oil and gas
properties, as prescribed by the Securities and Exchange Commission ("SEC").
Accordingly, all costs associated with acquisition, exploration and development
of oil and gas reserves, including directly related overhead costs, are
capitalized.
All capitalized costs of oil and gas properties, including the estimated
future costs to develop proved reserves, are amortized on the unit-of-production
method using estimates of proved reserves. Cost 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 periodically and any provision for impairment is
transferred to the full-cost amortization base. Sales of oil and gas properties
are credited to the full-cost pool unless the sale would have a significant
effect on the amortization rate. Abandonments of properties are accounted for as
adjustments to capitalized costs with no loss recognized. The Company's unproved
properties excluded from the amortization base were $3,567,000 and $1,655,000 at
December 31, 1999 and 1998, respectively.
The net capitalized costs are subject to a "ceiling test," which generally
limits such costs 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. 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 is 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.
F-7
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Derivative Instruments
The Company frequently enters into swaps, futures, options and other
derivative contracts to hedge the impact of market fluctuations in gas and oil
prices on anticipated future gas and oil production. The Company defers the
impact of changes in the market value of the contracts that serve as hedges
until the related transaction is completed.
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.
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.
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.
Changes in Accounting Standards
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities,"
is effective for fiscal years beginning after June 15, 2000. This statement
establishes accounting and reporting standards for derivative instruments and
for hedging activities. Management is currently evaluating the effect of
adopting SFAS 133 on the Company's consolidated financial statements.
Income or Loss Per Common Share
Income or loss per common share is based on the weighted average number of
shares of common stock outstanding. Convertible securities and warrants were
anti-dilutive due to net losses for December 31, 1999, 1998 and 1997 and were
not included in the calculation of income or loss per common share.
F-8
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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.
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.
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:
1999 1998
------------------------------------
(Unaudited)
------------------------------------
Revenue...................................... $ 73,104,000 $ 77,181,000
Net Income (Loss) Applicable to Common Stock. (12,024,000) (44,911,000)
Net Income (Loss) Per Common Share
Basic..................................... $ (0.60) $ (2.12)
Diluted.................................... $ (0.60) $ (2.12)
F-9
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 1999 and 1998 was $50,016.
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.
At December 31, 1999, the Company's note receivable from the Magnum Hunter
Employee Stock Ownership Plan (ESOP) was $1,638,287 (of which $1,487,504 is
classified as long-term.) 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. At December 31, 1998 the note balance was $878,997 (of which
$756,000 was classified as long-term.)
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.
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 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.
Subsequent to this date, $225,000 was repaid on the loan leaving a principal
balance of $146,860.
F-10
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 5 -- DEBT
Notes Payable and Long-term debt at December 31, 1999 and 1998 consisted of
the following:
1999 1998
----------------------------------------------
Notes Payable:
Note payable, secured by stock in NGTS, LLC., due February 1, 1999,
interest payable at 9% quarterly beginning March 31, 1998................ $ - $ 2,000,000
----------------------------------------------
Total Notes Payable............................................... $ - $ 2,000,000
----------------------------------------------
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 8.15% at
December 31, 1999) (a)................................................... $ 53,000,000 $ 65,000,000
Note payable to bank collateralized by vehicle, payable in monthly installments
of $1,031 including interest at 8.5% through
February 1999............................................................ - 2,000
Other
Senior notes, unsecured, due June 1, 2007, interest at 10% payable
semi-annually on June 1 and December 1................................... 140,000,000 140,000,000
Notes payable, non-interest bearing and uncollateralized, payable in
monthly installments of $1,000 through July 1, 2000...................... 6,000 18,000
----------------------------------------------
Total Long-Term Debt, with recourse............................... $193,006,000 $ 205,020,000
Less Current Portion....................... 6,000 13,000
----------------------------------------------
Long-Term Debt, with recourse..................................... $193,000,000 $ 205,007,000
----------------------------------------------
Long-Term Debt, non recourse to the Company:
Banks
Note payable, collateralized by oil and gas property and 1,840,271 units of Tel
Offshore Trust, due April 15, 1999, interest at Prime + 2%
(Effective rate of 9.75% at December 31, 1998) (b) ..................... $ - $ 26,000,000
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 9.23% at December 31, 1999) (c).................. 41,800,000 -
----------------------------------------------
Total Long-Term Debt, non recourse................................ $ 41,800,000 $ 26,000,000
----------------------------------------------
F-11
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:
2000............................................. $ 6,000
2001............................................. -
2002............................................. 41,800,000
2003............................................. 53,000,000
2004 to 2006..................................... -
2007............................................. 140,000,000
------------------
Total................................... $ 234,806,000
------------------
(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
$60,000,000 at December 31, 1999. The level of the borrowing base is dependent
on the valuation of the assets pledged, primarily oil and gas reserve values.
During 1998, the termination date was extended by one year to April 30, 2003.
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, 1999, the amounts borrowed
at these rates were:
LIBOR + 2.0% (total of 8.15%)............................... $ 53,000,000
Base Rate (Prime) + .75% (total of 9.25%)................... -
------------------
Total................................................ $ 53,000,000
------------------
(b) The note payable was incurred by Bluebird Energy, Inc., the Company's
wholly-owned unrestricted subsidiary, in connection with the Spirit 76
acquisition. The maturity date of this bridge loan facility, as amended, was
April 15, 1999. The bridge loan is non-recourse to the Company. Bluebird secured
a commitment for permanent financing from a bank providing for a revolving
credit facility of $75 million. See item (c) below.
(c) 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
$45,000,000 at December 31, 1999. 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 November 30, 1999,
the line of credit was amended to provide that the borrowing base will decrease
to $41,500,000 on March 31, 2000 and thereafter the borrowing base will reduce
by $2,000,000 quarterly beginning June 30, 2000. Effective March 27, 2000 the
banks suspended this amendment and established a borrowing base of $43,500,000.
The banks agreed to redetermine the borrowing base and the need to reimplement
the amendment upon the earlier of May 15, 2000 or the consummation or
termination of a proposed sale of oil and gas properties. 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, 1999
the amounts borrowed at these rates were:
LIBOR + 2.75% (total of 9.23%).............................. $ 41,800,000
Base Rate (Prime) + 1.25% (total of 9.75%).................. -
------------------
Total................................................ $ 41,800,000
------------------
F-12
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 6 -- PRODUCTION PAYMENT LIABILITY
The Company has an obligation under a production payment conveyance. The
conveyance provides for a royalty payment equal to 50% of the monthly net
revenue proceeds received by the Company in certain oil and gas properties. The
balance owed under the conveyance bears interest at 15% per annum and is
non-recourse to the Company. The balance owed under this conveyance was $93,000
at December 31, 1998. During 1999, the Company sold a number of properties
covered by the conveyances and used the proceeds to repay the total balance due
at that time.
In November, 1996, the Company entered into a second production payment
conveyance with the same party. 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 $460,000 and $540,000 at December 31, 1999 and 1998,
respectively. The production payment bears interest at the rate of 13.5% per
annum and is non-recourse to the Company.
NOTE 7 -- INCOME TAXES
The Company accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes", which requires the recognition of a liability or
asset, net of a valuation allowance, for the deferred tax consequences of all
temporary differences between the tax bases and the reported amounts of assets
and liabilities, and for the future benefit of operating loss carryforwards. The
following is a reconciliation of income tax expense reported in the statement of
operations:
1999 1998 1997
-------------------------------------------------------------
Income tax expense (benefit) at statutory rates......... $ (2,352,000) $ (21,263,000) $ (1,153,000)
State tax expense (benefit)............................. (193,000) (1,747,000) (133,000)
Change in valuation allowance........................... 2,315,000 8,370,000 290,000
Other................................................... 230,000 - (288,000)
-------------------------------------------------------------
Tax expense (benefit)............................ $ - $ (14,640,000) $ (1,284,000)
-------------------------------------------------------------
The tax effects of significant temporary differences and carryforwards are
as follows:
December 31
---------------------------------------
1999 1998
---------------------------------------
Property and equipment, including intangible drilling costs........... $ - $ -
Total deferred tax liability................................. - -
Allowance for doubtful accounts....................................... 425,000 414,000
Reserves.............................................................. 33,000 33,000
Property and equipment, including intangible drilling costs........... 1,984,000 8,812,000
Depletion carryforwards............................................... 196,000 196,000
Operating loss and other carryforwards................................ 21,688,000 12,556,000
Total deferred tax assets.................................... 24,326,000 22,011,000
---------------------------------------
Valuation allowance................................................... (10,975,000) (8,660,000)
---------------------------------------
Net Deferred Tax Asset (Liability)........................... $13,351,000 $13,351,000
---------------------------------------
F-13
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, $876,000.
The Company and its subsidiaries have net operating loss carryforwards of
approximately $57,089,000 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 in connection with the Hunter Resources
acquisition on December 31, 1995. A second change is deemed to have occurred
February 3, 1999 in connection with the purchase of preferred stock by ONEOK
Resources Company. Approximately $1,992,000 of the net operating losses are
subject to limitation of $718,000 per year and $31,113,000 are subject to a
limitation of $7,850,000 per year. In addition, the Company has depletion
carryforwards of $517,000 with no expiration period. A valuation allowance
reduces deferred taxes based on the criteria set forth in SFAS 109.
NOTE 8 -- STOCKHOLDERS' EQUITY
Preferred Stock
Shares of preferred stock may be issued in such series, with such
designations, preferences, stated values, rights, qualifications or limitations
as determined solely by the Board of Directors. Of the 10,000,000 shares of
$.001 par value preferred stock the Company is authorized to issue, 216,000
shares have been designated as Series A Preferred Stock, 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 6, 1996, the Company entered into an agreement to issue
1,000,000 shares of new Series A preferred stock, known as the 1996 Series A
Convertible Preferred Stock, in a private placement. 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. Beginning in December
1998, the Company has an option to exchange the stock into convertible
subordinated debentures of equivalent value. The purpose of the private
placement was to fund the capital cost necessary to drill certain development
projects and to fund the capital costs of several West Texas waterflood
projects. Proceeds from the offering were initially used to reduce the Company's
existing bank indebtedness. Certain capital expenditure requirements for
developmental drilling and waterflood projects were required under the agreement
whereby this stock was issued. The Company has met all of these requirements. On
December 23, 1996, the 1996 Series A Convertible Preferred Stock was issued,
resulting in net proceeds to the Company after offering costs of $9,280,000.
Dividends of $875,000, $875,000 and $875,000 were declared in 1997, 1998 and
1999, respectively.
F-14
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On February 3, 1999, the Company sold 50,000 shares of its 1999 Series A 8%
Convertible Preferred Stock for $50 million in a private placement. The
Preferred Stock 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.
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.
Warrants
A total of 1,687,500 warrants were issued in 1994 and were exercisable at
$5.50 per share through November 12, 1998, of which 833,324 were exercised prior
to 1996. The warrants were redeemable by the Company at $0.02 per warrant upon
30 day notice at any time after November 12, 1995 or earlier if the closing bid
price of the common stock equaled or exceeded $6.75 for five consecutive trading
days. The Company called the warrants for redemption on November 14, 1997, after
which 846,256 warrants were exercised for net proceeds to the Company of
$4,654,000. The remaining 7,920 warrants were redeemed.
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 the warrants were
exercised in 1999. 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
and with an expiration date of October 1999, 25,000 warrants with an exercise
price of $5.65 expiring October 2000 and 25,000 warrants with an exercise price
of $6.13 expiring October 2001. None of the warrants were exercised through
1999.
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 in January
2000. During June and October, 1997, 100,000 warrants and 50,000 warrants were
exercised at $4.125 per share and an average of $4.25 per share, respectively,
resulting in net proceeds to the Company of $625,000. In December, 1997, 37,500
warrants at an exercise price of $3.00 per share expired.
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 share of 1999 Series A 8% Convertible Stock owned. The
warrants have an exercise price of $6.50 per share, expire on June 30, 2002 and
are redeemable by the Company at any time prior to expiration at $0.01 per
share. The warrants are publicly traded on the American Stock Exchange. At
December 31, 1999, the Company had a total of 10,583,149 warrants issued.
F-15
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Common Stock
On November 21, 1997, the Company sold 6,500,000 newly issued shares of its
common stock in a public offering, receiving cash proceeds of approximately
$36.2 million after fees and expenses. Additionally, in 1997, 13,556 shares of
the Company's common stock were contributed to the 401(k) plan, 89,242 shares of
common stock were issued upon exercise of employees' stock options, 1,000 shares
of common stock, valued at $4,000 were issued in exchange for services, and
16,306 shares of common stock, valued at $90,000, were issued to acquire oil and
gas properties.
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 and 96,913 shares were issued upon exercise of
employee stock options.
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 $1.7
million. Additionally in 1999, 41,115 shares of the Company's common stock were
contributed to the 401(k) plan and 102,145 shares were issued upon exercise of
employee stock options.
Earnings Per Share
The following table reconciles the numerators and denominators used in the
computations of both basic and diluted EPS as required by SFAS No. 128,
"Earnings per Share":
For the Year Ended For the Year Ended For the Year Ended
December 31, 1999 December 31, 1998 December 31, 1997
----------------------------------------------------------------------------------------------------------
Loss Shares Per Per Per
Share Loss Shares Share Loss Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
----------------------------------------------------------------------------------------------------------
Income (Loss) before
extraordinary item....$ (6,828,000) $(47,080,000) $(2,108,000)
Less: Preferred Stock
dividends... (4,509,000) (875,000) (875,000)
----------------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available to
common stockholders..... (11,337,000) 20,172,062 $(0.56) (47,955,000) 21,189,516 $(2.26) (2,983,000) 14,535,805 $(0.21)
Effect of dilutive securities
Warrants............... - - - - -
Options................ - - - - -
Convertible preferred stock - - - - -
Diluted EPS
Income (Loss) available to
common stockholders and ----------------------------------------------------------------------------------------------------------
assumed conversions....$(11,337,000) 20,172,062 $(0.56) (47,955,000) 21,189,516 $(2.26) (2,983,000) 14,535,805 $(0.21)
----------------------------------------------------------------------------------------------------------
F-16
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The warrants, options, and convertible preferred stock were not included in
the computation of diluted earnings per share in 1999, 1998 and 1997 since the
Company incurred a loss before extraordinary items for the year and any effect
would be anti-dilutive. At December 31, 1998 and 1997, the Company had
outstanding 141,000 warrants at a weighted average exercise price of $4.75 per
share, 2,538,000 options at a weighted average exercise price of $5.00 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, 3,788,092
options at a weighted average exercise price of $3.55 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.
NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION
During 1999, the Company contributed 41,115 shares valued at $123,000 to
the Company's 401(k) plan. The Company wrote down the carrying costs of certain
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. The Company
wrote-down the carrying costs of certain investments by $2,304,000 ($1,429,000
after income tax benefit). Interest paid in 1998 was $17,089,187.
During 1997, the Company purchased oil and gas properties by issuing 16,306
shares valued at $90,000. The Company contributed 13,556 shares valued at
$59,000 to the Company's 401(k) plan. The Company issued 1,000 shares valued at
$4,000 in exchange for services rendered. Interest paid in 1997 was $12,001,557.
NOTE 10 -- ENVIRONMENTAL ISSUES
Being engaged in the oil and gas exploration and development business, the
Company may become subject to certain liabilities as they relate to
environmental clean up of well sites or other environmental restoration
procedures as they relate to the drilling of oil and gas wells and the operation
thereof. In the Company's acquisition of existing or previously drilled well
bores, the Company may not be aware of what environmental safeguards were taken
at the time such wells were drilled or during the time that such wells were
operated. Should it be determined that a liability exists with respect to any
environmental clean-up or restoration, the liability to cure such a violation
would most likely fall upon the Company. In certain acquisitions, the Company
has received contractual warranties that no such violations exist, while in
other acquisitions the Company has waived its rights to pursue a claim for such
violations from the selling party. No claim has been made nor has a claim been
asserted, nor is the Company aware of the existence of any material liability
which the Company may have, as it relates to any environmental clean-up,
restoration or the violation of any rules or regulations relating thereto.
F-17
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 11 -- COMMITMENTS AND CONTINGENCIES
The Company has certain lease agreements for the use of office space 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:
2000........................................................... $ 717,432
2001........................................................... 710,008
2002........................................................... 695,666
2003........................................................... 627,544
2004........................................................... 608,036
Thereafter..................................................... 557,366
-----------------
Total Minimum Payments Required $ 3,916,052
-----------------
Rental expense was $367,000, $327,934, and $218,951 for 1999, 1998, and
1997, 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, 1999 and 1998, there was no NGTS, LLC debt outstanding.
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, 1999 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, 1998, the Company had provided a
$790,000 reserve for the carrying value of a note receivable. After establishing
this reserve, management believes those market values approximate carrying
values at December 31, 1999 and 1998. The market values of equity investments
are based upon quoted prices (see Note 1). At December 31, 1999, 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 $119,000,000.
F-18
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, 1999, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
-------------------- ---------------------- ----------------------- -------------------
Oil
- -------
Swap................ 30,000 Bbl Jan 00 - Dec 00 $17.60
Collar.............. 30,000 Bbl Jan 00 - Mar 00 Floor - $18.00
Cap - $22.65
Collar.............. 30,000 Bbl Jan 00 - Mar 00 Floor - $18.00
Cap - $23.87
Collar.............. 30,000 Bbl Apr 00 - Jun 00 Floor - $18.00
Cap - $24.50
Collar.............. 30,000 Bbl Apr 00 - Jun 00 Floor - $18.00
Cap - $26.00
Collar.............. 30,000 Bbl Jul 00 - Sep 00 Floor - $18.00
Cap - $24.00
Collar.............. 30,000 Bbl Jul 00 - Sep 00 Floor - $18.00
Cap - $24.65
Gas
- -------
Collar.............. 300,000 MMBtu Jan 00 - Mar 00 Floor - $ 2.00
Cap - $ 2.32
Collar ............. 300,000 MMBtu Apr 00 - Oct 00 Floor - $ 1.80
Cap - $ 2.25
Swap................ 100,000 MMBtu Jan 00 - Mar 00 $ 2.86
Collar ............. 100,000 MMBtu Jan 00 - Mar 00 Floor - $ 2.62
Cap - $ 3.82
Purchased Call...... 100,000 MMBtu Feb 00 - Mar 00 $ 2.86
Net gains and (losses) related to derivative transactions for the years
ended December 31, 1999, 1998 and 1997 were $(3,232,000), $2,739,000,
$(1,537,000), respectively. At December 31, 1999, the unrealized loss from
derivative transactions was $(3,812,000).
F-19
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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.
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
Pay Fixed/Receive Variable $50,000,000 06/01/00 9.16% fixed LIBOR + 3.34%
The pay variable/receive fixed swap has an early termination provision
granting the counterparty the right to terminate the swap on June 1, 2000, in
exchange for a fee payment to the Company of $125,000. As a result of these two
swaps, the Company saved approximately $209,000 in interest expense during the
year ended December 31, 1999. The unrealized savings in interest expense at
December 31, 1999 calculated through May 31, 2000 was approximately $175,000.
Thereafter, the economic impact depends on whether or not LIBOR rates increase
significantly.
NOTE 14 -- STOCK COMPENSATION PLAN
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").
ESOP
The Company established an ESOP and a related trust 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. The Plan also allows
for the Company to make discretionary contributions to the ESOP. It is also the
Company's intent to invest all contributions in the Company's Common Stock. In
this regard, on October 11, 1996, the ESOP purchased 22,556 shares of the
Company's Common Stock for $3.75 per share from a third party. To fund this
purchase, the ESOP borrowed $84,585 from a bank. At December 31, 1997, the
Company contributed funds sufficient to pay off the loan and accrued interest to
the ESOP. The ESOP then retired the bank debt and 22,556 shares were allocated
among the plan participants.
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.
F-20
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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. The loan is interest free and is due
December 31, 2004. The loan is secured by 651,535 shares of the Company's common
stock.
Incentive Stock Option Plans
The Company established these plans beginning April 1, 1996. They are
governed by Section 422 of the Internal Revenue Code, and Section 16(b) of the
Securities Exchange Act of 1934. These Option Plans cover 4,088,650 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
options granted subsequent to 1996 vest as described below. The exercise price
is fair market value at the date of grant, except for individuals who own 10% or
more of the Company's stock.
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.
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. 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 1,228,650 new options to employees at an
average price of $2.57. These options vested 20% at the date of grant, with the
balance vesting an additional 20% per year on the anniversary date over the next
four years. Additionally, the expiration date of 300,000 options previously
granted to two former employees was modified to extend the expiration date from
January 5, 2000 to January 5, 2002.
The following is a summary of stock option activity under the Option Plans:
1999 1998 1997
----------------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
--------- ------------- -------- -------------- -------- -------------
Outstanding - Beginning of Year.... 2,661,587 $ 3.90 2,538,500 $ 5.00 1,187,742 $ 3.72
Granted............................ 1,228,650 2.57 220,000 5.89 1,440,000 5.93
Exercised.......................... (102,145) .73 (96,913) .81 (89,242) 3.01
Canceled........................... - - - - - -
Repriced - previous................ - - (1,590,000) 5.96 - -
Repriced - new..................... - - 1,590,000 3.75 - -
-----------------------------------------------------------------------------------
Outstanding - End of Year.......... 3,788,092 $ 3.55 2,661,587 $ 3.90 2,538,500 $ 5.00
========= ========= =========
Exercisable - End of Year.......... 2,709,172 2,501,587 2,338,500
========= ========= =========
F-21
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The following is a summary of stock options outstanding at December 31,
1999:
Weighted
Average
Number of Remaining
Options Contractual Life Number of
Exercise Price Outstanding (Years) Exercisable Options
-------------------------------------------------------------------------
$ 1.65........................... 18,000 less than .1 18,000
2.50........................... 1,198,650 5.0 239,730
3.75........................... 1,590,000 3.0 1,470,000
4.375.......................... 25,000 2.0 25,000
4.50........................... 881,442 2.0 881,442
5.25........................... 65,000 3.4 65,000
5.375.......................... 10,000 2.3 10,000
--------------------------------------------------------------------------
3,788,092 2,709,172
--------------------------------------------------------------------------
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 had the
Company adopted Statement No. 123 is as follows:
1999 1998 1997
---------------------------------------------------------
Net Income (Loss) Applicable to Common Stock:
As reported.............................................. $(11,337,000) $(47,955,000) $(4,367,000)
Pro Forma................................................ (13,208,000) (49,160,000) (6,573,000)
Basic Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ (0.56) $ (2.26) $ (0.30)
Pro Forma................................................ (0.65) (2.32) (0.45)
Diluted Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ (0.56) $ (2.26) $ (0.30)
Pro Forma................................................ (0.65) (2.32) (0.45)
The weighted average grant date fair value of new options granted was
$1,672,000 during 1999. The weighted average grant date fair value of options
whose expiration date was extended in 1999 was $200,000. Fair value of options
and warrants was calculated by using the Black-Scholes options pricing model
using the following weighted average assumptions for 1999 activity: risk free
interest rate of 5.875% on new options, expected life of five years on new
options and two years on options whose term was extended, expected volatility of
52% on new options and 60% on options whose term was extended and no dividend
yield.
F-22
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 and Mr. R. Douglas Cronk 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. 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. 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. 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. 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. 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
Footnote 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-23
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Segment data for the three years ended December 31, 1999 follows (in
thousands):
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) (2,103) 15,110
Equity earnings (losses) of affiliates... (103) (103)
Interest expense......................... (22,103) (22,103)
Other income............................. 354 354
-----------------
Loss before income taxes................. - $ (6,742)
Provision for deferred income tax benefit - -
Minority interest........................ (86) (86)
-----------------
Net loss................................. $ (6,828)
-----------------
Capital expenditures (net of asset sales)$ 54,877 $ 3,331 $ 410 $ - $ - $ 58,618
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 (1,995) (42,962)
Equity earnings (losses) of affiliates... (116) (116)
Interest expense......................... (18,207) (18,207)
Other income............................. 572 572
-----------------
Loss before income taxes................. $ (60,713)
Provision for 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
F-24
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Gas Gathering,
Exploration & Marketing & Oil Field
1997: Production Processing Services All Other Elimination Consolidated
----------------------------------------------------------------------------------
Revenue from external customers......... $ 34,569 $ 10,297 $ 570 $ 3,398 $ - $ 48,834
Intersegment revenues.................... - 13,683 3,257 - (16,940) -
Depreciation, depletion, amortization
and impairment........................... 11,578 661 104 20 12,363
Segment profit (loss).................. 8,280 1,713 1,230 (1,576) 9,647
Equity earnings (losses) of affiliates... 6 6
Interest expense......................... (13,788) (13,788)
Other income............................. 762 762
-----------------
Loss before income taxes................. $ (3,373)
Provision for deferred income tax benefit 1,284 1,284
Minority interest........................ (19) (19)
-----------------
Net loss................................. $ (2,108)
-----------------
Capital expenditures (net of asset sales)$ 156,872 $ 2,064 $ 395 $ - $ $ 159,331
Gas Gathering,
Exploration & Marketing & Oil Field
Production Processing Services All Other Elimination Consolidated
---------------------------------------------------------------------------------
As of December 31, 1999..................
Segment assets............................ $ 278,652 $ 12,416 $ 4,252 $ 10,790 $ 306,110
Equity subsidiary investments............. 4,163 4,163
As of December 31, 1998.................
Segment assets............................ 233,824 13,729 7,230 12,359 267,142
Equity subsidiary investments............. 4,266 4,266
As of December 31, 1997...................
Segment assets............................ 221,272 14,275 5,092 10,430 251,069
Equity subsidiary investments............. 4,372 4,372
F-25
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 17 -- CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
The Company and its wholly owned subsidiaries, except 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. 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. Condensed consolidating financial information for
Magnum Hunter Resources, Inc. and subsidiaries as of December 31, 1999 and 1998
and for the year ended December 31, 1999 is as follows:
Magnum Hunter Resources, Inc. and Subsidiaries
Condensed Consolidating Balance Sheets
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.............................. $ 15,076 $ 3,741 $ (2,601) $ 16,216
Property and equipment
(using full cost accounting).............. 211,159 54,036 265,195
Investment in subsidiaries
(equity method)............................ 13,302 - (13,302) -
Other assets................................ 24,189 510 24,699
---------------------------------------------------------------------------
Total assets............................. $ 263,726 $ 58,287 $ (15,903) $ 306,110
==========================================================================
LIABILITIES AND SHAREHOLDERS'
EQUITY
Current liabilities......................... $ 16,442 $ 3,185 $ (2,601) $ 17,026
Long-term liabilities....................... 193,644 41,800 235,444
Shareholders' equity........................ 53,640 13,302 (13,302) 53,640
---------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 263,726 $ 58,287 $ (15,903) $ 306,110
===========================================================================
F-26
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
December 31, 1998
- -----------------------------------------------------------------------------------------------------------------------
Magnum Hunter Bluebird Magnum Hunter
Resources, Inc. Energy, Inc. Resources, Inc.
Amounts in Thousands And Guarantor Subs (Non Guarantor) Eliminations Consolidated
- --------------------
---------------------------------------------------------------------------
ASSETS
Current assets.............................. $ 12,310 $ 1,379 $ - $ 13,689
Property and equipment
(using full cost accounting).............. 203,766 24,670 228,436
Investment in subsidiaries
(equity method)............................ - - - -
Other assets................................ 25,017 - 25,017
---------------------------------------------------------------------------
Total assets............................. $ 241,093 $ 26,049 $ - $ 267,142
==========================================================================
LIABILITIES AND SHAREHOLDERS'
EQUITY
Current liabilities......................... $ 14,363 $ 49 $ - $ 14,412
Long-term liabilities....................... 205,738 26,000 231,738
Shareholders' equity........................ 20,992 - - 20,992
---------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 241,093 $ 26,049 $ - $ 267,142
===========================================================================
Magnum Hunter Resources, Inc. and Subsidiaries
Condensed Consolidating Statement of Operations
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................................... 62,186 14,678 (410) 76,454
----------------------------------------------------------------------------
Income (loss) before (8,997) 2,169 - (6,828)
Equity in net earnings of subsidiaries.... 2,169 - (2,169) -
----------------------------------------------------------------------------
Income (loss) before income taxes.......... (6,828) 2,169 (2,169) (6,828)
Income tax provision....................... - - - -
----------------------------------------------------------------------------
Net income (loss)........................ $ (6,828) $ 2,169 $ (2,169) $ (6,828)
----------------------------------------------------------------------------
F-27
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)
Proved oil and gas reserves consist of those estimated quantities of crude
oil, 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.
Estimated quantities of proved oil and gas reserves of the Company were as
follows:
Gas
Oil (Thousand
(Barrels) Cubic Feet)
---------------------------------------
December 31, 1997
Proved Reserves................................................ 20,946,415 207,775,770
Proved developed reserves...................................... 12,036,234 154,964,396
December 31, 1998
Proved Reserves................................................ 17,348,641 219,059,674
Proved developed reserves...................................... 9,474,591 174,987,374
December 31, 1999
Proved Reserves................................................ 25,533,750 229,999,526
Proved developed reserves...................................... 16,299,585 184,954,732
The changes in Proved Reserves for the years ended December 31, 1999, 1998
and 1997 were as follows:
Gas
Oil (Thousand
(Barrels) Cubic Feet)
--------------------------------------
Reserves at December 31, 1996........................................ 5,338,255 90,565,997
Purchase of minerals-in-place........................................ 15,282,168 108,620,963
Sale of minerals-in-place............................................ (24,882) (22,517)
Extensions and discoveries........................................... 1,777 18,000
Production........................................................... (737,289) (9,613,623)
Revisions of estimates............................................... 1,086,386 18,206,950
---------------------------------------
Reserves at December 31, 1997........................................ 20,946,415 207,775,770
Purchase of minerals-in-place........................................ 1,362,404 39,535,361
Sale of minerals-in-place............................................ (4,314) -
Extensions and discoveries........................................... 279,248 12,091,186
Production........................................................... (1,140,762) (14,119,330)
Revisions of estimates............................................... (4,094,350) (26,223,313)
---------------------------------------
Reserves at December 31, 1998........................................ 17,348,641 219,059,674
Purchase of minerals-in-place........................................ 3,122,738 15,989,997
Sale of minerals-in-place............................................ (21,273) (196,682)
Extensions and discoveries........................................... 163,865 6,067,527
Production........................................................... (1,310,405) (19,041,012)
Revisions of estimates............................................... 6,230,184 8,120,022
----------------------------------------
Reserves at December 31, 1999........................................ 25,533,750 229,999,526
----------------------------------------
F-28
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (Continued)
(Unaudited)
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, 1999, 1998 and 1997 were as
follows:
1999 1998 1997
-----------------------------------------------------
Unproved oil and gas properties................................ $ 3,566,902 $ 1,654,986 $ 516,560
Proved properties.............................................. 349,510,185 296,545,064 227,389,446
-----------------------------------------------------
Gross Capitalized Costs........................................ 353,077,087 298,200,050 227,906,006
Accumulated depreciation, depletion, amortization and impairment (100,370,224) (79,193,796) (16,091,001)
----------------------------------------------------
Net Capitalized Costs................................ $ 252,706,863 $ 219,006,254 $ 211,815,005
====================================================
Costs incurred in oil and gas producing activities, both capitalized and
expensed, during the years ended December 31, 1999, 1998 and 1997 were as
follows:
1999 1998 1997
------------------------------------------------
Property acquisition costs
Proved properties................................................. $ 34,477,750 $ 36,619,796 $ 137,430,583
Unproved properties............................................... 1,911,916 1,138,426 57,306
Exploration costs................................................... 6,835,000 4,696,095 737,936
Development costs................................................... 12,176,557 27,839,727 18,284,460
-----------------------------------------------
Total Costs Incurred...................................... $ 55,401,223 $ 70,294,044 $ 156,510,285
===============================================
Results of operations from oil and gas producing activities for the years
ended December 31, 1999, 1998 and 1997 were as follows:
1999 1998 1997
------------------------------------------------
Oil and gas production revenue..................................... $ 60,673,493 $ 43,564,728 $ 35,658,032
Disposal services revenue.......................................... - - 5,130
Production costs................................................... (23,575,241) (20,682,187) (13,901,537)
Depreciation, depletion, amortization and impairment............... (21,176,428) (63,102,795) (11,577,460)
------------------------------------------------
Results of Operations for Producing Activities $ 15,921,824 $(40,220,254) $ 10,184,165
================================================
The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 1999, 1998 and 1997 were
as follows:
1999 1998 1997
--------------------------------------------------------------
Future cash inflows....................... $ 1,037,682,380 $ 625,818,712 $ 811,512,060
Future development and production costs... (349,974,145) (278,222,069) (336,730,398)
--------------------------------------------------------------
Future net cash flows, before incoome tax. 687,708,235 347,596,643 474,781,662
Future income taxes....................... (127,742,620) - (93,828,793)
--------------------------------------------------------------
Future Net Cash Flows..................... 559,965,615 347,596,643 380,952,869
10% annual discount....................... (258,619,307) (168,187,696) (211,181,318)
--------------------------------------------------------------
Standardized Measure of Discounted
Net Cash Flows.................. $ 301,346,308 $ 179,408,947 $ 169,771,551
==============================================================
F-29
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (Continued)
(Unaudited)
The primary changes in the standardized measure of discounted estimated
future net cash flows for the years ended December 31, 1999, 1998 and 1997 were
as follows:
1999 1998 1997
----------------------------------------------------------
Purchases of minerals-in-place................................. $ 45,321,069 $ 46,388,818 $ 136,739,277
Sales of minerals-in-place..................................... (167,874) (8,604) (191,741)
Extensions, discoveries and improved recovery, less related costs 8,398,247 10,836,769 38,555
Sales of oil and gas produced, net of production costs......... (37,098,252) (22,882,541) (21,756,495)
Development costs incurred during the period................... 12,176,557 27,839,727 16,289,428
Revision of prior estimates:
Net change in prices and costs............................... 107,174,805 (61,951,610) (141,112,592)
Change in quantity estimates................................. 36,936,790 (55,991,223) 46,255,955
Accretion of discount.......................................... 17,940,895 16,977,155 11,708,486
Net change in income taxes..................................... (68,744,876) 48,428,905 4,715,817
----------------------------------------------------------
Net Change.................................... $ 121,937,361 $ 9,637,396 $ 52,686,690
------------------------------------------------------------
Estimated future cash inflows are computed by applying year-end prices of
oil and gas to year-end quantities of Proved Reserves. Estimated future
development and production costs are determined by estimating the expenditures
to be incurred in developing and producing the proved oil and gas reserves at
the end of the year, based on year-end costs and assuming continuation of
existing economic conditions. Estimated future income tax expense is calculated
by applying year-end statutory tax rates to estimated future pre-tax net cash
flows related to proved oil and gas reserves, less the tax basis of the
properties involved.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and as such, do not
necessarily reflect the Company's expectations of actual revenues to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process are equally applicable to the standardized
measure computations since these estimates are the basis for the valuation
process.
F-30
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................... 42 Director, President and Chief Executive Officer
Matthew C. Lutz................. 65 Chairman of the Board and Executive Vice President
Richard R. Frazier.............. 53 President and Chief Operating Officer of Magnum Hunter
Production, Inc. and Gruy
Chris Tong...................... 43 Senior Vice President and Chief Financial Officer
R. Douglas Cronk . . . . . . . . 53 Senior Vice President of Operations of Magnum Hunter Production,
Inc. and Gruy
Morgan F. Johnston.............. 39 Vice President, General Counsel and Secretary
David S. Krueger................ 50 Vice President and Chief Accounting Officer
Michael McInerney . . . . . . . 58 Vice President, Corporate Development & Investor Relations
Charles R. Erwin................ 52 Vice President of Exploration of Magnum Hunter Production, Inc. and
Gruy
Gregory L. Jessup............... 46 Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits.............. 48 Vice President and Controller of Gruy
Craig Knight.................... 43 Vice President of Operations of Hunter Gas Gathering, Inc.
Earl Krieg, Jr. ................ 46 Vice President of Engineering of Magnum Hunter Production, Inc. and
Gruy
Gerald W. Bolfing............... 71 Director
Jerry Box....................... 61 Director
Larry W. Brummett............... 49 Director
David L. Kyle................... 47 Director
Oscar C. Lindemann.............. 77 Director
John H. Trescot, Jr............. 74 Director
James E. Upfield................ 79 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 Swanson Consulting Services, Inc., a private
Houston based geological firm, Novavax, Inc., an American Stock Exchange listed
pharmaceutical company, and Karts International Incorporated, an OTC listed
manufacturing company. He also serves as a Trustee of TEL Offshore Trust, an OTC
listed oil and gas trust of which Magnum Hunter owns an approximate 40%
interest.
43
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.
44
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 Manager of Exploration for Gruy Petroleum
Management Co. since May of 1999. Mr. Erwin became Vice President of Exploration
for Magnum Hunter Production, Inc. and Gruy in January 2000. 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, 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 Gruy
Petroleum Management Co. 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.
45
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 24 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.
Larry W. Brummett has served as a director of the Company since February
1999. Mr. Brummett has been employed by ONEOK Inc. for more than 23 years. He
was employed by ONEOK's Oklahoma Natural Gas Company division as an engineer
trainee in June 1974 and, after receiving a number of promotions within the
division, was elected Vice President of Tulsa District in September 1, 1986, and
Executive Vice President in May 1990. He was elected Executive Vice President of
ONEOK Inc. January 1993. He was elected President and Chief Executive Officer in
February 1994, and was elected to the additional position of Chairman of the
Board effective June 1994. Mr. Brummett is a director of American Gas
Association; Southern Gas Association; Oklahoma State Chamber of Commerce;
Metropolitan Chamber of Commerce, Tulsa; and the Oklahoma City Branch of the
Federal Reserve Bank. He is also an officer or director of numerous civic and
business organizations and not-for-profit associations. He attended the
University of Oklahoma, earning B.S. and M.S. degrees in civil engineering, and
is also a graduate of the Advanced Management Program at Harvard Business
School.
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.
46
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. For the past five years, Mr. Trescot has been the principal of AWA
Management Corporation, a consulting firm specializing in financial evaluations.
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 Florestal e Agropecuaria, Ltda (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. 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.
[Rest of page intentionally left blank]
47
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, 1999.
Long Term Compensation
Annual Awards Payout
Compensation
(a) (b) (c) (d) (e) (f) (g) (h) (i)
Name, Other Number
Principal Annual Restricted Options LTP All Other
Position Year Salary Bonus Compensation (b) Stock SARs Payouts Compensation
-------- ---- ------ ----- ------------- ----- ---- ------- ------------
Gary C. Evans 1999 $250,000 $250,000 $ 7,500 - - - -
President and CEO 1998 $250,000 $300,000 - - - - -
1997 $200,025 $250,000 - - - - -
Matthew C. Lutz 1999 $150,000 $125,000 $ 6,000 - - - -
Executive V.P. and 1998 $156,000 $100,000 - - - - -
Chairman 1997 $106,000 $100,000 - - - - -
Richard R. Frazier 1999 $150,000 $ 75,000 $ 4,200 - - - -
President of 1998 $154,200 $ 50,000 - - - - -
Magnum Hunter 1997 $124,200 $ 50,000 - - - - -
Production, Inc.
Chris Tong (a) 1999 $150,000 $ 35,000 $ 6,000 - - - -
Senior Vice President & 1998 $156,000 $ 30,000 - - - - -
Chief Financial Officer 1997 $ 78,500 $ 25,000 - - - - -
R. Douglas Cronk 1999 $115,000 $ 25,000 $ 4,200 - - - -
Senior V.P. of Magnum 1998 $104,200 $ 20,000 - - - - -
Hunter Production, Inc. 1997 $ 92,033 $ 10,000 - - - - -
- ---------------------
(a) Mr. Tong was hired in August of 1997.
(b) Other compensation consists of a vehicle allowance paid to the
employee.
48
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of securities Value of unexercised
underlying in-the-money
unexercised options/SARs at fiscal
options/SARs at fiscal year-end ($)
year-end (#)
Shares Acquired Value Exercisable/ Exercisable/
Name On Exercise (#) Realized ($) Unexercisable Unexercisable
(a) (b) (c) (d) (e)
- -----------------------------------------------------------------------------------------------------------------------
Gary C. Evans - - 700,000 / 200,000 0 / 0
Matthew C. Lutz 51,073 $150,831 505,000 / 120,000 0 / 0
Richard R. Frazier - - 225,000 / 100,000 0 / 0
R. Douglas Cronk - - 96,000 / 44,000 0 / 0
Chris Tong - - 121,000 / 84,000 0 / 0
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 1998, independent directors received $1,000 per
meeting as compensation for their services. For fiscal year 1999, 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. 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 and Mr. R. Douglas Cronk 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. 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. 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. 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. 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. 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.
49
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.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth certain information as of March 15, 2000,
regarding the share ownership of the Company by (i) each person known to the
Company to be the beneficial owner of more than 5% of the outstanding shares of
Common Stock of the Company, (ii) each director, (iii) the Company's Chief
Executive Officer and the four other most highly compensated executive officers
of the Company, and (iv) all directors and executive officers of the Company, as
a group. None of the directors or executive officers named below, as of March
15, 2000, owned any shares of the Company's Series A Preferred Stock, its 1996
Series A Convertible Preferred Stock or its 1999 Series A 8% 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 (q)
Directors and Executive Officers
Gary C. Evans ............................................ 2,262,952 (a) 10.8%
Matthew C. Lutz........................................... 703,588 (b) 3.4%
Richard R. Frazier........................................ 288,115 (c) 1.4%
Chris Tong................................................ 129,951 (d) *
R. Douglas Cronk ......................................... 99,768 (e) *
Gerald W. Bolfing......................................... 368,460 (f) 1.8%
Jerry Box................................................. 12,000 (g) *
Oscar C. Lindemann........................................ 39,526 (h) *
John H. Trescot, Jr....................................... 102,056 (i) *
James E. Upfield......................................... 93,544 (j) *
David L. Kyle ............................................ 19,342 (k) *
Larry M. Brummett ........................................ 10,342 (l) *
All directors and executive officers as a group
(12 persons).............................................. 4,129,644 18.8%
Beneficial owners of 5 percent or more
(excluding persons named above)
ONEOK Resources Company
100 W. Fifth Street
Tulsa, OK 74103-4298 ..................................... 9,523,809 (m) 32.0%
TCW Group, Inc.
865 South Figueroa Street
Los Angeles, CA 90017.................................... 1,904,762 (n) 8.6%
Janus Capital Corporation
100 Fillmore St., Suite 300
Denver, CO. 80206........................................ 1,653,075 (o) 8.2%
Dimensional Fund Advisors Inc.
1299 Ocean Avenue, 11th Floor
Santa Monica, CA 90401.................................... 1,173,100 (p) 5.8%
- -------------
* Less than one percent.
50
(a) Includes 700,000 shares of common stock issuable upon the exercise of
certain currently exercisable options. 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 505,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(c) Includes 225,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(d) Includes 121,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(e) Includes 96,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(f) Includes 12,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(g) Includes 2,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(h) Includes 12,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(i) Includes 37,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(j) Includes 12,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(k) Includes 2,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(l) Includes 2,000 shares of common stock issuable upon the exercise of
certain currently exercisable options.
(m) Consists of shares attributable to shares of Common Stock issuable upon
conversion of 50,000 shares of the Company's 1999 Series A 8% Convertible
Preferred Stock.
(n) Consists of shares attributable to shares of Common Stock issuable upon
conversion of 1,000,000 shares of the Company's 1996 Series A Convertible
Preferred Stock.
(o) Based on Schedule 13G filed by Janus Capital Corporation on February
14, 2000.
(p) Based on Schedule 13G filed by Dimensional Fund Advisors Inc. on
February 4, 2000.
(q) 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. Subsequent to year-end, $225,000 was repaid. The outstanding principal
balance as of March 15, 2000 was $146,860.
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 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.
51
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.
52
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 oil, 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.
Proved Undeveloped Reserves. Proved 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.
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.
SEC 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,
1999, 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, 1999, or as otherwise
indicated.
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.
53
Item 14. Exhibits and Reports on Form 8-K.
Exhibit
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)
54
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
10.6* Employment Agreement for Matthew C. Lutz
10.7* Employment Agreement for Richard R. Frazier
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)
21 Subsidiaries of the Registrant (Incorporated by reference to Form 10-K for the fiscal year-end December
31, 1998 filed April 14, 1999)
27* Financial Data Schedule
* Filed herewith.
(B) Form 8-K's - None.
55
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 report to be signed
on its behalf by the undersigned, thereunto duly authorized.
MAGNUM HUNTER RESOURCES, INC.
By: /s/ Gary C. Evans March 30, 2000
- ---------------------------------------------
Gary C. Evans, President & CEO
In accordance with the Exchange Act, this report 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, 2000
- ----------------------------
Gary C. Evans Chief Executive Officer
/s/ Matthew C. Lutz Chairman of the Board and March 30, 2000
- --------------------------
Matthew C. Lutz Executive Vice President of
Exploration and Business
Development
/s/ Chris Tong Senior Vice President and March 30, 2000
- -------------------------------
Chris Tong Chief Financial Officer
/s/ David S. Krueger Vice President and March 30, 2000
- --------------------------
David S. Krueger Chief Accounting Officer
/s/ Morgan F. Johnston Vice President, General Counsel March 30, 2000
- -------------------------
Morgan F. Johnston and Secretary
/s/ Gerald W. Bolfing Director March 30, 2000
- --------------------------
Gerald W. Bolfing
/s/ Oscar C. Lindemann Director March 30, 2000
- -----------------------
Oscar C. Lindemann
/s/ John H. Trescot, Jr. Director March 30, 2000
- ---------------------------
John H. Trescot, Jr.
/s/ James E. Upfield Director March 30, 2000
- ---------------------------
James E. Upfield
56