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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, 1998
[ ] 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 1200, Irving, Texas 75039
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (972) 401-0752
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class Name of each exchange on which registered
Common Stock ($.002 par value) American Stock Exchange
- ------------------------------ -----------------------
Securities registered under Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of March 31, 1999, 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 $51,469,744.
The number of shares outstanding of the registrant's common stock at March 31,
1999 was 20,082,341.
TABLE OF CONTENTS
Securities and Exchange Commission
Item Number and Description
PART I
Item 1. Business............................................................1
The Company........................................................1
Business Strategy .................................................2
Recent Acquisitions ...............................................3
Development and Exploration Activities ............................6
Gathering and Processing of Gas ...................................8
Marketing of Production ...........................................9
Petroleum Management and Consulting Services ......................9
Competition........................................................9
Regulation .......................................................10
Employees ........................................................13
Facilities .......................................................13
Item 2. Properties.........................................................14
Oil and Gas Reserves .............................................14
Oil and Gas Production, Prices and Costs .........................16
Drilling Activity ................................................17
Oil and Gas Wells ................................................18
Oil and Gas Acreage ..............................................18
Item 3. Legal Proceedings..................................................19
Item 4. Submission of Matters to a Vote of Security Shareholders...........19
PART II
Item 5. Market for Common Equity and Related Stockholder Matters...........20
Item 6. Selected Financial Data............................................21
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...............................23
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.........32
Item 8. Financial Statements and Supplementary Data........................35
Item 9. Change in and Disagreements with Accountants on
Accounting and Financial Disclosure...............................36
PART III
Item 10. Directors and Executive Officers of the Registrant..................36
Item 11. Executive Compensation..............................................40
Item 12. Security Ownership of Certain Beneficial Owners and Management......42
Item 13. Certain Relationships and Related Transactions......................43
Glossary............................................................44
Item 14. Exhibits and Reports on Form 8-K....................................46
i
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 exploitation and
development, acquisition, exploration and operation of oil and gas properties
with a geographic focus in Texas, Oklahoma and New Mexico. In December 1995, the
Company consummated the acquisition of all of the subsidiaries of Hunter
Resources, Inc., a Pennsylvania corporation (the "Magnum Hunter Combination"),
and the management of Hunter Resources, Inc. assumed operating control of the
Company. The new management 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, in June 1996 the Company
acquired the Panoma Properties (as defined herein) from Burlington Resources
Inc. ("Burlington") for a net purchase price of $34.7 million (the "Panoma
Acquisition"). Additionally, in April 1997 the Company acquired the Permian
Basin Properties (as defined herein) from Burlington for a net purchase price of
$133.8 million (the "Permian Basin Acquisition"). On December 31, 1998 the
Company acquired the Spirit 76 Properties (as defined herein) from Spirit Energy
76 ("Spirit 76"), a business unit of Union Oil Company of California, for a net
purchase price of approximately $25 million (the "Spirit 76 Acquisition"). The
Company presently intends to focus its efforts on additional producing property
acquisitions, its substantial inventory of exploitation and development
opportunities and, to a lesser extent, selected exploratory drilling prospects.
The Company has identified over 400 development drilling locations (including
both production and injection wells) on its properties, substantially all of
which are low-risk in-fill drilling opportunities.
On March 27, 1998 the Company acquired an approximately 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 $10.3 million (the "TEL Acquisition"). 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.
At December 31, 1998, the Company had an interest in 3,059 wells and had
estimated Proved Reserves of 323.2 Bcfe with an SEC PV-10 of $179.4 million.
Approximately 70% of these reserves were Proved Developed Producing Reserves and
88.1% were attributable to the Panoma Properties, the Permian Basin Properties
and the Spirit 76 Properties. At December 31, 1998, the Company's Proved
Reserves had an estimated Reserve Life of approximately 13 years and were 68%
gas. The Company serves as operator for approximately 65% of its properties
(based on the number of producing wells in which the Company owns an interest).
Additionally, the Company owns over 480 miles of gas gathering systems and a 50%
interest in a gas processing plant that is located adjacent to the Company's
largest gas gathering system.
Beginning with the Magnum Hunter Combination in December 1995, the Company
has completed twelve acquisitions for an aggregate net purchase price of $221.8
million. This strategy has added approximately 346.6 Bcfe of reserves
(determined as of the respective times of their acquisition) at an average cost
of $0.63 per Mcfe, as well as a 427 mile gas gathering system and a 50% interest
in the McLean Gas Plant (the "McLean Plant Acquisition"). As a result of its
property acquisitions and successful drilling activities, the Company has
achieved substantial growth as described below:
o Proved Reserves increased to 323.2 Bcfe at year end 1998 from 36.7 Bcfe
at year end 1995;
o SEC PV-10 increased to $179.4 million at year end 1998 from $37.2 million
at year end 1995; and
o Average daily production increased to 57.8 MMcfe in the fourth quarter of
1998 from 0.8 MMcfe in fiscal 1995
Recent Developments
On February 3, 1999, the Company closed various transactions with ONEOK
Resources Company ("ONEOK"), a wholly-owned subsidiary of ONEOK, Inc., the
eighth largest natural gas distributor in the United States, relating to (i)
ONEOK's purchase of $50 million of Convertible Preferred Stock of the Company,
(ii) ONEOK's ability to market certain of the Company's natural gas production
in the state of Oklahoma and (iii) ONEOK's ability to participate in future
acquisitions of the Company in the state of Oklahoma (the "ONEOK Transaction").
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 to repay
senior bank indebtedness. ONEOK had the right to nominate two new members to the
Company's existing Board of Directors which ONEOK exercised on February 18,
1999. See "Selected Financial Data" and "Directors, Executive Officers,
Promoters and Control Persons."
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. On February 17, 1999, the
Company revised its previously announced stock repurchase program to spend up to
$4 million without a share limitation.
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) strategic acquisitions of Proved Reserves and (iii) a selective
exploration program.
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.
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 65% of its properties (78% 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. The Company owns over 85% and markets directly and
indirectly approximately 95% of the 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 approximately 350 MMcf per day as of
December 31, 1998. NGTS markets substantially all of the Company's natural gas.
The Company is also considering opportunities to acquire or develop additional
gas gathering and processing facilities that are associated with its current
production.
Exploration. The Company is systematically increasing its exploration
efforts, focusing on established geological trends where the Company can employ
its geological, geophysical and engineering expertise. The Company is actively
generating and evaluating prospects for the application of 3-D seismic and
advanced drilling technologies.
Recent Acquisitions
The most significant of the Company's completed acquisitions are the Spirit
76 Acquisition, the Permian Basin Acquisition, the Panoma Acquisition, the TEL
Acquisition and the McLean Plant Acquisition.
Spirit 76 Acquisition
On December 31, 1998 the Company acquired from Spirit 76 natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
(the "Spirit 76 Properties") currently producing about 12 million cubic feet of
natural gas equivalent per day. The net purchase price was approximately $25
million after certain purchase price adjustments including preferential rights
exercised by third parties and other customary adjustments.
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 acquired from Spirit 76.
According to Ryder Scott, as of December 31, 1998, the Spirit 76 Properties had
Proved Reserves of .98 MMBbl of oil and 35.7 Bcf of gas, or on a Natural Gas
Equivalent basis 41.6 Bcfe. Ryder Scott further estimated the SEC PV-10 for the
Spirit 76 Properties to be $37.6 million as of December 31, 1998 based on prices
of $9.42 per Bbl of oil and $2.18 per Mcf of gas. The Proved Reserves are
located principally in the Ardmore Basin in south central Oklahoma and in the
Oklahoma/Texas panhandle. Approximately 86% of the estimated reserves are gas
and 14% are oil located on approximately 50,000 net mineral leasehold acres in
twelve counties in Oklahoma and five counties in Texas. Total net daily
production to the Company's interest acquired is approximately 11 million cubic
feet of natural gas production and 165 barrels of oil. Approximately 80% of the
Proved Reserves were classified Proved Developed Producing Reserves as of
December 31, 1998. The Company has engaged its Houston based geological
affiliate, Swanson Consulting Services, Inc., to begin an evaluation of the most
prospective undeveloped properties located in one of the fields acquired. The
Company's wholly-owned subsidiary, Gruy Petroleum Management Co. ("Gruy"), has
become the operator of 62% or 111 of the 179 wells acquired from Spirit 76.
3
The major fields in the Spirit 76 Properties are the Cumberland, Caddo and
Hitchcock.
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. Potential exists for three additional wells to complete development
of the shallow gas on 160-acre spacing. The shallowest zone in the field is the
Goddard, which is a channel sand. The Company has interest in a total of 128
wells in this field, with working interest varying from 17.2% to 100%. The
Company operates all but nine of these wells. The latest available gross
production from such wells averaged 6,200 Mcf/d and 190 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 1,920 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 six of these wells. The
latest available gross production from the wells averaged 1,676 Mcf/d and 23
Bbl/d.
Permian Basin Acquisition
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 included 1,852 producing oil and gas wells on
approximately 113,810 gross acres (82,175 net acres). One of the Company's
subsidiaries, Gruy Petroleum Management Co. ("Gruy"), serves as operator on
approximately 60% of the wells on the Permian Basin Properties. Management
believes the Permian Basin Properties provide significant opportunities for
exploitation and development of both oil and gas through workovers and
recompletions, enhanced recovery projects and in-fill drilling.
According to Ryder Scott, as of December 31, 1998, the Permian Basin
Properties had Proved Reserves of 10.65 MMBbl of oil and 85.3 Bcf of gas, or on
a Natural Gas Equivalent basis, 149.2 Bcfe. Ryder Scott further estimated the
SEC PV-10 for the Permian Basin Properties to be $59.12 million as of December
31, 1998 based on prices of $9.42 per Bbl of oil and $2.18 per Mcf of gas at
December 31, 1998. Approximately 60% of the Proved Reserves were classified as
proved developed producing reserves as of December 31, 1998. 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 Properties are the Westbrook,
Levelland/Slaughter, Lea County Shallow Properties and the Brunson Ranch.
4
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 in the Permian Basin
Acquisition:
Gross Oil
Well Working Net Revenue Production
Property Operator Count Interest Interest (Bbl/d)
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Southwest Westbrook Unit............... Company 135 89.9% 77.5% 425
Morrison "G" Lease (1)................. Company 12 83.3% 72.9% 26
North Westbrook Unit................... Third Party 294 2.0% 2.8%(2) 1,200
(1) Subsequent to the Permian Basin Acquisition, the Company acquired
the remaining 16.7% of the working interest in the Morrison "G"
Lease, increasing its Net Revenue Interest to 87.5%.
(2) Includes an overriding Royalty Interest.
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 plans to initiate
waterflood enhancement operations on the Southwest Westbrook Unit and the
Morrison "G" Lease in either 1999 or 2000 assuming oil prices continue to
improve.
Levelland/Slaughter. The Levelland and Slaughter Fields consist of 155
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)
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TLB Unit............................... Company 20 100.0% 87.3% 80
Veal Lease............................. Company 52 100.0% 87.1% 220
NW Slaughter Unit...................... Company 83 74.8% 62.8% 290
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 are likely. 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 anticipated for
that property. The operator of an adjacent property has been successfully
injecting carbon dioxide for a number of years to 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 which
are planned.
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 and completing such wells using technology designed for high
bottom hole pressure conditions.
5
Panoma Acquisition
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"). By year-end of 1998, the Company had drilled an additional 80
wells. A continuous drilling program is budgeted, with an additional 20 wells
proposed to be drilled in 1999. The net purchase price, 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. According to
Ryder Scott, the Proved Reserves attributable to the Panoma Properties as of
December 31, 1998 aggregated 94 Bcfe with an SEC PV-10 of $50.9 million.
The Panoma Properties currently consist of approximately 630 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 gas from the
Granite Wash and/or Brown Dolomite formations.
TEL Acquisition
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 $10.3 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 1.3
Bcfe in 1998.
McLean Plant Acquisition
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,
which is connected to the Panoma gas gathering system and a related products
pipeline. The Company receives 100% of the net profits from the McLean Gas Plant
until it recoups the $2.5 million purchase price, after which time it will
receive 50% of the net profits. At January 31, 1999, the Company had recouped
approximately $1.36 million or 54% of its initial investment. See "Gathering and
Processing of Gas."
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, to a lesser extent, 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 $9.0 million
for exploitation and development activities for 1999. The Company has identified
over 400 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.
6
Permian Basin Properties. In evaluating the Permian Basin Properties, the
Company has identified approximately 400 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 1998, the Company drilled 19 wells
in the Sawyer Canyon Field in the Sonora area located in Sutton County, Texas.
The Company owns an interest in 146 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. The
Company has plans to continue to develop the Sawyer Canyon Field in 1999. The
Company has budgeted approximately $3.5 million for development of the Permian
Basin properties in 1999.
Panoma Properties. 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 westernmost field with 80 wells
having been completed during the two years ended December 1998. Upon completion
of this well program, the westernmost field will have been effectively developed
with 320 acre spacing. The Company has budgeted approximately $1.5 million for
development of the Panoma Properties through 1999.
Spirit 76 Acquisition. The Company has engaged its Houston based geological
affiliate, Swanson Consulting Services, Inc., to begin an evaluation of the most
prospective undeveloped properties located in one of the fields acquired, being
the Cumberland Field. 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 Company has budgeted approximately $1.5 million for development of
the Cumberland Field through 1999.
Exploratory Drilling
The Company attempts to lessen the risks inherent in exploratory drilling
by: (i) concentrating in specific areas in the United States where the Company's
technical staff has considerable experience and which are in known producing
trends where the potential for significant reserves exists; (ii) diversifying
through investment in multiple prospects; (iii) utilizing 3-D seismic and other
advanced technologies; and (iv) promoting out interests to industry partners.
The Company spent approximately $6.0 million of its $36 million 1998
capital budget on exploratory drilling. The Company has a $1.0 million
exploration budget for 1999, including geological and geophysical expenses for
its currently owned properties. Six exploratory wells were drilled in 1998 of
which five were successful. Exploratory successes include the Mossy Grove
Prospect in Walker County, Texas where a discovery completed in July 1998 has
produced nearly 750 MMcf of natural gas in 8 months and is currently flowing at
approximately 2 MMcf/d. A confirmation to this discovery, located 3.5 miles
southwest, has been recently completed and is flowing over 5 MMcf/d. The Company
owns 25% and 55% working interest, respectively, in these two producing wells
and owns an average of a 25% working interest in a 43,000 acre lease block
surrounding the new wells where additional development drilling is planned.
7
A new oil discovery on the Sunburst Prospect in Terry County, Texas is
currently producing approximately 42 Bbls of oil per day. This well was
completed in September 1998 and a confirmation test is planned by the middle of
1999. The Company is operator and owns a 39% working interest in the discovery
and approximately 1,500 acres of the prospect. Additional development drilling
is expected later in 1999.
A 3-D seismic program on the Bobcat Project in Hockley County, Texas has
been completed and the interpretation of the data confirms the presence of
numerous high quality, exploratory prospects. The entire project covers over
30,000 acres with approximately 15,000 acres under lease or option. An
exploratory drilling program is expected to commence in late 1999 and extend
into 2000.
The Company is actively generating and evaluating other projects for future
exploration activity.
Gathering and Processing of Gas
Hunter Gas Gathering, Inc., a wholly-owned subsidiary of the Company, owns
two gas gathering systems located in Oklahoma and Texas, neither of which are
subject to regulation by the Federal Energy Regulatory Commission ("FERC"), and
a 50% ownership interest in the McLean Gas Plant in the Texas Panhandle. Gruy
operates both gas gathering systems. In October of 1998, the Company sold a
small gathering system located in Louisiana that accounted for less than 2% of
the Company's total gas gathering throughput.
Generally, the gathering systems transport the 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 1998, gas
throughput for the Panoma gas gathering system was approximately 18.2 MMcf per
day. The Panoma gas gathering system was recently 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 535 of the
approximately 630 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.
The Company's North Appleby gas gathering system is located primarily in
Nacogdoches County in east Texas. Approximately 39 wells are connected to the
system, which delivers approximately 2.2 MMcf per day for third parties to
Natural Gas Pipeline Co. for transportation to other markets. The Company is
currently negotiating with several third parties for the possible sale of the
North Appleby gas gathering system.
Effective January 1, 1997, the Company purchased for $2.5 million a 50%
ownership interest in the McLean Gas Plant, the gas processing facility
connected to the Company's Panoma gas gathering system. The purchase also
included a 23-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 16.4 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. Under the
terms of the Company's operating agreement with Carrera, the Company receives
100% of the net profits from the McLean Gas Plant until it recoups the $2.5
million purchase price, at which point net profits will be divided equally
between the Company and Carrera. As of January 31, 1999 the Company had recouped
approximately 54% of its $2.5 million investment.
8
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 the spot market
on a month-to-month basis at prevailing spot market prices or 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 purchasers. Oil is usually sold for
the Company's own account through the services of Enmark Services, a marketing
agent in Dallas, Texas. While the Company has historically been able to sell oil
above posted prices, it is also exposed to the commodities risk inherent in
short-term contracts which the Company attempts to mitigate through various
financial hedges. For a discussion of the Company's hedging activities, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources - Hedging Activity" and Note 13 to
the Company's Consolidated Financial Statements.
In December 1997, Hunter Gas Gathering, Inc. acquired a thirty percent
(30%) membership interest in NGTS, a 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
$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
1998, NGTS reported total revenues of approximately $224.7 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 the Magnum Hunter Combination 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 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
9
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, gas 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.
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;
10
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.
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
11
procedures. Because of the novelty and uncertainty surrounding the indexing
methodology, as well as the possibility of the use of cost of service ratemaking
and market-based rates, the Company is not able at this time to predict the
effects of Order No. 561, if any, on the transportation costs associated with
oil production from the Company's oil producing operations.
Environmental Regulation
The Company's exploration, development, and production of oil and gas,
including its operation of saltwater injection and disposal wells, are subject
to various federal, state and local environmental laws and regulations. Such
laws and regulations can increase the costs of planning, designing, installing
and operating oil and gas wells. The Company's domestic activities are subject
to a variety of environmental laws and regulations, including but not limited
to, the Oil Pollution Act of 1990 ("OPA"), the Clean Water Act ("CWA"), the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
the Resource Conservation and Recovery Act ("RCRA"), the Clean Air Act ("CAA"),
and the Safe Drinking Water Act ("SDWA"), as well as state regulations
promulgated under comparable state statutes. The Company also is subject to
regulations governing the handling, transportation, storage, and disposal of
naturally occurring radioactive materials that are found in its oil and gas
operations. Civil and criminal fines and penalties may be imposed for
non-compliance with these environmental laws and regulations. Additionally,
these laws and regulations require the acquisition of permits or other
governmental authorizations before undertaking certain activities, limit or
prohibit other activities because of protected areas or species, and impose
substantial liabilities for cleanup of pollution.
Under the OPA, a release of oil into water or other areas designated by the
statute could result in the Company being held responsible for the costs of
remediating such a release, certain OPA specified damages, and natural resource
damages. The extent of that liability could be extensive, as set forth in the
statute, depending on the nature of the release. A release of oil in harmful
quantities or other materials into water or other specified areas could also
result in the Company being held responsible under the CWA for the costs of
remediation, and civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws, can
impose joint and several and retroactive liability, without regard to fault or
the legality of the original conduct, on certain classes of persons for the
release of a "hazardous substance" into the environment. In practice, cleanup
costs are usually allocated among various responsible parties. Potentially
liable parties include site owners or operators, past owners or operators under
certain conditions, and entities that arrange for the disposal or treatment of,
or transport hazardous substances found at the site. Although CERCLA, as
amended, currently exempts petroleum, including but not limited to, crude oil,
gas and natural gas liquids from the definition of hazardous substance, the
Company's operations may involve the use or handling of other materials that may
be classified as hazardous substances under CERCLA. Furthermore, there can be no
assurance that the exemption will be preserved in future amendments of the act,
if any.
RCRA and comparable state and local requirements impose standards for the
management, including treatment, storage, and disposal of both hazardous and
nonhazardous solid wastes. The Company generates hazardous and nonhazardous
solid waste in connection with its routine operations. From time to time,
proposals have been made that would reclassify certain oil and gas wastes,
including wastes generated during drilling, production and pipeline operations,
as "hazardous wastes" under RCRA which would make such solid wastes subject to
much more stringent handling, transportation, storage, disposal, and clean-up
requirements. This development could have a significant impact on the Company's
operating costs. While state laws vary on this issue, state initiatives to
further regulate oil and gas wastes could have a similar impact.
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, 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
12
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 1999 and $75,000 in 2000.
It is not anticipated that the Company will be required in the near future
to expend amounts that are material in relation to its total capital
expenditures program by reason of environmental laws and regulations, but
inasmuch as such laws and regulations are frequently changed, the Company is
unable to predict the ultimate cost of compliance. There can be no assurance
that more stringent laws and regulations protecting the environment will not be
adopted or that the Company will not otherwise incur material expenses in
connection with environmental laws and regulations in the future.
Employees
At December 31, 1998, the Company had 69 full-time employees of which 12
were management, 26 were administrative and 31 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 11,590 square feet of office space at
600 East Las Colinas Boulevard, Suite 1200, Irving, Texas, under a lease that
expires in November 2001. The Company owns a field office and production yard in
Shamrock, Texas. The Company also has field production offices in Midland and
Abilene, Texas, Hobbs, New Mexico and Oklahoma City, Oklahoma.
13
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 ("PGH") of Austin, Texas, both
independent petroleum engineers with respect to the Company's interests at
December 31, 1998 (using oil and gas prices in effect at December 31, 1998) and
December 31, 1997. 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, 1998, 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, 1998, 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,
---------------------------------------
1998 1997
---------------------------------------
Gas (per Mcf)............................ $2.12 $ 2.34
Oil (per Bbl)............................ $9.42 $16.08
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.
14
Results of drilling, testing, and production subsequent to the date of the
estimate may justify revision of such estimate. Future prices received for the
sale of oil and gas will likely be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.
Except for the effect of changes in oil and gas prices, no major discovery
or other favorable or adverse event is believed to have caused a significant
change in these estimates of the Company's Proved Reserves since December 31,
1998. 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, 1998.
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, 1998
and 1997.
Estimated Proved Oil and Natural Gas Reserves (1)
At December 31,
---------------------------------------
1998 1997
---------------------------------------
Net gas reserves (Mcf):
Proved developed producing........................... 173,220,374 154,749,340
Proved developed non-producing....................... 1,767,000 215,056
Proved undeveloped................................... 44,072,300 52,811,374
---------------------------------------
Total proved gas reserves.......................... 219,059,674 207,775,770
---------------------------------------
Net oil reserves (Bbl):
(including condensate and NGL)
Proved developed producing .......................... 9,015,703 12,021,950
Proved developed non-producing....................... 458,888 14,284
Proved undeveloped................................... 7,874,050 8,910,181
---------------------------------------
Total proved oil reserves.......................... 17,348,641 20,946,415
---------------------------------------
Total Proved Reserves (Mcfe).............................. 323,151,521 333,454,260
---------------------------------------
Estimated SEC PV-10 of Proved Reserves (1)
At December 31,
---------------------------------------
1998 1997
---------------------------------------
Estimated SEC PV-10 (2) :
Proved developed producing .......................... $ 156,629,617 $ 173,189,655
Proved developed non-producing ...................... 4,355,278 342,473
Proved undeveloped .................................. 18,424,052 38,054,232
---------------------------------------
Total Proved Reserves.............................. $ 179,408,947 $ 211,586,360
---------------------------------------
- -----------
(1) Based upon reserve reports at December 31, 1998 and December 31, 1997
prepared by Ryder Scott and PGH.
(2) 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.
15
Significant Properties
On December 31, 1998, 82% of the Company's Proved Reserves on a Bcfe basis
were located in the Spirit 76 Properties, the Permian Basin Properties and the
Panoma Properties. On such date, the Company's properties included working
interests in 3,059 gross (1,671 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, 1998.
SEC PV-10 (1)
----------------------------------------------------------------------------
Natural Gas
Amount % of Oil Gas Equivalent
(in thousands) Total (Bbl) (Mcf) (Bcfe)
-------------------------------------------- --------------- ---------------
Spirit 76 Properties (2)............. $ 37,593,943 21.0% 978,496 35,721,581 41.59
Permian Basin Properties (2)(3)...... 59,012,596 32.9% 10,650,255 85,237,426 149.14
Panoma Properties (2) .............. 50,989,042 28.4% 2,842,637 76,923,054 93.98
Other (2)(3)......................... 31,813,366 17.7% 2,877,253 21,177,613 38.44
-------------------------------------------- --------------- ---------------
Total ........................ 179,408,947 100.0% 17,348,641 219,059,674 323.15
-------------------------------------------- --------------- ---------------
- ----------
(1) 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.
(2) Based on a reserve report at December 31, 1998 prepared by
Ryder Scott.
(3) Based on reserve reports at December 31, 1998 prepared by PGH.
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,
1998 1997
----------------------------------------
Oil and gas production:
Oil (Mbbl).......................................... 1,141 737
Gas (MMcf).......................................... 14,119 9,614
Natural Gas Equivalents (MMcfe)..................... 20,965 14,037
Average sales price (1):
Oil (per Bbl)....................................... $ 12.67 $ 17.70
Gas (per Mcf)....................................... 2.02 2.24
Natural Gas Equivalents (per Mcfe).................. 2.05 2.46
Oil and gas production lifting costs (per Mcfe) ...... .68 .56
Production taxes and other costs (per Mcfe)(2)........ $ .31 $ .35
- ----------
(1) Before deduction of production taxes and net of hedging results for the
two years ended December 31, 1998.
(2) Includes ad valorem taxes, insurance, bonds, company overhead and net
profits interest.
16
Drilling Activity
The following table sets forth the results of the Company's drilling
activities during the two fiscal years ended December 31, 1998 and 1997.
Gross Wells (a) Net Wells (b)
Year Type of Well Total Producing (c) Dry (d) Total Producing (c) Dry (d)
---- ------------ ----- ------------- ------- ----- ------------- -------
1998 Exploratory
Texas 5 4 1 3.25 2.64 .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
1997 Exploratory
Texas 1 0 1 .2 0 .2
Oklahoma 1 1 0 .25 .25 0
Other 1 0 1 1 0 1
Development
Texas 71 71 0 67.1 67.1 0
Oklahoma 5 2 3 1.24 .51 .73
Other 1 1 0 .5 .5 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.
17
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, 1998. All of these
wells are located in the United States.
Productive Wells
As of December 31, 1998
Gross(1) Net(2)
Location Oil Gas Total Oil Gas Total
- -------- --- --- ----- --- --- -----
Texas...................... 1,438 904 2,342 671 621 1,292
Oklahoma................... 31 361 392 27 160 187
Mississippi................ 4 0 4 3 0 3
New Mexico................. 60 245 305 37 149 186
California................. 14 0 14 1 0 1
Kansas..................... 2 0 2 2 0 2
---------------------------------------------------------------------------------------------------------
Total ............ 1,549 1,510 3,059 741 930 1,671
---------------------------------------------------------------------------------------------------------
- ----------
(1) 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, but do not include injector wells.
(2) 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, 1998.
Developed Undeveloped
Gross (a) Net (b) Gross (a) Net (b)
Texas.............................. 258,664 210,972 75,381 39,373
Oklahoma........................... 93,138 66,370 6,582 3,302
Mississippi........................ 528 452 0 0
New Mexico......................... 41,437 35,420 0 0
California......................... 509 38 0 0
Kansas............................. 80 69 0 0
-------------------------------------------------------------------------------------------------
Total.......................... 394,356 313,321 81,963 42,675
-------------------------------------------------------------------------------------------------
(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.
18
Substantially all of the Company's interests are leasehold working
interests or overriding royalty interests (as opposed to mineral or fee
interests) under standard onshore oil and gas leases. As is customary in the
industry, the Company generally acquires oil and gas acreage without any
warranty of title except as to claims made by, through or under the transferor.
Although the Company has title examined by a landman or title attorney prior to
acquisition of developed 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 1998.
[Rest of page intentionally left blank]
19
PART II
Item 5. Market for Common Equity and Related Stockholder Matters.
The Common Stock 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."
Prior to March 8, 1996, the Common Stock was listed on the American Stock
Exchange Emerging Company Marketplace. At December 31, 1998, there were 3,543
stockholders of record.
Average Daily
Trading Volume
High Low (Shares)
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
1997
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . $6.63 $4.19 96,554
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . $6.31 $5.00 41,845
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . $6.44 $5.00 55,194
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . $7.94 $4.88 159,423
On March 31, 1999, the last reported sale price of the Company's Common
Stock on the American Stock Exchange was $2.88 per share.
The Company has not previously paid any cash dividends on its Common Stock
and does not anticipate paying dividends on its Common Stock in the foreseeable
future. It is the present intention of management to utilize all available funds
for the development of the Company's business activities. The Company may not
pay any dividends on Common Stock unless and until all dividend rights on
outstanding Preferred Stock have been satisfied. The Company's existing credit
facility restricts the payment of cash dividends on the Company's securities.
20
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, 1998, 1997, 1996, 1995 and 1994, which have been derived from the
Company's audited consolidated financial statements and notes thereto, and
unaudited summary pro forma data for the year ended December 31, 1998. The pro
forma data gives effect to the consummation of the TEL Offshore and Spirit 76
Acquisitions and the ONEOK Transaction. The pro forma income statement data and
other data for the year ended December 31, 1998 reflects such adjustments as if
the TEL Offshore and Spirit 76 Acquisitions and the ONEOK Transaction had
occurred on January 1, 1998. The pro forma balance sheet data reflects such
adjustments as if the ONEOK Transaction had occurred on December 31, 1998. The
pro forma financial data does not purport to represent what the Company's
financial position or results of operations would actually have been had the TEL
Offshore and Spirit 76 Acquisition and the ONEOK Transaction in fact occurred on
the assumed date and are not necessarily indicative of future operating results
or financial position. 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."
Year Ended December 31,
Pro forma
1994 1995 1996 1997 1998 1998
---- ---- ---- ---- ---- ----
(dollars in thousands)
Income Statement Data:
Total operating revenues......................... $ 745 $ 649 $16,412 $48,834 $51,400 $ 62,588
1,336 1,692 13,541 39,187 94,362 101,420
Total operating costs and expenses (1)........... ----------------------------------------------------------------------
Operating profit (loss).......................... (591) (1,043) 2,871 9,647 (42,962) (38,833)
Net income (loss) before extraordinary loss...... (546) (968) 509 (2,108) (47,080) (41,639)
Extraordinary loss from early extinguishment
of debt, net of taxes ......................... - - - (1,384) - -
Net Income (loss) ............................... (546) (968) 509 (3,492) (47,080) (41,639)
(580) (617) (406) (875) (875) (4,875)
Dividends applicable to preferred shares......... ----------------------------------------------------------------------
$ (1,126) $(1,585) $ 103 $ (4,367) $(47,955) $(46,514)
Income (loss) applicable to common shares........ ----------------------------------------------------------------------
Income (loss) per common share before
extraordinary item
Basic......................................... $ (0.27) $ (0.28) $ 0.01 $ (0.21) $ (2.26) $ (2.20)
Diluted....................................... $ (0.27) $ (0.28) $ 0.01 $ (0.21) $ (2.26) $ (2.20)
Income (loss) per common share after
extraordinary item
Basic......................................... $ (0.27) $ (0.28) $ 0.01 $ (0.30) $ (2.26) $ (2.20)
Diluted....................................... $ (0.27) $ (0.28) $ 0.01 $ (0.30) $ (2.26) $ (2.20)
Other Data:
EBITDA (2)....................................... $ (297) $ (545) $ 6,166 $ 22,772 $ 22,112 $ 31,597
Capital expenditures (3)......................... $ 1,945 $ 1,244 $41,471 $160,059 $ 70,187 $ 71,529
- --------
(1) Includes in 1998 and pro forma 1998 the write-down of $42,745,000 of oil
and gas properties in the full-cost pool due to ceiling test limitation.
(2) 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.
(3) Capital expenditures include cash expended for acquisitions plus normal
additions to oil and natural gas properties and other
fixed assets.
21
December 31,
-----------------------------------------------------------------------
Pro forma
1994 1995 1996 1997 1998 1998
---- ---- ---- ---- ---- ----
(dollars in thousands)
Balance Sheet Data:
Working capital (deficiency).................... $1,197 $ (916) $ 2,279 $ 2,610 $ (723) $ (723)
Property, plant and equipment, net.............. 7,255 36,405 73,648 221,259 228,436 228,436
Total assets.................................... 9,575 40,065 83,072 251,069 267,142 267,142
Total debt(1)................................... 186 9,612 38,766 161,543 231,020 184,637
Stockholders' equity............................ $8,645 $ 24,496 $ 35,154 $ 72,140 $ 20,992 $ 67,375
- -----------
(1) Consists of long-term debt, including current maturities of long-term
debt, and excluding production payment liabilities of $288,000,
$937,000, $743,000 and $633,000 as of December 31, 1995, 1996, 1997 and
1998, respectively.
The following table sets forth unaudited summary finacial results on a
quarterly basis for the two most recent years.
1998
----------------------------------------------
First Second Third Fourth
----------------------------------------------
(In thousands, except per share data)
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 1,260 973 (46,490)
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)
1997
----------------------------------------------
First Second Third Fourth
----------------------------------------------
Revenues.................................. $ 10,339 $ 9,872 $ 13,389 $15,234
Depreciation, depletion and amortization.. 1,081 3,379 4,147 3,756
Net Operating Profit...................... 1,428 2,039 3,298 2,882
Net Income (Loss) before
extraordinary item...................... 250 (974) (509) (872)
Net Income (Loss)......................... 250 (2,358) (509) (872)
Income (Loss) per common share, basic
Before extraordinary loss............ $ 0.00 $ (0.09) $ (0.05) $ (0.06)
Extraordinary loss................... - (0.10) - -
After extraordinary loss............. 0.00 (0.19) (0.05) (0.06)
Income (Loss) per common share, diluted
Before extraordinary loss............ $ 0.00 $ (0.09) $ (0.05) $ (0.06)
Extraordinary loss................... - (0.10) - -
After extraordinary loss............. 0.00 (0.19) (0.05) (0.06)
22
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.
During 1996, management implemented a business strategy that emphasized
acquisition of long-lived, Proved Reserves with significant exploitation and
development opportunities that management considered to have a lower risk
profile than the Company's historic projects. Prior to 1996 and under prior
management, the Company was primarily focused on developing and selling higher
risk, non-operated exploratory and development projects and did not focus on
acquisitions. In order to improve the economics of acquisitions, the Company
emphasizes strict cost control in all aspects of its business and seeks to
operate its properties wherever possible. The Company also participates, to a
lesser extent, in selected exploration projects on a controlled risk basis.
As a part of the Company's new strategy, in June 1996 the Company acquired
the Panoma Properties for a net purchase price of $34.7 million from Burlington,
which included interests in 520 gas wells in the Texas Panhandle and western
Oklahoma and an associated 427 mile gas gathering system. The Company assumed
operations of approximately 90% of the wells and of the gathering system and
began planning for increased density development drilling on the Panoma
Properties.
In January 1997 the Company purchased for $2.5 million a 50% interest in a
gas processing plant, the McLean Gas Plant, which currently processes 100% of
the gas produced from the Panoma Properties. The Company receives 100% of the
net profits of the plant until it recoups its investment, after which time the
Company will receive 50% of the net profits. At January 31, 1999, the Company
had recouped approximately 54% of its $2.5 million investment. Management
believes that the acquisition of the McLean Gas Plant allows the Company to
capture a significant portion of the profits generated from processing the gas
produced at the Panoma Properties that would otherwise go to third party
processors.
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 consist 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 April 29, 1997 the Company received and accepted two new loan
commitments from Bankers Trust Company, as Agent, and other banks for senior
credit facilities for the Company and several of its subsidiaries. The two new
senior credit facilities were structured as the $130.0 million Credit Facility
with a term of five years and a $60.0 million one year senior subordinated
bridge facility (the "Term Loan Facility") convertible into a five year term
loan. The new credit facilities were conditioned, among other things, upon the
closing of the Permian Basin Acquisition, which took place on April 30, 1997.
The Credit Facility provided the Company the flexibility of choosing a range of
either "LIBOR" or "Prime" based interest rate options. This Credit Facility
replaced the Company's previously existing $100.0 million revolving credit
facility.
On May 29, 1997, the Company placed, through a Rule 144A private placement
offering, $140 million in Senior Notes due 2007. The Notes have a 10% coupon,
with interest payable on June 1 and December 1, commencing on December 1, 1997.
Except for Bluebird Energy, Inc. there is no restriction on the ability of any
consolidated or unconsolidated subsidiary to transfer funds to the Company in
the form of cash dividends, loans or advances. Net proceeds from the sale of the
Senior Notes were used to completely repay the Company's outstanding bridge loan
facility in the principal amount of $60 million with the remaining proceeds used
to repay a substantial portion of the Company's outstanding revolving credit
facility. At that time, the maximum commitment under the revolving credit
23
facility was reduced from $130 million to $75 million, with a borrowing base of
$60 million. The credit facility was amended as of September 30, 1997, to
increase the maximum commitment from $75 million to $125 million, increase the
borrowing base by $5 million to $65 million, and modify the interest expense
coverage ratio test.
On December 18, 1997, the Company acquired a thirty percent (30%)
membership interest in NGTS, LLC., a newly formed wholly-owned subsidiary of
Natural Gas Transmission Services, Inc., a natural gas marketing and trading
company. NGTS, LLC assumed all of the parent company's operations as of December
1, 1997. The Company, as of December 1, 1997, dedicated its natural gas
production to NGTS, LLC for marketing. The Company's $4.35 million acquisition
was completed for a combination of cash ($2.35 million) and promissory notes
($2.0 million) that had equity "put" features. The Company retired the
promissory notes with cash on January 31, 1999.
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, became 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 newly formed 100% owned
subsidiary, Bluebird Energy, Inc. acquired from Spirit 76 natural gas reserves
and associated assets in producing fields located in Oklahoma and Texas
currently producing about 12 million cubic feet of natural gas equivalent per
day. 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
the 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 banks. The maturity date of the bridge
loan facility, as amended, is April 15, 1999. The loan is non-recourse to the
Company. Bluebird has secured a commitment for permanent financing from a bank
providing for a revolving credit facility of $75 million with an initial
borrowing base of $30 million, due three years from the date of closing
(anticipated to be April 15, 1999) with interest rates for both "LIBOR" and
"Base Rate" (Prime).
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.
24
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.
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 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. While
this write-down is not recoverable if prices increase, it should have the effect
of lowering the Company's future depletion rates. Without the benefit of
improvements in pricing subsequent to December 31, 1998, the Company would have
incurred an impairment of $81.2 million. 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
25
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.
Results of Operations For the Years Ended 1997 and 1996
As discussed above, the Company acquired the Panoma Properties in June
1996, the McLean Gas Plant in January 1997, and the Permian Basin Properties in
April 1997. As such, the results of operations for the fiscal year ended 1997
included twelve months of operations for the Panoma Properties and the McLean
Gas Plant and eight months for the Permian Basin Properties, while the
corresponding period in 1996 contained six months of operations for the Panoma
Properties and no results related to the McLean Gas Plant and the Permian Basin
Properties. Unless otherwise stated, the increases in the 1997 period over the
1996 period were a direct result of these acquisitions.
Oil and gas sales were $34.6 million in 1997, a 237% increase over sales of
$10.2 million in 1996. In 1997, the Company sold 737,289 Bbl of oil, a 286%
increase, and 9,614 MMcf of gas, a 259% increase over the prior year. The price
received for oil was $17.70 per Bbl and for gas was $2.24 per Mcf in 1997,
representing a 13% decrease in oil price from $20.46 per Bbl in 1996 and a 5%
decrease in gas price from $2.37 per Mcf in 1996. Oil and gas production costs
increased 192% to $12.8 million in 1997 from $4.4 million in 1996. The gross
operating margin from oil and gas production was $21.8 million in 1997, a 271%
increase over the gross operating margin of $5.9 million in 1996, principally
due to the volume increase of oil and gas sold. On an equivalent unit basis, the
gross margin was $1.55 per Mcfe in 1997 versus $1.53 in 1996, a 1% increase.
Gas gathering, marketing, and processing revenues were $10.3 million in the
1997 period, a 79% increase over revenues of $5.8 million in 1996. Costs from
these activities were $7.9 million in 1997, a 68% increase over costs of $4.7
million in 1996. Gross operating margin was $2.4 million in 1997 versus $1.1
million in 1996, a 125% increase. Total gathering system throughput increased
60% to 20.5 MMcf per day in 1997 compared with 12.8 MMcf per day in 1996. Due to
the McLean Gas Plant acquisition, gas plant processing throughput was 14.9 MMcf
per day in 1997 versus none reported in 1996. Gross operating margin from
gathering operations was $0.22 per Mcf of throughput in 1997 versus $0.23 per
Mcf in 1996. The gross operating margin from gas processing was $0.20 per Mcf of
throughput versus none reported in 1996.
Revenues from oil field services and international sales were $4.0 million
in 1997, an 885% increase over revenues of $396,000 in 1996, principally due to
an increase in sales of Hunter Butcher International, L.L.C. ("Hunter Butcher")
in the amount of $3.4 million. Operating costs were $3.7 million in 1997, a $3.5
million increase over 1996, also principally due to Hunter Butcher. The gross
operating margin from these activities was $223,000 in 1997 versus $129,000 in
the 1996 period. The margin from Hunter Butcher operations was $60,000 in 1997
versus $32,000 in the 1996 period. Oil field services produced an operating
margin of $163,000 in 1997 versus a loss of $97,000 in 1996.
Depreciation and depletion expense increased 319% to $12.4 million in 1997
from $3.0 million in 1996 due to the acquisitions. Depletion expense on oil and
gas production in 1997 was $11.6 million, or $0.82 per Mcfe, in 1997 versus $2.6
million, or $0.70 per Mcfe, in 1996. General and administrative expense
increased 92% to $2.4 million in 1997 from $1.2 million in 1996, due to
increased staffing and other costs as a result of the acquisitions and increased
activity levels of the Company.
26
Operating profit increased to $9.6 million in 1997 from $2.9 million in
1996, a 236% increase. Equity in earnings of affiliate, net of income tax, was
$6,000 in 1997 versus none reported in 1996 due to the NGTS acquisition in
December, 1997. Other income increased 122% to $762,000 due to gain on sale of
marketable securities. Interest expense increased to $13.8 million in 1997 from
$2.4 million in 1996, an increase of 476%, due to increased levels of borrowing
under the Company's revolving credit lines, the Notes, and bridge financing used
to fund the acquisitions previously mentioned. The Company incurred a net loss
before income tax and minority interest of $3.4 million in 1997, versus net
income of $821,000 in 1996, principally due to interest expense on the
acquisitions exceeding operating income and due to the higher charge for
depreciation and depletion. The Company provided for a deferred income tax
benefit of $1.3 million on this loss in 1997 versus deferred income tax expense
of $312,000 in 1996. After recording a $19,000 minority interest loss in Hunter
Butcher, the Company reported a net loss in 1997 before extraordinary items of
$2.1 million, or $0.21 per common share, versus a $509,000 net profit, or $.01
per common share, in 1996.
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. The early extinguishment was a result of the Notes
financing and new amended revolving credit agreements with banks arranged to
repay the Company's previous credit facility in conjunction with the purchase of
the Permian Basin Properties from Burlington. The net loss in 1997, after the
extraordinary charge, applicable to common shareholders was $4.4 million ($0.30
per common share) compared to net income of $103,000 ($.01 per common share) in
1996. The Company accrued $875,000 in dividends on its preferred stock in 1997
versus $406,000 in 1996.
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 December 1996 the Company issued $10.0 million of TCW Preferred Stock to
facilitate its development drilling program.
On April 30, 1997 the Company closed the acquisition of the Permian Basin
Properties for a net purchase price of approximately $133.8 million. At the same
time, the Company's previously existing $100.0 million credit facility was
replaced by two new credit facilities; a $130.0 million Credit Facility and a
$60.0 million Term Loan Facility for a combined aggregate amount of $190.0
million. The initial advances under these new facilities totaled $179.5 million,
including funds to complete the Permian Basin Acquisition, to pay principal and
accrued interest remaining on the Company's previous credit facility, and to
provide cash for working capital purposes.
On May 29, 1997 the Company sold, through a Rule 144A private placement
offering, $140.0 million aggregate principal amount of Notes. Net proceeds from
the sale of the Notes were used to completely repay the Company's Term Loan
Facility in the principal amount of $60.0 million and to repay a substantial
portion of the indebtedness outstanding under the Credit Facility. The Notes
bear interest at 10% per annum, with interest payable on June 1 and December 1
commencing on December 1, 1997. After paydown, the maximum commitment under the
Credit Facility was reduced from $130.0 million to $75.0 million, with a
Borrowing Base of $60.0 million. The Credit Facility was amended effective
September 30, 1997 to increase the maximum commitment from $75.0 million to
$125.0 million, increase the Borrowing Base by $5.0 million to $65.0 million and
modify the Consolidated EBITDA to Interest Expense ratio. In July 1998, the
Credit Facility was enhanced by extending the term of the facility from four to
five years, improving the tests concerning certain financial covenants which the
Company must meet, and lowering interest rate spreads by 1/4 percent. In
December 1998, the Credit Facility was amended to allow for a temporary increase
of the borrowing base to $70 million in anticipation of the sale of preferred
stock described below. With these adjustments, total long-term debt under the
Credit Facility at December 31, 1998 was $65 million, leaving
27
$5 million available to draw at such time, prior to the next borrowing base
redetermination. At December 31, 1998, the Company had $4.9 million in cash and
cash equivalents a working capital deficiency of $723 thousand, in addition to
the funds available under the Credit Facility.
The Company called for redemption on November 14, 1997 its publicly traded
Warrants, each of which was exercisable for three shares of Common Stock at an
exercise price of $5.50 per share and redeemable at $0.02 per Warrant. As a
result, Warrants were exercised for an aggregate of 846,256 shares of Common
Stock and the remaining Warrants covering 7,920 shares of Common Stock were
redeemed. The Company received cash proceeds of approximately $4.7 million. In
addition, 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.
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.
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 $1.9 million. In February 1999,
the program was revised to remove the share limitation discussed above.
In December 1998, the Company's 100% owned subsidiary, Bluebird Energy,
Inc., 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
banks. The maturity date of the bridge loan facility, as amended, is April 15,
1999, and is non-recourse to the Company. Bluebird has secured a commitment for
permanent financing from a bank providing for a revolving credit facility of $75
million with an initial borrowing base of $30 million, due three years from the
date of closing (anticipated to be April 15, 1999) with interest rates for both
"LIBOR" and "Base Rate" (Prime).
In December 1998, the Company announced a letter of intent for a strategic
alliance with another 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 will be payable in cash beginning August of
1999 at the rate of 8% per annum and will be cumulative. The net proceeds
received from the sale of Preferred Stock, $46.4 million, was used to repay
senior bank indebtedness.
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 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.
28
For 1996, the Company had a net increase in cash of $143,000. The Company's
operating activities provided net cash of $3.0 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
$41.5 million in investing activities, principally for additions to property and
equipment of $41.5 million, as well as increases in deposits and other assets.
Financing activities provided $38.6 million of cash, principally from the
aggregate proceeds from the issuance of long-term debt of $56.5 million and
production payments of $750,000, less the combined payments on such debt and
production payments totaling $27.5 million, as well as proceeds from the
issuance of preferred stock of $9.8 million. The Company also paid $295,000 to
redeem a portion of the outstanding Series C Preferred Stock and $438,000 to pay
dividends on preferred stock.
Capital Requirements
For fiscal 1999 the Company has budgeted approximately $10 million for
development and exploration activities, including $9 million budgeted for
development projects on the Permian Basin, Panoma Properties and Walker County
and $1 million budgeted for exploration projects. While the Company has not yet
developed a budget for fiscal 2000, the reserve report includes capital
expenditures of approximately $12.7 million on development activities. The
Company is not contractually obligated to proceed with any of its budgeted
capital expenditures. The amount and allocation of future capital expenditures
will depend on a number of factors that are not entirely within the Company's
control or ability to forecast, including drilling results and changes in oil
and gas prices. Due to the recent decline in oil and gas prices, the Company may
redirect some of its budgeted funds or it may defer certain projects until a
later date. As a result, actual capital expenditures may vary significantly from
current expectations.
In connection with the acquisition of 30% of the outstanding common
member's equity of NGTS, the Company was obligated to pay a note of $2.0 million
to current and former shareholders of NGTS. The loan repayment was originally at
the Company's option payable in common stock or cash at December 31, 1998. The
repayment date was amended to February 1, 1999 and was paid on such date by the
Company with cash.
During February 1999, the Company closed its sale of Convertible Preferred
Stock realizing net proceeds of approximately $46.4 million, which were
principally used to repay senior bank indebtedness.
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 $42 million after the sale of Convertible
Preferred Stock in February 1999) will be adequate to meet its anticipated
requirements for working capital, capital expenditures and scheduled interest
payments for the foreseeable future. The Credit Facility contains several
financial loan covenants, one of which in particular, the EBITDA to interest
ratio, is very sensitive to oil and natural gas price levels. While the Company
is in compliance with this covenant at December 31, 1998, a continuation of low
product prices in the future might jeopardize this ratio. The Company has been
considering several alternatives to reduce this risk, including the acquisition
or drilling of higher cash flow producing properties (shorter reserve life) to
somewhat offset its long lived reserve base or monetizing certain non-strategic
assets.
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 would 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 1996, the Company experienced some inflation in oil and gas prices
with moderate increases in property acquisition and development costs. During
1997, the Company received significantly lower (13%) oil prices and slightly
lower (1%) gas prices for the natural resources produced from its properties. In
1998, the Company
29
experienced a further erosion of prices of 28% for oil and 10% gas. Due to the
severity of the decline in prices, the Company experienced a loss from the
write-down of its full cost pool. 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 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. Subsequent to year end 1998, oil prices rose while gas prices
declined slightly.
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
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, 1998, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
Oil
Collar....... 15,000 Bbl Jan 99 - Dec 99 Floor - $15.00
Cap - $19.20
Call Option.. 15,000 Bbl Jan 99 - Dec 99 $19.20
Gas
Swap ........ 100,000 MMBtu Jan 99 - Mar 99 $2.36
Swap......... 600,000 MMBtu Apr 99 - Oct 99 $2.04
Collar....... 600,000 MMBtu Jan 99 - Mar 99 Floor - $2.23
Cap - $2.68
Call Option.. 200,000 MMBtu Jan 99 - Mar 99 $2.75
Net gains and (losses) related to derivative transactions for the years
ended December 31, 1998, 1997 and 1996 were $2,739,000, $(1,537,000) and
$(272,000), respectively. At December 31, 1998, the unrealized gain from
derivative transactions was $1,198,000.
Year 2000 Compliance
Year 2000 issues relate to the ability of computer programs or equipment to
accurately calculate, store or use dates after December 31, 1999. These dates
can be handled or interpreted in a number of different ways, but the most common
errors are for the system to contain a two digit year which may cause the system
to interpret the year 2000 as 1900 or 1980, and the system will not recognize
the year 2000 as a leap year. Errors such as these can result in system
failures, miscalculations and the disruption of operations, including, among
other things, a temporary inability to process transactions, send invoices or
engage in similar normal business activities. In response to the Year 2000
30
issues, the Company has developed a strategic plan divided into the following
phases: inventory, product compliance based on vendor representations and
in-house testing, third party integration and development of a contingency plan.
All of the Company's processing needs are handled by third party systems,
none of which have been substantially modified and all of which have been
purchased or upgraded within the last few years. Therefore, the Company's
initial review of its in-house systems with regard to Year 2000 issues required
an inventory of its systems and a review of the vendor representations. The
Company has completed this initial review of its information systems, various
types of equipment and non-information technology have also been reviewed, and
based on vendor representations, are either compliant, will be compliant with
the next forthcoming software release or are systems that are not date specific.
The Company's non-information technology consists primarily of various oil
and gas exploration and production equipment. The initial review has established
that the primary non-information technology systems functions are either not
date sensitive or are Year 2000 compliant based on vendor representations, and
are therefore predicted to operate in customary manners when faced with Year
2000 issues. However, the Company has determined that in the event such systems
are unable to address the Year 2000, employees can manually perform most, if not
all, functions.
In anticipation of Year 2000 issues, the Company is also evaluating the
Year 2000 readiness status of its third party service suppliers. In addition to
reviewing Year 2000 readiness statements issued by the third parties handling
the Company's processing needs, to date the Company has received and is relying
upon, Year 2000 readiness reports periodically issued by its financial services
and electrical service providers, vendors and purchasers of the Company's oil
and natural gas products. The Company is continuing to review Year 2000
readiness of third party service suppliers and based on their representations,
does not currently foresee material disruptions in the Company's business as a
result of Year 2000 issues. Unanticipated prolonged losses of certain services,
such as electrical power, could cause material disruptions for which no
economically feasible contingency plan has been developed.
The Company is continuing to conduct in-house testing of the core systems
and non-information technology, and to date either all systems tested have
adequately addressed possible Year 2000 scenarios or the Company has a plan in
place to remedy the deficiency. The Company expects testing to be completed
during the second quarter of 1999. After the completion of its Year 2000 review
and testing, the Company will further develop a contingency plan as required,
including replacing or upgrading by December 31, 1999 any system incapable of
addressing the Year 2000 correctly. This final step is expected to be completed
during the third quarter of 1999.
Although the effects of Year 2000 issues cannot be predicted with
certainty, the Company believes that the potential impact, if any, of such
events will, at most, require employees to manually complete otherwise automated
tasks or calculations, other than those which might occur in a "worst case"
scenario as described below, which the Company does not anticipate will occur.
After considering Year 2000 effects on in-house operations, the company
expects a minimal level of additional training would be required to perform
these tasks on a manual basis due to the level of experience of its personnel
and the routine nature of the tasks being performed. If, based on the results of
its in-house testing, the Company should determine that certain systems are not
Year 2000 compliant and it appears as though the system is not likely to be
compliant within a reasonable time period, the Company will either elect to
perform the task manually or will attempt to purchase a different system for
that particular task and convert before December 31, 1999. The Company does not
believe that either option would impact the Company's ability to continue
exploration drilling, production or sales activities, although the tasks may
require additional time and personnel to complete the same functions or may
require incremental time and personnel during 1999 for a conversion to a new
system.
The Company's core business consists primarily of oil and gas acquisitions,
development and exploration activities. The equipment that is deemed "mission
critical" to the Company's activities requires external power sources such as
electricity supplied by third parties. Although the Company maintains limited
on-site secondary power
31
sources such as generators, it is not economically feasible to maintain
secondary power supplies for any major component of its "mission critical"
equipment. Therefore, the most reasonably likely worst case Year 2000 scenario
for the Company would involve a disruption of third party supplied electrical
power, which would result in a substantial decrease in the Company's oil
production. Such event could result in a business interruption that could
materially affect the Company's operations, liquidity or capital resources.
The Company has initiated the third party integration phase and will
continue to have formal communications with its significant suppliers, business
partners and key customers to determine the extent to which the Company is
vulnerable to either the third parties or its own failure to correct their Year
2000 issues. The Company has been communicating with such third parties to keep
them informed of the Company's internal assessment of its Year 2000 review and
plans. This portion of the review and discussions with third parties is expected
to be completed during the second quarter of 1999. To date, approximately
three-quarters of these third parties have provided certain favorable
representations as to their Year 2000 readiness and received similar
representations from the Company. There can be no guarantee that the systems of
other companies on which the Company relies will be timely converted or that the
conversion will be compatible with the Company's systems. However, after
reviewing and estimating the effects of such events, the Company's contingency
plan involves identifying and arranging for other vendors, purchasers and third
party contractors to provide such services, if necessary, in order to maintain
its normal operations.
The Company has, and will continue to, utilize both internal and external
resources to complete tasks and perform testing necessary to address the Year
2000 issue. The Company has not incurred, and does not anticipate that it will
incur, any significant costs relating to the assessment and remediation of Year
2000 issues.
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 2000, 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. 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
32
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 applies 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 March 1, 1999, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
Oil
Collar............. 15,000 Bbl Jan 99 - Dec 99 Floor - $15.00
Cap - $19.20
Call Option........ 15,000 Bbl Jan 99 - Dec 99 $19.20
Gas
Swap .............. 100,000 MMBtu Jan 99 - Mar 99 $2.36
Swap............... 600,000 MMBtu Apr 99 - Oct 99 $2.04
Swap............... 555,000 MMBtu March 99 $1.796
Collar ............ 600,000 MMBtu Jan 99 - Mar 99 Floor - $2.23
Cap - $2.68
Call Option........ 200,000 MMBtu Jan 99 - Mar 99 $2.75
Based on future market prices at December 31, 1998, the fair value of the
open contracts was $1,198,000. If future market prices were to increase 10% from
those in effect at December 31, 1998, the fair value of the open contracts would
be $(236,000). If future market prices were to decline 10% from those in effect
at December 31, 1998, the fair value of the open contracts would be $2,682,000.
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.
[Rest of page intentionally left blank]
33
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 Company does not hold or
issue derivative financial instruments for trading purposes.
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) 1999 2000 2001 2002 2003 2004-2006 2007 Total Fair Value
---- ---- ---- ---- ---- --------- ---- ----- ----------
Variable Rate Debt:
Bank Debt (1).............. $ - $ - $ - $26,000 $65,000 $ - $ - $ 91,000 $ 91,000
Fixed Rate Debt:
Senior Notes (2)........... $ - $ - $ - $ - $ - $ - $140,000 $140,000 $117,600
Other (3).................. $2,020 $ - $ - $ - $ - $ - $ - $ 2,020 $ 2,020
- ------------
(1) The average interest rate on the bank debt is 7.6%. (2) The interest rate on
the senior notes is a fixed 10%. (3) The average interest rate on the other
notes is 8.9%.
[Rest of page intentionally left blank]
34
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, 1998 and 1997..................F-2
Consolidated Statements of Operations and Comprehensive Income
for the Years Ended December 31, 1998, 1997 and 1996.....................F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1998, 1997 and 1996.............................F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1998, 1997 and 1996...................................F-5
Notes to Consolidated Financial Statements...................................F-6
Supplemental Information (Unaudited)........................................F-26
35
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, 1998, and 1997, and
the related statements of operations and comprehensive income, stockholders'
equity, and cash flows for the three years ended December 31, 1998. 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 generally accepted auditing
standards. 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, 1998 and 1997, and
the results of their operations and its cash flows for the three years ended
December 31, 1998, in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Dallas, Texas
April 6, 1999
F-1
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands of dollars)
December 31, December 31,
1998 1997
-----------------------------------
ASSETS
Current Assets
Cash and cash equivalents................................................ $ 4,853 $ 3,030
Restricted cash ......................................................... 459
Accounts receivable
Trade, net of allowance of $166 for 1998 and 1997................... 5,686 12,850
Due from affiliates................................................. 310 58
Notes receivable from affiliate.......................................... 747 355
Current portion of long-term notes receivable, net of
allowance of $790 and $200............................................. 57 357
Prepaid and other........................................................ 1,577 1,299
-----------------------------------
Total Current Assets............................................... 13,689 17,949
-----------------------------------
Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved........................................................... 1,655 517
Proved............................................................. 296,545 227,389
Pipelines................................................................ 9,131 9,166
Other property........................................................... 1,554 776
-----------------------------------
Total Property, Plant and Equipment...................................... 308,885 237,848
Accumulated depreciation, depletion, amortization and impairment... (80,449) (16,589)
-----------------------------------
Net Property, Plant and Equipment........................................ 228,436 221,259
-----------------------------------
Other Assets
Deposits and other assets................................................ 6,644 5,863
Investment in unconsolidated affiliate................................... 4,266 4,372
Deferred tax asset ...................................................... 13,351 -
Long-term notes receivable, net of imputed interest...................... 756 1,626
-----------------------------------
Total Assets $ 267,142 $ 251,069
-----------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities................................... $ 11,821 $ 9,235
Dividends payable........................................................ 219 219
Suspended revenue payable................................................ 359 1,162
Current maturities of long-term debt..................................... 13 24
Notes payable............................................................ 2,000 4,699
-----------------------------------
Total Current Liabilities.......................................... 14,412 15,339
-----------------------------------
Long-Term Liabilities
Long-term debt, less current maturities.................................. 231,007 161,519
Production payment liability............................................. 633 743
Deferred income taxes.................................................... - 1,289
Minority interest........................................................ 98 39
Commitments and Contingencies (Note 11)
Stockholders' Equity
Preferred stock - $.001 par value; 10,000,000 shares authorized,
216,000 designated as Series A; 80,000 issued and outstanding,
liquidation amount $0................................................ - -
1,000,000 designated as 1996 Series A Convertible; 1,000,000
issued and outstanding, liquidation amount $10,000,000............... 1 1
Common Stock - $.002 par value; 50,000,000 shares authorized,
21,738,320 shares issued............................................. 43 43
Additional paid-in capital............................................... 80,000 80,731
Accumulated other comprehensive income................................... (1,429) -
Accumulated deficit...................................................... (55,714) (8,634)
-----------------------------------
22,901 72,141
Treasury stock, at cost
(1,054,507 and 538,633 shares of common stock, respectively) (1,909) (1)
-----------------------------------
Total Stockholders' Equity.................................................... 20,992 72,140
-----------------------------------
Total Liabilities and Stockholders' Equity.................................... $ 267,142 $ 251,069
-----------------------------------
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, except for per share amounts)
For the Years Ended
December 31,
----------------------------------------------------
1998 1997 1996
----------------------------------------------------
Operating Revenues:
Oil and gas sales.......................................... $ 43,565 $ 34,569 $ 10,248
Gas gathering, marketing and processing.................... 6,954 10,297 5,768
Oil field services and international sales................. 881 3,968 396
----------------------------------------------------
Total Operating Revenues............................. 51,400 48,834 16,412
----------------------------------------------------
Operating Costs and Expenses:
Oil and gas production lifting costs....................... 14,265 7,901 4,390
Production taxes and other costs........................... 6,417 4,911 -
Gas gathering, marketing and processing.................... 5,750 7,909 4,708
Oil field services and international sales................. 467 3,745 267
Depreciation, depletion and amortization................... 21,757 12,363 2,951
Write-down of oil and gas properties ...................... 42,745 - -
General and administrative................................. 2,961 2,358 1,225
----------------------------------------------------
Total Operating Costs and Expenses................... 94,362 39,187 13,541
----------------------------------------------------
Operating Profit (Loss)....................................... (42,962) 9,647 2,871
Equity in earnings (loss) of affiliate, net of income tax.. (116) 6 -
Other income............................................... 572 762 344
Interest expense........................................... (18,207) (13,788) (2,394)
----------------------------------------------------
Net Income (Loss) before income tax and minority interest..... (60,713) (3,373) 821
Benefit (Provision) for deferred income tax................ 13,670 1,284 (312)
----------------------------------------------------
Net Income (Loss) before minority interest.................... (47,043) (2,089) 509
Minority interest in subsidiary earnings (loss)............ (37) (19) -
----------------------------------------------------
Net Income (Loss) Before Extraordinary Loss................... (47,080) (2,108) 509
Extraordinary Loss From Early Extinguishment of Debt, net of
tax benefit of $848........................................... - (1,384) -
----------------------------------------------------
Net Income (Loss)............................................. (47,080) (3,492) 509
Dividends Applicable to Preferred Stock.................... (875) (875) (406)
----------------------------------------------------
Income (Loss) Applicable to Common Shares..................... $ (47,955) $ (4,367) $ 103
----------------------------------------------------
Net Income (Loss) $ (47,080) $ (3,492) $ 509
Other Comprehensive Income, net of tax
Sale of Investment Shares.................................. - (51) (57)
Unrealized Gain (Loss) on Investments...................... (1,429) - 51
----------------------------------------------------
Comprehensive Income (Loss) $ (48,509) $ (3,543) $ 503
----------------------------------------------------
Income (Loss) per Common Share - Basic
Before Extraordinary Loss.................................. $ (2.26) $ (0.21) $ 0.01
Extraordinary Loss......................................... - (0.09) -
----------------------------------------------------
After Extraordinary Loss................................... $ (2.26) $ (0.30) $ 0.01
----------------------------------------------------
Income (Loss) per Common Share - Diluted
Before Extraordinary Loss.................................. $ (2.26) $ (0.21) $ 0.01
Extraordinary Loss......................................... - (0.09) -
----------------------------------------------------
After Extraordinary Loss................................... $ (2.26) $ (0.30) $ 0.01
----------------------------------------------------
Common Shares Used in Per Share Calculation
Basic ..................................................... 21,189,516 14,535,805 12,485,893
----------------------------------------------------
Diluted ................................................... 21,189,516 14,535,805 12,561,760
----------------------------------------------------
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, 1998, 1997 and 1996
(dollars in thousands)
Preferred Stock Common Stock Treasury Stock
Shares Amount Shares Amount Shares Amount
---------------------------------------------------------------------------------
Balance at December 31, 1995....................... 767,050 $ 1 11,598,183 $ 23 - $ -
Conversion of preferred stock to common stock... (658,934) (1) 1,821,638 4
preferred stock................................. (28,116) -
Issuance of 1996 Series A convertible preferred
stock, net of offering costs................. 1,000,000 1
Shares issued as collateral, returned and held as
treasury stock............................... 610,170 1 (610,170) (1)
Exercise of employees' common stock options...... 12,258
Issuance of common stock to acquire oil and gas
properties..................................... 188,410 1 51,300
Sale of investment shares........................
Dividends declared on preferred stock............ 34,421 - 2,117
Net income from operations.......................
Unrealized gain on investments...................
---------------------------------------------------------------------------------
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 from operations.........................
Unrealized (loss) on investments.................
---------------------------------------------------------------------------------
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 from operations ........................
Unrealized (loss) on investment .................
---------------------------------------------------------------------------------
Balance at December 31, 1998....................... 1,080,000 $ 1 21,738,320 $ 43 (1,054,507) $(1,909)
---------------------------------------------------------------------------------
Additional Accumulated Other
Paid-In Comprehensive Accumulated
Capital Income Deficit
---------------------------------------------------------------------------------
Balance at December 31, 1995....................... $ 29,660 $ 57 $ (5,245)
Conversion of preferred stock to common stock... (3)
Redemption of 28,116 shares of Series C
preferred stock................................. (294)
Issuance of 1996 Series A convertible preferred
stock, net of offering costs................. 9,785
Shares issued as collateral, returned and held as
treasury stock............................... (1)
Exercise of employees' common stock options...... 9
Issuance of common stock to acquire oil and gas
properties..................................... 938
Sale of investment shares........................ (57)
Dividends declared on preferred stock............ 122 (406)
Net income from operations....................... 509
Unrealized gain on investments................... 51
---------------------------------------------------------------------------------
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 from operations......................... (3,492)
Unrealized (loss) on investments................. (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 from operations ........................ (47,080)
Unrealized (loss) on investment ................. (1,429)
---------------------------------------------------------------------------------
Balance at December 31, 1998....................... $ 80,000 $ (1,429) $ (55,714)
---------------------------------------------------------------------------------
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,
----------------------------------------------------
1998 1997 1996
----------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income (loss).......................................................... $ (47,080) $ (3,492) $ 509
Adjustments to reconcile net income (loss) to cash provided by
(used for) operating activities:
Extraordinary loss...................................................... - 1,384 -
Depreciation, depletion and amortization................................ 21,757 12,363 2,951
Write-down of oil and gas properties ................................... 42,745 - -
Amortization of financing fees.......................................... 793 508 -
Increase in reserve for doubtful accounts............................... 591 322 -
Deferred income taxes................................................... (13,670) (1,284) 312
Equity in unconsolidated affiliate...................................... 116 (6) -
Minority interest....................................................... 37 19 -
(Gain) Loss on sale of assets........................................... 52 (386) (143)
Other................................................................... (83) 93 32
Changes in certain assets and liabilities
Accounts and notes receivable........................................ 6,859 (8,295) (3,250)
Other current assets................................................. (278) (1,247) (30)
Accounts payable and accrued liabilities............................. 1,849 5,673 2,647
----------------------------------------------------
Net Cash Provided By Operating Activities.................................. 13,688 5,652 3,028
----------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets............................................... 359 593 318
Additions to property and equipment........................................ (70,187) (160,059) (41,471)
Increase in deposits and other assets...................................... (3,878) (6,159) (527)
Loan made for promissory note receivable................................... (1,691) (237) (58)
Payments received on promissory note receivable ........................... 28 256 277
Other long-term investments................................................ - (361) -
Investment in unconsolidated affiliate..................................... - (2,362) -
----------------------------------------------------
Net Cash Used In Investing Activities...................................... (75,369) (168,329) (41,461)
----------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of long-term debt and production payment........ 80,000 352,500 57,262
Fees paid related to financing activities.................................. - (1,800) -
Proceeds from short-term notes payable..................................... - 2,699 -
Payments of principal on long-term debt and production payment............. (10,633) (229,917) (27,459)
Payment of short-term notes payable ....................................... (2,699) - -
Payments of other liabilities.............................................. - - (290)
Payment of fees on issuance of preferred stock............................. - (505) -
Proceeds from issuance of common and preferred stock,
net of offering costs................................................... 78 41,721 9,796
Redemption of preferred stock.............................................. - - (295)
Purchase of treasury stock ................................................ (1,908) - -
(Decrease) in segregated funds for payment of notes payable ............... (459) - -
Dividends paid............................................................. (875) (678) (438)
----------------------------------------------------
Net Cash Provided By Financing Activities.................................. 63,504 164,020 38,576
----------------------------------------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS..................................... 1,823 1,343 143
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.............................. 3,030 1,687 1,544
----------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................................... $ 4,853 $ 3,030 $ 1,687
----------------------------------------------------
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 a natural gas
processing plant located in Texas.
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 consolidated
on a pro rata basis its 40% ownership of TEL Offshore Trust. The Company
accounts for its investment in NGTS, Inc. 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 not presented separate financial statements
and other disclosures concerning each Guarantor because management has
determined that such information is not material to investors. 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 at December 31, 1998 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. There was no restricted cash at December 31,
1997.
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, 1997, the Company had no securities available for sale and
no gross unrealized gains reported in equity. During 1997, securities were sold
for gross proceeds of $483,500 and the Company realized a gain of $330,000.
At December 31, 1998, the Company's available for sale securities were
classified as non-current assets and included in deposits and other assets. 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 $1,655,000 and $517,000 at
December 31, 1998 and 1997, 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.
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.
Comprehensive Income
SFAS No. 130, "Reporting Comprehensive Income," became effective as of the
first quarter of 1998. This statement requires companies to report and display
comprehensive income and its components (revenues, expenses, gains and losses).
Comprehensive income includes all changes in equity during a period except those
resulting from investments by owners and distributions to owners. The Company
had an unrealized loss on investments of $1,429,000 (net of income tax benefit
of $876,000) at December 31, 1998, resulting in a comprehensive loss for the
year ended December 31, 1998, of $48,509,000.
For the year ended December 31, 1997, the Company recognized gains from
sale of investments of $330,000 in net income, and a loss from sale of
investment shares of $51,000 (net of income tax benefits of $31,000) in
comprehensive income, resulting in a comprehensive loss of $3,643,000.
F-8
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
At December 31, 1996, the Company recognized a gain from sale of securities
of $143,000 in net income, booked an unrealized gain on investments of $51,000
(net of income tax of $31,000) and realized a loss from the sale of investment
shares of $57,000 (net of income tax benefit of $35,000) in comprehensive
income, resulting in comprehensive income of $503,000.
Changes in Accounting Standards
SFAS 131, "Disclosures About Segments of an Enterprise and Related
Information," became effective in 1998. This statement establishes standards for
defining and reporting business segments. The Company has determined it has
three reportable segments, (1) Exploration and Production, (2) Gas Gathering,
Marketing and Processing and (3) Oil Field Services. The adoption of SFAS 131
does not affect the Company's consolidated financial position, results of
operations or cash flows.
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities,"
is effective for fiscal years beginning after June 15, 1999. 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, 1998 and 1997 and were not
included in the calculation of income or loss per common share.
Use of Estimates and Certain Significant Estimates
The preparation of the Company's financial statements in conformity with
generally accepted accounting principles 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 June 28, 1996, the Company purchased 470 gas wells and approximately 427
miles of a gas gathering pipeline system for a net purchase price of $34.7
million. The properties are located in the Panhandle of Texas and western
Oklahoma and are referred to as the "Panoma Properties." As the purchase was not
completed until the end of the second quarter of 1996, the consolidated
financial statements for 1996 include the operating results of the Panoma
Properties for only the last six months of the year.
In January 1997, the Company purchased a fifty percent (50%) interest in
the McLean Gas Plant, the gas processing facility connected to the Company's
Panoma gas gathering system for $2.5 million. Under the terms of the purchase
agreement, the Company will receive 100% of the net profits of the plant until
it receives the $2.5 million purchase price at which point its net profits
interest will revert to fifty percent (50%), the Company's ownership position.
F-9
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On April 30, 1997, the Company acquired from a subsidiary of Burlington
Resources, Inc., effective as of January 1, 1997, the Permian Basin Properties,
consisting of 25 field areas in west Texas and 22 field areas in southeast New
Mexico, for a net purchase price of $133.8 million after adjustments of $9.7
million for production cash flow from January 1, 1997 to the closing date and
other minor adjustments.
On December 18, 1997, the Company acquired a thirty percent (30%)
membership interest in NGTS, LLC, ("NGTS") a newly formed wholly-owned
subsidiary of Natural Gas Transmission Services, Inc., a natural gas marketing
and trading company based in Dallas, Texas. NGTS assumed all of the parent
company's operations as of December 1, 1997. The Company dedicated substantially
all of its natural gas production to NGTS for marketing. The Company's $4.35
million acquisition was completed with a combination of cash ($2.35 million) and
promissory notes ($2.0 million), which were paid in cash on February 1, 1999.
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 currently producing about 16.2
million cubic feet of natural gas equivalent per day. The net purchase price was
approximately $25 million after certain purchase price adjustments including
preferential rights exercised by third parties and other customary adjustments.
The following summary, prepared on a pro forma basis, presents the results
of operations for the years ended December 31, 1998 and 1997, 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:
1998 1997
----------------------------------------
(Unaudited)
----------------------------------------
Revenue.............................................. $ 62,588,000 $ 76,547,000
Net Income (Loss) Applicable to Common Stock
before extraordinary items......................... (46,514,000) (2,287,000)
Net Income (Loss) Per Common Share before
extraordinary items Basic.......................... $ (2.20) $ (.16)
Diluted............................................ $ (2.20) $ (.16)
NOTE 3 -- NOTES RECEIVABLE
On July 28, 1995, the Company received a non-interest bearing note
receivable in the amount of $223,500 in exchange for its interest in an oil and
gas property. Interest at 10 percent was imputed on the note resulting in a
discount of $28,366. The note provides for payments of $7,000 per month which
were received timely in 1997. As of December 31, 1997, the unpaid balance, net
of discount, was $27,705. This note was paid off in 1998.
F-10
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On November 4, 1996, the Company received an interest bearing note due on
November 1, 1999, in exchange for its interest in oil and gas properties.
Interest is at the rate of 12% per annum. The note was collateralized by the oil
and gas properties sold. As of December 31, 1997, the unpaid balance was
$1,598,238. During 1998, the required payments under the note were not made, and
the Company took possession of the properties. The Company recorded an
impairment to the properties of $579,000 at the time it took possession.
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, 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 and $353,071 at December 31, 1998 and
1997, respectively, 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,
1999.
Through December 31, 1998, the Company loaned the Magnum Hunter Employee
Stock Ownership Plan (ESOP) a total of $878,997 (of which $756,000 is classified
as long-term at December 31, 1998)for purposes of purchasing Magnum Hunter
Resources Common Stock on the open market. The loan is interest free and is due
December 31, 2003. The loan is secured by 291,300 shares of the Company's Common
Stock.
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. Provided the Company does not consummate a
business transaction with the publicly traded oil and gas company by the end of
1999, 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. The loan bears interest at
10% and is due December 31, 1999. Subsequent to December 31, 1998, $65,000 was
repaid on the loan.
During 1996, as part of the Company's overall compensation package, the
Company's officers and directors were granted the right to participate in
certain development and exploration projects of the Company on a promoted basis.
As of December 31, 1996, eleven (11) of the Company's officers and directors as
a group spent an aggregate of $137,340 participating in 6 wells. The Company
discontinued this program as of January 1, 1997.
F-11
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 5 -- DEBT
Notes Payable and Long-term debt at December 31, 1998 and 1997 consisted of
the following:
1998 1997
---------------------------------------
Notes Payable:
Note payable to bank, due March 3, 1998,
including interest at 8.25%.............................................. $ - $ 2,699,000
Note payable, secured by stock in NGTS, LLC., due February 1, 1999,
interest payable at 9% quarterly
beginning March 31, 1998................................................ 2,000,000 2,000,000
---------------------------------------
Total Notes Payable............................................... $ 2,000,000 $ 4,699,000
---------------------------------------
Long-Term Debt:
Banks
Revolving promissory note, collateralized by pipeline and
oil and gas properties, due April 30, 2003
(effective rate of 6.81% at December 31, 1998) (1)....................... $ 65,000,000 $ 21,500,000
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) (2) ..................... $ 26,000,000 -
Note payable to bank collateralized by vehicle, payable in monthly
installments of $1,031 including interest at 8.5% through
February 1999............................................................ 2,000 13,000
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, assumed in
Hunter acquisition....................................................... 18,000 30,000
---------------------------------------
Total Long-Term Debt.............................................. $231,020,000 $161,543,000
Less Current Portion.......................... 13,000 24,000
---------------------------------------
Long-Term Debt............................................ $231,007,000 $161,519,000
---------------------------------------
F-12
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:
1999...................................................... $ 13,000
2000...................................................... 7,000
2001...................................................... -
2002...................................................... 26,000,000
2003 to 2006.............................................. 65,000,000
2007...................................................... 140,000,000
-----------------
$ 231,020,000
=================
(1) 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
$70,000,000 at December 31, 1998. 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, 1998, the amounts borrowed
at these rates were:
LIBOR + 1.5% (total of 6.81%)............................. $ 65,000,000
Base Rate (Prime) at 7.75%................................ -
-----------------
Total.............................................. $ 65,000,000
-----------------
(2) 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, is
April 15, 1999. The bridge loan is non-recourse to the Company. Bluebird has
secured a commitment for permanent financing from a bank providing for a
revolving credit facility of $75 million with an initial borrowing base of $30
million, due three years from the date of closing (anticipated to be April 15,
1999) with interest at rate options for both "LIBOR" and "Base Rate" (Prime).
The level of the borrowing base is dependent on the valuation of the assets
pledged, primarily oil and gas reserve values and Bluebird's interest in the TEL
Offshore Trust. 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.
Borrowings under the line of credit are non-recourse to the Company.
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
and $147,000 at December 31, 1998 and 1997, respectively.
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 $540,000 and $596,000 at December 31, 1998 and 1997,
respectively. The production payment bears interest at the rate of 13.5% per
annum and is non-recourse to the Company.
F-13
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 7 -- INCOME TAXES
The Company accounts for income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes", which requires the recognition of a liability or
asset, net of a valuation allowance, for the deferred tax consequences of all
temporary differences between the tax bases and the reported amounts of assets
and liabilities, and for the future benefit of operating loss carryforwards. The
following is a reconciliation of income tax expense reported in the statement of
operations:
1998 1997
-----------------------------------------
Income tax expense (benefit) at statutory rates...................... $ (21,263,000) $ (1,153,000)
State tax expense (benefit).......................................... (1,747,000) (133,000)
Other................................................................ - (288,000)
Change in valuation allowance........................................ 8,370,000 290,000
-----------------------------------------
Tax expense (benefit)......................................... $ (14,640,000) $ (1,284,000)
-----------------------------------------
The tax effects of significant temporary differences and carryforwards are
as follows:
December 31,
------------------------------------------
1998 1997
------------------------------------------
Property and equipment, including intangible drilling costs.......... $ - $ (5,245,000)
------------------------------------------
Total deferred tax liability................................ - (5,245,000)
------------------------------------------
Allowance for doubtful accounts...................................... 414,000 191,000
Reserves............................................................. 33,000 -
Property and equipment, including intangible drilling costs.......... 8,812,000 -
Depletion carryforwards.............................................. 196,000 196,000
Operating loss and other carryforwards............................... 12,556,000 3,859,000
------------------------------------------
Total deferred tax assets................................... 22,011,000 4,246,000
------------------------------------------
Valuation allowance.................................................. (8,660,000) (290,000)
------------------------------------------
Net Deferred Tax Asset (Liability).......................... $ 13,351,000 $ (1,289,000)
------------------------------------------
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 $32,986,000 that expire, if unused, in years 1999 through 2018,
and of which approximately $608,000 expire in 1999. 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.
F-14
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 8 -- STOCKHOLDERS' EQUITY
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 and 1,000,000 shares have been designated as 1996
Series A Convertible Preferred Stock. Thus, 7,234,000 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.
The Series B Preferred Stock was issued as a unit, comprised of 1,000
shares of Series B Preferred Stock and two production certificates. The Series B
preferred stockholders are entitled to receive cumulative dividends of $0.35
annually per share, payable quarterly. The holders of the units are entitled to
receive $10,000 per unit in dividends and in production payments. The production
payments were derived from 50% of the Company's net revenue from production of
oil and gas. Beginning June 15, 1994, the Company offered to exchange (the
"Exchange Offer") 1,250 shares of common stock for each Series B production
certificate. All of the shares were converted to common stock during 1996.
Separate and apart from the Exchange Offer, two of the Company's previous
officers and directors (the "Officers") set aside 125,000 shares (the "Stock")
of their own common stock of the Company for a single individual (the
"Individual") who owned approximately 55% of the Series B production
certificates that were exchanged. The Stock was being held by an independent
party to this transaction until fair market value of the Exchange Shares, when
the Exchange Shares become eligible for sale pursuant to Rule 144 of the
Securities Act of 1933, was determined. The Company issued 125,000 shares of its
common stock to the Officers in exchange for their assignment to the Company of
all of the Officers' rights, title and interest in the Stock. The Company has
recorded the new shares issued at par value. The value of the exchange shares
was determined in 1996, and the Company issued 5,000 shares of its common stock
to the Individual. Subsequent to December 31, 1996, the 125,000 shares being
held were returned to the Company and are being held as treasury stock.
The Series C preferred stock was convertible at the option of the holder at
any time into three shares of common stock and, after November 12, 1994, would
automatically convert into common stock any time the closing bid price of the
common stock equals or exceeds $5.00 per share for twenty consecutive trading
days. The Series C preferred stock was redeemable by the Company beginning
November 12, 1995, at $10.50 per share plus accrued and unpaid dividends. If
declared by the Board of Directors, dividends accrued at the annual rate of
$1.10 per share, were cumulative from the date of first issuance and were paid
quarterly in arrears. The Board of Directors declared dividends on the Series C
preferred stock of $339,827 for the year ended December 31, 1996. The aggregate
annual dividend requirements for the 625,000 shares of Series C preferred stock
outstanding at December 31, 1996 was none. As of December 31, 1996, all Series C
preferred stock had been redeemed or converted to common stock.
F-15
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 $122,000, $875,000 and $875,000 were declared in 1996, 1997 and
1998, respectively.
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.
The Series C preferred stock was originally issued as a unit comprised of
one share of Series C preferred stock and warrants to purchase three (3) shares
of common stock. A total of 1,687,500 warrants were issued 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 and expiring in January 1999. At December 31, 1998, 45,000 of these
warrants had been earned. 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 expiring 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. No warrants were exercised in 1996. At December 31, 1996,
the Company had 1,176,676 total warrants issued, including the publicly traded
warrants. Additionally, in 1996, 610,170 shares of the Company's common stock
that had been held as collateral were returned and held in the treasury, 12,258
shares of common stock were issued upon exercise of employees' stock options,
239,710 shares of common stock, valued at $939,000, were issued to acquire oil
and gas properties, and 36,538 shares of common stock were issued as dividends
on the Company's Series C Preferred Stock.
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. 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. At
December 31, 1998 and 1997, the Company had 166,000 total warrants issued, of
which 141,000 had been earned.
F-16
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 $1.9 million under this program.
Additionally, in 1998, 12,813 shares of the Company's common stock were
contributed to the 401(k) plan, and 96,913 shares were issued upon exercise of
employee stock options.
Earnings Per Share
The following table reconciles the numerators and denominators used in the
computations of both basic and diluted EPS as required by SFAS No. 128,
"Earnings per Share":
For the Year Ended For the Year Ended For the Year Ended
December 31, 1998 December 31, 1997 December 31, 1996
-----------------------------------------------------------------------------------------------------------
Per Per Per
Loss Shares Share Loss Shares Share Income Shares Share
(Numerator) (Denominator)Amount (Numerator) (Denominator)Amount (Numerator) (Denominator) Amount
-----------------------------------------------------------------------------------------------------------
Income (Loss) before
extraordinary item...$(47,080,000) $(2,108,000) $ 509,000
Less: Preferred Stock
dividends.. (875,000) (875,000) (406,000)
-----------------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available
to common stockholders. (47,955,000) 21,189,516 $(2.26) (2,983,000) 14,535,805 $(.21) 103,000 12,485,893 $ .01
Effect of dilutive
securities
Warrants.............. - - - - - 14,943
Options............... - - - - - 60,924
Convertible preferred
stock - - - - - -
Diluted EPS
Income (Loss) available to
common stockholders and
-----------------------------------------------------------------------------------------------------------
assumed conversions...$(47,955,000) 21,189,51 $(2.26) $(2,983,000) 14,535,805 $(.21) $ 103,000 12,561,760 $ .01
-----------------------------------------------------------------------------------------------------------
The warrants, options, and convertible preferred stock were not included in
the computation of diluted earnings per share in 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.
F-17
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION
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.
During 1996, the Company purchased oil and gas properties by issuing
239,710 shares of its common stock, valued at $938,444. The Company converted
658,934 shares of Series B and Series C preferred stock into 1,821,638 shares of
common stock. The Company issued 36,538 shares of common stock valued at
$121,700 in lieu of cash dividends on preferred stock. The Company received
equity securities with a fair value of $150,000 as partial payment for the sale
of property interests. Interest paid in 1996 was $2,344,308.
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.
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 2001 with an
option to renew the lease for a three year term. The various office equipment
leases extend until 2002. 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:
1999............................................................... $ 293,662
2000............................................................... 300,516
2001............................................................... 261,072
2002............................................................... 12,475
Thereafter......................................................... -
-----------
Total Minimum Payments Required $ 867,725
-----------
Rental expense was $327,934, $218,951 and $129,169 for 1998, 1997 and 1996,
respectively.
F-18
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 1998 and 1997, 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, 1998 is adequate.
To the extent the Company receives the spread between the contract floor
and the Index price applies 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 provided a
$590,000 reserve for the carrying value of a note receivable. After establishing
this reserve, management believes those market values approximate carrying
values at December 31, 1998 and 1997. The market values of equity investments
are based upon quoted prices (see Note 1). At December 31, 1998, the fair market
value of the Company's debt was equal to its carrying value, except for the 10%
Senior Notes. The fair market value of the 10% Senior Notes was $117,600,000.
NOTE 13 -- COMMODITY DERIVATIVES AND HEDGING ACTIVITIES
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, 1998, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price Fair Value
Oil
Collar.............. 15,000 Bbl Jan 99 - Dec 99 Floor - $15.00
Cap - $19.20 $ 673,425
Call Option......... 15,000 Bbl Jan 99 - Dec 99 $19.20 -
Gas
Swap ............... 100,000 MMBtu Jan 99 - Mar 99 $2.36 $ 111,000
Swap................ 600,000 MMBtu Apr 99 - Oct 99 $2.04 $ 50,750
Collar ............. 600,000 MMBtu Jan 99 - Mar 99 Floor - $2.23
Cap - $2.68 $ 363,000
Call Option......... 200,000 MMBtu Jan 99 - Mar 99 $2.75 -
F-19
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Net gains and (losses) related to derivative transactions for the years
ended December 31, 1998, 1997 and 1996 were $2,739,000, $(1,537,000) and
$(272,000), respectively. At December 31, 1998, the unrealized gain from
derivative transactions was $1,198,000.
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. The loan is interest free and is due
December 31, 2003. The loan is secured by 291,300 shares of the Company's Common
Stock.
1996 Incentive Stock Option Plan
The Company established this plan effective April 1, 1996, and is governed
by Section 422 of the Internal Revenue Code, and Section 16(b) of the Securities
Exchange Act of 1934. The Option Plan covers 1,200,000 shares of the Company's
Common Stock. Eligibility is limited to employees and directors of the Company
and its subsidiaries. The actual selection of grantees is made by the Board of
Directors. The term of the Option Plan is 10 years, and 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 are fully vested and exercisable when
granted. 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 1996, the Board granted the remaining 935,442 options to employees
and directors at an exercise price of $4.50 per share.
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 5
years.
During 1998, the Board granted 220,000 new options to employees at an
average price of $5.89. 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.
F-20
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The following is a summary of stock option activity under the Option Plan:
1998 1997 1996
----------------------------------------------------------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
----------------------------------------------------------------------------
Outstanding -
Beginning of Year.......... 2,538,500 $ 5.00 1,187,742 $ 3.72 264,558 $ 0.82
Granted.................... 220,000 5.89 1,440,000 5.93 935,442 4.50
Exercised.................. (96,913) .81 (89,242) 3.01 (12,258) .73
Canceled................... - - - - - -
Repriced - previous........ (1,590,000) 5.96 - - - -
Repriced - new............. 1,590,000 3.75 - - - -
----------------------------------------------------------------------------
Outstanding -
End of Year................ 2,661,587 $ 3.90 2,538,500 $ 5.00 1,187,742 $ 3.72
----------------------------------------------------------------------------
Exercisable -
End of Year................ 2,501,587 2,338,500 970,684
----------------------------------------------------------------------------
The following is a summary of stock options outstanding at December 31,
1998:
Weighted
Average
Number of Remaining
Options Contractual Life Number of
Exercise Price Outstanding (Years) Exercisable Options
----------------------------------------------------------------------
$ .73.......................... 102,145 1.0 102,145
1.65........................... 18,000 1.0 18,000
3.75........................... 1,590,000 4.0 1,430,000
4.375.......................... 25,000 3.0 25,000
4.50........................... 881,442 2.3 881,442
5.25........................... 35,000 3.4 35,000
5.375.......................... 10,000 3.3 10,000
----------------------------------------------------------------------
2,661,587 2,501,587
----------------------------------------------------------------------
The Company adopted the disclosures only portion of SFAS No. 123 as it
continues to follow the provisions of APB No. 25, which is the intrinsic value
method of accounting for stock-based compensation.
F-21
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
On a pro forma basis, the effect of stock based compensation had the
Company adopted Statement No. 123 is as follows:
1998 1997 1996
----------------------------------------------------
Net Income (Loss) Applicable to Common Stock:
As reported.............................................. $ (47,955,000) $(4,367,000) $ 103,000
Pro Forma................................................ (49,160,000) (6,573,000) (1,540,000)
Basic Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ (2.26) $ (.30) $ .01
Pro Forma................................................ (2.32) (.45) (.12)
Diluted Earnings (Loss) per Share:
As reported, after extraordinary loss.................... $ (2.26) $ (.30) $ .01
Pro Forma................................................ (2.32) (.45) (.12)
The weighted average grant date fair value of new options granted was
$580,000 during 1998. The weighted average grant date fair value of options
repriced in 1998 was $624,884. Fair value of options and warrants was calculated
by using the Black-Scholes options pricing model using the following weighted
average assumptions for 1998 activity: risk free interest rate of 5.5% on new
options and 5.75% on repriced options, expected life of 5 years on new options
and 4 years on repriced options, expected volatility of 57% and no dividend
yield.
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 and Mr.
Chris Tong each have employment agreements with the Company. Mr. Evans'
agreement terminates January 1, 2003 and continues thereafter on a year to year
basis and provides for a salary of $250,000 per annum. Mr. Lutz's agreement
terminates January 1, 2003 and continues thereafter on a year to year basis and
provides for a salary of $150,000 per annum. Mr. Frazier's agreement terminates
January 1, 2001 and continues thereafter on a year to year basis and provides
for a salary of $150,000 per annum. Mr. Tong's agreement terminates January 1,
2001 and continues thereafter on a year to year basis and provides for a salary
of $150,000 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 and
Mr. Lutz, 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. Frazier and Mr. Tong, the employee shall
receive the greater of (i) the employee's base salary for the remaining term or
any renewal period thereof, or (ii) 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
$5,000,000.
F-22
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 one natural gas liquids processing plant 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.
Segment data for the three years ended December 31, 1998 follows (in
thousands):
Gas Gathering,
Exploration & Marketing &
1998: Production Processing Oil Field 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)
============
Segment assets.......................... $ 233,824 $ 13,729 $ 7,230 $ 12,359 $ 267,142
Equity subsidiary investments........... 4,266 4,266
Capital expenditures (net of asset sales) 70,294 (35) 740 38 71,037
Geographic Information: Revenues Long-Lived Assets
----------------------- --------- -----------------
United States.............. $ 51,400 $ 228,436
Foreign countries.......... - -
----------------------------------
Total...................... $ 51,400 $ 228,436
----------------------------------
F-23
Gas Gathering,
Exploration & Marketing &
1997: Production Processing Oil Field 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)
============
Segment assets.......................... $ 221,272 $ 14,275 $ 5,092 $ 10,430 $ 251,069
Equity subsidiary investments........... 4,372 4,372
Capital expenditures (net of asset sales) 156,872 2,064 395 - 159,331
Geographic Information: Revenues Long-Lived Assets
United States.............. $ 45,436 $ 221,259
Foreign countries.......... 3,398 -
------------------------------------------
Total...................... $ 48,834 $ 221,259
------------------------------------------
Gas Gathering,
Exploration & Marketing &
1996: Production Processing Oil Field Services All Other Elimination Consolidated
----- ---------- ---------- ------------------- --------- ----------- ------------
Revenue from external customers......... $ 10,248 $ 5,768 $ 373 $ 23 $ - $ 16,412
Intersegment revenues................... - 3,999 666 - (4,665)
Depreciation, depletion, amortization and
impairment.............................. 2,599 288 42 22 2,951
Segment profit (loss)................... 2,991 869 (223) (766) 2,871
Interest expense........................ (2,394) (2,394)
Other income............................ 344 344
------------
Earnings before income taxes............ $ 821
Provision for deferred income tax ...... (312) (312)
------------
Net income.............................. $ 509
============
Segment assets.......................... $ 61,281 $ 10,604 $ 1,703 $ 9,484 $ $ 83,072
Equity subsidiary investments........... - -
Capital expenditures (net of asset sales) 33,934 6,015 235 - 40,184
Geographic Information: Revenues Long-Lived Assets
----------------------- --------- -----------------
United States.............. $ 16,389 $ 73,648
Foreign countries.......... 23 -
----------------------------------
Total...................... $ 16,412 $ 73,648
----------------------------------
F-24
NOTE 17 -- SUBSEQUENT EVENTS
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 $46.4 million, to repay senior bank debt.
On February 17, 1999, the Company revised its previously announced stock
repurchase program to spend up to $4 million without a share limitation.
Subsequent to December 31, 1998, the Company repurchased 601,472 shares of its
common stock for $1.7 million.
F-25
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
The changes in Proved Reserves for the years ended December 31, 1997 and
1996 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
--------------------------------------
F-26
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, 1998 and 1997 were as follows:
1998 1997
---------------------------------
Unproved oil and gas properties............................................. $ 1,654,986 $ 516,560
Proved properties........................................................... 296,545,064 227,389,446
---------------------------------
Gross Capitalized Costs..................................................... 298,200,050 227,906,006
Accumulated depreciation, depletion, amortization and impairment............ (79,193,796) (16,091,001)
---------------------------------
Net Capitalized Costs............................................. $ 219,006,254 $ 211,815,005
---------------------------------
Costs incurred in oil and gas producing activities, both capitalized and
expensed, during the years ended December 31, 1998 and 1997 as follows:
1998 1997
-----------------------------------
Property acquisition costs
Proved properties......................................................... $ 36,619,796 $ 137,430,583
Unproved properties....................................................... 1,138,426 57,306
Exploration costs........................................................... 4,696,095 737,936
Development costs........................................................... 27,839,727 18,284,460
-----------------------------------
Total Costs Incurred.............................................. $ 70,294,044 $ 156,510,285
-----------------------------------
Results of operations from oil and gas producing activities for the years
ended December 31, 1998 and 1997 were as follows:
1998 1997
---------------------------------
Oil and gas production revenue............................................. $ 43,564,728 $ 35,658,032
Disposal services revenue.................................................. - 5,130
Production costs........................................................... (20,682,187) (13,901,537)
Depreciation, depletion, amortization and impairment....................... (63,102,795) (11,577,460)
---------------------------------
Results of Operations for Producing Activities $(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, 1998 and 1997 were as
follows:
1998 1997
------------------------------------
Future cash inflows...................................................... $ 625,818,712 $ 811,512,060
Future development and production costs.................................. (278,222,069) (336,730,398)
------------------------------------
Future net cash flows, before income tax................................. 347,596,643 474,781,662
Future income taxes...................................................... - (93,828,793)
------------------------------------
Future Net Cash Flows.................................................... 347,596,643 380,952,869
10% annual discount...................................................... (168,187,696) (211,181,318)
------------------------------------
Standardized Measure of Discounted Future Net
Cash Flows.............................................. $ 179,408,947 $ 169,771,551
------------------------------------
F-27
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, 1998 and 1997 were as
follows:
1998 1997
-------------------------------------
Purchases of minerals-in-place....................................... $ 46,388,818 $ 136,739,277
Sales of minerals-in-place........................................... (8,604) (191,741)
Extensions, discoveries and improved recovery, less related costs 10,836,769 38,555
Sales of oil and gas produced, net of production costs............... (22,882,541) (21,756,495)
Development costs incurred during the period......................... 27,839,727 16,289,428
Revision of prior estimates:
Net change in prices and costs..................................... (61,951,610) (141,112,592)
Change in quantity estimates....................................... (55,991,223) 46,255,955
Accretion of discount................................................ 16,977,155 11,708,486
Net change in income taxes........................................... 48,428,905 4,715,817
-------------------------------------
Net Change.......................................... $ 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-28
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................... 41 Director, President and Chief Executive Officer
Matthew C. Lutz................. 64 Chairman of the Board and Executive Vice President of
Exploration and Business Development
Richard R. Frazier.............. 52 President and Chief Operating Officer of Magnum Hunter
Production, Inc. and Gruy
Chris Tong...................... 42 Senior Vice President and Chief Financial Officer
R. Douglas Cronk . . . . . . . . 51 Senior Vice President of Magnum Hunter Production, Inc. and Gruy
David S. Krueger................ 49 Vice President and Chief Accounting Officer
Morgan F. Johnston.............. 38 Vice President, General Counsel and Secretary
Michael McInerney . . . . . . . 57 Vice President, Corporate Development & Investor Relations
Craig Knight.................... 42 Vice President of Operations of Hunter Gas Gathering, Inc.
Gregory L. Jessup............... 45 Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits.............. 47 Vice President and Controller of Gruy
Gerald W. Bolfing............... 70 Director
Jerry Box....................... 60 Director
Larry W. Brummett............... 48 Director
David L. Kyle................... 46 Director
Oscar C. Lindemann.............. 76 Director
John H. Trescot, Jr............. 73 Director
James E. Upfield................ 78 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, a NASDAQ listed
manufacturing company. He also serves as a Trustee of TEL Offshore Trust, an OTC
listed oil and gas trust.
36
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 of Exploration and Business Development 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 are 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.
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.
37
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.
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.
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.
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.
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.
38
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.
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 last five years, Mr. Trescot has been a principal of AWA
Management Corporation, a professional consulting firm specializing in oil,
timber, pulp and paper, and financial management. Early in his career, Mr.
Trescot held various positions in woodlands, and pulp and paper, advancing to
the position of Senior Vice President, Southern Operations at Hudson Pulp &
Paper Corp. (now part of Georgia Pacific Corp.). Later Mr. Trescot became Vice
President of The Charter Company, a corporation with operations in oil,
communications and insurance. In 1979, Mr. Trescot became the Chief Executive
Officer of "Jari" Florestal e Agropecuaria, Ltda.,a pulp, timber, rice and
kaolin operation in the Amazon Basin of Brazil owned by D.K. Ludwig. In 1981,
Mr. Trescot became the Chief Executive Officer of TOT Drilling Corp., a contract
drilling company with operations in west Texas and New Mexico.
39
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.
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, 1998 (collectively the "Named Executive
Officers").
Long Term Compensation
----------------------------------
Annual Compensation
----------------------------------------- Awards Payout
----------------------------------
(a) (b) (c) (d) (e) (f) (g) (h) (i)
Name, Other Number
Principal Annual Restricted Options LTP All Other
Position Year Salary Bonus Compensation Stock SARs Payouts Compensation
- ----------------------------------------------------------------------------------------------------------------------------
Gary C. Evans 1998 $250,000 $300,000
President and CEO 1997 $200,025 $250,000 - - - - -
1996 $150,000 $100,000 - - - - -
Matthew C. Lutz 1998 $156,000 $100,000
Executive V.P. and 1997 $106,000 $100,000 - - - - -
Chairman 1996 $ 65,600 $ 10,000 - - - - -
Richard R. Frazier 1998 $154,200 $ 50,000
President of 1997 $124,200 $ 50,000 - - - - -
Magnum Hunter 1996 $ 98,350 $ 9,000
Production, Inc.
Chris Tong 1998 $156,000 $ 30,000
Senior Vice President & 1997(1)$ 78,500 $ 25,000 - - - - -
Chief Financial Officer
R. Douglas Cronk 1998 $104,200 $20,000
Senior V.P. of Magnum 1997 $ 92,033 $10,000 - - - - -
Hunter Production, Inc. 1996(2)$ 37,100 $ 3,000
- ---------------------
(1) Mr. Tong was hired in August of 1997.
(2) Mr. Cronk was hired in July of 1996.
40
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of securities
underlying Value of unexercised
unexercised in-the-money
options/SARs at fiscal options/SARs at fiscal
year-end (#) year-end ($)
Shares acquired on Exercisable/ Exercisable/
Name exercise (#) Value Realized ($) unexercisable unexercisable
(a) (b) (c) (d) (e)
Gary C. Evans 89,377 $280,711 650,000 / 0 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 receive a $10,000 retainer for being a board member and in addition
shall receive $1,000 per meeting attended. Each new independent director added
to the board in fiscal year 1999 will be 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 and Mr.
Chris Tong each have employment agreements with the Company. Mr. Evans'
agreement terminates January 1, 2003 and continues thereafter on a year to year
basis and provides for a salary of $250,000 per annum. Mr. Lutz's agreement
terminates January 1, 2003 and continues thereafter on a year to year basis and
provides for a salary of $150,000 per annum. Mr. Frazier's agreement terminates
January 1, 2001 and continues thereafter on a year to year basis and provides
for a salary of $150,000 per annum. Mr. Tong's agreement terminates January 1,
2001 and continues thereafter on a year to year basis and provides for a salary
of $150,000 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 and
Mr. Lutz, 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. Frazier and Mr. Tong, the employee shall
receive the greater of (i) the employee's base salary for the remaining term or
any renewal period thereof, or (ii) 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
$5,000,000.
41
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth certain information as of March 17, 1999,
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
17, 1999, 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 1200,
Irving, Texas 75039.
Common Stock
Beneficially Owned
Number of Percent
Name Shares of Class (12)
Directors and Executive Officers
Gary C. Evans ............................................ 2,164,766 (1) 10.4%
Matthew C. Lutz........................................... 683,388 (2) 3.3%
Richard R. Frazier........................................ 259,213 (3) 1.2%
Chris Tong................................................ 98,951 (4) *
R. Douglas Cronk ......................................... 103,768 (5) *
Gerald W. Bolfing......................................... 363,558 (6) 1.8%
Jerry Box................................................. 0 -
Oscar C. Lindemann........................................ 41,160 (7) *
John H. Trescot, Jr....................................... 87,154 (8) *
James E. Upfield......................................... 87,642 (9) *
David L. Kyle ............................................ 0 -
Larry M. Brummett ........................................ 0 -
All directors and executive officers as a group
(11persons) 3,889,600 18.0%
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 (10) 32.2%
TCW Group, Inc.
865 South Figueroa Street
Los Angeles, CA 90017.................................... 1,904,762 (11) 8.7%
Janus Capital Corporation
100 Fillmore St. , Suite 300
Denver, CO. 80206........................................ 1,800,595 9.0%
- -------------
(1) Includes 650,000 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.
42
(2) Includes 526,073 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(3) Includes 200,000 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(4) Includes 90,000 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(5) Includes 100,000 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(6) Includes 35,536 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(7) Includes 35,536 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(8) Includes 35,000 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(9) Includes 35,536 shares of common stock issuable upon the exercise
of certain currently exercisable options.
(10) 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.
(11) 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.
(12) 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.
During December 1998, the Company's Board of Directors authorized a loan of
up to $300,000 be made available to Gary C. Evans, President and Chief Executive
Officer of the Company, as part of his 1998 compensation package and to exercise
certain stock options. A total of $230,000 was drawn under the loan, and
subsequent to year-end $65,000 was repaid. The balance outstanding at December
31, 1998 was $230,000 and bears interest at 10% and is due December 31, 1999.
The outstanding balance as of March 31, 1999 was $165,000.
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. Provided the
Company does not consummate a business transaction with the publicly traded oil
and gas company by the end of 1999, 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.
43
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.
44
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,
1998, 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, 1998, 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.
45
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
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.
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.
10.5 Employment Agreement for Gary C. Evans (Incorporated by reference
to Registration Statement on Form S-4, File No. 333-2290)
10.6 Employment Agreement for Matthew C. Lutz (Incorporated by
reference to Registration Statement on Form S-4,File No. 333-2290)
10.7 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)
10.8 Registration Rights Agreement, dated May 29, 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)
10.9 Purchase and Sale Agreement, dated May 17, 1996 between Meridian
Oil, Inc. and ConMag Energy Corporation (Incorporated by reference
to Form 8-K, dated June 28, 1996, filed July 12, 1996)
10.10 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)
46
10.11 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)
10.12* Purchase and Sale Agreement dated November 25, 1998 between Magnum
Hunter Production, Inc. and Unocal Oil Company of California
10.13 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
27* Financial Data Schedule
* Filed herewith.
(B) Form 8-K's
A Form 8-K, dated December 14, 1998 was filed by the Company on December
15, 1998 under Item 5 concerning the Company's execution of a Letter of Intent
with ONEOK Inc., the eighth largest natural gas distributor in the United States
relating to ONEOK's purchase of $50 million of Convertible Preferred Stock of
the Company, ONEOK's ability to market the Company's natural gas production in
the state of Oklahoma, ONEOK's ability to participate in future acquisitions of
the Company in the state of Oklahoma and ONEOK's participation in the Company's
acquisition of certain oil and gas assets acquired from Spirit 76.
47
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 April 14, 1999
- ---------------------------------------------
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 April 14, 1999
Gary C. Evans Chief Executive Officer
/s/ Matthew C. Lutz Chairman of the Board and April 14, 1999
- --------------------------
Matthew C. Lutz Executive Vice President of
Exploration and Business
Development
/s/ Chris Tong Senior Vice President and April 14, 1999
- --------------------------
Chris Tong Chief Financial Officer
/s/ David S. Krueger Vice President and April 14, 1999
David S. Krueger Chief Accounting Officer
/s/ Morgan F. Johnston Vice President, General Counsel April 14, 1999
- --------------------------
Morgan F. Johnston and Secretary
/s/ Gerald W. Bolfing Director April 14, 1999
- --------------------------
Gerald W. Bolfing
/s/ Oscar C. Lindemann Director April 14, 1999
- --------------------------
Oscar C. Lindemann
/s/ John H. Trescot, Jr. Director April 14, 1999
- --------------------------
John H. Trescot, Jr.
/s/ James E. Upfield Director April 14, 1999
- --------------------------
James E. Upfield
48