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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
[X] Annual Report under Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the fiscal year ended December 31,
1997
[ ] Transition Report under 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.
(Name of small business issuer 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)
Issuer's telephone number, including area code: (972) 401-0752
Securities registered under 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
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Securities registered under Section 12(g) of the Act: None
Check whether the Issuer (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
2 months (or for such shorter period that the Issuer was required to file such
reports) and (2) has been subject to such filing requirements for the past 90 da
Yes X No
Check if no disclosure of delinquent filers in response to Item 405 of
regulation S-B is contained in this form, and no disclosure will be contained,
to the best of the Issuer's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB [ ]
The Issuer's revenues for its most recent fiscal year: $49,923,000
As of March 27, 1998, 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 $94,578,801.
The number of shares outstanding of the Issuer's common stock at December 31,
1997: 21,738,320
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INDEX
Securities and Exchange Commission
Item Number and Description
PART I
Item 1 Description of Business.............................................1
Item 2 Description of Properties..........................................11
Item 3 Legal Proceedings..................................................17
Item 4 Submission of Matters to a Vote of Security Shareholders...........17
PART II
Item 5 Market for Common Equity and Related Stockholder Matters...........17
Item 6 Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................18
Item 7 Consolidated Financial Statements..................................25
Item 8 Change in and Disagreements with Accountants
on Accounting and Financial Disclosure...........................26
PART III
Item 9 Directors Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act................26
Item 10 Executive Compensation..............................................30
Item 11 Security Ownership of Certain Beneficial Owners and Management......33
Item 12 Certain Relationships and Related Transactions......................33
Item 13 Exhibits and Reports on Form 8-K....................................34
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Item 1. Description of Business
The Company
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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"). The Company presently intends
to focus its efforts on its substantial inventory of exploitation and
development opportunities, further acquisitions and, to a lesser extent,
selected exploratory drilling prospects. The Company has identified over 600
development drilling locations (including both production and injection wells)
on its properties, substantially all of which are low-risk in-fill drilling
opportunities.
At December 31, 1997, the Company had an interest in 2,626 wells and had
estimated proved reserves of 333 Bcfe with an SEC PV-10 (as defined herein) of
$211.6 million. Approximately 68% of these reserves were proved developed
producing reserves and 90% were attributable to the Panoma Properties and the
Permian Basin Properties. At December 31, 1997, the Company's proved reserves
had an estimated reserve life index of approximately 16 years and were 62% gas.
The Company serves as operator for approximately 70% of its properties (based on
the number of producing wells in which the Company owns an interest).
Additionally, the Company owns over 500 miles of gas gathering systems and a 50%
interest in a gas processing plant that is connected to the Company's largest
gas gathering system, which was purchased with the Panoma Properties.
Beginning with the Magnum Hunter Combination in December 1995, the
Company has made nine acquisitions for an aggregate net purchase price of $185.4
million. This strategy has added approximately 305.6 Bcfe of reserves
(determined as of the respective times of their acquisition) at an average cost
of $0.61 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
acquisitions, the Company has achieved substantial growth as described below:
o Proved reserves increased to 333 Bcfe at year end 1997 from 36.7 Bcfe at
year end 1995;
o SEC PV-10 increased to $211.6 million at year end 1997from $37.2 million
at year end 1995;
o Average daily production increased to 50.5 million cubic feet equivalent
in the fourth quarter of 1997 from 800 thousand cubic feet equivalent
in fiscal 1995; and
Business Strategy
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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 and (iii) a selective exploration
program.
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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.
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 70% of its properties (90% 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
approximately 10% of the gas that moves through its gas gathering systems and,
therefore, directly 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, 1997. NGTS now markets substantially all of the Company's natural
gas. The Company is also considering opportunities to acquire or develop
additional gas gathering and processing capability.
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
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The most significant of the Company's completed acquisitions are the
Permian Basin Acquisition, the Panoma Acquisition and the McLean Plant
Acquisition.
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 of
the Company 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 infill drilling.
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During 1997 daily net production from the Permian Basin Properties was
22.13 MMcf per day of gas and over 2,153 Bbl per day of oil. According to Ryder
Scott Co. ("Ryder Scott"), independent petroleum engineers engaged by the
Company to evaluate the Permian Basin Properties, as of December 31, 1997, the
Permian Basin Properties had proved reserves of 14.7 MMBbl of oil and 103.2 Bcf
of gas, or on a natural gas equivalent basis, 191.7 Bcfe. Ryder Scott further
estimated the SEC PV-10 for the Permian Basin Properties to be $123.1 million as
of December 31, 1997 based on prices of $16.08 per Bbl of oil and $2.34 per Mcf
of gas at December 31, 1997. Approximately 65% of the proved reserves were
classified as proved developed producing reserves as of December 31, 1997. 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.
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 on April 30, 1997:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
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% 450
Morrison "G" Lease (1).......... Company 2 83.3% 72.9% 10
North Westbrook Unit... .......... Third Party 294 2.0% 2.8%(2) 1,560
(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.
</TABLE>
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 1998.
Ryder Scott attributed approximately 2%, or $4.3 million, of the SEC PV-10
at December 31, 1997 to a four year enhancement program on an existing
waterflood project on the Westbrook Field in Mitchell County, Texas. The Company
has identified approximately 250 drilling locations, including production and
injection wells, to further develop the fields at a cost of approximately $38.1
million. When completed, the properties will be developed on a ten acre, line
drive waterflood pattern, as opposed to the current 28 acre, five-spot pattern.
The Company has budgeted approximately $11.0 million during 1998 for development
of the Westbrook Field. Given current oil prices, the Company is considering
delaying some of these expenditures and is considering adjusting the budget
toward funding currently owned gas projects where development opportunities
exist.
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:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
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% 85
Veal Lease.................. Company 52 100.0% 87.1% 225
NW Slaughter Unit........... Company 83 74.8% 62.8% 330
</TABLE>
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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 several 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 13 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. Three of these wells are currently producing a total of
approximately 2.4 MMcf of gas per day from the Atoka formation at a depth of
approximately 16,000 feet. The Company recompleted an additional well in June
1997 that is producing 2.3 MMcf of gas per day. Undeveloped potential exists on
the properties through redrilling the Atoka formation and completing such wells
using technology designed for high bottom hole pressure conditions.
Burlington has agreed to indemnify the Company for breaches by Burlington
of the purchase agreement as well as any claims attributable to or arising out
of acts or omissions of Burlington (including, but not limited to, environmental
claims) occurring before January 1, 1997. There are certain limitations on the
amount of, and time period for bringing, a claim for indemnity made by the
Company. Burlington is a defendant in two actions claiming that Burlington
underpaid royalty owners on properties in New Mexico and Texas, including
properties that are a part of the Permian Basin Properties. The plaintiffs in
the New Mexico action are seeking class certification while the Texas action has
been certified as a class action. Burlington's indemnity would hold the Company
harmless from any of these claims arising prior to January 1, 1997. The Company
has also agreed, subject to certain limitations, to indemnify Burlington for
matters arising subsequent to January 1, 1997 as well as for certain liabilities
and obligations assumed by the Company as part of the purchase transaction.
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 the associated 427 mile gas gathering system (the "Panoma
Properties"). At year-end the Company had drilled an additional 40 wells, and a
continuous drilling program is progressing into 1998, with an additional well
being added every 7 days. The net purchase price, after certain purchase price
adjustments, was $34.7 million, funded by borrowings under the Company's
previous 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,
1997 aggregated 110 Bcfe with an SEC PV-10 of $66.4 million.
The Panoma Properties currently consist of approximately 560 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.
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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. During 1997, the Company recouped approximately
$1 million or 41% of its initial investment. See "Gathering and Processing of
Gas."
Development and Exploration Activities
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Overview
The Company presently intends to focus its efforts on its substantial
inventory of exploitation and development activities, further acquisitions 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 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 $30.0 million
for exploitation and development activities for 1998. The Company has identified
over 600 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.
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. In addition, in
evaluating the Permian Basin Properties, Ryder Scott attributed approximately
2%, or $4.3 million, of their SEC PV-10 at December 31, 1997 to a four-year
enhancement program, commencing in 1998, on an existing waterflood in the
Westbrook Field in Mitchell County, Texas. The proposed waterflood project is
estimated to cost an aggregate of $38.1 million. The Company has budgeted
approximately $11.0 million for development of the Westbrook Field in 1998.
Given current oil prices, the Company is considering delaying some of these
expenditures and instead directing some of these funds to currently owned gas
projects.
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 is underway in the westernmost field with 40 wells of a 70
well program having been completed during 1997. Upon completion of the 70 well
program, the westernmost field will be developed with 320 acre spacing. The
Company has budgeted approximately $4.0 million for development of the Panoma
Properties through 1998.
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Waterfloods. The Company believes it can enhance the value of selected
west Texas fields through in-fill drilling and enhanced recovery projects,
including several waterflood projects. While waterfloods typically take
considerable time to respond to fluid injection, the west Texas properties have
in-fill drilling potential that management believes could result in a somewhat
faster increase in production and cash flow. The Company has budgeted
approximately $7.3 million in 1998 for five west Texas waterflood projects;
however, the timing of these expenditures may be delayed due to significantly
lower oil prices experienced during the first quarter of 1998.
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 $3.0 million of its $20.0 million 1997
capital budget on exploratory drilling. The Company has a $6.0 million
exploration budget for 1998, including geological and geophysical expenses.
Three exploratory wells were drilled in 1997. One of these is located on a 7,500
acre lease block in Roger Mills County, Oklahoma and was completed as a gas well
flowing approximately 500 Mcfe per day. A second exploratory well located on a
3,000 acre block in Fayette County, Texas has encountered oil shows but was
junked and abandoned due to mechanical problems. The Company owns 25% and 20%
working interests, respectively, in these two prospects where additional
drilling is being evaluated. The third exploratory well resulted in a dry hole
in Ellis County, Oklahoma. An exploratory well on the Mossy Grove prospect in
Walker County, Texas commenced in late 1997 but encountered drilling problems
above the objective and is being redrilled as a dual lateral (turnazontal) well.
The Company owns a 25% working interest in the proposed test well which is
located on a 30,000 acre lease block. The primary objective is the Glen Rose
formation at approximately 11,800 feet. In Victoria County, Texas the Company
has purchased 1,000 acres overlaying a shallow Frio structure. Magnum Hunter is
the operator and owns a 75% working interest in this prospect where an
exploratory well is scheduled for the second quarter of 1998. Seismic
acquisition has commenced on the Bobcat Trend in Hockley Co., Texas where the
Company owns a twenty-five percent (25%) working interest after payout. A 3-D
seismic program has been designed to evaluate 16 geological and geophysical
leads in an area of active exploration for the Strawn and Canyon formations. The
project covers approximately 30,000 acres and over 15,000 acres are currently
under option. The Company is actively generating and evaluating other prospects
for the application of future 3-D seismic and advanced drilling technologies.
Gathering and Processing of Gas
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Hunter Gas Gathering, Inc., a wholly owned subsidiary of the Company,
owns three gas gathering systems located in Oklahoma, Texas and Louisiana, none
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. Two of the gas gathering systems, Panoma and North Appleby, account
for more than 90% of the throughput from the Company's three systems. Gruy
operates all three gas gathering systems.
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.
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The Panoma system, the largest of the Company's three gas gathering
systems, consists of approximately 435 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 1997, gas throughput for the Panoma gas gathering system was
approximately 17 MMcf per day. The Panoma gas gathering system currently
delivers gas to El Paso Natural Gas Company for transport to markets in western
Oklahoma and the West Coast, although the Company is actively exploring
additional markets for such gas. The Company, which operates approximately 500
of the approximately 600 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 2.6 MMcf per day for third parties to
Natural Gas Pipeline Co. for transportation to other markets.
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 17 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 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 December 31, 1997 the Company had recouped
approximately 41% of its $2.5 million investment.
Marketing of Production
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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. In 1996 the Company sold approximately 91% of
its gas to Crosstex, a gas marketing firm in Dallas, Texas. Crosstex did not
purchase more than 10% of the Company's total oil and gas production during
1997. The Company typically obtains letters of credit guaranteeing the payment
of the purchase price for its gas.
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 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 14 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 through a combination of cash ($2.35 million) and promissory notes
($2.0 million), due December 1, 1998, that have equity "put" features once
Magnum Hunter's common stock achieves a trading range of $7.50 per share. Magnum
Hunter may, at its option, retire the promissory notes early with stock or cash
at anytime.
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NGTS is a four year old natural gas marketing and trading company with
operations concentrated in the western two-thirds of the country. In fiscal
1997, NGTS reported total revenues of approximately $195.6 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 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; Other Activities
- --------------------------------------------------------------
Gruy. 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 banks, 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;
petroleum engineering services; and consultation as an expert witness. 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.
Hunter Butcher. The Company provides consulting services to Latin
American energy companies through Hunter Butcher International, L.L.C. ("Hunter
Butcher"). Hunter Butcher has primarily focused on assisting energy-related
Mexican companies in obtaining financing for their purchases in the United
States of products for import into Mexico. This is accomplished through a
commercial bank credit facility established to facilitate short and medium term
credit for Hunter Butcher to purchase these products and resell them to its
clients at a slight premium. The credit risk to Hunter Butcher on such resales
is lessened by partial guarantees of approximately 85% to 90% of such borrowings
by the Export Import Bank of the United States (the "ExIm Bank"), by credit
insurance and through deposits by Hunter Butcher's clients to secure the
unguaranteed portion of the indebtedness and certain interest. Hunter Butcher
could, however, incur a loss under such arrangement in repaying indebtedness
under the credit facility since the applicable ExIm Bank guaranty and deposit
would not be adequate to pay interest under the credit facility at the default
rate or cover other possible losses. In addition, the Company itself may from
time to time guarantee the indebtedness incurred under the credit facility by
Hunter Butcher for its clients, but the Company's credit facility limits the
Company to guaranteeing not more than $3.0 million of such indebtedness at any
time. The Company is currently in the process of winding down the business of
Hunter Butcher and this division should no longer be active after 1998.
Competition
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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 substantiallygreater
financial resources and larger staffs and facilities than those of the Company.
In addition, the Company
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<PAGE>
frequently encounters competition in the acquisition of oil and gas
properties and gas gathering systems, and in its management and consulting
business. The principal means of such competition are the amount and terms of
the consideration offered. The principal means of such competition with respect
to the sale of oil and gas production are product availability and price. The
price at which the Company's products may be sold will continue to be affected
by a number of factors, including the price of alternate fuels such as oil, 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.
FERC regulates interstate gas transportation rates and service
conditions, which affect the marketing of gas produced by the Company, as well
as the revenues received by the Company for sales of such production. Since the
mid-1980's, FERC has issued a series of orders, culminating in Order Nos. 636,
636-A and 636-B ("Order 636"), that have significantly altered the marketing and
transportation of gas. Order 636 mandates a fundamental restructuring of
interstate pipeline sales and transportation service, including the unbundling
by interstate pipelines of the sale, transportation, storage and other
components of the city-gate sales services such pipelines previously performed.
One of FERC's purposes in issuing the orders is to increase competition within
all phases of the gas industry. Order 636 and subsequent FERC orders on
rehearing have been appealed and are pending judicial review. Because these
orders may be modified as a result of the appeals, it is difficult to predict
the ultimate impact of the orders on the Company and its gas marketing efforts.
Generally, Order 636 has eliminated or substantially reduced the interstate
pipelines' traditional role as wholesalers of gas, and has substantially
increased competition and volatility in gas markets.
The price the Company receives from the sale of oil and natural gas
liquids is affected by the cost of transporting products to market. Effective
January 1, 1995, FERC implemented regulations establishing an indexing system
for transportation rates for oil pipelines, which, generally, would index such
rates to inflation, subject to certain conditions and limitations. The Company
is not able to predict with certainty the effects, if any, of these regulations
on its operations. However, the regulations may increase transportation costs or
reduce wellhead prices for oil and natural gas liquids. Finally, from time to
time regulatory agencies have imposed price controls and limitations on
production by restricting the rate of flow of oil and gas wells below natural
production capacity in order to conserve supplies of oil and gas.
9
<PAGE>
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 pipeline, drilling, and production 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 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.
10
<PAGE>
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 $100,000 in 1998 and $75,000 in 1999.
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, 1997, the Company had 67 full-time employees of which 10
were management, 28 were administrative and 29 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 and Hobbs, New Mexico.
Item 2. Description of Properties
Oil and Gas Reserves
- --------------------
General
All information set forth in this Form 10-KSB 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 (i) 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, 1997 (using oil and gas prices at December 31, 1997) and (ii) by
the engineers named in the footnotes to the tables below with respect to the
Company's interests at December 31, 1996. 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, 1997, 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
11
<PAGE>
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, 1997, 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,
-------------------------------------
1997 1996
-------------------------------------
Gas (per Mcf)............................ $ 2.34 $ 4.00
Oil (per Bbl)............................ $ 16.08 $ 24.31
All reserves are evaluated at contract temperature and pressure which can
affect the measurement of gas reserves. Operating costs, development costs and
certain production-related and ad valorem taxes were deducted in arriving at the
estimated future net cash flows. No provision was made for income taxes. The
estimates following this section set forth reserves considered to be
economically recoverable under normal operating methods and existing conditions
at the prices and operating costs prevailing at the dates indicated above. The
estimates of the SEC PV-10 from future net cash flows differ from the
standardized measure of discounted future net cash flows set forth in the notes
to the Consolidated Financial Statements of the Company, which is calculated
after provision for future income taxes. There can be no assurance that these
estimates are accurate predictions of future net cash flows from oil and gas
reserves or their present value.
Proved reserves are estimates of oil and gas to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas will likely be different from those used in preparing
these 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, 1997. 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, 1997.
12
<PAGE>
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,
1996 and 1997.
Estimated Proved Oil and Natural Gas Reserves (1)
At December 31,
--------------------------------
1997 1996
--------------------------------
Net gas reserves (Mcf):
Proved developed producing................. 154,749,340 71,166,555
Proved developed non-producing............. 215,056 108,586
Proved undeveloped......................... 52,811,374 19,290,856
--------------------------------
Total proved gas reserves................ 207,775,770 90,565,997
================================
Net oil reserves (Bbl):
(including condensate and NGL)
Proved developed producing................. 12,021,950 1,849,846
Proved developed non-producing............. 14,284 112,338
Proved undeveloped......................... 8,910,181 3,376,071
--------------------------------
Total proved oil reserves................ 20,946,415 5,338,255
================================
Total proved reserves (Mcfe).................... 333,454,260 122,595,527
================================
Estimated SEC PV-10 of Proved Reserves (1)
At December 31,
--------------------------------
1997 1996
--------------------------------
Estimated SEC PV-10 (2) :
Proved developed producing ............... $ 173,189,655 $ 115,858,134
Proved developed non-producing ........... 342,473 664,308
Proved undeveloped........................ 38,054,232 48,244,017
--------------------------------
Total proved reserves................... $ 211,586,360 $ 164,766,459
================================
(1) Based upon (i) reserve reports at December 31, 1996 prepared
by Gaffney, Cline & Associates ("Gaffney Cline") and Glenn
Harrison Petroleum Consultants, Inc.; and (ii) reserve reports
at 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.
13
<PAGE>
Significant Properties
On December 31, 1997, 90% of the Company's proved reserves on a Bcfe
basis were located in the Permian Basin Properties and the Panoma Properties. On
such date the Company's properties included working interests in 2,626 gross
(1,482 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, 1997.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
SEC PV-10 (1)
-------------------------------
Natural Gas
Amount % of Oil Gas Equivalent
(in thousands) Total (Bbl) (Mcf) (Mcfe)
--------------------------------------------------------------------------
Permian Basin Properties (2)(3)...... 123,054,987 58.16 14,746,386 103,238,221 191,716,537
Panoma Properties (2) .............. 66,463,866 31.41 3,144,520 90,985,490 109,852,610
Other (2) (3)........................ 22,067,507 10.43 3,055,509 13,552,059 31,885,113
--------------------------------------------------------------------------
Total......................... $ 211,586,360 100.0% 20,946,415 207,775,770 333,454,260
==========================================================================
(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, 1997 prepared by Ryder Scott.
(3) Based on reserve reports at December 31, 1997 prepared by PGH.
</TABLE>
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,
1997 1996
--------------------------
Oil and gas production:
Oil (Mbbl)........................................ 737 191
Gas (MMcf)........................................ 9,614 2,675
Natural Gas Equivalents (MMcfe)................... 14,037 3,821
Average sales price (1):
Oil (per Bbl)..................................... $ 17.70 $ 20.46
Gas (per Mcf)..................................... 2.35 2.37
Natural Gas Equivalents (per Mcfe)................ 2.54 2.68
Oil and gas production expense per (Mcfe) (2)....... $ .99 $ 1.15
(1) Before deduction of production taxes and net of hedging results for
the two years ended December 31, 1997.
(2) Includes lease operating expenses and production and ad valorem
taxes, if applicable. For the years ended December 31, 1997 and
1996, includes internal transfer price expenses for gas gathering
and overhead costs of $0.17 per Mcfe, and $0.23 per Mcfe,
respectively.
14
<PAGE>
Drilling Activity
- -----------------
The following table sets forth the results of the Company's drilling
activities during the two fiscal years ended December 31, 1997.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C>
Gross Wells(1) Net Wells(2)
Year Type of Well Total Producing(3) Dry(4) Total Producing(3) Dry(4)
---- ------------ ----- ------------ ------ ----- ------------ ------
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 .5 .73
Other 1 1 0 .5 .5 0
1996 Exploratory
Texas 8 4 4 5.23 2.63 2.60
Oklahoma 0 0 0 0 0 0
Other 0 0 0 0 0 0
Development
Texas 2 2 0 .35 .35 0
Oklahoma 1 1 0 .31 .31 0
Other 0 0 0 0 0 0
(1) 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.
(2) The number of net wells is the sum of fractional working interests
owned in gross wells expressed as whole numbers and fractions
thereof.
(3) 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.
(4) A dry well is an exploratory or development well that is not a
producing well.
</TABLE>
15
<PAGE>
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, 1997. All of these
wells are located in the United States.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Productive Wells
As of December 31, 1997
------------------------
Gross(1) Net(2)
Location Oil Gas Total Oil Gas Total
- -------- --- --- ----- --- --- -----
Texas...................... 1,444 741 2,185 675 516 1,191
Oklahoma................... 3 119 122 1 103 104
Mississippi................ 4 0 4 3 0 3
New Mexico................. 60 239 299 37 144 181
California................. 14 0 14 1 0 1
Kansas..................... 2 0 2 2 0 2
---------------------------------------------------------------
Total............. 1,527 1,099 2,626 719 763 1,482
===============================================================
(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.
</TABLE>
Oil and Gas Acreage
- -------------------
The following table summarizes the Company's developed and undeveloped
leasehold acreage at December 31, 1997.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Developed Undeveloped
-----------------------------------------------------
Gross(1) Net(2) Gross(1) Net(2)
-----------------------------------------------------
Texas........................ 242,549 199,920 40,805 14,001
Oklahoma..................... 45,610 42,982 3,352 838
Mississippi.................. 528 452 0 0
New Mexico................... 40,637 35,323 0 0
California................... 509 38 0 0
Kansas....................... 80 69 0 0
-----------------------------------------------------
Total.................. 329,913 278,784 44,157 14,839
=====================================================
(1) The number of gross acres is the total number of acres in which a
working interest is owned.
(2) The number of net acres is the sum of fractional working interests
owned in gross acres expressed as whole numbers and fractions thereof.
</TABLE>
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
16
<PAGE>
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 1997.
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 March 31, 1998, there were 3,606
stockholders of record.
Average Daily
Trading Volume
High Low (Shares)
----- ----- ---------------
1996
First Quarter.......................$3.63 $2.75 19,737
Second Quarter......................$4.75 $3.06 47,360
Third Quarter.......................$4.75 $3.56 23,781
Fourth Quarter......................$5.06 $4.25 45,658
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 27, 1998, the last reported sale price of the Company's Common
Stock on the American Stock Exchange was $5.1875 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.
17
<PAGE>
Item 6. 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, 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. As of December 31, 1997 the Company
had recouped approximately 41% 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 provides 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.
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
18
<PAGE>
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 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 have equity "put" features. The Company may, at its option,
retire the promissory note due December 1, 1998, with stock or cash.
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. While the Company
has never been required to write-down its asset base, significant downward
revisions of quantity estimates or declines in oil and gas prices from those in
effect on December 31, 1997, which are not offset by other factors, could
possibly result in a write-down for impairment of oil and gas properties.
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 $35.7 million in 1997, a 250% 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 $2.35 per Mcf in 1997,
representing a 13% decrease in oil price from $20.46 per Bbl in 1996 and a 1%
decrease in gas price from $2.37 per Mcf in 1996. Oil and gas production costs
increased 217% to $13.9 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
19
<PAGE>
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.
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) in 1997 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.
20
<PAGE>
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. With these
adjustments, total long-term debt under the Credit Facility at December 31, 1997
was $21.5 million, leaving $43.5 million available to draw at such time, prior
to the next borrowing base redetermination based upon financial results of the
Company. At December 31, 1997, the Company had $3.0 million in cash and cash
equivalents and $2.6 million in net working capital, 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.
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 $168.6 million in investing activities, principally for additions
to property and equipment of $160.1 million. Financing activities provided
$164.3 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.
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
$41.7 million in
21
<PAGE>
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 $38.9 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 1998 the Company has budgeted approximately $36 million for
development and exploration activities, including $30 million budgeted for
development projects on the Permian Basin and Panoma Properties and $6.0 million
budgeted for exploration projects. In addition, with respect to the recently
closed Permian Basin Acquisition, the Company anticipates that it will spend
approximately $38.1 million over a four year period which began in 1997 on a
development program to enhance an existing waterflood project in the Westbrook
Field located in Mitchell County, Texas. While the Company has not yet developed
a budget for fiscal 1999, Ryder Scott has capital expenditures planned of
approximately $18 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 prices, the Company may redirect some
of its budgeted funds from oil projects to gas 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 is obligated to pay a note of $2.0 million
to current and former shareholders of NGTS. This loan is due December 1, 1998
and may be repaid, at the option of the Company, with cash or shares of its
common stock.
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 $43.5 million as of December 31, 1997) will be
adequate to meet its anticipated requirements for working capital, capital
expenditures and scheduled interest payments for the foreseeable future.
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 the past several years, the Company had 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. The results of operations and cash flow of the Company have
been, and will continue to be, affected to a certain extent 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
22
<PAGE>
Company's oil and gas production during the next 12 months. Subsequent to
year end 1997, oil prices continued to decline. If this decline were to continue
in 1998, the Company might be forced to recognize a loss from thewrite down of
its full cost pool.
The Company markets oil and gas for its own account, which exposes the
Company to the attendant commodities risk. Substantially all 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 with a variety of purchasers.
Hedging Activity
Periodically, the Company enters into futures, options, and swap contracts
to reduce the effects of fluctuations in crude oil and gas prices. As of
December 31, 1997 the Company had 33% of its oil production and 43% of its gas
production hedged although lesser or greater amounts may be hedged in the
future. At December 31, 1997, the Company had open contracts for an oil price
collar covering 30,000 Bbls of oil per month (with cap and floor prices of
$23.25 and $18.50, respectively) through December 1998. At December 31, 1997,
the Company had gas price swaps on 100,000 MMBtu of gas per month at $1.905 per
MMBtu through January 1998, 100,000 MMBtu of gas per month at $1.77 per MMBtu
through January 1998 and 300,000 MMBtu of gas per month at an average price of
$2.55 per MMBtu through March 1998. The average Btu content of gas produced by
the Company exceeds 1,100 Btu per Mcf of gas. Therefore, each of the above gas
prices should be increased by 10% to reflect the actual gas price per Mcf
received by the Company. All of these swaps are against the El Paso Permian
Basin Index. These contracts expire monthly. The Company has also written a call
option on 100,000 MMbtu of gas per month at an average price of $2.90 per MMBtu
through March, 1998. The gains or losses on the Company's hedging transactions
are determined as the difference between the contract price and a reference
price, generally closing prices on the New York Mercantile Exchange. The
resulting transaction gains and losses are determined monthly and are included
in the period the hedged production or inventory is sold. Net losses relating to
these derivatives for the years ended December 31, 1997 and 1996 were $1.5
million and $272,000, respectively.
Year 2000 Compliance
The inability of computers, software and other equipment utilizing
microprocessors to recognize and properly process data fields containing a two
digit year is commonly referred to as the Year 2000 Compliance issue. As the
year 2000 approaches, such systems may be unable to accurately process certain
date-based information.
The Company has identified no significant applications that will require
modifications to ensure Year 2000 Compliance.
In addition, the Company plans to communicate with others with whom it does
significant business to determine their Year 2000 Compliance readiness and the
extent to which the Company is vulnerable to any third party Year 2000 issues.
However, there can be no guarantee that the systems of other companies on which
the Company's systems rely will be timely converted, or that a failure to
convert by another company, or a conversion that is incompatible with the
Company's systems, would not have a material adverse effect on the Company.
The total cost to the Company of these Year 2000 Compliance activities has
not been and is not anticipated to be material to its financial position or
results of operations in any given year. However, there can be no guarantee that
these estimates will be achieved and actual results could differ from those
plans.
23
<PAGE>
Recently Issued Accounting Pronouncements
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for reported and
display of comprehensive income in the financial statements. Comprehensive
income is the total of net income and all other non-owner changes in equity.
SFAS No. 131 requires that companies disclose segment data based on how
management makes decisions allocating resources to segments and measuring their
performance. SFAS Nos. 130 and 131 are effective for 1998. Adoption of these
standards is not expected to have an effect on the Company's financial
statements, financial position or results of operations.
24
<PAGE>
Item 7.Consolidated Financial Statements and Unaudited Supplemental Information
Index to Consolidated Financial Statements
Page
Independent Auditors' Report.........................................F-1
Financial Statements:
Consolidated Balance Sheet at December 31, 1997 and 1996.....F-2
Consolidated Statements of Operations for the Years Ended
December 31, 1997 and 1996..........................F-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1997 and 1996..............F-4
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1997 and 1996....................F-5
Notes to Consolidated Financial Statements...........................F-6
Supplemental Information (Unaudited).................................F-21
25
<PAGE>
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, 1997, and 1996, and
the related consolidated statements of operations, stockholders' equity, and
cash flows for each of the two years in the period ended December 31, 1997.
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
misstatements. 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 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the two years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Dallas, Texas
March 13, 1998 (except for the last paragraphs of Notes 5 and 16 as to which
the date is March 27, 1998)
F-1
<PAGE>
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
(in thousands of dollars)
<TABLE><CAPTION>
<S> <C> <C>
December 31, December 31,
1997 1996
------------------------------------
ASSETS
Current Assets
Cash and cash equivalents............................................ $ 3,030 $ 1,687
Securities available for sale........................................ - 233
Accounts receivable
Trade, net of allowance of $166 and $132........................ 12,850 4,372
Due from affiliates............................................. 58 241
Notes receivable from affiliate...................................... 355 264
Current portion of long-term note receivable, net allowance of $200
and $0....................................................... 357 198
Prepaid and other.................................................... 1,299 52
---------------------------------
Total Current Assets........................................... 17,949 7,047
---------------------------------
Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved....................................................... 517 459
Proved......................................................... 227,028 70,575
Pipelines............................................................ 9,166 7,102
Other property....................................................... 776 381
---------------------------------
Total Property, Plant and Equipment.................................. 237,487 78,517
Accumulated depreciation, depletion, and impairment............ (16,589) (4,869)
---------------------------------
Net Property, Plant and Equipment.................................... 220,898 73,648
---------------------------------
Other Assets
Deposits and other assets............................................ 5,863 645
Investment in unconsolidated affiliate............................... 4,372 -
Other long-term investments.......................................... 361 -
Long-term notes receivable, net of imputed interest.................. 1,626 1,732
---------------------------------
Total Assets $ 251,069 $ 83,072
=================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities............................... $ 9,235 $ 3,940
Dividends payable.................................................... 219 22
Suspended revenue payable............................................ 1,162 784
Current maturities of long-term debt................................. 24 22
Notes payable........................................................ 4,699 -
---------------------------------
Total Current Liabilities...................................... 15,339 4,768
---------------------------------
Long-Term Liabilities
Long-term debt, less current maturities.............................. 161,519 38,744
Production payment liability......................................... 743 937
Deferred income taxes................................................ 1,289 3,469
Minority interest.................................................... 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 and 14,252,822 shares issued, respectively.............. 43 29
Additional paid-in capital................................................ 80,731 40,216
Accumulated deficit....................................................... (8,634) (5,142)
Unrealized gain on investments............................................ - 51
---------------------------------
72,141 35,155
Treasury stock (538,633 and 544,495 shares of common stock, respectively). (1) (1)
---------------------------------
Total Stockholders' Equity................................................ 72,140 35,154
----------------------------------
Total Liabilities and Stockholders' Equity................................ $ 251,069 $ 83,072
==================================
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-2
<PAGE>
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Operations
(in thousands, except for per share amounts)
<TABLE>
<CAPTION>
<S> <C> <C>
For the Years Ended
December 31,
----------------------------------
1997 1996
----------------------------------
Operating Revenues:
Oil and gas sales...................................................... $ 35,658 $ 10,248
Gas gathering, marketing and processing................................ 10,297 5,768
Oil field services and international sales............................. 3,968 396
----------------------------------
Total Operating Revenue.......................................... 49,923 16,412
----------------------------------
Operating Costs and Expenses:
Oil and gas production................................................. 13,901 4,390
Gas gathering, marketing and processing................................ 7,909 4,708
Oil field services and international sales............................. 3,745 267
Depreciation and depletion............................................. 12,363 2,951
General and administrative............................................. 2,358 1,225
----------------------------------
Total Operating Costs and Expenses............................... 40,276 13,541
----------------------------------
Operating Profit.......................................................... 9,647 2,871
Equity in earnings of affiliate, net of income tax..................... 6 -
Other income........................................................... 762 344
Interest expense....................................................... (13,788) (2,394)
---------------------------------
Net Income (Loss) before income tax and minority interest................. (3,373) 821
Benefit (Provision) for deferred income tax............................ 1,284 (312)
----------------------------------
Net Income (Loss) before minority interest................................ (2,089) 509
Minority interest in subsidiary earnings............................... (19) -
----------------------------------
Net Income (Loss) Before Extraordinary Loss............................... (2,108) 509
Extraordinary Loss From Early Extinguishment of Debt, net of tax
benefit of $848..................................................... (1,384) -
----------------------------------
Net Income (Loss)......................................................... (3,492) 509
Dividends Applicable to Preferred Stock................................ (875) (406)
----------------------------------
Income (Loss) Applicable to Common Shares................................. $ (4,367) $ 103
----------------------------------
Income (Loss) per Common Share - Basic
Income (Loss) Before Extraordinary Loss................................ $ (0.21) $ 0.01
Extraordinary Loss..................................................... (0.09) -
----------------------------------
Income (Loss) After Extraordinary Loss................................. $ (0.30) $ 0.01
----------------------------------
Income (Loss) per Common Share - Diluted
Income (Loss) Before Extraordinary Loss................................ $ (0.21) $ 0.01
Extraordinary Loss..................................................... (0.09) -
----------------------------------
Income (Loss) After Extraordinary Loss................................. $ (0.30) $ 0.01
----------------------------------
Common Shares Used in Per Share Calculation
Basic.................................................................. 14,535,805 12,485,893
----------------------------------
Diluted................................................................ 14,535,805 12,561,760
----------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-3
<PAGE>
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity
For the Periods Ended December 31, 1997 and 1996
(dollars in thousands)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
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
Redemption of 28,116 shares of Series C
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 96 Series A preferred stock
Net loss.........................................
Unrealized gain on investments...................
------------------------------------------------------------------
Balance at December 31, 1997....................... 1,080,000 $ 1 21,738,320 $ 43 (538,633) $ (1)
==================================================================
The accompanying notes are an integral part of these consolidated financial statements
</TABLE>
<PAGE>
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity
For the Periods Ended December 31, 1997 and 1996
(dollars in thousands)
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Unrealized
Additional Gain (Loss)
Paid-In Accumulated On
Capital Deficit Investments
-----------------------------------------------------------------
Balance at December 31, 1995....................... $ 29,660 $ (5,245) $ 57
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 $ (5,142) $ 51
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 96 Series A preferred stock (875)
Net loss......................................... (3,492)
Unrealized gain on investments................... (51)
------------------------------------------------------------------
Balance at December 31, 1997....................... $ 80,371 $ (8,634) $ -
==================================================================
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-4
<PAGE>
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(in thousands)
<TABLE>
<CAPTION>
<S> <C> <C>
For the Years Ended
December 31,
------------------------------
1997 1996
------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income (loss)........................................................... $ (3,492) $ 509
Adjustments to reconcile net income (loss) to cash provided by
(used for) operating activities:
Extraordinary loss....................................................... 1,384 -
Depreciation and depletion............................................... 12,363 2,951
Amortization of financing fees........................................... 508 -
Increase in reserve for doubtful accounts................................ 322 -
Deferred income taxes.................................................... (1,284) 312
Equity in unconsolidated affiliate....................................... (6) -
Minority interest........................................................ 19 -
(Gain) Loss on sale of assets............................................ (386) (143)
Other.................................................................... 93 32
Changes in certain assets and liabilities
Accounts and notes receivable.......................................... (8,295) (3,250)
Other current assets................................................... (1,247) (30)
Accounts payable and accrued liabilities............................... 5,673 2,647
------------------------------
Net Cash Provided By Operating Activities...................................... 5,652 3,028
------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets................................................ 593 318
Additions to property and equipment......................................... (160,059) (41,471)
Increase in deposits and other assets....................................... (6,159) (527)
Loan made for promissory note receivable.................................... (237) (58)
Other long-term investments................................................. (361) -
Investment in unconsolidated affiliate...................................... (2,362) -
------------------------------
Net Cash Used In Investing Activities....................................... (168,585) (41,738)
------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of long-term debt and production
payment................................................................. 352,500 57,262
Fees paid related to bridge financing....................................... (1,800) -
Proceeds from short-term notes payable...................................... 2,699 -
Payments of principal on long-term and production payment................... (229,917) (27,459)
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.................................................... 41,721 9,796
Redemption of preferred stock............................................... - (295)
Payments received on notes receivable....................................... 256 277
Dividends paid.............................................................. (678) (438)
------------------------------
Net Cash Provided By Financing Activities................................... 164,276 38,853
------------------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS...................................... 1,343 143
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............................... 1,687 1,544
------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD..................................... $ 3,030 $ 1,687
------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-5
<PAGE>
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"), formerly Magnum Petroleum,
Inc., 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, providing management and advisory consulting services on oil and
gas properties for third parties, and providing consulting and U.S. export
services to facilitate Latin American trade in energy products. 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 three gathering systems located in
Texas, Louisiana 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, Gruy Petroleum
Management Company, Hunter Gas Gathering, Inc., Inesco Corporation, Magnum
Hunter Production, Inc., Midland Hunter Petroleum Limited Liability Company, and
SPL Gas Marketing, Inc. and its 51% owned subsidiary, Hunter Butcher
International Limited Liability Company. The Company accounts for its investment
in NGTS 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 are direct Guarantors of the Company's Section 144 A 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 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. 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.
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.
Investments
The Company follows accounting procedures according to Statement of
Financial Accounting Standards 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
assets available-for-sale and are measured at fair value. Unrealized gains and
losses for these investments are reported as a separate component of
stockholders' equity.
F-6
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
At December 31, 1996, the Company's available for sale securities had an
amortized cost basis of $150,000, gross unrealized gains reported in equity of
$51,150 and a fair market value of $232,500. During 1996, securities were sold
for gross proceeds of $187,312 and the Company realized a gain of $142,872.
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.
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 $517,000 and $459,000 at
December 31, 1997 and 1996, 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.
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.
F-7
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Other Property
Other property and equipment are carried at cost. Depreciation is
provided using the straight-line method over estimated useful lives ranging from
five to ten years. Gain or loss on retirement or sale or other disposition of
assets is included in results of operations in the period of disposition.
Other Oil and Gas Related Services
Other oil and gas related services consist largely of fees earned from
the Company's operation of oil and gas properties for third parties. Such fees
are recognized in the month the service is provided.
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.
Income or Loss Per Common Share
During 1997, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 128, "Earnings per Share," which requires dual
presentation of basic and diluted earnings per shares ("EPS") on the face of the
consolidated income statement and requires a reconciliation of the numerators
and denominators of the basic and diluted EPS calculations. Accordingly, all EPS
information for all periods presented have been restated to present basic and
diluted EPS under the provisions of SFAS No. 128.
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.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for reported and
display of comprehensive income in the financial statements. Comprehensive
income is the total of net income and all other non-owner changes in equity.
SFAS No. 131 requires that companies disclose segment data based on how
management makes decisions allocating resources to segments and measuring their
performance. SFAS Nos. 130 and 131 are effective for 1998. Adoption of these
standards is not expected to have an effect on the Company's financial
statements, financial position or results of operations.
F-8
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 2 -- ACQUISITIONS
On June 28, 1996, the Company purchased 469 gas wells and approximately
427 miles of a gas gathering pipeline system for a net purchase price of
$34,652,395. 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.
On November 4, 1996, the Company entered into an agreement to sell
certain oil and gas properties for $1,850,000, including $150,000 of restricted
securities of an American Stock Exchange listed company and a $1,700,000
promissory note payable out of 100% of the net oil and gas income of the
properties. The agreement calls for the Company's subsidiary to continue to
operate the properties for a monthly management fee.
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.
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 $9.7
million for production cash flow from January 1, 1997 to the closing date and
other minor adjustments.
The following summary, prepared on a pro forma basis, presents the
results of operations for the years ended December 31, 1997 and 1996, as if the
acquisitions occurred as of the beginning of the respective years. The pro forma
information includes the effects of adjustments for increased general and
administrative expense, interest expense, depreciation, depletion and income
taxes:
<TABLE>
<CAPTION>
<S> <C> <C>
1997 1996
---------------------------------
(Unaudited)
---------------------------------
Revenue........................................................$ 62,550,000 $ 63,648,000
Net Income (Loss) Applicable to Common Stock before
extraordinary items.......................................... (2,100,000) 1,158,000
Net Income (Loss) Per Common Share before extraordinary items
Basic........................................................$ (.14) $ .09
Diluted......................................................$ (.14) $ .09
Average shares outstanding - Basic............................. 14,535,805 12,485,893
Average shares outstanding - Diluted........................... 14,535,805 12,561,760
</TABLE>
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
F-9
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Company's $4.35 million acquisition was completed for a combination of cash
($2.35 million) and promissory notes ($2.0 million) that have equity "put"
features. The Company may, at its option, retire the promissory note due
December 1, 1998 with stock or cash.
As of December 31, 1997, the Company had acquired 74,500 Units of TEL
Offshore Trust for investment purposes. Subsequent to that date, the Company
announced a cash tender offer for $9,599,000 to acquire at least forty percent
(40%) of the outstanding Units of TEL at $5.50 per Unit, which was successful.
At December 31, 1997, the investment in TEL was included in other long-term
investments.
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.
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 is collateralized by the oil
and gas properties sold. As of December 31, 1997, the unpaid balance was
$1,598,238.
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. Based on the current market value of the collateral
securities, the Company made a $200,000 allowance for the realization of the
note. The net carrying value of the note, at December 31, 1997 was $330,016.
NOTE 4 -- RELATED PARTY TRANSACTIONS
In conjunction with the acquisition of Hunter, the Company assumed a note
receivable with a balance of $178,527 and $353,071 at December 31, 1996 and
1997, respectively, from an owner in an affiliated limited liability company.
The note provides for interest at ten percent and has a due date of March 1,
1998. It is management's intent to extend the due date to December 31,1998.
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-10
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 5 -- DEBT
Notes Payable and Long-term debt at December 31, 1997 and 1996 consisted
of the following:
<TABLE>
<CAPTION>
<S> <C> <C>
1997 1996
-----------------------------
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 December 1, 1998, or earlier
under special conditions, payable in cash or common stock of the Company at
its option, interest payable
at 9% in cash quarterly beginning March 31, 1998......................... 2,000,000 -
-----------------------------
Total Notes Payable............................................... $ 4,699,000 $ -
=============================
Long-Term Debt:
Banks
Revolving promissory note, collateralized by pipeline and oil and gas
properties, due April 30, 2002, (1)...................................... $ 21,500,000 $ -
Revolving promissory note, collateralized by pipeline and oil and gas
properties, due June 30, 2001, interest at LIBOR + 2.25% (total of
7.625% at December 31, 1996)............................................. - 38,700,000
Note payable to bank collateralized by vehicle payable in monthly installments
of $1,031 including interest at 8.5% through
February 1999............................................................ 13,000 24,000
Other
Senior notes, unsecured, due June 1, 2007, interest at 10% payable
semi-annually on June 1 and December 1................................... 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....................................................... 30,000 42,000
-----------------------------
Total Long-Term Debt.............................................. $161,543,000 $38,766,000
Less Current Portion.......................... 24,000 22,000
-----------------------------
Long-Term Debt............................................ $161,519,000 $38,744,000
==============================
</TABLE>
F-11
<PAGE>
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:
1998............................................. $ 24,000
1999............................................. 14,000
2000............................................. 5,000
2001............................................. -
2002............................................. 21,500,000
2003 to 2006..................................... -
2007............................................. 140,000,000
---------------
$ 161,543,000
===============
(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 $65,000,000 at December 31, 1997. The level
of the borrowing base is dependent on the valuation of the
assets pledged, primarily oil and gas reserve values. The line
of credit includes covenants, the most restrictive of which
require 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,
1997, the amounts borrowed at these rates were:
LIBOR + 1% (total of 6.77%)........................ $ 17,000,000
Base Rate (Prime) at 8.5%.......................... 4,500,000
-----------------
Total....................................... $ 21,500,000
At December 31, 1997, the Company was not in compliance with the interest
coverage ratio covenant of the revolving promissory note. The lenders have
agreed to waive compliance with the interest coverage ratio requirement at
December 31, 1997, and amend the interest coverage ratio requirement as stated
in the Amended and Restated Credit Agreement for each of the quarters in the
year ended December 31, 1998.
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 $147,000
and $210,000 at December 31, 1997 and 1996, 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 $596,000 and $726,000 at December 31, 1997 and 1996,
respectively. The production payment bears interest at the rate of 13.5% per
annum and is non-recourse to the Company.
NOTE 7 -- INCOME TAXES
The Company accounts for income taxes in accordance with Statement of
Financial Accounting Standards 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
F-12
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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:
1997 1996
----------------------------
Income tax expense (benefit) at statutory rates $(1,153,000) $ 279,000
State tax expense (benefit) (133,000) 24,000
Other (288,000) 9,000
Change in valuation allowance 290,000 -
-----------------------------
Tax expense (benefit) $(1,284,000) $ 312,000
=============================
The tax effects of significant temporary differences and carryforwards
are as follows:
<TABLE>
<CAPTION>
<S> <C> <C>
December 31,
----------------------------------
1997 1996
----------------------------------
Property and equipment, including intangible drilling costs............... $ (5,245,000) $ (6,381,000)
Annualized gain on investment............................................. - (32,000)
----------------------------------
Total deferred tax liability.............................................. (5,245,000) (6,413,000)
----------------------------------
Allowance for doubtful accounts........................................... 191,000 49,000
Depletion carryforwards................................................... 196,000 361,000
Operating loss and other carryforwards.................................... 3,859,000 2,534,000
----------------------------------
Total deferred tax assets........................................ 4,246,000 2,944,000
----------------------------------
Valuation allowance....................................................... (290,000) -
----------------------------------
Net Deferred Tax Liability....................................... $ (1,289,000) $ (3,469,000)
==================================
</TABLE>
The Company and its subsidiaries have net operating loss carryforwards
(NOL) of approximately $9,954,000 that expire, if unused, in years through 2012,
and of which approximately $608,000 expire in 1999. Approximately $1,992,000 of
the NOL carries a limitation of approximately $718,000 per year. In addition,
the Company has depletion carryforwards of approximately $517,000. A valuation
allowance reduces deferred taxes based on the criteria set forth in SFAS 109.
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 will be 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
F-13
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 year-end, 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.
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 $5.875 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
F-14
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
issued, resulting in net proceeds to the Company after offering costs of
$9,282,000. Dividends of $22,000 and $875,000 were declared in 1996 and 1997,
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, 1997, 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, 1997, the Company had 166,000 total warrants issued, of which
141,000 had been earned.
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.
F-15
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Earnings Per Share
During 1997, the Company adopted SFAS No. 128, "Earnings per Share." As a
result of the adoption of SFAS No. 128, all earnings per share ("EPS") amounts
have been restated to the basic and diluted presentations required by this
pronouncement. The following table reconciles the numerators and denominators
used in the computations of both basic and diluted EPS:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
For the Year Ended For the Year Ended
December 31, 1997 December 31, 1996
-----------------------------------------------------------------------------------------
Per Per
Loss Shares Share Income Shares Share
(Numerator) (Denominator) Amount (Numerator) (Denominator) Amount
-----------------------------------------------------------------------------------------
Income (Loss) before extraordinary
item.......................... $ (2,108,000) $ 509,000
Less: Preferred Stock dividends (875,000) (406,000)
------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available to
common stockholders........... (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......... $ (2,983,000) 14,535,805 $ (.21) $ 103,000 12,561,760 $ .01
============================================================================================
</TABLE>
The warrants, options, and convertible preferred stock were not included in
the computation of diluted earnings per share in 1997 since the Company incurred
a loss before extraordinary items for the year and any effect would be
anti-dilutive. At December 31, 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 $5.875 per share.
Additionally, effective December 1997, the Company issued a note payable for
$2,000,000 due December 1, 1998, payable, at its option, in either cash or
common stock.
NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION
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
F-16
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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 1999. 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:
1998....................................................... $ 263,886
1999....................................................... 266,770
2000....................................................... 271,157
2001....................................................... 246,959
Thereafter................................................. 13,155
----------------
Total Minimum Payments Required $ 1,061,927
================
Rental expense was $218,951 and $129,169 for 1997 and 1996, respectively.
In December, 1997, the Company amended its Revolving Loan Agreement with
certain banks to permit guarantees of NGTS, LLC's debt, not to exceed
$4,000,000, and trade payables or letters of credit for the purchase of natural
gas not to exceed an aggregate of $15,000,000 on behalf of NGTS, LLC. As of
December 31, 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, 1997 is adequate.
Management estimates the market values of notes receivable and payable
based on expected cash flows. At December 31, 1997, the Company provided a
$200,000 reserve for the carrying value of a note receivable. After establishing
this reserve, management believes those market values approximate carrying
values at December 31, 1997 and 1996. The market values of equity investments
are based upon quoted prices (see Note 1).
F-17
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 1997, the Company had open contracts for oil price collars on
30,000 barrels of oil per month (with cap and floor prices of $23.25 and $18.50,
respectively) through December, 1998. At December 31, 1997, the Company had open
contracts for gas prices swaps of 500,000 MMbtu of gas at an average price of
$2.45 during January, 1998, 300,000 MMbtu of gas at an average price of $2.54
during February, 1998, and 300,000 MMbtu of gas at an average price of $2.25
during March, 1998. Additionally, the Company had written call options on
100,000 MMbtu per month for the months of January through March, 1998 at prices
averaging $2.90 per MMbtu. Net losses related to derivative transactions for the
years ended December 31, 1997 and 1996 were $1,537,000 and $272,000,
respectively. At December 31,1997, the unrealized gain from derivative
transactions was $336,000.
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"). In addition, the Company
authorized, after the effect of the ESOP transaction described below, the
issuance of its common stock to participants in the Magnum Hunter Resources,
Inc. 401(k) plan in an amount that matched employee contributions up to one
hundred percent (100%). The cost of this matching contribution was $157,000 and
$59,000 in 1997 and 1996, respectively.
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 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 elected to
pay the loan and accrued interest and contribute the stock as part of the
$157,000 matching of employee contribution to the 401(k) plan.
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
options is at the discretion of the Board, with 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.
In addition, 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.
F-18
<PAGE>
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:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
1997 1996
----------------------------------------------------------------------
Weighted Weighted
Average Average
Shares Exercise Price Shares Exercise Price
----------------------------------------------------------------------
Outstanding - Beginning of Year....... 1,187,742 $ 3.72 264,558 $ 0.82
Granted............................... 1,440,000 5.93 935,442 4.50
Exercised............................. (89,242) 3.01 (12,258) .73
Canceled.............................. - - - -
----------------------------------------------------------------------
Outstanding - End of Year............. 2,538,500 $ 5.00 1,187,742 $ 3.72
======================================================================
Exercisable - End of Year............. 2,338,500 970,684
======================================================================
The following is a summary of plan stock options outstanding at December 31, 1997:
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Weighted
Average
Number of Remaining
Options Contractual Life Number of
Exercise Price Outstanding (Years) Exercisable Options
-----------------------------------------------------------------------
$ .73..................... 191,522 3.0 191,522
1.65..................... 25,536 3.0 25,536
4.50..................... 881,442 3.7 881,442
4.375.................... 25,000 4.0 25,000
5.375.................... 10,000 4.3 10,000
5.25..................... 35,000 4.4 35,000
5.875.................... 1,170,000 5.0 1,170,000
6.0...................... 100,000 5.0 -
7.125.................... 100,000 5.0 -
-----------------------------------------------------------------------
2,538,500 2,338,500
=======================================================================
</TABLE>
The Company adopted the disclosures only portion of SFAS No. 123 as it
continued to follow the provisions of APB No. 25, which is the intrinsic value
method of accounting for stock-based compensation.
On a pro forma basis, the effect of stock based compensation had the
Company adopted Statement No. 123 is as follows:
<TABLE>
<CAPTION>
<S> <C> <C>
1997 1996
--------------------------------------
Net Income (Loss) Applicable to Common Stock:
As reported............................................ $ (4,367,000) $ 103,000
Pro Forma.............................................. (6,573,000) (1,540,000)
Basic Earnings (Loss) per Share:
As reported, after extraordinary loss.................. $ (.30) $ .01
Pro Forma.............................................. (.45) (.12)
Diluted Earnings (Loss) per Share:
As reported, after extraordinary loss.................. (.30) .01
Pro Forma.............................................. (.45) (.12)
</TABLE>
F-19
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The weighted average grant date fair value of options granted was $2.87
during 1997. Fair value of options and warrants was calculated by using the
Black-Scholes options pricing model using the following weighted average
assumptions for 1997 activity: risk free interest rate of 5.67%, expected life
of 5.0 years, expected volatility of 57.0% and no dividend yield.
NOTE 15 -- EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND
CHANGE-IN-CONTROL ARRANGEMENTS
Mr. Gary C. Evans and Mr. Matthew C. Lutz have employment agreements with
Magnum Hunter Resources, Inc. Mr. Evans' agreement terminates December 31, 1998
and continues thereafter on a year to year basis and provides for a base salary
of $250,000 per annum. Mr. Lutz's agreement terminates September 30, 1998 and
continues thereafter on a year to year basis and provides for a base salary of
$150,000 per annum. Both 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 associate with a business that competes
with the Company for a period of one year after cessation of employment. The
Company also has key man life insurance on Mr. Evans in the amount of
$5,000,000.
NOTE 16 -- SUBSEQUENT EVENTS
On January 9, 1998, the Company adopted a Shareholder Rights Plan, pursuant
to which Rights would be distributed as a dividend to its common stockholders at
a rate of one Right for each share of common stock held of record on January 20,
1998. Under the Rights Plan, the Rights will initially represent the right to
purchase one one-hundreth of a share of 1998 Series A Junior Participating
Preferred Stock for $35.00 per one one-hundreth of a share. The Rights will
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 attached to and trade with the Company's common stock.
The Rights will expire January 20, 2008. The Rights may be redeemed by the
continuing members of the Company's Board of Directors at $.01 per Right prior
to the tenth day after a person or group has accumulated 15% or more of the
Company's common stock. The Rights will not be taxable to the Company's
shareholders. In the event that a person or group acquires 15% or more of the
Company's common stock, the Rights would then be modified to represent the right
to receive for the exercise price, Magnum Hunter common stock having a value
worth twice the exercise price. In the event that the Company is involved in a
merger or other business combination at any time after a person or group has
acquired 15% or more of Magnum Hunter's common stock, the Rights will be
modified so as to entitle a holder to buy a number of shares of common stock of
the acquiring entity having a market value of twice the exercise price of each
Right.
On January 28, 1998, the Company announced, and later amended, 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 announced that 1,745,353 Units, or 40.1% of the total number of Units
outstanding, had been tendered.
F-20
<PAGE>
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, 1996
Proved reserves.............................. 5,338,255 90,565,997
Proved developed reserves.................... 1,962,184 71,275,141
December 31, 1997
Proved reserves.............................. 20,946,415 207,775,770
Proved developed reserves.................... 12,036,234 154,964,396
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, 1995.................. 3,767,739 14,071,916
Purchase of minerals-in-place.................. 2,678,579 81,943,557
Sale of minerals-in-place...................... (214,381) (1,318,164)
Extensions and discoveries..................... - 151,606
Production..................................... (191,203) (2,674,793)
Revisions of estimates......................... (702,479) (1,608,125)
-------------------------------
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 18,206,952
--------------------------------
Reserves at December 31, 1997................... 20,946,415 207,775,770
================================
F-21
<PAGE>
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 and
impairment as of December 31, 1997 and 1996 were as follows:
1997 1996
----------------------------
Unproved oil and gas properties................... $ 516,560 $ 459,254
Proved properties................................. 227,027,869 70,574,890
----------------------------
Gross Capitalized Costs........................... 227,544,429 71,034,144
Accumulated depreciation, depletion and impairment. (16,091,001) (4,513,541)
-----------------------------
Net Capitalized Costs................... $211,453,428 $ 66,520,603
=============================
Costs incurred in oil and gas producing activities, both capitalized and
expensed, during the years ended December 31, 1997 and 1996 as follows:
1997 1996
----------------------------
Property acquisition costs
Proved properties................................. $ 137,430,583 $ 31,982,821
Unproved properties............................. 57,306 -
Exploration costs............................... 737,936 1,114,733
Development costs................................. 18,284,460 837,273
----------------------------
Total Costs Incurred.................... $ 156,510,285 $ 33,934,827
=============================
Results of operations from oil and gas producing activities for the years
ended December 31, 1997 and 1996 were as follows:
1997 1996
----------------------------
Oil and gas production revenue.................... $ 35,658,032 $ 10,247,688
Disposal services revenue......................... 5,130 20,487
Production costs.................................. (13,901,537) (4,389,465)
Depreciation and depletion........................ (11,577,460) (2,598,939)
----------------------------
Results of Operations for Producing Activities $ 10,184,165 $ 3,279,771
============================
The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 1997 and 1996 were as
follows:
1997 1996
----------------------------
Future cash inflows.............................. $ 811,512,060 $ 492,157,062
Future development and production costs.......... (336,730,398) (138,614,804)
----------------------------
Future net cash flows, before income tax......... 474,781,662 353,542,258
Future income taxes.............................. (93,828,793) (102,341,098)
----------------------------
Future Net Cash Flows............................ 380,952,869 251,201,160
10% annual discount.............................. (211,181,318) (134,116,299)
----------------------------
Standardized Measure of Discounted Future Net
Cash Flows................................ $ 169,771,551 $ 117,084,861
=============================
F-22
<PAGE>
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, 1997 and 1996 were as
follows:
<TABLE>
<CAPTION>
<S> <C> <C>
1997 1996
------------------------------------
Purchases of minerals-in-place....................................... $ 136,739,277 $ 129,544,769
Sales of minerals-in-place........................................... (191,741) (2,195,780)
Extensions, discoveries and improved recovery, less related costs 38,555 302,785
Sales of oil and gas produced, net of production costs............... (21,756,495) (5,858,223)
Development costs incurred during the period......................... 16,289,428 -
Revision of prior estimates:
Net change in prices and costs..................................... (141,112,592) 14,993,539
Change in quantity estimates....................................... 46,255,955 (10,107,737)
Accretion of discount................................................ 11,708,486 2,981,968
Net change in income taxes........................................... 4,715,817 (42,396,139)
------------------------------------
Net Change.......................................... $ 52,686,690 $ 87,265,182
====================================
</TABLE>
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 assumption 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-23
<PAGE>
Item 8. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure.
The accounting firm of Hein + Associates, L.L.P. ("Hein") represented the
Company as its independent accountants during fiscal year 1995 and was dismissed
by the Company's Board of Directors on January 20, 1997. During the Company's
fiscal year ended December 31, 1995, and subsequent interim period, there were
no disagreements between the Company and Hein on any matter of accounting
principals or practices, financial statement disclosure, or auditing scope or
procedure, which disagreements, if not resolved to the satisfaction of Hein,
would have caused it to make reference to the subject matter of the disagreement
in connection with its reports. Hein's reports on the financial statements of
the Company for the fiscal year ended December 31, 1995, did not contain an
adverse opinion or disclaimer of opinion, and were not qualified or modified as
to uncertainty, audit scope or accounting principles. The Company's Board of
Directors appointed Deloitte & Touche LLP as the Company's independent
accountants on January 20, 1997.
PART III
Item 9. 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.
<TABLE>
<CAPTION>
<S> <C> <C>
Name Age Title
Gary C. Evans................... 40 Director, President, Chief Executive Officer
Matthew C. Lutz................. 63 Chairman of the Board and Executive Vice President of
Exploration and Business Development
Chris Tong...................... 41 Senior Vice President and Chief Financial Officer
David S. Krueger................ 48 Vice President and Chief Accounting Officer
Morgan F. Johnston.............. 37 Vice President, General Counsel and Secretary
Richard R. Frazier.............. 51 President and Chief Operating Officer of Magnum Hunter
Production, Inc. and Gruy
Michael McInerney . . . . . . . 56 Vice President, Corporate Development & Investor Relations
R. Douglas Cronk . . . . . . . . .50 Vice President of Magnum Hunter Production, Inc. and Gruy
Craig Knight.................... 41 Vice President of Operations of Hunter Gas Gathering, Inc.
Gerald W. Bolfing............... 69 Director
Oscar C. Lindemann.............. 75 Director
John H. Trescot, Jr............. 72 Director
James E. Upfield................ 77 Director
</TABLE>
Gary C. Evans has served as President, Chief Executive Officer and a
director of the Company since December, 1995 and Chairman and Chief Executive
Officer of all of the Hunter Subsidiaries since their formation or acquisition.
He served as Chief Financial Officer from January 1997 to August 1997. He acted
as Chairman, President and Chief Executive Officer of Hunter from September 1992
until October 1996. Previously, he was President and Chief Operating Officer of
Hunter from December 1990 to September 1992. From 1985 to 1990, Mr. Evans was
Chairman, President and Chief Executive Officer of Sunbelt Energy, Inc. and its
subsidiaries, which were merged with Hunter. 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 Karts International
Incorporated, a Nasdaq-listed company.
26
<PAGE>
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.
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.
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.
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 1, 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 is
licensed to practice law in the State of Texas.
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.
27
<PAGE>
Michael 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.
R. Douglas Cronk, has served as Vice President of Operations for
Magnum Hunter Production, Inc. and Gruy 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.
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.
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.
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.
28
<PAGE>
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.
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.
29
<PAGE>
Item 10. 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 officers of the Company. No other officer individually received annual
cash compensation exceeding $100,000 during the past three years.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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 1997 $200,025 $250,000 - - - - -
President and CEO 1996 $150,000 $100,000 - - - - -
Matthew C. Lutz 1997 $106,000 $100,000 - - - - -
Executive V.P. and 1996 $ 65,600 $ 10,000 - - - - -
Chairman
Richard R. Frazier 1997 $124,200 $ 50,000 - - - - -
President of
Magnum Hunter
Production, Inc.
David S. Krueger 1997 $ 93,366 $ 10,000 - - - - -
Vice President and
Chief Accounting
Officer
R. Douglas Cronk 1997 $ 92,033 $10,000 - - - - -
V.P. of Magnum
Hunter Production, Inc.
L.T. Rochford 1995 $ 96,000 $ -0- $15,693 - - - -
CEO
</TABLE>
Option/SAR Grants in Last Fiscal Year
(Individual Grants)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Number of Securities Percent of total Exercise of
Underlying Options/SARs options/SARs granted to base price
Name granted (#) employees in fiscal year ($/Sh) Expiration date
(a) (b) (c) (d) (e)
- ----------------------------------------------------------------------------------------------------------------------
Gary C. Evans 50,000 $4.50 12/05/2001
500,000 36.0% $5.875 12/12/2002
Richard R. Frazier 50,000 $4.50 12/05/2001
100,000 9.8% $5.875 12/12/2002
Matthew C. Lutz 350,000 23.0% $5.875 12/12/2002
David S. Krueger 25,000 1.6% $5.875 12/12/2002
R. Douglas Cronk 25,000 1.6% $5.875 12/12/2002
</TABLE>
30
<PAGE>
Compensation of Directors
The Company has six individuals who serve as directors, four 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 four 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 the first six months of 1997, independent directors
received $500 per meeting as compensation for their services. Beginning July 1,
1997, independent directors receive $1,000 per meeting. In addition, once a year
each independent director will be granted an option to acquire 10,000 shares of
the Company's common stock at an exercise price equal to the market price of the
Company's 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 and Mr. Matthew C. Lutz have employment agreements with
Magnum Hunter Resources, Inc. Mr. Evans' agreement terminates December 31, 1998
and continues thereafter on a year to year basis and provides for a base salary
of $250,000 per annum. Mr. Lutz's agreement terminates September 30, 1998 and
continues thereafter on a year to year basis and provides for a base salary of
$150,000 per annum. Both 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 associate with a business that competes
with the Company for a period of one year after cessation of employment. The
Company also has key man life insurance on Mr. Evans in the amount of
$5,000,000.
The Company has not entered into any contracts or arrangements with any
officer which would provide such individual with a form of compensation
resulting from such individual's resignation, retirement or any other
termination of such officer's employment with the Company or its subsidiary, or
from a change-in-control of the Company or a change in the officer's
responsibilities following a change-in-control.
Section 16 (a) Beneficial Ownership Reporting Compliance
For the fiscal year 1996, Gary C. Evans filed one late report on Form 3 and
three late reports on Form 4 relating to five transactions that occurred during
June, October, and December of 1996. For the fiscal year 1996, Matthew C. Lutz
filed one late report on Form 3 and three late reports on Form 4 relating to
four transactions that occurred during June, October, and December of 1996. For
the fiscal year 1996, Richard R. Frazier filed one late report on Form 3 and two
late reports on Form 4 relating to three transactions that occurred during
October, and December of 1996. For the fiscal year 1996, Gerald W. Bolfing filed
one late report on Form 3 and two late reports on Form 4 relating to two
transactions that occurred during October, and December of 1996. For the fiscal
year 1996, James E. Upfield filed one late report on Form 3 and three late
reports on Form 4 relating to three transactions that occurred during June,
October, and December of 1996. For the fiscal year 1996, Oscar C. Lindemann
filed one late report on Form 3 and two late reports on Form 4 relating to two
transactions that occurred during June and December of 1996. For the fiscal year
1997, Chris Tong filed one late report on Form 3 and three late reports on Form
4 relating to five transactions that occurred during September, November, and
December of 1997. For the fiscal year 1997, John H. Trescot, Jr. filed one late
report on Form 3 and three late reports on Form 4 relating to five transactions
that occurred during June, August, and December of 1997. For the fiscal year
1997, Gary C. Evans filed three late reports on Form 4 relating to three
transactions that occurred during August, November and December of 1997. For the
fiscal year 1997, Matthew C. Lutz filed two late reports on Form 4 relating to
two transactions that occurred during August and December of 1997. For the
fiscal year 1997,
31
<PAGE>
Richard R. Frazier filed three late reports on Form 4 relating to three
transactions that occurred during May, August, and December of 1997. For the
fiscal year 1997, Gerald W. Bolfing filed two late reports on Form 4 relating to
two transactions that occurred during August and December of 1997. For the
fiscal year 1997, James E. Upfield filed one late report on Form 4 relating to
one transaction that occurred during December of 1997. For the fiscal year 1997,
Oscar C. Lindemann filed two late reports on Form 4 relating to two transactions
that occurred during August and December of 1997. In making this disclosure, the
Company has relied solely on written representations of its directors and
executive officers and copies of the reports filed by them with the SEC.
32
<PAGE>
Item 11. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth certain information as of March 15, 1998,
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 two 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 owned, as of
March 24, 1997, any shares of the Company's Series A Preferred Stock or its 1996
Series A Convertible Preferred Stock. The business address of each officer and
director listed below is: c/o Magnum Hunter Resources, Inc., 600 East Las
Colinas Blvd., Suite 1200, Irving, Texas 75039.
<TABLE>
<CAPTION>
<S> <C> <C>
Common Stock
Beneficially Owned
Number of Percent
Name Shares of Class (3)
Directors and Executive Officers
Gary C. Evans ............................................ 2,178,226 (1) 10.0%
Matthew C. Lutz........................................... 672,411 3.0%
Gerald W. Bolfing......................................... 359,558 1.6%
Oscar C. Lindemann........................................ 37,160 *
John H. Trescot, Jr....................................... 60,154 *
James E. Upfield.......................................... 64,704 *
Richard R. Frazier........................................ 248,623 1.1%
Chris Tong................................................ 53,300 *
All directors and executive officers as a group (8 persons) 3,507,033 15.0%
Beneficial owners of 5 percent or more (excluding persons named
above)
TCW Group, Inc.
865 South Figueroa Street
Los Angeles, CA 90017.................................... 1,702,127 (2) 7.8%
Janus Capital Corporation
100 Fillmore St. , Suite 300
Denver, CO. 80206........................................ 1,474,900 6.8%
</TABLE>
(1) 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.
(2) 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.
(3) 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 12. Certain Relationships and Related Transactions.
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 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.
33
<PAGE>
Item 13. 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)
4.8 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)
4.9 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)
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)
21 Subsidiaries of the Registrant (Incorporated by reference to
Registration Statement on Form S-4, File No. 333-2290)
27 Financial Data Schedule
* Filed herewith.
(B) Form 8-K's
A Form 8-K, dated December 17, 1997 was filed by the Company on December 29,
1997 under Item 2 concerning the Company's acquisition of a thirty percent
membership interest in NGTS, L.L.C., a gas marketing company located in Dallas,
Texas. The Company amended the Form 8-K on February 13, 1998 to report the
historical and pro forma financial information for the NGTS acquisition.
34
<PAGE>
SIGNATURES
Pursuant to the requirements of the Section 13 or 15 (d) of the Securities and
Exchange Act of 1934, the Company has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
MAGNUM HUNTER RESOURCES, INC.
By: /s/ Gary C. Evans March 27, 1998
- ---------------------------------------------
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.
<TABLE>
<CAPTION>
<S> <C> <C>
Signature Title Date
/s/ Gary C. Evans Director, President
- -------------------------- Chief Executive Officer March 27, 1998
Gary C. Evans
/s/ Matthew C. Lutz Chairman of the Board and March 27, 1998
- -------------------------- Executive Vice President of
Matthew C. Lutz Exploration and Business
Development
/s/ Chris Tong Senior Vice President and March 27, 1998
- --------------------------- Chief Financial Officer
Chris Tong
/s/ David S. Krueger Vice President and March 27, 1998
- --------------------------- Chief Accounting Officer
David S. Krueger
/s/ Morgan F. Johnston Vice President, General Counsel March 27, 1998
- ------------------------- and Secretary
Morgan F. Johnston
/s/ Gerald W. Bolfing Director March 27, 1998
- --------------------------
Gerald W. Bolfing
/s/ Oscar C. Lindemann Director March 27, 1998
- -----------------------
Oscar C. Lindemann
/s/ John H. Trescot, Jr. Director March 27, 1998
- ---------------------------
John H. Trescot, Jr.
/s/ James E. Upfield Director March 27, 1998
- ---------------------------
James E. Upfield
</TABLE>
SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
This Second Amendment to Amended and Restated Credit Agreement (this
"Amendment") is dated as of September 30, 1997, by and among MAGNUM HUNTER
RESOURCES, INC., a Nevada corporation (the "Borrower"), each Bank (as defined in
the Credit Agreement), BANKERS TRUST COMPANY, individually, as administrative
agent (in such capacity, together with its successors in such capacity, the
"Administrative Agent"), and as an issuing bank, and BANQUE PARIBAS, a French
bank acting through its Houston Agency, individually, as collateral agent (in
such capacity, together with its successors in such capacity, the "Collateral
Agent"), and as documentation agent (in such capacity, together with its
successors in such capacity, the "Documentation Agent").
R E C I T A L S:
WHEREAS, the Borrower, each Bank then a party, the Administrative
Agent, the Documentation Agent, and First Union National Bank ("First Union"),
as collateral agent and syndication agent, entered into that certain Amended and
Restated Credit Agreement dated as of April 30, 1997 (the "Original Credit
Agreement") pursuant to which the Banks have agreed to make revolving credit
loans available to the Borrower under the terms and provisions stated therein;
and
WHEREAS, the parties to the Original Credit Agreement entered into a
First Amendment to Amended and Restated Credit Agreement, Resignation of
Collateral Agent and Appointment of Substitute Collateral Agent dated as of May
29, 1997 (together with the Original Credit Agreement, the "Credit Agreement");
and
WHEREAS, as of October 1, 1997, CIBC, Inc. became a Bank under the
Credit Agreement; and
WHEREAS, the Borrower has requested that the Banks and the Agents (i)
increase the Borrowing Base to $65,000,000, (ii) increase the Commitment of each
Bank, (iii) amend the Consolidated Interest Coverage Ratio and (iv) amend
certain provisions of the Credit Agreement; and
WHEREAS, the Banks and the Agents are willing to amend the Credit
Agreement as hereinafter provided; and
WHEREAS, the Borrower, the Banks and the Agents now desire to amend the
Credit Agreement as herein set forth.
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 1
<PAGE>
NOW, THEREFORE, in consideration of the premises herein contained and
other good and valuable considerations, the receipt and sufficiency of which are
hereby acknowledged, the parties hereto agree as follows:
ARTICLE I
Definitions
Section 1.1 Definitions. Capitalized terms used in this Amendment, to the
extent not otherwise defined herein, shall have the same meaning as in the
Credit Agreement, as amended hereby.
ARTICLE II
Amendments
Section 2.1 Additional Definitions. Section 1.1 is amended by adding the
following definitions in alphabetical order:
"Dissenting Bank" has the meaning assigned to it in Section 2.8(c) hereof.
"Unused Availability" means an amount equal to the difference between the
Borrowing Base and (a) outstanding Loans plus (b) outstanding Letter of Credit
Liabilities.
Section 2.2 Amendment to Definition of Consolidated Current Assets. The
definition of "Consolidated Current Assets" found in Section 1.1 is amended by
adding the following phrase at the end thereof: "plus Unused Availability".
Section 2.3 Amendment to Definition of Majority Banks. The definition of
"Majority Banks" found in Section 1.1 is amended by deleting each reference to
"75%" and inserting in lieu thereof references to "80%".
Section 2.4 Amendment to Section 2.8.
(a) Section 2.8(a) is amended by deleting the second and third sentences
thereof and inserting the following in lieu thereof:
"Effective October 1, 1997, the Borrowing Base shall be $65,000,000 and
shall be redetermined from time to time as provided herein."
(b) Section 2.8 is further amended by adding thereto a new subsection
reading as follows:
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 2
<PAGE>
"(c) In the event a Bank or Banks do not approve a proposed
Borrowing Base or Borrowing Base determined after consultation, but the
Required Banks do, the Administrative Agent and the Borrower may, but
shall not be required to, replace the Dissenting Bank with an Eligible
Assignee within 90 days of the applicable Determination Date or date of
special determination and upon payment to the Dissenting Bank of all of
its Loans and execution and delivery by the Eligible Assignee of an
Assignment and Acceptance, the Dissenting Bank shall no longer be a
Bank hereunder or have any Commitment or obligations to the Borrower."
Section 2.5 Amendment to Section 10.3. Section 10.3 is amended by adding
the following phrase immediately after the word "Person" found in the fourth
line thereof: "except as specifically permitted in Section 10.5 hereof" and by
changing the reference to "$1,000,000" to $1,500,000."
Section 2.6 Amendment to Section 10.5. Section 10.5 is amended by deleting
the word "The" from the first line and adding the following phrase before the
word "Borrower" in said line: "Without the prior written consent of the Majority
Banks, the" and by deleting the reference to "350,000" found in the fifth line
thereof and inserting in lieu thereof a reference to "1,500,000".
Section 2.7 Amendment to Section 11.1. Section 11.1 is amended in its
entirety to read ------------------------- as follows:
"Section 11.1 Consolidated Interest Coverage Ratio. The
Borrower will not permit its Consolidated Interest Coverage Ratio,
measured as of the last day of any calendar quarter for the twelve
month period then ended, to be less than (a) 1.80 to 1.0 at the end of
any calendar quarter through March 31, 1998, (b) 2.0 to 1.0 at the end
of any calendar quarter from April 1, 1998 through June 30, 1998, (c)
2.25 to 1.0 at the end of any calendar quarter from July 1, 1998
through September 30, 1998 and (d) 2.50 to 1.0 at the end of any
calendar quarter after September 30, 1998."
Section 2.8 Amendment to Section 11.4. Section 11.4 is amended in its
entirety to read ------------------------- as follows:
"Section 11.4 Debt to Capitalization Ratio. Borrower will not
permit its Debt to Capitalization Ratio, measured as of the last day of
any calendar quarter to be more than (a) 0.86 to 1.0 as of the end of
any calendar quarter, through March 31, 1998, (b) 0.75 to 1.0 as of the
last day of any calendar quarter after March 31, 1998 through September
30, 1998 and (c) 0.70 to 1.0 as of the last day of any calendar quarter
after September 30, 1998."
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 3
<PAGE>
Section 2.9 Increased Commitments. The Commitments listed on the signature
pages to the Credit Agreement are hereby deleted, and the new Commitments shall
be as set forth on the signature pages to this Amendment.
Section 2.10 Borrower's Area Code. The area code for the Borrower's
telephone and telecopy numbers found on the Borrower's signature page to the
Credit Agreement is changed from "214" to "972".
Section 2.11 New Notes. The Borrower agrees to execute new Notes in favor
of the Banks, in the principal amount of each such Bank's modified Commitment.
ARTICLE III
Conditions to Precedent
Section 3.1 Necessary Documentation. This Amendment shall be effective when
the Agent shall have received the following, each dated (unless otherwise noted)
the date hereof, in form and substance satisfactory to the Agents:
(a) This Amendment executed by all parties;
(b) Replacement Notes, dated October 1, 1997, executed by the
Borrower in respect of the Assignment and Acceptance from the remaining
Banks under the Original Credit Agreement to CIBC, Inc.;
(c) A Certificate of the Chief Financial Officer of the
Borrower in the form attached hereto as Annex I;
(d) Notes executed by the Borrower reflecting the Commitments
set out on the signature pages to this Amendment; and
(e) Resolutions of the Board of Directors of the Borrower and
each Obligated Party, certified by its Secretary or Assistant
Secretary, that authorized the execution and delivery of this Amendment
and the replacement Notes.
Section 3.2 Representations and Warranties. All representations and
warranties contained in the Credit Agreement shall be true and correct on and as
of the date hereof with the same force and effect as if such representations and
warranties had been made on and as of such date.
Section 3.3 Additional Documentation. The Agents shall have such additional
approvals, opinions or documents as the Agents or their counsel, Winstead
Sechrest & Minick P.C., may reasonably request.
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 4
<PAGE>
ARTICLE IV
Miscellaneous
Section 4.1 Ratifications, Representations and Warranties. Except as
expressly modified and superseded by this Amendment, the terms and provisions of
the Credit Agreement and the other Loan Documents are ratified and confirmed and
shall continue in full force and effect. The representations and warranties
contained herein and in all other Loan Documents, as amended hereby, shall be
true and correct as of, and as if made on, the date hereof. The Borrower, the
Banks and the Agents agree that the Credit Agreement as amended hereby shall
continue to be legal, valid, binding and enforceable in accordance with its
terms.
Section 4.2 Reference to the Credit Agreement. Each of the Loan Documents,
including the Credit Agreement and any and all other agreements, documents or
instruments now or hereafter executed and delivered pursuant to the terms hereof
or pursuant to the terms of the Credit Agreement as amended hereby, are hereby
amended so that any reference in such Loan Documents to the Credit Agreement
shall mean a reference to the Credit Agreement as amended hereby.
Section 4.3 Expenses. The Borrower agrees to pay on demand all expenses set
forth in Section 14.1 of the Credit Agreement.
Section 4.4 Severability. Any provisions of this Amendment held by court of
competent jurisdiction to be invalid or unenforceable shall not impair or
invalidate the remainder of this Amendment and the effect thereof shall be
confined to the provisions so held to be invalid or unenforceable.
Section 4.5 Applicable Law. This Amendment and all other Loan Documents
executed pursuant hereto shall be governed by and construed in accordance with
the laws of the State of New York.
Section 4.6 Successors and Assigns. This Amendment is binding upon and
shall inure to the benefit of the Banks, the Agents and the Borrower and their
respective successors and assigns.
Section 4.7 Counterparts. This Amendment may be executed in one or more
counterparts, each of which when so executed shall be deemed to be an original
but all of which when taken together shall constitute one and the same
instrument.
Section 4.8 Headings. The headings, captions, and arrangements used in this
Amendment are for convenience only and shall not affect the interpretation of
this Amendment.
Section 4.9 NO ORAL AGREEMENTS. THIS AMENDMENT AND ALL OTHER INSTRUMENTS,
DOCUMENTS AND AGREEMENTS EXECUTED AND DELIVERED IN CONNECTION HEREWITH REPRESENT
THE FINAL AGREEMENT BETWEEN THE PARTIES, AND MAY NOT BE CONTRADICTED BY EVIDENCE
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 5
<PAGE>
OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.
THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
[Balance of this page intentionally left blank.]
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 6
<PAGE>
EXECUTED as of the day and year first above written.
BORROWER:
MAGNUM HUNTER RESOURCES, INC.
By:
Name:
Title:
ADMINISTRATIVE AGENT:
BANKERS TRUST COMPANY
By
Name:
Title:
DOCUMENTATION AGENT
AND COLLATERAL AGENT:
BANQUE PARIBAS
By:
Name:
Title:
- and -
By:
Michael H. Fiuzat
Vice President
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 7
<PAGE>
ISSUING BANK:
BANKERS TRUST COMPANY
By
Name:
Title:
BANKS:
Commitment: BANQUE PARIBAS
$46,875,000.00
By:
Name:
Title:
- and -
By:
Michael H. Fiuzat
Vice President
Commitment: BANKERS TRUST COMPANY
$46,875,000.00
By:
Name:
Title:
Commitment: CIBC, INC.
$31,250,000.00
By:
Name:
Title:
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 8
<PAGE>
ACKNOWLEDGEMENT BY GUARANTORS
Each of the undersigned Guarantors hereby (i) consents to the terms and
conditions of the Amendment, (ii) confirms and ratifies the terms of the Amended
and Restated Subsidiary Guaranty, (iii) acknowledges and agrees that its consent
is not required for the effectiveness of the Amendment and (iv) represents and
warrants that (a) no Default or Event of Default has occurred and is continuing,
(b) it is in full compliance with all covenants and agreements pertaining to it
in the Credit Documents and (c) it has reviewed a copy of the Amendment.
Executed as of September 30, 1997.
GUARANTORS:
HUNTER GAS GATHERING, INC.
GRUY PETROLEUM MANAGEMENT CO.
MAGNUM HUNTER PRODUCTION, INC.
CONMAG ENERGY CORPORATION
RAMPART PETROLEUM, INC.
By:
Name:
Title:
SECOND AMENDMENT TO CREDIT AGREEMENT - Page 9
THIRD AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
This Third Amendment to Amended and Restated Credit Agreement (this
"Amendment") is dated as of December 15, 1997, by and among MAGNUM HUNTER
RESOURCES, INC., a Nevada corporation (the "Borrower"), each Bank (as defined in
the Credit Agreement), BANKERS TRUST COMPANY, individually, as administrative
agent (in such capacity, together with its successors in such capacity, the
"Administrative Agent"), and as an issuing bank, and BANQUE PARIBAS, a French
bank acting through its Houston Agency, individually, as collateral agent (in
such capacity, together with its successors in such capacity, the "Collateral
Agent"), and as documentation agent (in such capacity, together with its
successors in such capacity, the "Documentation Agent").
R E C I T A L S:
WHEREAS, the Borrower, each Bank then a party, the Administrative Agent,
the Documentation Agent, and First Union National Bank ("First Union"), as
collateral agent and syndication agent, entered into that certain Amended and
Restated Credit Agreement dated as of April 30, 1997 (the "Original Credit
Agreement") pursuant to which the Banks have agreed to make revolving credit
loans available to the Borrower under the terms and provisions stated therein;
and
WHEREAS, the parties to the Original Credit Agreement entered into a First
Amendment to Amended and Restated Credit Agreement, Resignation of Collateral
Agent and Appointment of Substitute Collateral Agent dated as of May 29, 1997
(the "First Amendment"); and
WHEREAS, as of October 1, 1997, CIBC, Inc. ("CIBC") became a Bank under the
Original Credit Agreement as amended by the First Amendment; and
WHEREAS, the parties to the Original Credit Agreement and CIBC entered into
a Second Amendment to Amended and Restated Credit Agreement dated as of
September 30, 1997 (together with the First Amendment and the Original Credit
Agreement, the "Credit Agreement"); and
WHEREAS, the Borrower has requested that the Banks and the Agents amend the
Credit Agreement to (i) permit the investment in the Marketing LLC (defined
below) in the form of cash and promissory notes; (ii) permit certain Debt
related to the Marketing LLC; (iii) permit it to provide the limited Guarantee
of certain debt of the Marketing LLC; and (iv) permit it to provide certain
Trade Guarantees (defined below) of the Marketing LLC; and
WHEREAS, the Banks and the Agents are willing to amend the Credit Agreement
as hereinafter provided; and
WHEREAS, the Borrower, the Banks and the Agents now desire to amend the
Credit Agreement as herein set forth.
NOW, THEREFORE, in consideration of the premises herein contained and other
good and valuable considerations, the receipt and sufficiency of which are
hereby acknowledged, the parties hereto agree as follows:
ARTICLE I
Definitions
Section 1.1 Definitions. Capitalized terms used in this Amendment, to the
extent not otherwise defined herein, shall have the same meaning as in the
Credit Agreement, as amended hereby.
THIRD AMENDMENT TO CREDIT AGREEMENT - Page 1
<PAGE>
ARTICLE II
Amendments
Section 2.1 Additional Definitions. Section 1.1 is amended by adding the
following definitions in alphabetical order:
"Marketing Debt" means Debt of the Borrower in an amount not
to exceed $4,000,000, which Debt shall consist of the Borrower's
guaranty of Marketing LLC's credit facility. Marketing Debt shall be
characterized as Debt of the Borrower solely for purposes of
calculating the Borrower's Debt to Capitalization Ratio under Section
11.4 hereof.
"Marketing LLC" means the limited liability company being
formed by the Borrower or one of its Subsidiaries and NGTS that will
assume all of NGTS's natural gas marketing operations.
"Marketing Note" means, collectively, one or more promissory
notes in the amount of $2,000,000 issued by the Borrower and payable to
NGTS, which promissory notes shall be payable in cash or common stock
of the Borrower, at the sole option of Borrower. The amount of the
Marketing Note shall not be characterized as Debt, including for
purposes of computing the Borrower's Debt to Capitalization Ratio under
Section 11.4 hereof, so long as the Marketing Note is payable, at the
sole option of the Borrower, in common stock of the Borrower.
"NGTS" means Natural Gas Transmission Services, Inc.
"Permitted Investment in Marketing LLC" means an investment by
the Borrower in Marketing LLC, in an amount not to exceed $4,500,000,
which investment shall consist of (a) approximately $2,500,000 in cash
and (b) the Marketing Note.
"Trade Guarantees" means Contingent Liabilities in lieu of
letters of credit issued on behalf of the Marketing LLC and for which
the Borrower or one of its Subsidiaries are severally, or jointly and
severally with one or more other Persons, or both, liable, which Trade
Guarantees shall not exceed an aggregate of $15,000,000. Joint and
several Trade Guarantees shall be subject to written indemnification
agreements, in form and substance and from Persons satisfactory to the
Agents, in their sole discretion, the effect of which shall be to
reduce the liability of the Borrower. Trade Guarantees will be treated
as Debt solely for the purpose of computing the Borrower's Debt to
Capitalization Ratio and solely for purposes of computing the
Borrower's Debt to Capitalization Ratio under Section 11.4 hereof, the
amount of joint and several Trade Guarantees that are characterized as
Debt in calculating such ratio shall be reduced by giving effect to the
aforementioned written indemnification agreements. Notwithstanding the
foregoing, the Majority Banks shall at all times reserve the right to
include the entire amount of joint and several Trade Guarantees, or any
portion thereof, as Debt in computing the ratio, based on such factors
as the Majority Banks may from time to time deem material, in their
discretion; provided, however, that an Agent on behalf of the Majority
Banks must give the Borrower written notice at least 90 days prior to
the end of a fiscal quarter in order for any amount of joint and
several Trade Guarantees in excess of the Borrower's and its
Subsidiaries' ratable share of such joint and several Trade Guarantees
to be included as Debt in computing the Borrower's Debt to
Capitalization Ratio for such fiscal quarter.
Section 2.2 Amendment to Section 10.1. Section 10.1 is amended by deleting
clause (d) in its entirety and substituting the following in lieu thereof: "(d)
the Senior Unsecured Debt, the Marketing Debt, the Trade Guarantees, and the
Marketing Note."
Section 2.3 Amendment to Section 10.3. Section 10.3 is amended by changing
the reference to "$1,500,000" to $1,500,000 plus the Permitted Investment in
Marketing LLC."
THIRD AMENDMENT TO CREDIT AGREEMENT - Page 2
<PAGE>
Section 2.4 Amendment to Section 10.5. Section 10.5 is amended by deleting
the reference to "1,500,000" found in the fifth line thereof and inserting in
lieu thereof a reference to "1,500,000 plus the Permitted Investment in
Marketing LLC."
ARTICLE III
Conditions Precedent
Section 3.1 Necessary Documentation. This Amendment shall be effective when
the Agent shall have received this Amendment executed by all parties.
Section 3.2 Borrower Covenant. The Borrower shall, within 30 days after the
date hereof, provide ----------------- the Agents with:
(a) Copies of all organizational documents, operating agreements and
regulations of the Marketing LLC; and
(b) Any and all indemnification agreements relating to the Trade Guarantees
and such other information and documents relating to the indemnification
agreements as may be requested by the Agents, in their sole discretion.
Section 3.3 Representations and Warranties. All representations and
warranties contained in the Credit Agreement shall be true and correct on and as
of the date hereof with the same force and effect as if such representations and
warranties had been made on and as of such date.
Section 3.4 Additional Documentation. The Agents shall have such additional
approvals, opinions or documents as the Agents or their counsel, Winstead
Sechrest & Minick P.C., may reasonably request.
ARTICLE IV
Miscellaneous
Section 4.1 Ratifications, Representations and Warranties. Except as
expressly modified and superseded by this Amendment, the terms and provisions of
the Credit Agreement and the other Loan Documents are ratified and confirmed and
shall continue in full force and effect. The representations and warranties
contained herein and in all other Loan Documents, as amended hereby, shall be
true and correct as of, and as if made on, the date hereof. The Borrower, the
Banks and the Agents agree that the Credit Agreement as amended hereby shall
continue to be legal, valid, binding and enforceable in accordance with its
terms.
Section 4.2 Reference to the Credit Agreement. Each of the Loan Documents,
including the Credit Agreement and any and all other agreements, documents or
instruments now or hereafter executed and delivered pursuant to the terms hereof
or pursuant to the terms of the Credit Agreement as amended hereby, are hereby
amended so that any reference in such Loan Documents to the Credit Agreement
shall mean a reference to the Credit Agreement as amended hereby.
Section 4.3 Expenses. The Borrower agrees to pay on demand all expenses set
forth in Section 14.1 -------- of the Credit Agreement.
Section 4.4 Severability. Any provisions of this Amendment held by court of
competent jurisdiction to be invalid or unenforceable shall not impair or
invalidate the remainder of this Amendment and the effect thereof shall be
confined to the provisions so held to be invalid or unenforceable.
THIRD AMENDMENT TO CREDIT AGREEMENT - Page 3
<PAGE>
Section 4.5 Applicable Law. This Amendment and all other Loan Documents
executed pursuant hereto shall be governed by and construed in accordance with
the laws of the State of New York.
Section 4.6 Successors and Assigns. This Amendment is binding upon and
shall inure to the benefit of the Banks, the Agents and the Borrower and their
respective successors and assigns.
Section 4.7 Counterparts. This Amendment may be executed in one or more
counterparts, each of which when so executed shall be deemed to be an original
but all of which when taken together shall constitute one and the same
instrument.
Section 4.8 Headings. The headings, captions, and arrangements used in this
Amendment are for convenience only and shall not affect the interpretation of
this Amendment.
Section 4.9 NO ORAL AGREEMENTS. THIS AMENDMENT AND ALL OTHER INSTRUMENTS,
DOCUMENTS AND AGREEMENTS EXECUTED AND DELIVERED IN CONNECTION HEREWITH REPRESENT
THE FINAL AGREEMENT BETWEEN THE PARTIES, AND MAY NOT BE CONTRADICTED BY EVIDENCE
OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES.
THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
[Balance of this page intentionally left blank.]
THIRD AMENDMENT TO CREDIT AGREEMENT - Page 4
<PAGE>
EXECUTED as of the day and year first above written.
BORROWER:
MAGNUM HUNTER RESOURCES, INC.
By:
Name:
Title:
ADMINISTRATIVE AGENT:
BANKERS TRUST COMPANY
By
Name:
Title:
DOCUMENTATION AGENT
AND COLLATERAL AGENT:
BANQUE PARIBAS
By:
Name:
Title:
- and -
By:
Michael H. Fiuzat
Vice President
ISSUING BANK:
BANKERS TRUST COMPANY
By
Name:
Title:
THIRD AMENDMENT TO CREDIT AGREEMENT - Page 5
<PAGE>
BANKS:
BANQUE PARIBAS
By:
Name:
Title:
- and -
By:
Michael H. Fiuzat
Vice President
BANKERS TRUST COMPANY
By:
Name:
Title:
CIBC, INC.
By:
Name:
Title:
THIRD AMENDMENT TO CREDIT AGREEMENT - Page 6
<PAGE>
ACKNOWLEDGEMENT BY GUARANTORS
Each of the undersigned Guarantors hereby (i) consents to the terms and
conditions of the Amendment, (ii) confirms and ratifies the terms of the Amended
and Restated Subsidiary Guaranty, (iii) acknowledges and agrees that its consent
is not required for the effectiveness of the Amendment and (iv) represents and
warrants that (a) no Default or Event of Default has occurred and is continuing,
(b) it is in full compliance with all covenants and agreements pertaining to it
in the Credit Documents and (c) it has reviewed a copy of the Amendment.
Executed as of December 15, 1997.
GUARANTORS:
HUNTER GAS GATHERING, INC.
GRUY PETROLEUM MANAGEMENT CO.
MAGNUM HUNTER PRODUCTION, INC.
CONMAG ENERGY CORPORATION
RAMPART PETROLEUM, INC.
By:
Name:
Title:
THIRD AMENDMENT TO CREDIT AGREEMENT - Page 7
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<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> Year
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 3,030
<SECURITIES> 0
<RECEIVABLES> 13,786
<ALLOWANCES> (166)
<INVENTORY> 0
<CURRENT-ASSETS> 17,949
<PP&E> 237,487
<DEPRECIATION> 16,589
<TOTAL-ASSETS> 251,069
<CURRENT-LIABILITIES> 15,339
<BONDS> 162,262
0
1
<COMMON> 43
<OTHER-SE> 72,096
<TOTAL-LIABILITY-AND-EQUITY> 251,069
<SALES> 45,955
<TOTAL-REVENUES> 49,923
<CGS> 21,810
<TOTAL-COSTS> 25,555
<OTHER-EXPENSES> 13,580
<LOSS-PROVISION> 373
<INTEREST-EXPENSE> 13,788
<INCOME-PRETAX> (3,373)
<INCOME-TAX> (1,284)
<INCOME-CONTINUING> (2,108)
<DISCONTINUED> 0
<EXTRAORDINARY> (1,384)
<CHANGES> 0
<NET-INCOME> (4,367)
<EPS-PRIMARY> (0.30)
<EPS-DILUTED> (0.30)
</TABLE>
