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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark one)
[X] Annual Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 For the fiscal year ended
December 31, 1998
[ ] Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 For the transition period from
__________ to ___________ .
Commission File No. 1-12508
MAGNUM HUNTER RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Nevada 87-0462881
State or other jurisdiction of (I.R.S. Employer
incorporation or organization Identification No.)
600 East Las Colinas Blvd., Suite 1200, Irving, Texas 75039
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (972) 401-0752
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class Name of each exchange on which registered
Common Stock ($.002 par value) American Stock Exchange
- ------------------------------ -----------------------
Securities registered under Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of March 31, 1999, the aggregate market value of voting stock held by
non-affiliates, computed by reference to the closing price as reported by the
American Stock Exchange, was $51,469,744.
The number of shares outstanding of the registrant's common stock at March 31,
1999 was 20,082,341.
TABLE OF CONTENTS
Securities and Exchange Commission
Item Number and Description
PART I
Item 1. Business............................................................1
The Company........................................................1
Business Strategy .................................................2
Recent Acquisitions ...............................................3
Development and Exploration Activities ............................6
Gathering and Processing of Gas ...................................8
Marketing of Production ...........................................9
Petroleum Management and Consulting Services ......................9
Competition........................................................9
Regulation .......................................................10
Employees ........................................................13
Facilities .......................................................13
Item 2. Properties.........................................................14
Oil and Gas Reserves .............................................14
Oil and Gas Production, Prices and Costs .........................16
Drilling Activity ................................................17
Oil and Gas Wells ................................................18
Oil and Gas Acreage ..............................................18
Item 3. Legal Proceedings..................................................19
Item 4. Submission of Matters to a Vote of Security Shareholders...........19
PART II
Item 5. Market for Common Equity and Related Stockholder Matters...........20
Item 6. Selected Financial Data............................................21
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...............................23
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.........32
Item 8. Financial Statements and Supplementary Data........................35
Item 9. Change in and Disagreements with Accountants on
Accounting and Financial Disclosure...............................36
PART III
Item 10. Directors and Executive Officers of the Registrant..................36
Item 11. Executive Compensation..............................................40
Item 12. Security Ownership of Certain Beneficial Owners and Management......42
Item 13. Certain Relationships and Related Transactions......................43
Glossary............................................................44
Item 14. Exhibits and Reports on Form 8-K....................................46
i
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Form 10-K under "Item 1. Business," "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and elsewhere in this Form 10-K constitute "forward- looking
statements" within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21B of the Securities Exchange Act of 1934, as amended. All
statements, other than statements of historical facts, included in this Form
10-K that address activities, events or developments that Magnum Hunter
Resources, Inc. and its subsidiaries (collectively, the "Company") expects,
projects, believes or anticipates will or may occur in the future, including
such matters as oil and gas reserves, future drilling and operations, future
production of oil and gas, future net cash flows, future capital expenditures
and other such matters, are forward-looking statements. Such forward- looking
statements involve known and unknown risks, uncertainties and other factors
which may cause the actual results, performance or achievements of the Company
to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. Such factors include,
among others, the following: the volatility of oil and gas prices, the Company's
drilling results, the Company's ability to replace reserves, the availability of
capital resources, the reliance upon estimates of proved reserves, operating
hazards and uninsured risks, competition, government regulation, the ability of
the Company to implement its business strategy and other factors referenced in
this Form 10-K.
Item 1. Business
The Company
Magnum Hunter Resources, Inc., a Nevada corporation ("Magnum Hunter" or the
"Company"), is an independent energy company engaged in the exploitation and
development, acquisition, exploration and operation of oil and gas properties
with a geographic focus in Texas, Oklahoma and New Mexico. In December 1995, the
Company consummated the acquisition of all of the subsidiaries of Hunter
Resources, Inc., a Pennsylvania corporation (the "Magnum Hunter Combination"),
and the management of Hunter Resources, Inc. assumed operating control of the
Company. The new management implemented a business strategy that emphasized
acquisitions of long-lived Proved Reserves with significant exploitation and
development opportunities where the Company generally could control the
operations of the properties. As part of this strategy, in June 1996 the Company
acquired the Panoma Properties (as defined herein) from Burlington Resources
Inc. ("Burlington") for a net purchase price of $34.7 million (the "Panoma
Acquisition"). Additionally, in April 1997 the Company acquired the Permian
Basin Properties (as defined herein) from Burlington for a net purchase price of
$133.8 million (the "Permian Basin Acquisition"). On December 31, 1998 the
Company acquired the Spirit 76 Properties (as defined herein) from Spirit Energy
76 ("Spirit 76"), a business unit of Union Oil Company of California, for a net
purchase price of approximately $25 million (the "Spirit 76 Acquisition"). The
Company presently intends to focus its efforts on additional producing property
acquisitions, its substantial inventory of exploitation and development
opportunities and, to a lesser extent, selected exploratory drilling prospects.
The Company has identified over 400 development drilling locations (including
both production and injection wells) on its properties, substantially all of
which are low-risk in-fill drilling opportunities.
On March 27, 1998 the Company acquired an approximately 40% beneficial
ownership interest in TEL Offshore Trust ("TEL"), a trust created under the laws
of the state of Texas pursuant to a cash tender offer for an aggregate purchase
price of approximately $10.3 million (the "TEL Acquisition"). The principal
asset of TEL consists of a 99.99% interest in the TEL Offshore Trust
partnership. Chevron USA Inc. owns the remaining .01% interest in the
partnership. The partnership owns an overriding royalty interest equivalent to a
25% net profits interest in certain oil and gas properties located offshore
Louisiana.
At December 31, 1998, the Company had an interest in 3,059 wells and had
estimated Proved Reserves of 323.2 Bcfe with an SEC PV-10 of $179.4 million.
Approximately 70% of these reserves were Proved Developed Producing Reserves and
88.1% were attributable to the Panoma Properties, the Permian Basin Properties
and the Spirit 76 Properties. At December 31, 1998, the Company's Proved
Reserves had an estimated Reserve Life of approximately 13 years and were 68%
gas. The Company serves as operator for approximately 65% of its properties
(based on the number of producing wells in which the Company owns an interest).
Additionally, the Company owns over 480 miles of gas gathering systems and a 50%
interest in a gas processing plant that is located adjacent to the Company's
largest gas gathering system.
Beginning with the Magnum Hunter Combination in December 1995, the Company
has completed twelve acquisitions for an aggregate net purchase price of $221.8
million. This strategy has added approximately 346.6 Bcfe of reserves
(determined as of the respective times of their acquisition) at an average cost
of $0.63 per Mcfe, as well as a 427 mile gas gathering system and a 50% interest
in the McLean Gas Plant (the "McLean Plant Acquisition"). As a result of its
property acquisitions and successful drilling activities, the Company has
achieved substantial growth as described below:
o Proved Reserves increased to 323.2 Bcfe at year end 1998 from 36.7 Bcfe
at year end 1995;
o SEC PV-10 increased to $179.4 million at year end 1998 from $37.2 million
at year end 1995; and
o Average daily production increased to 57.8 MMcfe in the fourth quarter of
1998 from 0.8 MMcfe in fiscal 1995
Recent Developments
On February 3, 1999, the Company closed various transactions with ONEOK
Resources Company ("ONEOK"), a wholly-owned subsidiary of ONEOK, Inc., the
eighth largest natural gas distributor in the United States, relating to (i)
ONEOK's purchase of $50 million of Convertible Preferred Stock of the Company,
(ii) ONEOK's ability to market certain of the Company's natural gas production
in the state of Oklahoma and (iii) ONEOK's ability to participate in future
acquisitions of the Company in the state of Oklahoma (the "ONEOK Transaction").
The Preferred Stock has a liquidation value of $50 million and is
convertible into the Company's Common Stock at $5.25 per share. Dividends on the
Preferred Stock are payable in cash at the rate of 8% per annum and are
cumulative. The Company used the net proceeds from the transaction to repay
senior bank indebtedness. ONEOK had the right to nominate two new members to the
Company's existing Board of Directors which ONEOK exercised on February 18,
1999. See "Selected Financial Data" and "Directors, Executive Officers,
Promoters and Control Persons."
On September 8, 1998, the Company announced a stock repurchase program for
up to one million shares of the Company's common stock in the open market or
privately negotiated transactions, to be completed before April 30, 1999 at a
value not to exceed $4 million in the aggregate. On February 17, 1999, the
Company revised its previously announced stock repurchase program to spend up to
$4 million without a share limitation.
Business Strategy
The Company's objective is to increase its reserves, production, cash flow
and earnings utilizing a program of (i) exploitation and development of acquired
properties, (ii) strategic acquisitions of Proved Reserves and (iii) a selective
exploration program.
The following are key elements of the Company's strategy:
Exploitation and Development of Existing Properties. The Company has a
substantial inventory of exploitation projects including development drilling,
workovers and recompletions. The Company seeks to maximize the value of its
properties through development activities including in-fill drilling,
waterflooding and other enhanced recovery techniques.
2
Management of Operating Costs. The Company emphasizes strict cost controls
in all aspects of its business and seeks to operate its properties wherever
possible. By operating approximately 65% of its properties (78% of its SEC PV-10
value), the Company is generally able to control direct operating and drilling
costs as well as to manage the timing of development and exploration activities.
Property Acquisitions. Although the Company has an extensive inventory of
exploitation and development opportunities, it continues to pursue strategic
acquisitions which fit its objectives of having Proved Reserves with development
potential and operating control.
Expansion of Gas Gathering, Processing and Marketing Operations. The
Company has implemented several programs to expand and increase the efficiency
of its gas gathering systems. The Company owns over 85% and markets directly and
indirectly approximately 95% of the gas that moves through its gas gathering
systems and, therefore, benefits from any cost and productivity improvements. In
December 1997, the Company acquired a 30% interest in NGTS, LLC ("NGTS"), a
natural gas marketing company marketing approximately 350 MMcf per day as of
December 31, 1998. NGTS markets substantially all of the Company's natural gas.
The Company is also considering opportunities to acquire or develop additional
gas gathering and processing facilities that are associated with its current
production.
Exploration. The Company is systematically increasing its exploration
efforts, focusing on established geological trends where the Company can employ
its geological, geophysical and engineering expertise. The Company is actively
generating and evaluating prospects for the application of 3-D seismic and
advanced drilling technologies.
Recent Acquisitions
The most significant of the Company's completed acquisitions are the Spirit
76 Acquisition, the Permian Basin Acquisition, the Panoma Acquisition, the TEL
Acquisition and the McLean Plant Acquisition.
Spirit 76 Acquisition
On December 31, 1998 the Company acquired from Spirit 76 natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
(the "Spirit 76 Properties") currently producing about 12 million cubic feet of
natural gas equivalent per day. The net purchase price was approximately $25
million after certain purchase price adjustments including preferential rights
exercised by third parties and other customary adjustments.
The Company has received an engineering evaluation from Ryder Scott Company
("Ryder Scott"), independent petroleum engineers engaged by the Company to
evaluate the Company's properties, on the net reserves acquired from Spirit 76.
According to Ryder Scott, as of December 31, 1998, the Spirit 76 Properties had
Proved Reserves of .98 MMBbl of oil and 35.7 Bcf of gas, or on a Natural Gas
Equivalent basis 41.6 Bcfe. Ryder Scott further estimated the SEC PV-10 for the
Spirit 76 Properties to be $37.6 million as of December 31, 1998 based on prices
of $9.42 per Bbl of oil and $2.18 per Mcf of gas. The Proved Reserves are
located principally in the Ardmore Basin in south central Oklahoma and in the
Oklahoma/Texas panhandle. Approximately 86% of the estimated reserves are gas
and 14% are oil located on approximately 50,000 net mineral leasehold acres in
twelve counties in Oklahoma and five counties in Texas. Total net daily
production to the Company's interest acquired is approximately 11 million cubic
feet of natural gas production and 165 barrels of oil. Approximately 80% of the
Proved Reserves were classified Proved Developed Producing Reserves as of
December 31, 1998. The Company has engaged its Houston based geological
affiliate, Swanson Consulting Services, Inc., to begin an evaluation of the most
prospective undeveloped properties located in one of the fields acquired. The
Company's wholly-owned subsidiary, Gruy Petroleum Management Co. ("Gruy"), has
become the operator of 62% or 111 of the 179 wells acquired from Spirit 76.
3
The major fields in the Spirit 76 Properties are the Cumberland, Caddo and
Hitchcock.
Cumberland. The Cumberland Field is located in Bryan and Marshall Counties,
Oklahoma. It was discovered in 1940 and is productive in multiple reservoirs
from the Goddard down to the Arbuckle formation. Depths range from 2,000' to
6,800'. Initially, the field produced oil from the Bromide, McLish and Oil Creek
formations. These zones were unitized in 1964 for waterflood operations, which
continue today. The "Shallow Gas" zones include the Sycamore, Woodford, Hunton,
and Viola. These formations are predominantly gas productive and are produced
commingled. Potential exists for three additional wells to complete development
of the shallow gas on 160-acre spacing. The shallowest zone in the field is the
Goddard, which is a channel sand. The Company has interest in a total of 128
wells in this field, with working interest varying from 17.2% to 100%. The
Company operates all but nine of these wells. The latest available gross
production from such wells averaged 6,200 Mcf/d and 190 Bbl/d.
Caddo. The Caddo Field is located in Carter County, Oklahoma. It was
discovered in 1939 and currently produces gas from various shallow reservoirs,
such as the Goddard, Sycamore, Woodford, Hunton, and Viola, at depths ranging
from 2,200' to 4,200'. Initially all of these reservoirs were produced
separately; however, today, many are commingled down-hole. The Company operates
14 wells with a 100% working interest. The latest available gross production
from the wells averaged 1,920 Mcf/d.
Hitchcock. The Hitchcock Field is located in Blaine County, Oklahoma. It
was discovered in 1965 and produces gas from the Morrow formation at depths
ranging from 8,000' to 8,200'. Original development in this field was based on
640-acre spacing. Recent drilling activity has focused on in-fill locations in
the Morrow. The Company currently has interest in 15 wells, with working
interest varying from 12.5% to 87.5%, and operates six of these wells. The
latest available gross production from the wells averaged 1,676 Mcf/d and 23
Bbl/d.
Permian Basin Acquisition
On April 30, 1997 the Company acquired from Burlington, effective as of
January 1, 1997, certain oil and gas properties consisting of 25 field areas in
west Texas and 22 field areas in southeast New Mexico (the "Permian Basin
Properties"), for a net purchase price of $133.8 million after adjustments
aggregating $9.7 million. The primary producing formations include the Yates,
Seven Rivers and Queen in Lea and Eddy Counties, New Mexico; the Atoka in the
Brunson Ranch Field in Loving County, Texas; the Clearfork in the Westbrook
Field in Mitchell County, Texas; the San Andres in the Levelland/Slaughter Field
in Cochran County, Texas; and the Canyon Sand in Sutton County, Texas. The
Permian Basin Properties included 1,852 producing oil and gas wells on
approximately 113,810 gross acres (82,175 net acres). One of the Company's
subsidiaries, Gruy Petroleum Management Co. ("Gruy"), serves as operator on
approximately 60% of the wells on the Permian Basin Properties. Management
believes the Permian Basin Properties provide significant opportunities for
exploitation and development of both oil and gas through workovers and
recompletions, enhanced recovery projects and in-fill drilling.
According to Ryder Scott, as of December 31, 1998, the Permian Basin
Properties had Proved Reserves of 10.65 MMBbl of oil and 85.3 Bcf of gas, or on
a Natural Gas Equivalent basis, 149.2 Bcfe. Ryder Scott further estimated the
SEC PV-10 for the Permian Basin Properties to be $59.12 million as of December
31, 1998 based on prices of $9.42 per Bbl of oil and $2.18 per Mcf of gas at
December 31, 1998. Approximately 60% of the Proved Reserves were classified as
proved developed producing reserves as of December 31, 1998. See "Properties -
Oil and Gas Reserves." Based on the $133.8 million adjusted purchase price and
Proved Reserves of 186.9 Bcfe as of April 30, 1997, the Company paid
approximately $0.72 per Mcfe for the Permian Basin Properties.
The major fields in the Permian Basin Properties are the Westbrook,
Levelland/Slaughter, Lea County Shallow Properties and the Brunson Ranch.
4
Westbrook. The Westbrook Field covers 45 square miles of the Permian Basin
in Mitchell County, Texas and produces from the Clearfork formation at a depth
of approximately 3,200 feet. The following table sets forth information
regarding three properties in the Westbrook Field in the Permian Basin
Acquisition:
Gross Oil
Well Working Net Revenue Production
Property Operator Count Interest Interest (Bbl/d)
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Southwest Westbrook Unit............... Company 135 89.9% 77.5% 425
Morrison "G" Lease (1)................. Company 12 83.3% 72.9% 26
North Westbrook Unit................... Third Party 294 2.0% 2.8%(2) 1,200
(1) Subsequent to the Permian Basin Acquisition, the Company acquired
the remaining 16.7% of the working interest in the Morrison "G"
Lease, increasing its Net Revenue Interest to 87.5%.
(2) Includes an overriding Royalty Interest.
Most of the leases and units in the field had waterflood projects initiated
in the 1960's and those projects are still active. The Company plans to initiate
waterflood enhancement operations on the Southwest Westbrook Unit and the
Morrison "G" Lease in either 1999 or 2000 assuming oil prices continue to
improve.
Levelland/Slaughter. The Levelland and Slaughter Fields consist of 155
wells located in Cochran County, Texas that produce from the San Andres
formation at a depth of 5,000 feet. The interests acquired in the Permian Basin
Acquisition include the following three properties in the Levelland and
Slaughter Fields:
Gross Oil
Well Working Net Revenue Production
Property Operator Count Interest Interest (Bbl/d)
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TLB Unit............................... Company 20 100.0% 87.3% 80
Veal Lease............................. Company 52 100.0% 87.1% 220
NW Slaughter Unit...................... Company 83 74.8% 62.8% 290
Discovered in the 1930's, all three properties have been actively
waterflooded since the 1970's. While the projects are mature, additional
drilling and waterflood enhancement are likely. No Proved Undeveloped Reserves
were assigned by Ryder Scott to either the TLB Unit or the Veal Lease. Proved
Undeveloped Reserves were assigned by Ryder Scott to the NW Slaughter Unit in
contemplation of a carbon dioxide injection project which is anticipated for
that property. The operator of an adjacent property has been successfully
injecting carbon dioxide for a number of years to enhance production.
Lea County Shallow Properties. The Lea County Shallow Properties consist of
approximately 300 wells in Lea County, New Mexico which are in the Rhodes,
Jalmat, Monument, Langlie Mattix, Eumont and Eunice Fields. The fields produce
from the Yates, Seven Rivers, Queen and other formations at depths generally
shallower than 3,000 feet. Production is generally high Btu gas, which produces
into low pressure gathering systems. At year-end approximately 15 proved
undeveloped locations were identified and the Company anticipates that numerous
additional recompletion, stimulation, workover or development drilling
opportunities will result from detailed geological and engineering studies which
are planned.
Brunson Ranch. The Brunson Ranch Field consists of four wells located in
Loving County, Texas in the deep Delaware Basin geological province of the
Permian Basin. The wells are currently producing a total of approximately 4.2
MMcf of gas per day from the Atoka formation at a depth of approximately 16,000
feet. Undeveloped potential exists on the properties through redrilling the
Atoka formation and completing such wells using technology designed for high
bottom hole pressure conditions.
5
Panoma Acquisition
On June 28, 1996, the Company purchased from Burlington interests in 520
gas wells in the Texas Panhandle and western Oklahoma (470 of which are operated
by the Company) and an associated 427 mile gas gathering system (the "Panoma
Properties"). By year-end of 1998, the Company had drilled an additional 80
wells. A continuous drilling program is budgeted, with an additional 20 wells
proposed to be drilled in 1999. The net purchase price, after certain purchase
price adjustments, was $34.7 million, funded by borrowings under the Company's
previous senior credit facility. Gruy is the operator of the gas gathering
system and the wells that were previously operated by Burlington. According to
Ryder Scott, the Proved Reserves attributable to the Panoma Properties as of
December 31, 1998 aggregated 94 Bcfe with an SEC PV-10 of $50.9 million.
The Panoma Properties currently consist of approximately 630 gas wells in
the West Panhandle, East Panhandle, and South Erick Fields along a corridor 65
miles long and 20 miles wide stretching from Beckham County, Oklahoma to Gray
County, Texas. All wells are less than 2,300 feet deep and produce gas from the
Granite Wash and/or Brown Dolomite formations.
TEL Acquisition
On March 27, 1998 the Company acquired approximately 40% beneficial
ownership interest in TEL Offshore Trust, a trust created under the laws of the
state of Texas pursuant to a cash tender offer for an aggregate purchase price
of approximately $10.3 million. The principal asset of TEL consists of a 99.99%
interest in the TEL Offshore Trust partnership. Chevron USA Inc. owns the
remaining .01% interest in the partnership. The partnership owns an overriding
royalty interest equivalent to a 25% net profits interest in certain oil and gas
properties located offshore Louisiana. TEL produced a total of approximately 1.3
Bcfe in 1998.
McLean Plant Acquisition
On January 1, 1997, the Company complemented its Panoma Acquisition by
purchasing for $2.5 million a 50% ownership interest in the McLean Gas Plant,
which is connected to the Panoma gas gathering system and a related products
pipeline. The Company receives 100% of the net profits from the McLean Gas Plant
until it recoups the $2.5 million purchase price, after which time it will
receive 50% of the net profits. At January 31, 1999, the Company had recouped
approximately $1.36 million or 54% of its initial investment. See "Gathering and
Processing of Gas."
Development and Exploration Activities
Overview
The Company presently intends to continue to focus its efforts on property
acquisitions, its substantial inventory of exploitation and development
activities and, to a lesser extent, selected exploratory drilling prospects.
The Company seeks to minimize its overhead and capital expenditures by
subcontracting the drilling, redrilling and workover of wells to independent
drilling contractors and by outsourcing other services. The Company typically
compensates its drilling subcontractors on a turnkey (fixed price), footage or
day-rate basis depending on the Company's assessment of risk and cost
considerations on each individual project.
Development Drilling
The Company's development strategy focuses on maximizing the value and
productivity of its oil and gas asset base through development drilling and
enhanced recovery projects. The Company has budgeted approximately $9.0 million
for exploitation and development activities for 1999. The Company has identified
over 400 development drilling locations (including both production and injection
wells) on its properties. In exploiting its producing properties, the Company
relies upon its in-house technical staff of petroleum engineering and geological
professionals and utilizes the services of outside consultants on a selective
basis.
6
Permian Basin Properties. In evaluating the Permian Basin Properties, the
Company has identified approximately 400 drilling locations including production
and injection wells. Engineering and geological studies are being initiated to
more precisely identify specific development locations. The Lea County Shallow
Properties consist of approximately 300 wells in Lea County, New Mexico which
are in the Rhodes, Jalmat, Monument, Langlie Mattix, Eumont and Eunice Fields.
These fields produce from the Yates, Seven Rivers, Queen and other formations at
depths generally shallower than 3,000 feet. Production is generally high Btu
gas, which produces into low pressure gathering systems. At year-end
approximately 15 proved undeveloped locations were identified and the Company
anticipates that numerous additional recompletion, stimulation, workover or
development drilling opportunities will result from detailed geological and
engineering studies which are planned. During 1998, the Company drilled 19 wells
in the Sawyer Canyon Field in the Sonora area located in Sutton County, Texas.
The Company owns an interest in 146 wells in this area which consists of the
Sawyer Canyon Field, the Sonora Canyon Field and the Phyllis-Sonora Field.
Production from all fields is from a series of tight canyon-age gas sands. The
Company has plans to continue to develop the Sawyer Canyon Field in 1999. The
Company has budgeted approximately $3.5 million for development of the Permian
Basin properties in 1999.
Panoma Properties. The Company believes that developmental drilling can
continue to enhance the value of the Panoma Properties, which produce from the
Brown Dolomite and Granite Wash formations in the Texas Panhandle and western
Oklahoma. The easternmost fields are developed on 160 acre spacing because the
original spacing of 640 acres proved inadequate to drain reserves efficiently.
In-fill development has been underway in the westernmost field with 80 wells
having been completed during the two years ended December 1998. Upon completion
of this well program, the westernmost field will have been effectively developed
with 320 acre spacing. The Company has budgeted approximately $1.5 million for
development of the Panoma Properties through 1999.
Spirit 76 Acquisition. The Company has engaged its Houston based geological
affiliate, Swanson Consulting Services, Inc., to begin an evaluation of the most
prospective undeveloped properties located in one of the fields acquired, being
the Cumberland Field. The Cumberland Field was discovered in 1940 and is
productive in multiple reservoirs from the Goddard down to the Arbuckle
formation. Depths range from 2,000' to 6,800'. Initially, the field produced oil
from the Bromide, McLish and Oil Creek formations. These zones were unitized in
1964 for waterflood operations, which continue today. The "Shallow Gas" zones
include the Sycamore, Woodford, Hunton, and Viola. These formations are
predominantly gas productive and are produced commingled. Potential exists for
three additional wells to complete development of the shallow gas on 160-acre
spacing. The Company has budgeted approximately $1.5 million for development of
the Cumberland Field through 1999.
Exploratory Drilling
The Company attempts to lessen the risks inherent in exploratory drilling
by: (i) concentrating in specific areas in the United States where the Company's
technical staff has considerable experience and which are in known producing
trends where the potential for significant reserves exists; (ii) diversifying
through investment in multiple prospects; (iii) utilizing 3-D seismic and other
advanced technologies; and (iv) promoting out interests to industry partners.
The Company spent approximately $6.0 million of its $36 million 1998
capital budget on exploratory drilling. The Company has a $1.0 million
exploration budget for 1999, including geological and geophysical expenses for
its currently owned properties. Six exploratory wells were drilled in 1998 of
which five were successful. Exploratory successes include the Mossy Grove
Prospect in Walker County, Texas where a discovery completed in July 1998 has
produced nearly 750 MMcf of natural gas in 8 months and is currently flowing at
approximately 2 MMcf/d. A confirmation to this discovery, located 3.5 miles
southwest, has been recently completed and is flowing over 5 MMcf/d. The Company
owns 25% and 55% working interest, respectively, in these two producing wells
and owns an average of a 25% working interest in a 43,000 acre lease block
surrounding the new wells where additional development drilling is planned.
7
A new oil discovery on the Sunburst Prospect in Terry County, Texas is
currently producing approximately 42 Bbls of oil per day. This well was
completed in September 1998 and a confirmation test is planned by the middle of
1999. The Company is operator and owns a 39% working interest in the discovery
and approximately 1,500 acres of the prospect. Additional development drilling
is expected later in 1999.
A 3-D seismic program on the Bobcat Project in Hockley County, Texas has
been completed and the interpretation of the data confirms the presence of
numerous high quality, exploratory prospects. The entire project covers over
30,000 acres with approximately 15,000 acres under lease or option. An
exploratory drilling program is expected to commence in late 1999 and extend
into 2000.
The Company is actively generating and evaluating other projects for future
exploration activity.
Gathering and Processing of Gas
Hunter Gas Gathering, Inc., a wholly-owned subsidiary of the Company, owns
two gas gathering systems located in Oklahoma and Texas, neither of which are
subject to regulation by the Federal Energy Regulatory Commission ("FERC"), and
a 50% ownership interest in the McLean Gas Plant in the Texas Panhandle. Gruy
operates both gas gathering systems. In October of 1998, the Company sold a
small gathering system located in Louisiana that accounted for less than 2% of
the Company's total gas gathering throughput.
Generally, the gathering systems transport the gas from wells to a common
point where it is dehydrated prior to redelivery to downstream pipelines. In
managing its gas gathering systems, the Company has emphasized operating
efficiency and overhead management and introduced a program which ties
throughput costs to volume transported rather than to compression capacity. The
Company believes that its focus on volume-based pricing reduces the potential
financial impact of a decline in actual throughput.
The Panoma system, the largest of the Company's gas gathering systems,
consists of approximately 442 miles of pipeline. The main trunklines run east to
west for approximately 66 miles with the east end starting in Beckham County,
Oklahoma and the west end starting in Gray County, Texas. At year end 1998, gas
throughput for the Panoma gas gathering system was approximately 18.2 MMcf per
day. The Panoma gas gathering system was recently connected to a third party
"header" system which provides access to all major interstate pipelines in the
area via seven pipeline interconnects serving Midwestern, Western and Oklahoma
intrastate markets. The Company, which operates approximately 535 of the
approximately 630 wells connected to the Panoma system, is also actively seeking
to add new wells to such system through acquisition, development or arrangements
with third party producers.
The Company's North Appleby gas gathering system is located primarily in
Nacogdoches County in east Texas. Approximately 39 wells are connected to the
system, which delivers approximately 2.2 MMcf per day for third parties to
Natural Gas Pipeline Co. for transportation to other markets. The Company is
currently negotiating with several third parties for the possible sale of the
North Appleby gas gathering system.
Effective January 1, 1997, the Company purchased for $2.5 million a 50%
ownership interest in the McLean Gas Plant, the gas processing facility
connected to the Company's Panoma gas gathering system. The purchase also
included a 23-mile products pipeline between the McLean Gas Plant and the Koch
Pipeline at Lefors, Texas and all gas and product purchase and sales agreements
related to the plant. The McLean Gas Plant is a modern cryogenic gas processing
plant with a throughput capacity of 23.0 MMcf per day. Current throughput is
approximately 16.4 MMcf per day. The Company acquired its 50% ownership interest
in the plant from Carrera Gas Company, L.L.C. ("Carrera") of Tulsa, Oklahoma,
which owns the remaining 50% of the plant and operates the facility. Under the
terms of the Company's operating agreement with Carrera, the Company receives
100% of the net profits from the McLean Gas Plant until it recoups the $2.5
million purchase price, at which point net profits will be divided equally
between the Company and Carrera. As of January 31, 1999 the Company had recouped
approximately 54% of its $2.5 million investment.
8
Marketing of Production
The Company markets all of its gas production as well as gas it purchases
from third parties to gas marketing firms or end users either on the spot market
on a month-to-month basis at prevailing spot market prices or at negotiated
prices under long-term contracts. Marketing gas for its own account exposes the
Company to the attendant commodities risk which the Company attempts to mitigate
through various financial hedges. The Company normally sells its own oil under
month-to-month contracts with a variety of purchasers. Oil is usually sold for
the Company's own account through the services of Enmark Services, a marketing
agent in Dallas, Texas. While the Company has historically been able to sell oil
above posted prices, it is also exposed to the commodities risk inherent in
short-term contracts which the Company attempts to mitigate through various
financial hedges. For a discussion of the Company's hedging activities, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources - Hedging Activity" and Note 13 to
the Company's Consolidated Financial Statements.
In December 1997, Hunter Gas Gathering, Inc. acquired a thirty percent
(30%) membership interest in NGTS, a newly formed subsidiary of Natural Gas
Transmission Services, Inc. ("NGTS, Inc.") NGTS assumed all of NGTS Inc.'s
operations as of December 1, 1997. The Company acquired its interest in NGTS for
$4.35 million.
NGTS is a five year old natural gas marketing and trading company with
operations concentrated in the western two-thirds of the country. In fiscal
1998, NGTS reported total revenues of approximately $224.7 million. NGTS is
presently marketing approximately 350 million cubic feet of natural gas per day.
As of December 1, 1997, the Company and its gas gathering subsidiary, Hunter Gas
Gathering, Inc., dedicated substantially all of its natural gas production to
NGTS for marketing. The balance of the Company's production is dedicated to
either ONEOK or various third parties through gas processing agreements.
The market for oil and natural gas produced by the Company depends on
factors beyond its control, including the extent of domestic production and
imports of oil and natural gas, the proximity and capacity of natural gas
pipelines and other transportation facilities, weather, demand for oil and
natural gas, the marketing of competitive fuels and the effects of state and
federal regulation. The oil and natural gas industry also competes with other
industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers.
Petroleum Management and Consulting Services
The Company acquired Gruy in the Magnum Hunter Combination in December
1995. Gruy, which conducts operations for both the Company and third parties,
has over a 40-year history of managing properties for financial institutions,
bankruptcy trustees, estates, individual investors, trusts and independent oil
and gas companies. Gruy provides drilling, completion and other well-site
services; advice regarding environmental and other regulatory compliance;
receipt and disbursement functions and other managerial services and petroleum
engineering services. Gruy manages, operates and provides consulting services on
oil and gas properties, gathering systems and processing plants located in
Texas, Oklahoma, Mississippi, Louisiana, New Mexico and Kansas. Gruy is an
important component of the Company's acquisition program. As the operator of
wells for third parties and as a provider of consulting services for the energy
industry, Gruy is often uniquely able to identify attractive acquisition
opportunities.
Competition
The oil and gas industry is highly competitive. Competitors of the Company
include major oil companies, other independent oil and gas concerns, and
individual producers and operators, many of which have substantially greater
financial resources and larger staffs and facilities than those of the Company.
In addition, the Company frequently encounters competition in the acquisition of
oil and gas properties and gas gathering systems, and in its management and
consulting business. The principal means of such competition are the amount and
terms of the consideration offered. The principal means of such competition with
respect to the sale of oil and gas production are product
9
availability and price. The price at which the Company's products may be sold
will continue to be affected by a number of factors, including the price of
alternate fuels such as oil, gas and coal and competition among various gas
producers and marketers.
Regulation
General Federal and State Regulation
The Company's oil and gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Because such rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
laws.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells, and the regulation
of spacing, plugging and abandonment of such wells. Many states restrict
production to the market demand for oil and gas. Some states have enacted
statutes prescribing ceiling prices for gas sold within their states.
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the
past, the federal government has regulated the wellhead price of natural gas.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was
enacted, which amended the NGPA to remove wellhead price controls on all
domestic natural gas as of January 1, 1993. While sales by producers of natural
gas, and all sales of oil, condensate and natural gas liquids, can currently be
made at uncontrolled market prices, Congress could re-enact price controls in
the future.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that have had a major impact on natural gas pipeline
operations, services and rates and thus have significantly altered the marketing
and price of natural gas. Commencing in April 1992, the FERC issued Order Nos.
636, 636-A and 636-B (collectively, "Order No. 636"), which, among other things,
require each interstate pipeline company to "restructure" to provide
transportation separate or "unbundled" from the sale of gas and to make
available on an open and nondiscriminatory basis numerous constituent services
(such as gathering services, storage services, firm and interruptible
transportation services) and to adopt a new ratemaking methodology to determine
appropriate rates for those services. To the extent the pipeline company or its
sales affiliate makes gas sales as a merchant in the future, it does so in
direct competition with all other sellers pursuant to private contracts;
however, pipeline companies and their affiliates were not required to remain
"merchants" of gas and several of the interstate pipeline companies have become
"transporters" only. Following the conclusion of individual restructuring
proceedings for each interstate pipeline pursuant to Oder No. 636, the FERC has
approved, with modifications, all of the restructuring plans implementing Order
No. 636 on every interstate pipeline.
On July 16, 1996, the Court of Appeals for the District of Columbia Circuit
(D.C. Circuit) issued its opinion on review of Order No. 636. The opinion upheld
most elements of Order No. 636 including the unbundling of sales and
transportation services, curtailment of pipeline capacity, implementation of the
capacity release program and the mandatory imposition of straight-fix-variable
("SFV") rate design for interstate pipeline companies. The D.C. Circuit did
remand certain aspects of Order No. 636 to the FERC for further explanation
including, inter alia, the FERC's decision to exempt pipelines from sharing in
gas supply realignment ("GSR") costs caused by restructuring; FERC's selection
of a 20 year matching cap for the right-of-first-refusal mechanism; the FERC's
restriction on the entitlement of no-notice transportation service to only those
customers receiving bundled sales service at the time of restructuring;
10
and FERC's determination that pipelines should focus on individual customers,
rather than customer classes, in mitigating the effects of SFV rate design. On
May 12, 1997, the United States Supreme Court denied certiorari of the D.C.
Circuit's decision.
On February 27, 1997, the FERC issued its order on remand ("Order No.
636-C"). The order reaffirmed the holding of Order No. 636 that pipelines should
be entitled to recover 100% of their prudently incurred GSR costs. Moreover, the
FERC determined since Order No. 636, the average length of transportation
contracts was substantially less than 20 years. Thus, FERC reduced the contract
matching cap for the right-of-first-refusal mechanism to five years. In light of
the varied post-restructuring experience with no-notice service, the FERC also
decided to no longer limit a pipeline's no-notice service to its bundled sales
customers at the time of restructuring. Finally, the FERC reaffirmed that
pipelines should focus on individual customers, rather than customer classes, in
mitigating the effects of SFV rate design. On May 28, 1998, FERC denied requests
for rehearing of Order No. 636-C. Appeals of individual pipeline restructuring
orders are still pending before the D.C. Circuit.
On May 31, 1995, the FERC issued a policy statement on how interstate
natural gas pipelines can recover the costs of new pipeline facilities. The
policy statement focused on whether projects would be priced on rolled-in basis
(rolling in the expansion costs with the existing facilities) or on an
incremental basis (establishing separate cost of services and separate rates for
the existing and expansion facilities). The policy statement established a
presumption in favor of rolled-in rates when the rate increase to existing
customers from rolling in the new facilities is 5% or less. In the policy
statement, the FERC contemplated that the resolution of pricing methodology
would take place in individual proceedings based on the facts and circumstances
of the project. The Company cannot predict what action the FERC will take in the
individual proceedings.
In October 1992, Congress passed the Energy Policy Act of 1992 ("Energy
Policy Act"). The Energy Policy Act deemed petroleum pipeline rates in effect
for the 365-day period ending on the date of enactment of the Energy Policy Act
or that were in effect on the 365th day preceding enactment and had not been
subject to complaint, protest or investigation during the 365-day period to be
just and reasonable under the Interstate Commerce Act. The Energy Policy Act
also provides that complaints against such rates may only by filed under the
following limited circumstances: (i) a substantial change has occurred since
enactment in either the economic circumstances or the nature of the services
which were a basis for the rate; (ii) the complainant was contractually barred
from challenging the rate prior to enactment; or (iii) the rate is unduly
discriminatory or preferential. The Energy Policy Act further required FERC to
issue rules establishing a simplified and generally applicable ratemaking
methodology for petroleum pipelines proceedings. On October 22, 1993, the FERC
responded to the Energy Policy Act directive by issuing Order No. 561, which
adopts a new indexing rate methodology for petroleum pipelines. Under the new
regulations, which were effective January 1, 1995, petroleum pipelines are able
to change their rates within prescribed ceiling levels that are tied to the
Producer Price Index for Finished Goods, minus one percent. Rate increases made
pursuant to the index will be subject to protest, but such protest must show
that the portion of the rate increase resulting from application of the index is
substantially in excess of the pipeline's increase in costs. The new indexing
methodology can be applied to any existing rate, even if the rate is under
investigation. If such rate is subsequently adjusted, the ceiling level
established under the index must be likewise adjusted.
In Order No. 561, FERC said that as a general rule pipeliners must utilize
the index methodology to change their rates. FERC indicated, however, that it
was retaining cost of service ratemaking, market-based rates, and settlements as
alternatives to the indexing approach. A cost of service methodology will also
continue to be used to determine just and reasonable initial rates for new
services. A pipeline can also follow a cost of service approach when seeking to
increase its rates above index levels for uncontrollable circumstances. A
pipeline can seek to charge market-based rates if it can establish that it lacks
market power. Finally, a pipeline can establish rates pursuant to settlement if
agreed upon by all current shippers.
On May 10, 1996, the D.C. Circuit affirmed Order No. 561. The Court held
that by establishing a general indexing methodology along with limited
exceptions to index rates, FERC had reasonably balanced its dual
responsibilities of ensuring just and reasonable rates and streamlining
ratemaking through generally applicable
11
procedures. Because of the novelty and uncertainty surrounding the indexing
methodology, as well as the possibility of the use of cost of service ratemaking
and market-based rates, the Company is not able at this time to predict the
effects of Order No. 561, if any, on the transportation costs associated with
oil production from the Company's oil producing operations.
Environmental Regulation
The Company's exploration, development, and production of oil and gas,
including its operation of saltwater injection and disposal wells, are subject
to various federal, state and local environmental laws and regulations. Such
laws and regulations can increase the costs of planning, designing, installing
and operating oil and gas wells. The Company's domestic activities are subject
to a variety of environmental laws and regulations, including but not limited
to, the Oil Pollution Act of 1990 ("OPA"), the Clean Water Act ("CWA"), the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
the Resource Conservation and Recovery Act ("RCRA"), the Clean Air Act ("CAA"),
and the Safe Drinking Water Act ("SDWA"), as well as state regulations
promulgated under comparable state statutes. The Company also is subject to
regulations governing the handling, transportation, storage, and disposal of
naturally occurring radioactive materials that are found in its oil and gas
operations. Civil and criminal fines and penalties may be imposed for
non-compliance with these environmental laws and regulations. Additionally,
these laws and regulations require the acquisition of permits or other
governmental authorizations before undertaking certain activities, limit or
prohibit other activities because of protected areas or species, and impose
substantial liabilities for cleanup of pollution.
Under the OPA, a release of oil into water or other areas designated by the
statute could result in the Company being held responsible for the costs of
remediating such a release, certain OPA specified damages, and natural resource
damages. The extent of that liability could be extensive, as set forth in the
statute, depending on the nature of the release. A release of oil in harmful
quantities or other materials into water or other specified areas could also
result in the Company being held responsible under the CWA for the costs of
remediation, and civil and criminal fines and penalties.
CERCLA and comparable state statutes, also known as "Superfund" laws, can
impose joint and several and retroactive liability, without regard to fault or
the legality of the original conduct, on certain classes of persons for the
release of a "hazardous substance" into the environment. In practice, cleanup
costs are usually allocated among various responsible parties. Potentially
liable parties include site owners or operators, past owners or operators under
certain conditions, and entities that arrange for the disposal or treatment of,
or transport hazardous substances found at the site. Although CERCLA, as
amended, currently exempts petroleum, including but not limited to, crude oil,
gas and natural gas liquids from the definition of hazardous substance, the
Company's operations may involve the use or handling of other materials that may
be classified as hazardous substances under CERCLA. Furthermore, there can be no
assurance that the exemption will be preserved in future amendments of the act,
if any.
RCRA and comparable state and local requirements impose standards for the
management, including treatment, storage, and disposal of both hazardous and
nonhazardous solid wastes. The Company generates hazardous and nonhazardous
solid waste in connection with its routine operations. From time to time,
proposals have been made that would reclassify certain oil and gas wastes,
including wastes generated during drilling, production and pipeline operations,
as "hazardous wastes" under RCRA which would make such solid wastes subject to
much more stringent handling, transportation, storage, disposal, and clean-up
requirements. This development could have a significant impact on the Company's
operating costs. While state laws vary on this issue, state initiatives to
further regulate oil and gas wastes could have a similar impact.
Because oil and gas exploration and production, and possibly other
activities, have been conducted at some of the Company's properties by previous
owners and operators, materials from these operations remain on some of the
properties and in some instances require remediation. In addition, the Company
has agreed to indemnify sellers of producing properties from whom the Company
has acquired reserves against certain liabilities for environmental claims
associated with such properties. While the Company does not believe that costs
to be incurred by the Company
12
for compliance and remediating previously or currently owned or operated
properties will be material, there can be no guarantee that such costs will not
result in material expenditures.
Additionally, in the course of the Company's routine oil and gas
operations, surface spills and leaks, including casing leaks, of oil or other
materials occur, and the Company incurs costs for waste handling and
environmental compliance. Moreover, the Company is able to control directly the
operations of only those wells for which it acts as the operator.
Notwithstanding the Company's lack of control over wells owned by the Company
but operated by others, the failure of the operator to comply with applicable
environmental regulations may, in certain circumstances, be attributable to the
Company. The Company currently expects to spend approximately $400,000 over the
next five years in connection with remediation and environmental compliance,
including $75,000 in 1999 and $75,000 in 2000.
It is not anticipated that the Company will be required in the near future
to expend amounts that are material in relation to its total capital
expenditures program by reason of environmental laws and regulations, but
inasmuch as such laws and regulations are frequently changed, the Company is
unable to predict the ultimate cost of compliance. There can be no assurance
that more stringent laws and regulations protecting the environment will not be
adopted or that the Company will not otherwise incur material expenses in
connection with environmental laws and regulations in the future.
Employees
At December 31, 1998, the Company had 69 full-time employees of which 12
were management, 26 were administrative and 31 were field employees. None of the
Company's employees are represented by a union. Management considers its
relations with employees to be good.
Facilities
The Company occupies approximately 11,590 square feet of office space at
600 East Las Colinas Boulevard, Suite 1200, Irving, Texas, under a lease that
expires in November 2001. The Company owns a field office and production yard in
Shamrock, Texas. The Company also has field production offices in Midland and
Abilene, Texas, Hobbs, New Mexico and Oklahoma City, Oklahoma.
13
Item 2. Description of Properties
Oil and Gas Reserves
General
All information set forth in this Form 10-K regarding estimated Proved
Reserves, related estimated future net cash flows and SEC PV-10 of the Company's
oil and gas interests is taken from reports prepared by Ryder Scott Company of
Houston, Texas and Pollard, Gore & Harrison ("PGH") of Austin, Texas, both
independent petroleum engineers with respect to the Company's interests at
December 31, 1998 (using oil and gas prices in effect at December 31, 1998) and
December 31, 1997. The estimates of these independent petroleum engineers were
based upon their review of production histories and other geological, economic,
ownership and engineering data provided by the Company.
SEC PV-10 is the present value of Proved Reserves which is an estimate of
the discounted future net cash flows from each of the Company's properties at
December 31, 1998, or as otherwise indicated. Net cash flow is defined as net
revenues less, after deducting production and ad valorem taxes, future capital
costs and operating expenses, but before deducting federal income taxes. As
required by rules of the Securities and Exchange Commission, the future net cash
flows have been discounted at an annual rate of 10% to determine their "present
value". The present value is shown to indicate the effect of time on the value
of the revenue stream and should not be construed as being the fair market value
of the properties. In accordance with Commission rules, estimates have been made
using constant oil and gas prices and operating costs, at December 31, 1998, or
as otherwise indicated.
In accordance with Commission guidelines, the estimates of future net cash
flows from Proved Reserves and their SEC PV-10 are made using oil and gas sales
prices in effect as of the dates of such estimates and are held constant
throughout the life of the properties. The Company's estimates of Proved
Reserves, future net cash flows and SEC PV-10 were estimated using the following
weighted average prices, before deduction of production taxes:
Prices used in Reserve Reports at
December 31,
---------------------------------------
1998 1997
---------------------------------------
Gas (per Mcf)............................ $2.12 $ 2.34
Oil (per Bbl)............................ $9.42 $16.08
All reserves are evaluated at contract temperature and pressure which can
affect the measurement of gas reserves. Operating costs, development costs and
certain production related and ad valorem taxes were deducted in arriving at the
estimated future net cash flows. No provision was made for income taxes. The
estimates following this section set forth reserves considered to be
economically recoverable under normal operating methods and existing conditions
at the prices and operating costs prevailing at the dates indicated above. The
estimates of the SEC PV-10 from future net cash flows differ from the
standardized measure of discounted future net cash flows set forth in the notes
to the Consolidated Financial Statements of the Company, which is calculated
after provision for future income taxes. There can be no assurance that these
estimates are accurate predictions of future net cash flows from oil and gas
reserves or their present value.
Proved Reserves are estimates of oil and gas to be recovered in the future.
Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein.
14
Results of drilling, testing, and production subsequent to the date of the
estimate may justify revision of such estimate. Future prices received for the
sale of oil and gas will likely be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered.
Except for the effect of changes in oil and gas prices, no major discovery
or other favorable or adverse event is believed to have caused a significant
change in these estimates of the Company's Proved Reserves since December 31,
1998. No estimates of Proved Reserves of oil and gas have been filed by the
Company with, or included in any report to, any United States authority or
agency (other than the Commission) since January 1, 1998.
Company Reserves
The following tables set forth the estimated Proved Reserves of oil and gas
of the Company and the SEC PV-10 thereof on an actual basis at December 31, 1998
and 1997.
Estimated Proved Oil and Natural Gas Reserves (1)
At December 31,
---------------------------------------
1998 1997
---------------------------------------
Net gas reserves (Mcf):
Proved developed producing........................... 173,220,374 154,749,340
Proved developed non-producing....................... 1,767,000 215,056
Proved undeveloped................................... 44,072,300 52,811,374
---------------------------------------
Total proved gas reserves.......................... 219,059,674 207,775,770
---------------------------------------
Net oil reserves (Bbl):
(including condensate and NGL)
Proved developed producing .......................... 9,015,703 12,021,950
Proved developed non-producing....................... 458,888 14,284
Proved undeveloped................................... 7,874,050 8,910,181
---------------------------------------
Total proved oil reserves.......................... 17,348,641 20,946,415
---------------------------------------
Total Proved Reserves (Mcfe).............................. 323,151,521 333,454,260
---------------------------------------
Estimated SEC PV-10 of Proved Reserves (1)
At December 31,
---------------------------------------
1998 1997
---------------------------------------
Estimated SEC PV-10 (2) :
Proved developed producing .......................... $ 156,629,617 $ 173,189,655
Proved developed non-producing ...................... 4,355,278 342,473
Proved undeveloped .................................. 18,424,052 38,054,232
---------------------------------------
Total Proved Reserves.............................. $ 179,408,947 $ 211,586,360
---------------------------------------
- -----------
(1) Based upon reserve reports at December 31, 1998 and December 31, 1997
prepared by Ryder Scott and PGH.
(2) SEC PV-10 differs from the standardized measure of discounted
future net cash flows set forth in the notes to the Consolidated Financial
Statements of the Company, which is calculated after provision for future
income taxes.
15
Significant Properties
On December 31, 1998, 82% of the Company's Proved Reserves on a Bcfe basis
were located in the Spirit 76 Properties, the Permian Basin Properties and the
Panoma Properties. On such date, the Company's properties included working
interests in 3,059 gross (1,671 net) productive oil and gas wells.
The following table sets forth summary information with respect to the
Company's estimated Proved Reserves of oil and gas at December 31, 1998.
SEC PV-10 (1)
----------------------------------------------------------------------------
Natural Gas
Amount % of Oil Gas Equivalent
(in thousands) Total (Bbl) (Mcf) (Bcfe)
-------------------------------------------- --------------- ---------------
Spirit 76 Properties (2)............. $ 37,593,943 21.0% 978,496 35,721,581 41.59
Permian Basin Properties (2)(3)...... 59,012,596 32.9% 10,650,255 85,237,426 149.14
Panoma Properties (2) .............. 50,989,042 28.4% 2,842,637 76,923,054 93.98
Other (2)(3)......................... 31,813,366 17.7% 2,877,253 21,177,613 38.44
-------------------------------------------- --------------- ---------------
Total ........................ 179,408,947 100.0% 17,348,641 219,059,674 323.15
-------------------------------------------- --------------- ---------------
- ----------
(1) SEC PV-10 differs from the standardized measure of discounted
future net cash flows set forth in the notes to the Consolidated
Financial Statements of the Company, which is calculated after
provision for future income taxes.
(2) Based on a reserve report at December 31, 1998 prepared by
Ryder Scott.
(3) Based on reserve reports at December 31, 1998 prepared by PGH.
Oil and Gas Production, Prices and Costs
The following table shows the approximate net production attributable to
the Company's oil and gas interests, the average sales price and the average
production expense attributable to the Company's oil and gas production for the
periods indicated. Production and sales information relating to properties
acquired or disposed of is reflected in this table only since or up to the
closing date of their respective acquisition or sale and may affect the
comparability of the data between the periods presented.
Year Ended December 31,
1998 1997
----------------------------------------
Oil and gas production:
Oil (Mbbl).......................................... 1,141 737
Gas (MMcf).......................................... 14,119 9,614
Natural Gas Equivalents (MMcfe)..................... 20,965 14,037
Average sales price (1):
Oil (per Bbl)....................................... $ 12.67 $ 17.70
Gas (per Mcf)....................................... 2.02 2.24
Natural Gas Equivalents (per Mcfe).................. 2.05 2.46
Oil and gas production lifting costs (per Mcfe) ...... .68 .56
Production taxes and other costs (per Mcfe)(2)........ $ .31 $ .35
- ----------
(1) Before deduction of production taxes and net of hedging results for the
two years ended December 31, 1998.
(2) Includes ad valorem taxes, insurance, bonds, company overhead and net
profits interest.
16
Drilling Activity
The following table sets forth the results of the Company's drilling
activities during the two fiscal years ended December 31, 1998 and 1997.
Gross Wells (a) Net Wells (b)
Year Type of Well Total Producing (c) Dry (d) Total Producing (c) Dry (d)
---- ------------ ----- ------------- ------- ----- ------------- -------
1998 Exploratory
Texas 5 4 1 3.25 2.64 .61
Oklahoma 0 0 0 0 0 0
New Mexico 1 1 0 .05 .05 0
Other 0 0 0 0 0 0
Development
Texas 79 79 0 74.4 74.4 0
Oklahoma 0 0 0 0 0 0
New Mexico 5 5 0 5 5 0
Other 0 0 0 0 0 0
1997 Exploratory
Texas 1 0 1 .2 0 .2
Oklahoma 1 1 0 .25 .25 0
Other 1 0 1 1 0 1
Development
Texas 71 71 0 67.1 67.1 0
Oklahoma 5 2 3 1.24 .51 .73
Other 1 1 0 .5 .5 0
- ----------
(a) The number of gross wells is the total number of wells in which a
working interest is owned. Fluid injection wells for waterflood and
other enhanced recovery projects are not included as gross wells.
(b) The number of net wells is the sum of fractional working interests
owned in gross wells expressed as whole numbers and fractions
thereof.
(c) A producing well is an exploratory or development well found to be
capable of producing either oil or gas in sufficient quantities to
justify completion as an oil or gas well.
(d) A dry well is an exploratory or development well that is not
a producing well.
17
Oil and Gas Wells
The following table sets forth the number of oil and natural gas wells in
which the Company had a working interest at December 31, 1998. All of these
wells are located in the United States.
Productive Wells
As of December 31, 1998
Gross(1) Net(2)
Location Oil Gas Total Oil Gas Total
- -------- --- --- ----- --- --- -----
Texas...................... 1,438 904 2,342 671 621 1,292
Oklahoma................... 31 361 392 27 160 187
Mississippi................ 4 0 4 3 0 3
New Mexico................. 60 245 305 37 149 186
California................. 14 0 14 1 0 1
Kansas..................... 2 0 2 2 0 2
---------------------------------------------------------------------------------------------------------
Total ............ 1,549 1,510 3,059 741 930 1,671
---------------------------------------------------------------------------------------------------------
- ----------
(1) The number of gross wells is the total number of wells in which a
working interest is owned. Well counts include wells with multiple
completions, but do not include injector wells.
(2) The number of net wells is the sum of fractional working interests
owned in gross wells expressed as whole numbers and fractions
thereof.
Oil and Gas Acreage
The following table summarizes the Company's developed and undeveloped
leasehold acreage at December 31, 1998.
Developed Undeveloped
Gross (a) Net (b) Gross (a) Net (b)
Texas.............................. 258,664 210,972 75,381 39,373
Oklahoma........................... 93,138 66,370 6,582 3,302
Mississippi........................ 528 452 0 0
New Mexico......................... 41,437 35,420 0 0
California......................... 509 38 0 0
Kansas............................. 80 69 0 0
-------------------------------------------------------------------------------------------------
Total.......................... 394,356 313,321 81,963 42,675
-------------------------------------------------------------------------------------------------
(a) The number of gross acres is the total number of acres in which a
working interest is owned.
(b) The number of net acres is the sum of fractional working interests
owned in gross acres expressed as whole numbers and fractions
thereof.
18
Substantially all of the Company's interests are leasehold working
interests or overriding royalty interests (as opposed to mineral or fee
interests) under standard onshore oil and gas leases. As is customary in the
industry, the Company generally acquires oil and gas acreage without any
warranty of title except as to claims made by, through or under the transferor.
Although the Company has title examined by a landman or title attorney prior to
acquisition of developed acreage in those cases in which the economic
significance of the acreage justifies the cost, there can be no assurance that
losses will not result from title defects or from defects in the assignment of
leasehold rights. In certain instances, title opinions may not be obtained if,
in the Company's judgment, it would be uneconomical or impractical to do so.
Item 3. Legal Proceedings.
No legal proceedings are pending other than ordinary routine litigation
incidental to the Company's business, the outcome of which management believes
will not have a material adverse effect on the Company.
Item 4. Submission of Matters to a Vote of Security Holders.
The Company had no matters requiring a vote of security holders during the
fourth quarter of 1998.
[Rest of page intentionally left blank]
19
PART II
Item 5. Market for Common Equity and Related Stockholder Matters.
The Common Stock has been listed on the American Stock Exchange since March
8, 1996. The Common Stock has been listed under the ticker symbol "MHR" since
March 18, 1997, prior to which time it was listed under the ticker symbol "MPM."
Prior to March 8, 1996, the Common Stock was listed on the American Stock
Exchange Emerging Company Marketplace. At December 31, 1998, there were 3,543
stockholders of record.
Average Daily
Trading Volume
High Low (Shares)
1998
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . $5.50 $3.88 85,139
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . $7.94 $5.13 210,992
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . $6.88 $3.00 118,228
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . $4.38 $2.75 133,437
1997
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . $6.63 $4.19 96,554
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . $6.31 $5.00 41,845
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . $6.44 $5.00 55,194
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . $7.94 $4.88 159,423
On March 31, 1999, the last reported sale price of the Company's Common
Stock on the American Stock Exchange was $2.88 per share.
The Company has not previously paid any cash dividends on its Common Stock
and does not anticipate paying dividends on its Common Stock in the foreseeable
future. It is the present intention of management to utilize all available funds
for the development of the Company's business activities. The Company may not
pay any dividends on Common Stock unless and until all dividend rights on
outstanding Preferred Stock have been satisfied. The Company's existing credit
facility restricts the payment of cash dividends on the Company's securities.
20
Item 6. Selected Financial Data
The selected historical financial data sets forth summary historical
consolidated financial data of the Company as of and for the years ended
December 31, 1998, 1997, 1996, 1995 and 1994, which have been derived from the
Company's audited consolidated financial statements and notes thereto, and
unaudited summary pro forma data for the year ended December 31, 1998. The pro
forma data gives effect to the consummation of the TEL Offshore and Spirit 76
Acquisitions and the ONEOK Transaction. The pro forma income statement data and
other data for the year ended December 31, 1998 reflects such adjustments as if
the TEL Offshore and Spirit 76 Acquisitions and the ONEOK Transaction had
occurred on January 1, 1998. The pro forma balance sheet data reflects such
adjustments as if the ONEOK Transaction had occurred on December 31, 1998. The
pro forma financial data does not purport to represent what the Company's
financial position or results of operations would actually have been had the TEL
Offshore and Spirit 76 Acquisition and the ONEOK Transaction in fact occurred on
the assumed date and are not necessarily indicative of future operating results
or financial position. The selected historical financial data is qualified in
its entirety by, and should be read in conjunction with "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and the financial
statements and the notes thereto included elsewhere in this Form 10-K. For
additional information relating to the Company's operations, see "Business" and
"Properties."
Year Ended December 31,
Pro forma
1994 1995 1996 1997 1998 1998
---- ---- ---- ---- ---- ----
(dollars in thousands)
Income Statement Data:
Total operating revenues......................... $ 745 $ 649 $16,412 $48,834 $51,400 $ 62,588
1,336 1,692 13,541 39,187 94,362 101,420
Total operating costs and expenses (1)........... ----------------------------------------------------------------------
Operating profit (loss).......................... (591) (1,043) 2,871 9,647 (42,962) (38,833)
Net income (loss) before extraordinary loss...... (546) (968) 509 (2,108) (47,080) (41,639)
Extraordinary loss from early extinguishment
of debt, net of taxes ......................... - - - (1,384) - -
Net Income (loss) ............................... (546) (968) 509 (3,492) (47,080) (41,639)
(580) (617) (406) (875) (875) (4,875)
Dividends applicable to preferred shares......... ----------------------------------------------------------------------
$ (1,126) $(1,585) $ 103 $ (4,367) $(47,955) $(46,514)
Income (loss) applicable to common shares........ ----------------------------------------------------------------------
Income (loss) per common share before
extraordinary item
Basic......................................... $ (0.27) $ (0.28) $ 0.01 $ (0.21) $ (2.26) $ (2.20)
Diluted....................................... $ (0.27) $ (0.28) $ 0.01 $ (0.21) $ (2.26) $ (2.20)
Income (loss) per common share after
extraordinary item
Basic......................................... $ (0.27) $ (0.28) $ 0.01 $ (0.30) $ (2.26) $ (2.20)
Diluted....................................... $ (0.27) $ (0.28) $ 0.01 $ (0.30) $ (2.26) $ (2.20)
Other Data:
EBITDA (2)....................................... $ (297) $ (545) $ 6,166 $ 22,772 $ 22,112 $ 31,597
Capital expenditures (3)......................... $ 1,945 $ 1,244 $41,471 $160,059 $ 70,187 $ 71,529
- --------
(1) Includes in 1998 and pro forma 1998 the write-down of $42,745,000 of oil
and gas properties in the full-cost pool due to ceiling test limitation.
(2) EBITDA is defined as net income (loss) before income taxes and minority
interest, plus the sum of depletion and depreciation and interest expense.
EBITDA is not a measure of cash flow as determined by generally accepted
accounting principles. The Company has included information concerning
EBITDA because EBITDA is a measure used by certain investors in
determining the Company's historical ability to service its indebtedness.
EBITDA should not be considered as an alternative to, or more meaningful
than, net income or cash flows as determined in accordance with generally
accepted accounting principles or as an indicator of the Company's
operating performance or liquidity.
(3) Capital expenditures include cash expended for acquisitions plus normal
additions to oil and natural gas properties and other
fixed assets.
21
December 31,
-----------------------------------------------------------------------
Pro forma
1994 1995 1996 1997 1998 1998
---- ---- ---- ---- ---- ----
(dollars in thousands)
Balance Sheet Data:
Working capital (deficiency).................... $1,197 $ (916) $ 2,279 $ 2,610 $ (723) $ (723)
Property, plant and equipment, net.............. 7,255 36,405 73,648 221,259 228,436 228,436
Total assets.................................... 9,575 40,065 83,072 251,069 267,142 267,142
Total debt(1)................................... 186 9,612 38,766 161,543 231,020 184,637
Stockholders' equity............................ $8,645 $ 24,496 $ 35,154 $ 72,140 $ 20,992 $ 67,375
- -----------
(1) Consists of long-term debt, including current maturities of long-term
debt, and excluding production payment liabilities of $288,000,
$937,000, $743,000 and $633,000 as of December 31, 1995, 1996, 1997 and
1998, respectively.
The following table sets forth unaudited summary finacial results on a
quarterly basis for the two most recent years.
1998
----------------------------------------------
First Second Third Fourth
----------------------------------------------
(In thousands, except per share data)
Revenues.................................. $ 12,753 $ 13,261 $ 13,580 $11,806
Depreciation, depletion and amortization.. 3,875 4,941 4,805 8,136
Write-down of oil and gas properties...... - - - 42,745
Net Operating Profit (Loss)............... 1,295 1,260 973 (46,490)
Net Loss.................................. (1,747) (1,915) (2,272) (41,146)
Loss per common share, basic.............. $ (0.09) $ (0.10) $ (0.12) $ (1.96)
Loss per common share, diluted............ $ (0.09) $ (0.10) $ (0.12) $ (1.96)
1997
----------------------------------------------
First Second Third Fourth
----------------------------------------------
Revenues.................................. $ 10,339 $ 9,872 $ 13,389 $15,234
Depreciation, depletion and amortization.. 1,081 3,379 4,147 3,756
Net Operating Profit...................... 1,428 2,039 3,298 2,882
Net Income (Loss) before
extraordinary item...................... 250 (974) (509) (872)
Net Income (Loss)......................... 250 (2,358) (509) (872)
Income (Loss) per common share, basic
Before extraordinary loss............ $ 0.00 $ (0.09) $ (0.05) $ (0.06)
Extraordinary loss................... - (0.10) - -
After extraordinary loss............. 0.00 (0.19) (0.05) (0.06)
Income (Loss) per common share, diluted
Before extraordinary loss............ $ 0.00 $ (0.09) $ (0.05) $ (0.06)
Extraordinary loss................... - (0.10) - -
After extraordinary loss............. 0.00 (0.19) (0.05) (0.06)
22
Item 7. Management Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion and analysis should be read in conjunction with
the Company's consolidated financial statements and the notes associated with
them contained elsewhere in this report. This discussion should not be construed
to imply that the results discussed herein will necessarily continue into the
future or that any conclusion reached herein will necessarily be indicative of
actual operating results in the future. Such discussion represents only the best
present assessment by management of the Company.
During 1996, management implemented a business strategy that emphasized
acquisition of long-lived, Proved Reserves with significant exploitation and
development opportunities that management considered to have a lower risk
profile than the Company's historic projects. Prior to 1996 and under prior
management, the Company was primarily focused on developing and selling higher
risk, non-operated exploratory and development projects and did not focus on
acquisitions. In order to improve the economics of acquisitions, the Company
emphasizes strict cost control in all aspects of its business and seeks to
operate its properties wherever possible. The Company also participates, to a
lesser extent, in selected exploration projects on a controlled risk basis.
As a part of the Company's new strategy, in June 1996 the Company acquired
the Panoma Properties for a net purchase price of $34.7 million from Burlington,
which included interests in 520 gas wells in the Texas Panhandle and western
Oklahoma and an associated 427 mile gas gathering system. The Company assumed
operations of approximately 90% of the wells and of the gathering system and
began planning for increased density development drilling on the Panoma
Properties.
In January 1997 the Company purchased for $2.5 million a 50% interest in a
gas processing plant, the McLean Gas Plant, which currently processes 100% of
the gas produced from the Panoma Properties. The Company receives 100% of the
net profits of the plant until it recoups its investment, after which time the
Company will receive 50% of the net profits. At January 31, 1999, the Company
had recouped approximately 54% of its $2.5 million investment. Management
believes that the acquisition of the McLean Gas Plant allows the Company to
capture a significant portion of the profits generated from processing the gas
produced at the Panoma Properties that would otherwise go to third party
processors.
In April 1997 the Company purchased the Permian Basin Properties from
Burlington for a net purchase price of $133.8 million after purchase price
adjustments of $9.7 million. These properties consist of approximately 1,852
producing oil and gas wells and associated acreage in west Texas and southeast
New Mexico. This acquisition substantially increased the Company's cash flow and
inventory of exploitation, development and exploration opportunities.
On April 29, 1997 the Company received and accepted two new loan
commitments from Bankers Trust Company, as Agent, and other banks for senior
credit facilities for the Company and several of its subsidiaries. The two new
senior credit facilities were structured as the $130.0 million Credit Facility
with a term of five years and a $60.0 million one year senior subordinated
bridge facility (the "Term Loan Facility") convertible into a five year term
loan. The new credit facilities were conditioned, among other things, upon the
closing of the Permian Basin Acquisition, which took place on April 30, 1997.
The Credit Facility provided the Company the flexibility of choosing a range of
either "LIBOR" or "Prime" based interest rate options. This Credit Facility
replaced the Company's previously existing $100.0 million revolving credit
facility.
On May 29, 1997, the Company placed, through a Rule 144A private placement
offering, $140 million in Senior Notes due 2007. The Notes have a 10% coupon,
with interest payable on June 1 and December 1, commencing on December 1, 1997.
Except for Bluebird Energy, Inc. there is no restriction on the ability of any
consolidated or unconsolidated subsidiary to transfer funds to the Company in
the form of cash dividends, loans or advances. Net proceeds from the sale of the
Senior Notes were used to completely repay the Company's outstanding bridge loan
facility in the principal amount of $60 million with the remaining proceeds used
to repay a substantial portion of the Company's outstanding revolving credit
facility. At that time, the maximum commitment under the revolving credit
23
facility was reduced from $130 million to $75 million, with a borrowing base of
$60 million. The credit facility was amended as of September 30, 1997, to
increase the maximum commitment from $75 million to $125 million, increase the
borrowing base by $5 million to $65 million, and modify the interest expense
coverage ratio test.
On December 18, 1997, the Company acquired a thirty percent (30%)
membership interest in NGTS, LLC., a newly formed wholly-owned subsidiary of
Natural Gas Transmission Services, Inc., a natural gas marketing and trading
company. NGTS, LLC assumed all of the parent company's operations as of December
1, 1997. The Company, as of December 1, 1997, dedicated its natural gas
production to NGTS, LLC for marketing. The Company's $4.35 million acquisition
was completed for a combination of cash ($2.35 million) and promissory notes
($2.0 million) that had equity "put" features. The Company retired the
promissory notes with cash on January 31, 1999.
On January 28, 1998, the Company commenced a cash purchase offer for Units
of TEL Offshore Trust. Previous to the offer, the Company owned 161,500 Units
representing 3.4% of the Units outstanding. As amended, the offer was to
purchase between forty percent (40%) and sixty percent (60%) of the Trust's
outstanding Units at $5.50 per Unit. On March 27, 1998, the Company purchased
1,745,353 Units pursuant to the tender offer and, together with the Units it
previously owned, became the owner of approximately 40% of the total number of
Units outstanding for an aggregate of $10.4 million.
On December 31, 1998, the Company through its newly formed 100% owned
subsidiary, Bluebird Energy, Inc. acquired from Spirit 76 natural gas reserves
and associated assets in producing fields located in Oklahoma and Texas
currently producing about 12 million cubic feet of natural gas equivalent per
day. The net purchase price was approximately $25 million after certain purchase
price adjustments, including preferential rights exercised by third parties and
other customary adjustments. As part of the capitalization of Bluebird, the
Company contributed 1,840,271 units of TEL Offshore Trust. Bluebird, as an
"unrestricted subsidiary" as defined under certain credit agreements, is neither
a guarantor of the Company's 10% Senior Notes due 2007 nor can it be included in
the determining compliance with certain financial covenants under the Company's
credit agreements. To finance the Spirit 76 Acquisition, Bluebird borrowed $26
million under a bridge loan facility with banks. The maturity date of the bridge
loan facility, as amended, is April 15, 1999. The loan is non-recourse to the
Company. Bluebird has secured a commitment for permanent financing from a bank
providing for a revolving credit facility of $75 million with an initial
borrowing base of $30 million, due three years from the date of closing
(anticipated to be April 15, 1999) with interest rates for both "LIBOR" and
"Base Rate" (Prime).
The Company uses the full cost method of accounting for its investment in
oil and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and gas reserves are capitalized
into a "full cost pool" as incurred, and properties in the pool are depleted and
charged to operations using the unit-of-production method based on the ratio of
current production to total proved oil and gas reserves. To the extent that such
capitalized costs (net of accumulated depreciation, depletion and amortization)
less deferred taxes exceed the SEC PV-10 of estimated future net cash flow from
Proved Reserves of oil and gas, and the lower of cost or fair value of unproved
properties after income tax effects, such excess costs are charged to
operations. Once incurred, a write-down of oil and gas properties is not
reversible at a later date even if oil or gas prices increase. Due primarily to
the severe decline in world crude oil and natural gas prices experienced in
1998, the Company recognized a non-cash impairment of oil and gas properties of
$42.7 million at December 31, 1998 pursuant to the ceiling limitation required
by the full cost method of accounting, using certain improvements in pricing
experienced after the end of the period. Without the benefit of improvements in
pricing subsequent to December 31, 1998, the Company would have incurred an
impairment of $81.2 million.
24
Results of Operations For the Years Ended 1998 and 1997
As discussed above, the Company acquired the Permian Basin Properties in
April 1997, and its interest in TEL in March 1998. Unless otherwise stated, the
increases in the 1998 period over the 1997 period were substantially a result of
these acquisitions and the increases in daily oil and gas production associated
with the Company's successful drilling operations.
Oil and gas sales were $43.6 million in 1998, a 26% increase over sales of
$34.6 million in 1997. In 1998, the Company sold 1,140,762 Bbl of oil, a 55%
increase, and 14,119 MMcf of gas, a 47% increase over the prior year. The price
received for oil was $12.67 per Bbl and for gas was $2.02 per Mcf in 1998,
representing a 28% decrease in oil price from $17.70 per Bbl in 1997 and a 10%
decrease in gas price from $2.24 per Mcf in 1997. Oil and gas production lifting
costs increased 81% to $14.3 million in 1998 from $7.9 million in 1997. The
gross operating margin from oil and gas production was $22.9 million in 1998, a
5% increase over the gross operating margin of $21.8 million in 1997. On an
equivalent unit basis, the gross margin was $1.06 per Mcfe in 1998 versus $1.55
in 1997, a 32% decrease. The sales price per Mcfe was $2.05 in 1998 versus $2.46
in 1997, a 17% decrease. Production lifting costs increased 21% to $0.68 per
Mcfe in 1998 from $0.56 per Mcfe in 1997. Production tax and other costs
decreased 11% to $0.31 per Mcfe in 1998 from $0.35 per Mcfe in 1997. Total
equivalent units sold increased 49% to 21 Bcfe in 1998 from 14 Bcfe in 1997.
Gas gathering, marketing, and processing revenues were $7.0 million in the
1998 period, a 32% decrease from revenues of $10.3 million in 1997. Gross
operating margin was $1.2 million in 1998 versus $2.4 million in 1997, a 50%
decrease. Total gathering system throughput increased 1% to 20.8 MMcf per day in
1998 compared with 20.5 MMcf per day in 1997. Gas plant processing throughput
was 15.7 MMcf per day in 1998 versus 14.9 MMcf per day. Gross operating margin
from gathering operations was $0.11 per Mcf of throughput in 1998 versus $0.22
per Mcf in 1997, a 48% decrease. The gross operating margin from gas processing
was $0.07 per Mcf of throughput in 1998 versus $0.20 per Mcf in 1997, a 67%
decrease.
Revenues from oil field services and international sales were $881 thousand
in 1998, a 78% decrease from revenues of $4.0 million in 1997, principally due
to a decrease in sales in Hunter Butcher International, L.L.C. ("Hunter
Butcher") in the amount of $3.1 million. Operating costs were $467 thousand in
1998, a $3.3 million decrease over 1997, also principally due to Hunter Butcher.
The gross operating margin from these activities was $414,000 in 1998 versus
$223,000 in the 1997 period.
Depreciation and depletion expense increased 76% to $21.8 million in 1998
from $12.4 million in 1997 due to the acquisitions and to loss of reserves as a
result of year-end prices. Depletion expense on oil and gas production in 1998
was $20.9 million, or $1.00 per Mcfe, in 1998 versus $11.6 million, or $0.82 per
Mcfe in 1997. The Company wrote-down the value of its oil and gas full cost pool
by $42.7 million in 1998 versus none in 1997. This write-down was the result of
the low oil and gas prices experienced by all producers in December 1998. While
this write-down is not recoverable if prices increase, it should have the effect
of lowering the Company's future depletion rates. Without the benefit of
improvements in pricing subsequent to December 31, 1998, the Company would have
incurred an impairment of $81.2 million. General and administrative expense
increased 26% to $3.0 million in 1998 from $2.4 million in 1997, due to
increased staffing and other costs as a result of the acquisitions, increased
activity levels of the Company and the provision for doubtful accounts on a note
receivable.
Operating profit decreased $52.6 million to a loss of $43.0 million in 1998
versus a profit of $9.6 million in 1997. Equity in earnings of affiliate, net of
income tax, was a loss of $116,000 in 1998 versus a profit of $6,000 reported in
1997. Other income decreased 25% to $572,000 in 1998 versus $762,000 in 1997 due
to gain on sale of marketable securities in 1997 which did not occur in 1998.
Interest expense increased to $18.2 million in 1998 from $13.8 million in 1997,
an increase of 32%, due to increased levels of borrowing under the Company's
revolving credit lines and the Notes. The Company incurred a net loss before
income tax and minority interest of $60.7 million in 1998, versus a net loss of
$3.4 million in 1997, principally due to the write-down of oil and gas reserves,
lower oil and gas prices and higher interest expense. The Company provided for a
deferred income tax benefit of $13.7 million on this loss in 1998 versus a
deferred income tax benefit of $1.3 million in 1997. After recording a $37,000
minority
25
interest loss in Hunter Butcher, the Company reported a net loss in 1998 before
extraordinary item of $47.1 million, or $2.26 per common share, versus a
minority interest loss of $19,000 and a net loss before extraordinary item of
$2.1 million, or $0.21 per common share in 1997.
The Company realized an extraordinary loss of $1.4 million ($0.09 per
common share) as required under Accounting Principles Board ("APB") Statement
No. 26 and Statement of Financial Standards ("SFAS") No. 4, from the early
extinguishment of bank debt in 1997 and none in 1998. The net loss in 1997,
after the extraordinary charge, applicable to common shareholders was $4.4
million ($0.30 per common share) in 1997 compared to a net loss of $48.0 million
($2.26 per common share) in 1998. The Company accrued $875,000 in dividends on
its preferred stock in both years 1998 and 1997.
Results of Operations For the Years Ended 1997 and 1996
As discussed above, the Company acquired the Panoma Properties in June
1996, the McLean Gas Plant in January 1997, and the Permian Basin Properties in
April 1997. As such, the results of operations for the fiscal year ended 1997
included twelve months of operations for the Panoma Properties and the McLean
Gas Plant and eight months for the Permian Basin Properties, while the
corresponding period in 1996 contained six months of operations for the Panoma
Properties and no results related to the McLean Gas Plant and the Permian Basin
Properties. Unless otherwise stated, the increases in the 1997 period over the
1996 period were a direct result of these acquisitions.
Oil and gas sales were $34.6 million in 1997, a 237% increase over sales of
$10.2 million in 1996. In 1997, the Company sold 737,289 Bbl of oil, a 286%
increase, and 9,614 MMcf of gas, a 259% increase over the prior year. The price
received for oil was $17.70 per Bbl and for gas was $2.24 per Mcf in 1997,
representing a 13% decrease in oil price from $20.46 per Bbl in 1996 and a 5%
decrease in gas price from $2.37 per Mcf in 1996. Oil and gas production costs
increased 192% to $12.8 million in 1997 from $4.4 million in 1996. The gross
operating margin from oil and gas production was $21.8 million in 1997, a 271%
increase over the gross operating margin of $5.9 million in 1996, principally
due to the volume increase of oil and gas sold. On an equivalent unit basis, the
gross margin was $1.55 per Mcfe in 1997 versus $1.53 in 1996, a 1% increase.
Gas gathering, marketing, and processing revenues were $10.3 million in the
1997 period, a 79% increase over revenues of $5.8 million in 1996. Costs from
these activities were $7.9 million in 1997, a 68% increase over costs of $4.7
million in 1996. Gross operating margin was $2.4 million in 1997 versus $1.1
million in 1996, a 125% increase. Total gathering system throughput increased
60% to 20.5 MMcf per day in 1997 compared with 12.8 MMcf per day in 1996. Due to
the McLean Gas Plant acquisition, gas plant processing throughput was 14.9 MMcf
per day in 1997 versus none reported in 1996. Gross operating margin from
gathering operations was $0.22 per Mcf of throughput in 1997 versus $0.23 per
Mcf in 1996. The gross operating margin from gas processing was $0.20 per Mcf of
throughput versus none reported in 1996.
Revenues from oil field services and international sales were $4.0 million
in 1997, an 885% increase over revenues of $396,000 in 1996, principally due to
an increase in sales of Hunter Butcher International, L.L.C. ("Hunter Butcher")
in the amount of $3.4 million. Operating costs were $3.7 million in 1997, a $3.5
million increase over 1996, also principally due to Hunter Butcher. The gross
operating margin from these activities was $223,000 in 1997 versus $129,000 in
the 1996 period. The margin from Hunter Butcher operations was $60,000 in 1997
versus $32,000 in the 1996 period. Oil field services produced an operating
margin of $163,000 in 1997 versus a loss of $97,000 in 1996.
Depreciation and depletion expense increased 319% to $12.4 million in 1997
from $3.0 million in 1996 due to the acquisitions. Depletion expense on oil and
gas production in 1997 was $11.6 million, or $0.82 per Mcfe, in 1997 versus $2.6
million, or $0.70 per Mcfe, in 1996. General and administrative expense
increased 92% to $2.4 million in 1997 from $1.2 million in 1996, due to
increased staffing and other costs as a result of the acquisitions and increased
activity levels of the Company.
26
Operating profit increased to $9.6 million in 1997 from $2.9 million in
1996, a 236% increase. Equity in earnings of affiliate, net of income tax, was
$6,000 in 1997 versus none reported in 1996 due to the NGTS acquisition in
December, 1997. Other income increased 122% to $762,000 due to gain on sale of
marketable securities. Interest expense increased to $13.8 million in 1997 from
$2.4 million in 1996, an increase of 476%, due to increased levels of borrowing
under the Company's revolving credit lines, the Notes, and bridge financing used
to fund the acquisitions previously mentioned. The Company incurred a net loss
before inco