<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-KSB
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; or
[_] 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. 0-19753
GOTHIC ENERGY CORPORATION
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(Name of Small Business Issuer in its Charter)
Oklahoma 22-2663839
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(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification No.)
5727 South Lewis Avenue - Suite 700 - Tulsa, Oklahoma 74105
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(Address of Principal Executive Offices) (Zip Code)
(918) 749-5666
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(Issuer's Telephone Number, Including Area Code)
Securities registered under Section 12(b) of the Exchange Act:
Title of Each Class Name of Each Exchange on Which Registered
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None
Securities Registered Pursuant to Section 12(g) of the Exchange Act:
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Common Stock, par value $.01 per share
Redeemable Common Stock Purchase Warrants expiring January 24, 2001
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(Title of Each Class)
Check whether the Issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past twelve (12) months (or
for such shorter period that the Issuer was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days.
[X] Yes [_] No
Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B in this form, and no disclosure will be contained, to the
best of Issuer's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB, or any amendment to
this Form 10-KSB. [X]
State Issuer's revenues for its most recent fiscal year: $53,033,000
The aggregate market value of the voting stock held by non-affiliates
computed by reference to the price at which the stock was sold, or the average
bid and asked prices of such stock, as of March 12, 1999, was $9,655,349. (Non-
affiliates have been determined on the basis of holdings set forth in the
information incorporated by reference under Item 11 of this Annual Report on
Form 10-KSB.)
The number of shares outstanding of each of the Issuer's classes of common
equity, as of December 31, 1998, was 16,261,640.
DOCUMENTS INCORPORATED BY REFERENCE
None
(cover continued on next page)
<PAGE>
Commission File No. 333-52225
GOTHIC PRODUCTION CORPORATION
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(Name of Small Business Issuer in its Charter)
Oklahoma 73-1539475
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(State or Other Jurisdiction of (IRS Employer
Incorporation or Organization) Identification No.)
5727 South Lewis Avenue - Suite 700 - Tulsa, Oklahoma 74105
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(Address of Principal Executive Offices) (Zip Code)
(918) 749-5666
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(Issuer's Telephone Number, Including Area Code)
Securities registered under Section 12(b) of the Exchange Act:
Title of Each Class Name of Each Exchange on Which Registered
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None
Securities Registered Pursuant to Section 12(g) of the Exchange Act:
None
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(Title of Each Class)
Check whether the Issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past twelve (12) months (or
for such shorter period that the Issuer was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days.
[X] Yes [_] No
Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B in this form, and no disclosure will be contained, to the
best of Issuer's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB, or any amendment to
this Form 10-KSB. [X]
State Issuer's revenues for its most recent fiscal year: $32,000,000
The aggregate market value of the voting stock held by non-affiliates. -0-
The number of shares outstanding of each of the Issuer's classes of common
equity, as of December 31, 1998, was 100 shares, par value $1.00 per share.
DOCUMENTS INCORPORATED BY REFERENCE
None.
GOTHIC ENERGY CORPORATION
GOTHIC PRODUCTION CORPORATION
This Annual Report on Form 10-KSB is filed by Gothic Energy Corporation (file
number 0-19753) pursuant to Section 13 of the Securities Exchange Act of 1934,
as amended, and by Gothic Production Corporation (file number 333-52225)
pursuant to Section 15(d) of the Securities Exchange Act of 1934, as amended.
See Note 14 to Consolidated Financial Statements, included in Item 7 herein.
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TABLE OF CONTENTS
Page
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PART I
Item 1. Description of Business 1
Item 2. Description of Property 15
Item 3. Legal Proceedings 17
Item 4. Submission of Matters to a Vote of Security Holders 17
PART II
Item 5. Market for Common Equity and Related Security
Holder Matters 18
Item 6. Management's Discussion and Analysis or Plan of
Operation 19
Item 7. Financial Statements 43
Item 8. Changes in and Disagreements on Accounting and
Financial Disclosure 43
PART III
Item 9. Directors, Executive Officers, Promoters and
Control Persons; Compliance With Section 16(a) of
the Exchange Act 44
Item 10. Executive Compensation 47
Item 11. Security Ownership of Certain Beneficial Owners and
Management 51
Item 12. Certain Relationships and Related Transactions 53
Glossary 55
PART IV
Item 13. Exhibits and Reports on Form 8-K 59
<PAGE>
PART I
Item 1 - Description of Business:
General
Gothic Energy Corporation (the "Company") is an independent energy company
primarily engaged in the acquisition, development, exploitation, exploration and
production of natural gas and oil. Members of the Company's current management,
including the Company's Chairman and Chief Executive Officer, assumed operating
control of the Company in November 1994 after selling American Natural Energy
Corporation ("ANEC") (a publicly traded exploration and production company),
earlier that year. The new management team commenced natural gas and oil
operations by implementing a business strategy emphasizing acquisitions of long-
lived, proved producing natural gas properties with significant development and
exploitation potential. As a result of this strategy, the Company has grown
primarily through 14 acquisitions of producing oil and gas properties for total
consideration of $339.9 million, including the acquisition, on January 23, 1998,
of the natural gas producing properties of Amoco Corporation located in the
Anadarko and Arkoma Basins of Oklahoma (the "Amoco Acquisition"). As of December
31, 1998, the Company had proved reserves of 306.7 Bcf of natural gas and 1.8
MMBbls of oil (317.2 Bcfe), with a PV-10 of approximately $203.0 million as
estimated by the Company's independent petroleum engineers.
The Company's natural gas and oil reserves and acreage are principally
located in the Anadarko, Arkoma and Permian/Delaware basins, which are
historically prolific basins with multiple producing horizons and long-lived
reserves. These basins generally provide significant development and
exploitation potential through low-risk infill drilling and the implementation
of new workover, drilling and recompletion technologies. While continuing to
pursue attractive acquisition opportunities, the Company has increased its focus
on implementing a comprehensive development and exploitation program designed to
increase its natural gas and oil production, earnings, cash flow and net asset
value by enhancing proved producing reserves and converting proved undeveloped
reserves to proved producing reserves. The Company has identified, as of March
15, 1999, 225 development and exploitation projects within its properties.
Since July 1, 1997, the Company initiated a comprehensive development program
and as of March 15, 1999 had successfully drilled 62 wells, 59 of which have
been completed and are producing and, at March 15, 1999, an additional eight
wells were in various stages of completion. Through March 15, 1999, the Company
has not engaged in any material exploration
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activities but intends to devote a limited amount of capital in the future to
pursue "controlled-risk" exploration opportunities.
At December 31, 1998, the Company held an interest in approximately 452,000
gross acres (approximately 237,000 net acres) and had an interest in 952 gross
wells (453 net wells). The Company serves as operator of 540 of the wells in
which it has an interest. Operated wells account for approximately 74% of the
PV-10 value of the Company's proved reserves as of December 31, 1998. The
Company had estimated proved reserves of 317.2 Bcfe with a PV-10 of $203.0
million as of December 31, 1998. These reserves, of which 83% were classified as
proved developed, had an estimated average reserve life of approximately 10.5
years and 97% were natural gas. For the year ended December 31, 1998, the
Company had revenues of $53.0 million, EBITDA of $37.1 million and a net loss of
$129.7 million.
Business Strategy
The Company's objective is to increase its reserves, production, earnings,
cash flow and net asset value through a growth strategy that includes (i)
acquiring strategic natural gas and oil properties in a disciplined manner, (ii)
developing, exploiting and exploring its properties and (iii) maintaining a low
operating cost structure.
. Strategic Acquisitions. The Company has increased its reserves through
acquisitions, having added 424.9 Bcfe through 14 acquisitions at a total
acquisition cost of $339.9 million, or an average cost of $0.80 per Mcfe.
The Company utilizes a disciplined acquisition strategy, focusing its
acquisition efforts on producing natural gas properties within strategic
geographic areas with (I) relatively long-lived natural gas production,
(ii) quantifiable development and exploitation potential, (iii) low risk
exploration potential, (iv) historically low operating expenses or the
potential to reduce operating expenses, (v) close proximity to the
Company's existing production or in areas where the Company has the ability
to develop operating economies of scale and (vi) geological, geophysical
and other technical and operating characteristics with which management of
the Company has expertise. The Company applies strict economic and reserve
risk criteria in evaluating acquisitions of natural gas and oil properties
and companies.
. Development, Exploitation and Exploration. The Company seeks to
maximize the value of its natural gas and oil properties through
development drilling, workovers, recompletions, reductions in operating
costs and enhanced
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operating efficiencies. The Company has, as of March 15, 1999, identified
225 development and exploitation projects within its properties, of which
100 have been assigned proved undeveloped reserves. The Company's 1999
development drilling program includes plans to spend approximately $16.0 to
$18.0 million to drill approximately 30 to 40 wells, of which most are
classified as infill development wells on proved undeveloped locations.
The Company also continually evaluates and pursues exploitation
opportunities, including workover and recompletion projects. The Company
expects it will spend approximately $2.0 million annually on these
projects. The Company intends to devote a limited amount of capital in the
future to pursue "controlled-risk" exploration opportunities by drilling on
undeveloped acreage in areas in close proximity to producing properties.
The Company believes geological and geophysical data, including 3D and 2D
seismic surveys acquired in the Amoco Acquisition, will enable it to reduce
costs and risks associated with drilling activities throughout its Anadarko
basin properties.
. Maintain Low Cost Operations. The Company is able to control directly
operating and drilling costs as the operator of wells comprising
approximately 74% of the PV-10 value of proved reserves as of December 31,
1998. In addition, the Company has been able to reduce per unit operating
costs by eliminating unnecessary field and corporate overhead costs and by
divesting marginal and non-strategic properties with limited development
potential. Lease operating expenses have decreased 55%, from $0.85 per Mcfe
of production in 1996 to $0.38 per Mcfe for the year ended December 31,
1998. Further, general and administrative expenses per Mcfe of production
have decreased 66%, from $0.41 per Mcfe to $0.14 per Mcfe over the same
period. The Company intends to further improve the efficiency of and reduce
the operating costs associated with well operations through the use of
advanced wireless technology licensed to the Company as part of the Amoco
Acquisition. This technology enables the Company to remotely monitor well
operations, thereby reducing the need for on-site monitoring personnel.
The Company intends to deploy this technology throughout many of its
producing properties in the Anadarko and Arkoma basins.
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Significant Acquisitions
Since November 1994, the Company has actively engaged in the acquisition of
producing natural gas and oil properties, primarily in Oklahoma, Texas, New
Mexico and Kansas. The following table summarizes certain information concerning
the Company's significant acquisitions from November 1994 through December 31,
1998.
<TABLE>
<CAPTION>
Estimated Proved
Reserves at
Date of Acquisition Acquisition
Acquisition/(1)/ Cost/(2)/ Cost/(2)/
Date of Acquisition Principal Seller (Bcfe) (in millions) (per Mcfe)
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
January 23, 1998 Amoco Production Company(3) 240.0 $242.0 $1.01
September 9, 1997 Affiliates of HS Resources, Inc. 50.6 27.5 0.54
August 12, 1997 Kerr-McGee Corporation 7.1 3.6 0.51
May 15, 1997 Fina Oil and Chemical Company 7.8 3.3 0.42
February 18, 1997 Horizon Gas Partners, L.P. 13.8 10.0 0.72
February 18, 1997 Norse Exploration, Inc.;
H. Huffman & Company(4) 22.9 8.4 0.37
December 17, 1996 Athena Energy, Inc. 4.9 4.2 0.86
May 16, 1996; Comstock Oil & Gas, Inc. and
August 5, 1996 Additional working interest
Acquisition(5) 13.2 9.7 0.73
January 30, 1996 Buttonwood Energy Corporation 26.7 20.5 0.77
May 31, 1995; Johnson Ranch Partners and
May 20, 1996 Additional working interest
Acquisition(6) 37.9 10.7 0.28
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Total 424.9 $339.9 $0.80
===== ====== =====
</TABLE>
_____________________________
(1) Estimated proved reserves at date of acquisition are based on reserve
reports prepared for the specific acquisition. Estimated proved reserves
for the Amoco Acquisition are based on the December 31, 1997 reserve report
prepared by the Company's independent petroleum engineer.
(2) Does not include costs to develop these properties, which properties may
include a substantial amount of proved undeveloped reserves.
(3) Includes cash paid of $238.4 million, $2.9 million in net gas balancing
liabilities assumed by the Company, and five-year warrants to purchase 1.5
million shares of Common Stock at an exercise price of $3.00 per share which
were valued by the Company at $1.2 million, less amounts allocated to gas
systems totaling $467,000.
(4) Includes cash paid of $14.7 million and two-year warrants to purchase
200,000 shares of Common Stock at an exercise price of $2.50 per share which
were valued by the Company at $254,000, less amounts allocated to a
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gas system and to unproved properties. Also includes additional interests
acquired in the same properties in a subsequent transaction.
(5) Includes natural gas and oil properties acquired on the date indicated for
$6.4 million, as well as the subsequent acquisition of additional working
interests on the date indicated for $3.3 million in the same area as the
earlier acquisition.
(6) Includes properties purchased for $7.2 million in cash and 1.0 million
shares of Common Stock valued at $2.69 per share and the subsequent purchase
by the Company of related overriding royalty interests for $800,000.
The Company continually reviews potential acquisition opportunities
(including opportunities to acquire natural gas and oil properties or related
assets or entities owning natural gas and oil properties or related assets and
opportunities to engage in mergers, consolidations or other business
combinations with entities owning natural gas and oil properties or related
assets) and at any given time may be in various stages of evaluating such
opportunities and anticipates making additional acquisitions if such properties
fit into its overall business strategy. The Company does not have a budget
specifically for acquisitions, however, since the timing and size of potential
acquisitions cannot be predicted. As of March 15, 1999, the Company had no
definitive agreements with respect to any significant acquisitions.
Natural Gas and Oil Reserves
The following table sets forth certain information on the total proved
natural gas and oil reserves, and the PV-10 of estimated future net revenues of
total proved natural gas and oil reserves as of December 31, 1998 for the
Company based on the report of Lee Keeling and Associates, Inc. The calculations
which Lee Keeling and Associates, Inc. used in preparation of such report were
prepared using geological and engineering methods generally accepted by the
petroleum industry and in accordance with SEC guidelines.
<TABLE>
<CAPTION>
As of December 31, 1998
---------------------------------------------------------------------------------
Natural Gas
Natural Gas Oil Equivalent PV-10%
(MMcf) (MBbls) (Mmcfe) (in thousands)
----------------------------------- -----------------------------------
<S> <C> <C> <C> <C>
Proved developed reserves 254,762 1,523 263,900 $183,403
Proved undeveloped reserves 51,906 238 53,334 19,617
----------------------------------- -----------------------------------
Total proved reserved 306,668 1,761 317,234 $203,020
=================================== ===================================
</TABLE>
Prices used in calculating future net revenue of proved reserves as of December
31, 1998 and related PV-10 were $1.81 per Mcf of natural gas and $10.50 per
barrel of oil based on average prices received by the Company during December
1998. Subsequent to December 31, 1998, average prices received for natural gas
and oil
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decreased and have been as low as $1.40 per Mcf and $10.30 per barrel through
March 1, 1999. If the March 1, 1999 prices had been used in the preparation of
the Company's natural gas and oil reserves, the estimated quantities and value
of such reserves would have been lower than that which is shown above.
The Company has not filed any estimates of proved natural gas and oil
reserves with any federal authority or agency other than the Securities and
Exchange Commission.
Principal Areas of Operations
The following table sets forth the principal areas of operation and
estimated proved natural gas and oil reserves, PV-10 of the estimated future net
revenues and percent of total PV-10 of the Company at December 31, 1998.
<TABLE>
<CAPTION>
Natural
Oil and Natural Gas PV10% % of
Condensate Gas Equivalent (in Total
Field (MBbls) (MMcf) (MMcfe) thousands) PV10%
- ---------------------------------- ---------- ------- --------- ---------- -----
<S> <C> <C> <C> <C> <C>
Anadarko Basin:
Springer Field................... 121 21,360 22,086 $ 16,763 8.3%
Northwest Okeene/Cedardale Field. 185 35,120 36,230 25,339 12.5%
Cement Field..................... 296 70,541 72,317 38,264 18.8%
Mocane Laverne & Hugoton Fields.. 53 15,706 16,024 11,426 5.6%
Watonga-Chickasha................ 598 100,760 104,348 73,685 36.3%
Arkoma Basin:
Arkoma Field..................... - 29,532 29,532 18,866 9.3%
Permian/Delaware Basin:
Johnson Ranch/Brushy Draw........ 508 11,593 14,641 9,663 4.8%
Pecos Slope...................... 22,056 22,056 9,014 4.4%
----- ------- ------- -------- -----
Totals............................ 1,761 306,668 317,234 $203,020 100.0%
===== ======= ======= ======== =====
</TABLE>
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Drilling Activity
The following table sets forth development drilling results for the years
ended December 31, 1996, 1997 and 1998. There were no exploratory wells drilled
during those years.
1996 1997 1998
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Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Productive 2.0 .5 17.0 9.9 44.0 20.4
Non-Productive --- -- ---- --- 2.0 1.8
--- -- ---- --- ---- ----
Total 2.0 .5 17.0 9.9 46.0 22.2
=== == ==== === ==== ====
In the third quarter of 1997, the Company initiated a comprehensive
development program and, as of March 15, 1999, had successfully drilled 62
wells, of which 59 have been completed and are producing and, at March 15, 1999,
eight additional wells were at various stages of completion. The Company's 1999
development drilling program includes plans to spend approximately $16.0 to
$18.0 million to drill approximately 30 to 40 wells, most of which are infill
development wells on proved undeveloped locations. The Company also continually
evaluates and pursues exploitation opportunities, including workover and
recompletion projects. The Company expects it will spend approximately $2.0
million annually on these projects. The Company intends to devote a limited
amount of capital in the future to pursue "controlled-risk" exploration
opportunities by drilling on undeveloped acreage in areas in close proximity to
producing properties. The Company believes geological and geophysical data,
including 3D and 2D seismic surveys acquired in the Amoco Acquisition, will
enable it to reduce costs and risks associated with drilling activities
throughout its Anadarko basin properties.
The final determination with respect to any potential drilling locations
and the expected time frame for the drilling of any well will depend on a number
of factors, including (i) the results of exploration efforts and the review and
analysis of the seismic or other data, (ii) the availability of sufficient
capital resources by the Company for drilling prospects, and (iii) economic and
industry conditions at the time of drilling, including prevailing and
anticipated prices for natural gas and oil and the availability of drilling rigs
and crews. There can be no assurance that any wells will, if drilled, encounter
reservoirs of commercial quantities of natural gas or oil.
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Operating Control Over Production Activities
The Company operates 540 of the 952 wells in which it owns an interest,
representing approximately 74% of its PV-10 as of December 31, 1998. The non-
operated properties are being operated by unrelated third parties pursuant to
operating agreements which are, for the most part, standard to the industry.
Decisions about operations regarding non-operated properties may be determined
by the outside operator rather than the Company. If the Company declines to
participate in additional activities proposed by the outside operator, under
certain operating agreements, the Company will not receive revenues from, and/or
will lose its interest in, the activity in which it declines to participate.
Pursuant to the Amoco Acquisition, the Company received a license to use
advanced well automation technology developed by Amoco. This technology is a
wireless application that allows the Company to remotely monitor production,
well pressure and temperature along with other well control factors on a real-
time basis. Further, the technology helps to regulate the well's productivity
and makes periodic adjustments to allow the well to flow more efficiently. The
Company believes that the application of this wireless technology will allow the
Company to employ fewer personnel to monitor well activity and operate wells
more economically. This technology is currently being utilized on certain of
the Anadarko basin wells acquired in the Amoco Acquisition. The Company intends
to deploy this technology to other properties in the Anadarko and Arkoma basins
and, as a result, expects to further reduce overall lease operating costs.
Title to Natural Gas and Oil Properties
The Company has acquired interests in producing and non-producing acreage
in the form of working interests, royalty interests and overriding royalty
interests. Substantially all of the Company's property interests are held
pursuant to leases from third parties. The leases grant the lessee the right to
explore for and extract natural gas and oil from specified areas. Consideration
for a lease usually consists of a lump sum payment (i.e., bonus) and a fixed
annual charge (i.e., delay rental) prior to production (unless the lease is paid
up) and, once production has been established, a royalty based generally upon
the proceeds from the sale of natural gas and oil. Once wells are drilled, a
lease generally continues so long as production of natural gas and oil
continues. In some cases, leases may be acquired in exchange for a commitment to
drill or finance the drilling of a specified number of wells to predetermined
depths. Some of the Company's non-producing acreage is held under leases from
mineral owners or a government entity which expire at varying dates. The Company
is obligated to pay annual delay rentals to the lessors of certain properties in
order to prevent the leases from terminating. Because
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substantially all of the Company's undeveloped acreage is held by production,
annual delay rentals are generally nominal.
Title to leasehold properties is subject to royalty, overriding royalty,
carried, net profits and other similar interests and contractual arrangements
customary in the natural gas and oil industry, and to liens incident to
operating agreements, liens relating to amounts owed to the operator, liens for
current taxes not yet due and other encumbrances. In addition, in certain areas
the Company's interests in producing properties are subject to certain
agreements and other instruments that have not been recorded in real property
records. The effect of these unrecorded instruments has been confirmed based
upon a review of historic cost and revenue information, including joint interest
billings, division orders, check stubs and other production accounting
information reflecting such unrecorded interests. The Company believes that
such burdens and unrecorded instruments neither materially detract from the
value of its interest in the properties, nor materially interfere with the use
of such properties in the operation of its business.
While updated title opinions may not always be received prior to the
acquisition of a producing natural gas and oil property, title opinions on
significant producing properties have historically been obtained in connection
with pledging the Company's producing properties under bank loan agreements. On
undeveloped leases, title opinions are usually not obtained until immediately
prior to the drilling of a well on a property. Accordingly, the Company's
proved undeveloped reserves may be the subject of significantly less title
investigation. It is contemplated, however, that investigations will be made in
accordance with standard practices in the industry before the acquisition of
producing properties and before exploratory drilling.
Production and Sales Prices
The Company's production of natural gas and oil is derived solely from
within the United States. The Company is not obligated to provide a fixed and
determinable quantity of oil and/or natural gas in the future under existing
contracts or agreements with customers. However, from time to time, the Company
does enter into hedging agreements with respect to its natural gas and oil
production. At December 31, 1998, the Company had entered into swap agreements
relating to the sale of 60,000 Mcf per day at a floor price of $2.10 per Mcf and
expiring on January 31, 1999. In March 1999, the Company entered into a hedge
agreement in the form of a collar with respect to the production of 50,000 MMBTU
of natural gas per day during the period of April through October 1999. The
collar places a floor of $1.65 per MMBTU and a ceiling of $2.16 per MMBTU for
the effective price of natural gas received by the Company. The Company will pay
the other party $0.05 per MMBTU per day over the term of the agreement.
The Company does not refine or process the natural gas and oil it produces,
but sells the production to unaffiliated natural gas and oil purchasing
companies in the area in which it is produced. The Company sells crude oil on a
market price basis and sells natural gas under contracts to both interstate and
intrastate natural gas pipeline companies.
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<PAGE>
Marketing of Production
The Company's production of natural gas and oil is marketed to third
parties consistent with industry practices. Typically, oil is sold at the
wellhead at field posted prices, and gas is sold under contract at negotiated
prices based upon factors normally considered in the industry, such as distance
from the well to the pipeline, well pressure, estimated reserves, quality of gas
and prevailing supply/demand conditions.
Typically, gas production is sold to various pipeline companies. The basic
terms of all the contracts are essentially the same in that the Company makes
gas production available to the pipeline companies at certain given points of
delivery on their pipelines and the pipeline company accepts such gas and
delivers it to the end user. The pipeline company then has the obligation to
pay the Company a price for the gas which is based on published indices of
average pipeline prices or upon a percentage of the pipeline resale value.
In January 1998 the Company entered into a ten-year marketing agreement
with Continental Natural Gas Company ("Continental") whereby the majority of the
natural gas associated with the Amoco Acquisition will be sold to Continental at
current market prices adjusted for marketing and transportation fees.
The Company's revenues, earnings and cash flows are highly dependent upon
current prices for natural gas and oil. In December 1998, natural gas and oil
prices received by the Company for its production were $1.81 per Mcf and $10.50
per Bbl, respectively. In general, prices of natural gas and oil are dependent
upon numerous factors beyond the control of the Company, including supply and
demand, competition, imports and various economic, political, environmental and
regulatory developments, and accordingly, future prices of natural gas and oil
may be different from prices in effect at December 31, 1998. As of March 1,
1999, prices received by the Company for natural gas had declined to $1.40 per
Mcf. In view of the many uncertainties affecting the supply and demand for
crude oil, natural gas and refined petroleum products, the Company is unable to
accurately predict future natural gas and oil prices and demand or the overall
effect they will have on the Company.
During the year ended December 31, 1998, the Company sold approximately 50%
of its gas production to Continental Natural Gas Corporation and 32% and 25% of
its oil production to Sun Company Inc. and Duke Energy, Inc., respectively.
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Competition
The natural gas and oil industry is highly competitive in all of its
phases. The Company encounters competition from other natural gas and oil
companies in all areas of its operations, including the acquisition of producing
properties and the marketing of natural gas and oil. Many of these companies
possess greater financial and other resources than the Company. Competition for
acquisition of producing properties is affected by the amount of funds available
to the Company, information about producing properties available to the Company
and any standards established from time to time by the Company for the minimum
projected return on investment. Because gathering systems are the only practical
method for the intermediate transportation of natural gas, competition is
presented by other pipelines and gas gathering systems. Competition may also be
presented by alternative fuel sources, including heating oil and other fossil
fuels. Because the primary markets for natural gas liquids are refineries,
petrochemical plants and fuel distributors, prices are generally set by or in
competition with the prices for refined products in the petrochemical, fuel and
motor gasoline markets.
Regulation
The natural gas and oil business is regulated extensively by federal, state
and local authorities. Various governmental agencies, both federal and state,
have promulgated rules and regulations binding on the natural gas and oil
industry and its individual members, some of which carry substantial penalties
for the failure to comply. The regulatory burdens on the natural gas and oil
industry increase its cost of doing business and, consequently, affect its
profitability. Because such laws and regulations are frequently amended or
reinterpreted, the Company is unable to predict the future cost of complying
with such regulations. The Company believes that it is in material compliance
with its regulatory obligations.
The States of Oklahoma and 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 natural gas and
oil. These states also have statutes or regulations addressing conservation
matters, including provisions for the unitization or pooling of natural gas and
oil properties, the establishment of maximum rates of production from wells and
the regulation of spacing, plugging and abandonment of such wells.
Environmental Matters. The Company's operations and properties are subject
to extensive and changing federal, state and local laws and regulations relating
to environmental protection, including the generation, storage, handling,
emission, transportation and discharge of materials into the environment, and
relating to safety and health. The recent trend in
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<PAGE>
environmental legislation and regulation generally is toward stricter standards,
and this trend will likely continue. These laws and regulations may require the
acquisition of a permit or other authorization before construction or drilling
commences and for certain other activities; limit or prohibit construction,
drilling and other activities on certain lands lying within wilderness and other
protected areas; and impose substantial liabilities for pollution resulting from
the Company's operations. The permits required for various of the Company's
operations are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce compliance with
their regulations, and violators are subject to fines or injunction, or both. In
the opinion of management, the Company is in substantial compliance with current
applicable environmental laws and regulations, and the Company has no material
commitments for capital expenditures to comply with existing environmental
requirements. Nevertheless, changes in existing environmental laws and
regulations or in interpretations thereof could have a significant impact on the
Company, as well as the natural gas and oil industry in general. The
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA")
and comparable state statutes impose strict, joint and several liability on
owners and operators of sites and on persons who dispose of or arrange for the
disposal of "hazardous substances" found at such sites. Although CERCLA
currently excludes petroleum from its definition of "hazardous substance," state
laws affecting the Company's operations impose clean-up liability relating to
petroleum and petroleum related products. It is not uncommon for the neighboring
land owners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment. The Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes govern the disposal of "solid waste" and "hazardous waste" and
authorize imposition of substantial fines and penalties for noncompliance.
Although RCRA classifies certain oil field wastes as "non-hazardous," such
exploration and production wastes could be reclassified as hazardous wastes,
thereby making such wastes subject to more stringent handling and disposal
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990
contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States. For onshore facilities that may affect
waters of the United States, the Environmental Protection Agency ("EPA")
requires an operator to demonstrate $10.0 million in financial responsibility,
and for offshore facilities the financial responsibility requirement is at least
$35.0 million. Regulations are currently being developed under federal and
state laws concerning oil pollution prevention and other matters that may impose
additional regulatory burdens on the Company. In addition, the Clean Water Act
and analogous state laws require permits to be obtained to authorize discharge
into surface waters or to construct facilities in wetland areas. With respect
to certain of its operations, the Company is required to maintain such permits
or meet general permit requirements. The EPA recently
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<PAGE>
adopted regulations concerning discharges of storm water runoff. This program
requires covered facilities to obtain individual permits, participate in a group
or seek coverage under an EPA general permit. The Company believes that it will
be able to obtain, or be included under, such permits, where necessary, and to
make minor modifications to existing facilities and operations that would not
have a material effect on the Company.
The Company has acquired leasehold interests in numerous properties that
for many years have produced natural gas and oil. Although the previous owners
of these interests may have used operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the properties. In addition, some of the
Company's properties are or have been operated by third parties over whom the
Company has or had no control. Notwithstanding the Company's lack of control
over properties operated by others, the failure of the operator to comply with
applicable environmental regulations may, in certain circumstances, adversely
impact the Company.
Marketing and Transportation. In the past, the transportation and sale for
resale of natural gas in interstate commerce has 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"). Since 1978, maximum selling prices of certain
categories of natural gas sold in the "first sales," whether sold in interstate
or intrastate commerce, has been regulated pursuant to the NGPA. The term
"first sales" means the first time gas is sold as a severed hydrocarbon after it
is produced from the ground. The NGPA established various categories of natural
gas and provided for graduated deregulation of price controls of several
categories of natural gas. There is currently no price regulation for "first
sales" of gas. On July 26, 1989, the Natural Gas Wellhead Decontrol Act was
enacted. This act amended the NGPA to remove both price and non-price controls
from natural gas sold in "first sales" as of January 1, 1993. Under current
market conditions, deregulated gas prices under new contracts tend to be
substantially lower than most regulated price ceilings prescribed by the NGPA.
The effect of termination of these price controls cannot be determined.
The FERC regulates interstate natural gas transportation rates and service
conditions, which affect the marketing of gas produced by the Company, as well
as the revenues received by the Company for sales of such production. Since the
mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636,
636-A and 636-B ("Order 636"), that have significantly altered the marketing and
transportation of natural gas. Order 636 mandates a fundamental restructuring
of interstate pipeline sales and transportation service, including the
unbundling by interstate pipelines of the sale, transportation, storage and
other components of the city-gate sales services such pipelines previously
performed. One of FERC's purposes in issuing the order was to increase
competition within all phases of the natural gas industry. Numerous parties
have filed petitions for review of Order 636, as well as orders in individual
pipeline restructuring
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<PAGE>
proceedings. In July 1996, Order 636 was generally upheld on appeal, and the
portions remanded for further action do not appear to materially affect the
Company. Because Order 636 may be modified as a result of the appeals, it is
difficult to predict the ultimate impact of the orders on the Company and its
gas marketing efforts. Generally, Order 636 has eliminated or substantially
reduced the interstate pipelines' traditional role as wholesalers of natural gas
and has substantially increased competition and volatility in natural gas
markets.
The price the Company receives from the sale of natural gas liquids and oil
is affected by the cost of transporting products to markets. Effective January
1, 1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such rates
to inflation, subject to certain conditions and limitations. The Company is not
able to predict with certainty the effect, if any, of these regulations on its
operations. However, the regulations may increase transportation costs or reduce
well head prices for natural gas liquids and oil.
Operational Hazards and Insurance
The Company maintains various types of insurance to cover its operations,
including $2.0 million of general liability insurance and an additional $5.0
million of excess liability insurance. The Company's insurance does not cover
every potential risk associated with the drilling and production of natural gas
and oil. Coverage is not obtainable for certain types of environmental hazards.
The occurrence of a significant adverse event, the risks of which are not fully
covered by the Company's insurance, could have a material adverse effect on the
Company's financial condition and results of operations. Moreover, no assurance
can be given that the Company will be able to maintain adequate insurance in the
future at reasonable rates.
Employees
As of March 15, 1999 the Company had a total of 30 employees consisting of
17 production and land personnel, and 13 financial, accounting and
administrative personnel, two of whom are executive officers.
Executive Office
The Company leases approximately 11,325 square feet of space in Tulsa,
Oklahoma for its corporate and administrative offices. The annual rental is
approximately $143,000 and the lease expires December 31, 1999. The Company
believes this facility is adequate for its present requirements.
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<PAGE>
Incorporation
The Company is an Oklahoma corporation. It was incorporated on November 19,
1985 under the laws of the State of New Jersey and was reincorporated as a
Delaware corporation on June 23, 1994. On December 4, 1996, the Company was
reincorporated as an Oklahoma corporation by merging the Delaware corporation
with and into a wholly owned subsidiary incorporated for that purpose under the
laws of the State of Oklahoma. Its principal office is at 5727 South Lewis
Avenue, Suite 700, Tulsa, Oklahoma 74105, and its telephone number is (918) 749-
5666.
Item 2 - Description of Property:
Acreage
The following table shows the approximate gross and net acres of leasehold
interests of the Company on December 31,1998.
<TABLE>
<CAPTION>
Developed Undeveloped Acreage
Acreage
---------------------- ----------------------
Field Gross Net Gross Net
- --------------------------------------------------- -------- -------- -------- --------
<S> <C> <C> <C> <C>
Anadarko Basin
Springer Field................................... 7,200 4,680 150 75
Northwest Okeene/Cedardale Field................. 66,560 51,906 1,920 274
Cement Field..................................... 48,640 29,184 3,201 920
Mocane Laverne & Hugoton Fields.................. 93,518 49,485 420 420
Watonga-Chickasha................................ 135,680 69,196 8,157 2,850
Arkoma Basin
Arkoma Field..................................... 74,240 18,560 ------ ------
Permian/Delaware Basin
Johnson Ranch/Brushy Draw........................ 160 120 ------ ------
Pecos Slope...................................... 12,000 9,000 ------ ------
------- ------- ------ -----
Totals......................................... 437,998 232,131 13,848 4,539
======= ======= ====== =====
</TABLE>
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Productive Well Summary
The following table sets forth by field the respective interests in
productive wells owned by the Company as of December 31,1998.
<TABLE>
<CAPTION>
Gross Net
Field Well Count Well Count
- ------------------------------------------------ ---------- ----------
<S> <C> <C>
Anadarko Basin:
Springer Field................................. 32 15
Northwest Okeene/Cedardale Field............... 194 111
Cement Field................................... 57 16
Mocane Laverne & Hugoton Fields................ 88 42
Watonga-Chickasha.............................. 359 174
Arkoma Basin:
Arkoma Field................................... 130 24
Permian/Delaware Basin:
Johnson Ranch/Brushy Draw...................... 13 3
Pecos Slope.................................... 79 68
--- ---
Totals.......................................... 952 453
=== ===
</TABLE>
Natural Gas and Oil Production
The following table shows the approximate net natural gas and oil
production attributable to the Company for the years ended December 31, 1996,
1997 and 1998.
YEAR ENDED DECEMBER 31,
1996 1997 1998
---- ---- ----
Natural gas (MMcf)............................. 3,404 6,583 24,455
Oil (MBbls).................................... 164 176 257
Natural gas equivalent (MMcfe)................. 4,388 7,639 25,997
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Item 3 - Legal Proceedings:
No legal proceedings are pending against the Company other than ordinary
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:
No matter was submitted during the fourth quarter of the fiscal year ended
December 31, 1998 to a vote of security holders.
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PART II
Item 5 - Market for Common Equity and Related Security Holder Matters:
The Company's Common Stock is quoted on the NASDAQ SmallCap Market under
the symbol GOTH. The following table sets forth the high and low bid quotations
on the NASDAQ SmallCap Market for the Company's Common Stock by calendar quarter
for the period January 1,1996 through March 12,1999.
Bid
-----------------------------
Calendar Quarter High Low
-------------------------- ------------ ------------
1997:
First Quarter $ 3-3/8 $ 2-3/16
Second Quarter $ 2-3/4 $1-11/16
Third Quarter $ 3-1/16 $ 1-3/4
Fourth Quarter $ 4 $ 2-1/2
1998:
First Quarter $ 3-1/16 $1-13/16
Second Quarter $ 2-3/8 $1-3/16/
Third Quarter $1-19/32 $ 9/16
Fourth Quarter $ 23/32 $ 7/32
1999:
First Quarter $ 25/32 $ 11/32
(through March 12)
The foregoing amounts, represent inter-dealer quotations without adjustment
for retail markups, markdowns or commissions and do not represent the prices of
actual transactions. On March 12,1999, the closing bid quotations for the
Common Stock, as reported on the NASDAQ SmallCap Market, was $ 19/32.
Because the Company's Common Stock has traded at a price below $1.00 per
share for more than 30 consecutive trade dates and because, by virtue of the
provision for impairment in the amount of $34.0 million in the carrying value at
September 30,1998 of its oil and natural gas properties, its net tangible assets
were less than $2.0 million at September 30,1998, the staff of the Nasdaq
SmallCap Market advised the Company on January 26,1999 that its securities would
be delisted from trading on that system. On February 1,1999, the Company
requested a hearing
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with respect to the staff's determination which hearing has been scheduled for
April 9,1999. There can be no assurance that the Company will be successful at
the hearing in having the staff's determination reversed. The Company expects
that if its securities are delisted from the Nasdaq SmallCap Market that such
securities will be quoted and traded in the over-the-counter market.
As of March 12,1999, the Company had 132 shareholders of record and
believes that it has in excess of 500 beneficial holders. The Company has never
paid a cash dividend on its Common Stock and management has no present intention
of commencing to pay dividends on its Common Stock. Under the terms of various
of the Company's loan documents, the Company is prohibited from paying cash
dividends on its Common Stock.
Item 6 - Management's Discussion and Analysis or Plan of Operation:
The discussion in this section of this Annual Report is intended to comply with
the so called "plain-English" rule adopted by the Commission relating to the
language used.
A Discussion of Our Results of Operations
General
Our results of operations have been significantly affected by the
acquisition of producing natural gas and oil properties over the last three
years as well as a re-capitalization we completed in April 1998. During 1998,
we completed the acquisition of a major amount of natural gas and oil assets
from Amoco Corporation for a purchase price of $240.8 million. Amoco also
received warrants to purchase 1.5 million shares of our common stock exercisable
at $3.00 per share, which we valued at $1.2 million, and the transfer of
certain producing properties having a value of less than $1.8 million. The
Amoco acquisition added approximately 240.0 Bcfe of proved reserves with a PV-10
of approximately $230.1 million to our reserves as of December 31,1997. During
1997, we completed seven acquisitions of producing natural gas and oil
properties for a purchase price of approximately $52.8 million. These
acquisitions added approximately 102.2 Bcfe to our reserves of natural gas and
oil. During 1996, we completed four acquisitions of producing oil and natural
gas properties for a purchase price of approximately $34.4 million which added
approximately 44.8 Bcfe to our reserves of oil and natural gas. The
acquisitions were financed primarily through bank and other borrowings and the
sale of equity securities.
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<PAGE>
The recapitalization we completed on April 27, 1998 involved the following:
. the transfer of all of our natural gas and oil properties to a wholly
owned subsidiary we organized named Gothic Production Corporation
. the sale of $235.0 million of 11 1/8% Senior Secured Notes due May 1,
2005 by Gothic Production secured by the natural gas and oil
properties we transferred to Gothic Production
. the sale by us for approximately $60.2 million of our 14 1/8% Senior
Secured Discount Notes due May 1, 2006 secured by our holdings of the
outstanding shares of Gothic Production
. the sale by us to Chesapeake Energy Corporation for approximately
$39.5 million of our shares of Series B Preferred Stock which had a
liquidation value of $50.0 million and ten-year warrants to purchase
for $0.01 per share 2,439,246 shares of our Common Stock
. the sale to Chesapeake for approximately $20.0 million of a 50%
interest in the natural gas and oil properties in the Arkoma Basin we
transferred to Gothic Production
. the execution by us of a participation agreement with Chesapeake
granting a 50% interest in the undeveloped acreage of Gothic
Production for $10.5 million
. the repayment or refinancing of substantially all of our debt and
preferred securities outstanding
The report of our independent accountants, PricewaterhouseCoopers LLP,
dated March 12, 1999, contains an additional paragraph wherein they point out
that we have suffered recurring losses from operations and we have a net capital
deficiency that raise substantial doubt about our ability to continue as a going
concern. Our financial statements have been prepared assuming we will continue
as a going concern. Our financial statements do not include any adjustments that
might result from the outcome of this uncertainty.
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<PAGE>
Our plans in regard to the matters referred by our independent accountants
include the following:
. Based upon the prices we have been receiving for natural gas and oil
since the beginning of 1999, we believe that in order to meet a
portion of the cash interest payments on our outstanding indebtedness
we will need to borrow under our bank credit facility.
. Our ability to borrow under our bank credit facility is dependent upon
our ability to be in continuing compliance with its terms.
. During 1998 we required waivers from the bank on three occasions with
respect to our compliance with a minimum interest coverage ratio
contained in the bank credit facility.
. We expect to need further waivers of this provision throughout 1999
and believe that such waivers by the bank will be forthcoming.
. On the basis of our belief as to the availability of these bank
waivers throughout 1999, we believe we will be able to meet all cash
interest payments we are required to make in 1999.
As we describe in more detail below, during the year ended December 31,
1998, we made a $76.0 million pre-tax provision for impairment of our natural
gas and oil properties because of the drop in natural gas and oil prices during
the last half of 1998. Further declines in prevailing prices subsequent to
December 31, 1998 may give rise to a further provision for impairment of our
properties.
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<PAGE>
Natural Gas and Oil Production, Revenue and Price History
The table below reflects certain of our summary operating data for the
periods presented:
1996 1997 1998
---------- ---------- ----------
Net Production:
Oil (Mbls) 164 176 257
Natural Gas (Mmcf) 3,404 6,583 24,455
Natural Gas Equivalent (Mmcfe) 4,388 7,639 25,997
Oil and Natural Gas Sales:
Oil $ 3,488 $ 3,551 $ 3,469
Natural Gas 6,897 13,867 47,245
---------- ---------- ----------
Total $ 10,385 $ 17,418 $ 50,714
========== ========== ==========
Average Sales Price:
Oil (Bbl) $ 21.27 $ 20.18 $ 13.50
Natural gas (Mcf) 2.03 2.11 1.93
Natural gas equivalent (Mcfe) 2.37 2.28 1.95
Expenses ($ per Mcfe):
Lease Operating (1) $ 0.85 $ 0.73 $ 0.38
General and Administrative 0.41 0.30 0.14
Depreciation, Depletion and
Amortization (2) 0.64 0.72 0.91
- --------------------
(1) These amounts include lease operating costs and production taxes and are
net of well operator overhead reimbursement which are billed to the owners
of the working interests and recorded as well operations revenue.
(2) These amounts represent depreciation, depletion and amortization of oil
and natural gas properties only.
-22-
<PAGE>
A Comparison of Operating Results For The Years Ended December 31, 1998 and
December 31, 1997
Our revenues were $53.0 million for the year 1998 as compared to $23.3
million for the year 1997. This represents a 127% increase in total revenue for
1998. Natural gas and oil sales for the year ended 1998 increased $33.3 million
to $50.7 million compared to $17.4 million in 1997, or an increase of 191%. Of
the 1998 revenues, $3.5 million was from oil sales and $47.2 million was from
natural gas sales. In 1997, we had $3.6 million from oil sales and $13.9
million from natural gas sales. The increase in our natural gas and oil sales
was primarily the result of a 271% increase in natural gas production and a 46%
increase in oil production for 1998 when compared to 1997. The increase in
volumes of oil and natural gas sold resulted primarily from the natural gas and
oil properties acquired from Amoco in January 1998 and from the acquisitions we
completed in 1997. Our oil sales in 1998 were based on the sale of 257,000
barrels at an average price of $13.50 per barrel as compared to 176,000 barrels
at an average price of $20.18 per barrel in 1997. Natural gas sales in 1998
were based on the sale of 24,455,000 mcf at an average price of $1.93 per mcf
compared to 6,583,000 mcf at an average price of $2.11 per mcf in 1997. Also
included in our 1997 revenues is $4.6 million from the gas gathering system,
processing plant and storage facility that we acquired in January 1997. These
assets, as well as gas processing and gathering system assets included with the
assets acquired from Amoco, were sold in January 1998 for $6.0 million.
We incurred lease operating expenses during 1998 of $12.1 million compared
with lease operating expenses of $6.9 million for 1997. Our lease operating
expenses include approximately $3.5 million and $1.3 million in production taxes
which we incurred from our share of production in 1998 and 1997, respectively.
This increase in lease operating expenses is primarily because of the 240%
increase in our natural gas and oil production (on an Mcfe basis) resulting
primarily from the acquisitions we completed. Our lease operating expenses as a
percentage of natural gas and oil sales decreased to 24% in 1998 as compared to
40% in 1997. Lease operating expenses per Mcfe decreased to $0.38 for 1998
compared to $0.73 in 1997. Both of these decreases we believe are due to our use
of telemetry and other more efficient means of operating our properties that we
acquired as part of our transaction with Amoco in early 1998.
Our depreciation, depletion and amortization expense was $24.0 million for
1998 as compared to $5.8 million for 1997. The increase was primarily the result
of the increased production associated with the acquisitions we completed.
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<PAGE>
Our general and administrative costs were $3.6 million for 1998 as compared
to $2.3 million for 1997. This increase was primarily the result of personnel we
added and other costs we incurred related to the Amoco acquisition and the
administrative costs incurred in operating the wells acquired. Although our
general and administrative costs increased $1.3 million during 1998, the costs
per Mcfe decreased from $0.30 in 1997 to $0.14 in 1998.
We account for our oil and gas exploration and development activities using
the full cost method of accounting prescribed by the Securities and Exchange
Commission. Accordingly, all our productive and non-productive costs incurred in
connection with the acquisition, exploration and development of natural gas and
oil reserves are capitalized and depleted using the units-of-production method
based on proved oil and gas reserves. We capitalize our costs including salaries
and related fringe benefits of employees directly engaged in the acquisition,
exploration and development of natural gas and oil properties, as well as other
directly identifiable general and administrative costs associated with these
activities. These costs do not include any costs related to production, general
corporate overhead, or similar activities. Our natural gas and oil reserves are
estimated annually by independent petroleum engineers. Our calculation of
depreciation, depletion and amortization ("DD&A") includes estimated future
expenditures that we believe we will incur in developing our proved reserves and
the estimated dismantelment and abandonment costs, net of salvage values. In the
event the unamortized cost of the natural gas and oil properties we are
amortizing exceeds the full cost ceiling as defined by the Commission, we charge
the amount of the excess to expense in the period during which the excess
occurs. The full cost ceiling is based principally on the estimated future
discounted net cash flows from our natural gas and oil properties. Changes in
our estimates or declines in prevailing natural gas and oil prices could cause
us to reduce in the near term our carrying value of our natural gas and oil
properties. A write-down arising out of these conditions is referred to
throughout our industry as a full cost ceiling write-down.
During the year ended December 31, 1998, we made a $76.0 million pre-tax
provision for impairment of our natural gas and oil properties because of the
drop in natural gas and oil prices during the last half of 1998. Our full cost
ceiling at December 31, 1998 was based on natural gas prices received at the
time of $1.81 per Mcf and oil prices received of $10.50 per Bbl. This provision
resulted from a full cost ceiling write-down. The write-down is shown in our
balance sheet as a reduction of the cost of natural gas and oil properties.
Subsequent to December 31, 1998, there was a further decline in natural gas
prices. At March 1, 1999, the natural gas price
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<PAGE>
which we received declined to approximately $1.40 per Mcf. If we had used the
March 1, 1998 prices in this evaluation, we would have made an additional
provision of approximately $60.0 million. Based on rules promulgated by the
Securities and Exchange Comission, we evaluate any impairment of our natural gas
and oil properties, based on prevailing prices as of the end of each quarter.
The actual amount of any additional impairment resulting from further declines
in prevailing prices will not be determined until the end of the first quarter
of 1999.
We evaluate natural gas and oil reserve acquisition opportunities in light
of many factors only a portion of which may be reflected in the amount of proved
natural gas and oil reserves that we propose to acquire. In determining the
purchase price to be offered, we do not solely rely on proved oil and gas
reserves or the value of such reserves determined in accordance with Rule 4-10
of Regulation S-X adopted by the Commission. Factors we consider include the
probable reserves of the interests intended to be acquired, anticipated
efficiencies and cost reductions that we believe can be made in us operating the
producing properties, the additional reserves that we believe can be proven
relatively inexpensively based on our knowledge of the area where the interests
are located and existing producing properties we own. We may also consider other
factors if appropriate. We may conclude that an acquisition is favorable even if
there may be a full cost ceiling write-down associated with it based on other
factors we believe are important. We do not perform a ceiling test for specific
properties acquired because the ceiling test is performed at each quarter and at
year end for all of our properties included in our cost center and is based on
prices for oil and gas as of that date which may be higher or lower than the
prices used when evaluating potential acquisitions. We review the transaction in
the light of proved and probable reserves, historic and seasonal fluctuations in
the prices of natural gas and oil, anticipated future prices for natural gas and
oil, the factors described above as well as other factors that may relate to the
specific properties under review.
Our interest and debt issuance costs were $35.4 million for 1998 as
compared to $8.8 million for 1997. This increase was primarily because of
interest on our 11 1/8% Senior Secured Notes which were issued in April 1998 by
Gothic Production, interest on our 14-1/8% Senior Secured Discount Notes which
we issued in April 1998, and amortization of the costs incurred to complete the
sale of these notes and amendments to our bank credit facility. We incurred
interest costs of $5.4 million with our bank, $4.2 million related to our 12
1/4% Senior Notes, which were refinanced on April 27, 1998, $17.7 million
related to our 11 1/8% Senior Secured Notes, $6.0 million related to our 14 1/8%
Senior Secured Discount Notes, $2.0 million as amortization of loan costs and
$106,000 with other parties.
We recorded an extraordinary loss on the early extinguishment of debt in
the amount of $31.5 million during 1998 compared to a similar charge of $907,000
in 1997. The 1998 amount reflects the payment of $20.8 million in consent fees,
$6.3 million in the write-off of unamortized discount and debt issuance costs
and $4.4 million in unamortized bank loan costs.
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<PAGE>
We obtained consents to the amendment of the terms of our 12 1/4% Senior Notes
in early 1998 prior to repaying the notes and also prepaid our bank credit
facility in April 1998.
We also recognized $10.7 million in preferred dividends and amortization
of preferred discount on our Series A and Series B Convertible Preferred Stock
during 1998, compared to the payment of $264,000 in preferred dividends in 1997.
Our shares of preferred stock on which we paid dividends in 1997 were all
converted into Common Stock by the end of 1997. The preferred dividends paid in
1998 included a 14% annual dividend rate for three months on the Series A
Preferred Stock and a 12 % annual dividend rate for approximately eight months
on the Series B Preferred Stock. We had preferred dividends and amortization of
preferred discount in 1998 of which $3.9 million was the write-off of discount
costs which resulted from the redemption of the Series A Preferred Stock in
April 1998. Also, $1.2 million relates to eight months of amortization of the
discount resulting from the sale of the Series B Preferred Stock and the related
warrants.
Our profitability and revenues are dependent, to a significant extent, upon
prevailing spot market prices for natural gas and oil. In the past, natural gas
and oil prices and markets have been volatile. Prices are subject to wide
fluctuations in response to changes in supply of and demand for natural gas and
oil, market uncertainty and a variety of additional factors that are beyond our
control. Such factors include political conditions, weather conditions,
government regulations, the price and availability of alternative fuels and
overall economic conditions. Natural gas prices have fluctuated significantly
over the past twelve months.
We use the sales method for recording natural gas sales. Our oil and
condensate production is sold, title passed, and revenue recognized at or near
our wells under short-term purchase contracts at prevailing prices in accordance
with arrangements which are customary in our industry. Sales of gas applicable
to our interest in producing natural gas and oil wells are recorded as revenues
when the gas is metered and title transferred pursuant to the gas sales
contracts covering our interest in gas reserves. During such times as our sales
of gas exceed our pro rata ownership in a well, such sales are recorded as
revenues unless total sales from the well have exceeded our share of estimated
total gas reserves underlying the property at which time the excess is recorded
as a gas balancing liability. Such imbalances are incurred from time to time in
the ordinary course of our business in the operation of our gas wells as a
consequence of operational factors.
At December 31, 1998, we had a gas balancing asset of $1.6 million and a
gas balancing liability of $3.9 million. The balances that existed at December
31, 1998, except for possible immaterial amounts, were not the result of
producing operations we conducted but related to the assets we acquired. It is
not our policy to operate wells in such a manner that imbalances are created. We
expect that the imbalances that existed at December 31, 1998 will be settled
upon
-26-
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abandonment of the wells or will be reflected in the price if the respective
well interest is sold prior to then.
Matters Relating to Our Liquidity and Capital Resources
General
Since 1994, our principal sources of cash have been bank borrowings, the
sale of equity and debt securities and cash flow from operations. The following
reflects our comparative cash flows for the years ended December 31, 1997 and
1998:
Year Ended December 31,
-----------------------------
1997 1998
------------ ------------
(in thousands)
-----------------------------
Net cash provided by operating activities $ 7,069 $ 11,567
Net cash used in investing activities 86,168 191,375
Net cash provided by financing activities 95,614 165,375
Our net cash provided by operations increased to $11.6 million for 1998 as
compared to net cash provided of $7.1 million for 1997. The improved operating
cash flows for 1998 relate primarily to the significant increase in income from
operations before non-cash charges resulting from the Amoco acquisition and the
acquisitions completed in 1997, partially offset by the interest costs and
changes in working capital.
We used $191.4 million of net cash in investing activities for 1998
compared to net cash used of $86.2 million in 1997. This increase was primarily
because of the cash paid of $217.0 million to complete the Amoco acquisition
and well enhancement costs of approximately $18.4 million. These were partially
offset by proceeds of $20.0 million received from the sale of half of our
interest in the Arkoma Basin to Chesapeake, $10.5 million received from
Chesapeake for the right to participate in up to 50% of substantially all of our
undeveloped acreage, $6.0 million received from Chesapeake from the sale of
interests in certain natural gas and oil properties, $6.0 million received from
the sale of our gas gathering and processing system and $1.5 million received
from the sale of interests in other natural gas and oil properties during 1998.
Our net cash provided by financing activities for 1998 was $165.4 million
compared to $95.6 million provided in 1997. The 1998 amount includes proceeds
from short and long-term debt related to the Amoco acquisition and the
subsequent recapitalization of $431.3 million and proceeds from the issuance of
our Series A and Series B Preferred Stock of $73.5 million,
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partially offset by the redemption of the Series A Preferred Stock and accrued
dividends for $40.8 million, payment of $38.5 million in 12 1/4% Senior Notes
consent fees and other bank and offering fees and payments of short and long-
term debt of $259.9 million.
How We Have Financed Our Acquisitions
We have had a series of credit facilities in existence with Bank One,
Texas, N.A. commencing in January 1996. Borrowings under these credit facilities
were used to finance the payment of all or a substantial portion of the purchase
price for the acquisitions of natural gas and oil properties we acquired since
early 1996. The proceeds from the sale of equity securities financed
substantially all of the balance. At present, the credit facility, with Gothic
Production as the borrower and the parent corporation as the guarantor, permits
borrowings from time to time in the amount of up to $20.1 million. Interest on
borrowings is payable monthly at the bank's base rate, as determined from time
to time. All outstanding borrowings are due on April 30, 2001, the maturity
date, when the credit facility ends. Borrowings under the credit facility are
secured by a senior lien on the natural gas and oil assets owned by Gothic
Production. As of December 31, 1998, no borrowings were outstanding under this
credit facility.
In September 1997, we sold our 12 1/4% Senior Notes for $100.0 million. The
net proceeds were used to complete the acquisition of natural gas and oil
properties and repay outstanding indebtedness, including $48.0 million
outstanding under a credit facility at the time.
The long-term financing to fund the repayment of bank and other acquisition
financing incurred to complete our acquisition of the natural gas and oil
properties from Amoco in January 1998 was obtained in a recapitalization we
completed on April 27, 1998 and which we have described above. The
recapitalization, included the sale of the 11 1/8% Senior Secured Notes of
Gothic Production, the 14 1/8% Senior Secured Discount Notes by the parent
corporation, the sale of the Series B Preferred Stock and the sale of certain
assets and participation rights in assets. We realized a total of $354.7 million
from these transactions. We used these funds as follows:
. to repay in full our outstanding bank indebtedness of $206.4 million
which had been incurred to fund the acquisition of the Amoco assets,
. to prepay our outstanding 12 1/4% Senior Notes which we issued in
September 1997 and interest in the total amount of $102.3 million,
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. to redeem for $38.7 million our outstanding Series A Preferred Stock
we issued in January 1998 to provide interim financing to complete the
acquisition of the Amoco assets, and
. to pay fees and expenses relating to the recapitalization of
approximately $4.2 million.
Our bank credit facility and outstanding notes contain numerous affirmative
and negative covenants. We must be in compliance with the bank credit facility
in order to borrow funds. In addition, the breach of certain covenants could
cause our outstanding indebtedness to the bank to become immediately due and
payable. We are also required to be in compliance with the affirmative and
negative covenants under our outstanding notes. If we fail to remain in
compliance with these covenants under our notes the indebtedness may become
immediately due and payable. If either our bank indebtedness or outstanding
notes should become immediately due and payable, under the cross-default terms
of these debt instruments, the other outstanding indebtedness would become
immediately due and payable. This could result in an aggregate of $301.2
million of indebtedness being immediately due and payable.
On three occasions in 1998 - June 30, September 30 and December 31, 1998 -
we were not in compliance with one of the covenants in our bank credit facility.
This covenant requires us to have at the end of each quarter a minimum interest
coverage ratio of 1.5 to 1.0. On each occasion, we received a waiver from the
bank. However, without the waiver we would have been unable to borrow funds
under the credit facility and had any borrowings been outstanding, the bank had
the right to demand immediate payment. Commencing March 31, 1999, the interest
coverage ratio increases to 2.0 to 1.0. We anticipate requiring another waiver
from the bank with respect to compliance with this covenant throughout 1999.
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Future Capital Requirements and Resources
Our capital requirements relate to the acquisition, exploration,
enhancement, development and operation of natural gas and oil properties. In
general, because our natural gas and oil reserves are depleted by production
over time, the success of our business strategy is dependent upon a continuous
acquisition, exploitation, enhancement, and development program. In order to
achieve profitability and generate cash flow, we are dependent upon acquiring or
developing additional natural gas and oil properties or entering into joint
natural gas and oil well development arrangements. At year end, we had no
borrowings outstanding under our credit facility. However, we currently have
$1.5 million outstanding. Under our bank credit facility, we have a current
borrowing availability of $20.1 million.
The Effect on Us of Changes in Prices and Inflation
Our revenues and the value of our natural gas and oil properties are
affected by changes in the prevailing prices for natural gas and oil. Natural
gas and oil prices are subject to seasonal and other fluctuations that are
beyond our control and ability to predict.
From time to time, we hedge the natural gas prices we receive through the
use of commodity swap agreements in an effort to reduce the effects of the
volatility of the price of natural gas and crude oil on our operations. These
agreements involve the receipt of fixed-price amounts in exchange for variable
payments based on NYMEX prices and specific volumes. In connection with these
commodity swap agreements, we may also enter into basis swap agreements to
reduce the effects of unusual fluctuations between prices actually received at
the well head and NYMEX prices. Through the use of commodity price and basis
swap agreements, we can fix the price we receive for specified amounts of
production to the commodity swap price less the basis swap price. The
differential to be paid or received, under the swap agreement, is accrued in the
month of the related production and recognized as a component of natural gas and
crude oil sales. We do not acquire, hold or issue financial instruments for
trading purposes.
While the use of hedging arrangements limits our downside risk on downward
price movements, it may also limit our future gains from upward movements. All
hedging is accomplished under agreements based upon industry standard forms. We
address market risk by selecting instruments whose value fluctuations correlate
strongly with the underlying commodity being hedged. We have not been required
to provide collateral relating to our hedging activities.
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Although certain of our costs and expenses are affected by the level of
inflation, inflation has not had a significant effect on our results of
operations during 1998.
Year 2000 Computer Issues
The Year 2000 computer issue is the result of computer programs being
written to use two digits to define year dates. Computer programs running date-
sensitive software may recognize a date using "00" as the year 1900 rather than
the year 2000. This could result in systems failure or miscalculations causing
disruptions of operations.
We initiated a comprehensive assessment of our information technology and
non-information technology systems to ensure that our systems either will be
unaffected by the year 2000 issue or will be upgraded to enable compliance with
Year 2000 standards. In general, our information technology computer systems
consist of our office computer network and financial management software. Our
other computer systems, which are non-information technology, consist of certain
office equipment and other systems associated with our natural gas and oil
properties. We are also evaluating the Year 2000 compliance by our customers and
suppliers to ascertain the potential impact on us of the extent of our customers
and suppliers compliance with Year 2000 issues.
We began an in-house assessment of our year 2000 problem with respect to
our information technology systems in mid 1997. Since that time, we have
upgraded all of our financial management software to newer versions which are
Year 2000 compliant. In addition, we have replaced nearly all of our information
technology hardware so that this hardware is now Year 2000 compliant. To date
the cost of the upgrade and of this software and hardware has been approximately
$60,000.
Additionally, we have assessed our non-information technology systems which
consist primarily of embedded technology at our Watonga, Oklahoma field office
and the production telemetry equipment used on our operated wellsites. We
believe that our non-information technology systems will be Year 2000 compliant
by June 1999 without any material costs.
We are conducting an assessment of Year 2000 exposures related to our
suppliers and customers. We have identified our key customers and suppliers and
have requested information as to the Year 2000 compliance of such customers.
Although no contingency plans have been developed to date, we will begin to
formulate such plans as we ascertain the preparedness of our customers and
suppliers.
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We anticipate that all of our internal systems and equipment will be Year
2000 compliant by the end of the second quarter of 1999. We believe that the
total costs associated with modifying our existing systems will not have a
material adverse effect on our results of operations or financial condition.
Nonetheless, if all Year 2000 issues are not adequately assessed or if the
necessary remedial efforts are not implemented on a timely basis, we may not be
Year 2000 compliant which, in turn, could have a material adverse effect on our
business, operating results or financial condition. In addition, our operations
may be disrupted in the event our suppliers or service providers are not Year
2000 compliant and such failure could have a material adverse effect on our
business, operating results or financial condition.
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the Private
Securities Litigation Reform Act of 1995
With the exception of historical matters, the matters we have discussed
above and elsewhere in this Annual Report are "forward-looking statements" as
defined under the Securities Exchange Act of 1934, as amended, that involve
risks and uncertainties. The forward-looking statements we discuss in this
Annual Report appear in various places including under the headings: (i) "A
Discussion of Our Results of Operations -- General" as to our ability to borrow
under our bank credit facility throughout 1999 and our ability to obtain waivers
from the bank, (ii) "A Comparison of Operating Results For The Year Ended
December 31, 1998 and December 31, 1997" relating to our dependence for profits
and revenues on prevailing spot market prices for oil and gas, (iii) "Changes in
Prices and Inflation" as to the impact of inflation on us, and (iv) "Matters
Relating to Our Liquidity and Capital Resources" as to our capital requirements,
business strategy, our ability to continue as a going concern, ability to attain
and maintain profitability and cash flow, dependence upon the acquisition of and
ability to acquire additional oil and gas properties or entering into joint oil
and gas well development arrangements, access to debt and equity capital and
availability of joint venture development arrangements, estimates as to our
needs for additional capital and the times at which additional capital will be
required, expectations as to our sources for this capital and funds, our ability
to successfully implement our business strategy, ability to identify and
integrate successfully any additional producing oil and gas properties we
acquire and whether such properties can be operated profitably, ability to
maintain compliance with covenants of our various loan documents and other
agreements pursuant to which we have issued securities and obtain waivers when
and as required, our ability to borrow funds or maintain levels of borrowing
availability under our credit arrangements, statements about Proved Reserves or
borrowing availability based on Proved Reserves and future net cash flows and
their present value.
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We want to caution readers that the risk factors described below, as well
as those described elsewhere in this Annual Report, or in our other filings with
the Commission, in some cases have affected, and in the future could affect, our
actual results and could cause our actual consolidated results during 1999 and
beyond, to differ materially from those expressed in any forward-looking
statements made by or on our behalf.
Substantial Indebtedness
At December 31, 1998, we had $301.2 million of long-term indebtedness as
compared to a negative stockholders' equity of $83.9 million. This level of
indebtedness may pose substantial risks to us and the holders of our securities.
These risks would include the possibility that we may not generate sufficient
cash flow to pay the principal of and interest on our indebtedness and the risk
of default thereunder. Our historical earnings were insufficient to cover our
fixed charges, including preferred dividends, by $108.9 million and $3.9 million
for 1998 and 1997. If we are unsuccessful in increasing our proved reserves or
realizing production from our proved undeveloped reserves, our future net
revenue from existing proved reserves may not be sufficient to pay the principal
of and interest on our indebtedness in accordance with their terms. Our levels
of indebtedness may also adversely affect our ability to incur additional
indebtedness and finance our future operations and capital needs, and may limit
our ability to pursue other business opportunities. The agreements under which
our indebtedness is outstanding contain financial and other restrictive
covenants which could limit our operating and financial flexibility and, if
violated, would result in an event of default which could preclude our access to
credit under our bank credit facility or otherwise have a material adverse
effect on us. A default under our bank credit facility or other loan documents
could lead to a foreclosure against the assets that collateralize such
indebtedness. In addition, the terms of our indebtedness contain provisions
whereby a default under one loan agreement may also constitute a default under
other indebtedness. If we should default under the terms of one loan agreement
such default could also constitute an event of default under other indebtedness
which could result in all of such indebtedness becoming immediately due and
payable. There are currently no defaults under any of our outstanding
indebtedness. We were not in compliance with the minimum interest coverage ratio
of 1.5 to 1.0 as of June 30, 1998, September 30, 1998 and December 31, 1998. On
each occasion, we received a waiver from the bank relating to compliance with
that ratio. Commencing March 31, 1999, this interest coverage ratio increases to
2.0 to 1.0. We anticipate requiring further waivers from the bank throughout
1999 with respect to our compliance with this covenant.
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Auditors Report; Uncertainty as to Going Concern; Financial Statement
Presentation
The report of our independent accountants, PricewaterhouseCoopers LLP,
dated March 12, 1999, contains an additional paragraph wherein they point out
that we have suffered recurring losses from operations and we have a net capital
deficiency. The report states that these matters raise substantial doubt about
our ability to continue as a going concern. Our financial statements have been
prepared assuming we will continue as a going concern. Our financial statements
do not include any adjustments that would be necessary if we were not to
continue as a going concern.
Our ability to continue as a going concern makes us substantially dependent
on our ability to meet our obligations to pay interest on our outstanding
indebtedness. Because of depressed market prices for natural gas and oil,
during 1999 management intends to use borrowings under its credit facility to
meet a portion of our cash interest payments. If we are unable to obtain
waivers from the bank as to compliance with the minimum interest coverage ratio
described above under "Substantial Indebtedness" or possibly other covenants in
our credit facility we would be unable to borrow funds under the credit
facility. Our inability to borrow funds under our credit facility could cause
us to be unable to pay interest on our other outstanding indebtedness. A failure
to pay interest on our other outstanding indebtedness would be a default causing
all of that indebtedness to be immediately due and payable. Under cross-default
provisions under our existing agreements relating to our indebtedness, a default
under one loan is likely to result in a default under all our loans. This would
make all our indebtedness immediately due and payable. We expect to be able to
obtain the necessary waivers from the bank throughout 1999 and be able to borrow
the necessary funds that may be required to meet our interest payments.
Volatility of Natural Gas and Oil Prices; Full Cost Write Down
Our revenues, profitability, cash flow, ability to service debt and future
growth will be substantially dependent on prevailing prices for natural gas and
oil. The amounts of and prices obtainable for our natural gas and oil
production will be affected by market factors beyond our control. These include
the extent of domestic production, the level of imports of foreign natural gas
and oil, the general level of market demand on a regional, national and
worldwide basis, domestic and foreign economic conditions that determine levels
of industrial production, political events in foreign oil producing regions, and
variations in governmental regulations and tax laws or the imposition of new
governmental requirements upon the natural gas and oil industry, among other
factors. Prices for natural gas and oil are subject to worldwide fluctuation in
response to relatively minor changes in supply of and demand for natural gas and
oil, market
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uncertainty and a variety of additional factors that are beyond our control. Any
significant decline in natural gas and oil prices would have a material adverse
effect on us, including our inability to fund planned operations and capital
expenditures, write downs of the carrying value of our natural gas and oil
properties, and our inability to meet debt service requirements resulting in
defaults under bank loans and other indebtedness. In addition, the marketability
of our natural gas and oil production will depend in part upon the availability,
proximity and capacity of gathering systems, pipelines and processing
facilities.
The declines in natural gas and oil prices since mid-1998 have adversely
affected our cash flows from operations. On December 31, 1998, the prices of
natural gas and oil we received and upon which our reserves were determined had
decreased to $1.81 per mcf and $10.50 per barrel, resulting in a full cost
ceiling write-down of $76.0 million for the year ended December 31, 1998.
Subsequent to December 31, 1998, the natural gas industry experienced a further
decline in natural gas prices. At March 1, 1999 the natural gas price which we
received fell to approximately $1.40 per Mcf. If we had used the March 1, 1999
prices in this evaluation, we would have made an additional provision of
approximately $60.0 million. Based on rules promulgated by the SEC, we evaluate
any impairment of our natural gas and oil properties based on prevailing prices
as of the end of each quarter. The actual amount of any additional impairment
resulting from this further decline in prevailing prices, will not be
determinable until the end of the first quarter of 1999.
Restrictions Imposed by Lenders
The instruments governing our indebtedness impose significant operating and
financial restrictions on us. Such restrictions will affect, and in many
respects significantly limit or prohibit, among other things, our ability to
incur additional indebtedness, pay dividends, repay indebtedness prior to its
stated maturity, sell assets or engage in mergers or acquisitions. These
restrictions could also limit our ability to effect future financings, make
needed capital expenditures, withstand a future downturn in our business or the
economy in general, or otherwise conduct necessary corporate activities. Our
failure to comply with these restrictions could lead to a default under the
terms of such indebtedness. In the event of default, the holders of such
indebtedness could elect to declare all of those funds borrowed to be due and
payable together with accrued and unpaid interest. In such event, there can be
no assurance that we would be able to make such payments or borrow sufficient
funds from alternative sources to make any such payment. If our wholly owned
operating subsidiary, Gothic Production Corporation ("GPC") were unable to repay
all amounts declared due and payable under its bank credit facility or its
Senior Secured Notes, the lenders could proceed against the collateral granted
by GPC to satisfy the indebtedness and other obligations due and payable. If
the bank credit
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facility indebtedness or the Senior Secured Notes of GPC were to be accelerated
to become immediately due and payable, there can be no assurance that the assets
of GPC would be sufficient to repay in full such indebtedness and our other
indebtedness. Even if additional financing could be obtained, there can be no
assurance that it would be on terms that are favorable or acceptable to us. In
addition, the obligations under the bank credit facility and GPC's Senior
Secured Notes are secured by substantially all of the assets of GPC. The pledge
of such collateral to existing lenders could impair our ability to obtain
favorable financing from other sources.
Ability to Manage Growth
Although individual members of our management have significant experience
in the natural gas and oil industry, we have been engaged in the natural gas and
oil business for less than four years and have a limited operating history upon
which investors may base their evaluation of our performance. As a result of our
brief operating history and rapid growth, our operating results from historical
periods are not readily comparable and, as a consequence of the Amoco
acquisition, are not expected to be indicative of future results. There can be
no assurance that we will continue to experience growth in, or maintain our
current level of, revenues, natural gas and oil reserves or production. Our
natural gas and oil operations to date have focused on the acquisition of
producing natural gas and oil properties. Our business plan and reserve reports
include the drilling of approximately 30 to 40 development wells during 1999 at
an estimated cost of between $16.0 million and $18.0 million.
The Amoco acquisition and any future growth of our natural gas and oil
reserves, production and operations will place significant demands on our
operational, administrative and financial resources, and the increased scope of
operations will present challenges to us due to increased management time and
resources required. Our future performance and profitability will depend in part
on our ability to successfully integrate the operational, financial and
administrative functions of acquired properties into our operations, to hire
additional personnel and to implement necessary enhancements to our management
systems to respond to changes in our business. There can be no assurance that we
will be successful in these efforts. Our inability to integrate acquired
properties, to hire additional personnel or to enhance our management systems
could have a material adverse effect on our results of operations.
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Limitation on the Payment of Funds to us by GPC
Our cash flow, and consequently our ability to pay dividends and to service
our debt, is dependent upon the cash flows of GPC and the payment of funds by
GPC to us, as its parent corporation, in the form of loans, dividends, or
otherwise. The terms of our outstanding indebtedness impose, and agreements
entered into in the future may impose, significant restrictions on the payment
of dividends and the making of loans by GPC to us. Under the terms of our
outstanding indebtedness, subject to certain restrictions, GPC is permitted to
pay dividends to us equal to the semi-annual interest payments due on our
Discount Notes; provided that upon a notice of default or event of default under
the terms of our outstanding indebtedness, GPC will be prohibited from paying
such dividends until the date such default or event of default is cured or
waived. Accordingly, in such an event, repayment of the Discount Notes may
depend upon our ability to effect an offering of capital stock or to refinance
the Discount Notes. A default under the Discount Notes or any other outstanding
indebtedness would have a material adverse effect on holders of our common
stock.
Risk of Hedging Activities
In an attempt to reduce our sensitivity to energy price volatility, we use
swap arrangements that generally result in a fixed price for sales of its
natural gas and oil production over periods of up to 12 months. If our reserves
are not produced at rates equivalent to the hedged position, we would be
required to satisfy our obligations under hedging contracts on potentially
unfavorable terms without the ability to hedge that risk through sales of
comparable quantities of our own production. Hedging contracts limit the
benefits we will realize if actual prices rise above the contract prices. In
addition, hedging contracts are subject to the risk that the other party may
prove unable or unwilling to perform its obligations under such contracts. Any
significant non-performance could have a material adverse financial effect on
us. These arrangements provide for us to exchange a floating market price for a
fixed contract price. Payments are made by us when the floating price exceeds
the fixed price for a contract month and payments are received when the fixed
price exceeds the floating price. Settlements on these swaps are based on the
difference between the approximate average closing NYMEX price for a contract
month and the fixed contract price for the same month.
We were required under the terms of our credit facility in effect prior to
our recapitalization in April 1998 to enter into hedging agreements covering a
portion of our natural gas production. Because of this hedging activity, our
financial risk resulting from possible declines in the price of natural gas was
reduced; however, our ability to benefit from increases in
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the price of natural gas was limited. While we are no longer required under the
terms of our bank loan agreement to maintain any minimum amounts of hedging
agreements, we expect we will continue to enter into such agreements in the
future. Any reduction in our hedging activity will subject us to more
significant fluctuations in production revenues resulting from price volatility.
During 1998, we had swap agreements relating to the sale of 5,000 Mcf per
day at a price of $2.55 per Mcf and 15,000 Mcf per day at a price of $2.45 per
Mcf during the period January 1, 1998 through March 31, 1998. In February 1998,
we entered into swap agreements relating to the sale of 62,000 Mcf per day
during the period April 1, 1998 through October 31,1998 at an average price of
$2.09 per Mcf. Swap agreements relating to 7,000 Mcf per day were cancelled in
June 1998. Of the remaining 55,000 Mcf per day, 25,000 Mcf per day was subject
to a "call spread" agreement which provided that we receive additional payments
if the actual sales price of natural gas is between $2.30 and $2.70 per Mcf
during the period. The swap agreements for the period April through October 1998
covered approximately 80% of our natural gas production. In addition, we entered
into a swap agreement relating to the sale of 60,000 Mcf per day at a "floor"
price of $2.10 per Mcf during the period November 1998 through January 1999, and
we entered into a swap agreement for the month of December 1998 relating to the
sale of 40,000 MMBTU per day at a price of $2.345 per MMBTU.
In March 1999, we entered into a hedge agreement in the form of a collar
with respect to the production of 50,000 MMBTU of natural gas per day during the
period of April through October 1999. The collar places a floor of $1.65 per
MMBTU and a ceiling of $2.16 per MMBTU for the effective price we receive for
natural gas. If the NYMEX price of natural gas should fall below $1.65 per MMBTU
during the term of the collar agreement, we will be paid the difference by the
other party to the agreement on account of gas we sell below $1.65 per MMBTU. If
the NYMEX price of natural gas should rise above $2.16 per MMBTU during the term
of the collar agreement, we must pay the difference to the other party to the
agreement on account of gas we sell above $2.16 per MMBTU. For its risk assumed,
we have agreed to pay the other party to the agreement $0.05 per MMBTU per day
over the term of the agreement, payable monthly.
Need to Replace Reserves
Our success is substantially dependent on our ability to replace and expand
our natural gas and oil reserves through the acquisition of producing properties
and the exploitation and development of our properties. These activities involve
substantial risk. Without successful acquisition or drilling ventures, we will
be unable to replace the reserves being depleted by production, and our assets
and revenues, including the reserves, will decline. Our strategy includes
increasing our reserve base through continued exploitation of our existing
properties, exploration of new and existing properties and acquisitions of
producing properties. There can
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be no assurance that our acquisition and development activities will result in
the replacement of, or additions to, our reserves. Similarly, there can be no
assurance that we will have sufficient capital to engage in our acquisition or
development activities. Successful acquisition of producing properties generally
requires accurate assessments of recoverable reserves, future natural gas and
oil prices, operating costs, potential environmental and other liabilities and
other factors. Such assessments are necessarily inexact, and as estimates their
accuracy is inherently uncertain.
Acquisition Risks
Our rapid growth since we commenced natural gas and oil operations has been
largely the result of acquisitions of producing properties. We expect to
continue to evaluate and pursue acquisition opportunities available on terms our
management considers favorable. The successful acquisition of producing
properties requires an assessment of recoverable reserves, future natural gas
and oil prices, operating costs, potential environmental and other liabilities
and other factors beyond our control. This assessment is necessarily inexact
and its accuracy is inherently uncertain. In connection with such an
assessment, we perform a review of the subject properties we believe to be
generally consistent with industry practices. This review, however, will not
reveal all existing or potential problems, nor will it permit a buyer to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not be performed on every well, and structural and
environmental problems are not necessarily observable even when an inspection is
undertaken. We generally assume pre-closing liabilities, including
environmental liabilities, and generally acquire interests in the properties on
an "as is" basis. With respect to our acquisitions to date, we have no material
commitments for capital expenditures to comply with existing environmental
requirements. There can be no assurance that our acquisitions will be
successful. Any unsuccessful acquisition could have a material adverse effect
on us.
Drilling and Operating Risks
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells we drill will be productive or that we will recover all
or any portion of our investment. Drilling for natural gas and oil may involve
unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating
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and other costs. The cost of drilling, completing and operating wells is often
uncertain. Our drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, many of which are beyond our control. These include
economic conditions, mechanical problems, title problems, weather conditions,
compliance with governmental requirements and shortages or delays of equipment
and services. Our future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on our future
results of operations or financial condition.
In addition to the substantial risk that wells drilled will not be
productive, hazards such as unusual or unexpected geologic formations,
pressures, downhole fires, mechanical failures, blowouts, cratering, explosions,
uncontrollable flows of natural gas, oil or well fluids, pollution and other
physical and environmental risks are inherent in natural gas and oil exploration
and production. These hazards could result in substantial losses to us due to
injury and loss of life, severe damage to and destruction of property and
equipment, pollution and other environmental damage and suspension of
operations. As a protection against operating hazards, we maintain insurance
coverage against some, but not all, potential losses, as is common in the
natural gas and oil industry. We do not fully insure against all risks
associated with our business either because such insurance is not available or
because the cost thereof is considered prohibitive. The occurrence of an event
that is not covered, or not fully covered, by insurance could have a material
adverse effect on our financial condition and results of operations.
Uncertainty of Estimates of Reserves and Future Net Revenues; Significant
Undeveloped Reserves
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond our control. Information as to
our reserves represents estimates based on reports prepared by our independent
petroleum engineers, as well as internally generated reports. Petroleum
engineering is not an exact science. Information relating to proved natural gas
and oil reserves is based upon engineering estimates derived after analysis of
information we furnished or the operator of the property furnished. Estimates of
economically recoverable natural gas and oil reserves and of future net cash
flows necessarily depend upon a number of variable factors and assumptions.
These include historical production from the area compared with production from
other producing areas, the assumed effects of regulations by governmental
agencies and assumptions concerning future natural gas and oil prices, future
operating costs, severance and excise taxes, capital expenditures and workover
and remedial costs. All of these may in fact vary considerably from actual
results. Natural gas and oil prices, which fluctuate over time, may also affect
proved reserve estimates. For these reasons, estimates of the economically
recoverable quantities of natural gas and oil attributable to any particular
group of properties, classifications of such reserves based on risk of recovery
and estimates of
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<PAGE>
the future net cash flows expected from the properties which are prepared by
different engineers or by the same engineers at different times may vary
substantially. Actual production, revenues and expenditures with respect to our
reserves will likely vary from estimates, and such variances may be material.
Approximately 10% of our estimated PV-10 of proved reserves as of December 31,
1998 are classified as undeveloped. Either changes in estimates of proved
undeveloped reserves or the inability to fund development could result in
substantially reduced reserves. In addition, the timing of receipt of estimated
future net revenues from proved undeveloped reserves will be dependent upon the
timing and implementation of drilling and development activities estimated by us
for purposes of the reserve report.
Future Capital Requirements
We have made, and will continue to make, substantial capital expenditures
for the acquisition, development and production of natural gas and oil reserves,
particularly since a portion of our proved reserves consists of proved
undeveloped reserves which require significant capital expenditures to develop.
We have budgeted capital expenditures of approximately $16.0 to $18.0 million
for the year ending December 31, 1999. We are not contractually committed to
expend these funds. We currently expect that available cash, cash flows from
operations, proceeds from the private or public sale of debt or equity
securities, borrowings under the bank credit facility, and sales of certain
natural gas and oil properties will be sufficient to fund our debt service
requirements and planned capital expenditures for our existing properties
through 1999. However, we may need to raise additional capital to fund
acquisitions and the development of properties acquired, which capital may not
be available to us.
Under the terms of our transaction with Chesapeake entered into in April
1998, both Chesapeake and we are permitted to designate acreage for development
drilling by giving written notice to the other party. In order for us to
participate in any drilling proposals submitted by Chesapeake in the acreage
which is the subject of our participation agreement, we will need to have
available sufficient funds or borrowing availability to participate in the
proposed drilling activity. Certain terms of the participation agreement limit
the number of wells to be proposed by either party to the amount that would
require capital expenditures by us of $15.0 million in 1998 and $25.0 million in
1999. In the event we should not have funds available at the time, our interest
in the well could be forfeited.
We may seek additional capital, if required, from traditional reserve base
borrowing, equity and debt offerings or joint ventures to further develop and
exploit our properties and to acquire additional properties, subject to the
limitations contained in the terms of our outstanding indebtedness. Our ability
to access additional capital will depend on our continued success in
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<PAGE>
developing our natural gas and oil reserves and the status of the capital
markets at the time such capital is required. Accordingly, there can be no
assurance that capital will be available to us from any source or that, if
available, it will be at prices or on terms acceptable to us. Should we be
unable to access the capital markets or should sufficient capital not be
available, the development and exploitation of our properties could be delayed
or reduced and, accordingly, natural gas and oil revenues and operating results
may be adversely affected.
Reliance on Key Personnel
We are dependent upon the services of our Chief Executive Officer and
President, Michael Paulk. The loss of his services could have a material
adverse effect on us. We have entered into an employment agreement with Mr.
Paulk, with a current expiration date of December 31, 2001. In addition, we have
obtained a policy of life insurance on Mr. Paulk in the amount of $1.0 million,
naming GPC as beneficiary.
Governmental Regulation
Our operations are affected by extensive regulation under various federal,
state and local laws and regulations relating to the exploration for and
development, production, gathering and marketing of natural gas and oil and the
release of materials into the environment. In particular, our natural gas and
oil exploration, development and production and our activities in connection
with storage and transportation of liquid hydrocarbons are subject to stringent
environmental regulation by governmental authorities. Such regulations have
increased the costs of planning, designing, drilling, installing, operating and
abandoning natural gas and oil wells and other related facilities.
Although we believe that our operations are in general compliance with all
such laws and regulations, including applicable environmental laws and
regulations, risks of substantial costs and liabilities are inherent in natural
gas and oil operations. There can be no assurance that significant costs and
liabilities will not be incurred in the future. Moreover, it is possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies thereunder, and claims for damages to property,
employees, other persons and the environment resulting from our operations,
could result in substantial costs and liabilities in the future.
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<PAGE>
The discharge of natural gas, oil or other pollutants into the air, soil or
water may give rise to significant liabilities on our part to the government and
third parties, It may require us to incur substantial costs of remediation.
Moreover, we have agreed to indemnify sellers of producing properties purchased
by us, including Amoco Corporation, among others, against environmental claims
associated with such properties. No assurance can be given that existing
environmental laws or regulations, as currently interpreted or reinterpreted in
the future, or future laws or regulations will not materially adversely affect
our results of operations and financial condition or that material indemnity
claims will not arise against us with respect to properties we acquired.
Competition
The natural gas and oil industry is highly competitive. We compete with
other companies in acquisitions and the development, production and marketing of
natural gas and oil with major oil companies, other independent natural gas and
oil concerns, and individual producers and operators. Many of these competitors
have substantially greater financial and other resources than we have.
Furthermore, the natural gas and oil industry competes with other industries in
supplying the energy and fuel needs of industrial, commercial and other
consumers.
Item 7 - Financial Statements:
The response to this Item is included in a separate section of this report.
See page F-1.
Item 8 - Changes in and Disagreements on Accounting and Financial Disclosure:
During the two fiscal years ended December 31, 1998, the Company has not
filed any Current Report on Form 8-K reporting any change in accountants in
which there was a reported disagreement on any matter of accounting principles
or practices, financial statement disclosure or auditing scope or procedure.
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<PAGE>
PART III
--------
Item 9 - Directors, Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act:
Directors and Executive Officers. The Directors and executive officers of
the Company, certain significant employees, their ages and positions with the
Company are as follows:
Name Age Position With Company
---- --- ---------------------
John J. Fleming 59 Chairman of the Board and Director
Michael K. Paulk 50 President and Director
Steven P. Ensz 47 Vice-President, Finance and Chief Financial
Officer
Brian E. Bayley 46 Director
James S. Blair 46 Vice-President, Corporate Development
Bennett G. Shelton 41 Vice-President of Land and Contract
Administration
Richard O. Mulford 45 Vice-President of Operations
Robert G. Snead 60 Geologist
John Coughlon 41 Geologist
David Evans 42 Petroleum Engineer
R.L. Hilbun 50 Full-Time Consultant, Drilling and
Completion Engineer
R. Andrew McGuire 32 Controller
John J. Fleming: Mr. Fleming was elected a Director of the Company in
October 1994. Mr. Fleming is currently President of Bonanza Energy Ltd.,
engaged in oil and gas exploration and diversified investments. From August
1995 through December 1998, he was Chairman, President and Chief Executive
Officer of Profco Resources Ltd., engaged in oil and gas exploration. In
December 1998, it merged with GHP Exploration Ltd. to form TransAtlantic
Petroleum Corp. Mr. Fleming was Chairman of the Board of American Natural
Energy Corporation ("ANEC") from August 1993 to July 1994. He has been involved
in the oil and gas industry as president, chairman or chief executive officer of
a number of corporations for more than the past fifteen years. Mr. Fleming is
also a Director of Imco Recycling Inc., Newfoundland Capital Corporation, CHC
Helicopter Corporation, TransAtlantic Petroleum Corp., and Poco Petroleum Ltd.
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<PAGE>
Michael K. Paulk: Mr. Paulk was elected President and Director of the
Company in October 1994. Mr. Paulk has been engaged in the oil and gas industry
for more than fifteen years. He was President of ANEC from its inception in
1985 until his resignation in September 1994 after its acquisition by Alexander
Energy Corporation in July 1994.
Steven P. Ensz: Mr. Ensz has been Vice-President, Finance and Chief
Financial Officer of the Company since March 18, 1998 and is responsible for the
financial activities of the Company. From July 1991 to February 1998, he was
Vice-President, Finance of Anglo-Suisse, Inc., an oil and natural gas
exploration and producing company. From December 1983 to June 1991, he held
various positions within the energy industry, including President of Waterford
Energy, an independent oil and gas producer. Prior to December 1983, he was a
partner with Oak, Simon & Ott, CPAs. He is a certified public accountant.
Brian E. Bayley: Mr. Bayley was elected a Director of the Company in
February 1996. He has been President of Quest Management Corp., a private
management company, since December 1996, and of Quest Ventures Ltd., a private
merchant banking company, since December 1996. Prior to April 1997, Mr. Bayley
held a variety of positions with Quest Oil & Gas Inc., including Vice President,
Corporate Administration from September 1986 to October 1990, President and
Chief Executive Officer from October 1990 to October 1996, and Secretary from
October 1996 to April 1997. He was a Director from November 1990 to April 1997.
Mr. Bayley is a Director of a number of other corporations, none of which are
reporting companies under the Securities Exchange Act of 1934, as amended.
James S. Blair: Mr. Blair has been Vice-President, Corporate Development
of the Company since June 1997 and is responsible for the management and
coordination of acquisition and divestiture activities. From January 1989 to
June 1997, he was Vice-President, Land and Acquisitions of Toreador Royalty
Corporation where he was responsible for implementing the Company's
restructuring plan, and in charge of increasing production through acquisitions
and joint ventures. From May 1988 to January 1989, he was Vice-President of
Business Development of German Oil Company, and from 1980 to May 1988, he was
employed by Tenneco Oil Company where he was involved with business development
and acquisitions.
Bennett G. Shelton: Mr. Shelton was elected Vice President of Land and
Contract Administration on December 9, 1998. Prior there, he was employed by
the Company as Land Contracts Manager since May 1995. From August 1994 to May
1995, he was a Senior Landman with AEOK and prior thereto he was a Land and
Acquisition Manager with ANEC. Prior to April 1991, he was a staff landman with
Santa Fe Minerals, Inc. for approximately ten years. Mr. Shelton was elected a
Vice-President on December 9, 1998.
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<PAGE>
Richard O. Mulford: Mr. Mulford was elected Vice President of Operations
on December 9, 1998. From April 1995 to November 1998, he was employed as
Operations Manager of the Company since April 1995. From April 1985 to April
1995, he was a Production Superintendent with ANEC and has been employed in the
oil and natural gas industry since 1978. Mr. Mulford was elected Vice-President
on December 9, 1998.
Robert G. Snead: Mr. Snead, who has served as a geologist for the Company
on a full-time consulting basis since April 1997, was hired as a full-time
employee effective September 1, 1997. Between early 1994 and April 1997, he was
employed as an independent geologist and from 1985 to 1994 was the Senior Vice-
President/ Exploration Manager of LOGO, Inc., an oil and natural gas well
operating company.
John Coughlon: Mr. Coughlon has been employed by the Company since March
1998. Prior thereto, he was, commencing in December 1994, employed by Amoco
Production Company, most recently as Senior Staff Geologist. From October 1993
to December 1994 he served as Geological Consultant/Principle of Tower Energy
Corporation and prior thereto he was from July 1987 to October 1993 Senior
Geologist for Nicor Oil & Gas and from April 1980 to July 1987 he was employed
by Mobil Oil Corp.
David Evans: Mr. Evans was hired by the Company as a petroleum engineer in
November 1997. Prior thereto, he was Production Manager for Petroleum
Properties Management Co. from March 1996 to October 1997. From April 1992 to
March 1996, he was Engineering Manager for AEOK and from September 1987 to April
1992 he was Vice-President of Exploration and Production for Bradmar Petroleum
Corporation.
R.L. Hilbun: Mr. Hilbun is a full-time consultant to the Company serving
as a drilling and completion engineer. He has served in this capacity since
March 1997. Prior thereto, commencing in 1982, he was Vice-President,
Operations of PSEC, Inc., a natural gas and oil well operating company. He has
been employed in the natural gas and oil industry since 1970.
R. Andrew McGuire: Mr. McGuire has been employed by the Company as
Controller since November 1994. From February 1991 to October 1994, he was
employed as Accounting Manager of ANEC. From May 1988 to February 1991, he was
employed by OXY-USA, Inc., a subsidiary of Occidental Petroleum Corp., as an
accountant. Mr. McGuire is a certified public accountant.
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<PAGE>
Director and Officer Securities Reports
The Federal securities laws require the Company's Directors and executive
officers, and persons who own more than ten percent (10%) of a registered class
of the Company's equity securities to file with the Securities and Exchange
Commission initial reports of ownership and reports of changes in ownership of
any equity securities of the Company. Copies of such reports are required to be
furnished to the Company. To the Company's knowledge, based solely on a review
of the copies of such reports and other information furnished to the Company,
all persons subject to these reporting requirements filed the required reports
on a timely basis with respect to the Company's year ended December 31, 1998.
Item 10 - Executive Compensation:
The following table sets forth the annual and long-term compensation paid
during the Company's three fiscal years ended December 31, 1998 to the Company's
chief executive officer and the Company's other most highly compensated
executive officers who received compensation exceeding $100,000 and who served
in such capacities at December 31, 1998:
<TABLE>
<CAPTION>
SUMMARY COMPENSATION TABLE
Annual Compensation
- ------------------------------------------------------------------------------------------------------------------
Compensation
--------------------------------
Other Long-Term
Name and Annual Award's Option All Other
Principal Position Year Salary Bonus Comp. (#) Comp.
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Michael K. Paulk 1998 $180,000 $150,000 -0- 375,000 -0-
1997 $150,000 $150,000 -0- -0- -0-
1996 $107,458 $ 50,000 -0- 125,000 -0-
Steven P. Ensz/(1)/ 1998 $118,750 $100,000 -0- 125,000 -0-
James S. Blair/(2)/ 1998 $107,950 -0- -0- -0- -0-
1997 $ 59,500 -0- -0- 100,000 -0-
</TABLE>
- --------------
(1) Mr. Ensz was employed by the Company in March 1998.
(2) Mr. Blair was employed by the Company in June 1997.
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<PAGE>
Option Grants in Year Ended December 31, 1998.
The following table provides information with respect to the above named
executive officers regarding options granted to such persons during the
Company's year ended December 31, 1998.
<TABLE>
<CAPTION>
% of Total Options/ Market
Number of Securities SARs Granted to Exercise or Price on
Underlying SARs/ Employees in Base Price Expiration Date of
Name Options Granted (#) Fiscal Year ($/Share) Date Grant
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Michael K. Paulk 375,000/(1)/ 42% $2.00 4/28/2003 $2.00
Steven P. Ensz 125,000/(2)/ 14% $2.00 4/28/2003 $2.00
</TABLE>
- --------------------------
(1) Of which, options to purchase 187,500 shares become exercisable on April
28, 1999 and options to purchase the remaining 187,500 shares become
exercisable on April 28, 2000, provided, however, such options become
immediately fully exercisable in the event of a "change of control," as
defined, of the Company. On December 9, 1998, the exercise price of such
options was repriced to $0.40 per share.
(2) Of which, options to purchase 62,500 shares become exercisable on April 28,
1999 and options to purchase the remaining 62,500 shares become exercisable
on April 28, 2000, provided, however, such options become immediately fully
exercisable in the event of a "change of control," as defined, of the
Company. On December 9, 1998, the exercise price of such options was
repriced to $0.40 per share.
Stock Option Holdings at December 31, 1998.
The following table provides information with respect to the above named
executive officers regarding Company options held at the end of the Company's
year ended December 31, 1998 (such officers did not exercise any options during
the most recent fiscal year).
<TABLE>
<CAPTION>
Value of Unexercised
Number of Unexercised Options In-the-Money Options
at December 31,1998/(1)/ at December 31, 1998/(2)/
Name Exercisable Unexercisable Exercisable Unexercisable
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Michael K. Paulk 375,000 375,000 -0- -0-
Steven P. Ensz -0- 125,000 -0- -0-
James S. Blair 50,000 50,000 -0- -0-
</TABLE>
- ----------------------------
(1) The options are exercisable at $0.40 per share, which reflects the
repricing discussed below.
(2) Based on the closing sales price on December 31,1998 of $5/16.
On February 3, 1999, options to purchase 250,000 shares exercisable at $0.53 per
share were granted to each of Mr. Paulk and Mr. Ensz.
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<PAGE>
Option Repricing
On December 9, 1998, the Board of Directors of the Company authorized the
amendment of the terms of all of the options granted to employees under its
stock option plans to reduce the exercise price to $0.40 per share, the fair
market value of its outstanding shares of Common Stock on that date. At the
time, the Company had outstanding options to purchase a total of 2,695,000
shares held by 24 employees, three officers and two Directors with exercise
prices ranging from $1.50 to $2.56 per share. The options granted to Messrs.
Paulk, Ensz, and Blair were repriced on the basis of the substantial declines
commencing in mid-1998 in the prevailing market prices for natural gas and oil
which impacted the market price for the Company's securities.
Employment Agreements
The Company has entered into an employment agreement with Michael Paulk
effective January 1, 1999 pursuant to which he is employed as the President of
the Company. Mr. Paulk currently receives a base salary of $189,000 per year.
In addition, he is to receive a cash bonus as may be determined by the Company's
Board of Directors. Mr. Paulk is also entitled to participate in such incentive
compensation and benefit programs as the Company makes available. The term of
Mr. Paulk's agreement is for a period of three years and at the end of the first
year and at the end of each succeeding year the agreement is automatically
extended for one year such that at the end of each year there will automatically
be three years remaining on the term of the agreement. Mr. Paulk can terminate
the agreement at the end of the initial term and any succeeding term on not less
than six months notice. In the event the employment agreement is terminated by
the Company (other than for cause, as defined), Mr. Paulk is entitled to receive
a payment representing all salary due under the remaining full term of his
agreement and the Company is obligated to continue his medical insurance and
other benefits provided under the agreement in effect for a period of one year
after such termination. In the event of a change in control, as defined, of the
Company, Mr. Paulk has the right to terminate his employment agreement with the
Company within sixty days thereafter, whereupon the Company would be obligated
to pay to him a sum equal to three years his base salary under the agreement
plus a lump sum payment of $250,000.
The Company has also entered into an employment agreement with Steven P.
Ensz effective January 1, 1999 pursuant to which he is employed as the Vice
President and Chief Financial Officer of the Company. Mr. Ensz currently
receives a base salary of $157,500 per
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<PAGE>
year. In addition, he is to receive a cash bonus as may be determined by the
Company's Board of Directors. Mr. Ensz is also entitled to participate in such
incentive compensation and benefit programs as the Company makes available. The
term of Mr. Ensz' agreement is for a period of three years and at the end of the
first year and at the end of each succeeding year the agreement is automatically
extended for one year such that at the end of each year there will automatically
be three years remaining on the term of the agreement. Mr. Ensz can terminate
the agreement at the end of the initial term and any succeeding term on not less
than six months notice. In the event the employment agreement is terminated by
the Company (other than for cause, as defined), Mr. Ensz is entitled to receive
a payment representing all salary due under the remaining full term of his
agreement and the Company is obligated to continue his medical insurance and
other benefits provided under the agreement in effect for a period of one year
after such termination. In the event of a change in control, as defined, of the
Company, Mr. Ensz has the right to terminate his employment agreement with the
Company within sixty days thereafter, whereupon the Company would be obligated
to pay to him a sum equal to three years his base salary under the agreement
plus a lump sum payment of $200,000.
Directors Compensation
Each Director of the Company received a fee of $15,000 for serving in that
capacity during 1998 and each Director is reimbursed for his out-of-pocket
expenses in attending meetings.
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<PAGE>
Item 11 - Security Ownership of Certain Beneficial Owners and Management:
Set forth below is information concerning the Common Stock ownership of all
persons known by the Company to own beneficially 5% or more of the Company's
Common Stock, and the Common Stock ownership of each Director of the Company and
all Directors and officers of the Company as a group, as of March 15, 1999. As
of March 15, 1999, the Company had 16,291,640 shares of Common Stock
outstanding.
<TABLE>
<CAPTION>
Name and Address of Beneficial
Holder, Identity of Group/(1)(2)/ Amount/(3)/ Percent of Class
-------------------------------------- --------------------- ------------------
<S> <C> <C>
Michael Paulk 1,174,891/(4)/ 6.8%
John Fleming 550,000/(5)/ 3.3%
Brian E. Bayley 550,000/(6)/ 3.3%
Stratum Group, L.L.C./(7)/ 1,000,000/(8)/ 5.8%
650 Fifth Avenue
New York, New York 10019
Carl C. Icahn/(7)/ 1,600,000 9.8%
High River Limited Partnership/(7)/
Riverdale LLC/(7)/
Little Meadow Corp./(7)/
100 South Bedford Road
Mount Kisco, New York 10549
Amoco Corporation/(7)/ 1,500,000/(9)/ 8.4%
200 East Randolph Drive
Chicago, Illinois 60601
Croft-Leominster, Inc./(10)/ 838,700 5.1%
207 East Redwood Street - Suite 208
Baltimore, Maryland 21202
Chesapeake Energy Corporation/(11)/ 2,439,246 13.0%
6100 North Western Avenue
Oklahoma City, Oklahoma 73118
All Officers and Directors as a 3,004,891 15.7%
Group (7 persons)
</TABLE>
- --------------------------------
(1) This tabular information is intended to conform with Rule 13d-3 promulgated
under the Securities Exchange Act of 1934 relating to the determination of
beneficial ownership of securities. The tabular information gives effect
to the exercise of warrants or options
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<PAGE>
exercisable within 60 days of the date of this table owned in each case by
the person or group whose percentage ownership is set forth opposite the
respective percentage and is based on the assumption that no other person
or group exercise their option.
(2) The address of Mr. Paulk is c/o the Company, 5727 South Lewis Avenue, Suite
700, Tulsa, Oklahoma 74105. The address of Mr. Fleming is 1500, 340 12th
Avenue SW, Calgary, Alberta T2R 1L5. The address of Mr. Bayley is c/o
Quest Management Corp., 1095 West Pender Street-Suite 850, Vancouver,
British Columbia, Canada V6E 2M6.
(3) Except as otherwise noted, shares beneficially owned by each person as of
March 15, 1999 were owned of record and each person had sole voting and
investment power with respect to all shares beneficially held by such
person.
(4) Includes (i) 375,000 shares issuable upon exercise of options at an
exercise price of $0.40 per share and (ii) 375,000 shares issuable upon
exercise of options at an exercise price of $0.40 per share, of which
options to purchase 187,500 shares become exercisable on April 28, 1999 and
options to purchase the remaining 187,500 shares become exercisable on
April 28, 2000. Also includes 250,000 shares issuable on exercise of
options at an exercise price of $0.53 per share, of which options to
purchase 125,000 shares become exercisable on February 4, 2000 and options
to purchase the remaining 125,000 shares become exercisable on February 4,
2001. In the event of a "change of control" of the Company, as defined in
the option agreements, such remaining options become immediately
exercisable.
(5) Includes 100,000 shares issuable on exercise of options at an exercise
price of $0.40 per share which are exercisable during the five-year period
beginning July 11, 1995, 50,000 shares issuable on exercise of options at
an exercise price of $0.40 per share which are exercisable during the five-
year period beginning July 16, 1996, 150,000 shares issuable on exercise of
options at an exercise price of $0.40 per share which are exercisable
during the five year period beginning April 28, 1998, and 250,000 shares
issuable on exercise of options at an exercise price of $0.53 per share
which are exercisable during the five-year period beginning February 4,
1999.
(6) Includes 150,000 shares issuable on exercise of options at an exercise
price of $0.40 per share which are exercisable during the five-year period
beginning July 16, 1996, 150,000 shares issuable on exercise of options at
an exercise price of $0.40 per share which are exercisable during the five-
year period beginning April 28, 1998, and 250,000 shares issuable on
exercise of options at an exercise price of $0.53 per share which are
exercisable during the five-year period beginning February 4, 1999.
(7) Based on information contained in Schedule 13D provided by such person.
(8) Issuable on exercise of common stock purchase warrants at $2.67 per share,
as adjusted. The general partner of Stratum Group, L.P. is Stratum Finance,
L.L.C. and the members of Stratum Finance, L.L.C. are Energy Investment
Partners, a New York general partnership, Joseph M. Rinaldi, Michael W.
Walker, Richard E. Bani, John C. Alvardo, Curt S. Taylor,
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<PAGE>
and Betsy D. Cotton. Stratum Finance, L.L.C. is managed by Energy
Investment Partners, which has four votes, Joseph M. Rinaldi, who has one
vote, and Michael W. Walker, appointed by the natural person members of
Stratum Finance, L.L.C., who has one vote. Energy Investment Partners has
three general partners, SGLLC Partners, L.P. ("SGLLC"), SGLLC Partners
Offshore, L.P. ("Offshore") and The Beacon Group Energy Investment Fund,
L.P. ("Fund"). The sole general partner of each of SGLLC and Offshore is
SG-GP, L.P. whose sole general partner is Energy Fund GPI, Inc. ("GPI").
The sole general partner of Fund is Beacon Energy Investors, L.P.
("Investors"). The sole general partner of Investors is BEIGP, Inc.
("BEIGP"). The names of the officers and Directors of both GPI and BEIGP
are Geoffrey Boisi, John McWilliams, Preston Miller, Harold Pote, Faith
Rosenfeld, Robert Semmens, David Remmington, Thomas Mendell and Frank
Murray.
(9) Issuable on exercise of common stock purchase warrants at $2.59 per share,
as adjusted.
(10) Based on information contained in Schedule 13G provided by such person.
(11) Includes 2,439,246 shares issuable at a price of $0.01 per share on
exercise of a common stock purchase warrant.
Item 12 - Certain Relationships and Related Transactions:
Mr. Paulk is indebted to the Company in the amount of $179,000 under an
interest bearing promissory note dated September 1, 1997 due, as extended, on
January 31, 2000.
On January 23, 1998, the Company completed the Amoco Acquisition pursuant
to which, among other things, the Company issued to Amoco a five-year common
stock purchase warrant to purchase 1.5 million shares of Common Stock
exercisable at $3.00 per share.
On April 27, 1998, the Company completed a transaction with Chesapeake
Energy Corporation ("Chesapeake") pursuant to which it (i) executed a
participation agreement granting to Chesapeake a 50% interest in substantially
all of the Company's undeveloped acreage, (ii) sold for $20.0 million a 50%
interest in the Company's natural gas and oil properties in the Arkoma basin,
and (iii) sold 50,000 shares of Series B Preferred Stock and a common stock
purchase warrant. The Series B Preferred Stock had a liquidation value of $50.0
million and a dividend rate per annum equal to 12 1/2% of the aggregate
liquidation preference payable in additional shares of Series B Preferred Stock,
provided that, after April 1, 2000, at the Company's option, dividends may be
paid in cash. On June 30, 2008, the Series B Preferred Stock is mandatorily
redeemable in shares of Common Stock valued at the fair market value on the date
of redemption. The Company has the option at any time prior to April 30, 2000
to redeem the Series B Preferred Stock, in whole or in part, at 105% of the
liquidation preference payable in cash out of the net proceeds of a public or
private offering of any equity security. After April 30, 2000, the Series B
Preferred Stock can be redeemed, in whole or in part, at a
-53-
<PAGE>
redemption price equal to the liquidation preference. After April 20, 2000, the
Series B Preferred Stock is convertible into a number of shares of Common Stock
determined by dividing the liquidation preference by the higher of $2.04167 or
the fair market value on the date the Series B Preferred Stock is converted.
Notwithstanding the foregoing, no holder or group can convert the Series B
Preferred Stock to the extent that the conversion of such shares would cause
such holder or group to own more than 19.9% of the Company's outstanding Common
Stock. The shares of Series B Preferred Stock have no voting rights except as
required by Oklahoma law. At December 31, 1998, reflecting dividends paid,
Chesapeake held 54,187 shares of Series B Preferred Stock. The Series B
Preferred Stock ranks senior to all classes of Common Stock and other series and
classes of preferred stock with respect to dividend rights and rights on
liquidation, winding up and disolution.
The warrant sold to Chesapeake entitles it to purchase 2,439,246 shares of
the Company's Common Stock at an exercise price of $0.01 per share, subject to
certain adjustments, and expires on April 27, 2008.
So long as Chesapeake holds 50% or more of the outstanding shares of Series
B Preferred Stock it is granted certain preferential rights with respect to the
purchase of securities of the Company and is entitled to designate for election
to the Company's Board of Directors not less than 20% of the members of the
Board of Directors of the Company. Chesapeake has not designated any persons
for election through March 15, 1999. The Company's agreement with Chesapeake
also contains standstill provisions through March 1, 2000 restricting Chesapeake
from engaging in certain acquisition or other similar business combination
transactions or seeking to influence or control the Company.
Pursuant to the Participation Agreement between the Company and Chesapeake,
the Company sold Chesapeake the right through April 30, 2003 to participate in
up to 50% of the Company's interest in the development of any of the Company's
non-producing leasehold interests (other than the Arkoma basin and certain New
Mexico properties). Chesapeake also was sold the right to participate in up to
50% of the Company's interest in any subsequently acquired properties. During
the year ended December 31, 1998, Chesapeake elected to participate to the
extent of 50% of the Company's interest in the development of 26 non-producing
properties and no acquired properties.
-54-
<PAGE>
GLOSSARY
Wherever used herein, the following terms shall have the meanings
specified.
Bbl--One stock tank barrel, or 42 US gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf--One billion cubic feet.
Bcfe--One billion cubic feet of natural gas equivalent.
Behind Pipe--Hydrocarbons in a potentially producing horizon penetrated by
a well bore the production of which has been postponed pending the production of
hydrocarbons from another formation penetrated by the well bore. These
hydrocarbons are classified as proved but non-producing reserves.
Boe--Barrels of oil equivalent (converting six Mcf of natural gas to one
Bbl of oil).
Developed Acreage--Acres which are allocated or assignable to producing
wells or wells capable of production.
Development Well--A well drilled within the proved area of a natural gas
and oil reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry Well--A well found to be incapable of producing either oil or natural
gas in sufficient quantities to justify completion as an oil or natural gas
well.
EBITDA--Earnings (excluding discontinued operations, extraordinary items,
charges resulting from changes in accounting and significant non-recurring
revenues and expenses) before interest expense, provision for (or benefit for)
income taxes, depletion, depreciation and amortization expenses, and the
provision for impairment of natural gas and oil properties. EBITDA is not a
measure of cash flow as determined by generally accepted accounting principles.
EBITDA information has been included in this Prospectus because EBITDA is a
measure used by certain investors in determining historical ability to service
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 as an indicator of operating
performance or liquidity.
-55-
<PAGE>
Exploratory Well--A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.
Gross Acres or Gross Wells--The total acres or wells, as the case may be,
in which a working interest is owned.
Infill Well--A well drilled between known producing wells to better exploit
the reservoir
Mbbl--One thousand Bbl.
Mmbbl--One million Bbl.
Mboe--One thousand barrels of oil equivalent.
Mcf--One thousand cubic feet.
Mcfe--One thousand cubic feet of natural gas equivalent, using the ratio of
one Bbl of crude oil to six Mcf of natural gas.
Mmcf--One million cubic feet.
Mmcfe--One million cubic feet of natural gas equivalent.
Natural Gas and Oil Lease--An instrument by which a mineral fee owner
grants to a lessee the right for a specific period of time to explore for
natural gas and oil underlying the lands covered by the lease and the right to
produce any natural gas and oil so discovered generally for so long as there is
production in economic quantities from such lands.
Net Acres or Net Wells--The sum of the fractional working interests owned
in gross acres or gross wells.
NYMEX--New York Mercantile Exchange.
Overriding Royalty Interest--A fractional undivided interest in a natural
gas and oil property entitling the owner to a share of natural gas and oil
production, in addition to the usual royalty paid to the owner, free of costs of
production.
PDNP--Proved developed, non-producing or behind the pipe reserves.
-56-
<PAGE>
Productive Well--A well that is producing oil or natural gas or that is
capable of production.
Proved Developed Reserves--Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves--The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped Reserves or PUD--Reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for completion.
PV-10--The discounted future net cash flows for proved natural gas and oil
reserves computed on the same basis as the Standardized Measure, but without
deducting income taxes, which is not in accordance with generally accepted
accounting principles. PV-10 is an important financial measure for evaluating
the relative significance of natural gas and oil properties and acquisitions,
but should not be construed as an alternative to the SEC PV-10 (as determined in
accordance with generally accepted accounting principles).
Reserve Life--The estimated productive life of a proved reservoir based
upon the economic limit of such reservoir producing hydrocarbons in paying
quantities assuming certain price and cost parameters. For purposes of this
Report, reserve life is calculated by dividing the Proved Reserves (on an Mcfe
basis), as of December 31, 1998 by projected production volumes for the 12
months ending December 31, 1999.
Royalty Interest--An interest in a natural gas and oil property entitling
the owner to a share of natural gas and oil production free of costs of
production.
Secondary Recovery--A method of natural gas and oil extraction in which
energy sources extrinsic to the reservoir are utilized.
Standardized Measure--The estimated future net cash flows from proved
natural gas and oil reserves computed using prices and costs at the dates
indicated, after income taxes and discounted at 10%.
-57-
<PAGE>
Undeveloped Acreage--Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of natural gas and oil regardless of whether such acreage contains proved
reserves.
Working Interest--The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
-58-
<PAGE>
PART IV
Item 13 - Exhibits and Reports on Form 8-K:
<TABLE>
<CAPTION>
Exhibit Description
- --------------------- ---------------------------------------------------------------------
<S> <C>
3.1 Certificate of Incorporation of the Company filed October 11,1996/(1)/
3.2 Certificate of Ownership and Merger of the Company filed October 22,
1996/(1)/
3.4 By-Laws of the Company/(1)/
4.1 Specimen Stock Certificate
4.2 Warrant Agreement between Company and American Stock Transfer &
Trust Company, as Warrant Agent, including form of Redeemable
Warrant/(2)/
10.1 1989 Incentive Stock Option and Non-Statutory Plan, as amended /(1)/
10.2 1996 Omnibus Incentive Plan/(1)/
10.3 1996 Non-Employee Stock Option Plan/(1)/
10.2.1 Employment Agreement dated as of January 1, 1999 between the Company
and Michael Paulk*
10.2.2 Employment Agreement dated as of January 1, 1999 between the Company
and Steven P. Ensz*
10.3 Warrant Certificate to purchase 1,000,000 Shares of Company's Common
Stock at $3.25 per share issued to Stratum/(3)/
10.4 Registration Rights Agreement dated as of September 9, 1997 among
the Company, Gothic Energy of Texas, Inc., Gothic Gas Corporation,
Oppenheimer & Co., Inc, Banc One Capital Corporation and Paribas
Corporation.(4)
</TABLE>
-59-
<PAGE>
<TABLE>
<CAPTION>
Exhibit Description
- --------------------- ---------------------------------------------------------------------
<S> <C>
10.5 Warrant Agreement between the Company and American Stock Transfer &
Trust Company, as Warrant Agent, dated as of September 9, 1997(4)
10.6 Common Stock Purchase Warrant issued to Norse Exploration, Inc., and
Norse Pipeline, Inc.(5)
10.7 Purchase and Sale Agreement dated November 25, 1997 between Amoco
Production Company, as Seller, and Gothic Energy Corporation, as
Buyer(6)
10.8 Securities Purchase Agreement dated as of January 23, 1998(7)
10.9 Warrant Agreement between the Company and American Stock Transfer &
Trust Company, dated as of January 23, 1998(7)
10.10 Registration Rights Agreement dated as of January 23, 1998(7)
10.11 Common Stock Registration Rights Agreement dated as of January 23,
1998(7)
10.12 Warrant to Purchase Common Stock of the Company expiring November
24, 2002(7)
10.13 Securities Purchase Agreement dated as of March 31, 1998 by and
among Gothic Energy Corporation, Chesapeake Gothic Corp. and
Chesapeake Acquisition Corporation (filed as Exhibit 10.2 to Current
Report on Form 8-K dated March 31, 1998)(8)
10.14 Sale and Participation Agreement dated March 31, 1998 between
Chesapeake Gothic Corporation, Gothic Energy of Texas, Inc. and
Gothic Production Corporation (filed as Exhibit 10.3 to Current
Report on Form 8-K dated March 31, 1998)(8)
</TABLE>
-60-
<PAGE>
<TABLE>
<CAPTION>
Exhibit Description
- --------------------- ---------------------------------------------------------------------
<S> <C>
10.15 Oil and Gas Asset Purchase Agreement dated March 31, 1998 among
Chesapeake Gothic Corp., Chesapeake Acquisition Corporation and
Gothic Energy Corporation (filed as Exhibit 10.4 to Current Report
on Form 8-K dated March 31, 1998)(8)
10.16 Indenture dated as of April 21, 1998 between GPC and The Bank of New
York, as Trustee, with respect to the 11-1/8% Senior Secured Notes
due 2005(8)
10.17 Registration Rights Agreement dated as of April 21, 1998 by and
among GPC, Gothic, Donaldson, Lufkin & Jenrette Securities
Corporation and CIBC Oppenheimer Corp.(8)
10.18 Securities Purchase Agreement dated as of April 21, 1997 among
Gothic and the Purchasers named therein with respect to 104,000
Units of Securities of Gothic(8)
10.19 Indenture dated as of April 21, 1998 between Gothic and The Bank of
New York, as Trustee, with respect to the 14-1/8% Senior Secured
Discount Notes due 2006(8)
10.20 Warrant Agreement dated as of April 21, 1998 between Gothic and
American Stock Transfer & Trust Company, as Warrant Agent(8)
10.21 Notes Registration Rights Agreement dated as of April 21, 1998 among
Gothic and the Purchasers named therein(8)
10.22 Warrant Registration Rights Agreement dated as of April 21, 1998
among Gothic and the Purchasers named therein(8)
10.23 Certificate of Designation for the Senior Redeemable Preferred
Stock, Series B(8)
10.24 Warrant to Purchase Common Stock dated April 27, 1998 issued to
Chesapeake Gothic Corp.(8)
10.25 Securities Purchase Agreement dated as of March 31, 1998 by and
among Gothic Energy Corporation, Chesapeake Gothic Corp. and
Chesapeake Acquisition Corporation(9)
</TABLE>
-61-
<PAGE>
<TABLE>
<CAPTION>
10.26 Sale and Participation Agreement dated March 31, 1998 between
Chesapeake Gothic Corporation, Gothic Energy of Texas, Inc. and
Gothic Production Corporation(9)
10.27 Oil and Gas Asset Purchase Agreement dated March 31, 1998 among
Chesapeake Gothic Corp., Chesapeake Acquisition Corporation and
Gothic Energy Corporation(9)
21.0 Subsidiaries of the registrant:
Name State or Jurisdiction of Incorporation
- --------------------- ----------------------------------------------------------------
<S> <C>
Gothic Production Oklahoma
Corporation
23.0 Consent of PricewaterhouseCoopers LLP
27.0 Financial Data Schedule.
</TABLE>
- --------------------------
* Filed herewith.
(1) Filed as an exhibit to Annual Report on Form 10-KSB for the year ended
December 31, 1997
(2) Filed as an exhibit to Registration Statement on Form SB-2 (File No.
33-99190)
(3) Filed as an exhibit to Current Report on Form 8-K for May 31, 1995
(4) Filed as an exhibit to Current Report on Form 8-K for September 9,
1997
(5) Filed as an exhibit to Current Report on Form 8-K for February 18,1997
(6) Filed as an exhibit to Current Report on Form 8-K/A for November 25,
19977
(7) Filed as an exhibit to Current Report on Form 8-K/A for January 23,
1998
(8) Filed as an exhibit to Current Report on Form 8-K for April 27,1998.
(9) Filed as an exhibit to Current Report on Form 8-K for March 31, 1998.
-62-
<PAGE>
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Gothic Energy Corporation
By: /s/ Michael K. Paulk
------------------------------------------------
Michael K. Paulk, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the Company
and in the capacities and on the dates indicated.
Signature Title Date
- --------- ----- ----
/s/ Michael K. Paulk President (Principal March 31, 1999
- ------------------------------- Executive Officer and Director)
Michael K. Paulk
/s/ Steven P. Ensz Vice-President, Finance and March 31, 1999
- -------------------------------- Chief Financial Officer
Steven P. Ensz (Principal Financial and
Accounting Officer)
/s/ John J. Fleming Director March 31, 1999
- -------------------------------
John J. Fleming
/s/ Brian E. Bayley Director March 31, 1999
- -------------------------------
Brian E. Bayley
-63-
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Accountants......................................................................... F-2
Consolidated Balance Sheet, December 31, 1998............................................................. F-3
Consolidated Statement of Operations, Years ended December 31, 1997 and 1998.............................. F-4
Consolidated Statement of Stockholders' Equity (Deficit), Years ended December 31, 1997 and 1998.......... F-5
Consolidated Statement of Cash Flows, Years ended December 31, 1997 and 1998.............................. F-6
Notes to Consolidated Financial Statements................................................................ F-7
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Stockholders of Gothic Energy Corporation
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, stockholders' equity (deficit) and cash
flows present fairly, in all material respects, the financial position of Gothic
Energy Corporation and Subsidiary at December 31, 1998, and the results of their
operations and their cash flows for the years ended December 31, 1997 and 1998,
in conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these financial statements in accordance
with generally accepted auditing standards which require that we plan and
perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the acounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
The accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern. As discussed in Note
2 to the financial statements, the Company has suffered recurring losses from
operations and has a working capital and a net capital deficiency that raise
substantial doubt about its ability to continue as a going concern. Management's
plans in regard to these matters are also described in Note 2. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 12, 1999
F-2
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1998
(DOLLARS IN THOUSANDS, EXCEPT PAR VALUE)
<TABLE>
<S> <C>
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents........................................................... $ 2,289
Natural gas and oil receivables..................................................... 7,236
Receivable from officers and employees.............................................. 55
Other............................................................................... 221
---------
TOTAL CURRENT ASSETS.............................................................. 9,801
PROPERTY AND EQUIPMENT:
Natural gas and oil properties on full cost method:
Properties being amortized........................................................ 242,012
Unproved properties not subject to amortization................................... 2,862
Equipment, furniture and fixtures................................................... 3,327
Accumulated depreciation, depletion and amortization................................ (33,201)
---------
PROPERTY AND EQUIPMENT, NET......................................................... 215,000
OTHER ASSETS, NET.................................................................... 12,487
---------
TOTAL ASSETS...................................................................... $ 237,288
=========
LIABILITIES AND STOCKHOLDER'S EQUITY (DEFICIT)
----------------------------------------------
CURRENT LIABILITIES:
Accounts payable trade.............................................................. $ 3,208
Revenues payable.................................................................... 6,031
Accrued interest expense............................................................ 4,358
Accrued liabilities................................................................. 253
---------
TOTAL CURRENT LIABILITIES......................................................... 13,850
LONG-TERM DEBT, NET.................................................................. 301,179
GAS IMBALANCE AND OTHER LIABILITIES.................................................. 6,180
COMMITMENTS AND CONTINGENCIES (NOTES 5,9 AND 13)
STOCKHOLDERS' EQUITY (DEFICIT):
Series B Preferred stock, par value $.05, authorized 165,000 shares; 54,187 shares
issued and outstanding............................................................ 36,945
Common stock, par value $.01, authorized 100,000,000 shares; issued and
outstanding 16,261,640 shares..................................................... 162
Additional paid in capital.......................................................... 42,996
Accumulated deficit................................................................. (163,845)
Note receivable..................................................................... (179)
---------
TOTAL STOCKHOLDERS' EQUITY (DEFICIT).............................................. (83,921)
---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT).............................. $ 237,288
=========
</TABLE>
See accompanying notes to consolidated financial statements
F-3
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1997 and 1998
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1997 1998
-------- ---------
<S> <C> <C>
REVENUES:
Natural gas and oil sales...................................................... $17,418 $ 50,714
Gas system revenue............................................................. 4,562 --
Well operations................................................................ 1,283 2,319
-------- ---------
Total revenues................................................................. 23,263 53,033
COSTS AND EXPENSES:
Lease operating expense........................................................ 6,860 12,129
Gas system expense............................................................. 3,501 --
Depletion, depreciation and amortization....................................... 5,791 24,001
General and administrative expense............................................. 2,318 3,565
Severance for former officer................................................... -- 258
Provision for impairment of natural gas and oil properties..................... -- 76,000
-------- ---------
Operating income (loss).......................................................... 4,793 (62,920)
Interest expense and amortization of debt issuance costs......................... (8,800) (35,438)
Interest and other income........................................................ 330 433
Loss on sale of investments...................................................... -- (305)
-------- ---------
LOSS BEFORE EXTRAORDINARY ITEM................................................... (3,677) (98,230)
LOSS ON EARLY EXTINGUISHMENT OF DEBT............................................. 907 31,459
-------- ---------
NET LOSS......................................................................... (4,584) (129,689)
PREFERRED DIVIDEND ($47.65 and $125.76 PER PREFERRED SHARE)...................... 264 5,599
PREFERRED DIVIDEND--AMORTIZATION OF PREFERRED DISCOUNT........................... -- 5,095
-------- ---------
NET LOSS AVAILABLE FOR COMMON SHARES............................................. $(4,848) $(140,383)
======== =========
LOSS PER COMMON SHARE BEFORE EXTRAORDINARY ITEM, BASIC
AND DILUTED.................................................................... $(.28) $(6.70)
======== =========
NET LOSS PER COMMON SHARE, BASIC AND DILUTED..................................... $(.35) $(8.63)
======== =========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING....................................... 14,019 16,262
======== =========
</TABLE>
See accompanying notes to consolidated financial statements
F-4
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
ACCUMULATED
COMMON PREFERRED ADDITIONAL OTHER
SHARES SHARES COMMON PREFERRED PAID-IN ACCUMULATED COMPREHENSIVE
OUTSTANDING OUTSTANDING STOCK STOCK CAPITAL DEFICIT INCOME
----------- ----------- ------ --------- ---------- ------------ -------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, AT DECEMBER 31,
1996................................. 12,382 6 $123 $ -- $33,322 $ (18,614) $ --
Issuance of common stock on
exercise of note extension
warrants......................... 35 -- -- -- 35 -- --
Issuance of common stock on
conversion of debt............... 14 -- -- -- 28 -- --
Issuance of common stock on
exercise of Quest warrants....... 300 -- 3 -- 297 -- --
Warrants issued in connection
with property acquisition........ -- -- -- -- 254 -- --
Issuance of common stock with
bridge financing................. 450 -- 5 -- 1,059 -- --
Issuance of common stock on
conversion of preferred
stock............................ 3,055 (6) 31 -- (31) -- --
Costs related to Form S-3
registration statement........... -- -- -- -- (153) -- --
Warrants issued in connection
with Senior Notes Offering....... -- -- -- -- 1,190 -- --
Issuance of common stock on
exercise of option............... 5 -- -- -- 10 -- --
Issuance of common stock as
employee bonuses................. 21 -- -- -- 32 -- --
Preferred stock dividends.......... -- -- -- -- -- (264) --
Net loss........................... -- -- -- -- -- (4,584) --
Unrealized loss on available-for-
sale investments................. -- -- -- -- -- -- (121)
Advance to officer to purchase
stock............................ -- -- -- -- -- -- --
------ ----- ------ -------- ------- --------- -------------
BALANCE, AT DECEMBER 31,
1997................................. 16,262 -- 162 -- 36,043 (23,462) (121)
Issuance of Series A Preferred
stock............................ -- 37 -- 33,909 (20) -- --
Warrants issued in connection
with Series A Preferred.......... -- -- -- -- 941 -- --
Warrants issued in connection
with Amoco acquisition........... -- -- -- -- 1,153 -- --
Redemption of Series A Preferred... -- (37) -- (33,909) -- -- --
Issuance of Series B Preferred
stock............................ -- 50 -- 31,527 -- -- --
Warrants issued in connection
with Series B Preferred -- -- -- -- 4,879 -- --
Preferred Stock dividend
- Series A....................... -- -- -- -- -- (1,412) --
Preferred dividend - amortization
of discount - Series A -- -- -- -- -- (3,864) --
Preferred Stock dividend
- Series B -- 4 -- 4,187 -- (4,187) --
Preferred dividend - amortization
of discount - Series B -- -- -- 1,231 -- (1,231) --
Net loss........................... -- -- -- -- -- (129,689) --
Realized loss on available for sale
investments...................... -- -- -- -- -- -- 121
Advance to officer................. -- -- -- -- -- -- --
------ ----- ------ -------- ------- --------- -------------
BALANCE, AT DECEMBER 31,
1998................................. 16,262 54 $162 $ 36,945 $42,996 $(163,845) $ --
====== ===== ====== ======== ======= ========= =============
<CAPTION>
TOTAL
NOTE STOCKHOLDERS'
RECEIVABLE EQUITY
--------- ------------
<S> <C> <C>
BALANCE, AT DECEMBER 31,
1996................................. $ -- $ 14,831
Issuance of common stock on
exercise of note extension
warrants......................... -- 35
Issuance of common stock on
conversion of debt............... -- 28
Issuance of common stock on
exercise of Quest warrants....... -- 300
Warrants issued in connection
with property acquisition........ -- 254
Issuance of common stock with
bridge financing................. -- 1,064
Issuance of common stock on
conversion of preferred
stock............................ -- --
Costs related to Form S-3
registration statement........... -- (153)
Warrants issued in connection
with Senior Notes Offering....... -- 1,190
Issuance of common stock on
exercise of option............... -- 10
Issuance of common stock as
employee bonuses................. -- 32
Preferred stock dividends.......... -- (264)
Net loss........................... -- (4,584)
Unrealized loss on available-for-
sale investments................. -- (121)
Advance to officer to purchase
stock............................ (169) (169)
-------- ------------
BALANCE, AT DECEMBER 31,
1997................................. (169) 12,453
Issuance of Series A Preferred
stock............................ -- 33,889
Warrants issued in connection
with Series A Preferred.......... -- 941
Warrants issued in connection
with Amoco acquisition........... -- 1,153
Redemption of Series A Preferred... -- (33,909)
Issuance of Series B Preferred
stock............................ -- 31,527
Warrants issued in connection
with Series B Preferred......... -- 4,879
Preferred Stock dividend - Series A -- (1,412)
Preferred dividend - amortization
of discount - Series A -- (3,864)
Preferred Stock dividend - Series B -- --
Preferred dividend - amortization
of discount - Series B -- --
Net loss........................... -- (129,689)
Realized loss on available for sale
investments...................... -- 121
Advance to officer................. (10) (10)
--------- ------------
BALANCE, AT DECEMBER 31,
1998................................. $ (179) $ (83,921)
======== ============
</TABLE>
See accompanying notes to consolidated financial statements
F-5
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1998
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1998
------------ ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss................................................................... $ (4,584) $ (129,689)
ADJUSTMENTS TO RECONCILE NET LOSS TO NET CASH PROVIDED
BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization................................... 5,791 24,001
Amortization of discount and loan costs.................................... 1,804 1,994
Provision for impairment of natural gas and oil properties................. -- 76,000
Accretion of interest on discount notes.................................... -- 6,023
Loss on early extinguishment of debt....................................... 907 31,459
CHANGES IN ASSETS AND LIABILITIES:
Increase in accounts receivable............................................ (428) (4,009)
(Increase) decrease in other current assets................................ 1 (143)
Increase in accounts and revenues payable.................................. 317 5,605
Increase (decrease) in gas imbalance payable............................... (737) 65
Increase in accrued liabilities............................................ 3,688 411
(Increase) decrease in other assets........................................ 310 (150)
------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES...................................... 7,069 11,567
NET CASH USED BY INVESTING ACTIVITIES:
Increase in notes receivable from officers and directors................... (336) --
Collection of note receivable from officer and director.................... -- 167
Purchase of available-for-sale investments................................. (527) (462)
Proceeds from sale of investments.......................................... -- 1,359
Proceeds from sale of property and equipment............................... 4,276 44,678
Purchase of property and equipment......................................... (83,440) (218,738)
Property development costs................................................. (6,141) (18,379)
------------ ------------
NET CASH USED BY INVESTING ACTIVITIES.......................................... (86,168) (191,375)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from short-term borrowings........................................ 14,500 60,000
Payments of short-term borrowings.......................................... (14,500) (60,000)
Proceeds from long-term borrowings......................................... 160,347 431,290
Payments of long-term borrowings........................................... (61,864) (259,884)
Purchase of senior notes for treasury...................................... (796) --
Redemption of preferred stock, net......................................... -- (40,809)
Proceeds from sale of preferred stock, net................................. -- 73,475
Proceeds from exercise of common stock warrants............................ 345 --
Payment of loan and offering fees.......................................... (2,084) (38,535)
Payment of preferred dividends............................................. (264) --
Other...................................................................... (70) (162)
------------ ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES...................................... 95,614 165,375
NET CHANGE IN CASH AND CASH EQUIVALENTS........................................ 16,515 (14,433)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD................................. 207 16,722
------------ ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD....................................... $ 16,722 $ 2,289
============ ============
SUPPLEMENTAL DISCLOSURE OF INTEREST PAID....................................... $ 7,011 $ 23,063
============ ============
</TABLE>
See accompanying notes to consolidated financial statements
F-6
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. GENERAL AND ACCOUNTING POLICIES
ORGANIZATION AND NATURE OF OPERATIONS--The consolidated financial statements
include the accounts of Gothic Energy Corporation, a "holding company", and its
subsidiary, Gothic Production Corporation ("Gothic Production") since its
formation in April of 1998, (collectively referred to as the ''Company''). All
significant intercompany balances and transactions have been eliminated. The
Company is primarily engaged in the business of acquiring, developing and
exploiting natural gas and oil reserves in Oklahoma, Texas, New Mexico and
Kansas. Substantially all of the Company's natural gas and oil production is
being sold regionally in the ''spot market'' or under short-term contracts, not
extending beyond twelve months.
USE OF ESTIMATES--The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. In addition,
accrued and deferred lease operating expenses, gas imbalance liabilities,
natural gas and oil reserves (see note 15) and the tax valuation allowance (see
note 8) also include significant estimates which, in the near term, could
materially differ from the amounts ultimately realized or incurred.
CASH EQUIVALENTS--Cash equivalents include cash on hand, amounts held in
banks, money market funds and other highly liquid investments with a maturity of
three months or less at date of purchase.
CONCENTRATION OF CREDIT RISK--Financial instruments which potentially subject
the Company to concentrations of credit risk consist principally of cash, cash
equivalents and trade receivables. The Company's accounts receivable are
primarily from the purchasers (See Note 11--Major Customers) of natural gas and
oil products and exploration and production companies which own interests in
properties operated by the Company. The industry concentration has the potential
to impact the Company's overall exposure to credit risk, either positively or
negatively, in that the customers may be similarly affected by changes in
economic, industry or other conditions. The Company generally does not require
collateral from customers. The cash and cash equivalents are with major banks or
institutions with high credit ratings. At December 31, 1998, the Company had a
concentration of cash of $2,300,000 with two banks, which was in excess of
federally insured limits.
FAIR VALUE OF FINANCIAL INSTRUMENTS--The following disclosure of the estimated
fair value of financial instruments is made in accordance with the requirements
of Statement of Financial Accounting Standards No. 107, ''Disclosures About Fair
Value of Financial Instruments''. The estimated fair value amounts have been
determined by the Company using available market information. Considerable
judgment is required in interpreting market data to develop the estimates of
fair value. The use of different market assumptions or valuation methodologies
may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities
approximate fair values due to the short-term maturities of these instruments.
The Company estimates the fair value of its 11 1/8% Senior Secured Notes and its
14 1/8% Senior Secured Discount Notes using estimated market prices. The
Company's carrying amount for such debt at December 31, 1998, was $235,000,000
and $66,179,000, respectively, compared to an approximate fair value of
$178,600,000 and $33,300,000, respectively. The carrying value of other long-
term debt approximates its fair value as interest rates are primarily variable,
based on prevailing market rates.
HEDGING ACTIVITIES--The Company has only limited involvement with derivative
financial instruments, as defined in Statement of Financial Accounting Standards
No. 119 ''Disclosure About Derivative Financial Instruments and Fair Value of
Financial Instruments'', and does not use them for trading purposes. The
Company's objective is to hedge a portion of its exposure to price volatility
from producing natural gas. These arrangements may expose the Company to credit
risk from its counterparty.
F-7
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
During 1997 and 1998, the Company entered into agreements with a gas purchaser
to hedge a portion of its monthly gas production in an effort to reduce the
effects of the volatility of the price of natural gas on the Company's
operations, and to adhere to requirements called for under the Company's Credit
Facility. Under the agreements, the difference between the current value of the
Company's gas sales, based upon the spot market price, and a fixed price was
received or paid by the Company.
At December 31, 1998, the Company had swap agreements relating to the sale of
60,000 Mcf per day at a "floor" price of $2.10 per Mcf expiring on January 31,
1999. During 1998, all swap contracts relating to the sale of natural gas were
designated as hedges; therefore, any gains and losses on such contracts were
included in natural gas and oil sales in 1998 when the gas was sold.
In February 1998, the Company entered into swap agreements related to the sale
of 30,000 Mcf per day for the month of March 1998 at $2.16 per Mcf and 62,000
Mcf per day during the period April 1, 1998 through October 31, 1998 at an
average price of $2.09 per Mcf. Of this 62,000 Mcf per day, 25,000 Mcf was
subject to a ''call spread'' agreement which provided that the Company receive
additional payments for 25,000 Mcf if the actual sales price of natural gas was
between $2.30 and $2.70 per Mcf during the period. The swap agreements for the
month of March 1998 and the period April through October 1998 covered
approximately 55% and 69%, respectively, of the Company's natural gas production
at that time.
NATURAL GAS AND OIL PROPERTIES--The Company accounts for its natural gas and
oil exploration and development activities using the full cost method of
accounting prescribed by the Securities and Exchange Commission (''SEC'').
Accordingly, all productive and non-productive costs incurred in connection with
the acquisition, exploration and development of natural gas and oil reserves are
capitalized and depleted using the units-of-production method based on proved
natural gas and oil reserves. The Company capitalizes costs including salaries
and related fringe benefits of employees and/or consultants directly engaged in
the acquisition, exploration and development of natural gas and oil properties,
as well as other directly identifiable general and administrative costs
associated with such activities. Such costs do not include any costs related to
production, general corporate overhead, or similar activities.
The Company's natural gas and oil reserves are estimated annually by
independent petroleum engineers. The Company's calculation of depreciation,
depletion and amortization (''DD&A'') includes estimated future expenditures to
be incurred in developing proved reserves and estimated dismantlement and
abandonment costs, net of salvage values. The average composite rate used for
DD&A of natural gas and oil properties was $.72 and $.91 per Mcfe in 1997 and
1998, respectively. DD&A of natural gas and oil properties amounted to
$5,530,000 and $23,600,000 in 1997 and 1998, respectively.
In the event the unamortized cost of natural gas and oil properties being
amortized exceeds the full cost ceiling as defined by the SEC, the excess is
charged to expense in the period during which such excess occurs. The full cost
ceiling is based principally on the estimated future discounted net cash flows
from the Company's natural gas and oil properties. The Company recorded a
$76,000,000 provision for impairment of natural gas and oil properties during
the year ended December 31, 1998. No such provision was recorded in 1997. As
discussed in Note 15, estimates of natural gas and oil reserves are imprecise.
Changes in the estimates or declines in natural gas and oil prices could cause
the Company in the near-term to reduce the carrying value of its natural gas and
oil properties further.
Sales and abandonments of properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized unless a significant amount of
reserves is involved. Since all of the Company's natural gas and oil properties
are located in the United States, a single cost center is used.
EQUIPMENT, FURNITURE AND FIXTURES--Equipment, furniture and fixtures are
stated at cost and are depreciated on the straight-line method over their
estimated useful lives which range from three to seven years.
DEBT ISSUANCE COSTS--Debt issuance costs, including the original issue
discount, associated with the Company's 11 1/8% Senior Secured Notes Due 2005,
the 14 1/8% Senior Secured Discount Notes Due 2006 and the
F-8
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
12 1/4% Senior Notes Due 2004, redeemed in April 1998, are amortized and
included in interest expense using the effective interest method over the term
of the notes. The unamortized portion of debt issuance costs associated with the
Company's Credit Facility is included in other assets and amortized and included
in interest expense using the straight-line method over the term of the
Facility. Amortization of debt issuance costs for the years ended December 31,
1997 and 1998 amounted to $1,804,000 and $1,994,000, respectively.
NATURAL GAS AND OIL SALES AND NATURAL GAS BALANCING--The Company uses the
sales method for recording natural gas sales. The Company's oil and condensate
production is sold, title passed, and revenue recognized at or near its wells
under short-term purchase contracts at prevailing prices in accordance with
arrangements which are customary in the oil industry. Sales of gas applicable to
the Company's interest in producing natural gas and oil leases are recorded as
revenues when the gas is metered and title transferred pursuant to the gas sales
contracts covering its interest in gas reserves. During such times as the
Company's sales of gas exceed its pro rata ownership in a well, such sales are
recorded as revenues unless total sales from the well have exceeded the
Company's share of estimated total gas reserves underlying the property at which
time such excess is recorded as a gas imbalance liability. At December 31, 1998,
total sales exceeded the Company's share of estimated total gas reserves on 35
wells by $3,119,000 (1,714,000 Mcf), based on the year end ''spot market'' price
of natural gas. The gas imbalance liability has been classified in the balance
sheet as non-current, as the Company does not expect to settle the liability
during the next twelve months.
The Company has recorded deferred charges for estimated lease operating
expenses incurred in connection with its underproduced gas imbalance position.
At December 31, 1998, cumulative total gas sales volumes for underproduced wells
were less than the Company's pro-rata share of total gas production from these
wells by 4,799,000 Mcf, resulting in prepaid lease operating expenses of
$1,584,000, which are included in other assets in the accompanying balance
sheet. The rate used to calculate the deferred charge is the average annual
production costs per Mcf.
The Company has recorded accrued charges for estimated lease operating
expenses incurred in connection with its overproduced gas imbalance position. At
December 31, 1998, cumulative total gas sales volumes for overproduced wells
exceeded the Company's pro-rata share of total gas production from these wells
by 2,543,000 Mcf, resulting in accrued lease operating expenses of $839,000,
which are included in the gas imbalance liability in the accompanying balance
sheet. The rate used to calculate the accrued liability is the average annual
production costs per Mcf.
INCOME TAXES--The Company applies the provisions of Statement of Financial
Accounting Standards No. 109, ''Accounting for Income Taxes'' (''SFAS No.
109''). Under SFAS No. 109, deferred tax liabilities or assets arise from the
temporary differences between the tax basis of assets and liabilities, and their
basis for financial reporting, and are subject to tests of realizability in the
case of deferred tax assets. A valuation allowance is provided for deferred tax
assets to the extent realization is not judged to be more likely than not.
LOSS PER COMMON SHARE--Loss per common share before extraordinary item and
loss per common share are computed in accordance with Statement of Financial
Accounting Standards No. 128 (''FAS 128''). Presented on the Consolidated
Statements of Operations is a reconciliation of loss available to common
shareholders. There is no difference between actual weighted average shares
outstanding, which are used in computing basic loss per share and diluted
weighted average shares, which are used in computing diluted loss per share
because the effect of outstanding options and warrants would be antidilutive.
(See Notes 6 and 7 for options and warrants outstanding during 1997 and 1998 and
options still outstanding at December 31, 1998, which were not included in the
computation of diluted loss per share.)
STOCK BASED COMPENSATION--The Company applies Accounting Principles Board
Opinion No. 25 in accounting for its stock option plans. Under this standard, no
compensation expense is recognized for grants of options which include an
exercise price equal to or greater than the market price of the stock on the
date of grant. Accordingly, based on the Company's grants in 1997 and 1998, no
compensation expense has been recognized.
F-9
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
RECENTLY ISSUED FINANCIAL ACCOUNTING PRONOUNCEMENTS - In June 1997, the
Financial Accounting Standards Board ("FASB") issued FAS 130, "Reporting
Comprehensive Income", and FAS 131, "Disclosures about Segments of an Enterprise
and Related Information," effective for fiscal years beginning after December
15, 1997. The Company adopted FAS 130 in 1998. FAS 131 does not effect the
Company as the Company operates in only one business segment in the United
States.
In June 1998, the FASB issued Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities." FAS 133 is effective for fiscal years
beginning after June 15, 1999, but earlier application is permitted as of the
beginning of any fiscal quarter subsequent to June 15, 1998. FAS 133
standardizes the accounting for derivative instruments by requiring that all
derivatives be recognized as assets and liabilities and measured at fair value.
Upon the Statement's initial application, all derivatives are required to be
recognized in the statement of financial position as either assets or
liabilities and measured at fair value. In addition, all existing hedging
relationships must be designated, reassessed, documented and the accounting
conformed to the provisions of FAS 133. Due to the limited nature of the
Company's hedging activities, the Company does not expect the adoption of FAS
133 to have a significant impact on its financial position or results of
operations when adopted.
NOTE 2. GOING CONCERN
The Company incurred a significant net loss in 1998, due principally to a
decline in commodity prices during the year. This commodity price decline
required the Company to write down the carrying value of its natural gas and oil
properties by $76,000,000. More significantly, the commodity price decline
affects the ongoing revenues and cash flows of the Company.
This decline in revenues has the result of causing the Company to be in
default with interest coverage covenants under its Credit Facility. The
interest coverage test is made on a quarterly basis and was required to be 1.5
to 1.0 at the end of each quarter through December 31, 1998. Beginning with the
quarter ending March 31, 1999, the minimum interest coverage ratio shall not be
less than 2.0 to 1.0.
The Company did not comply with the minimum interest coverage ratio for the
quarters ended June 30, 1998, September 30, 1998, and December 31, 1998. The
Company requested and Bank One, Texas, N.A. granted waivers for each of the
violations. Based on current commodity prices, the Company does not expect to be
in compliance with these covenants during 1999. While the Company expects and
intends to utilize the Credit Facility to meet interest and other working
capital requirements, if necessary, the Company does not have a written
commitment from the bank indicating that the bank will continue to grant
waivers, if necessary, for non-compliance with the covenant during 1999.
Accordingly, there is no assurance that the Company will be able to borrow
funds, if necessary, under its Credit Facility.
It is the intention of the Company to continue to spend available cash flow
(EBITDA less cash interest payable on Senior Secured Notes) on the development
of natural gas and oil properties. With commodity prices continuing to reflect
the excess of supply in the overall system, the prices of natural gas continue
to be depressed. These depressed prices affect the Company's ability to
generate sufficient reserves to replace current production. Absent an overall
increase in commodity prices, the Company will continue to be limited in its
ability to increase production and related cash flow to a level sufficient to
meet its ongoing financial covenants under its Credit Facility.
NOTE 3. NATURAL GAS AND OIL PROPERTY ACQUISITIONS AND DISPOSITIONS WRITEDOWN
1998 Transactions
AMOCO ACQUISITION - On January 23, 1998, the Company completed the acquisition
from Amoco Production Company ("Amoco"), a subsidiary of Amoco Corporation, of
certain producing natural gas properties, located in the Anadarko and Arkoma
Basins of Oklahoma. The purchase price was $240,845,000. Amoco also received
warrants to purchase 1,500,000 shares of the Company's common stock for $3.00
per share, with an estimated fair value at the date of acquisition of
approximately $1,155,000, and certain producing properties having a value of
approximately $1,800,000. The acquisition and related fees and expenses were
financed through an amended and restated credit facility with Bank One, Texas,
NA. ("Bank One") (See Note 5) and the issuance of
F-10
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
$37,000,000 of Series A Preferred Stock (see Note 6). The Company acquired
interests in 821 gross wells and assumed operations of 291 of the properties.
The Company also acquired approximately 10,000 net undeveloped acres located
throughout the Anadarko Basin as well as substantial mineral and overriding
royalty interests. In connection with the Amoco Acquisition, the Company entered
into a transition agreement which provided for a payment of $540,000 per month
to be made to Amoco commencing January 1, 1998 for the operation and
administration of the properties acquired. This transition payment was made by
the Company for January and February 1998. Since March 1, 1998, the Company has
operated the properties. The transition agreement established effective control
for the Company over the properties, and accordingly, January 1, 1998 has been
used as the effective date for the Amoco Acquisition for accounting purposes.
CHESAPEAKE DISPOSITIONS - On April 27, 1998, the Company sold to Chesapeake
Energy Corporation ("Chesapeake") for $20,000,000, a 50% interest in its natural
gas and oil properties in the Arkoma basin and sold for $10,500,000, a 50%
participation right in substantially all of the Company's undeveloped acreage
(see Note 4, "The Chesapeake Transaction"). In addition, in a separate
transaction, on May 28, 1998, the Company sold to Chesapeake for $6,000,000 its
interest in certain natural gas and oil properties.
SYCAMORE SYSTEM DISPOSITION - During January 1998 and concurrent with the
Amoco Acquisition, the Company sold the Sycamore System and other gas systems
acquired from Amoco for $6,000,000.
1997 TRANSACTIONS
HS Acquisition--On September 9, 1997, the Company acquired from two affiliates
of HS Resources, Inc. (''HS'') various working interests in a total of
approximately 250 natural gas and oil producing wells located in New Mexico and
Oklahoma. The purchase price for the properties was approximately $27,500,000,
plus the transfer of certain producing properties owned by the Company having a
value of less than $1,000,000. The New Mexico properties acquired from HS
consist of working interests in approximately 100 wells located in four fields
in Chavez and Eddy counties in the Delaware/Permian basin. The Company operates
92 of these wells. The Oklahoma properties acquired from HS consist of working
interests in approximately 150 wells located in various fields in the Anadarko
Basin where the Company has other operations. The Company operates 50 of these
wells.
KERR-MCGEE ACQUISITION--On August 12, 1997, the Company acquired from Kerr-
McGee Corporation various working interests and royalty interests in 162 wells
located in Canadian and Grady Counties, Oklahoma for approximately $3,600,000.
The Company is the operator of 16 of these wells.
FINA ACQUISITION--On May 15,1997, the Company acquired from Fina Oil and
Chemical Company various working interests in 20 producing gas wells located in
Beaver County, Oklahoma and Clarke County, Kansas. The purchase price was
$3,350,000. The Company operates all 20 producing wells.
NORSE ACQUISITION--On February 18, 1997, the Company acquired from Norse
Exploration, Inc., and Norse Pipeline, Inc., various working interests in 11
natural gas and oil producing properties and, through the acquisition of the
outstanding capital stock of Norse Pipeline, Inc., its 40.09% general
partnership interest in the Sycamore Gas System (the ''Sycamore System''), an
Oklahoma gathering system, processing plant and storage facility. The natural
gas and oil wells and the gathering system are located in the Springer Field in
Carter County, Oklahoma. The total purchase price was $10,750,000, plus two-year
warrants to purchase 200,000 shares of the Company's Common Stock at a per share
exercise price of $2.50. The estimated fair value of such warrants at the date
of acquisition was approximately $254,000.
HUFFMAN ACQUISITION--The Company also on February 18, 1997, acquired from H.
Huffman & Company, an Oklahoma limited partnership, various working interests in
13 natural gas and oil producing properties and an additional 10.97% interest in
the Sycamore System. The natural gas and oil wells are located in the same
producing area as the properties acquired from Norse. The total purchase price
for the assets acquired was $3,950,000.
HORIZON ACQUISITION--The Company also acquired, on February 18, 1997, from
Horizon Gas Partners, L.P. and HSRTW, Inc., various working and royalty
interests in approximately 100 natural gas and oil producing
F-11
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
properties. The producing properties are located in Major and Blaine counties of
Oklahoma. The purchase price was $10,000,000.
1997 PROPERTY DISPOSITIONS--Management of the Company reviews the properties
acquired and from time to time disposes of wells that are deemed to be
unprofitable, fail to meet management's operating requirements or, under certain
circumstances, are operated by other parties. During 1997, the Company disposed
of various interests in an aggregate of approximately 450 properties for a total
sales price of $3,993,000. All of such proceeds were used for working capital
purposes.
The following reflects the unaudited proforma results of operations assuming
the 1997 and 1998 acquisitions and dispositions had all been consummated on
January 1, 1997.
<TABLE>
<CAPTION>
1997 1998
----------- ------------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C>
Revenues................................................................... $ 70,606 $ 51,110
Operating income (loss).................................................... 24,723 (62,612)
Loss before extraordinary item............................................. (10,828) (97,922)
Net loss................................................................... (18,714) (140,075)
Basic and diluted loss per common share.................................... (1.14) (8.61)
</TABLE>
NOTE 4. RECAPITALIZATION
On April 27, 1998, the Company completed a series of transactions which
recapitalized the Company through (i) the transfer of all of the Company's
natural gas and oil interests in natural gas and oil properties to Gothic
Production , (ii) the issuance by the Company of shares of its Series B
Preferred Stock, (iii) the sale of interests in natural gas and oil properties
for $20,000,000, (iv) the execution of a participation agreement granting a 50%
interest in substantially all of the Company's undeveloped acreage for
consideration of $10,500,000, (v) the issuance by the Company of its 14 1/8 %
Senior Secured Discount Notes Due 2006, (vi) the issuance by Gothic Production
of its 11 1/8% Senior Secured Notes Due 2005 and (vii) the repayment and/or
refinancing of substantially all of the Company's then existing debt and
preferred securities (together the "Recapitalization"). Certain transactions
undertaken in the Recapitalization are described in greater detail below.
CORPORATE RESTRUCTURING
Gothic Production was organized as a wholly owned subsidiary of the Company
in March 1998. At the closing of the Recapitalization, the Company transferred
to Gothic Production its ownership of all its natural gas and oil properties.
The natural gas and oil assets collateralize Gothic Production's obligations
under a credit facility with Bank One (the "Credit Facility") and the 11 1/8%
Senior Secured Notes.
THE CHESAPEAKE TRANSACTION
On April 27, 1998, the Company completed several agreements with Chesapeake,
pursuant to which the Company (i) executed a participation agreement granting a
50% interest in substantially all of Gothic Production 's undeveloped acreage
for consideration of $10,500,000, (ii) sold for $20,000,000, a 50% interest in
Gothic Production's natural gas and oil properties in the Arkoma basin, and
(iii) sold for $39,500,000, 50,000 shares of the Company's Series B Preferred
Stock, having a liquidation value of $50,000,000, and ten-year warrants to
purchase, at an exercise price of $0.01 per share, 2,439,246 shares of the
Company's Common Stock. Such warrants had an estimated fair value of $4,879,000
on the date of issuance.
F-12
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
FINANCING TRANSACTIONS
The following financing transactions were also completed as part of the
Recapitalization:
<TABLE>
<CAPTION>
<S> <C>
11 1/8% Senior Secured Notes Due 2005.................. Gothic Production sold $235,000,000 principal amount of
11 1/8% Senior Secured Notes
14 1/8% Senior Secured Discount Notes Due 2006......... The Company sold approximately $60,155,000 initial principal amount
($104,000,000 principal amount at maturity) of 14 1/8 % Senior Secured
Discount Notes due 2006 collateralized by the outstanding capital stock of
Gothic Production held by the Company and seven-year common stock purchase
warrants exercisable at $2.40 per share to purchase 825,000 shares of
Common Stock.
Series B Preferred Stock and Warrants.................. The Company sold for $39,500,000, 50,000 shares of its Series B Preferred
Stock, having a liquidation preference of $50,000,000, and ten-year common
stock purchase warrants exercisable at $0.01 per share to purchase
2,439,246 shares of Common Stock.
Arkoma Property Sales.................................. The Company sold for $20,000,000, a 50% interest in its natural gas and
oil properties in the Arkoma basin.
Credit Facility........................................ Gothic Production, with the Company as guarantor, entered into the Credit
Facility with Bank One which provides among other things, borrowing
availability of approximately $25,000,000 (See Note 5).
REPAYMENTS AND REDEMPTIONS
The net proceeds of approximately $350,500,000 from the Recapitalization
described above were applied to repay or redeem the following:
12 1/4% Senior Notes................................... These notes, outstanding in the principal amount of approximately
$99,300,000, were redeemed for approximately $102,300,000, inclusive of a
1% redemption premium and accrued interest.
Series A Preferred Stock............................... These shares were redeemed for $38,700,000, inclusive of a 1% redemption
premium and payment-in-kind dividends through the redemption date.
Credit Facility........................................ An aggregate of $206,400,000 of indebtedness owing to Bank One was repaid.
</TABLE>
F-13
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 5. FINANCING ACTIVITIES
CREDIT FACILITY
On April 27, 1998, in connection with the Recapitalization of the Company,
the Company repaid $206,400,000 of indebtedness owing to Bank One, including
accrued interest. Additionally, Gothic Production, with the Company as
guarantor, entered into the Credit Facility.
The Credit Facility consists of a revolving line of credit, with an initial
Borrowing Base of $25,000,000. Borrowings initially are limited to being
available for the acquisition and development of natural gas and oil properties,
letters of credit and general corporate purposes. The Borrowing Base will be
redetermined at least semi-annually and was initially redetermined on October 1,
1998. Upon completion of the October 1, 1998 redetermination, the borrowing base
remained at $25,000,000. The principal is due at maturity, April 30, 2001.
Interest is payable monthly calculated at the Bank One Base Rate, as determined
from time to time by Bank One. Gothic Production may elect to calculate interest
under a London Interbank Offered Rate ("LIBOR") plus 1.5% (or up to 2.0% in the
event the loan balance is greater than 75% of the Borrowing Base). Gothic
Production is required to pay a commitment fee on the unused portion of the
Borrowing Base equal to 1/2 of 1% per annum. Under the Credit Facility, Bank One
holds first priority liens on substantially all of the natural gas and oil
properties of Gothic Production, whether currently owned or hereafter acquired.
As of December 31, 1998, Gothic Production had no amounts outstanding under the
Credit Facility.
The Credit Facility requires, among other things, semi-annual engineering
reports covering oil and natural gas reserves on the basis of which semi-annual
and other redeterminations of the borrowing base and monthly commitment
reduction are made. The Credit Facility also includes various affirmative and
negative covenants, including, among others, (i) prohibitions against additional
indebtedness unless approved by the lenders, subject to certain exceptions, (ii)
prohibitions against the creation of liens on the assets of the Company, subject
to certain exceptions, (iii) prohibitions against cash dividends, (iv)
prohibitions against hedging positions unless consented to by Bank One, (v)
prohibitions on asset sales, subject to certain exceptions, (vi) restrictions on
mergers or consolidations, (vii) a requirement to maintain a ratio of current
assets to current liabilities of 1.0 to 1.0, and (viii) a minimum interest
coverage ratio of not less than 1.5 to 1.0 as of the end of each quarter
calculated quarterly beginning with the quarter ending June 30, 1998 and
increasing to 2.0 to 1.0 as of the end of each quarter beginning with the
quarter ending March 31, 1999. The Credit Facility includes covenants
prohibiting cash dividends, distributions, loans or advances to third parties,
subject to certain exceptions. If Gothic Production is required to purchase or
redeem any portion of the 11 1/8% Senior Secured Notes, or if any portion of the
11 1/8% Senior Secured Notes become due, the Borrowing Base is subject to
reduction. Gothic Production is required to escrow interest payments due on the
Senior Secured Notes at such times as its borrowings under the Credit Facility
equal or exceed 75% of the Borrowing Base. Events of default include the non-
payment of principal, interest or fees, a default under other outstanding
indebtedness, a breach of the representations and warranties contained in the
loan agreement, material judgements, bankruptcy or insolvency, a default under
certain covenants not cured within a grace period, and a change in the
management or control of the Company. Gothic Production was not in compliance
with the minimum interest coverage of at least 1.5 to 1.0 during 1998. Gothic
Production received waivers of compliance with the covenant for the violations
in 1998.
11-1/8% SENIOR SECURED NOTES DUE 2005
The 11-1/8% Senior Secured Notes Due 2005 ("Senior Secured Notes") issued
by Gothic Production are fully and unconditionally guaranteed by the Company.
The aggregate principal amount of Senior Secured Notes outstanding is
$235,000,000 issued under an indenture dated April 21, 1998 (the "Senior Note
Indenture"). The Senior Secured Notes bear interest at 11-1/8% per annum payable
semi-annually in cash in arrears on May 1 and November 1 of each year commencing
November 1, 1998. The Senior Secured Notes mature on May 1, 2005. All of the
obligations of Gothic Production under the Senior Secured Notes are
collateralized by a second priority lien on substantially all of Gothic
Production's natural gas and oil properties, subject to certain permitted liens.
Gothic Production may, at its option, at any time on or after May 1, 2002,
redeem all or any portion of the Senior Secured Notes at redemption prices
decreasing from 105.563%, if redeemed in the 12-month period
F-14
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
beginning May 1, 2002, to 100.00% if redeemed in the 12-month period beginning
May 1, 2004 and thereafter plus, in each case, accrued and unpaid interest
thereon. Notwithstanding the foregoing, at any time prior to May 1, 2002, Gothic
Production may, at its option, redeem all or any portion of the Senior Secured
Notes at the Make-Whole Price (as defined in the Senior Note Indenture) plus
accrued or unpaid interest to the date of redemption. In addition, in the event
Gothic Production consummates one or more Equity Offerings (as defined in the
Senior Note Indenture) on or prior to May 1, 2001, Gothic Production, at its
option, may redeem up to 33-1/3% of the aggregate principal amount of the Senior
Secured Notes with all or a portion of the aggregate net proceeds received by
Gothic Production from such Equity Offering or Equity Offerings at a redemption
price of 111.125% of the aggregate principal amount of the Senior Secured Notes
so redeemed, plus accrued and unpaid interest thereon to the redemption date;
provided, however, that following such redemption, at least 66-2/3% of the
original aggregate principal amount of the Senior Secured Notes remains
outstanding.
Following the occurrence of any Change of Control (as defined in the Senior
Note Indenture), Gothic Production will offer to repurchase all outstanding
Senior Secured Notes at a purchase price equal to 101% of the aggregate
principal amount of the Senior Secured Notes, plus accrued and unpaid interest
to the date of repurchase.
The Senior Note Indenture under which the Senior Secured Notes were issued
contains certain covenants limiting Gothic Production with respect to or
imposing restrictions on the incurrence of additional indebtedness, the payment
of dividends, distributions and other restricted payments, the sale of assets,
creating, assuming or permitting to exist any liens (with certain exceptions) on
its assets, mergers and consolidations (subject to meeting certain conditions),
sale leaseback transactions, and transactions with affiliates, among other
covenants.
Events of default under the Senior Note Indenture include the failure to
pay any payment of principal or premium when due, failure to pay for 30 days any
payment of interest when due, failure to make any optional redemption payment
when due, failure to perform any covenants relating to mergers or
consolidations, failure to perform any other covenant or agreement not remedied
within 30 days of notice from the Trustee under the Senior Note Indenture or the
holders of 25% in principal amount of the Senior Secured Notes then outstanding,
defaults under other indebtedness of Gothic Production or the Company causing
the acceleration of the due date of such indebtedness having an outstanding
principal amount of $10,000,000 or more, the failure of Gothic Production to be
a wholly owned subsidiary of the Company, and certain other bankruptcy and other
court proceedings, among other matters.
14 1/8% SENIOR SECURED DISCOUNT NOTES DUE 2006
The 14 1/8% Senior Secured Discount Notes Due 2006 (the "Discount Notes")
were issued by the Company under an indenture (the "Discount Note Indenture")
dated April 21, 1998 in such aggregate principal amount and at such rate of
interest as generated gross proceeds of $60,155,000. The Company also issued
seven-year warrants to purchase, at an exercise price of $2.40 per share,
825,000 shares of the Company's Common Stock with the Discount Notes. The
estimated fair value of such warrants was approximately $554,000 on the date of
issuance. The Discount Notes were issued at a substantial discount from their
principal amount and accrete at a rate per annum of 14 1/8%, compounded semi-
annually, to an aggregate principal amount of $104,000,000 at May 1, 2002.
Thereafter, the Discount Notes accrue interest at the rate of 14 1/8% per annum,
payable in cash semi-annually in arrears on May 1 and November 1 of each year,
commencing November 1, 2002. The Discount Notes mature on May 1, 2006. The
Discount Notes are collateralized by a first priority lien against the
outstanding shares of capital stock of Gothic Production.
The Company may, at its option, at any time on or after May 1, 2003, redeem
all or any portion of the Discount Notes at redemption prices decreasing from
107.063% if redeemed in the 12-month period beginning May 1, 2003 to 100.00% if
redeemed in the 12-month period beginning May 1, 2005 and thereafter plus, in
each case, accrued and unpaid interest thereon. Notwithstanding the foregoing,
at any time prior to May 1, 2003, the Company may, at its option, redeem all or
any portion of the Discount Notes at the Make-Whole Price (as defined in the
Discount Note Indenture) plus accrued or unpaid interest to the date of
redemption. In addition, in the event the Company consummates one or more
Equity Offerings (as defined in the Discount Note Indenture) on or prior to May
1, 2001, the Company, at its option, may redeem up to 33-1/3% of the Accreted
Value (as defined in the
F-15
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Discount Note Indenture) of the Discount Notes with all or a portion of the
aggregate net proceeds received by the Company from such Equity Offering or
Equity Offerings at a redemption price of 114.125% of the Accreted Value of the
Discount Notes so redeemed, plus accrued and unpaid interest thereon to the
redemption date; provided, however, that following such redemption, at least 66-
2/3% of the Accreted Value of the Discount Notes remains outstanding.
Following the occurrence of any Change of Control (as defined in the
Discount Note Indenture), the Company will offer to repurchase all outstanding
Discount Notes at a purchase price equal to, prior to May 1, 2002, 101% of the
Accreted Value of the Discount Notes on the date of repurchase, plus accrued and
unpaid interest to the date of repurchase and thereafter, 101% of the aggregate
principal amount of the Discount Notes plus accrued and unpaid interest and
Liquidated Damages, if any, to the date of repurchase.
The Discount Note Indenture under which the Discount Notes were issued
contains certain covenants limiting the Company with respect to or imposing
restrictions on the incurrence of additional indebtedness, the payment of
dividends, distributions and other restricted payments, the sale of assets,
creating, assuming or permitting to exist any liens (with certain exceptions) on
its assets, mergers and consolidations (subject to meeting certain conditions),
sale leaseback transactions, and transactions with affiliates, among other
covenants.
Events of default under the Discount Note Indenture include the failure to
pay any payment of principal or premium when due, failure to pay for 30 days any
payment of interest when due, failure to make any optional redemption payment
when due, failure to perform any covenants relating to mergers or
consolidations, failure to perform any other covenant or agreement not remedied
within 30 days of notice from the Trustee under the Discount Note Indenture or
the holders of 25% in principal amount of the Discount Notes then outstanding,
defaults under other indebtedness of the Company causing the acceleration of the
due date of indebtedness having an outstanding principal amount of $10,000,000
or more, the failure of Gothic Production to be a wholly owned subsidiary of the
Company, and certain other bankruptcy and other court proceedings, among other
matters.
12 1/4% SENIOR NOTES DUE 2004
On September 9, 1997, the Company issued $100,000,000 principal amount of
12 1/4% Senior Notes Due 2004. On January 23, 1998, the Company obtained
consents to the amendment of the Company's outstanding 12 1/4% Senior Notes. Of
the consideration given for the consents, $15,000,000 was paid by the issuance
of 15,000 shares of Series A Preferred Stock (see Note 4) and $5,800,000 was
paid in cash. These consent fees totaling $20,800,000 together with unamortized
discount and debt issue costs of $5,300,000 and a $1,000,000 early redemption
premium related to the 12 1/4 % Senior Notes have all been written off as an
extraordinary loss during the quarter ended March 31, 1998, as the terms of the
consent constitute a substantial modification of the terms of the 12 1/4% Senior
Notes.
In connection with obtaining the consents, the Company agreed to raise a
total of at least $45,000,000 of equity by February 28, 1998 and at least
$100,000,000 from the sale of senior subordinated notes by March 31, 1998. In
the event the Company failed to comply with either of these agreements, until
such conditions were met, the interest rate on the 12 1/4% Senior Notes
increased by 1% until the additional equity was raised and also by 1% until the
senior subordinated notes were sold, provided, if the senior subordinated notes
were not sold by September 30, 1998, the interest rate on the 12 1/4% Senior
Notes increased by 2% until such senior subordinated notes were sold. Such
additional equity was not sold by February 28, 1998. Pursuant to such
consents, the holders of the 12 1/4% Senior Notes agreed that the Company had
the right to redeem such notes through March 31, 1998 at 100% of the principal
amount thereof and at 101% of the principal amount thereof through April 30,
1998 when such redemption right expired. On April 27, 1998, as part of the
Company's Recapitalization, the Senior Notes and all accrued interest were paid
in full. (See Note 4)
F-16
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
NOTE 6. STOCKHOLDERS' EQUITY
PREFERRED STOCK OFFERINGS
Series B Preferred Stock and Warrants. On April 27, 1998, as part of the
Recapitalization, the Company issued 50,000 shares of Series B Preferred Stock
with an aggregate liquidation value of $50,000,000, and ten-year warrants to
purchase, at an exercise price of $0.01 per share, 2,439,246 shares of the
Company's Common Stock. The estimated fair value of such warrants was
$4,879,000 on the date of issuance. The Series B Preferred Stock, with respect
to dividend rights and rights on liquidation, winding-up and dissolution, ranks
senior to all classes of Common Stock of the Company and senior to all other
classes or series of any class of preferred stock. Holders of the Series B
Preferred Stock are entitled to receive dividends payable at a rate per annum of
12% of the aggregate Liquidation Preference of the Series B Preferred Stock
payable in additional shares of Series B Preferred Stock; provided that after
April 1, 2000, at the Company's option, it may pay the dividends in cash.
Dividends are cumulative and will accrue from the date of issuance and are
payable quarterly in arrears.
At any time prior to April 30, 2000, the Series B Preferred Stock may be
redeemed at the option of the Company in whole or in part, at 105% of the
Liquidation Preference payable in cash out of the net proceeds from a public or
private offering of any equity security, plus accrued and unpaid dividends
(whether or not declared), which shall also be paid in cash. At any time on or
after April 30, 2000, the Series B Preferred Stock may be redeemed at the option
of the Company in whole or in part, in cash at a redemption price equal to the
Liquidation Preference.
The Company is required to redeem the Series B Preferred Stock on June 30,
2008 at a redemption price equal to the Liquidation Preference payable in cash
or, at the option of the Company, in shares of Common Stock valued at the fair
market value at the date of such redemption.
Except as required by Oklahoma law, the holders of Series B Preferred Stock
are not entitled to vote on any matters submitted to a vote of the stockholders
of the Company.
The Series B Preferred Stock is convertible at the option of the holders on
or after April 30, 2000 into the number of fully paid and non-assessable shares
of Common Stock determined by dividing the Liquidation Preference by the higher
of (i) $2.04167 or (ii) the fair market value on the date the Series B Preferred
Stock is converted. Notwithstanding the foregoing, no holder or group shall be
able to convert any shares of Series B Preferred Stock to the extent that the
conversion of such shares would cause such holder or group to own more than
19.9% of the outstanding Common Stock of the Company.
Series A Preferred Stock and Warrants. On January 23, 1998, the Company
issued an aggregate of 37,000 shares of Series A Preferred Stock, inclusive of
the shares issued as part of the consent fee described above, with each share
having a liquidation preference of $1,000. The shares of Series A Preferred
Stock were redeemable at any time upon payment in cash of 101% of the
liquidation preference, inclusive of accrued but unpaid dividends, and the
shares were mandatorily redeemable on December 31, 2004. The shares of Series A
Preferred Stock entitled the holders to receive cumulative dividends payable in
additional shares of Series A Preferred Stock at a rate per annum initially of
14% of the liquidation preference of the Series A Preferred Stock increasing on
April 1, 1998 and each 90-day period thereafter that the Series A Preferred
Stock remained outstanding by 1%, but not to exceed a maximum dividend per annum
of 20%, excluding any other adjustments to the dividend rate. The issuance of
the shares provided a portion of the cash paid as consideration in the Amoco
Acquisition and a fee in connection with an amendment obtained from the holders
of certain terms of the Company's 12 1/4% Senior Notes.
Concurrently with the sale of the Series A Preferred Stock, the Company
issued five-year Warrants to purchase an aggregate of 1,175,778 shares of Common
Stock exercisable at the lesser of $2.75 per share or the average of the daily
closing bid prices commencing five days and ending one day before the date of
exercise, subject to reduction to $0.01 per share under certain circumstances.
The estimated fair value of such Warrants was approximately $941,000 on the date
of issuance.
F-17
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
In March 1998, the Company obtained consents from the holders of
approximately 95% of the Series A Preferred Stock and the related warrants to
extend through April 30, 1998 the date on which (i) the warrant exercise price
on existing warrants would reduce to $0.01 and (ii) such holders would receive
additional warrants. On April 27, 1998, as part of the Company's
Recapitalization Plan, all 37,000 shares of the Series A Preferred Stock were
redeemed and all accrued dividends paid. (See Note 4)
During 1997, the Company issued 335,000 shares of its common stock upon
exercise of outstanding warrants, at a price of $1.00 per share, 14,000 shares
upon conversion of a note, and 5,000 shares upon exercise of an option held by a
former director of the Company at a price of $2.00 per share. Additionally, the
Company issued 250,000 shares of its common stock during the period as
consideration to enter into a note payable and later issued an additional
200,000 shares to extend the maturity date of the note.
In connection with past financing arrangements and as compensation for
consulting and professional services, the Company has issued warrants to
purchase its common stock.
A summary of the status of Gothic's warrants as of December 31, 1997 and 1998,
and changes during each of the years then ended, is presented below:
<TABLE>
<CAPTION>
WARRANTS OUTSTANDING WARRANTS EXERCISABLE
--------------------------- --------------------------
WEIGHTED
WEIGHTED AVERAGE
NUMBER AVERAGE NUMBER EXERCISE
OUTSTANDING PRICE EXERCISABLE PRICE
----------- --------- ------------ ---------
<S> <C> <C> <C> <C>
Balance at December 31, 1996 10,157,031 $2.43 10,157,031 $2.43
Warrants granted 1,600,000 2.94
Warrants exercised (335,000) 1.00
Warrants forfeited (17,500) 1.00
----------
Balance at December 31, 1997 11,404,531 $2.54 11,404,531 $2.54
Warrants granted 5,940,024 1.06
----------
Balance at December 31, 1998 17,344,555 $2.00 17,344,555 $2.00
==========
</TABLE>
The following table summarizes information about Gothic's warrants, which
were outstanding, and those which were exercisable, as of December 31, 1998:
<TABLE>
<CAPTION>
WARRANTS OUTSTANDING WARRANTS EXERCISABLE
------------------------------------------- --------------------------
WEIGHTED WEIGHTED WEIGHTED
PRICE NUMBER AVERAGE AVERAGE NUMBER AVERAGE
RANGE OUTSTANDING LIFE PRICE EXERCISABLE PRICE
------------- --------------- ------------ ------------ ------------- -----------
<S> <C> <C> <C> <C> <C>
$.01 - $3.00 17,344,555 3.8 years $2.00 17,344,555 $2.00
</TABLE>
NOTE 7. STOCK OPTIONS
INCENTIVE STOCK OPTION PLAN--The Company has an incentive stock option and
non-statutory option plan (the ''Plan''), which provides for the issuance of
options to purchase up to 2,500,000 shares of Common Stock to key employees and
Directors. The incentive stock options granted under the Plan are generally
exercisable for a period of ten years from the date of the grant, except that
the term of an incentive stock option granted under the Plan to a stockholder
owning more than 10% of the outstanding common stock must not exceed five years
and the exercise price of an incentive stock option granted to such a
stockholder must not be less than 110% of the fair market value
F-18
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
of the common stock on the date of grant. The exercise price of a non-qualified
option granted under the Plan may not be less than 40% of the fair market value
of the common stock at the time the option is granted. As of December 31, 1997
and 1998, options to purchase 1,505,000 and 2,095,000 shares of common stock,
respectively, had been issued under the Plan. Half of the options are
exercisable after the completion of one year of future service as an employee or
director with the remaining options being exercisable upon completion of the
second year of future service. No non-qualified options have been issued under
the Plan.
OMNIBUS INCENTIVE PLAN--On August 13, 1996 at the Annual Shareholders'
Meeting, the shareholders approved the 1996 Omnibus Incentive Plan and the 1996
Non-Employees Stock Option Plan. The 1996 Omnibus Incentive Plan provides for
compensatory awards of up to an aggregate of 1,000,000 shares of Common Stock of
the Company to officers, directors and certain other key employees. Awards may
be granted for no consideration and consist of stock options, stock awards,
stock appreciation rights, dividend equivalents, other stock-based awards (such
as phantom stock) and performance awards consisting of any combination of the
foregoing. Generally, options will be granted at an exercise price equal to the
lower of (i) 100% of the fair market value of the shares of Common Stock on the
date of grant or (ii) 85% of the fair market value of the shares of Common Stock
on the date of exercise. Each option will be exercisable for the period or
periods specified in the option agreement, which will generally not exceed 10
years from the date of grant. No options have been issued under the Omnibus
Incentive Plan.
NON-EMPLOYEE STOCK OPTION PLAN--The 1996 Non-Employee Stock Option Plan
provides a means by which non-employee Directors of the Company and consultants
to the Company can be given an opportunity to purchase stock in the Company. The
Plan provides that a total of 1,000,000 shares of the Company's Common Stock may
be issued pursuant to options granted under the Non-Employee Plan, subject to
certain adjustments. The exercise price for each option granted under the Non-
Employee Plan will be not less than the fair market value of the Common Stock on
the date of grant. Each option granted under the Non-Employee Plan is
exercisable 10 years after the date of grant. Options granted to Directors will
terminate thirty (30) days after the date the Director is no longer a Director
of the Company. As of December 31, 1997 and 1998, options to purchase 450,000
and 600,000 shares of common stock, respectively, had been issued under the Non-
Employee Plan.
A summary of the status of Gothic's stock options as of December 31, 1997 and
1998, and changes during each of the years then ended, is presented below:
<TABLE>
<CAPTION>
Options Outstanding OPTIONS EXERCISABLE
----------------------------------- -----------------------------
WEIGHTED
WEIGHTED AVERAGE
NUMBER AVERAGE NUMBER EXERCISE
Outstanding Price Exercisable Price
---------------- ----------------- -------------- -------------
<S> <C> <C> <C> <C>
Balance at December 31, 1996 2,245,000 $1.32 1,352,500 $1.93
Options granted 450,000 .40
Options exercised (5,000) 2.00
---------
Balance at December 31, 1997 2,690,000 $1.17 1,850,000 $1.52
Options granted 1,285,000 .40
Options forfeited (545,000) .40
---------
Balance at December 31, 1998 3,430,000 $1.00 1,927,500 $1.47
=========
</TABLE>
F-19
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The following table summarizes information about Gothic's stock options which
were outstanding, and those which were exercisable, as of December 31, 1998:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------- -----------------------------
WEIGHTED WEIGHTED WEIGHTED
PRICE NUMBER AVERAGE AVERAGE NUMBER AVERAGE
RANGE OUTSTANDING LIFE PRICE EXERCISABLE PRICE
----- ----------- -------- -------- ----------- --------
<S> <C> <C> <C> <C> <C>
$1.50- $3.30 735,000 2.2 years $3.21 735,000 $3.21
$0.40 2,695,000 3.3 years $0.40 1,192,500 .40
</TABLE>
The Company applies Accounting Principles Board Opinion No. 25 in accounting
for stock options granted to employees, including directors, and Statement of
Financial Accounting Standards No. 123 ("SFAS No. 123") for stock options and
warrants granted to non-employees. No compensation cost has been recognized in
1997 or 1998.
Had compensation been determined on the basis of fair value pursuant to SFAS
No. 123, net loss and loss per share would have been increased as follows:
<TABLE>
<CAPTION>
1997 1998
---------------- -------------
(IN THOUSANDS)
<S> <C> <C>
Net loss available for common shares:
As reported............................................................. $(4,848) $(140,383)
======= =========
Pro Forma............................................................... $(5,698) $(141,232)
======= =========
Basic and diluted loss per share:
As reported............................................................. $ (.35) $ (8.63)
======= =========
Pro Forma............................................................... $ (.41) $ (8.68)
======= =========
</TABLE>
The fair value of each option granted is estimated using the Black Scholes
model. The Company's stock volatility was 0.81 in 1997 and 1998, based on
previous stock performance. Dividend yield was estimated to remain at zero with
an average risk free interest rate of 6.25 percent and 4.81 percent in 1997 and
1998, respectively. Expected life was 3 years for options issued in both 1997
and 1998 based on prior experience, the vesting periods involved and the make up
of participating employees within each grant. Fair value of options granted
during 1997 and 1998 under the Stock Option Plan were $474,000 and $643,000,
respectively.
OPTION REPRICING - On December 9, 1998, the Board of Directors of the Company
authorized the amendment of the terms of all of the options granted to then
current employees under its stock option plans to reduce the exercise price to
$0.40 per share, the fair market value of its outstanding shares of Common Stock
on that date. At the time, the Company had outstanding options to purchase a
total of 2,695,000 shares held by 24 employees, three officers and two Directors
with exercise prices ranging from $1.50 to $2.56 per share. The fair value of
these options on the date of the repricing was approximately $65,000. The stock
option information in the tables above retroactively reflects the repriced
options.
NOTE 8. INCOME TAXES
Deferred tax assets and liabilities are comprised of the following at December
31, 1998 (in thousands):
<TABLE>
<S> <C>
Deferred tax assets:
Gas balancing liability........................................................ $ 1,488
Net operating loss carryforwards............................................... 38,149
Depletion carryforwards........................................................ 257
Tax over book basis of natural gas and oil properties.......................... 17,697
Accrued wages.................................................................. 61
--------
Gross deferred tax assets...................................................... 57,652
</TABLE>
F-20
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
<TABLE>
<S> <C>
Deferred tax liabilities:
Deferred lease operating expenses.............................................. (602)
--------
Gross deferred tax liabilities................................................. (602)
Net deferred tax assets........................................................... 57,050
Valuation allowance............................................................ (57,050)
--------
$ -
========
</TABLE>
Net operating losses of approximately $94,243,000 are available for future use
against taxable income. These net operating loss carryforwards ("NOL") expire in
the years 2010 through 2013.
In addition, an acquisition in January, 1996 made available approximately
$6,147,000 of net operating loss carryforwards and $675,000 of depletion
carryforwards generated prior to the acquisition. However, the loss
carryforwards and depletion carryforwards are limited annually under Internal
Revenue Code Section 382 due to a change in ownership. The net operating loss
carryforwards expire in the years 2000 through 2010 and the depletion
carryforwards can be carried forward indefinitely.
Pursuant to Section 382 of the Internal Revenue Code of 1986, as amended, in
the event that a substantial change in the ownership of the Company were to
occur in the future (whether through the sale of stock by a significant
shareholder or shareholders, new issuances of stock by the Company, conversions,
a redemption, recapitalization, reorganization, any combination of the foregoing
or any other method) so that ownership of more than 50% of the value of the
Company's capital stock changed during any three-year period, the Company's
ability to utilize its NOL's could be substantially limited.
Realization of the net deferred tax asset is dependant on generating
sufficient taxable income in future periods. The Company has recorded a 100%
valuation allowance, as it is more likely than not that realization will not
occur in the future.
NOTE 9. COMMITMENTS AND CONTINGENCIES
The Company has entered into an employment agreement with its President
effective January 1, 1999, whereby he will receive a base salary of $189,000 per
year. In addition, he is to receive a cash bonus as may be determined by the
Company's Board of Directors. The President is also entitled to participate in
such incentive compensation and benefit programs as the Company makes available.
The term of the agreement is for a period of three years and at the end of the
first year and at the end of each succeeding year the agreement is automatically
extended for one year such that at the end of each year there will automatically
be three years remaining on the term of the agreement. The President can
terminate the agreement at the end of the initial term and any succeeding term
on not less than six months notice. In the event the employment agreement is
terminated by the Company (other than for cause, as defined), the President is
entitled to receive a payment representing all salary due under the remaining
full term of his agreement and the Company is obligated to continue his medical
insurance and other benefits provided under the agreement in effect for period
of one year after such termination. In the event of a change in control, as
defined, of the Company, the President has the right to terminate his employment
agreement with the Company within sixty days thereafter, whereupon the Company
would be obligated to pay to him a sum equal to three years of his base salary
under the agreement, plus a lump sum payment of $250,000.
The Company has also entered into an employment agreement with its Chief
Financial Officer effective January 1, 1999, whereby he will receive a base
salary of $157,500 per year. In addition, he is to receive a cash bonus as may
be determined by the Company's Board of Directors. The CFO is also entitled to
participate in such incentive compensation and benefit programs as the Company
makes available. The term of the agreement is for a period of three years and at
the end of the first year and at the end of each succeeding year the agreement
is automatically extended for one year such that at the end of each year there
will automatically be three years remaining on the term of the agreement. The
CFO can terminate the agreement at the end of the initial term and any
succeeding term on not less than six months notice. In the event the employment
agreement is terminated by the Company (other than for cause, as defined), the
CFO is entitled to receive a payment representing all salary due under the
remaining full term of his agreement, and the Company is obligated to continue
his medical insurance and other benefits provided under the agreement in effect
for a period of one year after such termination. In the event of a change in
control, as defined, of the Company, the CFO has the right to terminate his
employment with the Company within sixty days thereafter, whereupon the Company
would be obligated to pay to him a sum equal to three years base salary, plus a
lump sum payment of $200,000.
The Company leases its corporate offices and certain office equipment and
automobiles under non-cancelable operating leases. Rental expense under non-
cancelable operating leases was $122,000 and $190,000 for the years ended
December 31, 1997 and 1998, respectively.
F-21
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Remaining minimum annual rentals under non-cancelable lease agreements
subsequent to December 31, 1998 are as follows:
<TABLE>
<S> <C>
1999.......................................................................... $227,000
2000.......................................................................... 57,000
2001.......................................................................... 25,000
2002.......................................................................... 14,000
2003.......................................................................... 9,000
</TABLE>
The Company is not a defendant in any pending legal proceedings other than
routine litigation incidental to its business. While the ultimate results of
these proceedings cannot be predicted with certainty, the Company does not
believe that the outcome of these matters will have a material adverse effect on
the Company.
NOTE 10. BENEFIT PLAN
The Company maintains a 401(k) Plan for the benefit of its employees. The Plan
was implemented in October 1997. The Plan permits employees to make
contributions on a pre-tax salary reduction basis. The Company makes limited
matching contributions to the Plan, and may also make other discretionary
contributions. The Company's contributions for 1997 and 1998 were $35,000 and
$62,000, respectively.
NOTE 11. MAJOR CUSTOMERS
During the year ended December 31, 1998, the Company was a party to contracts
whereby it sold 50% of its gas production to Continental Natural Gas
Corporation, and 32% and 25% of its oil production to Sun Refining and Marketing
and Duke Energy, Inc., respectively. The Company has a ten-year marketing
agreement, whereby the majority of the natural gas associated with the Amoco
Acquisition will be sold to Continental, at market prices, under this agreement.
NOTE 12. RELATED PARTY TRANSACTIONS
During 1997, the Company made advances totaling $336,000 to two officers and
directors of the Company. In February 1998, $168,000 was received in connection
with a severance agreement. The balance outstanding on the remaining advance was
$179,000 as of December 31, 1998. The advance is interest bearing.
NOTE 13. COMMON STOCK DELISTING
Because the Company's common stock has traded at a price below $1.00 per share
for more than 30 consecutive trading dates and because, by virtue of the
provision of impairment of natural gas and oil properties recognized during the
third and fourth quarters of 1998, its net tangible assets at year-end were less
than $2.0 million, its shares of common stock are subject to delisting from the
Nasdaq Smallcap Market. The Company was notified on January 26, 1999 that it no
longer met minimum listing requirements and that its shares would be delisted
from the Nasdaq Smallcap Market, effective with the close of business on
February 2, 1999. On February 1, 1999, the Company requested a hearing before
the staff of Nasdaq and additionally requested a stay of the delisting action
which was to have taken effect on February 2, 1999. The Company has been granted
a hearing to take place on April 9, 1999. If the appeal of the delisting is not
successful, the Company's common stock will be traded over-the-counter.
F-22
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
NOTE 14. SUMMARIZED FINANCIAL INFORMATION
Gothic Production Corporation was organized in March 1998 as a wholly owned
subsidiary of the Company. On April 27, 1998, the Company transferred to Gothic
Production its ownership of all its natural gas and oil properties. Following is
the summarized financial information related to Gothic Production as of December
31, 1998 and for the year ended December 31, 1998. (in thousands)
<TABLE>
<CAPTION>
As of December 31, 1998
-------------------------------------------------------------------------------------------
Gothic Energy
Gothic Energy Gothic Production Corporation
Corporation Corporation /(1)/ Consolidated
----------- ------------------- ------------
<S> <C> <C> <C>
Current assets $ - $ 9,801 $ 9,801
Non-current assets 2,230 225,257 227,487
Current liabilities - 13,850 13,850
Non-current liabilities 66,179 241,180 307,359
</TABLE>
<TABLE>
<CAPTION>
For the year ended December 31, 1998
--------------------------------------------------------------------------------------------
Gothic Energy
Gothic Energy Gothic Production Corporation
Corporation Corporation /(1)/ Consolidated
----------- ------------------- -------------
<S> <C> <C> <C>
Total revenues $ 21,033 $ 32,000 $ 53,033
Operating costs and
expenses 16,172 23,781 39,953
Provision for impairment
of natural gas and oil
properties - 76,000 76,000
Interest expense and
amortization of debt
issuance cost 16,821 18,617 35,438
Loss before
extraordinary item (12,408) (85,822) (98,230)
Net loss (43,842) (85,847) (129,689)
</TABLE>
(1) Since the Recapitalization on April 27, 1998
NOTE 15. SUPPLEMENTARY NATURAL GAS AND OIL INFORMATION
FINANCIAL DATA
The following supplemental historical and reserve information is presented in
accordance with Financial Accounting Standards Board Statement No. 69,
"Disclosures About Oil and Gas Producing Activities".
F-23
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
CAPITALIZED COSTS--The aggregate amounts of capitalized costs relating to
natural gas and oil producing activities, net of valuation allowances, and the
aggregate amounts of the related accumulated depreciation, depletion, and
amortization at December 31, 1998 were as follows:
<TABLE>
<CAPTION>
1998
--------------
(IN THOUSANDS)
<S> <C>
Proved properties...................................................... $242,012
Unproved properties, not subject to depreciation, depletion and
amortization (1)..................................................... 2,862
Less: Accumulated depreciation, depletion, and amortization............ (32,693)
--------
Net natural gas and oil properties.................................. $212,181
========
</TABLE>
(1) The Company expects to evaluate the unproved properties during the next two
years.
COSTS INCURRED--Costs incurred in natural gas and oil property acquisition,
exploration and development activities for the years ended December 31, 1997 and
1998 were as follows:
<TABLE>
<CAPTION>
1997 1998
------------ ----------------
(IN THOUSANDS)
<S> <C> <C>
Property acquisition.................................................. $83,694 $225,103
Development costs..................................................... 6,141 18,379
------- --------
Total costs incurred............................................... $89,835 $243,482
======= ========
</TABLE>
NATURAL GAS AND OIL RESERVES DATA (UNAUDITED)
ESTIMATED QUANTITIES--Natural gas and oil reserves cannot be measured exactly.
Estimates of natural gas and oil reserves require extensive judgments of
reservoir engineering data and are generally less precise than other estimates
made in connection with financial disclosures.
Proved reserves are those quantities which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known oil and natural gas reservoirs under existing economic and
operating conditions. Proved developed reserves are those reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are those reserves which are
expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required.
Estimates of natural gas and oil reserves require extensive judgments of
reservoir engineering data as explained above. Assigning monetary values to such
estimates does not reduce the subjectivity and changing nature of such reserve
estimates. Indeed, the uncertainties inherent in the disclosure are compounded
by applying additional estimates of the rates and timing of production and the
costs that will be incurred in developing and producing the reserves. The
information set forth herein is therefore subjective and, since judgments are
involved, may not be comparable to estimates submitted by other oil and natural
gas producers. In addition, since prices and costs do not remain static and no
price or cost escalations or de-escalations have been considered, the results
are not necessarily indicative of the estimated fair market value of estimated
proved reserves nor of estimated future cash flows and significant revisions
could occur in the near term. Accordingly, these estimates are expected to
change as future information becomes available. All of the Company's reserves
are located onshore in the states of Oklahoma, Texas, New Mexico, Arkansas and
Kansas.
F-24
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The following unaudited table, which is based on reports of Lee Keeling and
Associates, Inc., sets forth proved natural gas and oil reserves:
<TABLE>
<CAPTION>
1997 1998
----------------------- ----------------------
Bbls MCF Bbls MCF
--------- ------------ --------- -----------
(in thousands) (in thousands)
<S> <C> <C> <C> <C>
Proved Reserves:
Beginning of year..................................................... 1,158 64,534 3,585 127,460
Revisions of previous estimates....................................... 552 (13,154) (872) 39,577
Purchases of reserves in place........................................ 2,195 89,016 1,362 233,007
Production............................................................ (176) (6,583) (257) (24,455)
Sales of reserves in place............................................ (144) (6,353) (2,057) (68,921)
----- ------- ------ -------
End of year 3,585 127,460 1,761 306,668
===== ======= ====== =======
Proved Developed:
Beginning of year..................................................... 1,135 47,485 2,503 91,690
End of year........................................................... 2,503 91,690 1,523 254,762
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS--Future net cash
inflows are based on the future production of proved reserves of natural gas and
crude oil as estimated by Lee Keeling and Associates, Inc., independent
petroleum engineers, by applying current prices of natural gas and oil to
estimated future production of proved reserves. The average prices used in
determining future cash inflows for natural gas and oil as of December 31, 1998,
were $1.81 per mcf, and $10.50 per barrel, respectively. Future net cash flows
are then calculated by reducing such estimated cash inflows by the estimated
future expenditures (based on current costs) to be incurred in developing and
producing the proved reserves and by the estimated future income taxes.
Estimated future income taxes are computed by applying the appropriate year-
end statutory tax rate to the future pretax net cash flows relating to the
Company's estimated proved natural gas and oil reserves. The estimated future
income taxes give effect to permanent differences and tax credits and
allowances. Subsequent to December 31, 1998, the ''spot market'' price of
natural gas decreased to approximately $1.60 per mcf, and oil prices dropped to
approximately $10.30 per barrel, through March 12, 1998. This decline would have
a significant impact on the SMOG values.
Included in the estimated standardized measure of future cash flows are
certain capital projects (future development costs). The Company estimates the
capital required to develop its undeveloped natural gas and oil reserves during
1999 to be approximately $16,000,000 to $18,000,000. The Company's planned
financial arrangements are discussed in Note 5. If such capital is not employed,
the estimated future cash flows will be impacted.
The following table sets forth the Company's unaudited estimated standardized
measure of discounted future net cash flows.
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1998
---------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Cash Flows Relating to Proved Reserves:
Future cash inflows.............................................................. $ 351,915 $ 573,604
Future production costs.......................................................... (102,353) (141,253)
Future development costs......................................................... (26,911) (37,028)
Future income tax expense........................................................ (51,925) (47,264)
--------- ---------
170,726 348,059
Ten percent annual discount factor............................................... (76,624) (169,297)
--------- ---------
Standardized Measure of Discounted Future Net Cash Flows......................... $ 94,102 $ 178,762
========= =========
</TABLE>
F-25
<PAGE>
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
The following table sets forth changes in the standardized measure of
discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1998
------------ ------------
(IN THOUSANDS)
<S> <C> <C>
Standardized measure of discounted future cash flows-beginning of period............ $ 49,083 $ 94,102
Sales of natural gas and oil produced, net of operating expenses.................... (10,558) (38,585)
Purchases of reserves-in-place...................................................... 75,736 231,184
Sales of reserves-in-place.......................................................... (5,832) (62,933)
Revisions of previous quantity estimates and changes in sales prices and
production costs................................................................. (19,235) (54,416)
Accretion of discount............................................................... 4,908 9,410
-------- ---------
Standardized measure of discounted future cash flows-end of period.................. $ 94,102 $ 178,762
======== =========
</TABLE>
F-26
<PAGE>
EXHIBIT 10.2.1
EMPLOYMENT AGREEMENT
EMPLOYMENT AGREEMENT, effective as of this 1st day of January, 1999, by and
between GOTHIC ENERGY CORPORATION and GOTHIC PRODUCTION CORPORATION, both
Oklahoma corporations, with their principal place of business at 5727 South
Lewis Avenue, Suite 700, Tulsa, Oklahoma, 74105-7148 (collectively the
"Company"), and MICHAEL PAULK (the "Executive").
WHEREAS, the Executive is the President of the Company, the Company desires
to continue to employ the Executive as the President of the Company and the
parties hereto wish to set forth the terms of the Executive's employment with
the Company.
NOW, THEREFORE, in consideration of the mutual covenants hereinafter set
forth, the parties hereto agree as follows:
1. Employment. The Company hereby employs the Executive, and the
----------
Executive hereby accepts such employment, as President of the Company upon terms
and subject to the conditions contained herein.
2. Duties.
------
(a) The Executive shall perform all duties of the position of President
of the Company consistent with the powers and duties of such office set forth in
the Company's By-Laws, as well as any other duties, commensurate with the
Executive's position that are assigned by the Chairman of the Board ("Chairman")
or the Board of Directors ("Board").
(b) Throughout his employment hereunder, Executive shall devote his
full time, attention, knowledge and skills during regular business hours in
furtherance of the business of the Company and will faithfully, diligently and
to the best of his ability perform the duties described above in furtherance of
the Company's best interests. During his employment, the Executive shall not
engage, and shall not solicit any employees of the Company or affiliates to
engage in any commercial activities which are in any way in competition with the
activities of the Company, or which may in any way interfere with the
performance of his duties or responsibilities to the Company.
(c) The Executive shall at all times be subject to, rve and carry out
such rules, regulations, policies, directions and restrictions as the Company,
consistent with the Executive's rights and duties under his Agreement, may from
time to time establish and those imposed by law. The Company agrees to take
such action as shall be required to nominate the Executive as a director of the
Company at each election of directors.
3. Executive Covenants. In order to induce the Company to enter into this
-------------------
Employment Agreement, the Executive hereby agrees as follows:
(a) Except when disclosure is in the best interest of the Company or is
compelled by law, or disclosure is consented to or directed by the Chairman of
the Board, the Executive shall keep confidential and shall not divulge to any
other person or entity, during the term of the Executive's employment or
thereafter, any of the business secrets or other confidential information
regarding the Company or the Company's other subsidiaries which have not
otherwise become public knowledge.
(b) All papers, books and records of every kind and description
relating to the business and affairs of the Company, whether or not prepared by
the Executive, shall be the sole and exclusive property of the Company, and the
Executive shall surrender them to the Company at any time upon request by the
Chairman or the Board.
<PAGE>
4. Base Salary and Bonuses. As full compensation for Executive's services
-----------------------
hereunder and in exchange for his promises contained herein, the Company shall
compensate the Executive in the following manner (subject to Paragraph 4 (c)):
(a) Base Salary. The Company shall compensate Executive at the base
-----------
salary rate of One Hundred Eighty-Nine Thousand Dollars ($189,000) per annum,
payable in equal installments on the same basis as other senior salaried
officers of the Company. Such annual salary may be increased in the future by
such amounts and at such times as the Board or the Compensation Committee
thereof shall deem appropriate in its sole discretion.
(b) Annual Bonuses. Beginning with the calendar year 1999 and in each
--------------
year or portion thereof thereafter during the term of his Agreement, the Board
or Compensation Committee thereof shall consider the Executive for a cash
performance bonus in accordance with the following terms: The actual amount and
timing of such bonus, if any, shall be determined in good faith based on
criteria reasonably deemed to be relevant to such determination including,
without limitation, transactions effected for the benefit of the Company that
are outside of the ordinary course of business and directly or indirectly
accomplished through the efforts of the Executive (e.g., business combinations,
corporate partnerings and other similar transactions).
(c) The amounts set forth in subparagraphs (a) and (b) above shall be
subject to appropriate payroll withholding and any similar deductions required
by law.
5. Long-term Incentive Plan. The Executive shall be entitled to
------------------------
participate, to the extent he is eligible under the terms and conditions
thereof, any stock option plan, stock award plan, omnibus stock plan, or similar
incentive plan currently in existence or hereafter established by the Company.
Awards to the Executive under any such plan shall be made as provided in such
plans and at such times and in such amounts as shall be determined in the sole
discretion reasonably exercised of the Board or the Compensation Committee
thereof. Executive's right to receive a bonus shall be exclusively determined
by the provisions of Paragraph 4(b) hereof.
6. Benefit Plans. During the term of his employment, the Executive shall
-------------
be entitled to participate in the Company management employment benefits and
retirement plans (including any health and life insurance plans), as they are in
existence on the date of this Agreement, or as they may be amended or added
hereafter. Neither shall the Company be under any obligation solely as a result
of the Agreement to institute or continue the existence of any employee benefit
plan.
7. Other Benefits. The Executive shall be provided the following
--------------
additional benefits:
(a) Club Membership. Reimbursement to the Executive for the cost of his
---------------
and his immediate family's membership in one country club or his membership in
one business club, and for his business-related use thereof.
(b) Business Expense. Reimbursement to the Executive, upon proper
----------------
accounting, for reasonable expenses and disbursements incurred by him in the
course of the performance of his duties hereunder.
(c) Vacation. The Executive shall be entitled to four (4) weeks of
--------
vacation each year of the Agreement or such longer period as shall be provided
to senior executives of the Company, without reduction in salary.
(d) Automobile. The Executive shall be entitled to the use of an
----------
automobile, and upon proper accounting shall be reimbursed for reasonable
expenses incurred by him relating to the performance of his duties hereunder.
2
<PAGE>
8. Duration and Termination.
------------------------
(a) Duration. The effective date of this Agreement shall be January 1,
--------
1999, and it shall continue for a term of three (3) years. At the end of the
first year and at the end of each succeeding year this agreement shall be
automatically extended for one year such that at the end of each year there will
automatically be three years remaining on the term of this Agreement, provided
that the Executive shall have the right to terminate this Agreement at the end
of the initial term or any succeeding term on not less than six (6) months prior
written notice to the Company (in which event all rights and benefits of
Executive hereunder shall cease upon such termination's effective date).
(b) Termination at Any Time by Company. This Agreement shall be
terminable by the Company at any time for any reason, including death or
Disability (as hereinafter defined) of the Executive, upon not less than 45 days
prior written notice to the Executive and all rights and benefits of the
Executive hereunder (other than those arising under Section 9 hereof) shall
cease, except that the Executive will have the right to receive from the Company
(i) a payment representing all salary due under the remaining full term of this
Agreement, and (ii) the continuation of all medical insurance and other benefits
provided to the Executive as contemplated by Sections 6 and 7 hereof for a
period of one (1) year following the termination date. Notwithstanding the
foregoing, if the Company terminated this Agreement "for cause," then no
Termination Payment shall be made to the Executive and all rights, benefits and
obligations of the Executive under this Agreement, except the Executive's rights
under Section 9 hereof, shall cease. "For cause" shall include: (i) the
Executive's willful and material breach in respect of his duties under this
Agreement if such breach continues unremedied for thirty (30) days after written
notice thereof from the Board to the Executive specifying the acts constituting
the breach and requesting that they be remedied; or (ii) the Executive is
convicted or pleads guilty to a felony, during the employment period other than
for conduct undertaken in good faith in furtherance of the interests of the
Company. "Disability" shall mean that due to illness, accident or other physical
or mental incapacity, the Board has in good faith determined that the Executive
is unable to substantially perform his usual and customary duties under this
Agreement for more than four (4) consecutive months or six (6) months in any
calendar year.
(c) Rights of Termination by Executive. The Executive shall have the
----------------------------------
right, by written notice to the Company, to elect to terminate this Agreement
within sixty (60) days following a Change in Control (as defined below). In the
event that Executive makes such election, the Executive shall be entitled to
receive from the Company a payment equal to three years current base salary as
set forth herein or as hereafter increased by the Board or Compensation
Committee, plus a lump sum payment of Two Hundred Fifty Thousand Dollars
($250,000). Payment is to be made within sixty (60) days of receipt by the
Company of a written notice of Executive's election.
(d) Change in Control. For the purpose of this Agreement, a "Change in
-----------------
Control" means (i) the direct or indirect sale, lease, exchange or other
transfer of all or substantially all (50% or more) of the assets of the Company
to any person or entity (in either case, a "Person") or group of Persons acting
in concert as a partnership or other group (a "Group of Persons"), other than
an Affiliate (as defined below) of the Company, (ii) the merger, consolidation
or other business combination of the Company with or into another corporation
with the effect that the shareholders of the Company immediately prior to the
business combination hold 50% or less of the combined voting power of the then
outstanding securities of
3
<PAGE>
the surviving corporation of such merger ordinarily (and apart from rights
accruing under special circumstances) having the right to vote in the election
of directors, (iii) the replacement of a majority of the Board, over any period
of two (2) years or less, from the directors who constituted the Board at the
beginning of such period, and such replacement shall not have been approved by
the Board (or replacements approved by the Board) as constituted at the
beginning of such period, (iv) a Person or Group of Persons shall as a result of
a tender or exchange offer, open market purchases, privately negotiated
purchases or otherwise, have become the beneficial owner (within the meaning of
Rule 13d-3 under the Securities Exchange Act of 1934, as amended) of the
securities of the Company representing 50% or more of the combined voting power
of the then outstanding securities of the Company ordinarily (and apart from
rights accruing under special circumstances) having the right to vote in the
election of directors, or (v) a material change in the duties and/or
responsibilities of the Executive hereunder which change has been approved by
the Board or Chairman. As used in this Section 8, (a) the term "Affiliate"
means, with respect to any designated Person, any other Person that has a
relationship with the designated Person whereby either of such Persons directly
or indirectly controls or is controlled by or is under common control with the
other of such Persons, or holds or beneficially owns 10% or more of the equity
interest on the other Person or 10% or more of any class of voting securities of
the other Person and (b) the term "control" means the possession, directly or
indirectly, of the power, whether exercised or not exercised, to direct or cause
the direction of the management or policies of any Person, whether through the
ownership of voting securities, by contract or otherwise.
9. Indemnification. The Company shall defend and hold the Executive
---------------
harmless to the fullest extent permitted by applicable law, the Company's By-
Laws and the Company's Charter in connection with any claim, action, suit,
investigation or proceeding arising out of or relating to performance by the
Executive of services for, or action of the Executive is or was, a director,
officer, employee or agent of the Company or any parent, subsidiary or affiliate
of the Company, or of any other person or enterprise at the Company's request.
Expenses incurred by the Executive in defending a claim, action, suit or
investigation or proceeding shall be paid by the Company in advance of the final
disposition thereof upon the receipt by the Company of any undertaking by or on
behalf of the Executive to repay such amount if it shall ultimately be
determined that he is not entitled to be indemnified hereunder; provided
however, that this Paragraph 9 shall not apply to a non-derivative action
commenced by the Company against the Executive. The foregoing rights are not
exclusive and do not limit any rights accruing to the Executive under any other
agreement or contract or under applicable law.
10. Successors and Assigns. The rights of the Company hereunder shall run
----------------------
in favor of the Company, its successors, assigns, nominees or other legal
representatives. The rights of the Executives hereunder shall inure to the
benefit of the Executive's legal representatives, executors, heirs and
beneficiaries. Termination of Executive's employment shall not operate to
relieve him of any remaining obligations under Section 3 hereof, and all such
obligations are binding upon his heirs, executors, administrators or other legal
representatives. The Company shall require any successor (whether direct or
indirect, by purchase, merger, reorganization, consolidation, acquisition of
property or stock, liquidation or otherwise) to all or a significant portion of
the assets of the Company, by agreement in form and substance satisfactory to
the Executive, to expressly assume and agree to perform this Agreement in the
same manner and to the same extent that the Company would be required to perform
if no such succession had taken
4
<PAGE>
place. Regardless of whether such agreement is executed by a successor, this
Agreement shall be binding upon any successor in accordance with the operation
of law and such successor shall be deemed the "Company" for the purpose of this
Agreement.
11. Arbitration of All Disputes.
---------------------------
(a) Any controversy or claim arising out of or relating to this
Agreement or the breach thereof (including the arbitrability of any controversy
or claim), shall be settled by arbitration in the city of Tulsa in the State of
Oklahoma, by three (3) arbitrators, one of whom shall be appointed by the
Company, one by the Executive and the third of whom shall be appointed by the
first two arbitrators. If the first two arbitrators cannot agree on the
appointment of the third arbitrator, then the third arbitrator shall be
appointed by the American Arbitration Association. The arbitration shall be
conducted in accordance with the rules of the American Arbitration Association,
except with respect to the selection of the arbitrators which shall be as
provided in this Section. The cost of any arbitration process hereunder shall be
borne equally by the Company and Executive. The award of the arbitrators shall
be binding upon the parties. Judgment upon the award rendered by three
arbitrators may be entered in any court having jurisdiction thereof .
(b) In the event that it shall be necessary or desirable for the
Executive to retain legal counsel and/or incur other costs and expenses in
connection with the enforcement of any or all of his rights under this
Agreement, and provided that the Executive substantially prevails in the
enforcement of such rights, the Company shall pay (or the Executive shall be
entitled to recover from the Company, as the case may be) the Executive's
reasonable attorney's fees and costs and expenses in connection with the
enforcement of his rights, including the enforcement of any arbitration award,
up to $50,000 in the aggregate.
12. Notices. All notices, requests, demands and other communications
-------
hereunder must be in writing and shall be deemed to have been duly given upon
receipt if delivered by hand, sent by telecopier or courier, and three (3) days
after such communication is mailed within the continental United States by first
class certified mail, return receipt requested, postage prepaid, to the other
party, in each case addressed as follows:
(a) if to the Company:
Gothic Energy Corporation
5727 South Lewis Avenue, Suite 700
Tulsa, Oklahoma 74105
Attn: Chief Financial Officer
(b) if to the Executive:
Michael Paulk
10613 South Erie Avenue
Tulsa, Oklahoma 74137
Addresses may be changed by written notice sent to the other party at the last
recorded address of that party.
5
<PAGE>
13. Severability. If any provisions of this Agreement shall be adjudged
------------
by any court of competent jurisdiction to be invalid or unenforceable for any
reason, such judgment shall not affect, impair or invalidate the remainder of
this Agreement.
14. Prior Understanding. This Agreement embodies the entire understanding
-------------------
of the parties hereto, and supersedes all other oral or written agreements or
understandings between them regarding the subject matter hereof. No change,
alteration or modification hereof may be made except in writing, signed by both
parties hereto. The headings in this Agreement are for convenience and
reference only and shall not be construed as part of this Agreement or to limit
or otherwise affect the meaning hereof.
15. Execution in Counterparts. This Agreement may be executed by the
-------------------------
parties hereto in counterparts, each of which shall be deemed to be original,
but all such counterparts shall constitute one and the same instrument, and all
signatures need not appear on any one counterpart.
16. Choices of Laws. Subject to the provisions of Paragraph 11 and
---------------
without regard to the effect of principles of conflict of laws thereto,
jurisdiction over disputes with regard to this Agreement shall be exclusively in
the courts of the State of Oklahoma, and this Agreement shall be construed in
accordance with and governed by the laws of the State of Oklahoma.
IN WITNESS WHEREOF, the parties hereto have executed and delivered this
Agreement as of the day and year first above written.
GOTHIC ENERGY CORPORATION
By:
-------------------------------
ATTEST:
- -------------------------------
GOTHIC PRODUCTION CORPORATION
By:
-------------------------------
ATTEST:
- -------------------------------
----------------------------------
MICHAEL PAULK
6
<PAGE>
EXHIBIT 10.2.2
EMPLOYMENT AGREEMENT
EMPLOYMENT AGREEMENT, effective as of this 1st day of January, 1999, by and
between GOTHIC ENERGY CORPORATION and GOTHIC PRODUCTION CORPORATION, both
Oklahoma corporations, with their principal place of business at 5727 South
Lewis Avenue, Suite 700, Tulsa, Oklahoma, 74105-7148 (collectively the
"Company"), and STEVEN P. ENSZ (the "Executive").
WHEREAS, the Executive is the Vice President and Chief Financial Officer of
the Company, the Company desires to continue to employ the Executive as the Vice
President and Chief Financial Officer of the Company and the parties hereto wish
to set forth the terms of the Executive's employment with the Company.
NOW, THEREFORE, in consideration of the mutual covenants hereinafter set
forth, the parties hereto agree as follows:
1. Employment. The Company hereby employs the Executive, and the
----------
Executive hereby accepts such employment, as Vice President and Chief Financial
Officer of the Company upon terms and subject to the conditions contained
herein.
2. Duties.
------
(a) The Executive shall perform all duties of the position of Vice
President and Chief Financial Officer of the Company consistent with the powers
and duties of such office set forth in the Company's By-Laws, as well as any
other duties, commensurate with the Executive's position that are assigned by
the Chairman of the Board ("Chairman"), the Board of Directors ("Board") or the
President.
(b) Throughout his employment hereunder, Executive shall devote his
full time, attention, knowledge and skills during regular business hours in
furtherance of the business of the Company and will faithfully, diligently and
to the best of his ability perform the duties described above in furtherance of
the Company's best interests. During his employment, the Executive shall not
engage, and shall not solicit any employees of the Company or affiliates to
engage in any commercial activities which are in any way in competition with the
activities of the Company, or which may in any way interfere with the
performance of his duties or responsibilities to the Company.
(c) The Executive shall at all times be subject to, observe and carry
out such rules, regulations, policies, directions and restrictions as the
Company, consistent with the Executive's rights and duties under his Agreement,
may from time to time establish and those imposed by law.
3. Executive Covenants. In order to induce the Company to enter into this
-------------------
Employment Agreement, the Executive hereby agrees as follows:
(a) Except when disclosure is in the best interest of the Company or is
compelled by law, or disclosure is consented to or directed by the Chairman of
the Board, the Executive shall keep confidential and shall not divulge to any
other person or entity, during the term of the Executive's employment or
thereafter, any of the business secrets or other confidential information
regarding the Company or the Company's other subsidiaries which have not
otherwise become public knowledge.
<PAGE>
(b) All papers, books and records of every kind and description
relating to the business and affairs of the Company, whether or not prepared by
the Executive, shall be the sole and exclusive property of the Company, and the
Executive shall surrender them to the Company at any time upon request by the
Chairman or the Board.
4. Base Salary and Bonuses. As full compensation for Executive's services
-----------------------
hereunder and in exchange for his promises contained herein, the Company shall
compensate the Executive in the following manner (subject to Paragraph 4 (c)):
(a) Base Salary. The Company shall compensate Executive at the base
-----------
salary rate of One Hundred Fifty-Seven Thousand Five Hundred Dollars ($157,500)
per annum, payable in equal installments on the same basis as other senior
salaried officers of the Company. Such annual salary may be increased in the
future by such amounts and at such times as the Board or the Compensation
Committee thereof shall deem appropriate in its sole discretion.
(b) Annual Bonuses. Beginning with the calendar year 1999 and in each
--------------
year or portion thereof thereafter during the term of his Agreement, the Board
or Compensation Committee thereof shall consider the Executive for a cash
performance bonus in accordance with the following terms: The actual amount and
timing of such bonus, if any, shall be determined in good faith based on
criteria reasonably deemed to be relevant to such determination including,
without limitation, transactions effected for the benefit of the Company that
are outside of the ordinary course of business and directly or indirectly
accomplished through the efforts of the Executive (e.g., business combinations,
corporate partnerings and other similar transactions).
(c) The amounts set forth in subparagraphs (a) and (b) above shall be
subject to appropriate payroll withholding and any similar deductions required
by law.
5. Long-term Incentive Plan. The Executive shall be entitled to
------------------------
participate, to the extent he is eligible under the terms and conditions
thereof, any stock option plan, stock award plan, omnibus stock plan, or similar
incentive plan currently in existence or hereafter established by the Company.
Awards to the Executive under any such plan shall be made as provided in such
plans and at such times and in such amounts as shall be determined in the sole
discretion reasonably exercised of the Board or the Compensation Committee
thereof. Executive's right to receive a bonus shall be exclusively determined
by the provisions of Paragraph 4(b) hereof.
6. Benefit Plans. During the term of his employment, the Executive shall
-------------
be entitled to participate in the Company management employment benefits and
retirement plans (including any health and life insurance plans), as they are in
existence on the date of this Agreement, or as they may be amended or added
hereafter. Neither shall the Company be under any obligation solely as a result
of the Agreement to institute or continue the existence of any employee benefit
plan.
7. Other Benefits. The Executive shall be provided the following
--------------
additional benefits:
(a) Club Membership. Reimbursement to the Executive for the cost of his
---------------
and his immediate family's membership in one country club or his membership in
one business club, and for his business-related use thereof.
(b) Business Expense. Reimbursement to the Executive, upon proper
----------------
accounting, for reasonable expenses and disbursements incurred by him in the
course of the performance of his duties hereunder.
2
<PAGE>
(c) Vacation. The Executive shall be entitled to four (4) weeks of
--------
vacation each year of the Agreement or such longer period as shall be provided
to senior executives of the Company, without reduction in salary.
(d) Automobile. The Executive shall be entitled to the use of an
----------
automobile, and upon proper accounting shall be reimbursed for reasonable
expenses incurred by him relating to the performance of his duties hereunder.
8. Duration and Termination.
------------------------
(a) Duration. The effective date of this Agreement shall be January 1,
--------
1999, and it shall continue for a term of three (3) years. At the end of the
first year and at the end of each succeeding year this agreement shall be
automatically extended for one year such that at the end of each year there will
automatically be three years remaining on the term of this Agreement, provided
that the Executive shall have the right to terminate this Agreement at the end
of the initial term or any succeeding term on not less than six (6) months prior
written notice to the Company (in which event all rights and benefits of
Executive hereunder shall cease upon such termination's effective date).
(b) Termination at Any Time by Company. This Agreement shall be
----------------------------------
terminable by the Company at any time for any reason, including death or
Disability (as hereinafter defined) of the Executive, upon not less than 45 days
prior written notice to the Executive and all rights and benefits of the
Executive hereunder (other than those arising under Section 9 hereof) shall
cease, except that the Executive will have the right to receive from the Company
(i) a payment representing all salary due under the remaining full term of this
Agreement, and (ii) the continuation of all medical insurance and other benefits
provided to the Executive as contemplated by Sections 6 and 7 hereof for a
period of one (1) year following the termination date. Notwithstanding the
foregoing, if the Company terminated this Agreement "for cause," then no
Termination Payment shall be made to the Executive and all rights, benefits and
obligations of the Executive under this Agreement, except the Executive's rights
under Section 9 hereof, shall cease. "For cause" shall include: (i) the
Executive's willful and material breach in respect of his duties under this
Agreement if such breach continues unremedied for thirty (30) days after written
notice thereof from the Board to the Executive specifying the acts constituting
the breach and requesting that they be remedied; or (ii) the Executive is
convicted or pleads guilty to a felony, during the employment period other than
for conduct undertaken in good faith in furtherance of the interests of the
Company. "Disability" shall mean that due to illness, accident or other physical
or mental incapacity, the Board has in good faith determined that the Executive
is unable to substantially perform his usual and customary duties under this
Agreement for more than four (4) consecutive months or six (6) months in any
calendar year.
(c) Rights of Termination by Executive. The Executive shall have the
----------------------------------
right, by written notice to the Company, to elect to terminate this Agreement
within sixty (60) days following a Change in Control (as defined below). In the
event that Executive makes such election, the Executive shall be entitled to
receive from the Company a payment equal to three years current base salary as
set forth herein or as hereafter increased by the Board or Compensation
Committee, plus a lump sum payment of Two Hundred Thousand Dollars ($200,000).
Payment is to be made within sixty (60) days of receipt by the Company of a
written notice of Executive's election.
3
<PAGE>
(d) Change in Control. For the purpose of this Agreement, a "Change in
-----------------
Control" means (i) the direct or indirect sale, lease, exchange or other
transfer of all or substantially all (50% or more) of the assets of the Company
to any person or entity (in either case, a "Person") or group of Persons acting
in concert as a partnership or other group (a "Group of Persons"), other than
an Affiliate (as defined below) of the Company, (ii) the merger, consolidation
or other business combination of the Company with or into another corporation
with the effect that the shareholders of the Company immediately prior to the
business combination hold 50% or less of the combined voting power of the then
outstanding securities of the surviving corporation of such merger ordinarily
(and apart from rights accruing under special circumstances) having the right to
vote in the election of directors, (iii) the replacement of a majority of the
Board, over any period of two (2) years or less, from the directors who
constituted the Board at the beginning of such period, and such replacement
shall not have been approved by the Board (or replacements approved by the
Board) as constituted at the beginning of such period, (iv) a Person or Group of
Persons shall as a result of a tender or exchange offer, open market purchases,
privately negotiated purchases or otherwise, have become the beneficial owner
(within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934, as
amended) of the securities of the Company representing 50% or more of the
combined voting power of the then outstanding securities of the Company
ordinarily (and apart from rights accruing under special circumstances) having
the right to vote in the election of directors, or (v) a material change in the
duties and/or responsibilities of the Executive hereunder which change has been
approved by the Board or Chairman. As used in this Section 8, (a) the term
"Affiliate" means, with respect to any designated Person, any other Person that
has a relationship with the designated Person whereby either of such Persons
directly or indirectly controls or is controlled by or is under common control
with the other of such Persons, or holds or beneficially owns 10% or more of the
equity interest on the other Person or 10% or more of any class of voting
securities of the other Person and (b) the term "control" means the possession,
directly or indirectly, of the power, whether exercised or not exercised, to
direct or cause the direction of the management or policies of any Person,
whether through the ownership of voting securities, by contract or otherwise.
9. Indemnification. The Company shall defend and hold the Executive
---------------
harmless to the fullest extent permitted by applicable law, the Company's By-
Laws and the Company's Charter in connection with any claim, action, suit,
investigation or proceeding arising out of or relating to performance by the
Executive of services for, or action of the Executive is or was, a director,
officer, employee or agent of the Company or any parent, subsidiary or affiliate
of the Company, or of any other person or enterprise at the Company's request.
Expenses incurred by the Executive in defending a claim, action, suit or
investigation or proceeding shall be paid by the Company in advance of the final
disposition thereof upon the receipt by the Company of any undertaking by or on
behalf of the Executive to repay such amount if it shall ultimately be
determined that he is not entitled to be indemnified hereunder; provided
however, that this Paragraph 9 shall not apply to a non-derivative action
commenced by the Company against the Executive. The foregoing rights are not
exclusive and do not limit any rights accruing to the Executive under any other
agreement or contract or under applicable law.
4
<PAGE>
10. Successors and Assigns. The rights of the Company hereunder shall run
----------------------
in favor of the Company, its successors, assigns, nominees or other legal
representatives. The rights of the Executives hereunder shall inure to the
benefit of the Executive's legal representatives, executors, heirs and
beneficiaries. Termination of Executive's employment shall not operate to
relieve him of any remaining obligations under Section 3 hereof, and all such
obligations are binding upon his heirs, executors, administrators or other legal
representatives. The Company shall require any successor (whether direct or
indirect, by purchase, merger, reorganization, consolidation, acquisition of
property or stock, liquidation or otherwise) to all or a significant portion of
the assets of the Company, by agreement in form and substance satisfactory to
the Executive, to expressly assume and agree to perform this Agreement in the
same manner and to the same extent that the Company would be required to perform
if no such succession had taken place. Regardless of whether such agreement is
executed by a successor, this Agreement shall be binding upon any successor in
accordance with the operation of law and such successor shall be deemed the
"Company" for the purpose of this Agreement.
11. Arbitration of All Disputes.
---------------------------
(a) Any controversy or claim arising out of or relating to this
Agreement or the breach thereof (including the arbitrability of any controversy
or claim), shall be settled by arbitration in the city of Tulsa in the State of
Oklahoma, by three (3) arbitrators, one of whom shall be appointed by the
Company, one by the Executive and the third of whom shall be appointed by the
first two arbitrators. If the first two arbitrators cannot agree on the
appointment of the third arbitrator, then the third arbitrator shall be
appointed by the American Arbitration Association. The arbitration shall be
conducted in accordance with the rules of the American Arbitration Association,
except with respect to the selection of the arbitrators which shall be as
provided in this Section. The cost of any arbitration process hereunder shall be
borne equally by the Company and Executive. The award of the arbitrators shall
be binding upon the parties. Judgment upon the award rendered by three
arbitrators may be entered in any court having jurisdiction thereof.
(b) In the event that it shall be necessary or desirable for the
Executive to retain legal counsel and/or incur other costs and expenses in
connection with the enforcement of any or all of his rights under this
Agreement, and provided that the Executive substantially prevails in the
enforcement of such rights, the Company shall pay (or the Executive shall be
entitled to recover from the Company, as the case may be) the Executive's
reasonable attorney's fees and costs and expenses in connection with the
enforcement of his rights, including the enforcement of any arbitration award,
up to $50,000 in the aggregate.
12. Notices. All notices, requests, demands and other communications
-------
hereunder must be in writing and shall be deemed to have been duly given upon
receipt if delivered by hand, sent by telecopier or courier, and three (3) days
after such communication is mailed within the continental United States by first
class certified mail, return receipt requested, postage prepaid, to the other
party, in each case addressed as follows:
5
<PAGE>
(a) if to the Company:
Gothic Energy Corporation
5727 South Lewis Avenue, Suite 700
Tulsa, Oklahoma 74105
Attn: Chief Executive Officer
(b) if to the Executive:
Steven P. Ensz
5727 South Lewis Avenue, Suite 700
Tulsa, OK 74105
Addresses may be changed by written notice sent to the other party at the last
recorded address of that party.
13. Severability. If any provisions of this Agreement shall be adjudged
------------
by any court of competent jurisdiction to be invalid or unenforceable for any
reason, such judgment shall not affect, impair or invalidate the remainder of
this Agreement.
14. Prior Understanding. This Agreement embodies the entire understanding
-------------------
of the parties hereto, and supersedes all other oral or written agreements or
understandings between them regarding the subject matter hereof. No change,
alteration or modification hereof may be made except in writing, signed by both
parties hereto. The headings in this Agreement are for convenience and
reference only and shall not be construed as part of this Agreement or to limit
or otherwise affect the meaning hereof.
15. Execution in Counterparts. This Agreement may be executed by the
-------------------------
parties hereto in counterparts, each of which shall be deemed to be original,
but all such counterparts shall constitute one and the same instrument, and all
signatures need not appear on any one counterpart.
16. Choices of Laws. Subject to the provisions of Paragraph 11 and
---------------
without regard to the effect of principles of conflict of laws thereto,
jurisdiction over disputes with regard to this Agreement shall be exclusively in
the courts of the State of Oklahoma, and this Agreement shall be construed in
accordance with and governed by the laws of the State of Oklahoma.
6
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed and delivered this
Agreement as of the day and year first above written.
GOTHIC ENERGY CORPORATION
By:
---------------------------------
ATTEST:
- -----------------------------
GOTHIC PRODUCTION CORPORATION
By:
---------------------------------
ATTEST:
- -----------------------------
-----------------------------------
STEVEN P. ENSZ
7
<PAGE>
EXHIBIT 23.1
Consent of PricewaterhouseCoopers LLP
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
Gothic Energy Corporation, on Form S-3 (File No. 333-23239, No. 333-38679 and
No. 333-68085) of our report dated March 12, 1999, on our audit of the
consolidated financial statements of Gothic Energy Corporation and subsidiary as
of December 31, 1998 and for each of the two years in the period ended December
31, 1998, which report is included in this Annual Report on Form 10-KSB.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
April 6, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<CIK> 0001061312
<NAME> GOTHIC PRODUCTION CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 2,289
<SECURITIES> 0
<RECEIVABLES> 7,355
<ALLOWANCES> (64)
<INVENTORY> 0
<CURRENT-ASSETS> 9,801
<PP&E> 248,201
<DEPRECIATION> (33,201)
<TOTAL-ASSETS> 237,288
<CURRENT-LIABILITIES> 13,850
<BONDS> 301,179
0
36,945
<COMMON> 162
<OTHER-SE> (121,028)
<TOTAL-LIABILITY-AND-EQUITY> 237,288
<SALES> 50,714
<TOTAL-REVENUES> 53,033
<CGS> 39,953
<TOTAL-COSTS> 39,953
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 76,000
<INTEREST-EXPENSE> 35,310
<INCOME-PRETAX> (98,230)
<INCOME-TAX> 0
<INCOME-CONTINUING> (98,230)
<DISCONTINUED> 0
<EXTRAORDINARY> (31,459)
<CHANGES> 0
<NET-INCOME> (129,689)
<EPS-PRIMARY> (6.70)
<EPS-DILUTED> (6.70)
</TABLE>
