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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-KSB/A
(MARK ONE)
/X/ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
/ / TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ________________ TO ________________
COMMISSION FILE NUMBER: 1-12530
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FRONTIER NATURAL GAS CORPORATION
(Exact name of small business issuer in its charter)
OKLAHOMA 73-1421000
(State of incorporation) (I.R.S. Employer Identification
Number)
500 DALLAS, SUITE 2920
HOUSTON, TEXAS 77002
(Address of registrant's principal executive offices, including zip code)
Registrant's telephone number, including area code: (713) 739-7100
NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last
report)
--------------------------
Securities registered under Section 12(b) of the Exchange Act:
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NAME OF EACH EXCHANGE ON WHICH
REGISTERED TITLE OF EACH CLASS
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None None
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Securities registered under Section 12(g) of the Exchange Act:
COMMON STOCK
PREFERRED STOCK
SERIES A COMMON STOCK PURCHASE WARRANTS
SERIES B COMMON STOCK PURCHASE WARRANTS
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-B is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB. /X/
State issuer's revenues for its most recent fiscal year: $908,609
The aggregate market value of the voting stock held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant, for
this purpose, as if they may be affiliates of the registrant) was approximately
$6,487,857 on March 27, 1998 (based on the last sales price of $0.75 per share
as reported on the NASDAQ Stock Market).
9,935,906 shares as the registrant's common stock were outstanding as of
March 27, 1998.
DOCUMENTS INCORPORATED BY REFERENCE
Registrant's Proxy Statement for its 1998 Annual Meeting of Stockholders is
incorporated by reference into Part III.
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FRONTIER NATURAL GAS CORPORATION
FOR YEAR ENDED DECEMBER 31, 1997
TABLE OF CONTENTS
FORM 10-KSB
PART I
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ITEM PAGE
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1. Description of Business.............................................................................. 1
2. Description of Property.............................................................................. 16
3. Legal Proceedings.................................................................................... 17
4. Submission of Matters to a Vote of Security Holders.................................................. 17
PART II
5. Market for Common Equity and Related Stockholder Matters............................................. 18
6. Management's Discussion and Analysis or Plan of Operation............................................ 18
7. Financial Statements................................................................................. 24
8. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................................................ 45
PART III
9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the
Exchange Act........................................................................................ 46
10. Executive Compensation............................................................................... 47
11. Security Ownership of Certain Beneficial Owners and Management....................................... 51
12. Certain Relationships and Related Transactions....................................................... 52
PART IV
13. Exhibits and Reports on Form 8-K..................................................................... 53
Signatures........................................................................................... 55
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PART I
This Form 10-KSB contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. The Company's actual results could differ materially from
those set forth in the forward-looking statements. Certain factors that might
cause such a difference are discussed in the introductory paragraph to
Management's Discussion and Analysis beginning on page 11 of this Form 10-KSB.
ITEM 1. DESCRIPTION OF BUSINESS
GENERAL
THE COMPANY
The Company is an independent energy company engaged in the exploration for
and development of natural gas and oil reserves. It has also has engaged in the
acquisition, production, development and marketing of natural gas and oil. Its
early growth was through acquisitions of natural gas reserves principally in the
mid-continent area of Arkansas, Kansas, Oklahoma and Texas. In recent years, the
Company's business activities have evolved to focus more on exploration and
related developmental drilling projects in southern Louisiana and along the Gulf
Coast of Alabama, Mississippi and Texas. Currently its most significant interest
is its Starboard Project, which is composed of a group of distinct, high
potential exploration prospects, as well as undeveloped locations in the Gulf
Coast region of Louisiana. The Company's current business objective is to
increase its reserves by drilling natural gas and oil wells on prospects
identified and developed through the use of well correlations, CAEX technologies
and 3-D seismic surveys. Its strategy is to increase shareholder value by
becoming the most active explorer in those specific geographically focused areas
that comprise its exploration projects. The Company also may acquire producing
properties as market conditions and the Company's resources allow. The
appropriate use of 3-D seismic is the Company's key tool for achieving these
objectives.
In 1997 the Company was confronted with several issues that resulted in the
substantial depletion of its cash resources. Most significantly, the Company
lost substantial revenues over 1996 due to the premature loss of production in
its Mobile Bay area wells due to water encroachment. The Company also
experienced significant delays in drilling on its Starboard Project. It
responded by participation in a series of primarily third party originated
projects, many of which were not confirmed by 3-D seismic data, and which
drilling resulted in very poor results and minimal cash flow. The Board then
directed the Company to seek a strategic business combination. After a
significant search the Company entered into the below described agreement with
Esenjay Petroleum Corporation ("Esenjay") and Aspect Resources LLC ("Aspect"),
which if consummated, will result in substantial changes in the nature and scope
of the Company. Management and the Board believe said changes will position the
Company to effectively pursue its business strategy. In the event the agreements
are not consummated, the Company would have to seek other partners or sell down
the majority of its project inventory to survive.
On January 19, 1998, the Company entered into the Acquisition Agreement with
Esenjay and Aspect (the "Acquisition Agreement"). Pursuant to the terms and
conditions of the Acquisition Agreement, and subject to approval by the
Company's shareholders the Company will purchase from Esenjay (the "Esenjay
Assets") and Aspect (the "Aspect Assets") certain undeveloped oil and gas
exploration projects in the onshore Gulf Coast area (the "Acquisitions"). The
Company will issue up to 30,991,563 shares of Common Stock to Esenjay in
exchange for the Esenjay Assets, and will issue up to 29,648,636 shares of
Common Stock to Aspect or its assigns in exchange for the Aspect Assets. The
Company has filed a preliminary Schedule 14A proxy statement in this regard and
intends to have a shareholders meeting in late April or early May of 1998 to
seek the approval of its shareholders of the Acquisitions and related matters.
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The Company will substantially increase the scope and diversity of its
portfolio (generally 25% to 40%) of projects upon consummation of the
Acquisitions. The acquired assets include substantial working interests in 28
exploration projects, almost all of which are natural gas oriented, located
primarily along the Texas Gulf Coast. Most of the projects have been, are being,
or will be enhanced with 3-D seismic data and CAEX technologies. The
Acquisitions include leases or options in over 280,000 gross acres. The 3-D
seismic data acquired will, when complete, cover approximately 1,500 square
miles and will all have been shot and initially processed since November 1996.
Drilling operations have commenced on four of the exploration projects to be
acquired by the Company with substantial drilling anticipated through the
remainder of this year.
The discussion of the Company's business and properties set forth below is a
discussion of the Company's historical business and operations before
consummation of the Acquisitions.
The Company moved its headquarters to Houston, Texas, in September 1996, to
allow the Company to more effectively exploit opportunities along the Gulf
Coast. The Company's exploration activities for 1997 continued to center around
furthering its Gulf Coast projects, and in particular, the transition zones of
South Louisiana, which it initiated in 1995. The Company's main emphasis was in
furthering the Starboard Project and, in the second half of 1997, reviewing and
analyzing potential acquisitions and consolidations.
The Starboard Project, located in Terrebonne Parish, Louisiana, has been the
primary focus of the Company's exploration work for over two years, and
continues to be the most significant project in the Company's history. Partners
include Fina Oil and Chemical Company, two affiliates of public utilities, and a
development drilling financing commitment from Bank of America Illinois. The
Company owns working interests in its leases over this project ranging from 12%
to 48%, depending upon the target formation depths. The 3-D seismic data has
been shot, processed and interpreted. The project includes both developmental
and exploratory locations. After seismic interpretation, three initial wells
have been proposed by the partners, two of which are exploratory and one of
which is developmental. Drilling is expected to commence late in the second
quarter of 1998. The Company is highly dependent upon this project, which
dependence will, if the Acquisitions are consummated, be significantly reduced.
In 1997 the Company implemented a drilling program it considered to be
aggressive. In the first nine months of 1997, the Company participated in five
dry holes and one unsuccessful sidetrack operation on South Louisiana prospects.
It also participated in a dry hole in Mobile Bay, Alabama, on a high risk, high
potential Oligocene feature. The Company did however participate in two
successful completions in Garvin County, Oklahoma, resulting from 3-D seismic
data. No drilling was conducted in the fourth quarter. These results, coupled
with limited capital resources, caused the Company to primarily focus on its
Starboard Project and to look at potential consolidation opportunities. In this
regard, it looked at potential asset acquisitions using stock and other
potential opportunities, including business consolidations in order to increase
efficiencies and exploration capital.
As a result of its search for an appropriate business combination
transaction, the Company entered into the Acquisition Agreement with Esenjay and
Aspect. Upon consummation of the transactions contemplated by the Acquisition
Agreement, Esenjay and Aspect or its assignees would own an aggregate of
approximately 85.92% of the issued and outstanding Common Stock. If the Company
does not close the transaction set forth in the Acquisition Agreement, or find
alternative sources of capital, or sell substantial interests in its prospect
inventory, it will not have adequate liquidity to fund ongoing operations.
The Company plans to continue to expand its exploration activities in the
Gulf Coast area through several current activities, including (i) the
Acquisitions; (ii) generation of prospects with its existing partners; (iii)
identification of "bright spot" seismic anomalies; (iv) acquisition of acreage
on additional high potential Gulf Coast exploration projects identified by the
Company; and (v) evaluation of technology enhanced exploration prospect
opportunities in Gulf Coast areas.
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THE ACQUISITIONS
On January 19, 1998 the Company entered into an acquisition agreement with
Esenjay and Aspect, which calls for the Company to issue 30,991,563 shares of
its common stock for Esenjay and 29,648,636 shares of its common stock for
Aspect in exchange for substantial interests in an array of primarily natural
gas, technology enhanced exploration projects. The acquisitions include
interests in 28 projects, leases or options in over 280,000 gross acres, and
interests in 3-D seismic shoots and data, which will cover over 1,500 square
miles when completed. Closing of the Acquisition Agreement, a copy of which is
attached as an exhibit for this Form 10-KSB, is subject to, among other things,
approval by the Company's shareholders. The Company has filed, as of April 14,
1998, a schedule 14A proxy statement calling such a meeting for May 14, 1998. In
conjunction with the Acquisitions, if approved, the Board will add a new
President and C.E.O. and incur a change in the majority of its Board. The
Company will also redeem its issued and outstanding convertible preferred stock.
Further information is provided in the Acquisition Agreement, and amendments
thereof, attached as exhibits to this Form 10-KSB and any and all discussion
herein is qualified in its entirety by reference to said Acquisition Agreement.
Additional information is provided in the schedule 14A proxy statement.
The Effective Date of the Acquisitions is November 1, 1997. On the Effective
Date, none of the Esenjay Assets or Aspect Assets contained any producing
properties. Since the Effective Date, however, Esenjay and Aspect have drilled
or are drilling eight wells that will be for the Company's account if the
Acquisitions are consummated. Of these wells, four have been completed or are
awaiting completion; one has encountered pays which are behind pipe while deeper
zones are being penetrated; two wells are still drilling; and one well was a dry
hole. The eight wells are all based upon 3-D seismic and CAEX technologies and
are representative of the Company's anticipated strategy.
Set forth below is a description of the assets intended to be acquired
pursuant to the Acquisition Agreement. All of the interests are in non-producing
properties. All acreage figures are estimates only due to the ongoing daily
process of acquiring, evaluating, and releasing acreage. Estimates of drilling
and completion costs are gross amounts and are not net to the Companies'
interests in the related projects. Actual costs may vary materially from the
estimates. There can be no assurance that the Company will find commercial
hydrocarbon production from its exploration activities on said properties.
GERONIMO PROJECT. The Company will acquire from Esenjay an aggregate 20%
interest in this project, which consists of approximately 6,700 gross acres of
leases and options in San Patricio County, Texas. A 72 square mile 3-D seismic
survey has been conducted and has identified several prospective drillsites,
three of which have already been drilled. The first two proceeded the
Acquisition Agreement and were drilled by Esenjay. Both resulted in successful
completions. The third well was drilled since the effective date of the
Acquisition Agreement and will be for the account of the Company, if the
Acquisitions are consummated. The well is currently being completed. Historical
total production from Frio Sands within the 3-D seismic survey area has been 500
BCF of gas and 13 million barrels of oil. One deeper Vicksburg well is currently
scheduled to be drilled by the Company in 1998. The estimated cost of drilling
and completing a shallow well in this project area is approximately 1.2 million
dollars with deeper wells costing as much as $4 million.
DUVAL, MCMULLEN PROJECT. The Company will acquire from Esenjay an aggregate
90% interest in this project, which consists of approximately 2,000 gross and
net acres of options in Duval and McMullen Counties, Texas. Within this acreage
is a field that has produced one half trillion cubic feet of gas. A one year old
proprietary 3-D seismic survey has recently become available. Immediate plans
are to acquire and interpret the 3-D seismic data prior to any drilling.
Drilling and completed well costs are estimated to range from $800,000 for
shallow wells (the bulk of the area production has come from these shallower
field pays) and $1.2 million for deeper wells.
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LA ROSA PROJECT. The Company will acquire from Esenjay an 8% interest in
this project, which consists of approximately 7,700 gross acres of options and
leases. The La Rosa Field (which is within the project area) has produced in
excess of 15 million bbls of oil and 170 BCF of gas since 1938. Approximately 25
to 30 square miles of 3-D seismic data has been shot and interpreted. The
prospective sections are Frio and Vicksburg. The first well drilled in 1997, by
Esenjay, prior to entering the Acquisition Agreement, was completed as a Frio
Sands gas producer. One well has been drilled since the effective date of the
Acquisition Agreement, which will be for the account of the Company if the
Acquisitions are consummated. The well was a dry hole. The estimated costs of
drilling and completing a Frio Sands well in this project area are approximately
$550,000.
MATAGORDA I PROJECT. The Company will acquire from Esenjay an aggregate 74%
interest in this project, which consists of approximately 9,500 gross acres of
options in Matagorda County, Texas. Production was first discovered in this area
in 1932. Four shallow wells have produced 854,000 bbls of oil within this
acreage. Available 2-D seismic data suggests numerous undrilled fault segments.
In addition, only one deep well has been drilled. A 3-D seismic survey is
scheduled mid-year 1998 as part of an adjacent project (which survey will cover
the project area). The estimated costs of a drilled and completed shallow well
in this project area are approximately $550,000, and the costs of drilling and
completing a deeper well are approximately $1.3 million.
MATAGORDA II PROJECT. The Company will acquire from Esenjay an aggregate
66% interest in this project, which consists of approximately 7,500 gross acres
of options in Matagorda County, Texas. The project area has produced 41 BCF of
gas and 3,000,000 bbls of oil. Two exploitation/development prospects have been
generated within the prospect area. In additions a 1,000 acre wildcat prospect
has been identified for the entire package of Tex Miss sands, located within the
project area between two producing fields. This area is scheduled for a 3-D
survey mid-year 1998 in conjunction with the Matagorda I Project. The estimated
costs of drilling and completing a shallow well are approximately $550,000 and a
deep well $1.3 million.
THOMPSON CREEK PROJECT. The Company will acquire from Esenjay an aggregate
56% interest in this project, which consists of approximately 2,219 gross acres
in Wayne County, Mississippi. This project appears to be a large, faulted,
salt-based anticline with multiple oil pays. The prospective section ranges from
7,000 feet to 17,000 feet. There currently exists a drillable (without 3-D
seismic) Cotton Valley test which also has secondary objectives. This prospect
was generated by using subsurface and 2-D seismic. However, the Company intends
to employ 3-D seismic prior to any drilling. The structure has both anticline
and fault traps plus drape plays exist on the flank of the salt structure. Known
trend producers include the Tuscaloosa, Paluxy, Wash/Fred, Hosston, Rodessa,
Cotton Valley, Smackover and Norphlet. Typical initial flow rates are 500 bbls
of oil (allowable); wells can, however, easily test at rates greater than 1,000
bbls of oil in the Cotton Valley. Approximately 12 square miles of full fold 3-D
seismic data will be necessary to image the acreage position. A speculative 3-D
seismic survey is being conducted by a seismic vendor over this area and the
processed data should be delivered in the summer of 1998. The estimated costs of
drilling and completing a 15,500' Cotton Valley well in this project area are
approximately $1.35 million.
WILLACY COUNTY PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 78.875% interest in this project, which consists of approximately
10,288 gross acres of leases and options in Willacy County, Texas. Fields in the
immediate area have produced approximately 78 BCF of gas and 2.5 million bbls of
oil. This project includes separate geologic structures known by four different
field names. The pre 3-D seismic geologic study of this area has identified six
possible drilling locations. These locations were picked as a result of
subsurface well correlation and production analysis and will be re-evaluated
after interpretation of the 3-D seismic data. The estimated costs of drilling
and completing a well in this project area are approximately $550,000. A 50
square mile 3-D survey is scheduled for mid-year 1998.
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TIDEHAVEN PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 40.5% interest in this project, which consists of leases and options
covering approximately 7,300 gross acres in Matagorda County, Texas. Fields in
the immediate area have produced approximately 65 BCF of gas and 5 million bbls
of oil. The Tidehaven Field, which is inside the project area, has multiple Frio
Sands pays, down to 12,000 feet. Numerous known pays and multiple fault blocks
make this structure a good 3-D seismic candidate. Interpretation of the 28
square mile 3-D seismic data set is now 90% complete. As of this date, drilling
has commenced on a well in which the Company will, in the event the Acquisitions
are consummated, own a working interest effective prior to the date drilling
commenced. The estimated costs of drilling and completing wells in this project
range from $550,000 to approximately $1.3 million, depending upon depth.
EL MATON PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 46.5% interest in this project, which consists of leases and options
covering approximately 10,468 gross acres in Matagorda County, Texas. Fields in
the immediate area have produced 60 BCF of gas and associated condensate. A 29
square mile 3-D seismic survey was started in late May 1997 as an extension of
the Tidehaven shoot. The geologic setting and target zones are the same as
Tidehaven and the information obtained at Tidehaven should benefit the El Maton
project. The 3-D seismic data is in the interpretation phase and several leads
have been identified. The estimated costs of drilling and completing a well in
this project area are approximately the same as Tidehaven.
MIDFIELD PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 37.5% interest in this project, which consists of leases and options
covering approximately 4,300 gross acres in Matagorda County, Texas. Fields in
the immediate area have produced 90 BCF of gas and 10 million bbls of oil. The
project is an extension of the Tidehaven and El Maton 3-D seismic shoots. A 21
square mile 3-D seismic survey was started in late May 1997. The geologic
setting and target zones are the same as Tidehaven and the information obtained
from Tidehaven should benefit this project. Data interpretation is disappointing
for the zones, which have historically been productive in the area; however, the
data revealed two potential shallow locations. These locations need additional
work before drilling can be scheduled. The estimated costs of drilling and
completing a well in this project area are approximately $550,000.
WOLF POINT PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 45.5% interest in this project, which consists of approximately 1,520
gross acres of state leases in Calhoun County, Texas. Fields in the immediate
area have produced approximately 35 BCF of gas and 6 million bbls of oil. The
project area is covered by 3-D seismic data and Esenjay has drilled five
successful wells on adjacent leases. The prospects will require directional
drilling. This project has previously multiple Frio pay potential from 7,000 to
9,000 feet, all normal pressured. Known field pays from this area are from the
7,200' Frio, 7,500' Frio, 7,700' Frio, Broughton, Oats, Upper Middle and lower
Melbourne sands. Additional geophysical processing is in progress to attempt to
identify direct hydrocarbon indicators. Several potential drill sites have been
delineated. The total estimated costs of a drilled and completed well in this
project area are approximately $900,000.
HALL RANCH PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 41.5% interest in this project, which consists of leases and options
covering approximately 7,550 gross acres under 57 square miles of 3-D seismic
data in Karnes County, Texas. Fields in the immediate area have produced
approximately 250 BCF of gas and over 20 million bbls of oil. The Hall Ranch
area is an under-explored ridge on trend with several producing fields. Multiple
potential pays encompassing four expanded fault blocks have been delineated.
Including potential Wilcox pays from 8,000 to at least 17,000 feet. Known field
pays are from Wilcox reservoirs in the Migura, Roeder, Bunger, Hackney, Middle
Wilcox L series sands, and the Upper Wilcox. Several potential drill sites are
delineated. As of this date drilling has commenced on a deep well in which the
Company will, in the event the Acquisitions are consummated, own a working
interest effective prior to the date drilling commenced. Estimated drilling and
completed well costs in the project area range from approximately $270,000 to
$600,000, and wells completed in the deep zones (to 12,500 feet) cost
approximately $1.8 million.
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HORDES CREEK PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 41.5% interest in this project, which contains leases and options of
approximately 8,300 gross acres located in Goliad County, Texas. Hordes Creek
has potential in the Miocene, Frio, Yegua, and the Upper, Middle, and Lower
Wilcox. The targeted feature has produced 100 BCF of gas to date (from fields in
the project area). Preliminary migrated 3-D data covering 25 square miles is
being interpreted and currently four potential drilling locations have been
identified. The estimated costs of drilling and completing a 9,500' well in the
project area are approximately $800,000.
MIKESKA PROJECT. The Company will acquire from Aspect and Esenjay a 38%
interest in this project, which appears to contain two large growth faults under
a leasehold of 8,200 gross acres located in Live Oak County, Texas. Fields in
the immediate area have produced approximately 200 BCF of gas and 2 million bbls
of oil. This exploration play is characterized by excellent reservoir rock in
the Wilcox. Multiple pay potential exists from 8,500 feet to at least 16,000
feet. This portion of the Wilcox trend contains known pays from the Hockley,
four Queen City sands, four Slick sands, six Luling sands, three Tom Lyne sands
and three to five House sands. A 31 square mile 3-D seismic survey has been
conducted and the data is being interpreted. Currently, several drill sites have
been delineated, and as of this date drilling has commenced on a well in which
the Company will, in the event the Acquisitions are consummated, own a working
interest effective prior to the date drilling commenced. The estimated costs of
drilling and completing a deep well in this project area are approximately $1.4
million.
PILEDRIVER PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 62.5% interest in this project, which consists of 640 gross acres
located in Chambers County, Texas. Fields in the immediate area have produced
approximately 269 BCF of gas and 17 million bbls of oil. The objectives are two
Frio sands. One of these target sands had a significant gas test at the top of
the sand in a well that is down dip to Esenjay's acreage. A recent speculative
3-D seismic survey has been conducted by Western Geophysical. It is the
Company's current intention to acquire and interpret 3-D seismic over the
prospect before making any drilling decisions. The estimated costs of drilling
and completing a well are approximately $1.85 million.
HOUSTON ENDOWMENT PROJECT. The Company will acquire from Aspect and Esenjay
an aggregate 27% interest in this project, which consists of approximately
12,782 gross acres in San Patricio County, Texas. This acreage has been off the
market from 1948 until recently, and as such the Company believes the Endowment
acreage represents a unique opportunity due to the low level of drilling
activity in recent years. The leasehold has significant potential in many zones,
as approximately 20 reservoirs are productive along the trend. A 50 square mile
3-D seismic survey has been conducted and the data set is in the interpretation
phase. One deep dry hole has been drilled within the project area by Esenjay. It
is anticipated that a well will be drilled by the Company this year to test the
shallower sands. A seismic "bright spot" that conforms to structure exists at
the proposed drilling location. An additional shallow well is scheduled for the
2nd quarter of 1998. The estimated costs of drilling and completing a shallow
well in this project area are approximately $700,000 and approximately $1.3
million for a deep well.
BLESSING PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 24% interest in this project, which consists of 10,000 gross acres of
leases and options over 22 square miles of 3-D seismic coverage in Matagorda
County, Texas. Fields in the immediate area have produced approximately 301 BCF
of gas and 15 million bbls of oil. A 3-D seismic survey was conducted in
conjunction with the Tidehaven project. Deep results have been disappointing to
date; however, there are several upper Frio prospect leads. A shallow well, to
test the upper Frio Sands, has been drilled, in which the Company will, in the
event the Acquisitions are consummated, own a working interest effective prior
to the date drilling commenced. There are several potential pay sands in the
well. Pipe is currently being set in order to complete the well. Prior to
drilling, an additional interest was acquired in the well which brought the
Company's total prospective ownership to 37.5% The estimated costs of drilling
and completing a shallow
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well in this project area are approximately $550,000, and the costs of
completing a deep well are approximately $1.3 million.
LIPSMACKER PROJECT. The Company will acquire from Aspect and Esenjay an
aggregate 22% interest in this project, which consists of approximately 15,000
gross acres in Choctaw, Alabama and Clarke Counties, Mississippi. Esenjay
completed a 64 square mile 3-D seismic survey in the fall of 1996, and while
several drilling locations were delineated, the results were generally
disappointing. The estimated costs of drilling and completing a well in this
project area are approximately $1.15 million and there are two remaining
drillable locations. It is unlikely the Company will invest its own capital in
drilling these wells unless new, favorable data becomes available.
BIG GAS PROJECT. The Company will acquire from Aspect a 22.5% interest in
this 3-D seismic project, which consists of options and leases located on 24,700
gross acres in Galveston County, Texas. The primary geological areas identified
for drilling are the Frio and Vicksburg sands. An onshore seismic survey is
expected in mid-1998. The estimated costs of drilling and completing a shallow
well are approximately $900,000 and a deep well $1.5 million.
CANEY CREEK PROJECT. The Company will acquire from Aspect a 12.5% interest
in this project, which consists of options and leases covering 21,000 gross
acres in Matagorda and Wharton Counties, Texas. The project targets the Yegua
and Frio reservoirs. A 3-D seismic survey has been conducted and the
interpretation of the data should be finished by the end of 1998. The estimated
costs of drilling and completing a shallow well are approximately $700,000 and
$1.7 million for a deep well.
LOX B PROJECT. The Company will acquire from Aspect a 25% interest in this
project, which consists of 11,700 gross acres of leases and options in Jefferson
County, Texas. The primary Vicksburg objectives of this project, as well as
Hackberry targets, have been evaluated with 71 square miles of 3-D seismic data.
The interpretation has recognized 22 potential prospects. Most of these
potential targets have attributes analogous with known production. The estimated
costs of drilling and completing a well in this project are approximately
$750,000. The first prospect is likely to be tested during mid-1998.
WEST PORT ACRES PROJECT. The Company will acquire from Aspect a 12.5%
interest in this project, on which 800 gross acres in Jefferson County, Texas
has been leased and a 21 square mile 3-D seismic survey has been conducted.
Additional potential for Hackberry production exists west of Port Acres Field,
which has produced over 300 BCF of gas with over 10 million bbls of associated
condensate. The estimated costs of drilling and completing a shallow well are
approximately $600,000 to $700,000 and a deep well $1.3 million
SHERIFF FIELD AREA PROJECT. The Company will acquire from Aspect a 75%
interest in this project, which consists of 54,100 gross acres of options in
Calhoun County, Texas, in a lightly explored part of the Lower Frio and
Vicksburg sections southwest of Lavaca Bay. Complex shale domes and coastal axis
oriented ridges provide the setting for complex and poorly understood geology in
this portion of the trend. After interpretation of a pilot 3-D seismic survey, a
larger shoot is anticipated to begin in the second quarter of 1998 in which the
Company intends to participate. The estimated costs of drilling and completing a
shallow well are approximately $600,000 and a deep well $1.2 million.
SOUTH WEST PHEASANT PROJECT. The Company will acquire from Aspect a 75%
interest in this project, which consists of 10,000 gross acres of options in
Matagorda County, Texas. The primary target objectives are in the middle and
lower Frio section. A portion of the project area is covered by a Mobil 3-D
seismic survey that is currently being reprocessed. Final interpretations and
well recommendations are expected by April of 1998. The estimated costs of
drilling and completing a shallow well are approximately $550,000 and a deep
well $1.3 million.
EAST JEFFCO PROJECT. The Company will acquire from Aspect a 50% interest in
this project, which consists of 24,000 gross acres of leases and options in
Jefferson County, Texas. The Company plans to
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participate in a 3-D seismic survey that is scheduled for the second quarter of
1998, with Hackberry sands as the primary target. The estimated costs of
drilling and completing a shallow well are approximately $600,000 to $700,000
and a deep well $1.3 million.
STOWELL/BIG HILL PROJECT. The Company will acquire from Aspect a 50%
interest in this project, which consists of 11,700 gross acres of leases and
options in Jefferson County, Texas. Big Hill Field (which is within the project
area) was discovered in 1941 and contains approximately seventy field segments
recognized by the Texas Railroad Commission. Hackberry sands alone have produced
over 56 BCF of gas and 54 million bbls of liquids. The data from a 3-D seismic
survey is being interpreted. Multiple prospects have been identified in the
seismic data. The estimated costs of drilling and completing a shallow well are
approximately $600,000 to $700,000 and a deep well $1.3 million
WEST JEFFCO PROJECT. The Company will acquire from Aspect a 45% interest in
this project, which contains 13,500 gross acres of options in Jefferson County,
Texas. Numerous prospect leads have been identified within the area by log
shows, detailed structural mapping and 2-D seismic data. The Lower Frio Sands
have been prolific producers in this immediate area. A deep (Vicksburg)
exploration target has been conceived. The Company plans to participate in a 3-D
seismic survey that are anticipated to be started in the second quarter of 1998.
The estimated costs of drilling and completing a shallow well are approximately
$600,000 to $700,000 and a deep well $1.3 million.
WEST BEAUMONT PROJECT. The Company will acquire from Aspect a 6.25%
interest in this project, which consists of 11,264 gross acres of leases and
options in Jefferson County, Texas. The project is in the newly established
Hackberry trend, which has experienced over 20 new field discoveries in the past
year, with average reserve sizes of 500,000 bbls of oil equivalent per well. The
trend has been well defined by a three mile corridor downdip of the Hackberry
embayment failure edge. This project is west of the Tri-C 3-D seismic survey,
data from which has been utilized on five new discoveries to date. A 22.5 square
mile 3-D seismic survey has just been completed and will be received by the
Company after it is processed. The estimated costs of drilling and completing a
shallow well are approximately $600,000 to $700,000 and a deep well $1.3 million
EAST TEXAS PINNACLE REEF TREND PROJECT. The Company will acquire from
Aspect a 100% interest in its rights to 3-D seismic data pertaining to the East
Texas Cotton Valley Reef Trend. There is no current acreage position or defined
drilling opportunity currently included in this project.
Most of the above projects may have various independent third parties as
working interest owners based upon who owns leases, who elects to participate in
drilling, industry trades and other factors. Of the interests acquired from
Esenjay, Esenjay will deliver over 90% of its interests to the Company and
retain the balance. As to its retained interests, it will be responsible for its
own pro rata costs. Of the interests acquired from Aspect. Aspect delivered 100%
of its interests in several projects and Aspect retained interests of 50% in
most of the remaining projects. It will be responsible for its own pro rata
costs attributable to said retained interests.
CAEX TECHNOLOGY AND 3-D SEISMIC
The Company, either directly or through its partners, uses CAEX technology
to collect and analyze geological, geophysical, engineering, production and
other data obtained about potential gas or oil prospects. The Company uses this
technology to correlate density and sonic characteristics of subsurface
formations obtained from 2-D seismic surveys with like data from similar
properties, and uses computer programs and modeling techniques to determine the
likely geological composition of a prospect and potential locations of
hydrocarbons.
Once all available data has been analyzed to determine the areas with the
highest potential within a prospect area, the Company may conduct 3-D seismic
surveys to enhance and verify the geological interpretation of the structure,
including its location and potential size. The 3-D seismic process produces a
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three-dimensional image based upon seismic data obtained from multiple
horizontal and vertical points within a geological formation. The calculations
needed to process such data are made possible by computer programs and advanced
computer hardware.
While large oil companies have used 3-D seismic and CAEX technologies for
approximately 20 years, these methods were not affordable by smaller,
independent gas and oil companies until more recently, when improved data
acquisition equipment and techniques and computer technology became available at
reduced costs. The Company began using 3-D seismic and CAEX technologies in 1992
and is using these technologies on a continuing basis. The Company believes that
its use of CAEX and 3-D seismic technology may provide it with certain
advantages in the exploration process over those companies that do not use this
technology. These include better delineation of the subsurface, which can reduce
exploration risks and help optimize well locations in productive reservoirs. The
Company believes this can be readily validated based upon general industry
experience as well as the experience of Aspect and Esenjay. Because computer
modeling generally provides clearer and more accurate projected images of
geological formations, the Company believes it is better able to identify
potential locations of hydrocarbon accumulations and the desirable locations for
wellbores. However, the Company has not used the technology extensively enough
to make any conclusion regarding the Company's ability to interpret and use the
information developed from the technology.
EXPLORATION AND DEVELOPMENT
The Company considers the area along and in the Gulf Coast to be the premier
area in the United States to explore for significant new reserves. This
conclusion is based on several characteristics including (i) a large number of
productive intervals throughout a significant sedimentary section, (ii) numerous
wells with which to calibrate 3-D seismic data, and (iii) complicated geological
formations that the Company believes 3-D seismic is particularly well suited to
interpret. In 1994, the Company began devoting more of its resources to the Gulf
Coast region. The Company initially entered this area by evaluating the onshore
shallow Frio/Miocene Trend. The Company's emphasis recently has shifted to
larger exploration targets in this area due to the greater potential return on
investment resulting from the size of the geological features that remain to be
explored and produced. This includes shallow offshore prospects and deeper and
potentially much larger prospects centering in the transitional lands and waters
of South Louisiana and the transitional and onshore areas along the Texas Gulf
Coast. Additional 2-D and 3-D seismic surveys may need to be conducted to
evaluate these areas more fully, and when determined appropriate, the Company
intends to acquire acreage and drill wells as indicated by the evaluations.
Most of the prospects the Company is pursuing, including the Acquisitions,
are either on the edge of a large existing producing field or between such
fields. The prospects generally involve drilling in fault blocks that to date
have not been adequately tested. Thus, the Company intends to drill prospects
where the formations being tested are known to be productive in the general area
and where it believes 3-D seismic can be used to increase resolution and thereby
lower risk. The availability of the Company's resources and the availability of
joint venture partners will determine the extent to which the Company will
pursue its activities in the Gulf Coast region.
The Starboard Project is comprised of a group of distinct high potential
exploration prospects, as well as proved undeveloped locations. The proved
undeveloped portion of the Starboard Project has been evaluated by independent
petroleum engineers as containing substantial proved undeveloped reserves. See
Notes to Financial Statements. A 3-D seismic survey funded by Fina Oil and
Chemical Company and its partners has been shot and processed. Interpretation
began in March 1997 and the initial 3-D seismic data evaluated drill sites have
been selected.
The interests to be acquired pursuant to the Acquisition Agreement, which
are primarily natural gas oriented, are of such diversity and scope that the
Company's projects will be substantially diversified if the
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Acquisitions are closed. The projects acquired will make the Company
substantially less dependent upon the success or failure of its Starboard
Prospect.
ACQUISITIONS AND DIVESTMENTS
The Company has periodically acquired producing natural gas and oil
properties. In connection with each such acquisition, the Company considers (i)
current and historic production levels and reserve estimates, (ii) exploitation;
(iii) capital requirements; (iv) proximity of product markets; (v) regulatory
compliance; (vi) acreage potential; and (vii) existing production transportation
capabilities. The Company also considers the historic financial operating
results and cash flow potential of each acquisition opportunity and whether the
acquisition will improve the operations of other acquired properties. Evaluation
of the merits of a particular acquisition is based, to the extent relevant, on
all of the above factors as well as other factors deemed relevant by the
Company's management.
Initially, the Company concentrated its acquisition activity in Arkansas,
Kansas, Oklahoma, and Texas, believing that these areas had potential for
exploitation through additional development, enhanced recovery and improved
operating techniques. The Company typically sought properties that were
underdeveloped, overly burdened with expenses or owned by financially troubled
companies. During 1994, prices for natural gas and oil reserves were unusually
high. As a result of and in reaction to market conditions, the Company divested
selected proved producing natural gas and oil properties to take advantage of
the relatively higher prices being paid for such properties, and refocused most
of its 1994 and 1995 activities on its exploration program. However, the Company
will continue to evaluate properties for acquisition if they meet the Company's
acquisition criteria, and as resources permit.
In September 1996, the Company completed the sale of its N.E. Cedardale
field in Major County Oklahoma to OXY USA, Inc., for consideration totaling
$3,550,000. The properties sold represented a substantial portion of the
Company's Oklahoma production. The divestiture of the Oklahoma properties
further facilitated the Company's focus of its resources on its Gulf Coast
projects and reduced debt service requirements over the next three years in an
amount greater than the anticipated net revenue from the properties sold. The
sale included cash of $2,840,000 and certain exchange properties that were
concurrently sold to a third party for $710,000, netting the Company $3,550,000.
HEDGING ACTIVITIES AND MARKETING
The Company markets its natural gas through monthly spot sales. Because
sales made under spot sales contracts result in fluctuating revenues to the
Company depending upon the market price of gas, the Company may enter into
various hedging agreements to minimize the fluctuations and the effect of price
declines or swings. During January 1996, the Company, as required by a bank
credit agreement, entered into a swap agreement on 62,500 MMBTU of its monthly
mid-continent natural gas production for $1.566 per MMBTU for the period
beginning April 1, 1996 and ending January 31, 1999. The swap, which is the
Company's only current hedge, was reduced to 31,250 MMBTU on September 25, 1996,
in connection with the sale of the N.E. Cedardale field. The Company recorded a
loss of $212,000 on this swap reduction. The Company's net gas production
currently is less then the volumes hedged. The hedges in place expire in January
of 1999, and as of December 31, 1997 the Company had an accrued liability of
$128,936 to recognize the projected loss from the above hedges. The Company has
not recently conducted an active hedging program other then as required by the
bank credit agreement. In this regard, the Company had realized net losses of
$814,029 in 1996, which includes the $212,000 loss on the swap reductions, and
$375,410 in 1997 on its required hedge positions.
All of the Company's oil production is sold under market-sensitive or spot
price contracts. The Company's revenues from oil sales fluctuate depending upon
the market price of oil. No purchaser accounted for more than 10% of the
Company's total revenue in 1996 or 1997. The Company does not believe the loss
of any existing purchaser would have a material adverse effect on the Company.
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In December 1991 the Company entered into and performed under a long-term
fixed price contract with an industrial end-user, Waldorf Corporation, which
contract initially covered seven years and the delivery of 7.1 Bcf of natural
gas. The contract included certain prepayments to the Company. The agreement was
satisfied in January 1996 when the Company entered into an agreement with
Waldorf to terminate the Waldorf agreement as of January 31, 1996. The Company
paid Waldorf $2,181,489, which represents a return of Waldorf's advance on
2,490,103 MMBTU's of natural gas, plus a settlement payment of $313,912. The
Company has been able to sell all natural gas production to other sources at
equal or higher prices since the termination of the contract. The Company
anticipates that it will be able to continue to sell all available natural gas
production in the foreseeable future.
OPERATING HAZARDS AND INSURANCE
The gas and oil business involves a variety of operating risks, including
the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured
formations, and environmental hazards such as oil spills, gas leaks, ruptures or
discharges of toxic gases, the occurrence of any of which could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, cleanup responsibilities, regulatory investigation
and penalties and suspension of operations.
The Company maintains a gas and oil lease operator insurance policy that
insures the Company against certain sudden and accidental risks associated with
drilling, completing and operating its wells. There can be no assurance that
this insurance will be adequate to cover any losses or exposure to liability.
The Company also carries comprehensive general liability policies and an
umbrella policy. The Company and its subsidiaries carry workers' compensation
insurance in all states in which they operate. The Company maintains various
bonds as required by state and federal regulatory authorities. Although the
Company believes these policies are customary in the industry, they do not
provide complete coverage against all operating risks. An uninsured or partially
insured claim, if successful and of sufficient magnitude, could have a material
adverse effect on the Company and its financial condition. If the Company
experiences significant claims or losses, the Company's insurance premiums could
be increased which may adversely affect the Company and its financial condition
or limit the ability of the Company to obtain coverage. Any difficulty in
obtaining coverage may impair the Company's ability to engage in its business
activities.
REGULATION
GENERAL. The gas and oil industry is extensively regulated by federal,
state and local authorities. In particular, gas and oil production operations
and economics are affected by price controls, environmental protection statutes,
tax statutes and other laws and regulations relating to the petroleum industry,
as well as changes in such laws, changing administrative regulations and the
interpretations and application of such laws, rules and regulations. Gas and oil
industry legislation and agency regulations are under constant review for
amendment and expansion for a variety of political, economic and other reasons.
Numerous regulatory authorities, federal, and state and local governments issue
rules and regulations binding on the gas and oil industry, some of which carry
substantial penalties for failure to comply. The regulatory burden on the gas
and oil industry increases the Company's cost of doing business and,
consequently, affects its profitability. The Company believes it is in
compliance with all federal, state and local laws, regulations and orders
applicable to the Company and its properties and operations, the violation of
which would have a material adverse effect on the Company or its financial
condition.
SEISMIC PERMITS. Current law in the State of Louisiana requires permits
from owners of at least an undivided 80% interest in each tract over which the
Company intends to conduct seismic surveys. As a result, the Company may not be
able to conduct seismic surveys covering its entire area of interest. Moreover,
3-D seismic surveys typically are conducted from various locations both inside
and outside the area of interest to obtain the most detailed data of the
geological features within the area. To the extent
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that the Company is unable to obtain permits to access locations to conduct the
seismic surveys, the data obtained may not be as detailed as might otherwise be
available.
EXPLORATION AND PRODUCTION. The Company's operations are subject to various
regulations at the federal, state and local levels. Such regulations include (i)
requiring permits for the drilling of wells; (ii) maintaining bonding
requirements to drill or operate wells; and (iii) regulating the location of
wells, the method of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilled, the plugging and abandoning of wells
and the disposal of fluids used in connection with well operations. The
Company's operations also are subject to various conservation regulations. These
include the regulation of the size of drilling and spacing units, the density of
wells that may be drilled, and the unitization or pooling of gas and oil
properties. In addition, state conservation laws establish maximum rates of
production from gas and oil wells, generally prohibiting the venting or flaring
of gas, and impose certain requirements regarding the ratability of production.
The effect of these regulations is to limit the amount of gas and oil the
Company can produce from its wells and to limit the number of wells or the
locations at which the Company can drill. Recently enacted legislation and
regulatory action in Texas and Oklahoma is intended to reduce the total
production of natural gas in those states. Although such restrictions have not
had a material impact on the Company's operations to date, the extent of any
future impact therefrom cannot be predicted.
NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION. Federal legislation
and regulatory controls in the United States have historically affected the
price of the natural gas produced by the Company and the manner in which such
production is marketed. The transportation and sale for resale of natural gas in
interstate commerce are regulated by the Federal Energy Regulatory Commission
("FERC") pursuant to the Natural Gas Act and the Natural Gas Policy Act of 1978
("NGPA"). The maximum selling prices of natural gas were formerly established
pursuant to regulation. However, on July 26, 1989, the Natural Gas Wellhead
Decontrol Act of 1989 ("Decontrol Act") was enacted, which terminated wellhead
price controls on all domestic natural gas on January 1, 1993 and amended the
NGPA to remove completely by January 1, 1993 price and nonprice controls for all
"first sales" of natural gas, which will include all sales by the Company of its
own production. Consequently, sales of the Company's natural gas currently may
be made at market prices, subject to applicable contract provisions. The FERC's
jurisdiction over natural gas transportation was unaffected by the Decontrol
Act.
The FERC also regulates interstate natural gas transportation rates and
service conditions, which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has endeavored to make
interstate natural gas transportation more accessible to gas buyers and sellers
on an open and nondiscriminatory basis. The FERC's efforts have significantly
altered the marketing and pricing of natural gas. Commencing in April 1992, the
FERC issued Order Nos. 636, 636-A and 636-B (collectively, "Order No. 636"),
which, among other things, require interstate pipelines to "restructure" their
services to provide transportation separate or "unbundled" from the pipelines'
sales of gas. Also, Order No. 636 requires interstate pipelines to provide
open-access transportation on a basis that is equal for all gas supplies. Order
No. 636 has been implemented through decisions and negotiated settlements in
individual pipeline services restructuring proceedings. In many instances, the
result of Order No. 636 and related initiatives have been to substantially
reduce or eliminate the interstate pipelines' traditional role as wholesalers of
natural gas in favor of providing only storage and transportation services. The
FERC has issued final orders in virtually all pipeline restructuring
proceedings, and has now commenced a series of one year reviews to determine
whether refinements are required regarding he implementation by individual
pipelines Order No. 636. In July 1996, the United States Court of Appeals for
the District of Columbia Circuit largely upheld Order No. 636.
Although Order No. 636 does not regulate natural gas production operations,
the FERC has stated that Order No. 636 is intended to foster increased
competition within all phases of the natural gas industry. It is unclear what
impact, if any, increased competition within the natural gas industry under
Order
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No. 636 will have on the Company and its natural gas marketing efforts. Although
Order No. 636 could provide the Company with additional market access and more
fairly applied transportation service rates, terms and conditions, it could also
subject the Company to more restrictive pipeline imbalance tolerances and
greater penalties for violation of those tolerances. The Company does not
believe, however, that it will be affected by any action taken with respect to
Order No. 636 materially differently than other natural gas producers and
marketers with which it competes.
The FERC has recently announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner for setting
rates for new interstate pipeline construction, the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary market, and the use of negotiated and market-based
rates and terms and conditions for interstate gas transmission. While any
resulting FERC action would affect the Company only indirectly, the FERC's
stated intention is to further enhance competition in natural gas markets.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any such
proposals might become effective, or their effect, if any, on the operations of
the Company. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future.
LOUISIANA LEGISLATION. The Louisiana legislature passed Act 404 in 1993,
which permits a party transferring an oil field site to establish a
site-specific trust account for such oil field. If the site-specific trust
account is established in accordance with the requirements of the statute, the
party transferring the oil field site shall not thereafter be held liable by the
state for any site restoration costs or actions associated with the transferred
oil field site. The parties to a transfer may elect not to establish a site-
specific trust account, however, in the absence of such an account, the
transferring party will continue to have liability for the costs of restoration
of the site. If the parties to a transfer elect to establish a site-specific
trust account pursuant to the statute, the Louisiana Department of Natural
Resources ("DNR") requires an oil field site restoration assessment to be made
at the time of the transfer or within one year thereafter, to determine the site
restoration requirements existing at the time of transfer. Based upon the site
restoration assessment, the parties to the transfer must propose to the DNR a
funding schedule for the site-specific trust account, providing for some
contribution to the account at the time of transfer and at least quarterly
payment thereafter. If the DNR approves the establishment and funding of the
site-specific trust account, the purchaser will thereafter be the responsible
party to the state, except that the failure of a transferring party to make a
good faith disclosure of all oil field site conditions existing at the time of
the transfer will render that party liable for the costs of restoration of such
undisclosed conditions in excess of the balance of the site-specific trust fund.
OIL SALES AND TRANSPORTATION RATES. Sales of crude oil, condensate and gas
liquids by the Company are not regulated and are made at market prices. The
price the Company receives from the sale of these products is affected by the
cost of transporting the products to market. Effective as of January 1, 1995,
the FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which would generally index such rates
to inflation, subject to certain conditions and limitations. These regulations
could increase the cost of transporting crude oil, liquids and condensate by
pipeline. These regulations are subject to pending petitions for judicial
review. The Company is not able to predict with certainty what effect, if any,
these regulations will have on it, but other factors being equal, the
regulations may tend to increase transportation costs or reduce wellhead prices
for such commodities.
ENVIRONMENTAL MATTERS. The Company's oil and natural gas exploration,
development and production operations are subject to stringent federal, state
and local laws governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental agencies,
such as the Environmental Protection Agency ("EPA"), issue regulations to
implement and enforce such
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laws, which often require difficult and costly compliance measures that carry
substantial civil and criminal penalties for failure to comply. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentrations of various substances that can
be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands, ecologically sensitive and other protected areas, require
some form of remedial action to prevent pollution from former operations, such
as plugging abandoned wells, and impose substantial liabilities for pollution
resulting from the Company's operations. In addition, these laws, rules and
regulations may restrict the rate of oil and natural gas production below the
rate that would otherwise exist. The regulatory burden on the oil and gas
industry increases the cost of doing business and consequently affects its
profitability. Changes in environmental laws and regulations occur frequently,
and any changes that result in more stringent and costly waste handling,
disposal or cleanup requirements could adversely affect the Company's operations
and financial position, as well as those of the oil and gas industry in general.
While management believes that the Company is in substantial compliance with
current applicable environmental laws and regulations and the Company has not
experienced any material adverse effect from compliance with these environmental
requirements, there is no assurance that this will continue in the future.
The primary environmental statutory and regulatory programs that affect the
Company's operations include the following:
The Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), also known as "Superfund," imposes liability without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to be responsible for the release of a "hazardous substance"
into the environment. These persons include (i) the current owner and operator
of a facility from which hazardous substances are released, (ii) owners and
operators of the facility at the time the disposal of hazardous substances took
place, (iii) generators of hazardous substances who arranged for the disposal or
treatment at or transportation to such facility of hazardous substances and (iv)
transporters of hazardous substances to disposal or treatment facilities
selected by them.
Under CERCLA, such persons may be subject to joint and several liability for
the costs of cleaning up the hazardous substances that have been released into
the environment, for damages to natural resources and for the costs of certain
health studies, and it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other pollutants into the
environment. Furthermore, although petroleum, including crude oil and natural
gas, is exempt from CERCLA, at least two courts have ruled that certain wastes
associated with the production of crude oil may be classified as "hazardous
substances" under CERCLA, and thus such wastes may become subject to liability
and regulation under CERCLA. Regulatory programs aimed at remediation of
environmental releases could have a similar impact on the Company.
The Federal Water Pollution Control Act of 1972 ("FWPCA") as amended, also
known as the Clean Water Act ("CWA"), imposes restrictions and strict controls
regarding the discharge of pollutants including produced waters and other oil
and gas wastes, into waters of the United States (as defined in the CWA). The
discharge of pollutants into regulated waters is prohibited, except in accord
with the terms of a permit issued by EPA or the state. These proscriptions also
prohibit certain activity in wetlands unless authorized by a permit issued by
the U.S. Army Corps of Engineers. Sanctions for unauthorized discharges include
administrative, civil and criminal penalties, as well as injunctive relief.
The Oil Pollution Act of 1990 ("OPA") amends certain provisions of the CWA,
and other statutes as they pertain to the prevention of and response to spills
or discharges of hazardous substances or oil into navigable waters. Under OPA, a
person owning or operating a facility or equipment (including land drilling
equipment) from which there is a discharge or threat of a discharge of oil into
or upon navigable waters or adjoining shorelines is liable, regardless of fault,
as a "responsible party" for removal costs and damages.
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Federal law imposes strict, joint and several liability on facility owners for
containment and clean-up costs and certain other damages, including natural
resource damages, arising from a spill.
The EPA is also authorized to seek preliminary and permanent injunctive
relief and, in certain cases, criminal penalties and fines. State laws governing
the control of water pollution also provide varying civil and criminal penalties
and liabilities in the case of releases of petroleum or its derivatives into
surface waters or into the ground. In the event that a discharge occurs at a
well site at which the Company is conducting production operations, the Company
may be exposed to claims that it is liable under OPA, the CWA or similar state
laws.
The Resource Conservation and Recovery Act ("RCRA"), as amended, generally
does not regulate most wastes generated by the exploration and production of oil
and gas. RCRA specifically excludes from the definition of hazardous waste
"drilling fluids, produced waters, and other wastes associated with the
exploration, development, or production of crude oil, natural gas or geothermal
energy." However, these wastes may be regulated by EPA or state agencies as
solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste
solvents, laboratory wastes, and waste compressor oils, may be regulated as
hazardous waste. Pipelines used to transfer oil and gas may also generate some
hazardous wastes. Although the costs of managing solid and hazardous waste may
be significant, the Company does not expect to experience more burdensome costs
than similarly situated companies involved in oil and gas exploration and
production.
COMPETITION
The gas and oil industry is highly competitive in all of its phases. The
Company encounters strong competition from other gas and oil companies in all
areas of its operations, including the acquisition of exploratory and producing
properties, the permitting and conducting of seismic surveys and the marketing
of gas and oil. Many of these competitors possess greater financial, technical
and other resources than the Company. Competition for the 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 the Company establishes from time to time for the minimum projected
return on investment. Competition also may be presented by alternative fuel
sources, including heating oil and other fossil fuels. There has been increased
competition for lower risk development opportunities and for available sources
of financing. In addition, the marketing and sale of natural gas and processed
gas are competitive. Because the primary markets for natural gas liquids are
refineries, petrochemical plants and fuel distributors, prices generally are set
by or in competition with the prices for refined products in the petrochemical,
fuel and motor gasoline markets.
FACILITIES
In July 1996 the Company executed a five year lease agreement commencing
September 1, 1996 to occupy approximately 7,600 square feet of office space in
downtown Houston, at an annual rate of $117,068. The Company currently leases
more office space than it needs and intends to sublet a portion of its office
space in 1998. Frontier completed the move of its corporate headquarters to
Houston, Texas in September, 1996.
EMPLOYEES
The Company employs seven full-time and two part-time employees in its
Houston, Texas office. Their functions include management, production, geology,
geophysics, land, legal, gas marketing, accounting, financial planning and
administration. Certain operations of the Company's field activities are
accomplished through independent contractors and are supervised by the Company.
The Company believes its relations with its employees and contractors are good.
No employees of the Company are represented by a union.
15
<PAGE>
ITEM 2. DESCRIPTION OF PROPERTY
PRINCIPAL AREAS OF OPERATIONS
The Company owns and operates producing properties located in four states
with proved reserves located primarily in Louisiana, Oklahoma and Texas. The
Company currently owns interests in 6 wells it operates, of which 4 are
producing. The Company also owns non-operated interests in approximately 27
wells in Oklahoma, Texas, Louisiana and Kansas, of which 18 are producing. Daily
production from both operated and non-operated wells net to the Company's
interest averaged 332.34 Mcf per day and 19.96 Bbls of oil per day for the year
ended December 31, 1997. These properties provide the basis for the Company's
current revenues.
DRILLING ACTIVITY
The Company drilled only one well in each of 1991, 1992 and 1993, and such
wells were productive. In 1994, the Company drilled five exploratory wells of
which four were productive and one developmental well, which was not productive.
In 1995, the Company drilled seven exploratory wells of which four were
productive. In 1996, the Company participated in the drilling of four Garvin
County, Oklahoma wells of which two were productive. In 1997, the Company
participated in five dry holes and one unsuccessful sidetrack operation on South
Louisiana prospects. It also participated in a dry hole in Mobile Bay, Alabama,
on a high risk, high potential Oligocene feature. The Company also participated
in two successful completions in Garvin County, Oklahoma, on prospects resulting
from 3-D seismic data.
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding the Company's
ownership as of December 31, 1997 of productive gas and oil wells in the areas
indicated.
<TABLE>
<CAPTION>
GAS OIL
---------------------- ----------------------
GROSS NET GROSS NET
----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Oklahoma........................................................ 5 0.04 8 0.20
Texas........................................................... 1 0.07 5 2.22
Louisiana....................................................... 2 0.79 0 0.00
Kansas.......................................................... 1 0.10 0 0.00
--- --- --- ---
Total......................................................... 9 1.00 13 2.42
--- --- --- ---
--- --- --- ---
</TABLE>
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes, average prices received (net of transportation) and average production
costs associated with the Company's sale of gas and oil for the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1997 1996
------------- ------------
<S> <C> <C>
Net Production:
Oil (Bbl)...................................................... 7,286 9,276
Gas (Mcf)...................................................... 121,304 1,406,016
Gas equivalent (Mcfe).......................................... 165,020 1,461,672
Average sales price:
Oil ($ per Bbl)................................................ $ 20.28 $ 20.99
Gas ($ per Mcf)................................................ $ 2.06 $ 2.18
Average production expenses and taxes ($ per Mcfe)............. $ 2.13(1) $ .78
</TABLE>
- ------------------------
(1) This computation includes $164,792 in costs associated with the fulfillment
of contractual transportation obligations on the Company's Mobile Bay
Properties. If this amount were not included, the average production
expenses and taxes per Mcfe would have been $1.13.
16
<PAGE>
LEASEHOLD ACREAGE
The following table sets forth as of December 31, 1997, the gross and net
acres of proved developed and proved undeveloped gas and oil leases which the
Company holds or has the right to acquire. It does not include any of the
interests the Company would acquire if the Acquisitions are consummated.
<TABLE>
<CAPTION>
PROVED DEVELOPED PROVED UNDEVELOPED
-------------------- --------------------
STATE GROSS NET GROSS NET
- ----------------------------------------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C>
Oklahoma....................................... 38,606 14,091 1,370 452
Texas.......................................... 10,742 1,999 54 54
Alabama........................................ 5,156 4,877 5,710 1,805
Arkansas....................................... 1,672 357 6,360 2,544
Louisiana...................................... 1,474 449 4,075 3,397
Kansas......................................... 1,600 126 -- --
--------- --------- --------- ---------
Total........................................ 59,250 21,899 17,569 8,252
</TABLE>
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried
working, net profits, working and other similar interests and contractual
arrangements customary in the gas and oil industry, to liens for current taxes
not yet due and to other encumbrances. As is customary in the industry in the
case of undeveloped properties, little investigation of record title is made at
the time of acquisition (other than a preliminary review of local records).
Investigations, including a title opinion of legal counsel, are generally made
before commencement of drilling operations. The Company has granted a mortgage
on its interest in the Starboard Prospect to secure repayment of the
non-recourse funding to 420 Energy Investments, Inc., and a mortgage on all of
its undeveloped properties, including Starboard, to Duke Energy Financial
Services, Inc. It has also granted to Bank of America, Illinois, a mortgage on
virtually all remaining producing gas and oil properties to secure repayment
under its credit facility with the bank.
ITEM 3. LEGAL PROCEEDINGS
Esenjay was a defendant in a lawsuit regarding injuries to a former employee
that resulted in a judgment against Esenjay of approximately $17,700,000. The
judgment was settled by Esenjay's insurers, who agreed to make cash payments to
the plaintiff, and by Esenjay who agreed to implement a mutually agreeable work
safety plan. The settlement was entered into and approved by the court entering
an agreed judgment on December 31, 1997. On approximately April 16, 1998, the
plaintiff filed an action against both Esenjay and the Company alleging, in
part, that Esenjay has failed and refused to implement an appropriate safety
plan and entered negotiations with the Company to convey material assets to it
which, if consummated, would negate plaintiff's benefits to be obtained by
Esenjay's safety plan, thereby fraudulently inducing plaintiff to settle the
judgment against Esenjay. The Company believes the claims are not supported by
the facts and are without merit. The Company and Esenjay intend to vigorously
defend the claims.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On October 20, 1997 a special meeting of the shareholders of the Company was
held. At that meeting the shareholders approved an amendment, the Board of
Directors had authorized, to the Certificate of Incorporation to increase the
number of authorized shares of Common Stock from 20,000,000 to 40,000,000
shares. Under the amendment, Article V of the Certificate was approved to read
as follows: "The total number of shares of all classes of stock which the
corporation shall have the authority to issue is 45,000,000 shares, divided into
classes designated as (i) 40,000,000 shares of Common Stock, par value $0.01 per
share (the "Common Stock"), and 5,000,000 shares of Preferred Stock, par value
of $0.01 per share (the "Preferred Stock"). Said amendment was subsequently
filed of record on February 11, 1998.
17
<PAGE>
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
On November 12, 1993, Frontier Natural Gas Corporation's stock was admitted
to trading on the NASDAQ Small Cap Market under the symbols "FNGC" for its
common stock, "FNGCP" for its convertible preferred stock and "FNGCW" for its
Series A Warrants. On August 9, 1996 the Company's Series B Warrants were
admitted to trading on the same market. The Company estimates there are
approximately 84 common shareholders of record and 2,337 beneficial owners of
the common stock.
For the periods indicated below, the following table sets forth the range of
high and low sales prices for Frontier Natural Gas Corporation's common stock,
convertible preferred stock, Series A Warrants, and series B Warrants as
reported by NASDAQ. There was no public market for the securities prior to
November 12, 1993. NASDAQ quotations represent prices between dealers without
adjustment for retail markups, markdowns or commissions and may not necessarily
represent actual transactions. There have been no dividends declared or paid to
the owners of the common stock nor does the Company currently intend to declare
any such dividends. The Company's convertible preferred stock has priority as to
dividends over the common stock and no common stock cash dividend can be
declared or paid unless all accrued convertible preferred stock dividends have
been paid. As of December 31, 1997, the Company has undeclared and unpaid
dividends in the amount of $180,518 on its convertible preferred stock. Although
the Company is not required to declare and pay such dividends, the Company is
precluded from paying dividends to its common shareholders until such dividends
are paid current. Due to newly enacted listing requirements of the NASDAQ Small
Cap Market effective February 23, 1998, the Company is currently not in
compliance with the continued listing requirements in two regards. One is the
requirement for two independent directors. The Company has only one at this time
due to the death in February of 1998 of Mr. Neal Elliott. The Company's Board of
Directors has the power to, and intends to, elect an additional independent
director to cure this item on a timely basis. In addition, the new continued
listing requirement calls for a minimum bid price for the Company's common stock
to equal or exceed $1.00 on an ongoing basis. The Company intends to propose to
it's shareholders a reverse stock split intended to timely remedy this
deficiency.
<TABLE>
<CAPTION>
CONVERTIBLE PREFERRED SERIES A WARRANTS SERIES B WARRANTS
COMMON
---------------------- ---------------------- ---------------------- ----------------------
QUARTER ENDED HIGH LOW HIGH LOW HIGH LOW HIGH LOW
- ------------------------------ --------- --------- --------- --------- --------- --- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
December 31, 1997............. $ 2 $ 11/16 $ 8 1/2 $ 7 1/8 $ 3/8 $ 1/64 $ 7/16 $3/32
September 30, 1997............ 2 5/8 9 7 1/4 3/16 1/16 3/4 1/8
June 30, 1997................. 2 3/8 1 11/16 10 9 5/16 3/16 15/16 1/2
March 31, 1997................ 3 9/16 2 1/16 10 5/8 9 1/2 5/32 1 11/16 11/16
December 31, 1996............. 2 15/16 2 10 1/4 8 11/32 1/16 1 3/8 5/8
September 30, 1996............ 2 3/4 1 5/8 8 5/8 7 3/8 11/16 3/16 1 1/8 5/16
June 30, 1996................. 2 11/16 1 7/8 7 3/8 7 1/4 1/2 7/32 1 1/8 5/16
March 31, 1996................ 2 11/16 1 27/64 7 1/4 7 1/4 15/32 1/8 1 3/8 9/16
</TABLE>
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
The following discussion and analysis reviews Frontier Natural Gas
Corporation's operations for the years ended December 31, 1997 and 1996 and
should be read in conjunction with its consolidated financial statements and
notes related thereto. Certain statements contained herein set forth
management's intentions, plans, beliefs, expectations or predictions of the
future and are forward-looking statements. It is important to note that
Frontier's actual results could differ materially from those projected in such
forward-looking statements. The risks and uncertainties include but are not
limited to potential unfavorable or uncertain results of 3-D seismic surveys not
yet completed, drilling cost and operational uncertainties, risks associated
with quantities of total reserves and rates of production from existing gas and
oil reserves and pricing assumptions of said reserves, potential delays in the
timing of
18
<PAGE>
planned operations, competition and other risks associated with permitting
seismic surveys and with leasing oil and gas properties, potential cost
overruns, regulatory uncertainties, and the availability of capital to fund
planned expenditures as well as general industry and market conditions.
OVERVIEW
In mid-1996, the Company refocused its activities from acquiring gas
reserves principally in the mid-continent region of the United States to
concentrate on exploration and related development drilling projects in Southern
Louisiana and along the Gulf Coast region of Alabama, Mississippi and Texas. The
Company's most significant interest in the Gulf Coast region is the Starboard
Project, which is comprised of a group of distinct exploration prospects, as
well as undeveloped locations.
During 1996 and 1997, the Company's drilling activities, which were based
significantly on 2-D seismic data, were unsuccessful. This unsuccessful drilling
activity, along with an unexpected drop in production from the Company's Mobile
Bay area wells, reduced the Company's cash and capital resources at the time the
drilling phase of the Starboard Project was approaching. To address the
Company's capital needs for the Starboard Project and other activities, the
Board of Directors, at its meeting on August 12, 1997, directed management to
look for potential assets to acquire in exchange for the Company's Common Stock,
to identify and review potential business consolidation opportunities, identify
potential partners to help fund the Company's proposed drilling activities on
the Starboard Project and in other locations, and to consider any other avenues
to strengthen the Company's capital resources and diversify its exploration
opportunities. The Board also directed management to reduce overhead wherever
prudently possible and the Company retained an investment advisor to aid in
achieving these objectives.
To better the position the Company to enter into a potential transaction,
the Company called a special shareholders meeting to increase its authorized
Common Stock from 20,000,000 to 40,000,000 shares. The Company's shareholders
approved the increase on October 20, 1997. The Board also determined to not
further extend any existing employment contracts with senior management, and to
settle any deferred compensation liabilities with those individuals, to create
more flexibility in all appropriate alternatives for strategic consolidations.
The Company, in conjunction with its investment advisor, began reviewing
sources of capital and consolidation candidates, and where appropriate, entered
preliminary discussions to identify those candidates that the Company considered
most attractive and that had a similar interest in pursuing negotiations.
The Company explored a series of such transactions and ultimately management
brought four proposals to its Board of Directors. The Board, after receipt of
the advice of management and its investment adviser, and receipt of due
diligence reports and other materials, unanimously agreed that the transaction
with Aspect and Esenjay was the best option for the Company's shareholders. The
Acquisition Agreement was executed January 19, 1998, and is subject to, among
other items, approval by the Company's shareholders. The Company's ongoing
business plan is substantially dependent upon approval of the Acquisitions by
its shareholders and the closing of said Acquisitions. If closed, the Company
will convey a substantial majority of its common stock to acquire the array of
significant technology enhanced natural gas oriented exploration projects, many
of which are ready to drill. It will also substantially broaden and strengthen
its management which it believes will facilitate expanded access to capital
markets due to the value and diversity of its exploration project portfolio.
Conversely, if the Acquisitions are not closed, the Company would be required to
rapidly find another consolidation, or other capital sources, or sell
substantial interests in its existing exploration projects or it would be unable
to fund ongoing operations.
YEAR 2000
The Company has recognized the need to ensure its systems, equipment and
operations will not be adversely impacted by the change to the calendar year
2000. As such, the Company operates on an internally designed software package
that is compliant with the year 2000. The Company is attempting to identify
other potential areas of risk and has begun addressing these in its planning,
purchasing and daily
19
<PAGE>
operations. The total costs of connecting all internal systems, equipment and
operations to the year 2000 has not been fully quantified, but it is not
expected to be a material cost to the Company. However, although no estimates
can be made as to the potential adverse impact resulting from the failure of
third party service providers and vendors to prepare for the year 2000 the
Company intends to formulate a plan to deal with potential year 2000 issues.
COMPARISON OF 1997 TO 1996
REVENUE. Total revenues decreased 71.3% from $3,166,792 for the year ended
December 31, 1996, to $908,609 for the year ended December 31, 1997.
Total gas and oil revenues decreased 79.1% from $3,176,861 to $664,126. The
decrease in gas and oil revenues were primarily attributable to ceased
production from the Mobile Bay wells which came on stream in December of 1995
and from the sale of properties discussed below. A contributing factor to the
decline in gas and oil revenues was the sale of the Company's NE Cedardale field
located in Major County, Oklahoma in September 1996. The Company recorded gas
and oil revenues associated with the aforementioned factors of $2,003,251 for
1996 and $62,471 for 1997. The remainder of this decrease is primarily
attributable to sales of other interests and gas price fluctuations. Operating
fees to the Company decreased from $213,834 for the year 1996 to $55,021 for the
year 1997, due to the sale of a substantial portion of the Company's operated
properties. The decrease in gas and oil revenues was partially offset by an
increase in gain on sale of assets of $201,583 from $250,437 reported for the
year 1996 to $452,020 reported for the year 1997. The increase is notably due to
the sell down of certain Company prospects and the sale of certain Company
properties located in Texas, Oklahoma and Arkansas. The Company realized losses
from various commodity transactions totaling $375,410 for the year ended
December 31, 1997. The decrease in the loss is primarily attributable to the
amended swap agreement with Bank of America in September of 1996, which
decreased the volume of the swap agreements. This compares to a realized loss of
$814,029 for the same period 1996. Settlement costs in connection with the
amendment to the gas swap agreement with Bank of America totaling $212,000 are
included in the 1996 realized losses from commodity transactions. These swap
agreement losses were attributable to various transactions in which the Company
hedged its future gas delivery obligations as a requirement for its bank loan
facility. The determination of gains or losses is directly affected by the spot
gas prices being higher or lower than the hedge contracts for the same period.
In addition to the realized losses from commodity transactions, the Company
accrued $128,936 for unrealized losses for the year ended December 31, 1997.
This was the amount by which the hedges in place exceeded the production. There
were no accrued losses at December 31, 1996. The Company also had other revenues
of $241,788 for the year ended December 31, 1997 as compared to $339,689 for the
year ended December 31, 1996. The reduction is primarily attributable to reduced
revenues realized from the performance of exploratory and geophysical data
processing on a fee basis. Included in the year ended December 31, 1997 other
revenue is the net gain of $25,794 from the Company's officers deferred
compensation settlement, which was executed on August 15, 1997.
COSTS AND EXPENSES. Total costs and expenses of the Company decreased 28.4%
from $8,191,811 in 1996 to $5,862,412 in 1997. Although there were increases in
exploration costs, delay rentals and unrealized loss on commodity transactions
there were decreases in lease operating expenses, production taxes,
transportation, depreciation, interest expense, cost of settling gas contracts
and futures contracts and general and administrative expenses, which resulted in
the net decrease as more fully described below.
Exploration costs increased 71.5% from $1,317,161 in 1996 to $2,258,702 in
1997. The exploration costs in 1997 reflect $380,464 of charges attributable to
expensed investments, and $1,772,746 of dry hole costs. The increase was due to
increased exploratory drilling.
DELAY RENTAL TRANSACTIONS were $211,690 for the year ended December 31,
1997. This increase was primarily attributed to rental obligations of the
Company's Starboard Prospect in Terrebonne Parish, Louisiana. There were no such
transactions for the same period in 1996.
20
<PAGE>
LEASE OPERATING EXPENSE decreased 23.3% from $556,925 in 1996 to $427,240 in
1997. The reduction in lease operating costs was attributable to the sale of
operated properties including the N.E. Cedardale field sale in September of
1996, and a decline in rework activities. Of the year ended December 31, 1997
total lease operation costs, $99,809 was attributable to plugging and
abandonment costs of the Company's Mobile Bay wells which were plugged during
1997.
PRODUCTION TAXES declined 88.2% from $207,969 in 1996 to $24,497 in 1997 due
to reduced production as a result of the sale of certain of the Company's
properties including the N.E. Cedardale field and other properties located in
Texas, Arkansas and Oklahoma.
TRANSPORTATION AND GATHERING COSTS decreased from $368,716 in 1996 to
$143,265 in 1997. The decrease in transportation and gathering costs was almost
entirely attributable to the ceased production of the Mobile Bay wells.
DEPLETION, DEPRECIATION, AND AMORTIZATION EXPENSE ("DD&A") decreased by
85.9% from $2,237,648 in 1996 to $315,880 in 1997. The decrease in DD&A was
primarily attributable to the sale of certain of the Company's properties
including the NE Cedardale field located in Major County, Oklahoma on September
27, 1996.
INTEREST EXPENSE decreased to $60,942 in 1997 from $783,872 in 1996. The
decrease in interest expense was primarily attributable to the substantial loan
principal repayment made to Bank of America in September of 1996. During 1997,
the Company capitalized a large portion of its interest in its ongoing Starboard
Prospect, which capitalized amounts totaled 107,387 in 1996 and 235,977 in 1997.
COST OF SETTLING GAS CONTRACTS and futures contracts was attributable to the
settlement of a gas sales contract with Waldorf Corporation ($368,690) and the
settlement of a gas swap agreement, due to a reduction in quantities covered
thereunder in connection with the sale of the N.E. Cedardale field ($212,000)
for the year ended December 31, 1996. The Company incurred no similar costs in
1997.
GENERAL ADMINISTRATIVE EXPENSES ("G&A") decreased by 6.5% from $2,217,099 in
1996 to $2,070,812 in 1997. This was primarily attributable to overhead
reduction measures initiated during 1997.
IMPAIRMENT OF OIL AND GAS PROPERTIES increased from $51,000 in 1996 to
$349,384 in 1997. This was primarily due to the abandonment of previously
producing wells, of which $323,353 was attributable to the Company's Mobile Bay
wells located in Alabama.
NET INCOME (LOSS).
The net loss decreased from $5,025,019 to $4,953,803 for the year ended
December 31, 1996, and December 31, 1997, respectively. This decrease was due to
the factors discussed above.
The net loss per common share decreased from a net loss of $0.72 per share
in 1996 to a net loss of $0.51 per share in 1997. This is reflective of the
decrease in the net loss of $71,217 from the year ended December 31, 1996 to the
year ended December 31, 1997 and a change in the number of weighted average
equivalent shares outstanding. As a result of the common stock offering that was
finalized on August 14, 1996, approximately 9,877,000 weighted average common
equivalent shares at December 31, 1997 as compared to approximately 7,142,000
weighted average common equivalent shares at December 31, 1996.
KNOWN AND ANTICIPATED TRENDS, CONTINGENCIES AND DEVELOPMENTS IMPACTING FUTURE
OPERATING RESULTS.
The Company's future operating results will be substantially dependent upon
the success of the Company's efforts to consummate the Acquisitions and develop
the Esenjay Assets and Aspect Assets, as well as the Starboard Project and other
prospects. Because the Company had divested substantially all of its oil and gas
properties in the mid-continent region by the end of 1996, revenues from the
operation and sale of such properties have been substantially reduced during
1997 and will be reduced in future years. Further, following a sharp and
unexpected drop in production from the Company's Mobile Bay wells during the
fourth quarter of 1996, the Company's share of revenues from Mobile Bay have
been
21
<PAGE>
substantially reduced during 1997. Revenues from the operation of the
mid-continent and Mobile Bay properties and the sale of mid-continent properties
constituted the substantial majority of the Company's revenues during 1996.
As a result of the loss of revenues from the mid-continent region and Mobile
Bay, the Company's revenues during 1997 have been sharply reduced. While
management believes that the Acquisitions and the Starboard Project represent
the most promising prospects in the Company's history, none of those prospects
are currently producing revenue to the Company, and each will require
substantial outlays of capital to explore, develop and produce.
The Company's potential results in 1998 will be substantially effected by
the closing of the Acquisitions, which closing is subject to approval by the
Company's common shareholders, as well as other provisions of the Acquisition
Agreement.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 1997, the Company had a cash balance of $690,576 and a
working capital deficit of $413,377 as compared to a cash balance of $4,956,656
and working capital of $4,159,034 at December 31, 1996. The decrease in cash and
working capital was primarily attributable to the operating loss incurred during
1997 and, in particular, exploration costs associated with dry holes that were
drilled during 1997.
In addition to the changes in cash, the decrease in working capital was
primarily attributable to several factors. Current liability increases of
$186,174 in accounts payable (primarily due to a greater volume of exploration
activities), and $90,773 in accruals and other liabilities (primarily
attributable to the current portion of the unrealized loss on swap agreements)
were largely offset by a $292,032 reduction in the revenue distribution account
(primarily due to the sale of operated properties). They were the primary
changes in the category. Current assets were primarily effected by the
previously described reduction in cash and a reduction of $144,634 in accounts
receivable primarily attributable to the sale of operated properties.
Cash flows used in operations totaled $1,894,402, excluding $2,258,702 of
exploration costs, which are classified under cash flows used in investing
activities. Cash flows used in investing activities totaled $2,180,392. Included
in the cash flows used in investing activities are $3,023,253 of capital
expenditures on gas and oil properties, including the exploration costs referred
to above that are included in the operating loss for the period but are excluded
from operating cash flows. The Company received $1,002,540 of proceeds from the
sale of various oil and gas properties during 1997, which partially offset the
capital expenditures during 1997.
Cash flows from financing activities reflects a use of cash of $191,286
during 1997. Cash flows from financing activities consisted of proceeds from
debt issuance of $182,382 offset by repayments of long-term debt of $296,303 and
preferred stock dividends paid of $77,365.
The Company's major obligations at December 31, 1997, were substantially the
same as at December 31, 1996, and consisted principally of (i) servicing loans
from Bank of America ($293,888 at December 31, 1997) and other loans, (ii) a
non-recourse loan relating to the development of the Company's Starboard
Prospect ($864,000 at December 31, 1997), (iii) payment of preferred stock
dividends ($77,365 of dividends were paid during 1997), (iv) funding of the
Company's exploration activities, and (v) funding of the day-to-day operating
costs. Unrealized losses on commodity transactions were $128,936 for the period
ended December 31, 1997. There were no such losses for the same period in 1996.
The lack of success in 1997 drilling caused the Company to reduce its
exploration plans and seek a potential business consolidation. It was these
efforts which led to its negotiations with Aspect and Esenjay and to the
execution of the definitive agreement dated January 19, 1998, which governs the
terms of the Acquisition which is in the process of being submitted to the
Companies shareholders for approval. The Company is not currently seeking
additional projects and is focused upon working to consummate the Acquisitions.
22
<PAGE>
In conjunction with the Acquisition Agreement, Aspect committed to lend the
Company up to $1,800,000 to fund operational and exploration requirements prior
to closing of the Acquisitions. This credit facility was implemented January 12,
1998 and was superseded by a larger facility from Duke Energy Financial
Services, Inc., dated February 23, 1998 (the "Duke Facility"). Upon closing of
the Duke Facility, Aspect was repaid $500,000 in principal (plus interest) then
due. The Duke Facility provides that the Company can borrow up to $4,800,000
prior to closing of the Acquisitions and, if the Acquisitions are closed, up to
an aggregate of $7,800,000. Of the initial $4,800,000, $1,800,000 can be
utilized by the Company to fund general corporate needs and costs of
exploration, and $3,000,000 is to be utilized to loan to Esenjay (on a secured
basis) to pay exploration costs associated with Esenjay's working interests to
be conveyed to the Company upon closing of the Acquisitions, which costs may be
incurred after the effective date of the Acquisitions, but prior to the date of
closing. In the event the Acquisitions are closed, an additional $3,000,000 is
available to fund costs of redeeming the Companies currently outstanding
preferred stock (a condition of closing the Acquisitions) and exploration costs.
Major provisions of the Duke Facility include interest at the rate of a
national prime rate plus 4% per annum, cash payments equal to an overriding
royalty of 0.6% of the Company's interest in wells drilled by the Company while
the Duke Facility is outstanding, and the right of the lender to gather,
process, and transport and market, at competitive market rates, natural gas
produced from a majority of the projects the Company intends to acquire pursuant
to the Acquisitions. The Duke Facility is secured by mortgages on most of the
Company's undeveloped exploration projects. If the Acquisitions are closed, the
assets acquired will be subject to such mortgages. The Duke Facility is
repayable in twelve monthly payments (the first eleven in amounts equal to
1/30th of the principal balance on July 31, 1998 plus interest and the final
payment for the remaining principal plus interest) commencing August 31, 1998,
or sooner, in the event the borrower sells interests in the collateral or closes
any underwritten public offering of securities.
The Company has utilized, and expects to continue to utilize, its cash
balances and credit facilities to fund negative cash flows from operations. The
Company expects that it will have depleted its current cash reserves and fully
used its credit facilities by the third quarter of 1998. As such it is
imperative that the Company close the Acquisitions or find other sources of
capital or merger partners, or it will be unable to fund its projects and
operations other then by the sale of substantial working interests in Company
projects, including Starboard. The Company believes that such alternatives are
viable and achievable although no assurances can presently be made. However, a
sale of the Starboard Project interests, without closing the Acquisition, would
leave the Company without cash flow and minimal exploration project inventory.
The Company is presently in non-compliance with the terms of its loan from Bank
of America, but has secured a waiver of various covenants under the loan through
June 30, 1998. The Company anticipates that it will require additional waivers
of covenants under the Bank of America loan until such time as the Company
begins to receive revenues, if ever, from its current exploration projects. The
Company has no assurance said waiver will be granted.
In the event the Acquisitions are closed, the Company will have what it
considers an exceptional inventory of technology enhanced, gas oriented
exploration projects, many of which are ready to drill. Until such time as the
Company develops substantial revenues from producing properties, it will require
external sources of exploration capital. It believes it will have a drillable
project inventory such that it could effectively deploy over $25,000,000 of
exploratory costs in 1998 on the net interests acquired by it pursuant to the
Acquisitions. Sources include the Duke Facility, industry participants via the
sale of promoted interests, other credit facilities including its banks, which
the Company believes would be available in the event it can discover meaningful
natural gas and/or oil reserves net to its account, and additional equity
capital. In that the Company will operate most of the projects acquired, it
could also defer a portion of the capital costs to 1999 in the event adequate
resources were not available, however, management believes that such resources
will be available to it in 1998 under reasonable terms.
23
<PAGE>
ITEM 7. FINANCIAL STATEMENTS
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
Frontier Natural Gas Corporation
We have audited the accompanying consolidated balance sheets of Frontier
Natural Gas Corporation and subsidiaries (the "Company") as of December 31, 1997
and 1996 and the related consolidated statements of operations, stockholders'
equity, and cash flows for the years then ended. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free from
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of Frontier Natural
Gas Corporation and subsidiaries as of December 31, 1997 and 1996, and the
results of their operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles.
The accompanying 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's recurring losses from operations raise
substantial doubt about its ability to continue as a going concern. Management's
plans concerning 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.
Deloitte & Touche LLP
Houston, Texas
March 27, 1998
24
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1996
------------- -------------
<S> <C> <C>
Current Assets:
Cash and cash equivalents........................................................ $ 690,576 $ 4,956,656
Accounts receivable, net of allowance for doubtful accounts of $15,488 at
December 31, 1997 and $10,533 at December 31, 1996............................. 221,864 366,498
Prepaid expenses and other....................................................... 249,328 282,317
Receivables from affiliates...................................................... 105,171 152,419
------------- -------------
Total current assets........................................................... 1,266,939 5,757,890
Property and equipment:
Gas and oil properties, at cost--successful efforts method of accounting......... 3,235,848 5,280,115
Other property and equipment..................................................... 1,169,127 1,074,727
------------- -------------
4,404,975 6,354,842
Less accumulated depletion, depreciation and amortization........................ (1,260,605) (2,918,918)
------------- -------------
3,144,370 3,435,924
Other Assets....................................................................... 164,699 437,378
------------- -------------
Total assets................................................................... $ 4,576,008 $ 9,631,192
------------- -------------
------------- -------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
25
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1996
-------------- -------------
<S> <C> <C>
Current liabilities:
Accounts payable................................................................. $ 911,396 $ 725,222
Revenue distribution payable..................................................... 68,131 360,163
Current portion of long-term debt................................................ 401,085 304,540
Accrued and other liabilities.................................................... 299,704 208,931
-------------- -------------
Total current liabilities.................................................... 1,680,316 1,598,856
Long-term debt..................................................................... 22,680 325,394
Non-recourse debt.................................................................. 864,000 681,618
Accrued interest on non-recourse debt.............................................. 194,274 9,918
Other long-term liabilities........................................................ 9,918 223,624
-------------- -------------
Total liabilities.............................................................. 2,771,188 2,892,366
Commitments and contingencies
Stockholders' equity:
Cumulative convertible preferred stock $.01 par value; 5,000,000 shares
authorized; 85,961 shares issued and outstanding at December 31, 1997 and 1996;
($859,610 aggregate redemption and liquidation preference at December 31, 1997
and 1996)...................................................................... 860 860
Common stock:
Class A Common stock, $.01 par value; 40,000,000 shares authorized; 9,935,906
and 9,865,906 outstanding at December 31, 1997 and December 31, 1996,
respectively................................................................. 99,359 98,659
Unamortized value of warrants issued............................................. (27,163) (54,325)
Common stock subscribed.......................................................... -- 45,000
Common stock subscription receivable............................................. -- (45,000)
Additional paid-in capital....................................................... 14,668,626 14,599,326
Accumulated deficit.............................................................. (12,936,862) (7,905,694)
-------------- -------------
Total stockholders' equity................................................... 1,804,820 6,738,826
-------------- -------------
Total liabilities and stockholders' equity................................... $ 4,576,008 $ 9,631,192
-------------- -------------
-------------- -------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
26
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Revenues:
Gas and oil revenues.............................................................. $ 664,126 $ 3,176,861
Realized gain (loss) on commodity transactions.................................... (375,410) (814,029)
Unrealized loss on commodity transactions......................................... (128,936)
Gain on sale of assets............................................................ 452,020 250,437
Operating fees.................................................................... 55,021 213,834
Other revenues.................................................................... 241,788 339,689
------------- -------------
Total revenues.................................................................. 908,609 3,166,792
------------- -------------
Costs and expenses:
Lease operating expense........................................................... 427,240 556,925
Production taxes.................................................................. 24,497 207,969
Transportation and gathering costs................................................ 143,265 368,716
Gas purchases under deferred contract............................................. -- 82,461
Depletion, depreciation and amortization.......................................... 315,880 2,237,648
Impairment of oil and gas properties.............................................. 349,384 51,000
Exploration costs................................................................. 2,258,702 1,317,161
Interest expense.................................................................. 60,942 783,872
Deferred gas contract settlement.................................................. -- 368,960
General and administrative expense................................................ 2,070,812 2,217,099
Delay Rentals..................................................................... 211,690 --
------------- -------------
Total costs and expenses........................................................ 5,862,412 8,191,811
------------- -------------
Loss before provision for income taxes.............................................. (4,953,803) (5,025,019)
Benefit (provision) for income taxes................................................ -- --
------------- -------------
Net loss............................................................................ (4,953,803) (5,025,019)
Cumulative preferred stock dividend................................................. 103,153 103,153
------------- -------------
Net loss applicable to common stockholders.......................................... $ (5,056,956) $ (5,128,172)
------------- -------------
------------- -------------
$ (0.51) $ (0.72)
Weighted average number of common shares outstanding................................ 9,877,865 7,142,056
------------- -------------
------------- -------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
27
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
CLASS A COMMON SHARES UNAMORTIZED
PREFERRED STOCK VALUE OF ADDITIONAL
------------------------ ---------------------- WARRANTS PAID-IN ACCUMULATED
SHARES AMOUNT SHARES AMOUNT ISSUED CAPITAL DEFICIT
----------- ----------- --------- ----------- ------------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995....... 85,961 $ 860 5,058,406 $ 50,584 -- $7,866,879 $(2,854,887)
Issuance of common stock......... -- -- 4,807,500 48,075 -- 6,616,947 --
Warrant issued for services...... -- -- -- -- $ (82,500) 115,500 --
Cumulative preferred stock
dividend....................... -- -- -- -- -- -- (25,788)
Amortization of warrants......... 28,175
Net loss......................... -- -- -- -- -- -- (5,025,019)
----------- ----- --------- ----------- ------------- ---------- ------------
Balance, December 31, 1996....... 85,961 860 9,865,906 98,659 (54,325) 14,599,326 (7,905,694)
----------- ----- --------- ----------- ------------- ---------- ------------
Issuance of common stock......... -- -- 70,000 700 -- 69,300 --
Cumulative preferred stock
dividend....................... -- -- -- -- -- -- (77,365)
Amortization of warrants......... -- -- -- -- 27,162 -- --
Net loss......................... -- -- -- -- -- -- (4,953,803)
----------- ----- --------- ----------- ------------- ---------- ------------
Balance, December 31, 1997....... 85,961 $ 860 9,935,906 $ 99,359 $ (27,163) $14,668,626 ($12,936,862)
----------- ----- --------- ----------- ------------- ---------- ------------
----------- ----- --------- ----------- ------------- ---------- ------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
28
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Cash flows from operating activities:
Net loss.......................................................................... $ (4,953,803) $ (5,025,019)
Adjustments to reconcile net loss to net cash (used) in operating activities:
Depletion, depreciation and amortization........................................ 315,880 2,237,648
Impairment of oil and gas properties............................................ 349,384 51,000
Deferred gas contract settlement................................................ -- 368,960
Gain on sale of assets.......................................................... (452,020) (250,437)
Gain on settlement of deferred compensation agreement........................... (25,794) --
Deferred revenues under gas contract............................................ -- (74,400)
Amortization of financing costs and warrants.................................... 46,128 710,573
Unrealized loss on commodity transitions........................................ 128,936 --
Exploration costs............................................................... 2,258,702 1,317,161
Changes in operating assets and liabilities:
Trade and affliliate receivables.............................................. 191,882 303,975
Prepaid expenses and other.................................................... 198,418 (103,580)
Other assets.................................................................. 272,679 (191,791)
Accounts payable.............................................................. 186,174 (279,119)
Revenue distribution payable.................................................. (292,032) (132,909)
Accrued and other............................................................. (118,936) (2,647)
------------- -------------
Net cash (used) in operating activities......................................... (1,894,402) (1,070,585)
------------- -------------
Cash flows used in investing activities:
Capital expenditures--gas and oil properties...................................... (3,023,253) (3,515,841)
Capital expenditures--other property and equipment................................ (159,679) (203,808)
Proceeds from sale of assets...................................................... 1,002,540 4,671,088
------------- -------------
Net cash provided by (used) in investing activities............................. (2,180,392) 951,439
------------- -------------
Cash flows from financing activities:
Proceeds from issuance of debt.................................................... 182,382 4,717,280
Repayments of long-term debt...................................................... (296,303) (3,745,369)
Debt issuance cost................................................................ -- (183,387)
Payment for settlement of deferred gas contract................................... -- (2,181,489)
Preferred stock dividends paid.................................................... (77,365) (25,788)
Net proceeds from issuance of common stock........................................ -- 6,430,647
------------- -------------
Net cash provided by (used) in by financing activities.......................... (191,286) 5,011,894
------------- -------------
Net increase (decrease) in cash and cash equivalents.............................. (4,266,080) 4,892,748
Cash and cash equivalents at beginning of year...................................... 4,956,656 63,908
------------- -------------
Cash and cash equivalents at end of year............................................ $ 690,576 $ 4,956,656
------------- -------------
------------- -------------
Supplemental disclosure of cash flow information:
Cash paid for interest............................................................ $ 141,356 $ 818,769
------------- -------------
------------- -------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
29
<PAGE>
FRONTIER NATURAL GAS CORPORATION
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION--The Company's primary business activities include gas
and oil exploration, production and sales, primarily in the Southwestern and
Gulf Coast areas of the United States. The accompanying consolidated financial
statements include the accounts of the Company, and its subsidiaries.
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.
CASH EQUIVALENTS--The Company considers all investments with a maturity of
three months or less when purchased to be cash equivalents.
GAS AND OIL PROPERTIES--The Company uses the successful efforts method of
accounting for gas and oil exploration and development costs. All costs of
acquired wells, productive exploratory wells, and development wells are
capitalized. Exploratory dry hole costs, geological and geophysical costs, and
lease rentals on non-producing leases are expensed as incurred. Gas and oil
leasehold acquisition costs are capitalized. Costs of unproved properties are
transferred to proved properties when reserves are proved. Gains or losses on
sale of leases and equipment are recorded in income as incurred. Valuation
allowances are provided if the net capitalized costs of gas and oil properties
at the field level exceed their realizable values based on expected future cash
flows. Unproved properties are periodically assessed for impairment and, if
necessary, a loss is recognized by providing an allowance.
The costs of multiple producing properties acquired in a single transaction
are allocated to individual producing properties based on estimates of gas and
oil reserves and future cash flows.
Depletion is provided by the unit of production method based upon reserve
estimates. Depletion, depreciation and amortization includes approximately
$349,384 and $51,000 in 1997 and 1996, respectively, in impairment of gas and
oil properties, due to changes in reserve estimates.
OTHER PROPERTY AND EQUIPMENT--Other property and equipment is carried at
cost. The Company provides for depreciation of other property and equipment
using the straight-line method over the estimated useful lives of the assets,
which range from three to ten years.
Upon sale or retirement of an asset, the cost of the asset disposed of and
the related accumulated depreciation are removed from the accounts, and the
resulting gain or loss is reflected in income.
INCOME TAXES--The Company accounts for income taxes on an asset and
liability method which requires the recognition of deferred tax liabilities and
assets for the tax effects of temporary differences between the financial and
tax bases of assets and liabilities, operating loss carryforwards, and tax
credit carryforwards.
COMMODITY TRANSACTIONS--The Company attempts to minimize the price risk of a
portion of its future oil and gas production with commodity futures contracts.
Gains and losses on these contracts are recognized in the period in which
revenue from the related gas and oil production is recorded or when the
contracts are closed. To the extent that the quantities hedged under the
commodity transaction exceed current production, the Company recognizes gains or
losses on the overhedged amount.
CAPITALIZED INTEREST--The Company capitalizes interest costs incurred on
exploration projects. The interest capitalized for the years ended December 31,
1997 and 1996 was approximately $235,977 and $107,000, respectively.
30
<PAGE>
FRONTIER NATURAL GAS CORPORATION
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
GAS BALANCING--The Company records gas revenue based on the entitlement
method. Under this method, recognition of revenue is based on the Company's
pro-rata share of each well's production. During such time as the Company's
sales of gas exceed its pro-rata ownership in a well, a liability is recorded,
and conversely a receivable is recorded for wells in which the Company's sales
of gas are less than its pro-rata share. At December 31, 1997, the Company's gas
balancing position was approximately 29,244 MCF overproduced.
EXPLORATION COSTS--The Company expenses exploratory dry hole costs,
geological and geophysical costs, and impairment of unproved properties. During
1996, $43,000 of such costs represented geological and geophysical costs
expensed as required under the successful efforts method of accounting. There
were no such costs incurred in 1997.
FAIR VALUE OF FINANCIAL INSTRUMENTS--Statement of Financial Accounting
Standards No. 107. "Disclosures about Fair Value of Financial Instruments"
requires disclosure regarding the fair value of financial instruments for which
it is practical to estimate that value. The carrying amount of cash and cash
equivalents, accounts receivable and accounts payable, approximates fair market
value because of the short maturity of those instruments. The fair value of the
Company's long-term debt is estimated to approximate carrying value based on the
borrowing rates currently available to the Company for bank loans with similar
terms and average maturities.
The Company has interest rate and gas swap agreements that subject it to
off-balance sheet risk. The unrealized losses on these contracts, as disclosed
in the following footnotes, are based on market quotes. These unrealized losses
are not recorded in the consolidated financial statements to the extent the
swaps qualify for hedge accounting.
STOCK-BASED COMPENSATION--In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 123
("SFAS 123"), "Accounting for Stock-Based Compensation." SFAS 123 establishes a
fair value method and disclosure standards for stock-based employee compensation
arrangements, such as stock purchase plans and stock options. It also applies to
transactions in which an entity issues its equity instruments to acquire goods
or services from non-employees, requiring that such transactions be accounted
for based on fair value. As allowed by SFAS 123, the Company will continue to
follow the provisions of Accounting Principles Board Opinion No. 25 ("APB") for
its stock-based employee compensation arrangements. SFAS 123 requires entities
that elect to continue to measure compensation cost using APB 25 to disclose
proforma information computed as if the fair value based accounting method of
SFAS 123 had been applied for all awards granted after December 15, 1994.
EARNINGS PER SHARE--In February 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 128 ("SFAS 128"),
"Earnings per Share" and Statement of Financial Accounting Standards No. 129
("SFAS 129"), "Disclosure of Information about Capital Structure." SFAS 128
establishes standards for computing and presenting earnings per share ("EPS")
and requires restatement of all prior-period EPS data presented. SFAS 129
establishes standards for disclosing information about an entity's capital
structure. Basic earnings per share has been computed by dividing net income to
common shareholders by the weighted average number of common shares outstanding.
Diluted earnings per share is calculated by dividing net income to common
shareholders (as adjusted) by the weighted average number of common shares
outstanding plus dilutive potential common shares. For the years ended December
31, 1997 and 1996 all potentially diluted securities are anti-dilutive and
therefore are not included in the earnings per share calculation.
31
<PAGE>
FRONTIER NATURAL GAS CORPORATION
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (CONTINUED)
The following table presents information necessary to calculate basic and
diluted earnings per share for periods indicated, with 1996 being restated to
conform with the requirements of the Statement of Financial Accounting Standards
No. 128 Earning Per Share, described below.
<TABLE>
<CAPTION>
1997 1996
------------- -------------
<S> <C> <C>
BASIC EARNINGS PER SHARE
Weighted Average Common Shares Outstanding........................................ 9,877,865 7,142,056
Basic (Loss) Per Share............................................................ $ (0.51) $ (0.72)
------------- -------------
------------- -------------
EARNINGS FOR BASIC COMPUTATION
Net (Loss)........................................................................ $ (4,953,803) $ (5,025,019)
Preferred Share Dividends......................................................... (103,153) (103,153)
------------- -------------
Net Income (Loss) to Common Shareholders (Basic (Loss) Per Share Computation)..... $ (5,056,956) $ (5,128,172)
------------- -------------
------------- -------------
</TABLE>
RECLASSIFICATION--Certain reclassifications have been made to the 1996
financial statements to conform them to the classification used in 1997.
2. GOING CONCERN:
The accompanying consolidated financial statements have been prepared
assuming that the company will continue as a going concern. The Company has
experienced a significant decline in operations including declines in ongoing
gas and oil production. These declines have created a significant working
capital deficit and depleted cash reserves. As a result of the declining
positions, the Company has also failed to meet its financial debt covenants
although it has secured a waiver through the earlier of the consummation of the
Acquisitions or June 1998. In the event that the Company is not able to secure
future waivers and the debt is ultimately called, the Company may not be able to
timely meet this demand.
The Company has prepared an operating budget for 1998 which projects a
negative cash flow. Such negative cash flows are expected to further deplete
existing cash balances. The Company has obtained a bridge financing arrangement
from Duke Energy Financial Services, Inc. in connection with the proposed
Acquisitions discussed in Note 10. If the Company is unsuccessful in its attempt
to finalize the proposed Acquisitions and secure permanent financing, the
Company believes it will be unable to continue to meet its current obligations
during 1998 and beyond without selling substantial interests in its exploration
projects. The Company is actively pursuing completion of the proposed
Acquisitions and permanent financing.
3. STOCKHOLDERS' EQUITY:
Effective November 12, 1993, the Company completed its initial public
offering of 350,000 Units of its securities. Each unit consisted of two (2)
shares of cumulative convertible preferred stock (valued at $10.00 per share),
one (1) share of common stock (valued at $4.00) and one (1) warrant ("Series A
Warrant") (valued at $0.10). During 1995, the Company offered to exchange one
(1) share of cumulative convertible preferred stock plus all unpaid and accrued
preferred dividends for four (4) shares of common stock and two (2) Series A
Warrants for a limited period. The Company concluded its offer on May 26, 1995
with a total of 603,939 shares of convertible preferred stock tendered. As a
result of the offering, the Company issued 2,415,756 shares of Common Stock and
1,207,878 Series A Warrants. After May 26, 1995, the exchange ratio reverted to
the original conversion terms. The Company reflected the market value of the
32
<PAGE>
FRONTIER NATURAL GAS CORPORATION
3. STOCKHOLDERS' EQUITY: (CONTINUED)
additional two shares of common stock paid as a one-time premium to induce
conversion of the cumulative convertible preferred stock as an addition to net
loss in computing loss applicable to common shareholders in the amount of
$2,415,756. The Company was relieved of $232,285 of accrued dividends relating
to the shares tendered, which has been offset against the inducement premium. As
of December 31, 1997 and 1996, 85,961 shares of cumulative convertible preferred
stock were outstanding.
In connection with the debt financing obtained during the first quarter of
1996, the Company, pursuant to an agreement with a financial advisor, agreed to
pay a combination of cash, stock and warrants (See--"Warrants") in consideration
for assisting with obtaining the financing. The Company paid $200,000 in cash
and issued 150,000 shares of the Company's common stock to the advisor on June
6, 1996. These shares have been valued at $234,375, the fair market value at the
date granted.
On August 14, 1996, the Company closed the sale of a public offering of
1,350,000 Units of its securities. Subsequently, the Company sold an additional
over all allotment of 202,500 Units. Each Unit consisted of three shares of
Common Stock and three (3) Series B Redeemable Common Stock Purchase Warrants
("Series B Warrants"). The price for each Unit was $5.0625. The net proceeds,
after underwriter's commission and expenses, was approximately $6,431,000.
CONVERTIBLE PREFERRED STOCK--The Board of Directors of the Company has
adopted a Certificate of Designations creating a series of convertible preferred
stock consisting of 1,000,000 shares, par value $.01 per share, none of which
was outstanding as of December 31, 1997 and 1996. Shares of the convertible
preferred stock may be issued from time to time in one or more series with such
designations, voting powers, if any, preferences, and relative participating,
optional or other special rights, and such qualifications, limitations and
restrictions thereof, as are determined by resolution of the Board of Directors
of the Company. However, the holders of the shares of the convertible preferred
stock will not be entitled to receive liquidation preference of such shares,
until the liquidation preference of any other series or class of the Company's
stock hereafter issued that ranks senior as to liquidation rights to the
cumulative convertible preferred stock has been paid in full.
CUMULATIVE CONVERTIBLE PREFERRED STOCK--Holders of shares of cumulative
convertible preferred stock will be entitled to receive, when and if declared by
the Board of Directors out of funds at the time legally available, cash
dividends at a maximum annual rate of $1.20 per share, payable quarterly,
commencing 90 days after the date of first issuance. Dividends are cumulative
from the date of issuance of the cumulative convertible preferred stock. During
1997 and 1996, $77,365 and $25,788 was declared and paid in cumulative preferred
stock dividends. The Company has undeclared and unpaid dividends in the amount
of $180,518 ($1.50 per share) on its cumulative preferred stock for the period
from May 1, 1995 to December 31, 1997. The Company is not required to declare
and pay such dividends; however, until such dividends are paid current, the
Company is precluded from paying dividends to its common shareholders.
In the event of any liquidation, dissolution or wind-up of the Company,
holders of shares of cumulative convertible preferred stock are entitled to
receive the liquidation preference of $10.00 per share, plus an amount equal to
any accrued and unpaid dividends to the payment date, before any payment or
distribution is made to the holders of common stock, or any series or class of
the Company's stock hereafter issued, that will rank junior as to liquidation
rights to the cumulative convertible preferred stock.
The holders of cumulative convertible preferred stock will not have voting
rights except as required by law in connection with certain defaults and as
provided to approve certain future actions including any changes in the
provisions of the stock or the issuance of additional shares equal or senior to
the stock. Whenever dividends on the cumulative convertible preferred stock have
not been paid in an aggregate
33
<PAGE>
FRONTIER NATURAL GAS CORPORATION
3. STOCKHOLDERS' EQUITY: (CONTINUED)
amount equal to at least six quarterly dividends, the number of directors of the
Company will be increased by two and the holders of preferred stock will be
entitled to elect these additional directors.
REDEMPTION--The cumulative convertible preferred stock is redeemable for
cash, in whole or in part, at the option of the Company, at $10.00 per share,
plus any accrued and unpaid dividends, whether or not declared.
OPTIONAL CONVERSION--At any time after the initial issuance of the
cumulative convertible preferred stock and prior to the redemption thereof, the
holders of cumulative convertible preferred stock shall have the right,
exercisable at their option, to convert any or all of such shares into common
stock at the rate of conversion described below. During 1997 no shares of
cumulative convertible preferred stock were converted to common stock under the
original conversion terms. Automatic Conversion--If, at any time after the
initial issuance thereof, the last reported sales price of the cumulative
convertible preferred stock as reported on the NASDAQ System (or the closing
sale price as reported on any national securities exchange on which the
cumulative convertible preferred stock is then listed), shall, for a period of
10 consecutive trading days, exceed $13.00, then, effective as of the closing of
business on the tenth such trading day, all shares of cumulative convertible
preferred stock then outstanding shall immediately and automatically be
converted into shares of common stock and warrants at the rate of conversion
described below.
CONVERSION RATE--The conversion rate for the cumulative convertible
preferred stock (i.e., the number of shares of common stock into which each
share of cumulative convertible preferred stock is convertible) is determined by
dividing the conversion price then in effect by $5.00. The initial conversion
price is $10.00; therefore, the cumulative convertible preferred stock is
initially convertible into common stock and Series A Warrants at the conversion
rate of two (2) shares of common stock and two (2) Series A Warrants for each
share of cumulative convertible preferred stock converted.
WARRANTS--Each Series A Warrant issued in the initial public offering and in
the conversion of the cumulative convertible preferred stock entitles the holder
thereof to purchase one (1) share of common stock at a price equal to $6.00,
until five years from the effective date of the initial public offering. The
Warrants will, unless exercised or amended, expire on November 13, 1998.
Outstanding Series A Warrants may be redeemed by the Company for $.25 each on 30
days notice. As of December 31, 1997 and 1996, there were 1,578,078 Series A
Warrants outstanding.
Each Series B Warrant issued in the August 1996 public securities offering
entitles the holder to purchase one (1) share of common stock for $2.025
commencing August 8, 1997, and ending August 8, 2001. Each Series B Warrant is
redeemable by the Company with the prior consent of the underwriter at a price
of $0.01 per Series B Warrant, at any time after the Series B Warrants become
exercisable, upon not less than 30 days notice, if the last sale price of the
common stock has been at least 200% of the then exercise price of the Series B
Warrants for the 20 consecutive trading days ending on the third day prior to
the date on which the notice of redemption is given.
The Company has also issued a common stock warrant to purchase 25,000 shares
of common stock at $4.00 per share in connection with a loan agreement. This
warrant expires five (5) years from the effective date of the Company's initial
public offering. The loan was paid in full in 1993.
The Company and Hi-Chicago Trust agreed to a settlement in December 1995
whereby the Company issued 75,000 shares of common stock and a stock purchase
warrant to purchase up to 300,000 shares of common stock at an exercise price of
$3.00 per share to settle a claim asserted by Hi-Chicago Trust. The warrant is
exercisable through the earlier of 60 months from the settlement date or for a
period of 30 days
34
<PAGE>
FRONTIER NATURAL GAS CORPORATION
3. STOCKHOLDERS' EQUITY: (CONTINUED)
after the closing bid price of the Company's stock equals or exceeds $6.00 per
share for sixty consecutive trading days. The issued shares are unregistered.
In 1996, the Company issued to a bank providing financing, a warrant to
purchase up to 250,000 shares of common stock for a period of five years
beginning January 3, 1996, at an exercise price of the highest average of the
daily closing bid prices for thirty (30) consecutive trading days between
January 1, 1996, and June 30, 1996. The Company has recorded the warrants at a
value of approximately $82,500 as unamortized value of warrants issued. The
warrants are being amortized using the interest method with an unamortized
balance of $27,163 at December 31, 1997.
The Company has also issued a warrant to purchase 250,000 shares of the
Company's common stock at $2.00 per share to a financial advisor. The warrant
has a five year term commencing on January 12, 1996 and provides for
anti-dilution protection, registration rights, and permits partial exercise at
the election of the holder by exchanging the warrants with appreciated value
equal to each exercise price in lieu of cash. If additional funds are not
borrowed from the bank, a portion of the warrants will be returned. The Company
has recorded the warrants, which are not subject to return at their fair value
of approximately $33,000. The warrants subject to return will be recorded when
additional funds are borrowed.
On January 15, 1997, the Board of Directors authorized the Company to enter
into an agreement with Riches In Resources, Inc. to perform investor relations
services for the Company on a fee basis through January 15, 1999, and month to
month thereafter, which fee may be paid either in cash or in common stock at the
election of the Company. The Company elected to compensate Riches In Resources,
Inc. partially in cash and partially in stock, therefore Riches In Resources,
Inc. was issued 70,000 shares of common stock during 1997. At December 31, 1997,
the Company had prepaid consultant cost of $17,701 in association with this
transaction.
In the first quarter of 1998, the Company in connection with a financing
arrangement, issued warrants to purchase 150,000 shares of Common Stock at an
exercise price of $.50 per share.
EMPLOYEE OPTION PLAN--1997--The plan authorizes the issuance of up to
695,350 options to purchase one (1) share of common stock. Options to purchase
601,000 shares of common stock at prices ranging from $0.63 to $1.88 are
currently outstanding of which 31,000 expire in June of 1998.
Under the plan, the Board may grant options to officers and other employees
and shall provide for an automatic receipt of options by directors who are not
full time employees. Each option shall consist of an option to purchase one
share of common stock at an exercise price that shall be at least the fair
market value of the Common stock on the date of the grant of the option.
However, the Board may authorize vesting options as it deems necessary; such is
the case of certain officers reissued options under this plan during 1997.
Unless otherwise so designated, the options shall be exercisable at a rate of
33 1/3% on January 1, the year following the effective date of the grant, and
33 1/3% each January 1 thereafter. The Option holder's right is cumulative.
Unless otherwise designated by the Board, if the employment of the Option holder
is terminated for any reason, all unexercised Options shall terminate, be
forfeited and shall lapse within three months thereafter. The options have a
maximum life of ten years from the date of issuance.
STOCK INCENTIVE OPTION PLAN--1996--The 1996 stock incentive option plan was
approved by the Company's stockholders in June, 1996, and 350,000 shares of
common stock were initially reserved for issuance thereunder.
Currently, all options under the plan have expired or have been canceled by
the Board of Directors other than 130,000 options currently outstanding, of
which 116,000 expire by June of 1998.
35
<PAGE>
FRONTIER NATURAL GAS CORPORATION
3. STOCKHOLDERS' EQUITY: (CONTINUED)
MANAGEMENT INCENTIVE STOCK PLAN
The Plan initially authorized the issuance of up to 240,000 units. Each unit
consists of (i) an option to purchase one (1) share of Common Stock and (ii) a
cash payment ("Stock Appreciation Right" or "SAR") to be made by the Company
when the option is exercised. The value of the SAR is equal to twice the amount
by which the fair market value of the Common Stock on the date of the exercise
of the option exceeds the exercise price. Currently all units have expired or
have been canceled by the Board of Directors other than 48,000 units currently
outstanding, 42,000 of which expire by June 1998.
The following table summarizes activity under the Company's stock option
plans for the years ended December 31, 1997 and 1996.
<TABLE>
<CAPTION>
INCENTIVE STOCK MANAGEMENT INCENTIVE STOCK INCENTIVE
OPTION PLAN STOCK PLAN OPTION PLAN--1997 EMPLOYEE
-------------------- -------------------- ---------------------- OPTION PLAN--
1997 1996 1997 1996 1997 1996 1997
--------- --------- --------- --------- ---------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Shares available for grant..... -- 180,000 -- 120,000 8,000 350,000 695,350
Shares under option at end of
period....................... -- 180,000 48,000 112,000 122,000 342,000 601,000
Option price per share......... -- $ 1.679 $2.00-3.50 $2.00-3.50 $1.47-2.125 $1.47-2.125 $ 0.63-1.88
Shares exerciseable at end of
period....................... -- 156,000 48,000 102,000 40,666 -- 544,000
Sales exercised during the
period....................... -- -- -- -- -- -- --
Sales canceled................. 180,000 -- 64,000 120,000 220,000 --
Weighted Option Price.......... -- $ 1.679 $ 3.02 $ 3.09 $ 1.67 $ 1.569 $ 0.70
</TABLE>
STOCK OPTION PLANS--The Company has three fixed option plans which reserve
shares of common stock for issuance to executives, key employees and directors.
The Company has adopted the disclosure-only provisions of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation".
Accordingly, no compensation cost has been recognized for the stock option
plans. Had compensation cost for the Company's three stock option plans been
determined based on fair value at the grant date for awards in 1997 and 1996
consistent with the provisions of SFAS No. 123, the Company's net loss
applicable to common stockholders and net loss per common and common equivalent
share would have been the pro forma amounts indicated below:
<TABLE>
<CAPTION>
1997 1996
------------- -------------
<S> <C> <C>
Net loss applicable to common stockholders--as reported................... $ (5,056,956) $ (5,128,172)
------------- -------------
------------- -------------
Net loss applicable to common stockholders--pro forma..................... $ (5,679,620) $ (5,296,335)
------------- -------------
------------- -------------
Net loss per common and common equivalent share--as reported.............. $ (0.51) $ (0.72)
------------- -------------
------------- -------------
Net loss per common and common equivalent share--pro forma................ $ (0.57) $ (0.74)
------------- -------------
------------- -------------
</TABLE>
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option-pricing model with the following weighted-average
assumptions: no dividends; expected volatility of 60%; risk-free interest rate
of 5.71% and 6.50% in 1997 and 1996, respectively; and expected lives of five
(5) years.
36
<PAGE>
FRONTIER NATURAL GAS CORPORATION
3. STOCKHOLDERS' EQUITY: (CONTINUED)
OPTION REPRICINGS
In the last quarter of 1997, the Company determined to attempt to consummate
a significant corporate transaction in order to satisfy the Company's need for
additional capital resources. In connection with pursuing such a transaction,
Mr. Berry and Mr. Christofferson entered into Incentive Agreements and Contract
Settlement Agreements with the Company pursuant to which each of Mr. Berry and
Mr. Christofferson are entitled to receive certain Incentive Payments and
Contract Settlement Payments upon the consummation of such a transaction. Their
existing employment agreements will terminate upon the consummation of a
significant corporate transaction.
In negotiating the terms of the Incentive Agreements and Contract Settlement
Agreements, Mr. Berry and Mr. Christofferson determined that their existing
stock options would expire 90 days after their termination of employment. The
Compensation Committee of the Board of Directors which was comprised of Messrs.
Sweeny and Elliott, each of whom was an outside director, recognized that the
expiration of those options would result in a disincentive for Mr. Berry and Mr.
Christofferson to help the Company pursue a significant corporate transaction.
Therefore, the Compensation Committee determined that Mr. Berry's and Mr.
Christofferson's existing stock options should be canceled and replaced with new
stock options that would terminate not sooner than the date their old options
would have expired if their employment with the Company was not terminated. As
an added incentive, the Compensation Committee determined to reprice Mr. Berry's
and Mr. Christofferson' options so they could more readily benefit from any
upturn in the Company's Common Stock trading price upon the consummation of a
significant corporate transaction.
When determining the price at which Mr. Berry's and Mr. Christofferson's new
options would be exercisable, the Compensation Committee took the average
closing price of the Company's Common Stock on the Nasdaq Small-Cap Market over
the 20 day trading period immediately preceding the option reprice date, and
multiplied such average trading price by 65%. The Compensation Committee
believed that the discount to the average trading price was appropriate because
the shares of Common Stock issuable upon exercise of the repriced options would
not be freely tradeable and the discount was appropriate to reflect the actual
fair market value of the illiquid shares that would be received upon the
exercise of the new options.
The following table sets forth certain information with respect to
replacement stock options granted to Mr. Berry and Mr. Christofferson during the
year ended December 31, 1997, which are also reported above under "--Option
Grants."
<TABLE>
<CAPTION>
NUMBER OF
SECURITIES OF LENGTH OF ORIGINAL
UNDERLYING MARKET PRICE OF EXERCISE PRICE OPTION TERM
OPTIONS/SARS STOCK AT TIME OF AT TIME OF NEW REMAINING AT DATE
REPRICED OR REPRICING OR REPRICING OR EXERCISE OF REPRICING OR
NAME DATE AMENDED AMENDMENT AMENDMENT PRICE AMENDMENT (MONTHS)
- ------------------------------ --------- -------------- ------------------- --------------- ----------- -------------------
<S> <C> <C> <C> <C> <C> <C>
David W. Berry................ 12/3/97 120,000(1) $ .97 $ 1.62 $ .63 102
President and Chief
Executive 12/3/97 24,000(2) $ .97 $ 3.10 $ .63 69
Officer
David B. Christofferson....... 12/3/97 180,000(3) $ .97 $ 1.68 $ .63 62
Executive Vice President, 12/3/97 24,000(2) $ .97 $ 3.10 $ .63 69
General Counsel and
Secretary 12/3/97 100,000(1) $ .97 $ 1.47 $ .63 102
</TABLE>
- ------------------------------
(1) Consists of options to purchase shares of Common Stock pursuant to the Stock
Incentive Option Plan--1996.
37
<PAGE>
FRONTIER NATURAL GAS CORPORATION
3. STOCKHOLDERS' EQUITY: (CONTINUED)
(2) Consists of units, each of which included an option to purchase one (1)
share of Common Stock and a stock appreciation right ("SAR") equal to two
times the difference between the exercise price of the option and the market
value of the SAR at the date of exercise, so that one (1) unit had the value
of three (3) options, all issued pursuant to the Management Incentive Option
Plan.
(3) Consists of options to purchase 180,000 shares of Common Stock pursuant to
the Company's 1993 Incentive Stock Option Plan.
4. SALE OF GAS AND OIL ASSETS AND SEISMIC DATA:
On September 27, 1996, the Company sold its N.E. Cedardale field located in
Major County, Oklahoma to OXY USA Inc., for consideration totaling $3,550,000
which included cash of $2,840,000 and certain exchange properties which were
concurrently sold to a third party for $710,000. The sale was effective
September 1, 1996 and the Company incurred a loss of $10,523. The properties
sold represented a substantial portion of the Company's production. In
connection with the sale, the Company recorded a loss of $212,000 resulting from
the reduction in the quantity of gas covered by a swap agreement. The Company
sold various other properties in a number of different transactions during 1997
and 1996. These sales resulted in an aggregate gain of approximately $485,813
and $272,000 for 1997 and 1996, respectively.
5. GAS SALE AGREEMENT:
Effective December 1, 1991, the Company entered into a Gas Sale Agreement to
deliver gas to an end-user over a specified period of time in the future.
The Company was committed to deliver 7,100,000 MMBTU of gas to the purchaser
over a period of seven years beginning December 1, 1991. The Company was allowed
to deliver gas to satisfy the commitment from its own reserves or from
purchasing gas on the open market. The Company delivered 44% from purchases on
the open market for the year ended December 31, 1996 as follows:
<TABLE>
<CAPTION>
FOR YEAR ENDED
DECEMBER 31,
1996
(MMBTU)
---------------
<S> <C>
Gas purchased on open market.............................. 43,783
Gas delivered from Company reserves....................... 55,417
------
Total deliveries.......................................... 99,200
------
------
</TABLE>
The purchase price under the contract was fixed at $1.50 per MMBTU over the
life of the contract. The contract required the prepayment by the purchaser of
$0.75 per MMBTU for the remaining contract obligations. On January 5, 1996, the
Company entered into an agreement with the end user to terminate the Gas Sales
Agreement as of January 31, 1996. The Company paid the end user $2,181,489 which
represents a return of its $.75 advance on 2,490,103 MMBTU of gas plus a
settlement payment of $313,912.
38
<PAGE>
FRONTIER NATURAL GAS CORPORATION
6. LONG-TERM DEBT:
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1997 1996
------------ ------------
<S> <C> <C>
Note payable pursuant to a credit agreement with a bank of $293,888 and $493,888 ended
December 31, 1997 and 1996 respectively, interest at LIBOR rate (reserve adjusted),
plus one and seven-eighths percent (1.875%) (7.25% at December 31, 1997 and 1996),
payable in monthly installments, due in various monthly amounts through December,
1998, collateralized by producing oil and gas properties; net of discount of $18,966
and $37,931 ending December 31, 1997 and 1996 respectively.......................... $ 274,922 $ 455,956
Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest
accrued at 15%...................................................................... 864,000 681,618
Note payable to bank, interest at 7.49% to 12.5%, payable in monthly installments, due
in various amounts through 2001, collateralized by other property and equipment..... 48,843 73,978
Note payable, interest at 12%, payable monthly, principal due December 31, 1997....... 100,000 100,000
------------ ------------
1,287,765 1,311,552
Less current portion.................................................................. 401,085 304,540
------------ ------------
$ 886,680 $ 1,007,012
------------ ------------
------------ ------------
</TABLE>
Maturities of long-term debt (excluding non-recourse debt, which is solely
dependent upon the successful development and future production, if any, of the
Starboard Prospect) are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31,
YEAR 1997
- --------------------------------------------------------- ---------------
<S> <C>
1998..................................................... $ 401,085
1999..................................................... 16,459
2000..................................................... 6,221
2001..................................................... --
2002..................................................... --
</TABLE>
On January 3, 1996, the Company entered into a $15,000,000 credit agreement
with a bank. The agreement provided for the immediate funding of $4,000,000
which was used to terminate the Gas Sales Agreement and repay the deferred gas
revenues incurred under the Gas Sales Agreement, payoff the note payable to a
bank due August 1, 1996, pay the bank fees related to the financing with the
remainder being used to pay current liabilities.
The remaining funds are to be available for specified future drilling and
acquisition activities of the Company subject to the approval of the bank. The
Company repaid a substantial portion of this borrowing with proceeds from the
sale of its N.E. Cedardale properties in September of 1996. Due to this early
repayment of borrowings, the Company reduced debt issuance costs by $293,000 and
discount on notes payable by $207,000 and recorded these amounts as interest
expense. The loan is secured by a mortgage on
39
<PAGE>
FRONTIER NATURAL GAS CORPORATION
6. LONG-TERM DEBT: (CONTINUED)
all of the Company's significant producing properties. As part of the credit
agreement, the Company is subject to certain covenants and restrictions, among
which are the limitations on additional borrowing, and sales of significant
properties, working capital, cash, and net worth maintenance requirements and a
minimum debt to net worth ratio. As additional consideration for the loan, the
Company assigned the bank an overriding royalty interest in the mortgaged
properties. The required covenants during 1997 are as follows:
<TABLE>
<CAPTION>
COVENANT, AS DEFINED
- ------------------------------------------------------------
<S> <C>
Tangible Net Worth.......................................... $ 5,000,000
Current Ratio............................................... 1.1 : 1.0
Debt to Capitalization...................................... 0.6 : 1.0
Cash Flow Ratio............................................. 3.0 : 1.0
Cash on Hand................................................ $ 200,000
Working Capital............................................. $ 400,000
</TABLE>
The Company does not believe it will be able to comply with certain of the
covenants. The Company has obtained a waiver of the covenant through June 30,
1998. Management believes that the Company will require an additional waiver or
waivers during 1998.
In addition, the Company has entered into an interest rate swap guaranteeing
a fixed interest rate of 8.28% on the loan, and the Company will pay fees of
one-eighth of 1% (.0125%) on the unused portion of the commitment amount. The
unrealized loss on the interest rate swap agreement was $28,000 at December 31,
1996. At December 31, 1997 the unrealized loss was $21,910.
On March 12, 1996, the Company completed a financial package with a group
funded by a public utility to evaluate and develop a project in Terrebonne
Parish, Louisiana. This group will participate in 48% of all costs of evaluation
and development of the project area and provide a non-recourse loan to fund the
Company's 48% share of the leasehold and seismic evaluation costs of the
project. The loan is secured by a mortgage on the Company's interest in the
project. As of December 31, 1997, the Company has received advances aggregating
$864,000 on the non-recourse loan. The non-recourse loan will be paid solely by
the assignment on an 8% overriding royalty interest in the future revenues of
the financed project. Future funding will be provided as costs are incurred.
7. INCOME TAXES:
Deferred tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Net operating tax loss carryforward....................................... $ 4,332,710 $ 3,494,442
Property and equipment.................................................... (2,936,284) (1,942,813)
Employee benefits......................................................... -- 76,032
Valuation allowance....................................................... (3,254,886) (1,627,661)
------------- -------------
Net deferred tax asset (liability).................................... $ -- $ --
------------- -------------
------------- -------------
</TABLE>
The Company has recorded a deferred tax valuation allowance since, based on
an assessment of all available historical evidence, it is more likely than not
that future taxable income will not be sufficient to
40
<PAGE>
FRONTIER NATURAL GAS CORPORATION
7. INCOME TAXES: (CONTINUED)
realize the tax benefit. The Company and its subsidiaries have estimated net
operating loss carryforwards ("NOLs") at December 31, 1997, of approximately
$12,743,267, which may be used to offset future taxable income. The operating
loss carryforwards expire in the tax years 2006 through 2012.
The ability of the Company to utilize NOLs and tax credit carryforwards to
reduce future federal income taxes of the Company may be subject to various
limitations under the Internal Revenue Code of 1986, as amended (the "Code").
One such limitation is contained in Section 382 of the Code which imposes an
annual limitation on the amount of a corporation's taxable income that can be
offset by those carryforwards in the event of a substantial change in ownership
as defined in Section 382 ("Ownership Change"). In general, Ownership Change
occurs if during a specified three-year period there are capital stock
transactions, which result in an aggregate change of more than 50% in the
beneficial ownership of the stock of the Company. The Company may have incurred
such an Ownership Change.
8. RELATED PARTY TRANSACTIONS:
The Company made advances to officers and affiliates of the Company during
1997 and 1996 of $48,380 and $51,143, respectively, and received repayments of
$99,216 and $18,741, respectively. The December 31, 1997 and 1996 receivables
include approximately $47,787, from an affiliated partnership for which the
Company serves as the managing general partner. During 1996, as a result of the
Company's relocation, the Company purchased the homes of two officers for a
total aggregate cost of approximately $369,000. The houses were sold for a total
aggregate sales price of approximately $354,000 and the net amount realized by
the Company was approximately $324,000.
9. COMMITMENTS AND CONTINGENCIES:
The Company leases office space under lease agreements, which are classified
as operating leases. Lease expense under these agreements was $112,432 in 1997
and $106,440 in 1996. A summary of future minimum rentals on these
non-cancelable operating leases is as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31,
YEAR 1997
- --------------------------------------------------------- ---------------
<S> <C>
1998..................................................... $ 117,068
1999..................................................... $ 117,068
2000..................................................... $ 117,068
2001..................................................... $ 78,045
</TABLE>
The Company has entered into employment agreements with two officers. Two of
these agreements expire December 31, 1999 (and automatically renew for
additional one-year terms each December 31 unless specifically terminated by
either the Company or individual). The Company has entered into an incentive
agreement and a contract settlement agreement with two officers. Their
employment agreements with the Company will be terminated upon the closing of
the Acquisitions.
Pursuant to the incentive agreements and contract settlement agreements, in
the event the Acquisitions are closed, or in the event there is another
transaction which results in a change of control of the Company, it will pay
incentive payments totaling $246,000, as well as contract settlement payments
totaling $246,000. Each of the incentive payments and the contract settlement
payments may be paid in the form of promissory notes due not later than
September 30, 1998.
41
<PAGE>
FRONTIER NATURAL GAS CORPORATION
9. COMMITMENTS AND CONTINGENCIES: (CONTINUED)
The Company is party to various lawsuits arising in the normal course of
business. Management believes the ultimate outcome of these matters will not
have a material effect on the Company's consolidated financial position, results
of operations, and net cash flows.
Pursuant to the credit agreement with the bank, the Company entered into a
natural gas swap agreement on 62,500 MMBTU of natural gas per month at $1.566
per MMBTU for Mid-Continent gas for the period from April 1, 1996 through
January 31, 1999. The swap was amended to 31,250 MMBTU on September 25, 1996,
due to the sale of the N.E. Cedardale field. The Company recorded a loss of
$212,000 in connection with this reduction in quantities covered by the swap
agreement. Currently the Company's monthly natural gas production is
substantially less than the natural gas swap that is in place. The total
unrealized loss on the amended swap agreement was 128,936 at December 31, 1997.
The Company has a hedge in place, which limits the potential cost per MMBTU it
may have to settle at a price of $3.13 per MMBTU, for 31,250 MMBTU per month in
January and February 1998.
10. SUBSEQUENT EVENT
On January 19, 1998, the Company entered into the Acquisition Agreement with
Esenjay Petroleum Corporation ("Esenjay") and Aspect Resources LLC ("Aspect")
(the "Acquisition Agreement"). Pursuant to the terms and conditions of the
Acquisition Agreement and subject to approval by the Company's shareholders the
Company will purchase from Esenjay (the "Esenjay Assets") and Aspect (the
"Aspect Assets") certain undeveloped oil and gas exploration projects in the
onshore Gulf Coast area (the "Acquisitions"). The Company will issue up to
30,991,563 shares of Common Stock to Esenjay in exchange for the Esenjay Assets,
and will issue up to 29,648,636 shares of Common Stock to Aspect or its assigns
in exchange for the Aspect Assets. The Company has filed a preliminary Schedule
14A proxy statement in this regard and intends to have a shareholders meeting in
late April or early May of 1998 to seek the approval of its shareholders of the
Acquisitions and related matters. As part of the Acquisition, the Company
intends to redeem its Cumulative Committee Preferred Stock at its redemption
price of $10.00 per share plus all accrued and unpaid dividends.
In conjunction with the Acquisition Agreement Aspect committed to lend the
Company up to $1,800,000, and in January and February advanced $500,000 on said
credit facility. The facility was repaid by the Company on February 23, 1998,
when the Company entered into a $7,800,000 credit agreement with Duke Energy
Financial Services, Inc. Said new credit facility provides for up to $4,800,000
prior to closing of the Acquisitions, $1,800,000 of which can be used directly
by the Company and $3,000,000 to be utilized solely to loan to Esenjay to pay
exploratory costs incurred on the Esenjay Assets after the effective date of the
Acquisitions and prior to closing thereof. An additional $3,000,000 will be
available to the Company after closing of the Acquisitions to pay additional
exploratory costs. The credit facility bears interest at a national prime rate
plus 4%. In addition, the lender will be paid cash payments equal to an
overriding royalty of 0.6% of the Company's interest in wells drilled by the
Company while the credit facility is outstanding. The lender also has a right to
gather, process, transport and market, at competitive market rates, natural gas
produced from a majority of the projects the Company intends to acquire pursuant
to the Acquisitions. The facility is secured by mortgages on most of the
Company's undeveloped exploration projects. If the Acquisitions are closed, the
assets acquired will be subject to such mortgages. The facility is repayable in
eleven monthly payments equal to 1/30 of the principal plus interest, plus a
final monthly payment of all remaining principal plus interest commencing August
31, 1998, or sooner in the event the Company sells interests in the collateral
or closes any underwritten public offering of securities.
42
<PAGE>
FRONTIER NATURAL GAS CORPORATION
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED):
The Company's proved gas and oil reserves are located in the United States.
Proved reserves are those quantities of natural gas and crude oil which, upon
analysis of geological and engineering data, demonstrate with reasonable
certainty to be recoverable in the future from known gas and oil reservoirs
under existing economic and operating conditions (i.e. price and costs as of the
date the estimate is made). Proved developed (producing and non-producing)
reserves are those proved reserves which can be expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
gas and oil reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage shall be
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled units
can be claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation.
FINANCIAL DATA
The Company's gas and oil producing activities represent substantially all
of the business activities of the Company. The following costs include all such
costs incurred during each period, except for depreciation and amortization of
costs capitalized:
COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1997 1996
------------ -------------
<S> <C> <C>
Acquisition of properties
Proved............................................................................. $ 765,678 $ 1,305,219
Unproved........................................................................... 242,205 644,323
Exploration costs.................................................................... 1,861,432 182,147
Development costs.................................................................... 153,938 313,152
------------ -------------
Total costs incurred............................................................. $ 3,023,253 $ 2,444,841
------------ -------------
------------ -------------
</TABLE>
CAPITALIZED COSTS:
<TABLE>
<CAPTION>
AT DECEMBER 31,
---------------------------
1997 1996
------------ -------------
<S> <C> <C>
Proved and unproved properties being amortized....................................... $ 1,181,811 $ 4,681,518
Unproved properties not being amortized.............................................. 2,054,037 598,596
Less accumulated amortization........................................................ (438,044) (2,277,984)
------------ -------------
Net capitalized costs............................................................ $ 2,797,804 $ 3,002,130
------------ -------------
------------ -------------
</TABLE>
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:
The estimates of proved producing reserves were estimated. Proved reserves
cannot be measured exactly because the estimation of reserves involves numerous
judgmental and arbitrary determinations.
43
<PAGE>
FRONTIER NATURAL GAS CORPORATION
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED): (CONTINUED)
Accordingly, reserve estimates must be continually revised as a result of new
information obtained from drilling and production history or as a result of
changes in economic conditions.
<TABLE>
<CAPTION>
CRUDE OIL, CONDENSATE
AND NATURAL GAS
LIQUIDS (BARRELS)
NATURAL GAS (MCF) ---------------------
--------------------------
YEARS ENDED DECEMBER
YEARS ENDED DECEMBER 31, 31,
-------------------------- ---------------------
1997 1996 1997 1996
----------- ------------- --------- ----------
<S> <C> <C> <C> <C>
Proved developed and undeveloped reserves:
Beginning of period......................................... 8,901,555 18,564,141 183,735 279,501
Purchases of minerals-in-place.............................. -- 2,615,187 -- 84,096
Sales of minerals-in-place.................................. (159,528) (10,092,754) (3,857) (187,006)
Revisions of previous estimates............................. (3,129,076) (791,059) (59,121) 8,534
Extensions, discoveries and other additions................. 8,715 12,056 928 7,886
Production.................................................. (121,304) (1,406,016) (7,286) (9,276)
----------- ------------- --------- ----------
End of period............................................... 5,500,363 8,901,555 114,399 183,735
----------- ------------- --------- ----------
----------- ------------- --------- ----------
Proved developed reserves:
Beginning of period......................................... 985,524 7,307,717 46,420 72,515
----------- ------------- --------- ----------
----------- ------------- --------- ----------
End of period............................................... 521,345 985,524 24,358 46,420
----------- ------------- --------- ----------
----------- ------------- --------- ----------
</TABLE>
Reserves of wells, which have performance history, were estimated through
analysis of production trends and other appropriate performance relationships.
Where production and reservoir data were limited, the volumetric method was used
and it is more susceptible to subsequent revisions.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:
The standardized measure of discounted future net cash flows is based on
criteria established by Financial Accounting Standards Board Statement No. 69,
"Accounting for Oil and Gas Producing Activities" and is not intended to be a
"best estimate" of the fair value of the Company's oil and gas properties. For
this to be the case, forecasts of future economic conditions, varying price and
cost estimates, varying discount rates and consideration of other than proved
reserves (i.e., probable reserves) would have to be incorporated into the
valuations.
Future net cash inflows are based on the future production of proved
reserves of natural gas, natural gas liquids, crude oil and condensate as
estimated by petroleum engineers by applying current prices of gas and oil (with
consideration of price changes only to the extent fixed and determinable and
with consideration of the timing of gas sales under existing contracts or spot
market sales) to estimated future production of proved reserves. Average year
end prices used in determining future cash inflows for natural gas and oil for
the periods ended December 31, 1997 and 1996 were as follows: 1997--$2.46 per
MCF--Gas, $15.70 per barrel--Oil; 1996--$4.13 per MCF--Gas, $24.42 per
barrel--Oil, 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 tax rate to the future pretax net
cash flows relating to the Company's estimated proved oil and gas reserves. The
estimated future income taxes give effect to permanent differences and tax
credits and allowances.
44
<PAGE>
FRONTIER NATURAL GAS CORPORATION
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED): (CONTINUED)
The following table sets forth the Company's estimated standardized measure
of discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996
------------- -------------
<S> <C> <C>
Future cash inflows...................................................... $ 15,752,040 $ 41,251,837
Future development and production costs.................................. (7,468,887) (8,288,416)
Future income tax expenses............................................... (365,224) (6,628,489)
------------- -------------
Future net cash flows.................................................... 7,917,929 26,334,932
Discount................................................................. (4,019,429) (9,576,388)
------------- -------------
Standardized measure of discounted future net cash flows................. $ 3,898,500 $ 16,758,544
------------- -------------
------------- -------------
</TABLE>
The following table sets forth changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1996
-------------- --------------
<S> <C> <C>
Standardized measure of discounted future cash flows--beginning of period......... $ 16,758,544 $ 16,404,620
Sales of oil and gas produced, net of operating expenses.......................... (312,198) (1,977,577)
Net changes in sales prices and production costs.................................. (10,601,580) 7,177,867
Extensions, discoveries and improved recovery, less related costs................. 30,952 187,877
Change in future development costs................................................ (433,134) (17,400)
Previously estimated development costs incurred during the year................... 162,610 115,440
Revisions of previous quantity estimates.......................................... (4,973,603) (1,940,104)
Accretion of discount............................................................. 2,169,632 2,004,973
Net change of income taxes........................................................ 4,810,619 (1,292,670)
Purchases of minerals-in-place.................................................... -- 7,787,886
Sales of minerals-in-place........................................................ (371,728) (11,270,558)
Changes in production rates (timing) and other.................................... (3,341,614) (421,810)
-------------- --------------
Standardized measure of discounted future cash flows--end of period............... $ 3,898,500 $ 16,758,544
-------------- --------------
-------------- --------------
</TABLE>
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable.
45
<PAGE>
ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information regarding the Company's
current directors and executive officers.
<TABLE>
<CAPTION>
NAME AGE POSITION
- --------------------------------- --- -------------------------------------------------------------------------
<S> <C> <C>
David W. Berry................... 48 Chairman of the Board of Directors and President
David B. Christofferson.......... 49 Executive Vice President, Secretary, General Counsel and Director
Jeffrey R. Orgill................ 52 Director
Allen H. Sweeney................. 50 Director
Michael A. Barnes................ 55 Vice President of Exploration and Production
</TABLE>
DAVID W. BERRY has served as President of the Company since the
incorporation of its predecessor in August 1988, and has served as Chairman of
the Board of Directors since 1991. In 1978, he formed Berry Petroleum
Corporation, which was a regional natural gas and oil exploration company. In
1976 he co-founded Vulcan Energy Corporation, a Tulsa, Oklahoma, based
exploration and production company. Mr. Berry has served as the State Finance
Chairman of the Oklahoma State Republican Party, as a Trustee for the Oklahoma
Museum of Art and on the United States Senatorial Trust Committee. Mr. Berry is
a member of the Texas Independent Producers and Royalty Owners Association.
DAVID B. CHRISTOFFERSON has served as General Counsel, Secretary and a
director of the Company since 1989, and as Executive Vice President since 1993.
Mr. Christofferson has been active in the natural gas and oil industry for over
25 years, including the responsibility for over $100 million in natural gas and
oil loans when he managed the energy department of Utica National Bank. He
served as Executive Vice President of two independent natural gas and oil
companies that raised over $40 million in non-industry capital. Since 1981, and
before joining the Company, he served as a financial consultant and corporate
counsel to several Oklahoma based natural gas producers. He also briefly served
as General Counsel to a natural gas marketing company. Mr. Christofferson is a
member of the Texas Independent Producers and Royalty Owners Association. He
received a BBA in finance and a Juris Doctor from the University of Oklahoma. He
also received a Masters of Divinity from Phillips University. He is admitted to
practice law in Oklahoma.
JEFFREY R. ORGILL has served as Vice Chairman of the Board of Directors
since 1991. From October 1988 to May 1996, he served as the Company's Vice
President of Exploration and Production. Mr. Orgill was a consultant to the
Company from May 1, 1996 through March 31, 1998. He received a Bachelor of
Science degree in Geology and a Master of Science degree in Geology from Brigham
Young University.
ALLEN H. SWEENEY has served as a director of the Company since September
1993. From 1991 to 1994, Mr. Sweeney also served as Chief Accountant and as a
consultant to the Company. Since 1990, Mr. Sweeney has served as President and a
director of AHS & Associates, Inc., a gas and oil consulting firm, as President
and a director of Columbia Production Company, an independent gas and oil
company, and as Vice President and a director of Mid-America Waste Management,
Inc. He also is Chairman of the Board of Tengasco, Inc., a publicly held oil and
gas company. Mr. Sweeney received a BS in accounting from Oklahoma State
University and an MBA from Oklahoma City University.
MICHAEL A. BARNES has served as Vice President of Exploration and Production
since May 1996. From March 1991 until his employment with the Company, Mr.
Barnes served as Exploration Manager--Gulf Coast for Great Western Resources,
Inc. He has 30 years experience in the gas and oil industry with emphasis in the
Gulf Coast region. His experience includes seven years as a geologist with
Texaco, Inc. and ten years with Sandefer Oil & Gas, Inc., where he served as
Vice President of Exploration and Vice President of Exploitation. Mr. Barnes
received a BS in Geology from the University of Texas.
46
<PAGE>
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
Section 16(a) of the Exchange Act requires the Company's directors,
executive officers and persons who own more than 10% of a registered class of
the Company's equity securities, to file reports of ownership on Form 3 and
changes in ownership on Form 4 or 5 with the Commission. Such officers,
directors and 10% shareholders also are required by Commission rules to furnish
the Company with copies of all Section 16(a) reports they file. Based solely on
its review of the copies of such forms received by it, or written
representations from certain reporting persons that they were not required to
file a Form 5, the Company believes that, during the fiscal year ended December
31, 1997, its officers, directors and 10% shareholders complied with all Section
16(a) filing requirements applicable to such individuals.
ITEM 10. EXECUTIVE COMPENSATION
The following table sets forth the compensation, including bonuses, paid by
the Company during each of the three fiscal years ended December 31, 1995, 1996
and 1997 to the Chief Executive Officer and to its other executive officers
(other than the Chief Executive Officer) of the Company and its subsidiaries.
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
AWARDS
---------------------------
AWARDS OF ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS(1) COMPENSATION
- ------------------------------------------------------ --------- ---------- --------- ------------ -------------
<S> <C> <C> <C> <C> <C>
David W. Berry ....................................... 1997 $ 134,400 -- 192,000(2) $ 44,965(3)
Chairman of the Board, Chief Executive Officer and 1996 124,000 -- 192,000(2) 20,145(3)
President 1995 120,000 -- -- 18,367(3)
David B. Christofferson .............................. 1997 $ 112,000 -- 352,000(2) $ 47,888(4)
Director, Executive Vice President, Chief Financial 1996 103,000 -- 100,000(2) 22,469(4)
Officer and Secretary 1995 95,000 5,000 -- 20,090(4)
S. Gordon Reese, Jr.(5) .............................. 1997 $ 100,000 -- -- $ 6,553
Senior Vice President 1996 98,900 -- 85,000 --
1995 70,000 35,000 -- --
Michael A. Barnes(6) ................................. 1997 $ 100,000 -- 25,000 --
Vice President of Exploration and Production 1996 61,750 -- 25,000 --
1995 -- -- -- --
</TABLE>
- ------------------------
(1) Represents the number of shares issuable pursuant to vested and non-vested
stock options.
(2) In 1997 all stock options previously granted to Mr. Berry and Mr.
Christofferson were canceled and new stock options were granted to them
pursuant to the Employee Option Plan 1997 (the "1997 Plan"). Amounts stated
for 1997 include regrants of such canceled options. See "Option Repricings"
and "Employment Agreements."
(3) In 1997, the Company settled its deferred compensation liability to Mr.
Berry for a payment of $80,537. Of this amount, a total of $66,063 had been
reported as earned compensation in the years 1993-96, and the balance of
$14,474 is reported as earned in 1997.
(4) In 1997, the Company settled its deferred compensation liability to Mr.
Christofferson for a payment of $95,170. Of this amount, a total of $72,694
had been reported as earned compensation in the years 1993-96, and the
balance of $22,476 is reported as earned in 1997. See "Deferred
Compensation."
(5) Mr. Reese has resigned as an officer of the Company.
(6) Mr. Barnes will cease to be an officer of the Company within ninety days.
47
<PAGE>
OPTION GRANTS
The following table sets forth certain information relating to option grants
made in 1997 to the individuals named in the Summary Compensation Table above.
See "--Executive Compensation."
<TABLE>
<CAPTION>
POTENTIAL
REALIZABLE
VALUE AT
ASSUMED
ANNUAL
INDIVIDUAL GRANTS RATES OF
-------------------------------------------------------------------- STOCK PRICE
NUMBER OF APPRECIATION
SECURITIES OF % OF TOTAL FOR OPTION
UNDERLYING OPTIONS GRANTED TO EXERCISE TERM(2)
OPTIONS EMPLOYEES IN FISCAL 1997 PRICE PER EXPIRATION -----------
NAME GRANTED YEAR(1) SHARE DATE 5%
- -------------------------------------- ------------- ------------------------- ----------- ------------- -----------
<S> <C> <C> <C> <C> <C>
David W. Berry........................ 192,000(3) 30% $ .63 11/07 $ 136,000
David B. Christofferson............... 352,000(3) 54% $ .63 11/07 $ 249,920
S. Gordon Reese, Jr.(5)(4)............ -- -- -- -- --
Michael A. Barnes(6).................. 25,000(5) 4% $ 1.28 4/07 $ 1,500
<CAPTION>
MARKET PRICE
NAME 10% ON GRANT DATE
- -------------------------------------- ---------- -------------
<S> <C> <C>
David W. Berry........................ $ 316,000 $ 95,040(7)
David B. Christofferson............... $ 580,820 $ 174,240(7)
S. Gordon Reese, Jr.(5)(4)............ -- --
Michael A. Barnes(6).................. $ 25,000 $ 17,250
</TABLE>
- ------------------------
(1) Based on options to purchase a total of 646,000 shares of Common Stock
granted during 1997, of which 45,000 (or 7%) have expired.
(2) Potential values stated are the result of using the Securities and Exchange
Commission method of calculating 5% and 10% appreciation in value from the
date of grant to the end of the option term. Such assumed rates of
appreciation and potential realizable values are not necessarily indicative
of the appreciation, if any, that may be realized in future periods.
(3) Consists of options issued under the 1997 Plan, all of which are currently
exercisable. Such options were issued in 1997 in replacement of certain
options and stock appreciation rights issued in previous years. See
"--Option Repricings."
(4) Mr. Reese has resigned as an executive officer of the Company.
(5) All options were granted under the 1997 Plan. One-third of the options are
currently exercisable and the remaining two-thirds become exercisable over
1998 and 1999.
(6) Mr. Barnes will cease to be an officer of the Company within ninety days.
(7) See "Option Repricings".
OPTION REPRICINGS
In the last quarter of 1997, the Company determined to attempt to consummate
a significant corporate transaction to satisfy the Company's need for additional
capital resources. In connection with pursuing such a transaction, Mr. Berry and
Mr. Christofferson entered into Incentive Agreements and Contract Settlement
Agreements with the Company pursuant to which each of Mr. Berry and Mr.
Christofferson are entitled to receive certain Incentive Payments and Contract
Settlement Payments upon the consummation of such a transaction. Their existing
employment agreements will terminate upon the consummation of a significant
corporate transaction.
In negotiating the terms of the Incentive Agreements and Contract Settlement
Agreements, Mr. Berry and Mr. Christofferson determined that their existing
stock options would expire 90 days after their termination of employment. The
Compensation Committee of the Board of Directors, which was comprised of Messrs.
Sweeney and Elliott, each of whom was an outside director, recognized that the
expiration of those options would result in a disincentive for Mr. Berry and Mr.
Christofferson to help the Company pursue a significant corporate transaction.
Therefore, the Compensation Committee determined that Mr. Berry's and Mr.
Christofferson's existing stock options should be canceled and replaced with new
stock options that would terminate on the date their old options would have
expired if their employment with the Company was not terminated. As an added
incentive, the Compensation Committee determined to reprice Mr. Berry's and Mr.
Christofferson's options so they could more readily benefit from any upturn in
the Company's Common Stock trading price upon the consummation of a significant
corporate transaction.
48
<PAGE>
When determining the price at which Mr. Berry's and Mr. Christofferson's new
options would be exercisable, the Compensation Committee took the average
closing price of the Company's Common Stock on the Nasdaq Small-Cap Market over
the 20 day trading period immediately preceding the option reprice date, and
multiplied such average trading price by 0.65. The Compensation Committee
believed that the discount to the average trading price was appropriate because
the shares of Common Stock issuable upon exercise of the repriced options would
not be freely tradeable and the discount was appropriate to reflect the actual
fair market value of the illiquid shares that would be received upon the
exercise of the new options.
The following table sets forth certain information with respect to
replacement stock options granted to Mr. Berry and Mr. Christofferson during the
year ended December 31, 1997, which are also reported above under "--Option
Grants."
<TABLE>
<CAPTION>
NUMBER OF
SECURITIES OF LENGTH OF ORIGINAL
UNDERLYING MARKET PRICE OF OPTION TERM
OPTIONS/SARS STOCK AT TIME EXERCISE PRICE AT REMAINING AT DATE
REPRICED OR OF REPRICING OR TIME OF REPRICING NEW EXERCISE OF REPRICING OR
NAME DATE AMENDED AMENDMENT OR AMENDMENT PRICE AMENDMENT (MONTHS)
- ------------------------- --------- -------------- --------------- ------------------- ----------------- -------------------
<S> <C> <C> <C> <C> <C> <C>
David W. Berry........... 12/3/97 120,000(1) $ .97 $ 1.62 $ .63 102
President and Chief 12/3/97 24,000(2) $ .97 $ 3.10 $ .63 69
Executive Officer
David B.
Christofferson......... 12/3/97 180,000(3) $ .97 $ 1.68 $ .63 62
Executive Vice 12/3/97 24,000(2) $ .97 $ 3.10 $ .63 69
President, General 12/3/97 100,000(1) $ .97 $ 1.47 $ .63 102
Counsel and Secretary
</TABLE>
- ------------------------
(1) Consists of options to purchase shares of Common Stock pursuant to the 1996
Plan.
(2) Consists of units, each of which included an option to purchase one share of
Common Stock and a stock appreciation right ("SAR") equal to two times the
difference between the exercise price of the option and the market value of
the SAR at the date of exercise, so that one unit had the value of three
options, all issued pursuant to the 1993 MISP.
(3) Consists of options to purchase 180,000 shares of Common Stock pursuant to
the Company's 1993 Incentive Stock Option Plan.
OPTION EXERCISE AND YEAR-END VALUES
The following table sets forth certain information as of December 31, 1997
with respect to the unexercised options to purchase Common Stock to the
individuals named in the Summary Compensation Table above. See "Executive
Compensation." None of such individuals exercised any stock options during 1997.
<TABLE>
<CAPTION>
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED
OPTIONS AT DECEMBER 31, IN-THE-MONEY OPTIONS
1997 AT DECEMBER 31, 1997(1)
-------------------------- ------------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ------------------------------------------------------- ----------- ------------- ----------- -----------------
<S> <C> <C> <C> <C>
David W. Berry......................................... 192,000 -- $ 28,992 --
David B. Christofferson................................ 352,000 -- $ 53,192 --
S. Gordon Reese, Jr.................................... -- -- -- --
Michael A. Barnes...................................... 8,333 16,667 -- --
</TABLE>
- ------------------------
(1) Based on the last sale price of the Common Stock on the Nasdaq Small-Cap
Market on December 31, 1997 of $0.78.
49
<PAGE>
EMPLOYMENT AGREEMENTS
Mr. Berry and Mr. Christofferson (each an "Employee") each have entered into
an Incentive Agreement and a Contract Settlement Agreement, and their employment
agreements with the Company will be terminated upon the closing of the
Acquisitions. Pursuant to the Incentive Agreements and Contract Settlement
Agreements, the Company agreed that if the Company closes a significant
corporate transaction, and the Employee does not resign as an executive officer
before that time, the Company will pay an Incentive Payment of $134,000 to Mr.
Berry and $112,000 to Mr. Christofferson, as well as a Contract Settlement
Payment of $134,000 to Mr. Berry and $112,000 to Mr. Christofferson, at which
time Mr. Berry and Mr. Christofferson will be released from all further
obligations to the Company other than contractual confidentiality obligations.
Each of the Incentive Payments and the Contract Settlement Payments are in the
form of promissory notes bearing interest at the rate of 10% per year payable by
the Company to the Employees, with the principal amount being paid at a minimum
of $5,000 per month, beginning the first day of the third month after the
closing of the significant corporate transaction, and all principal and accrued
interest being due and payable upon the earlier of September 30, 1998, or the
completion of a public sale of any equity or debt securities of the Company,
whichever is earlier. Each of the employees, at their discretion, may defer
payment of up to 50% of the principal amount, due until January 15, 1999. The
Contract Settlement Payments are intended to satisfy the Employees existing
employment contracts. Incentive Payments are intended to compensate the
Employees for their services in soliciting, negotiating and closing a
significant corporate transaction and not in satisfaction of any prior
obligations to the Company. The Incentive Payments are in addition to any other
obligations or payments due to the Employees, including the settlement of their
previously existing employment contracts. In addition, as an inducement to the
Employees to continue to solicit and close a change of control transaction, and
regardless of whether such a transaction occurs, all of the stock options
previously granted to the employees by the Company were canceled, and the
Company issued to each of the employees new stock options pursuant to the
Employee Option Plan. See "--Option Grants" and "--Option Repricings."
The transactions contemplated by the Acquisition Agreement will constitute a
significant corporate transaction pursuant to which the Incentive Payments and
Contract Settlement Payments will be payable to Mr. Berry and Mr.
Christofferson. Upon the closing of the Acquisitions, Mr. Berry and Mr.
Christofferson will have no further contractual obligations to the Company other
than confidentiality obligations and any contractual arrangements they may
negotiate with the Company in the future.
DEFERRED COMPENSATION
Pursuant to employment agreements with Messrs. Berry, Orgill and
Christofferson, deferred compensation accrued annually payable at the rate of
$9,000 per year for each year the executive was employed by the Company. The
payment of such compensation is deferred until retirement at which time it is
payable for a period of 15 years. In lieu of receiving such deferred
compensation upon retirement, in 1997 the Company paid Mr. Berry $80,537 and Mr.
Christofferson $95,170, which amounts were based upon a present value
calculation of the deferred compensation accrued as of August 30, 1997.
OPTION PLANS
MANAGEMENT INCENTIVE STOCK PLAN-1993. The MISP-1993 authorized the issuance
of up to 240,000 units. Each unit consists of (i) an option to purchase one
share of Common Stock and (ii) a cash payment ("Stock Appreciation Right" or
"SAR") to be made by the Company when the option is exercised. The value of the
SAR is equal to twice the amount by which the fair market value of the Common
Stock on the date of exercise of the option exceeds the exercise price.
Currently, all units have expired or have been canceled by the Board of
Directors other than 48,000 units currently outstanding, 18,000 of which expire
in May 1998.
50
<PAGE>
STOCK INCENTIVE OPTION PLAN-1996. The 1996 Plan authorized the issuance of
up to 350,000 options to purchase one share of Common Stock. Currently, all
options have expired or have been canceled by the Board of Directors other than
142,000 options currently outstanding, of which 91,000 expire in May 1998.
EMPLOYEE OPTION PLAN-1997. The 1997 Plan authorizes the issuance of up to
695,350 options to purchase one share of Common Stock. Options to purchase
601,000 shares are currently outstanding, of which 6,000 expire in May 1998.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information, as of March 27, 1998,
with respect to the Common Stock owned by (i) each person known by management to
own beneficially more than 5% of the Company's outstanding Common Stock; (ii)
each of the Company's directors, nominees for directors and executive officers;
and (iii) all directors and executive officers of the Company as a group. Unless
otherwise noted, the persons named below have sole voting and investment power
with respect to such shares.
<TABLE>
<CAPTION>
PERCENTAGE OF
NUMBER OF OUTSTANDING
NAME OF BENEFICIAL OWNER SHARES(1) SHARES(2)(3)
- ----------------------------------------------------------------------------- ---------- --------------
<S> <C> <C>
David W. Berry(4)(5)......................................................... 852,930 8.0%
Alex Cranberg(6)............................................................. 123,900 1.16%
Jeffrey R. Orgill(4)(7)...................................................... 592,500 5.53%
David B. Christofferson(4)(8)................................................ 408,000 3.81%
Allen H. Sweeney(9).......................................................... 12,000 *
Michael A. Barnes(10)........................................................ 8,333 *
Michael E. Johnson(11)....................................................... 75,000 *
Charles J. Smith(11)......................................................... 75,000 *
Directors and executive officers as a group (5 persons)(12).................. 1,873,763 17.49%
</TABLE>
- ------------------------
* Less than 1%.
(1) Includes all shares with respect to which each person, executive officer or
director who directly, through any contract, arrangement, understanding,
relationship or otherwise, has or shares the power to vote or to direct
voting of such shares or to dispose or to direct the disposition of such
shares. Includes shares that may be purchased under stock options
exercisable within 60 days.
(2) Based on 9,935,906 shares of Common Stock outstanding at March 27, 1998,
plus, for each beneficial owner, those number of shares underlying
exercisable options held by each executive officer or director.
(3) Percent of class for any shareholder listed is calculated without regard to
shares of Common Stock issuable to others upon exercise of outstanding
stock options. Any shares a shareholder is deemed to own by having the
right to acquire by exercise of an option or warrant are considered to be
outstanding solely for the purpose of calculating that shareholder's
ownership percentage.
(4) Address c/o Frontier Natural Gas Corporation, One Allen Center, Suite 2950,
Houston, Texas 77002.
(5) Includes options to purchase 192,000 shares of Common Stock that are
currently exercisable.
(6) Includes options to purchase 112,500 shares of Common Stock that are
currently exercisable warrants held by Aspect, as to which Mr. Cranberg
disclaims beneficial ownership.
(7) Includes options to purchase 24,000 shares of Common Stock that are
currently exercisable.
(8) Includes options to purchase 352,000 shares of Common Stock that are
currently exercisable.
51
<PAGE>
(9) Includes options to purchase 12,000 shares of Common Stock that are
currently exercisable. Mr. Barnes will no longer be an employee of the
Company and his options will expire within ninety days.
(10) Includes 8,333 shares issuable pursuant to various options held by
executive officers and directors that are currently exercisable.
(11) Includes 75,000 shares of Common Stock issuable upon exercise of currently
exercisable warrants held by Esenjay. As to which Messrs. Johnson and
Smith disclaim beneficial ownership.
(12) Includes 588,333 shares issuable pursuant to various options held by
executive officers and directors and currently exercisable.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Effective May 1, 1996, Jeffrey Orgill and the Company agreed to the
termination of Mr. Orgill's employment agreement and Mr. Orgill resigned as Vice
President of Exploration and Production as of May 1, 1996 that expired in March,
1998. Mr. Orgill entered into a Consulting Agreement with the Company effective
May 1, 1996. Mr. Orgill was paid $10,000 per month under the terms of the
agreement through March 1998. Pursuant to the Consulting Agreement, the Company
paid $120,000 to Mr. Orgill during 1997 for consulting services.
The Company made advances to officers and affiliates of the Company during
1996 and 1997 of $51,143 and $48,380, respectively, and received repayments of
$18,741 and $99,216, respectively. The December 31, 1996 and 1997 receivables
include approximately $47,787 and $47,787, respectively, from an affiliated
partnership for which the Company serves as the managing general partner.
During 1996, as a part of the Company's relocation to Houston, Texas, the
Company purchased the homes of David W. Berry and David B. Christofferson, both
officers of the Company, for $191,395 and $178,000, respectively. These amounts
in each case were ascertained by averaging two independent MAI appraisals to
determine fair market value. The Company subsequently sold the homes at a sales
contract price of $176,200 and $178,000, respectively, pursuant to which sales
contracts the Company received net sales proceeds after commissions and other
selling expenses of $158,847 and $165,626, respectively.
52
<PAGE>
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
EXHIBIT NAME OF EXHIBIT
- ------------- --------------------------------------------------------------------------------------------------------
<C> <S>
2(a) Acquisition Agreement and Plan of Exchange Regarding the Acquisition of Certain Assets of Esenjay
Petroleum Corporation and Aspect Resources LLC by Frontier Natural Gas Corporation, dated January 19,
1998.
2(b) First Amendment to Acquisition Agreement and Plan of Exchange regarding the Acquisitions of certain
assets of Esenjay Petroleum Corporation and Aspect Resources LLC by Frontier Natural Gas Corporation,
amendment dated April 20, 1998.
3(a) Amended & Restated Certificate of Incorporation of the Company is incorporated by reference to the
Company's Registration Statement 333-06261, Amendment No. 1, dated July 31, 1996.
3(b)* Amended Certificate of Incorporation of the Company dated February 11, 1998.
3(c) By-Laws of the Company as currently in effect is incorporated by reference to the Company's Registration
Statement 33-69640-FW, wherein the same appeared as Exhibit 3.2.
4 See Articles V, and VI, of the Company's Certificate of Incorporation and Article V of the Company's
By-Laws as provided at Exhibits 3(a) and 3(b) above, and see also the Company's Certificate of
Designations of Convertible Preferred Stock as currently in effect which is incorporated by reference
to the Company's Registration Statement number 33-69640-FW dated September 29, 1993 wherein the same
appeared as Exhibit 3.3.
10(a) Employment Agreement by and between the Company and David W. Berry as currently in effect is
incorporated by reference to the Company's Registration Statement 33-69640-FW dated September 29, 1993
wherein the same appeared as Exhibit 10.1.
10(b)* Contract Settlement Agreement between Frontier Natural Gas Corporation and David W. Berry dated
effective January 1, 1998.
10(c) Employment Agreement by and between the Company and David B. Christofferson as currently in effect is
incorporated by reference to the Company's Registration Statement 33-69640-FW dated September 29, 1993
wherein the same appeared as Exhibit 10.2.
10(d)* Contract Settlement Agreement between Frontier Natural Gas Corporation and David B. Christofferson dated
effective January 1, 1998.
10(e) Frontier Natural Gas Corporation Incentive Stock Option Plan as currently in effect is incorporated by
reference to the Company's Registration Statement 33-69640-FW dated September 29, 1993 wherein the
same appeared as Exhibit 10.5.
10(f) Engagement Agreement between Weisser, Johnson & Co. Capital Corporation and Frontier Natural Gas
Corporation dated May 10, 1995 as amended January 12, 1996 as currently in effect as incorporated by
reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1995
dated March 29, 1996 wherein the same appears as Exhibit 10(h).
10(g) Common Stock Purchase Warrant with Hi-Chicago Trust as currently in effect as incorporated by reference
to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1995 dated March
29, 1996 wherein the same appears as Exhibit 10(i).
</TABLE>
53
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NAME OF EXHIBIT
- ------------- --------------------------------------------------------------------------------------------------------
<C> <S>
10(h) $15,000,000 Credit Agreement dated as of January 3, 1996 between Frontier Natural Gas Corporation as the
borrower and Bank of America Illinois, as the lender, as currently in effect and incorporated by
reference to the Company's current report on Form 8-K dated January 9, 1996.
10(i) $15,000,000 Credit Agreement dated as of January 3, 1996 between Frontier Natural Gas Corporation as the
borrower and Bank of America Illinois, as the lender, Amendment No. 1 to Credit Agreement, dated
November 1, 1996, as currently in effect.
10(j) Lease Agreement dated July 16, 1996, by and between the Company and Allen Center Company is incorporated
by reference to the Company's registration statement 333-06261 dated July 31, 1996 wherein the same
appeared as Exhibit 10.23.
10(k) Loan Agreement by and between Frontier Natural Gas Corporation and 420 Energy Investments, Inc. dated
March 1, 1996 as currently in effect as incorporated by reference to the Company's Annual Report on
Form 10-KSB for the fiscal year ended December 31, 1995 dated March 29, 1996 wherein the same appears
as Exhibit 10(r).
10(l) Warrant Agreement between Frontier Natural Gas Corporation and LaSalle Street Natural Resources
Corporation dated as of January 3, 1996 as currently in effect as incorporated by reference to the
Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1995 dated March 29,
1996 wherein the same appears as Exhibit 10(s).
10(m) Frontier Natural Gas Corporation Stock Incentive Plan 1996 as currently in effect as incorporated by
reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1995
dated March 29, 1996 wherein the same appears as Exhibit 10(t).
10(n) 3-D Seismic Participation Agreement dated May 30, 1996 by and between Frontier Natural Gas Corporation
and Fina Oil and Chemical Company.
10(o)* Frontier Natural Gas Corporation Employee Option Plan--1997 as currently in effect.
10(p)* Credit Agreement by and between Frontier Natural Gas Corporation and Duke Energy Financial Services,
Inc. dated as of February 23, 1998, as currently in effect.
11 See Note 1 to the audited consolidated financial statements.
21* Subsidiaries of Registrant.
27* Financial Data Schedule.
</TABLE>
- ------------------------
* Previously filed.
(b) Reports on Form 8-K.
None
54
<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.
<TABLE>
<S> <C> <C>
FRONTIER NATURAL GAS CORPORATION
By: /s/ DAVID W. BERRY
-----------------------------------------
David W. Berry,
CHAIRMAN OF THE BOARD OF DIRECTORS;
PRESIDENT
</TABLE>
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
below by the following persons on behalf of the registrant and in the capacities
and on the dates indicated.
NAME TITLE DATE
- ------------------------------ -------------------------- -------------------
/s/ DAVID W. BERRY Chief Executive Officer,
- ------------------------------ (Principal Executive
David W. Berry Officer) and Director
Executive Vice President,
General Counsel, Chief
/s/ DAVID B. CHRISTOFFERSON Financial Officer,
- ------------------------------ (Principal Accounting
David B. Christofferson and Financial Officer)
and Director
/s/ JEFFREY R. ORGILL
- ------------------------------ Vice Chairman of the Board
Jeffrey R. Orgill of Directors
/s/ ALLEN H. SWEENEY
- ------------------------------ Director
Allen H. Sweeney
55
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 650,576
<SECURITIES> 0
<RECEIVABLES> 237,352
<ALLOWANCES> (15,488)
<INVENTORY> 0
<CURRENT-ASSETS> 1,266,939
<PP&E> 4,404,975
<DEPRECIATION> (1,260,605)
<TOTAL-ASSETS> 4,576,008
<CURRENT-LIABILITIES> 1,680,316
<BONDS> 22,680
0
860
<COMMON> 99,359
<OTHER-SE> 1,704,601
<TOTAL-LIABILITY-AND-EQUITY> 4,576,008
<SALES> 664,126
<TOTAL-REVENUES> 908,609
<CGS> 0
<TOTAL-COSTS> 5,801,470
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 60,942
<INCOME-PRETAX> (4,953,803)
<INCOME-TAX> 0
<INCOME-CONTINUING> (4,953,803)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (4,953,803)
<EPS-PRIMARY> (0.51)
<EPS-DILUTED> (0.51)
</TABLE>
