UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-KSB
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 1996
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the transition period from to
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Commission file number: 0-22782
FRONTIER NATURAL GAS CORPORATION
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(Exact name of small business issuer in its charter)
Oklahoma 73-1421000
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(State of incorporation) (I.R.S. Employer Identification No.)
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
Securities registered under Section 12(b) of the Exchange Act:
Name of each exchange
Title of each class on which registered
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None None
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: $3,378,792
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 $23,401,719 on February 28, 1997 (based on the last sales price of
$2.75 per share as reported on the NASDAQ Stock Market).
9,865,906 shares as the registrant's common stock were outstanding as
of February 28, 1997.
DOCUMENTS INCORPORATED BY REFERENCE
Registrant's Proxy Statement for its 1997 Annual Meeting of Stockholders is
incorporated by reference into Part III.
<PAGE>
FRONTIER NATURAL GAS CORPORATION
For Year Ended December 31, 1996
TABLE OF CONTENTS
FORM 10-KSB
PART I
Item Page
1. Description of Business............................................. 1
2. Description of Property............................................. 8
3. Legal Proceedings................................................... 10
4. Submission of Matters to a Vote of Security Holders................. 10
PART II
5. Market for Common Equity and Related Stockholder Matters............ 11
6. Management's Discussion and Analysis or Plan of Operation........... 11
7. Financial Statements................................................ 17
8. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................................. 38
PART III
9. Directors, Executive Officers, Promoters and Control
Persons; Compliance with Section 16(a) of the Exchange Act......... 38
10. Executive Compensation.............................................. 38
11. Security Ownership of Certain Beneficial Owners and Management...... 38
12. Certain Relationships and Related Transactions...................... 38
PART IV
13. Exhibits and Reports on Form 8-K.................................... 38
Signatures.......................................................... 41
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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
Frontier Natural Gas Corporation, an Oklahoma Corporation incorporated in
1988 (the "Company"), is an independent energy company primarily engaged in the
exploration for natural gas and oil reserves and in the acquisition, production,
development and marketing of natural gas and oil properties. The Company's early
growth was through acquisitions of natural gas reserves, principally in the
Mid-Continent Area of Arkansas, Kansas, Oklahoma and Texas. In recent years,
however, the Company's business activities have focused more on exploration and
related developmental drilling projects situated in Southern Louisiana and along
the Gulf Coast of Alabama, Mississippi and Texas. The Company's current business
strategy is to increase its reserves by drilling natural gas and oil wells on
prospects identified and developed through the use of well correlations,
Computer Aided Exploration ("CAEX") technologies and 3-D seismic surveys, with
emphasis on the Gulf Coast and, particularly, the transition zone of Southern
Louisiana. As a supplemental part of such strategy, the Company may also acquire
producing properties as market conditions and the Company's resources allow.
During 1996, as part of its refocusing activities, the Company moved its
headquarters to Houston, Texas, and sold its interests in the N.E. Cedardale
field in Major County, Oklahoma, which represented its primary Mid-Continent
Area producing properties. Its primary focus is now along the Gulf Coast where
its most significant project is referred to as the Starboard Prospect. The
Starboard Prospect is comprised of a group of four distinct high potential
exploration prospects, as well as proved undeveloped locations. The proved
undeveloped portion of the Starboard Prospect has been evaluated by independent
petroleum engineers as containing substantial proved undeveloped reserves. As of
December 31, 1996, the Company had acquired acreage in the Starboard Prospect
which included estimated proved undeveloped reserves of 8 Bcfe and estimated
future net revenues of over $17 million net to its interest. These estimates
will likely change as the 3-D seismic data discussed below is interpreted.
Funding for the project has been provided from a variety of sources. Affiliates
of a public utility funded, through a non-recourse loan, most of the Company's
cost in acreage. A 3-D seismic survey was funded by Fina Oil and Chemical
Company and certain of its partners. The Company has a credit facility with Bank
of America, Illinois, available to fund its share of developmental drilling on
the project. Exploratory drilling will be funded via cash and/or industry
partners. The 3-D seismic has been shot and processed and interpretation has
begun. Final drilling plans are pending interpretation of the 3-D seismic with
initial drilling locations anticipated to be selected by mid-May 1997. The
Company owns working interests in the project ranging from 12% to 48%.
The Company also has interests in three South Louisiana drilling prospects
which are currently waiting on drilling rigs. Two have been confirmed via 3-D
seismic and the third is a high potential wildcat in which Hunt Petroleum
Corporation purchased a 50% working interest.
In addition to 3-D seismic, the Company makes extensive use of 2-D seismic
reprocessing and CAEX enhancement technologies to delineate "bright spot"
seismic anomalies. The Company believes that additional drilling prospects in
the Gulf Coast area may be identified through delineation of such "bright spot"
seismic anomalies. In September 1995, the Company entered into an agreement to
acquire, reprocess and interpret up to 1,600 miles of 2-D seismic data in the
shallow offshore Gulf Coast area. The reprocessing and interpretation of such
data is designed to identify "bright spot" gas accumulations which potentially
can identify the location of commercial quantities of hydrocarbons. In
connection with this agreement, the Company also entered into an agreement with
Marconi, Inc. to fund the project and to jointly explore any prospects thus
identified.
The Company plans to continue to expand its exploration activities in the
Gulf Coast area through a number of current activities, including the (1)
generation of prospects with its existing partners; (2) identification of
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"bright spot" seismic anomalies; (3) continuing acquisition of acreage on
additional high potential Southern Louisiana exploration projects identified by
the Company; and (4) continuing evaluation of high-graded exploration prospect
opportunities in Southern Louisiana and other Gulf Coast areas.
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 a potential gas or oil prospect. Using such
technology, the Company correlates density and sonic characteristics of
subsurface formations obtained from two-dimensional 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 in this manner 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 three-dimensional image based upon seismic data obtained from
multiple horizontal and vertical points within a geological formation. The
tremendous number of calculations needed to process such data is made possible
by computer programs and advanced computer hardware.
While 3-D seismic and CAEX technologies have been used by large oil
companies for approximately 20 years, the method was not affordable by smaller,
independent gas and oil companies until 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. In 1995, the Company created its
own seismic processing division-Exploration Geophysical Services-for the purpose
of assisting the prospect generation efforts of the Company. 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. 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 technology has not been used
extensively enough by the Company to make any conclusion regarding its
performance and the Company's ability to interpret and use the information
developed from the technology.
Exploration and Development
Gulf Coast. The Company considers the Gulf Coast, and in particular
Southern Louisiana, to be the premier area in the United States to explore for
significant new reserves. This conclusion is based on several characteristics of
Southern Louisiana including (1) a large number of productive intervals
throughout a significant sedimentary section, (2) numerous wells with which to
calibrate 3-D seismic, and (3) complicated geology that the Company believes 3-D
seismic is particularly well suited to interpret. In 1994, the Company began
devoting more of its energy to the Gulf Coast region. The Company initially
entered this area by evaluating the onshore shallow Frio/Miocene Trend. The
Company's emphasis is shifting to larger exploration targets in this area due to
the greater potential return on investment resulting from the size of the
geological features which 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 Southern Louisiana. 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 will acquire acreage
and drill wells as indicated by the evaluations.
Most of the prospects in Southern Louisiana being pursued by the Company
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 area and
where it believes 3-D seismic can be used to increase resolution and thereby
lower risk. The extent to which the Company will pursue its activities in the
Gulf Coast region will be determined by the availability of Company resources
and the availability of joint venture partners.
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Southern Louisiana and Gulf Coast of Texas. A primary area of focus for the
Company to identify gas and oil on prospects is in Southern Louisiana and along
the Gulf Coast of Texas. The Company directly and in conjunction with industry
partners has identified a number of prospects to be explored in the target
areas, and the Company has acquired its initial position in certain prospects,
including one which the Company refers to as the Starboard Prospect. The
Starboard Prospect is comprised of a group of four distinct high potential
exploration prospects, as well as proved undeveloped locations. The proved
undeveloped portion of the Starboard Prospect has been evaluated by independent
petroleum engineers as containing substantial proved undeveloped reserves. 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 initial 3-D evaluated
drill sites are anticipated to be selected within 60 days. As of December 31,
1996, the Company had acquired acreage in the Starboard Prospect which included
proved undeveloped reserves. Estimated reserves will likely change after
interpretation of the 3-D seismic. Based on subsurface and currently available
2-D seismic surveys, the Company has defined potential well locations within the
Starboard Prospect, including a number of both proved undeveloped locations and
exploratory prospects. The presence of proved undeveloped reserves within the
Starboard Prospect is expected to lower the project's overall risk.
Interpretation of the 3-D seismic will alter the final mapping of the
sub-surface with such changes altering the pre 3-D mapping of both proven and
exploratory locations. It is too early to evaluate the changes since
interpretation just began in March 1997. The Company has continued and likely
will continue to acquire additional acreage in the Starboard Prospect as revised
subsurface mapping is completed. No significant acquisition of acreage has
occurred since December 31, 1996.
In the first quarter of 1996 the Company completed a credit facility with
Bank of America, Illinois, which included a tranche of $2,500,000 for
developmental drilling on the Starboard Project. The $2,500,000 tranche
currently expires on June 30, 1997, but the bank has stated it is prepared to
extend the date upon request. It also completed an agreement with affiliates of
a utility which funded acreage and related costs including the Company's share.
The Company currently has an $864,000 non-recourse note payable pursuant to said
agreement. The note is payable solely from an 8% overriding royalty interest in
the Starboard Project which reduces to 2% proportionately to the Company's
interest after payout plus a yield of 15%. In the second quarter of 1996 the
Company finalized a joint exploration agreement with Fina Oil and Chemical
Company and its partners to fund the 3-D seismic over the Starboard Project. As
a result of all of the foregoing, the Company, as between it and all of its
Starboard Project partners, owns a 48% working interest in all formations
through the base of the Duval Sand (approximately 15,500 feet), a 36% working
interest in all formations from the base of the Duval Sand through the base of
the DeLarge Sand (approximately 16,500 feet) and a 12% working interest in
deeper formations. It intends to fund its share of developmental drilling costs
through the Bank of America, Illinois, facility and its share of exploratory
costs through cash and/or industry partners.
In the first quarter of 1997 the Company participated in three dry holes in
South Louisiana, for a cost of approximately $693,000 of which approximately
$159,000 of related costs were incurred and expensed as of December 31, 1996.
None of these wells were on prospects confirmed with 3-D seismic. It is also
evaluating a proved location which was attempted to be penetrated with an
unsuccessful sidetrack operation from an existing wellbore in the first quarter
of 1997.
The Company originated and assembled its Plaquemines Parish, Louisiana,
high-potential Schooner Prospect in 1996 resulting in the sale of a promoted 50%
working interest to Hunt Petroleum Corporation in the first quarter of 1997.
After the sale of two additional promoted interests the Company retains a 37%
working interest in this exploratory well. The well is scheduled to be drilled
in the second quarter of 1997.
The Company is also participating in two Terrebonne Parish, Louisiana,
prospects which are both waiting on a drilling rig. The prospects are both 3-D
seismic delineated "bright spot" anomalies. The Company owns a 65% working
interest in its Lucky 13 prospect and a 37.5% working interest in its Channel
Prospect.
Mobile Bay, Alabama. In February and April 1995, the Company successfully
completed two wells in the Mobile Bay area of Alabama offshore waters.
Initially, the wells were producing gas at the combined rate of approximately
10,000 Mcf of gas per day. The Company owns approximately a 30% working interest
in each well. Sales from these wells commenced in December 1995 and have
generated gross revenues to the Company of approximately $1,406,000 from their
inception through December 31, 1996. The wells, drilled on "bright spot" seismic
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anomalies, were identified and developed by the Company utilizing CAEX
technologies. In the fourth quarter of 1996 the production from these wells
unexpectedly declined significantly due to rapidly accelerated water production.
This resulted in significant cash expenditures and operating losses to the
Company. In February 1997, the Company unsuccessfully drilled the State Lease
#804 well to test the previously undrilled Oligocene formation for a cost of
$214,000 of which $10,000 in leasehold costs were incurred and expensed in 1996.
It is currently attempting to recomplete one of the two initial wells in another
formation. Production from these wells is not expected to result in significant
revenues for the Company in the future.
Gulf Coast "Bright Spot" Project. In September 1995, the Company entered
into an agreement with a seismic vendor to acquire, reprocess and interpret up
to 1,600 miles of 2-D seismic data in the shallow offshore Gulf Coast area to
identify "bright spot" gas accumulation indicators on the reprocessed data. The
Company entered into an agreement with Marconi, Inc. to jointly explore any
prospects thus identified. Under the joint venture agreement, Marconi, Inc.
bears 100% of the anticipated costs of the seismic reprocessing and
interpretation. The Company has rights to a 50% working interest in all
prospects located pursuant to this agreement.
Mid-Continent Area. The Company continues to phase out of the Mid-Continent
Area. It will continue in 1997 to work through industry partners to exploit its
3-D seismic data and leasehold position in the area but has no current plans for
significant expenditures in the area for its own account.
Acquisitions and Divestments
The Company periodically acquires producing natural gas and oil properties.
Initially, the Company concentrated its acquisition activity in Kansas,
Oklahoma, Arkansas and Texas, believing that these areas had potential for
exploitation through additional development and 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, natural gas and oil reserves generally available for
acquisition were at unusually high costs. As a result and in reaction to the
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.
During 1994, the Company sold its interest in the Lirette field in
Louisiana in two separate transactions for a sales price of $914,000 in the
first transaction and $1,239,000 in the second transaction. The transactions
resulted in net gains of $468,000 in the first transaction and $515,000 in the
second transaction. During 1995, the Company sold interests in over 40 wells
which did not fit the Company's long-term objectives for a sale price of over
$2,166,000 resulting in net gains of over $722,000.
On September 27, 1996, the Company completed the sale of its N.E. Cedardale
field located 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 facilitates the Company's focus of its resources on its Gulf Coast
projects and reduces debt service requirements over the next three years in an
amount greater than the anticipated net revenues from the properties sold. The
sale to OXY USA, Inc. included cash of $2,840,000 and certain exchange
properties which were concurrently sold to a third party for $710,000, netting
the Company $3,550,000. The sale was effective September 1, 1996 and the Company
incurred a book loss of $10,523. In connection with the sale, the Company also
incurred a loss of $212,000 resulting from the reduction in the quantity of gas
covered by a swap agreement. Due to the early repayment of the borrowing, the
Company reduced debt issuance costs by $293,000 and discount on notes payable by
$207,000. Said non-cash amounts were recorded as additional interest expense.
The Company's acquisition program is overseen by its management which
includes four officers with combined experience of more than 75 years in the gas
and oil industry. It is anticipated that acquisition opportunities may be
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brought to the attention of the Company's management by certain of its officers,
directors and their affiliates as well as by various unaffiliated sources. The
Company currently does not engage professional firms or consultants that
specialize in acquisitions on a formal basis. The Company may engage such firms
in the future, in which case the Company may pay a finder's fee or other cash or
stock compensation.
In connection with each acquisition, the Company considers (i) current and
historic production levels and reserve estimates; (ii) exploitation potential;
(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. Each
acquisition involves management's analysis of its ability to improve the
operations of the 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.
Marketing
The Company markets its natural gas through monthly spot sales. Because
sales made under spot sales contracts may 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 effect of price fluctuations. During
January 1996, pursuant to the Company's credit arrangement with the Bank of
America Illinois, the Company entered into a natural gas swap agreement on
62,500 Million British thermal units ("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 was reduced to 31,250 MMBTU on
September 25, 1996, in connection with the sale of the N.E. Cedardale field.
Frontier recorded a loss of $212,000 on this swap reduction. The Company also
had entered into another natural gas swap agreement on 45,000 MMBTU of natural
gas per month at $2.03 per MMBTU for its Mobile Bay gas production for the
period from January 24, 1996 through December 24, 1996, which swap agreement has
expired.
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 1995 except for the gas sales contract
discussed below. The Company does not believe the loss of any existing purchaser
would have a materially adverse effect on the Company.
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 $0.75 advance on
2,490,103 MMBTU of gas (the balance due as of January 31, 1996) 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, blowouts, 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 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
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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. While 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
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 regulation are under constant review for
amendment and expansion for a variety of political, economic and other reasons.
Numerous regulatory authorities, federal, state and local, 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% interests in each tract over which the
Company intends to conduct seismic surveys. As a result of such requirement, the
Company may not be able to conduct seismic surveys covering its entire area of
interest. Moreover, 3-D seismic surveys are typically conducted from various
locations both inside and outside the area of interest in order to obtain the
most detailed data of the geological features within the area. To the extent
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
types of regulation at the federal, state and local levels. Such regulation
includes (i) requiring permits for the drilling of wells; (ii) maintaining
bonding requirements in order 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 are also subject to various conservation
regulations. These include the regulation of the size of drilling and spacing
units, the density of wells which 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/or 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. The Company's drilling
activities in the Mobile Bay area are subject not only to the State of Alabama
regulation, but also to regulations of the U.S. Army Corps of Engineers and
various other federal and state environmental regulations relating to offshore
activities.
Marketing and Transportation. The sale of some natural gas production by
the Company may be subject to regulation under the Natural Gas Act and the
Natural Gas Policy Act of 1978 (the "NGPA"). Under the NGPA, ceiling prices
apply to first sales of certain natural gas production in both interstate and
intrastate commerce. Administration and enforcement of the NGPA ceiling prices
are delegated to the Federal Energy Regulatory Commission (the "FERC"). As a
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result of the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol Act"),
all price and non-price controls are eliminated for gas not under contract on
July 26, 1989. With respect to gas under contract on July 26, 1989, the
Decontrol Act provides that price and non-price controls are eliminated upon
contract termination or by written agreement of the parties. Since current
market prices for the Company's gas production which continues to be price
controlled are below NGPA maximum lawful prices, the Company is doubtful that
the Decontrol Act will have a significant impact on the prices received by the
Company for gas production in the near future.
In April 1992, the FERC issued Order No. 636, which provided for the
fundamental restructuring of interstate pipeline sales and transportation
services. Among other things, Order No. 636 required interstate pipelines to
"unbundle" their merchant sales functions from their transportation and storage
functions and to assign capacity rights they have on upstream pipelines to the
pipelines' former sales customers, and provided for the recovery by interstate
pipelines of costs associated with the pipelines' transition from providing
bundled sales services to providing unbundled transportation and storage
services. Order No. 636 may also increase transportation costs and tariffs on
interstate pipelines and cause interstate pipelines to seek to renegotiate or
terminate certain of their existing purchase contracts, but ultimately may
enhance gas marketing opportunities and available transportation. The rules
contained in Order No. 636, as amended by Order No. 636-A (issued in August
1992) and Order No. 636-B (issued in November 1992) are far reaching and
complex. In addition, several provisions of Order No. 636 are currently subject
to court challenges. Although the ultimate outcome of these challenges under
Order No. 636 cannot be predicted with certainty, the Company does not believe
the Order No. 636 will adversely effect its operations. Nevertheless, the Order
has resulted in a degree of uncertainty with respect to interstate natural gas
sales and transportation.
No Price Controls on Liquid Hydrocarbons. There are currently no price
controls on crude oil, condensate or natural gas liquids.
Environmental and Occupational Regulation. Various federal, state and local
laws and regulations covering the discharge of materials into the environment,
or otherwise relating to the protection of the public health and the
environment, may effect the Company's operations, expenses and costs. The trend
in environmental regulation which affect the Company has been to place more
restrictions and limitations on activities that impact the environment, such as
emissions of pollutants, generation and disposal of wastes, and use and handling
of chemical substances. Increasingly, strict environmental restrictions and
limitations have resulted in higher operating costs for the Company and other
similar businesses throughout the United States, and it is possible that the
costs of compliance with environmental laws and regulations will continue to
increase.
State initiatives to regulate further the disposal of gas and oil wastes
are also pending in certain states, including states in which the Company has
operations, and these initiatives could have a similar impact on the Company. In
addition, the Company is subject to laws and regulations concerning occupational
health and safety. It is not anticipated that the Company will be required in
the near future to expend amounts that are material in relation to its total
capital expenditures program by reason of environmental or occupational health
and safety laws and regulations, but inasmuch as such laws and regulations are
frequently changed, the Company is unable to predict the ultimate cost of
compliance.
The Company does not believe that its environmental risks are materially
different from those of comparable gas and oil companies operating in similar
geographic areas. Nevertheless, no assurance can be given that environmental
laws will not, in the future, result in a curtailment of production or material
increase in the cost of production, development or exploration or otherwise
adversely affect the Company's operations and financial condition. Although the
Company maintains liability insurance coverage for certain liabilities from
pollution, such environmental risks generally are not fully insurable.
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
7
<PAGE>
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. In the event 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 establishment and funding of the site-specific trust
account is approved by the DNR, the selling party shall not thereafter be held
liable by the state for any site restoration costs. 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 fund.
Competition
The gas and oil industry is highly competitive in all of its phases. The
Company encounters competition from other gas and oil companies in all areas of
its operations, including the acquisition of producing properties, the
permitting and conducting of seismic surveys and the marketing of gas and oil
and the availability of drilling rigs. Many of these competitors possess greater
financial, technical and other resources than the Company. Competition for
acquisition of producing properties is affected by the amount of funds available
to the Company, information about producing properties available to the Company,
and any standards established from time to time by the Company for the minimum
projected return on investment. Competition may also 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 are
generally 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 $111,120. Frontier completed the move of
its corporate headquarters to Houston, Texas in September 1996, to allow the
Company to more effectively exploit opportunities in their primary areas of
exploration, which are focused along the Gulf Coast, and in particular, the
transition zones of South Louisiana.
Employees
The Company employs 13 people in its Houston office and one person in its
Southern Louisiana office. They are all full time employees. Their functions
include management, engineering, production, geology, geophysics, land and
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.
ITEM 2. DESCRIPTION OF PROPERTY
Principal Areas of Operations
The Company owns and operates producing properties located in six states
with proved reserves located primarily in Oklahoma and Texas. The Company
currently owns interests in 8 wells it operates and also owns non-operated
interests in approximately 30 producing wells in Oklahoma, Texas, Louisiana,
Arkansas and Kansas. Daily production from both operated and non-operated wells
net to the Company's interest averaged 3,852 Mcf per day and 25.41 Bbls of oil
per day for the year ended December 31, 1996 These properties provide the basis
for the Company's revenues to date.
8
<PAGE>
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 the first quarter of
1997 the Company participated in three dry holes in South Louisiana and one dry
hole in Mobile Bay representing approximately $907,000 in drilling costs net to
the Company of which approximately $168,000 was incurred and expensed as of
December 31, 1996. Only the Mobile Bay dry hole was on a 3-D seismic confirmed
location. The Company has three wells scheduled to be drilled in the second
quarter of 1997, two of which are 3-D seismic confirmed and one of which is a
high-potential exploratory well. In addition, drilling will be scheduled on the
Starboard Project in 1997.
Productive Well Summary
The following table sets forth certain information regarding the Company's
ownership as of December 31, 1996 of productive gas and oil wells in the areas
indicated.
Gas Oil
--------------- -------------
Gross Net Gross Net
----- ---- ----- ----
Oklahoma 13 2.08 6 .78
Texas 1 0.07 11 3.54
Louisiana 2 0.79 0 0
Alabama 2 0.44 0 0
Arkansas 2 0.15 0 0
Kansas 1 0.10 0 0
- ---- - ----
Total 21 3.63 17 4.32
== ==== == ====
Volumes, Prices and Production Costs
The following table sets forth certain information regarding the production
volumes, average prices received and average production costs associated with
the Company's sale of gas and oil for the periods indicated.
Year Ended December 31,
-----------------------------
1996 1995
---------- -----------
Net Production:
Oil (Bbl) 9,276 23,244
Gas (Mcf) 1,406,016 1,146,696
Gas equivalent (Mcfe) 1,461,672 1,286,160
Average sales price:
Oil ($ per Bbl) $ 20.99 $ 17.36
Gas ($ per Mcf) $ 2.18 $ 1.58
Average production expenses
and taxes ($ per Mcfe) $ .78 $ .84
Leasehold Acreage
The following table sets forth as of December 31, 1996, 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.
9
<PAGE>
Proved Developed Proved Undeveloped
State Gross Net Gross Net
Oklahoma 38,606 14,091 1,370 452
Texas 10,742 1,998 54 54
Alabama - Onshore 2,730 2,582 3,362 1,101
Alabama - Offshore 2,425 2,295 2,348 704
Arkansas 1,672 357 6,360 2,544
Louisiana 1,474 449 4,075 3,397
Kansas 1,600 126 0 0
------ ------ ------ -----
Total 59,249 21,898 17,569 8,252
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 local 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, and has 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
The Company is party to a lawsuit filed in 1994 in the Circuit Court of
Mobile, Alabama. Said lawsuit was brought by Frontier Exploration and Production
Corporation ("Frontier") a subsidiary of the Company, as plaintiff to quiet
title to leases it owns in the Mobile Bay area in Mobile County, Alabama. The
original defendant, The Offshore Group, Inc. ("TOG"), filed various
counterclaims pursuant to which, inter alia, it (i) claimed an ownership
interest in the Mobile Bay area wells drilled by the Company and (ii) sought
recovery of substantial damages it claimed to have sustained due to, among other
stated reasons, delays in drilling allegedly caused by the Company. The well for
which TOG alleged it sustained damages was a dry hole. TOG has dismissed its
claims in this regard with prejudice. The Company has been awarded summary
judgment as to all remaining counterclaims of TOG with respect to the Mobile Bay
area wells, and the Company has sued TOG and certain of its principals for
fraudulently asserting such claims. On June 6, 1996, the summary judgment was
appealed. The Company does not believe TOG's appeal will succeed.
In addition to the above, the Company is a defendant from time to time in
lawsuits incidental to its business. The Company believes that none of such
current proceedings, individually or in the aggregate, will have a materially
adverse effect on the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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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. At February 28, 1997, the Company
estimates there are approximately 68 common shareholders of record and 1,709
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. The Company has undeclared and unpaid dividends in the amount of
$128,941 on its convertible preferred stock for the period from May 1, 1995 to
June 30, 1996. 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. The Company has since
declared and paid dividends on the convertible preferred stock for the quarters
ended September 30, 1996 and December 31, 1996.
<TABLE>
<CAPTION>
Convertible Series A Series B
Common Preferred Warrants Warrants
Quarter Ended High Low High Low High Low High Low
- ------------- -------- -------- ------- ------ ------- ------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
December 31, 1996 $2 15/16 $ 2 $10 1/4 $ 8 $ 11/32 $ 1/16 $1 3/8 $9/16
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 - -
March 31, 1996 2 11/16 1 27/64 7 1/4 7 1/4 15/32 1/8 - -
December 31, 1995 2 7/8 9 6 3/4 3/16 1/16 - -
September 30, 1995 2 3/32 1 3/4 10 9 5/16 5/32 - -
June 30, 1995 3 3/4 1 7/8 10 1/4 7 7/8 3/4 1/4 - -
March 31, 1995 4 7/8 3 1/4 12 8 3/4 1 1/4 13/16 - -
</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, 1996 and 1995 and
should be read in conjunction with its consolidated financial statements and
notes related thereto. Certain statements contained herein that set forth
management's intentions, plans, beliefs, expectations or predictions of the
future 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 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
The Company's exploration activities for 1996 continued to center
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<PAGE>
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 acquisition and financing of the Starboard Prospect. The
Company moved its headquarters to Houston, Texas, in September, 1996, to allow
the Company to more effectively exploit opportunities in these primary areas of
exploration.
During 1996, the Company raised funds through a bank financing agreement,
issued stock in a public offering, sold producing properties which no longer fit
the Company's business plan, and obtained partners for its exploration
activities.
The Company has what it considers to be an aggressive drilling program for
1997 with over $3.7 million in planned drilling activities along the Gulf Coast
Region. This includes a 15,000 foot test on the Company's Schooner Prospect in
Plaquemines Parish, Louisiana, a Company operated well in which it owns a 37%
working interest as well as two shallower tests (7,500 feet and 10,500 feet) on
3-D seismic confirmed prospects in Terrebonne Parish, Louisiana. All three of
these wells are expected to be drilled in the second quarter. This is
anticipated to be followed by drilling on the Starboard Project in which the 3-D
seismic data acquisition is complete. The Starboard Project is 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 said project ranging from 12% to 48% depending upon
the target formation depths. The 3-D seismic has been shot and processed and
interpretation is under way. The project includes developmental and exploratory
locations which will likely be modified after 3-D seismic interpretation is
complete. Initial drilling sites are anticipated to be identified in the second
quarter of 1997 and developmental and exploratory drilling commenced late in the
second or early in the third quarter of 1997.
In the first quarter of 1997, the Company participated in three dry holes
and one unsuccessful recompletion attempt on South Louisiana prospects, none of
which was confirmed by 3-D seismic. Approximate cost to the Company totaled
$907,000. It also participated in a dry hole in Mobile Bay on a high risk, high
potential Oligocene feature in which its cost, net to the Company, was
approximately $214,000. With the exception of the Mobile Bay well, the Company
has not yet drilled any of its high potential prospects which include its
Schooner Prospect and the exploratory targets in the Starboard Project.
Comparison of 1996 to 1995
Revenue. Total Revenues decreased 27% from $4,654,474 for the year ended
December 31, 1995, to $3,378,792 for the year ended December 31, 1996.
Total gas and oil revenues increased 18.7% from $2,676,847 to $3,176,861.
The increase in gas and oil revenues were primarily attributable to increased
production from the Mobile Bay wells which came on stream in December of 1995
and a 40% increase in average gas sales prices ($2.18 in 1996 vs. $1.58 in
1995). Total gas and oil revenues (net of production taxes and transportation
expenses) from Mobile Bay were $1,337,018 in 1996 as compared to $35,718 in
1995. The increase in gas and oil revenues from Mobile Bay and from higher
prices was partially offset by decreases in production attributable to the sale
of properties in the Mid-Continent Area.
Offsetting the increase in gas and oil revenues during 1996 were decreases
in revenues from operating fees, gains on sales of assets and the sale of
seismic data, all of which relate directly or indirectly to the divestiture of
the Company's operations in the Mid-Continent Area, as well as a loss on
commodity transactions. During 1995, the Company realized revenues of $601,100
from the sale of seismic data from its library covering prospects in Garvin
County, Oklahoma. The cost of such seismic data had previously been expensed in
1994 under the successful efforts method of accounting. No similar revenues were
recognized in 1996. The sale of substantially all of the Company's gas and oil
properties in Oklahoma, including the N.E. Cedardale field in Major County,
Oklahoma, which was sold in 1996, resulted in gains to the Company of $722,004
in 1995 and $250,437 in 1996. As a result of a sale of a substantial portion of
the Company's properties, operating fees to the Company decreased from $415,925
in 1995 to $213,834 in 1996. Finally, the Company realized losses from various
commodity transactions totaling $602,029 in 1996 as compared to $3,350, in 1995.
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<PAGE>
Such losses for 1996 were attributable to various transactions in which the
Company hedged its future gas delivery obligations. In addition to the
foregoing, the Company had other revenues of $339,689 in 1996 as compared to
$241,948 in 1995.
Costs and Expenses. Total costs and expenses of the Company increased 34%
from $6,249,952 in 1995 to $8,403,811 in 1996. The increase in costs and
expenses was primarily attributable to a combination of increases in depletion,
interest expense, exploration costs, transportation and gathering costs, and
settlements of futures and gas delivery contracts. Partially offsetting the
foregoing increases in expenses were decreases in lease operating expenses,
production taxes and general and administrative expenses.
Depletion, Depreciation, and Amortization Expense ("DD&A") increased by
93.5% from $1,182,998 in 1995 to $2,288,648 in 1996. The increase in DD&A was
primarily attributable to depletion recorded on the Company's Mobile Bay
properties ($832,642) and the write-down of the reserves of the Mobile Bay
properties ($930,502) during the fourth quarter of 1996 following significant
production declines experienced in the fourth quarter. The increase in DD&A
attributable to the Mobile Bay properties was partially offset by decreases in
DD&A from Mid-Continent properties which were disposed of during 1995 and 1996.
Interest expense increased to $783,872 in 1996 from $43,000 in 1995. The
increase in interest expense was attributable to the receipt of financing from
Bank of America in the amount of $4 million in January of 1996 and includes
$500,000 of financing costs which were classified as interest expense. Due to
the early repayment of the borrowing, the Company has reduced debt issuance
costs by $293,000 and discount on notes payable by $207,000 in accordance with
the interest method. Said non-cash amounts have been expensed as additional
interest expense. Such financing was utilized to pay certain amounts in
connection with the termination of a Gas Sales Agreement as well as certain
other obligations of the Company. The loan was substantially repaid in September
1996 from the proceeds of the sale from the N.E. Cedardale properties.
Exploration costs increased 19.2% from $1,105,214 in 1995 to $1,317,161 in
1996. The exploration costs in 1996 reflect $927,273 of charges attributable to
the impairment of oil and gas leases and expensed investments, $295,454 of dry
hole costs and $43,071 of expensed seismic costs. Included in 1996 dry hole
costs are $158,833 of leasehold and acquisition costs associated with the first
quarter 1997 drilling activity.
Transportation and gathering costs increased from $38,394 in 1995 to
$368,716 in 1996. The increase in transportation and gathering costs was
attributable to the commencement of production of the Mobile Bay wells and
payments pursuant to related transportation contracts. With the substantial drop
in production from the Mobile Bay wells, transportation costs in connection with
those wells are expected to decline substantially during 1997.
Cost of settling gas contracts and futures contracts attributable to
the settlement of a gas sales contract with Waldorf Corporation ($368,960) 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),
net of reductions in gas purchases to fulfill the Waldorf contract ($467,339),
totaled $113,621 in 1996. The Company incurred no similar costs in 1995.
Lease operating expense decreased 32.4% from $824,181 in 1995 to $556,925
in 1996. The reduction in lease operating costs was attributable to the sale of
operated properties, including the N.E. Cedardale field, and a decline in rework
activity.
Production taxes declined 3.1% from $214,664 in 1995 to $207,969 in 1996
due to the sale of the N.E. Cedardale properties which was partially offset by
increased production in Mobile Bay during the first half of 1996.
General administrative expenses ("G&A") decreased by 3.3% from $2,291,701
in 1995 to $2,217,099 in 1996.
13
<PAGE>
Net Income (loss). The net loss increased from $1,595,478 to $5,025,019 for
the year ended December 31, 1995, and December 31, 1996, respectively. This
increase was due to the factors discussed above.
The net loss per common share decreased from a net loss of $1.05 per share
in 1995 to a net loss of $0.72 per share in 1996. This is reflective of the
secondary offering that was finalized on August 14, 1996, resulting in
approximately 7,142,000 weighted average common equivalent shares at December
31, 1996 as compared to approximately 3,977,000 weighted average common
equivalent shares at December 31, 1995.
Known and Anticipated Trends, Contingencies and Developments Impacting Future
Operating Results.
As noted elsewhere, the Company's future operating results will be
substantially dependent upon the success of the Company's efforts to develop the
Starboard Project and other prospects in South Louisiana. 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 will be substantially reduced during 1997 and 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 anticipates that
revenues from Mobile Bay will be 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 expects that its revenues during 1997 will be sharply
reduced unless and until the Company's South Louisiana prospects begin to
produce revenue. While management believes that the Starboard Project and other
prospects in South Louisiana represent the most promising prospects in the
Company's history, none of those prospects are currently producing revenue to
the Company. The Company expects to drill exploratory and developmental wells on
a number of prospects during the second and third quarters of 1997. If the
Company's drilling activities do not produce the anticipated levels of reserves
and production or if the Company experiences delays in drilling and completing
such wells, the Company's anticipated revenues would be materially adversely
impacted in 1997 and possibly in future periods. Accordingly, the Company is
substantially dependent upon the outcome of its planned drilling efforts during
1997.
Liquidity and Capital Resources
The Company, largely through four major financing transactions, increased
its cash position from $64,000 at December 31, 1995, to $4,956,000 at December
31, 1996, and increased its working capital by approximately $6,867,000 as of
December 31, 1996. The four financing transactions included a credit facility
with Bank of America, in January 1996, a project financing in March 1996 related
to the Starboard Project, a secondary offering of common stock effective in
August of 1996, and the sale of the Company's N.E. Cedardale properties in Major
County, Oklahoma, to OXY USA, Inc. in September of 1996.
During January 1996, the Company entered into a $15,000,000 credit
agreement with the Bank of America, to provide $4,000,000 in immediate cash to
the Company. The loan was reduced by $3,316,112 in September 1996 with proceeds
of the N.E. Cedardale property sale and totaled $455,956 at December 31, 1996.
This loan is collateralized by the most significant proved developed gas and oil
properties of the Company and is payable in monthly installments through
December 1998. The Company has entered into an interest rate swap guaranteeing a
fixed interest rate of 8.28% on the loan.
The bank credit facility provides for an additional $2,500,000, subject to
bank prospect approval, to be used for the Company's share of developmental
drilling costs in the Starboard Project, a developmental and exploratory
drilling project in Terrebonne Parish, Louisiana. This portion of the facility
is set to expire June 30, 1997, however the bank has indicated it is prepared to
extend this commitment. An additional $8,500,000 will be available contingent
upon the Company's reserve base meeting the bank's lending parameters. Under the
terms of the loan, the Company is subject to certain restrictions and covenants
which escalate in 1997. The covenants include current ratio, cash on hand and
tangible net worth requirements among other requirements. Because of the
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<PAGE>
disposal of substantially all of the Company's operating properties, management
does not believe that the Company will be able to comply with the cash flow
covenants of the loan during 1997. The Company obtained a waiver of the covenant
through March 31, 1997, and has requested an additional waiver of such covenant.
Bank financing costs of $293,000 associated with the facility were expensed in
the third quarter of 1996, as a result of early paydown of the loan.
The second financing transaction occurred in March 1996 when the Company
entered into an agreement whereby it conveyed a 48% working interest in the
Company's working interest in the Starboard Project. The acquirer provided
funding through a non-recourse loan to the Company to cover all the costs in
obtaining the leasehold and seismic data on the Starboard Project. The loan was
originally anticipated to be approximately $1,728,000 at its conclusion and it
will be repaid solely by the assignment of an 8% overriding royalty interest in
the Starboard Project payable from the Company's interest in the project until
such time as the lender has received an amount equal to the loan plus closing
costs and a 15% internal rate of return. The loan is secured by a mortgage on
the Starboard Prospect. The Company received a reimbursement of costs of
approximately $255,000 from the third party and a $240,000 prospect fee as part
of the agreement. Approximately $682,000 was advanced on the non-recourse loan
as of December 31, 1996.
In August 1996, the Company closed a joint exploration agreement with Fina
Oil and Chemical Company and certain of its partners wherein Fina etal paid 100%
of the 3-D seismic costs related to the Starboard Project in return for certain
deep acreage rights, which deep rights had a limited affect on the Company's
primary exploration objectives in this project. The agreement preserves 100% of
Frontier's interest in proven undeveloped reserves while expanding its potential
exploratory drilling opportunities in terms of both number of potential wells
and net exploratory reserve potential. The new agreement includes all of
Frontier's prior industry partners in the Starboard Project, as well as Fina and
certain of its industry partners. The 3-D seismic has been shot and processed
and interpretation is underway with initial drill sites expected to be
determined by mid-May 1997. In conjunction with said Fina agreement, the total
loan amount for borrowing pursuant to the second financing discussed above was
reduced from $1,728,000 to $864,000. Expenditures in excess of the remaining
funds under the second financing are anticipated to be incurred.
The third financing occurred when, 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 overallotment of 202,500 Units.
Each unit consisted of three shares of Common Stock and three Series B
Redeemable Stock Purchase Warrants. The net proceeds after the underwriter's
commission and expense were approximately $6,431,000.
On September 27, 1996, the Company completed the fourth financial
transaction which was the sale of its N.E. Cedardale field located in Major
County, Oklahoma to OXY USA Inc., for consideration totaling $3,550,000. The
properties sold represent a substantial portion of Frontier's Oklahoma
production. The sale was pursued for three basic reasons. The first was an offer
management deemed as favorable; second, the divestiture of the Oklahoma
properties further facilitated the Company's focus of its resources on its Gulf
Coast projects, and finally, the result was a reduction in debt service
requirements over the next three years in an amount greater than the anticipated
net revenues from the properties sold. The sale to OXY USA, Inc. included cash
of $2,840,000 and certain exchange properties which were concurrently sold to a
third party for $710,000, netting the Company $3,550,000. The sale was effective
September 1, 1996, and the Company incurred a non-cash loss of $10,523. In
connection with the sale, the Company also incurred a loss of $212,000 due to a
reduction in the quantities covered by a gas swap contract. Due to the early
repayment of the borrowing, the Company also reduced debt issuance costs by
$293,000 and discount on notes payable by $207,000 and recorded these non-cash
amounts as interest expense.
As of December 31, 1996, the Company had $4,956,000 in cash and cash
equivalents. The Company's 1997 business plan included early 1997 drilling on
three prospects which were not confirmed with 3-D seismic and one recompletion
prospect, all of which were originated by third parties and pursued by the
Company in a project intended to increase its oil and gas revenues. The projects
were not successful. The Company's revenues were also adversely impacted due to
the previously unanticipated early declines in its Mobile Bay production in the
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<PAGE>
fourth quarter of 1996. As a result of the foregoing the Company continues to
incur significant cash flow deficits. In the event its second quarter drilling
is not successful it may not have sufficient funds for its share of third and
fourth quarter 1997 drilling costs. Alternative courses of action include
reducing its ownership through reduced activity, or the sale of promoted working
interests, or increases in equity capital. In that drilling costs are, to a
large extent, discretionary items, reductions in expenditures, if necessary, can
be made but this will reduce the Company's share of potential revenue from
successful wells. The Company does not believe such actions are necessary at
this time.
The Company's business philosophy has been to seek to minimize natural gas
price volatility by marketing reserves through the use of long-term end-user gas
contracts and utilizing the purchase of short-term commodity futures. The
Company currently has in effect a gas swap agreement initially incurred as a
requirement of the Bank of America, Illinois, financing. As of December 31,
1996, spot market prices exceeded the swap price. The Company is considering
reducing the volumes under the swap agreement.
In addition to its obligations discussed above, the Company had accrued but
undeclared and unpaid dividends with respect to its outstanding cumulative
convertible preferred stock totaling $128,941 (or $1.50 per share) at December
31, 1996. The cumulative convertible preferred stock is entitled to cumulative
cash dividends at a maximum annual rate of $1.20 per share when and if declared
by the Board of Directors. The cumulative preferred stock is subject to
redemption at $10.00 per share, plus any accrued and unpaid dividends, and is
convertible into two shares of common stock and two Series A Warrants, subject
to adjustment, at the option of the holder or automatically in the event the
sales price of the cumulative preferred stock exceeds $13.00 per share for ten
consecutive trading days. A total of 85,961 shares of cumulative preferred stock
were outstanding at December 31, 1996. Although the Company is not required to
declare and pay such dividends, such dividends are cumulative and no dividends
may be paid on the Company's common stock until such dividends are paid.
Further, in the event that unpaid cumulative dividends aggregate an amount equal
to at least six quarterly dividends (or $1.80), the number of directors will be
increased by two and the holders of the cumulative preferred stock will be
entitled to elect the additional directors. The Company has paid all current
quarterly dividends since September 30, 1996.
Other than funding committed to the Company, as described above, funds
provided by future oil and gas operations and the potential receipt of funds
from the exercise of outstanding warrants, the Company presently has no sources
of financing or commitments to provide financing. A total of 1,578,078 Series A
Warrants issued in connection with the Company's initial public offering and
conversion of shares of cumulative preferred stock, 4,657,500 Series B Warrants
issued in connection with the Company's 1996 public offering and 855,000
warrants issued in connection with various financing and other transactions were
outstanding and exercisable at December 31, 1996. Such warrants are exercisable
at prices ranging from $1.47 to $6.00 per share and expire between November 12,
1998 and August 8, 2001 subject to various redemption provisions. The exercise
of all outstanding warrants would result in the receipt by the Company of gross
proceeds of approximately $21.3 million and the issuance of 7,090,578 shares of
common stock. There can be no assurance, however, when, if ever, any or all of
the outstanding warrants will be exercised.
Other than funding its day-to-day operating costs and its proposed drilling
operations, the Company does not anticipate any substantial demands on the
liquidity or capital resources of the Company during the following twelve months
except as otherwise discussed above.
As stated, the Company does not currently believe, pending the results of
its second quarter drilling, that it will need additional funds beyond its
capital and credit lines over the next twelve months. However, in the event
second quarter drilling is unsuccessful, or it develops currently unknown
prospects and/or acquisition opportunities, it may seek additional exploration
and/or acquisition capital. Options available to the Company to raise any
additional funds for exploration and/or acquisitions include, but are not
limited to, (a) additional outside partners, (b) additional private borrowing,
(c) the further sale of 3-D seismic data and (d) the exercise of the Company's
currently outstanding warrants should the Company's stock prices rise by August
of 1997 to levels necessary to allow said warrants to be called.
16
<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, 1996 and
1995, and the related consolidated statements of income, 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, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
years then ended, in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
- ---------------------------
Deloitte & Touche LLP
Oklahoma City, Oklahoma
March 31, 1997
17
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31, December 31,
1996 1995
---------- ------------
<S> <C> <C>
Current Assets:
Cash and cash equivalents $4,956,656 $ 63,908
Accounts receivable, net of
allowance for doubtful
accounts of $10,533 at
December 31, 1996 and
$12,710 at December 31, 1995 366,498 612,876
Prepaid expenses and other 282,317 178,737
Receivables from affiliates 152,419 210,016
---------- -----------
Total current assets 5,757,890 1,065,537
Property and equipment:
Gas and oil properties, at
cost-successful efforts
method of accounting 5,280,115 11,109,678
Other property and equipment 1,074,727 906,453
---------- -----------
6,354,842 12,016,131
Less accumulated depletion,
depreciation and amortization (2,918,918) (2,895,159)
---------- -----------
3,435,924 9,120,972
Other Assets 437,378 252,966
---------- -----------
Total assets $9,631,192 $10,439,475
========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
18
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
December 31, December 31,
1996 1995
----------- -----------
<S> <C> <C>
Current liabilities:
Accounts payable $ 725,222 $ 2,065,341
Revenue distribution payable 360,163 493,072
Current portion of long-term debt 304,540 227,302
Deferred gas revenues - 828,000
Accrued and other liabilities 271,805 222,778
----------- -----------
Total current liabilities 1,661,730 3,836,493
Deferred gas revenues - 1,113,977
Long-term debt 325,394 150,271
Non-recourse debt 681,618 -
Other long-term liabilities 223,624 275,298
----------- -----------
Total liabilities 2,892,366 5,376,039
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, 1996 and 1995;
($856,910 aggregate liquidation
preference at December 31, 1996
and 1995) 860 860
Common stock:
Class A Common stock, $.01 par
value; 20,000,000 shares
authorized; 9,865,906 and
5,058,406 outstanding at
December 31, 1996 and
December 31, 1995, respectively 98,659 50,584
Unamortized value of warrants issued (54,325) -
Common stock subscribed 45,000 45,000
Common stock subscription receivable (45,000) (45,000)
Additional paid-in capital 14,599,326 7,866,879
Deficit (7,905,694) (2,854,887)
----------- -----------
Total stockholders' equity 6,738,826 5,063,436
----------- -----------
Total liabilities and
stockholders' equity $ 9,631,192 $10,439,475
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
19
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995
---------- -----------
<S> <C> <C>
Revenues:
Gas and oil revenues $ 3,176,861 $ 2,676,847
Gain (loss) on commodity transactions (602,029) (3,350)
Gain on sale of assets 250,437 722,004
Sale of seismic data - 601,100
Operating fees 213,834 415,925
Other revenues 339,689 241,948
------------ -----------
Total revenues 3,378,792 4,654,474
------------ -----------
Costs and expenses:
Lease operating expense 556,925 824,181
Production taxes 207,969 214,664
Transportation and gathering costs 368,716 38,394
Gas purchases under deferred contract 82,461 549,800
Depletion, depreciation and amortization 2,288,648 1,182,998
Exploration costs 1,317,161 1,105,214
Interest expense 783,872 43,000
Deferred gas contract settlement 368,960 -
Loss on settlement of futures contract 212,000 -
General and administrative expense 2,217,099 2,291,701
----------- -----------
Total costs and expenses 8,403,811 6,249,952
----------- -----------
Income (loss) before provision for
income taxes (5,025,019) (1,595,478)
Benefit (provision) for income taxes - -
----------- -----------
Net income (loss) (5,025,019) (1,595,478)
Cumulative preferred stock dividend 103,153 395,381
Value of common stock issued for
cumulative preferred stock in
excess of original terms, net of
relieved preferred stock dividend - 2,183,471
=========== ===========
Net income (loss) applicable to
common stockholders $(5,128,172) $(4,174,330)
=========== ===========
Net income (loss) per common and
common equivalent share $ (0.72) $ (1.05)
----------- -----------
Weighted average number of common
equivalent shares (in thousands) 7,142 3,977
=========== ===========
</TABLE>
The accompanying notes are an intergral part of these financial statements.
20
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Unauthorized
Preferred Class A Value of Additional
Stock Common Shares Warrants Paid-in
------------------- --------------------
Shares Amount Shares Amount Issued Capital Deficit
-------- ------- --------- -------- -------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1994 694,400 $ 6,944 2,418,050 $24,181 - $ 7,548,605 $(1,025,301)
Issuance of common stock - - 95,000 949 - 135,144 -
Issuance of subscribed
common stock - - 120,600 1,206 - 201,294 -
Conversion of preferred stock (608,439) (6,084) 2,424,756 24,248 - (18,164) -
Cumulative preferred
stock dividend - - - - - - (234,108)
Net loss - - - - - - (1,595,478)
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)
</TABLE>
The accompanying notes are an integral part of these financial statements.
21
<PAGE>
FRONTIER NATURAL GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------
1996 1995
----------- -----------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) $(5,025,019) $(1,595,478)
Adjustments to reconcile net loss
to net cash provided by operating
activities:
Depletion, depreciation and amortization 2,288,648 1,182,998
Deferred gas contract settlement 368,960 -
Gain on sale of assets (250,437) (722,004)
Deferred revenues under gas contract (74,400) (846,450)
Amortization of financing costs 710,573 -
Non-cash compensation expense
attributable to SAR's - (107,509)
Stock issued for settlement of
litigation - 96,093
Exploration costs 1,317,161 1,105,214
Changes in operating assets and
liabilities:
Accounts receivable 303,975 276,083
Prepaid expenses and other (103,580) 39,595
Other assets (191,791) (171,833)
Accounts payable (279,119) 278,155
Revenue distribution payable (132,909) 97,001
Accrued and other (2,647) 141,522
----------- -----------
Net cash (used) in operating activities (1,070,585) (226,613)
----------- -----------
Cash flows used in investing activities:
Capital expenditures - gas and oil properties (3,515,841) (2,387,383)
Capital expenditures - other property
and equipment (203,808) (131,775)
Proceeds from sale of assets 4,671,088 2,171,365
----------- -----------
Net cash provided by (used in)
investing activities 951,439 (347,793)
----------- -----------
Cash flows from financing activities:
Proceeds from issuance of debt 4,717,280 442,001
Repayments of long-term debt (3,745,369) (287,795)
Debt issuance cost (183,387) -
Payment for settlement of deferred
gas contract (2,181,489) -
Redemption of preferred stock of a subsidiary - (99,540)
Preferred stock dividends paid (25,788) (234,108)
Net proceeds from issuance of common stock 6,430,647 202,500
----------- -----------
Net cash provided by financing activities 5,011,894 23,058
----------- -----------
Net increase (decrease) in cash and
cash equivalents 4,892,748 (551,348)
Cash and cash equivalents at beginning of year 63,908 615,256
----------- -----------
Cash and cash equivalents at end of year $ 4,956,656 $ 63,908
=========== ===========
Supplemental disclosure of cash
flow information:
Cash paid for interest $ 818,769 $ 72,679
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
22
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
$51,000 and $109,000 in 1996 and 1995, respectively, in impairment of gas and
oil properties.
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 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,
1996 and 1995 was approximately $107,000 and $129,000, respectively.
23
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1996, the Company's gas
balancing position was approximately 31,500 MCF overproduced.
Exploration Costs - The Company expenses exploratory dry hole costs,
geological and geophysical costs, and impairment of unproved properties. During
1996 and 1995, $43,000 and $390,000 respectively of such costs represented
geological and geophysical costs expensed as required under the successful
efforts method of accounting.
Earnings (Loss) per share - Primary average shares are computed on the
basis of weighted average shares of common stock outstanding and, when dilutive,
common stock equivalent shares attributable to outstanding stock options, stock
subscriptions and warrants. Common stock equivalent shares are computed using
the treasury stock method. The computation of fully diluted loss per share was
antidilutive; therefore the amounts of primary and fully diluted earnings (loss)
are the same.
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 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 since 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.
New Accounting Standards - 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. These statements are effective for financial
statements for periods ending after December 15, 1997. The Company has not
determined if adoption of these standards will have a significant effect on its
consolidated financial statements.
Reclassification - Certain reclassifications have been made to the 1995
financial statements to conform them to the classification used in 1996.
24
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. 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 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 $ .10). During 1995, the Company offered to exchange one share of
cumulative convertible preferred stock plus all unpaid and accrued preferred
dividends for four shares of common stock and two 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
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, 1996 and 1995, 85,961 shares of cumulative convertible preferred
stock were outstanding.
During 1995, the Company issued 120,600 shares of common stock for $202,500
pursuant to stock subscription agreements entered into in a private placement
transaction in March 1993.
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
overallotment of 202,500 Units. Each Unit consisted of three shares of Common
Stock and three Series B Redeemable Common Stock Purchase Warrants ("Series B
Warrants"). The price for each Unit was $5.0625. The net proceeds after the
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, 1996 and 1995. 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
1996 and 1995, $25,788 and $234,108 was declared and paid in cumulative
preferred stock dividends. The Company has undeclared and unpaid dividends in
the amount of $128,941 ($1.50 per share) on its cumulative preferred stock for
the period from May 1, 1995 to June 30, 1996. The Company has paid all current
quarterly dividends since September 30, 1996. 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.
25
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 1996 no shares of
cumulative convertible preferred stock were converted to common stock under the
original conversion terms and 4,500 shares of cumulative convertible preferred
stock were converted to common stock during 1995 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 shares of common stock and two 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 share of common stock at a price equal to $6.00,
until five years from the effective date of the initial public offering.
Outstanding Series A Warrants may be redeemed by the Company for $.25 each on 30
days notice. As of December 31, 1996 and 1995, 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 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.
26
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATMENTS
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 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 $54,325 at December 31, 1996.
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.
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 reserved for issuance thereunder.
Each option grants the holder the right to purchase one share of Common
Stock at the exercise price which will be at least equal to the fair market
value of the Common Stock on the date of grant. Any terminated or expired
options will be available for future grant.
The Board shall determine and designate from time to time the employees of
the Company to whom options are to be granted and who thereby become
participants in the Plan. Options granted to officers and other key employees
are vested over a three year period with one-third of the option exercisable on
or after each of the three succeeding anniversary dates of the granting of the
option. The options are exercisable for a period of ten years from the date of
the grant. The Board may at its discretion set forth such other vesting and
exercise periods as it may from time to time establish. Options granted to
directors who are not full-time employees are determined initially by the Board
and automatically granted annually. The directors who were not full-time
employees were granted an aggregate of 12,000 options in 1996.
Initially three officers were granted options under the plan to purchase a
total of 305,000 shares of common stock and one key employee was granted the
option under the plan to purchase a total of 20,000 shares of common stock. The
exercise price is $1.47 for all options except for 120,000 options that were
granted to one officer whose option price is 110% plus $.01 of said $1.47 fair
market value.
During 1996, 20,000 options expired three months after an employee left the
company. On May 15, 1996, the Board of Directors granted 25,000 options to an
officer at an exercise price of $2.125 which equaled the fair market value of
the Common Stock on the date of grant.
Management Incentive Stock Plan - The plan provides for the granting of
Units to officers and other key employees and for the automatic granting of
Units to directors who are not full-time employees. Each Unit consists of (1) an
option to purchase one share of common stock at the exercise price (as defined
27
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
below) and (2) a cash payment ("Stock Appreciation Right" or "SAR") to be made
by the Company when the option is exercised. Said SAR shall be 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. The exercise price for Units
issued prior to the effective date of the initial public offering of common
stock of the Company was the average bid price per share of common stock for the
thirty day period immediately following the effective date (November 12, 1993)
of said initial public offering which was $3.10. The exercise price for Units
granted following the effective date of the initial public offering will be the
fair market value of the common stock on the grant date. Payment for shares
purchased may be made, at the option of the purchaser, in cash or in shares of
common stock (valued at their then fair market value). The "fair market value"
of common stock will be defined by the plan by reference to the market price of
the common stock.
The total number of Units which may be granted under the plan was
originally 240,000 Units. During 1996 the Board of Directors canceled 120,000
Units available for grant under the plan. Units not granted in any year may be
granted in any future year. The number is subject to adjustment to reflect stock
splits, stock dividends, recapitalization and other corporate events which
affect outstanding shares of common stock. If any such event occurs while Units
are outstanding under the plan, similar adjustments will be made in the number
of shares and the exercise price per share covered by such options. The options
expire ten years from date of grant if not exercised.
Remaining Units outstanding at December 31, 1996 from prior years' grants
are as follows:
Grant Date Outstanding Units Exercise Price
- ----------------- ----------------- --------------
September 2, 1993 86,000 $3.10
January 20, 1994 18,000 $3.50
April 22, 1994 4,000 $2.09
June 6, 1995 4,000 $2.00
All options originally issued were vested as of January 31, 1996. All Units
issued subsequent to the initial grant shall be exercisable on the three
succeeding anniversaries of their grant dates. All outstanding Units will also
become exercisable during a limited period prior to the consummation of any
merger of the Company (if it is not the surviving corporation), a sale of
substantially all of the Company's assets or dissolution of the Company, but
will terminate on the consummation of any such transaction. In addition, all
Units will become exercisable if any party, together with its affiliates,
acquires ownership or control of the majority of the outstanding shares of
common stock of the Company.
All Units granted to outside directors are exercisable one year after the
date of the grant. Except for outside directors, a holder of Units will forfeit
all unexercised Units if, prior to exercise, he or she ceases to be an employee
of the Company for any reasons except death, retirement (including early
retirement) or disability. If employment terminates because of any of these
reasons, Units may be exercised during limited periods thereafter.
Incentive Stock Option Plan - The incentive stock option plan was approved
by the Company's stockholders on September 2, 1993, and 180,000 shares of common
stock are reserved for issuance thereunder. Options granted under the plan must
be equal to or greater than the fair market value of common stock on the date of
grant, and are exercisable during the period beginning one year from the date of
grant and expiring nine years from the date of grant. On February 2, 1993, the
Board of Directors of the Company granted one employee the option under the plan
to purchase 180,000 shares of common stock. The rights to purchase 156,000 of
said shares have vested, and the remaining 24,000 shares will vest in 1997. The
exercise price of this option is $1.679.
28
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The plan allowed for the granting of options to officers and other key
employees and for the automatic granting of options to directors who are not
full-time employees. Each option in the new plan consists of an option to
purchase one share of common stock at an exercise price equal to the last trade
on the day preceding the date the grant was authorized. Units not granted in any
year may be granted in any future year. The option expires ten years from the
date of grant if not exercised. All options except those issued to outside
directors will be exercisable equally on the three succeeding anniversaries of
their grant date. Options issued to outside directors will be exercisable twelve
months after the date of grant.
The following table summarizes activity under the Company's stock option
plans for the years ended December 31, 1996 and 1995.
<TABLE>
<CAPTION>
Incentive Management Stock Incentive
Stock Option Plan Incentive Stock Plan Option Plan - 1996
----------------- ------------------------ ------------------
1996 1995 1996 1995 1996
------- ------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C>
Shares available for grant 180,000 180,000 120,000 240,000 350,000
Shares under option at end
of period 180,000 180,000 112,000 120,000 342,000
Option price per share $1.679 $1.679 $2.00-3.50 $2.00-3.50 $1.47-2.125
Shares exercisable at end
of period 156,000 132,000 102,000 72,667 -
Shares exercised during
the period - - - - -
Shares canceled - - 120,000 - -
Weighted average option price $1.679 - $3.09 - $1.569
</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 1996 and 1995
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:
1996 1995
------------- ------------
Net loss applicable to common
stockholders - as reported $ (5,128,172) $ (4,174,330)
============= ============
Net loss applicable to common
stockholders - pro forma $ (5,296,335) $ (4,176,704)
============= ============
Net loss per common and common
equivalent share - as reported $ (0.72) $ (1.05)
============= ============
Net loss per common and common
equivalent share - pro forma $ (0.74) $ (1.05)
============= ============
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 5.84% and 5.36% in 1996 and 1995, respectively; and expected lives of five
(5) years.
Redeemable Preferred Stock of a Subsidiary - In 1991, Frontier, Inc., a
29
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
subsidiary of the Company, issued 563,700 shares of redeemable preferred stock
through private placements. During 1995 and 1994, the Company redeemed 142,200
and 421,500 shares for a price of $99,540 and $290,217, respectively.
3. SALE OF GAS AND OIL ASSETS AND SEISMIC DATA:
On June 7, 1995, the Company entered into an agreement to jointly explore a
33 square mile area in Garvin County, Oklahoma. Pursuant to the agreement, the
Company sold a 50% ownership interest in its 3-D seismic data which had
previously been expensed under the successful efforts method of accounting. The
Company recognized revenue of approximately $589,000 relating to the sale of
this 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 represent 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. In addition the
Company sold other properties in 11 and 18 different transactions during 1996
and 1995, respectively. These transactions resulted in an aggregate gain of
approximately $272,000 and $722,000 for 1996 and 1995, respectively.
4. 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% and 37% from
purchases on the open market for the years ended December 31, 1996 and 1995,
respectively as follows:
For Year Ended December 31,
------------------------------
1996 (MMBTU) 1995 (MMBTU)
------------ ------------
Gas purchased on open market 43,783 413,434
Gas delivered from Company reserves 55,417 715,166
------ ---------
Total deliveries 99,200 1,128,600
====== =========
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.
30
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. LONG-TERM DEBT:
Long-term debt consists of the following: December 31,
----------------------
1996 1995
---------- -------
Note payable pursuant to a credit agreement
with a bank of $493,888, interest at LIBOR
rate (reserve adjusted), plus one and
seven-eighths percent (1.875%) (7.25% at
December 31, 1996), payable in monthly
installments, due in various monthly amounts
through December, 1998, collateralized by
producing oil and gas properties; net
of discount of $37,931 $ 455,956 $ -
Non-recourse loan, payable out of an 8% ORRI
on the Starboard Prospect, interest imputed
at 15% 681,618 -
Note payable to bank, interest at a New York
prime plus 1% (9.75% at December 31, 1995),
principal due August 1, 1996 - 180,554
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 73,978 97,019
Note payable, interest at 12%, payable monthly,
principal due December 31, 1997 100,000 100,000
---------- --------
1,311,552 377,573
Less current portion 304,540 227,302
---------- --------
$1,007,012 $150,271
========== ========
Maturities of the non-current portion of long-term debt (excluding
non-recourse debt) are as follows:
Year At December 31,
1996
- ----- ---------------
1998 $301,807
1999 $ 17,093
2000 $ 6,494
2001 $ 0
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 will 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 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:
31
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Covenant, as defined
- --------------------
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
The Company does not believe it will be able to comply with the cash flow
covenant during 1997. The Company has obtained a waiver of the covenant through
March 31, 1997. Management believes that the Company will require an additional
waiver or waivers during 1997.
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% (.8%) on the unused portion of the commitment
amount. The unrealized loss on the interest rate swap agreement was $28,000 at
December 31, 1996.
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. During 1996, the Company received a $240,000 prospect fee, a
reimbursement of cost of $255,000 and an advance on the non-recourse loan of
$681,618. 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.
6. INCOME TAXES:
Deferred tax assets and liabilities are as follows:
At December 31,
---------------------------------
1996 1995
------------- ------------
Net operating tax loss carryforward $ 3,494,442 $ 1,589,676
Property and equipment (1,942,813) (1,010,789)
Employee Benefits 76,032 (66,500)
Valuation Allowance (1,627,661) (645,387)
------------ -----------
Net deferred tax asset (liability) $ - $ -
============ ===========
The Company has recorded a deferred tax valuation allowance since, based on
an assessment of all available historic evidence, it is more likely than not
that future taxable income will not be sufficient to realize the tax benefit.
The Company and its subsidiaries have estimated net operating loss carryforwards
("NOLs")at December 31, 1996, of approximately $7,280,000 which may be used to
offset future taxable income. The operating loss carryforwards expire in the tax
years 2006 through 2011.
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
32
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
7. RELATED PARTY TRANSACTIONS:
The Company made advances to officers and affiliates of the Company during
1996 and 1995 of $51,143 and $14,234, respectively, and received repayments of
$18,741 and $30,282, respectively. The December 31, 1996 and 1995 receivables
include approximately $48,000 and $138,000, respectively, 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 subsequently sold for a total aggregate sales price of approximately
$354,000 and the net amount realized by the Company was approximately $324,000.
8. COMMITMENTS AND CONTINGENCIES:
The Company leases office space under lease agreements which are classified
as operating leases. Lease expense under these agreements was $106,440 in 1996
and $106,656 in 1995. A summary of future minimum rentals on these
non-cancelable operating leases is as follows:
Year At December 31,
1996
- ----- ---------------
1997 $ 111,120
1998 $ 111,120
1999 $ 111,120
2000 $ 111,120
2001 $ 74,080
The Company has entered into employment agreements with certain employees.
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 employee). The agreements provide for salaries for each
person and in addition, each of said two employees shall be entitled to receive
deferred compensation, provided the employee remains employed with the Company
until expiration of the initial term of his agreement and that he has not been
terminated for cause thereunder. Such deferred compensation shall be an annual
payment equal to the product of $9,000 multiplied by the number of years the
employee is employed by the Company commencing July 1, 1993 (up to a maximum of
ten years, and payments commence the year the Employee reaches age 65 or retires
from the Company, whichever is later). Deferred payments shall be paid for a
maximum of 15 years thereafter. The liability for these payments is being
accrued over a ten year period commencing July 1, 1993.
The Company also has employment agreements with two other employees. Both
agreements expire on December 31, 1997 and automatically renew for successive
one-year terms unless terminated by either the Company or the employee. The
agreements provide for salaries as well as certain incentive compensation. All
agreements contain provisions prohibiting the disclosure to third parties of
proprietary information relating to the Company.
The Company has entered into an agreement with a director to serve as a
consultant to the Company. The consulting agreement provides for the director to
furnish exploration and production oversight services on the Company's existing
properties and prospects in the Mid-Continent Area and prospect generation and
evaluation services on the Company's existing 3-D seismic data over acreage in
the Mid-Continent Area, for a period of 23 months commencing on May 1, 1996 for
a monthly compensation of $10,000. This consulting agreement was entered into in
33
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
settlement of a previously existing employment agreement which would have been
more costly to the Company and for a longer period of time.
The Company is party to a lawsuit filed on June 14, 1994 in the Circuit
Court of Mobile, Alabama. This lawsuit was brought by Frontier Exploration and
Production Corporation ("Frontier") a subsidiary of the Company, as plaintiff to
quiet title to leases it owns in the Mobile Bay area in Mobile County, Alabama.
The original defendant, The Offshore Group, Inc. ("TOG"), filed various
counterclaims pursuant to which, inter alia, it (i) claimed an ownership
interest in the Mobile Bay area wells drilled by the Company and (ii) sought
recovery of substantial damages it claimed to have sustained due to, among other
stated reasons, delays in drilling allegedly caused by the Company. The well for
which TOG alleged it sustained damages was a dry hole. TOG has dismissed its
claims in this regard with prejudice. The Company has been awarded summary
judgment as to all remaining counterclaims of TOG with respect to the Mobile Bay
area wells, and the Company has sued TOG and certain of its principals for
fraudulently asserting such claims. On June 6, 1996, the summary judgment was
appealed. The Company does not believe TOG's appeal will succeed.
The Company is party to various other lawsuits arising in the normal course
of business. Management believes that the ultimate outcome of these matters will
not have a material effect on the Company's consolidated financial position or
results of operations.
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. The unrealized loss on the amended swap agreement was $312,000 at
December 31, 1996. The Company also entered into another natural gas swap
agreement on 45,000 MMBTU of natural gas per month at $2.03 per MMBTU for Mobile
Bay gas which expired on December 24, 1996.
9. 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.
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 proved reserves that are expected to be recovered from new wells on
undrilled acreage, or from existing wells where a relatively major expenditure
is required for recompletion.
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:
34
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:
Years ended December 31,
------------------------
1996 1995
---------- -----------
Acquisition of properties
Proved $1,305,219 $ 33,586
Unproved 644,323 908,812
Exploration costs 182,147 1,601,664
Development costs 313,152 944,321
---------- -----------
Total costs incurred $2,444,841 $ 3,488,383
========== ===========
CAPITALIZED COSTS: At December 31,
------------------------
1996 1995
---------- ----------
Proved and unproved properties being amortized $4,681,518 $9,641,369
Unproved properties not being amortized 598,596 1,468,308
Less accumulated amortization (2,277,984) (2,399,465)
---------- ----------
Net capitalized costs $3,002,130 $8,710,212
========== ==========
Costs incurred include $1,061,000 of amounts in accounts payable at December 31,
1995.
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:
The estimates of proved producing reserves were estimated by independent
petroleum engineers, Hofmann & Associates Engineering and Atwater Consultants,
Inc. Proved reserves cannot be measured exactly because the estimation of
reserves involves numerous judgmental and arbitrary determinations. 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 (Mcf) natural gas liquids (barrels)
Years ended December 31, Years ended December 31,
------------------------ -------------------------
1996 1995 1996 1995
----------- ---------- -------- --------
<S> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Beginning of period 18,564,141 9,885,882 279,501 359,604
Purchases of minerals-in-place 2,615,187 10,518,110 84,096 119,719
Sales of minerals-in-place (10,092,754) (866,892) (187,006 (174,165)
Revisions of previous estimates (791,059) (1,474,440) 8,534 (2,412)
Extensions, discoveries and
other additions 12,056 1,648,177 7,886 -
Production (1,406,016) (1,146,696) (9,276) (23,244)
----------- ---------- ------- -------
End of period 8,901,555 18,564,141 183,735 279,501
=========== ========== ======= =======
Proved developed reserves:
Beginning of period 7,307,717 7,792,814 72,515 254,107
=========== ========== ======= =======
End of period 985,524 7,307,717 46,420 72,515
=========== ========== ======= =======
</TABLE>
35
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 prices
used in determining future cash inflows for natural gas and oil for the periods
ended December 31, 1996 and 1995 were as follows: 1996 - $ 4.13 per MCF - Gas, $
24.42 per barrel - Oil; 1995 - $1.83 per MCF - Gas, $18.28 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.
The following table sets forth the Company's estimated standardized measure
of discounted future net cash flows:
Year ended December 31,
-----------------------------
1996 1995
----------- ------------
Future cash inflows $41,251,837 $ 45,403,797
Future development and production costs (8,288,416) (14,138,352)
----------- ------------
Future net cash flows before income taxes 32,963,421 31,265,445
Discount of future net cash flows at 10% 11,267,101 11,215,719
----------- ------------
Discounted future net cash flows before
income taxes 21,696,320 20,049,726
Future income taxes, net of discount at 10% 4,937,776 3,645,106
----------- ------------
Standardized measure of discounted future
net cash flows $16,758,544 $ 16,404,620
=========== ============
36
<PAGE>
FRONTIER NATURAL GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth changes in the standardized measure of
discounted future net cash flows:
Year ended December 31,
------------------------------
1996 1995
------------ ------------
Standardized measure of discounted
future cash flows - beginning of period $ 16,404,620 $ 9,015,439
Net changes in sales prices and
production costs 7,177,867 (352,359)
Sales of oil and gas produced, net of
operating expenses (1,977,577) (976,107)
Purchases of minerals-in-place 7,787,886 11,580,164
Sales of minerals-in-place (11,270,558) (2,254,822)
Revisions of previous quantity estimates (1,940,104) (1,461,688)
Extensions, discoveries and improved
recovery, less related costs 187,877 2,034,255
Previously estimated development costs
incurred during the year 115,440 -
Change in future development costs (17,400) (56,220)
Accretion of discount 2,004,973 1,050,983
Net change of income taxes (1,292,670) (2,150,712)
Other (421,810) (24,313)
------------ -----------
Standardized measure of discounted future
cash flows - end of period $ 16,758,544 $16,404,620
============ ===========
37
<PAGE>
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not Applicable.
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT
The information required by this item is hereby partially incorporated by
reference to the Company's proxy statement which will be filed with the
Commission within one hundred twenty (120) days of the close of the fiscal year
pursuant to regulation 14A. The balance of the information is as follows:
The following person is a key employee:
Michael A. Barnes, Vice President of Exploration and Production, joined the
Company on May 15, 1996. From March 1991 until his employment with the Company,
Mr. Barnes served as Exploration Manager - Gulf Coast for Great Western
Resources, Inc. Prior to that Mr. Barnes worked for Sandefer Oil & Gas, Inc. for
ten years where he served as Vice President of Exploration and Vice President of
Exploitation. Mr. Barnes has 30 years experience in the gas and oil industry
with emphasis in the Gulf Coast region. Mr. Barnes holds a Bachelor of Science
degree in Geology from the University of Texas.
ITEM 10. EXECUTIVE COMPENSATION
The information required by this item is hereby incorporated by reference
to the Company's proxy statement, which will be filed with the Commission within
one hundred twenty (120) days of the close of the fiscal year pursuant to
regulation 14A.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is hereby incorporated by reference
to the Company's proxy statement, which will be filed with the Commission within
one hundred twenty (120) days of the close of the fiscal year pursuant to
regulation 14A.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is hereby incorporated by reference
to the Company's proxy statement, which will be filed with the Commission within
one hundred twenty (120) days of the close of the fiscal year pursuant to
regulation 14A.
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
Exhibit Name of Exhibit
- ------- -----------------------------------------------------------------------
3(a) Certificate of Incorporation of the Company as currently in effect is
incorporated by reference to the Company's Registration Statement
33-69640-FW dated September 29, 1993 wherein same appeared as Exhibit
3.1.
3(b) By-Laws of the Company 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 3.2.
38
<PAGE>
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) 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(c) Employment Agreement by and between the Company and Jeffrey R. Orgill
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 10.3.
10(d) Frontier Natural Gas Corporation Stock Incentive 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 10.4.
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)* Consulting Agreement by and between the Company and Jeffrey R. Orgill
dated May 1, 1996.
10(g) Joint Venture Agreement between Polaris Energy Corporation and Frontier
Natural Gas Corporation dated May 10, 1995 as amended December 12, 1995
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(g).
10(h) 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(i) 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).
10(j) Maysville Project Agreement between Amoco Production Company and Aspect
Resources Limited Liability Company and Frontier Natural Gas
Corporation dated June 7, 1995 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(j).
10(k) Gulf Coast Seismic "Bright Spot" Joint Venture dated September 8, 1995
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(k).
10(l) $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
39
<PAGE>
reference to the Company's current report on Form 8-K dated January 9,
1996.
10(m)* $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(n) Gas Sales Agreement dated December 31, 1991, by and among the Company,
Centran Corporation and Waldorf Corporation is incorporated by
reference to the Company's Registration Statement 33-69640-FW dated
September 29, 1993 wherein the same appeared as Exhibit 10.14.
10(o) Exchange Agreement between OXY USA Inc. and Frontier, Inc. and Frontier
Acquisition Corporation entered into as of September 1, 1996, as
currently in effect and incorporated by reference to the Company's
current report on Form 8-K dated September 27, 1996.
10(p) 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(q) Sale Agreement between Frontier Acquisition Corporation and Special
Energy Corporation entered into as of September 27, 1996, as currently
in effect and incorporated by reference to the Company's current report
on Form 8-K dated September 27, 1996.
10(r) 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(s) 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(t) 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(u)* 3-D Seismic Participation Agreement dated May 30, 1996 by and between
Frontier Natural Gas Corporation and Fina Oil and Chemical Company.
11* Statement re: computation of per share earnings.
21* Subsidiaries of Registrant.
27* Financial Data Schedule.
(b) Reports on Form 8-K.
None
- ------------------------
* Filed herewith
40
<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.
FRONTIER NATURAL GAS CORPORATION
March 31, 1997 By: /s/ DAVID W. BERRY
--------------------------------------------
David W. Berry, Chairman of the
Board of Directors; President
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.
March 31, 1997 /s/ DAVID W. BERRY
--------------------------------------------
David W. Berry, Chief Executive Officer,
(Principal Executive Officer) and Director
March 31, 1997 /s/ DAVID B. CHRISTOFFERSON
--------------------------------------------
David B. Christofferson, Executive Vice
President, General Counsel, Chief Financial
Officer, (Principal Accounting and Financial
Officer) and Director
March 31, 1997 /s/ S. Gordon Reese, Jr.
--------------------------------------------
S. Gordon Reese, Jr., Senior Vice President
- Gulf Coast Region and Director
March 31, 1997 /s/ Jeffrey R. Orgill
--------------------------------------------
Jeffrey R. Orgill, Vice Chairman of the
Board of Directors
March 31, 1997 /s/ Allen H. Sweeney
--------------------------------------------
Allen H. Sweeney, Director
March 31, 1997 /s/ Neal M. Elliott
--------------------------------------------
Neal M. Elliott, Director
41
CONSULTING AGREEMENT
WHEREAS, Frontier Natural Gas Corporation ("Frontier") and Jeffrey R.
Orgill, an individual ("Consultant"),previously executed that certain employment
agreement dated effective the 1st day of January, 1993, a copy of which is
attached hereto as Exhibit "A" (the "Employment Agreement") and ,
WHEREAS, Frontier and Consultant both have agreed that Consultant would
limit and modify Consultant's relationship with Frontier and,
WHEREAS, the parties have agreed that the Consultant shall become a
consultant to Frontier as set forth herein;
THEREFORE, the parties agree as follows:
1. Consultant. Consultant shall, effective the 1st day of May, 1996, cease
to be an employee of Frontier and shall thereafter serve as geological,
geophysical and exploration consultant to Frontier, pursuant to the terms of
this Consulting Agreement.
2. Duties. Frontier shall employee Consultant, and Consultant agrees to
serve as Frontier's geological, geophysical and exploration and production
consultant to the extent consistent with Consultant's background as required and
requested by Frontier up to a maximum of 40 hours per month, as requested by
Frontier, provided, however, that Consultant shall not be required to work more
than 24 hours (i.e. three eight-hour days) in any one week period. Services
requested in excess thereof shall be billed at the rate of $70.00 per hour, up
to a maximum of $400.00 per calendar day. Consultant shall provide exploration
and production oversight services on Frontier's currently existing properties
and prospects in the Mid-Continent Area and prospect generation and evaluation
services on Frontier's existing 3-D seismic data over acreage in the
Mid-Continent Area, and such other services as agreed to between Consultant and
Frontier. Frontier shall be required to provide Consultant access to all tools
necessary to perform the requested work.
3. Independent Contractor. Consultant shall serve as an independent
contractor and shall have the right to perform for Frontier and/or for third
parties from his offices in Oklahoma City; provided Consultant shall travel as
reasonably necessary.
4. Compensation. Employee's monthly consulting fee shall be $10,000.00 per
month, payable in equal semi-monthly installments on the 15th day of each month
and at the end of each month. Compensation paid pursuant hereto shall not be
subject to reduction by the amount of all applicable withholding, social
security and other similar state, federal and local taxes and deductions, all of
which Consultant agrees to pay as an independent contractor. Consultant agrees
to indemnify and hold harmless Frontier for any costs incurred in regard thereto
due to Consultant's failure to timely pay any such taxes.
5. Term. The term of this Consulting Agreement and all provisions hereof
shall commence effective May 1, 1996 and shall extend to March 31, 1998, at
which time the Consulting Agreement will expire, unless agreed to in writing
between the parties.
6. Director. Consultant may continue to serve on Frontier's Board of
Directors as he is elected to so serve by the shareholders of Frontier, and if
Consultant so serves, shall do so for no additional compensation other than as
set forth herein during the term of this Consulting Agreement.
7. Incentive Compensation. All units in Frontier's Stock Incentive Plan,
currently vested in Consultant, pursuant to paragraph 4 of the Employment
Agreement, shall remain vested and shall be exercisable throughout the duration
of Consultant's service as a Director of Frontier and such period thereafter as
set forth in said Stock Incentive Plan. There shall be no additional vesting of
additional incentive compensation for any rights not vested as of the date
hereof.
-1-
<PAGE>
8. Deferred Compensation. All amounts vested as of the date hereof in
Consultant, pursuant to paragraph 5 of the Employment Agreement, shall remain
valid and payable obligations of Frontier pursuant to the provisions of
paragraph 5 of the Employment Agreement. There shall be no further vesting after
the date hereof, and Consultant shall accrue no additional deferred compensation
not currently vested as of the date hereof.
9. Travel Expenses. Consultant shall be reimbursed for reasonable approved
travel and business expenses incurred in connection with Consultant's duties to
Frontier.
10. Confidentiality and Proprietary Ownership Agreement. Consultant will
maintain all information which is Frontier's proprietary information
confidential as set forth in paragraph 7(a) of the Employment Agreement
throughout the term of this Consulting Agreement and for one year thereafter.
Consultant can, however, perform services for third parties unrelated to
confidential information regarding Frontier's business activities beginning May
1, 1996, which permitted services shall include work on any oil and gas prospect
leads not currently on acreage owned by Frontier or on acreage which does not
underlie any of Frontier's existing seismic data bases.
11. Other. Frontier agrees to sell to Consultant for a total purchase price
of $1.00 the following:
a. Furniture currently located in Consultant's office at Frontier;
b. One (1) light table;
c. One (1) hard copy data base of Oklahoma data comprised of scout
tickets and well logs; provided, however, that Frontier shall have
access to said data base at any reasonable time and the right to use
any such data as it deems necessary; and provided further, that should
Consultant ever seek to dispose of data base, he shall offer same to
Frontier at a price of $1.00 prior to any such disposition;
d. One (1) Desk Jet 500 Plotter;
e. One (1) Mita copying machine which does not function;
f. One (1) lot of drafting tools comprised of triangles, etc.;
g. One DOS-based personal computer as currently used by Consultant;
h. Use of any mapping software as may be agreed to by the parties at a
future date.
All taxes or other liabilities accruing due to compensation to Consultant
as a result hereof shall be Consultant's sole responsibility, and Consultant
agrees to pay same and to indemnify Frontier for any costs in regard thereto.
Frontier also agrees that all rights to that certain Oak Tree Country Club
membership currently in Consultant's name vest solely in Consultant and
Consultant agrees that Frontier has no obligation in regards to any dues or
additional costs due on said membership.
12. Employment Agreement. All terms, obligations and provisions of each
party thereto to the other shall, other than those specifically extended in this
Consulting Agreement, be deemed of no further effect, and Frontier shall be
under no further obligation to Consultant, and Consultant under no further
obligation to Frontier, pursuant to the terms of said Employment Agreement as of
May 1, 1996, the effective date hereof.
13. Notices. Any notices, requests, demands or other communications
provided for by this Consulting Agreement shall be sufficient if, in writing,
and sent by Registered or Certified Mail, overnight courier or if delivered in
person to Frontier or Consultant at the following addresses:
"FRONTIER" FRONTIER NATURAL GAS CORPORATION
One Benham Place, Suite 120
9400 North Broadway
Oklahoma City, Oklahoma 73114
"CONSULTANT" JEFFREY R. ORGILL
[to be provided]
14. Governing Law. This Consulting Agreement shall be governed by and
construed in accordance with the laws of the State of Oklahoma.
-2-
<PAGE>
15. Assignment. The Consultant acknowledges that the services to be
rendered hereunder are unique and personal. Accordingly, the Consultant may not
assign any of his rights or delegate any of his duties or obligations under this
Consulting Agreement. The rights and obligations of Frontier under this
Consulting Agreement shall inure to the benefit of and shall be binding upon the
successors and assigns of Frontier.
16. Attorney's Fees. In the event that any legal action is taken to enforce
any of the terms of this Consulting Agreement, the prevailing party shall be
entitled to, in addition to all remedies provided to such party, reasonable
attorney's fees, costs and expenses.
17. Severability. If any provisions of this Consulting Agreement shall be
or become illegal or unenforceable, in whole or in part, for any reason
whatsoever, the remaining provisions shall nevertheless be deemed valid and
binding.
18. Partial Performance. Frontier agrees that in the event Frontier does
not request any consulting services from Consultant that it shall nonetheless
make all payments as set forth herein.
19. Entirety of Agreement. This writing represents the entire agreement
between the parties and can only be modified or awarded by a writing signed by
all of the parties hereto.
IN WITNESS WHEREOF, the parties have executed and delivered this Consulting
Agreement effective as of May 1, 1996.
"FRONTIER"
ATTEST: FRONTIER NATURAL GAS CORPORATION
/s/ James R. Harris, Jr. By: /s/ David W. Berry
- ---------------------------- ---------------------------------------
(SEAL) Its: President
"CONSULTANT"
By: /s/ Jeffrey R. Orgill
---------------------------------------
Jeffrey R. Orgill
STATE OF OKLAHOMA )
)
COUNTY OF OKLAHOMA )
Before me, the undersigned, a notary public, in and for the said county and
state, on the 18th day of April, 1996, personally appeared David W. Berry, as
President of Frontier Natural Gas Corporation, who acknowledged to me he
executed same as the free and voluntary act and deed of said corporation, for
the uses and purposes therein set forth.
In witness whereof, I have hereunto set my official signature and affixed
my official seal the day and year last above written.
/s/ Linda Bentley
---------------------------------------
Linda Bentley
Notary Public
My Commission Expires:
April 4, 1999
[SEAL]
-3-
<PAGE>
STATE OF OKLAHOMA )
)
COUNTY OF OKLAHOMA )
Before me, the undersigned, a notary public, in and for the said county and
state, on the 18th day of April, 1996, personally appeared Jeffrey R. Orgill, an
Individual, who acknowledged to me he executed same as the free and voluntary
act and deed, for the uses and purposes therein set forth.
In witness whereof, I have hereunto set my official signature and affixed
my official seal the day and year last above written.
/s/ Linda Bentley
-------------------------------------
Linda Bentley
Notary Public
My Commission Expires:
April 4, 1999
[SEAL]
AMENDMENT NO. 1 TO CREDIT AGREEMENT
THIS AMENDMENT NO. 1 TO CREDIT AGREEMENT (this "Amendment No. 1"), dated as
of November 1, 1996, between FRONTIER NATURAL GAS CORPORATION, an Oklahoma
corporation (the "Borrower"), and BANK OF AMERICA ILLINOIS, an Illinois banking
corporation (the "Lender").
W I T N E S S E T H:
WHEREAS, the Borrower and the Lender are parties to that certain Credit
Agreement, dated as of January 3, 1996 (hereinafter referred to as the "Existing
Credit Agreement"); and
WHEREAS, the Borrower has requested that certain amendments be made to the
Existing Credit Agreement; and
WHEREAS, the Lender is willing to make certain amendments to the Existing
Credit Agreement on the terms and conditions hereinafter provided;
NOW, THEREFORE, in consideration of the agreements herein contained, the
parties hereto hereby agree as follows:
ARTICLE I.
DEFINITIONS
SECTION 1.1 Certain Definitions. The following terms (whether or not
underscored) when used in this Amendment No. 1 shall have the following
meanings:
"Amended Credit Agreement" means the Existing Credit Agreement as amended
by this Amendment No. 1.
"Amendment No. 1 Effective Date" has the meaning provided in Section 4.1.
SECTION 1.2 Other Definitions. Unless otherwise defined or the context
otherwise requires, terms used herein (including in the preamble and recitals
hereto) have the meanings provided for in the Existing Credit Agreement.
-1-
<PAGE>
ARTICLE II.
AMENDMENTS TO
EXISTING CREDIT AGREEMENT
Effective on the Amendment No. 1 Effective Date, the Existing Credit
Agreement is amended in accordance with the terms of this Article II; except as
so amended, the Existing Credit Agreement shall continue to remain in all
respects in full force and effect.
SECTION 2.1 Amendments to Section 1.1.
(a) The definition of "Tranche B Availability Termination Date" in the
Existing Credit Agreement is deleted and the following definition is inserted in
its place:
"Tranche B Availability Termination Date" means June 30, 1997."
SECTION 2.2 Amendments to Borrower's Address. The address of the Borrower
set forth on the signature page of the Existing Credit Agreement is amended by
deleting the existing address and inserting in its place the following new
address:
Frontier Natural Gas Corporation
One Allen Center
500 Dallas Street
Suite 2920
Houston, TX 77002
713-739-7100
713-739-7124 (fax)
SECTION 2.3 Amendments to Certain Exhibits and Schedules.
(a) Schedule II to the Existing Credit Agreement is deleted and a new
Schedule II in the form of the Minimum Monthly Payments schedule shown in
Schedule II hereto is inserted in its place.
(b) Section 2.10 of the form of Mortgage and of each Mortgage previously
executed and delivered in favor of the Lender is deleted and a new Section 2.10
in the form shown in Exhibit A hereto is inserted in its place.
-2-
<PAGE>
ARTICLE III.
REPRESENTATIONS AND WARRANTIES
In order to induce the Lender to make the amendments provided for in
Article II, the Borrower hereby
(a) acknowledges and agrees that, immediately prior to the Amendment No.1
Effective Date, the aggregate outstanding principal amount of all Tranche A
Loans is $523,888 and the aggregate outstanding principal amount of all Tranche
B Loans is $0.00;
(b) represents and warrants that the Borrower has full power and authority
to execute, deliver and perform its obligations under this Amendment No. 1 and
all other Loan Documents delivered to Lender in connection herewith, and this
Amendment No. 1 and all such Loan Documents are the legally valid and binding
obligations of Borrower, enforceable against Borrower in accordance with their
respective terms;
(c) represents and warrants, that each of the representations and
warranties contained in the Existing Credit Agreement and in the other Loan
Documents is true and correct as of the date hereof as if made on the date
hereof (except, if any such representation and warranty relates to an earlier
date, such representation and warranty shall be true and correct in all material
respects as of such earlier date) and Borrower has performed each of the
covenants and agreements in the Existing Credit Agreement and the other Loan
Documents required to be performed by Borrower as of the date hereof; and
(d) There is no Default or Event of Default by Borrower or any other
Obligor under the Existing Credit Agreement or any other Loan Document and no
event exists which, with the giving of notice or the passage of time or both,
would give rise to a Default or Event of Default by Borrower or any other
Obligor under the Existing Credit Agreement or any Loan Document.
ARTICLE IV.
CONDITIONS TO EFFECTIVENESS
SECTION 4.1 Effective Date. This Amendment No. 1 shall become effective on
November 1, 1996, or, if later, the date (herein called the "Amendment No. 1
Effective Date") when the conditions set forth in this Section 4.1 have been
satisfied.
(a) Execution of Counterparts. The Lender shall have received counterparts
of this Amendment No. 1 duly executed and delivered on behalf of the Borrower
and the Lender.
-3-
<PAGE>
(b) Closing Fees, Expenses, etc. The Lender shall have received all
reasonable costs and expenses due and payable pursuant to Sections 3.3 and 9.3
of the Existing Credit Agreement, if then invoiced.
(c) Legal Details, etc. All documents executed or submitted pursuant
hereto, and all legal matters incident thereto, shall be satisfactory in form
and substance to the Lender and its counsel.
SECTION 4.2 Expiration. If all of the conditions set forth in Section 4.1
hereof shall not have been satisfied on or prior to February 7, 1997, the
agreements of the parties contained in this Amendment No. 1 shall, unless
otherwise agreed by the Lender, terminate effective immediately on such date and
without further action.
ARTICLE V.
MISCELLANEOUS
SECTION 5.1 Loan Document Pursuant to Existing Credit Agreement. This
Amendment No. 1 is a Loan Document executed pursuant to the Existing Credit
Agreement. Except as expressly amended or waived hereby, all of the
representations, warranties, terms, covenants and conditions contained in the
Existing Credit Agreement and each other Loan Document shall remain unamended
and in full force and effect. The amendments set forth herein shall be limited
precisely as provided for herein and shall not be deemed to be a waiver of,
amendment of, consent to or modification of any other term or provision of the
Existing Credit Agreement or of any term or provision of any other Loan Document
or of any transaction or further or future action on the part of the Borrower or
which would require the consent of the Lender under the Existing Credit
Agreement or any other Loan Document.
SECTION 5.2 Counterparts, etc. This Amendment No. 1 may be executed by the
parties hereto in several counterparts, each of which shall be deemed to be an
original and all of which shall constitute together but one and the same
agreement with the same effect as if all parties hereto had signed the same
signature page. Any signature page of this Amendment No. 1 may be detached from
any identical counterpart of this Amendment No. 1 having attached to it one or
more additional signature pages.
SECTION 5.3 GOVERNING LAW; ENTIRE AGREEMENT. THIS AMENDMENT NO. 1 SHALL BE
DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE
STATE OF ILLINOIS.
SECTION 5.4 Titles and Headings. The titles and headings of the Sections of
this Amendment No. 1 are intended for convenience only and shall not in any way
affect the meaning or construction of any provision of this Amendment No. 1.
-4-
<PAGE>
SECTION 5.5 Changes and Modifications in Writing. No provision of this
Amendment No. 1 may be changed or modified except by an instrument in writing
signed by the party against whom enforcement of the change or modification is
sought.
-5-
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 1 to
be executed by their respective officers hereunto duly authorized as of the day
and year first above written.
BORROWER
FRONTIER NATURAL GAS CORPORATION, an
Oklahoma corporation
By: /s/ illegible
-------------------------------------------
/s/ illegible
Title: Executive Vice President
LENDER
BANK OF AMERICA ILLINOIS
By: /s/ John H. Homer
-------------------------------------------
John H. Homer
Title: John H. Homer
-6-
<PAGE>
Exhibit A
NEW SECTION 2.10 OF MORTGAGE
2.10 Right of Entry.
(a) The Mortgagor will permit the Trustees or the Bank, or the agents of
either of them, at the cost and expense of the Mortgagor, to enter upon the
Mortgaged Property and all parts thereof, for the purpose of investigating and
inspecting the condition and operation thereof, and shall permit reasonable
access to the field offices and other offices, including the principal place of
business, of the Mortgagor to inspect and examine the Mortgaged Property and to
inspect, review and reproduce as necessary any books, records, accounts,
contracts or other documents of the Mortgagor.
(b) Without limiting the generality of the foregoing, the Bank shall have
the right, on twenty-four (24) hours prior notice to the Mortgagor, to cause
such persons and entities as the Bank may designate to enter the Mortgaged
Property to conduct (at the cost and expense of the Mortgagor), or to cause the
Mortgagor to conduct (at the cost and expense of the Mortgagor), such tests and
investigations as the Bank deems necessary to determine whether any hazardous
substance or solid waste is being generated, transported, stored, or disposed of
in accordance with applicable Environmental Laws. Such tests and investigations
may include, without limitation, underground borings, ground water analyses and
borings from the floors, ceilings and walls of any improvements located on the
Mortgaged Property. This Section 2.10 shall not be construed to affect or limit
the obligations of the Mortgagor pursuant to Section 2.5 hereof.
(c) The Bank shall have no duty to visit or observe the Mortgaged Property
or to conduct tests, and no site visit, observation or testing by the Bank shall
impose any liability on the Bank, nor shall the Mortgagor or any other Obligor
be entitled to rely on any visit, observation or testing by the Bank in any
respect. The Bank may, in its discretion, disclose to the Mortgagor or any other
Person, including any governmental agency, any report or finding made as a
result of, or in connection with, any site visit, observation or testing by the
Bank. The Mortgagor agrees that the Bank makes no warranty or representation to
the Mortgagor or any other Obligor regarding the truth, accuracy or completeness
of any such report or findings that may be so disclosed. The Mortgagor also
acknowledges that, depending upon the results of any site visit, observation or
testing by the Bank and disclosed to the Mortgagor, the Mortgagor may have a
legal obligation to notify one or more governmental agencies of such results,
that such reporting requirements are site-specific, and are to be evaluated by
the Mortgagor without advice or assistance from the Bank.
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Schedule II
Minimum Monthly Payments
3-D SEISMIC PARTICIPATION AGREEMENT
THIS AGREEMENT dated as of May 30, 1996, by and between FINA OIL AND
CHEMICAL COMPANY, ("FINA") a Delaware corporation, 14950 Heathrow Forest
Parkway, Houston, Texas 77032 and DENBURY MANAGEMENT, INC. ("DENBURY"), a Texas
corporation, 17304 Preston Road, Suite 200, Dallas, Texas 77252 (collectively,
FINA and Denbury shall be referred to as the "FINA GROUP"); and acting
individually herein SCANA PETROLEUM RESOURCES, INC. ("SPR"), a South Carolina
Corporation, 1200 Smith Street, Suite 500, Houston, Texas 77002-4308 ("SPR") and
FRONTIER NATURAL GAS CORPORATION ("FRONTIER"), an Oklahoma corporation, 9400
North Broadway Extension, Oklahoma City, Oklahoma 73114; SOUTH COAST EXPLORATION
COMPANY ("SOUTH COAST"), a Texas corporation, Two Post Oak Central, 1980 Post
Oak Boulevard, Suite 2050, Houston, Texas 77056; SOCO EXPLORATION L.P. ("SOCO"),
a Texas Limited Partnership, Two Post Oak Central, 1980 Post Oak Boulevard,
Suite 2050, Houston, Texas 77056; MATAGORDA PRODUCTION COMPANY ("MATAGORDA"), a
Texas corporation, 675 Bering Drive, Suite 850, Houston, Texas 77057 and POLARIS
EXPLORATION CORPORATION ("POLARIS"), a Texas corporation, P.O. Box 2080,
Beeville, Texas 78104-2080, (collectively, the "FRONTIER GROUP").
WITNESSETH:
WHEREAS, SPR and the members of the FINA GROUP and the members of the
FRONTIER GROUP each are presently engaged in the business of exploring for oil,
gas and other hydrocarbons within the state of Louisiana; and,
WHEREAS, SPR and the members of the FINA GROUP own leases, options and
other rights to explore within a certain area of Terrebonne Parish, Louisiana
and the members of the FRONTIER GROUP own leases, options and other rights to
explore within a certain area of Terrebonne Parish, Louisiana and FINA,
individually is the owner of certain lands located in a certain area of
Terrebonne Parish, Louisiana, which areas collectively are deemed by SPR, the
FINA GROUP and the FRONTIER GROUP to be prospective for finding oil, gas and
other hydrocarbons; and,
WHEREAS, certain members of the FINA GROUP own certain proprietary data or
are in possession of and have a license to use certain other data, which covers
substantially all of FINA's lands as well as lands adjacent to FINA's lands
which the FRONTIER GROUP may not have been licensed to use; and,
WHEREAS, certain members of the FRONTIER GROUP have a license to use
certain other data which the FINA GROUP may not have been licensed to use; and,
WHEREAS, SPR, the FINA GROUP and the FRONTIER GROUP recognize the benefit
of entering into an agreement which gives each access to the data presently
owned by or licensed to the other; and,
WHEREAS, the members of the FINA GROUP and the members of the FRONTIER
GROUP find it in their mutual interests to enter into an agreement for using the
data of SPR, the FINA GROUP and the FRONTIER GROUP for the purposes of exploring
for oil, gas and other hydrocarbons on the lands owned by FINA as well as the
adjacent lands which are covered by the leases, options to lease or other rights
to explore owned by either SPR, certain members of the FINA GROUP or certain
members of the FRONTIER GROUP and which are covered by data in the possession of
the members of SPR, the FINA GROUP and/or the FRONTIER GROUP.
NOW THEREFORE, for and in consideration of the premises and mutual
covenants herein contained, SPR, the members of the FINA GROUP and the members
of the FRONTIER GROUP do hereby covenant and agree as follows:
ARTICLE 1
CERTAIN DEFINITIONS
As used in this Agreement, the following words and terms shall have the
meanings here ascribed to them:
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1.1 "Agreement" shall refer to this Agreement.
1.2 "Contract Area" shall mean the area within the red outline on Exhibit
"A" attached hereto and made a part hereof for all purposes.
1.3 "Oil and Gas" shall mean oil, gas, casing head gas, gas condensate, and
all other liquid or gaseous hydrocarbons and other marketable substances
produced therewith, unless an intent to limit the inclusiveness of this term is
specifically stated.
1.4 "Oil and Gas Interests" shall mean unleased fee and mineral interests
in tracts of lands lying within the Contract Area which are owned by or within
the control of any of the parties to this Agreement.
1.5 "Oil and Gas Lease," "Lease" and "Leasehold" shall mean the oil and gas
leases or options to acquire oil and gas leases covering tracts of land lying
within the Contract Area which are either owned by any of the parties to this
Agreement or which any party to this Agreement is entitled to or may acquire a
future interest in.
1.6 FINA Fee Lands shall mean any and all lands or Oil and Gas Interests
within the Contract Area presently owned in fee by FINA. The FINA Fee Lands are
depicted in yellow on Exhibit "A" to this Agreement.
1.7 "FINA GROUP Leases" shall mean Oil and Gas leases, options to lease,
operating rights and other Oil and Gas Interests lying within the Contract Area
which are owned or committed to SPR and/or any member of the FINA GROUP as of
the Effective Date. FINA GROUP Leases are depicted in red on Exhibit "A" to this
Agreement.
1.8 "FRONTIER GROUP Leases" shall mean Oil and Gas leases, options to
lease, operating rights and other Oil and Gas interests lying within the
Contract Area which are owned by any member of the FRONTIER GROUP as of December
31, 1996. FRONTIER GROUP Leases are depicted in green on Exhibit "A" and set
forth on Exhibit "A-1" to this Agreement. FRONTIER GROUP Leases shall also
include any leases or options to lease within the area depicted in green on
Exhibit "A" which have multiple lessors owning an individual interest in the
leased lands as evidenced by at least one lessor's execution having been
acknowledged on or before December 31, 1996. In the event the balance of the
unsigned lessors have not executed their respective leases by December 31, 1996,
said interests associated with the unsigned lessors will become subject to the
AMI provisions set forth in provision 9.1 hereof. In addition to the leases
depicted in green, FRONTIER GROUP Leases shall include those leases described on
Exhibit "A- 3" and acquired prior to May 30, 1996 attached hereto, which cover
undivided interests in tracts within the Contract Area but are not colored green
on Exhibit "A".
1.9 "Effective Date" shall mean May 30, 1996.
1.10 "Designated Member" shall mean FINA Oil and Chemical Company as to the
FINA GROUP and Polaris Exploration Corporation as to the FRONTIER GROUP.
1.11 "JOA" shall mean the operating agreement for a given Contract Area
substantially in the form as that attached hereto as Exhibit "E".
1.12 "Disputed Acreage" shall mean those lands within the Contract Area as
to which a dispute exists between FINA and the State of Louisiana with respect
to the ownership thereof. Said lands are colored green hatched on Exhibit "A"
attached hereto. For purposes of this Agreement, and as between the parties
hereto, unless and until a determination is made, it shall be assumed that the
Disputed Acreage is actually owned 80% by FINA and 20% by the State of
Louisiana. Such ownership percentages shall be adjusted with respect to any
portion of the Disputed Acreage as to which a determination or settlement is
made as between FINA and the State of Louisiana on the percentage ownership
interests of such Disputed Acreage.
1.13 "Payout" shall mean that point in time when one hundred percent (100%)
of the gross income received from the sale of oil and gas production from a
well, less Lessor's royalty, the overriding royalty interest reserved by Laurent
Oil & Gas, Inc. and Leo R. Bader, other overriding royalty interest burdens, and
production and severance taxes, is equal to the costs incurred in drilling,
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testing, completing, equipping, and operating such well.
Use of the terms "group", "FRONTIER GROUP" or "FINA GROUP" shall mean,
unless the context otherwise clearly indicates, each and every member of the
applicable group and their respective subsidiaries, parents, partnerships,
affiliates or other person or entity owned or controlled by or which owns or
controls any such member; provided, however, that such terms shall not include
and this Agreement shall not be binding on Equitable Resources, Inc. or any
subsidiary or affiliate thereof which are not signatory parties to this
Agreement. Unless the context otherwise clearly indicates, words used in the
singular include the plural, the plural includes the singular and any references
to gender includes both the masculine and the feminine. The Designated Member of
each group agrees by its execution hereof to act as an uncompensated
administrator and facilitator for its group as an accommodation only. Each
Designated Member agrees to attempt to carry out its obligations as Designated
Members hereunder with ordinary care and diligence, but each party hereto
understands and agrees that its Designated Member shall have no liability to any
such party for any delays, omissions or other errors it may commit in relating
any rights, duties or other obligations, including any individual party and/or
group elections called for herein, for which such Designated Member is
responsible for communicating to its group members, except as result from the
gross negligence or willful misconduct of such Designated Member. In no event
shall either Designated Member be liable to any member of its group in
connection with any alleged failure to carry out its obligations as Designated
Member for any special, indirect or consequential damages, including without
limitation, lost profits. A Designated Member may resign at any time. Any group
shall have the power to elect a new Designated Member at any time. Such election
shall require twenty (20) days prior written notice and shall be decided by
working interest majority. No such change in a group's Designated Member shall
be effective upon the other parties hereto until such parties have received
written notice of the change in such Designated Member, as evidenced by the
signature and approval of all of the parties in the group changing its
Designated Member.
ARTICLE 2
THE LANDS
2.1 Lands, Oil and Gas Interests and Oil and Gas Leases Committed to the
Agreement. This Agreement shall cover and affect all the lands, Oil and Gas
Interests and Oil and Gas Leases lying within the Contract Area including, but
not limited to, the FINA GROUP Leases, the FRONTIER GROUP Leases, the unleased
portion of the entirety of the FINA Fee Lands as well as those of other owners
not under oil and gas lease or contractually committed by the owner thereof to
an unrelated third party by the terms of another agreement actually in existence
on the Effective Date. Each party to this Agreement hereby commits to the terms
and conditions hereof, and agrees to lease, convey, assign or otherwise transfer
to each and every other party hereto their respective interests in the FINA
GROUP Leases, the FRONTIER GROUP Leases and the FINA Fee Lands which are owned
or controlled by any such party as of the Effective Date, to the extent located
within the Contract Area, whether or not marked or otherwise designated on
Exhibit A. During the existence of this Agreement, no party may sell, lease,
convey, assign, encumber, mortgage, pledge or contract in any manner with
respect to the FINA Group Leases, the FRONTIER GROUP Leases or the FINA Fee
Lands, in any way which would impair or prejudice the rights of any other party
in or to such interests as provided for in this Agreement. No wells may be
drilled or other operations conducted in connection with the exploration for or
the production of oil or gas from the Contract Area prior to the completion of
the 3-D Survey and receipt of the fully processed data set without the prior
written consent of all parties hereto, nor after receipt of such data set except
pursuant to this Agreement. Notwithstanding the foregoing, such restrictions on
drilling and other operations shall not apply to Initially Excluded Lands as
long as they remain excluded, or to reservoirs, the entirety of which are, and
pursuant to this Agreement, will continue to be owned 100% by a party to the
exclusion of all other parties.
2.2 Lands, Oil and Gas Interests and Oil and Gas Leases Initially Excluded
from this Agreement. This Agreement does not cover lands, Oil and Gas Interests
or Oil and Gas Leases which are leased or contractually committed by the owner
thereof to an unrelated third party by the terms of another lease or other
agreement actually in existence on the Effective Date (the "Initially Excluded
Lands"). Each party represents and warrants as appropriate that all of the
leases and other agreements affecting the Initially Excluded Lands are set forth
on Exhibit "A-2", attached hereto and made a part hereof for all purposes.
Notwithstanding anything contained herein to the contrary, the Initially
Excluded Lands are limited only to those depicted in blue on the attached
Exhibit "A".
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2.3 Lands, Oil and Gas Interests and Oil and Gas Leases to be Subsequently
Committed to this Agreement. Should any of the Initially Excluded Lands either
revert to or otherwise be made available to SPR, any member of the FINA GROUP or
any member of the FRONTIER GROUP during the term of this Agreement, then those
lands shall likewise be covered and affected by this Agreement as of the
effective date of such reversion or other availability.
ARTICLE 3
TERM OF THE AGREEMENT
The term of this Agreement shall commence on May 30, 1996, and shall
continue for sixty (60) calendar months through May 30, 2001.
ARTICLE 4
CONSIDERATION
For and in consideration of the sum of ONE HUNDRED DOLLARS ($100.00) in
hand paid collectively by SPR and the FINA GROUP to the FRONTIER GROUP and other
good and valuable consideration, and of the other agreements of SPR, the FINA
GROUP and the FRONTIER GROUP herein and subject to the terms and conditions
herein set forth, SPR, the members of the FINA GROUP and the members of the
FRONTIER GROUP do hereby agree to join in the execution of this Agreement for
the purposes herein intended.
ARTICLE 5
WORKING INTEREST OF THE PARTIES
SPR, the FINA GROUP and the FRONTIER GROUP (subject to the terms and
provisions of this Agreement, and in particular Articles 7 and 9 hereof) shall
each collectively be entitled to receive, pursuant to the provisions hereof, and
own a working interest in the percentages set forth on Exhibit "B", in the FINA
Fee Lands, the FINA GROUP Leases, the FRONTIER GROUP Leases and any other lands,
leases and oil and gas interests within the Contract Area which may be obtained
pursuant to this Agreement.
ARTICLE 6
ACCESS TO EXISTING SEISMIC DATA
6.1 License to use Proprietary FINA GROUP Seismic Data. Each member of the
FRONTIER GROUP, upon execution of this Agreement, is hereby granted a license
("License"), in the form set out as Exhibit "D", attached hereto and made a part
hereof for all purposes, to use all of the FINA GROUP's proprietary seismic data
within the Contract Area according thereto.
6.2 License to use Proprietary FRONTIER GROUP Seismic Data. SPR and each
member of the FINA GROUP, upon execution of this Agreement, is hereby granted a
license ("License"), in the form set out as Exhibit D-1, attached hereto and
made a part hereof for all purposes, to use all of the FRONTIER GROUP's
proprietary seismic data within the Contract Area according thereto.
6.3 Access to Non-Proprietary FINA GROUP Seismic Data. During the term
hereof and to the extent permitted by such licenses, each member of the FRONTIER
GROUP is hereby granted access and the right to use any and all seismic data
covering lands within the Contact Area which seismic data is licensed to SPR or
any member of the FINA GROUP, to the extent such data is not also licensed or in
the possession of any member of the FRONTIER GROUP. Such access shall be granted
only on a controlled basis by SPR and the FINA GROUP, at an SPR or FINA GROUP
site agreed to by the member of the FRONTIER GROUP desiring such access, subject
to the terms and conditions of the licensing agreements in place. Those
licensing agreements are on file in FINA's or SPR's offices as applicable, and
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will remain there for the term of this Agreement, and by reference the terms
thereof are incorporated herein for all purposes.
6.4 Access to Non-Proprietary FINA Seismic Data. FINA has acquired, either
by purchase or as a condition of FINA's permit for a third party to acquire data
across FINA's Fee lands, licenses to use certain seismic data not owned by FINA.
As a participant in this Agreement during, but limited to the term hereof, SPR
and each member of the FINA GROUP and each member of the FRONTIER GROUP shall be
given access to and the right to use all of the said seismic data in FINA's
inventory within the Contract Area, but only to the extent permitted by such
licenses. This access and right to use shall be on a restricted basis,
controlled by FINA, at a FINA site agreed to by SPR, the member of the FINA
GROUP or the FRONTIER GROUP desiring such access, and shall be governed by the
terms and conditions of the various licensing agreements currently in place.
Those licensing agreements are on file in FINA's offices and by reference are
incorporated herein for all purposes.
6.5 Access to Non-Proprietary FRONTIER GROUP Seismic Data. During the term
hereof and to the extent permitted by such licenses, SPR and each member of the
FINA GROUP is hereby granted access and the right to use any and all seismic
data covering lands within the Contract Area, which seismic data is licensed to
any member of the FRONTIER GROUP, to the extent such data is not also licensed
or in the possession of SPR or any member of the FINA GROUP. Such access shall
be granted only on a controlled basis by the FRONTIER GROUP, at a FRONTIER GROUP
site agreed to by SPR or the member of the FINA GROUP desiring such access,
subject to the terms and conditions of the licensing agreements in place. Those
licensing agreements are on file in one of the FRONTIER GROUP's offices, and
will remain there for the term of this Agreement, and by reference the terms
thereof are incorporated herein for all purposes.
6.6 Access to Other Technical Data. During the term hereof, except to the
extent prevented by the terms of any agreements with the providers of, or the
co-owners of such data, SPR and each member of the FINA GROUP and of the
FRONTIER GROUP, shall also have access to and the use of any and all other
technical data owned by SPR or any member of either group which is deemed to be
useful by such party in the exploration for oil and gas, including, but not
limited to, core data, engineering data, well logs, gravity surveys, geochemical
surveys, paleontological data or any other data currently in each respective
party's files pertaining to the Contract Area. Access, for the purposes hereof
shall include the right for SPR and/or any member of either the FINA GROUP or
the FRONTIER GROUP, at their own expense, to make copies of the other's data.
SPR, nor any party of either the FINA GROUP nor the FRONTIER GROUP shall be
required, however, to show any interpretive geological, geophysical or
engineering data to the other, except that data necessary to support or required
to propose the designation of a Prospect Area within the Contract Area, as
hereinafter provided.
6.7 Confidential Technical Data. Technical data which is restricted
pursuant to the terms of an agreement of confidentiality shall not be made
available under the terms of this Article 6.
6.8 Lost Licensing Agreements. In the event license to any data cannot be
found by the party owning the data, the party owning the data shall use its best
efforts to obtain a copy of the license for the data, but in the event a
licensing agreement as to certain data cannot be located, or obtained without
repurchasing the data, the party in possession of the data may withhold
disclosure of such data, at its sole option.
ARTICLE 7
OPTION AND AGREEMENT TO LEASE
AGREEMENT TO DELIVER WORKING INTERESTS
7.1 Lease Option. At any time during the period beginning on the date a
fully processed data set covering the Contract Area and the 3-D Survey License
Area is delivered to each and every party hereto and ending with the termination
of this Agreement, the FRONTIER GROUP shall have the right and option
("Option"), but not the obligation, to obtain from FINA a lease covering all or
part of the FINA Fee Lands (excluding any Initially Excluded Lands). The Option
shall give such rights to acquire such lease(s) to the FRONTIER GROUP to the
exclusion of any person or entity not a party to this Agreement. The leasehold
interest granted pursuant to such leases(s) shall be limited to that working
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interest set forth for the FRONTIER GROUP on Exhibit "B" hereto. The Option
shall be exercised by giving written notice to FINA (with a copy to SPR) at the
address set forth herein. In this notice the FRONTIER GROUP shall identify the
acreage to be leased by legal description and tender a check in the amount of
$150 per net mineral acre selected. The lease term shall be for three (3) years
(with annual rentals of $150 per net mineral acre) and the landowner's royalty
reserved unto FINA shall be 33.33% of 8/8ths. Within thirty days after receipt
of such notice, FINA agrees to execute and deliver to the FRONTIER GROUP,
jointly, one original of an oil and gas lease covering the acreage selected
identical in form to the lease attached hereto and made a part hereof as Exhibit
"C", and containing the identical terms and conditions as set forth therein.
7.2 Agreement to Deliver Working Interest in Leases, Options to Lease and
Oil and Gas Interests. FINA shall give notice to SPR and each member of the
FRONTIER GROUP at least 72 hours prior to the time the fully processed data set
covering the Contract Area and the 3-D Survey License Area will be delivered to
SPR and the FRONTIER GROUP. Simultaneously with delivery by the FINA GROUP to
SPR and the FRONTIER GROUP of the fully processed data set covering the Contract
Area and the 3-D Survey License Area, the FRONTIER GROUP shall deliver to SPR
and the FINA GROUP, jointly, at no cost to SPR and the FINA GROUP, an assignment
duly executed and in the form attached hereto as Exhibit "G", of the FRONTIER
GROUP's interest in and to the FRONTIER GROUP Leases (hereinafter referred to as
the "Assignment"); limited however, to the interest in such FRONTIER GROUP
Leases as set forth for SPR and the FINA GROUP on Exhibit "B" hereto. The
undivided interests in the Leases to be conveyed to SPR and the FINA GROUP shall
have no burdens other than landowner royalty and the overriding royalty
interests to be granted to Laurent Oil & Gas, Inc. ("Laurent") and Leo R. Bader
("Bader") pursuant to that certain letter agreement dated April 27, 1995 by and
among Frontier, Polaris, Laurent and Bader as amended dated August 14,1996 (the
"Laurent Agreement") (which shall not exceed 3% on Leases with lessor's
royalties of 25% or less, or 1.5% on Leases with lessor's royalty of greater
than 25%, or 1.5% on Leases acquired by farm out or exploration agreement) to be
borne by SPR and the members of the FINA GROUP in proportion to their respective
working interests. Burdens on such Leases in excess of land owner royalty and
overrides under the Laurent Agreement shall be the sole responsibility of the
members of the FRONTIER GROUP creating said excess burden. All obligations owed
to Laurent or Bader pursuant to any agreement (including specifically but
without limitation the Laurent Agreement) to permit the acquisition by either or
both of them of interests in leasehold or other interests (not including
overriding royalty interests) after completion of the 3-D Survey shall be borne
entirely by the FRONTIER GROUP, and the members thereof shall jointly and
severally indemnify and hold harmless SPR and each and every member of the FINA
GROUP from and against any reduction in interest or any other loss, cost,
expense or claim whatsoever arising in connection therewith.
7.3 Agreement to Assign Options and the Rights to Options. Included on
Exhibit A-1 attached hereto is a list of all of the options to lease held by the
FRONTIER GROUP. Exercise by the FRONTIER GROUP of any options to lease, owned by
any member of the FRONTIER GROUP within the Contract Area, shall be the sole
responsibility of the FRONTIER GROUP. Any and all leases so acquired shall be
assigned by the FRONTIER GROUP to SPR and the FINA GROUP within three business
days after receipt thereof by such member(s) of the FRONTIER GROUP, as provided
herein, and neither SPR nor the FINA GROUP shall be charged for any portion of
the costs or expense incurred in connection with the acquisition or exercise
thereof. Should any member of the FRONTIER GROUP elect to not exercise its pro
rata portion of any part of such option, the remaining members of the FRONTIER
GROUP will have the right to acquire said interest. Should the FRONTIER GROUP
collectively elect, for any reason, not to exercise all or any pro rata portion
of any part of such options as contemplated herein, then it shall deliver
written notice of its election not to exercise to SPR and each member of the
FINA GROUP as soon as possible, but in no event less than ten (10) business days
prior to the expiration of the applicable option. SPR, the FINA GROUP or any
member thereof, would have the option, but not obligation, to exercise the
remaining pro rata portion of any part of said options in accordance with their
terms at its sole cost and expense. The FRONTIER GROUP will take such action as
is necessary to permit the timely exercise of such option by SPR and any member
in the FINA GROUP desiring to exercise same. In the event any such option is
exercised by any member of the FINA GROUP, each non-participating member of the
FRONTIER GROUP shall forfeit any interest in and to any leases acquired pursuant
to such options. After delivery of the fully processed data set covering the
Contract Area and the 3-D Survey License Area to the FRONTIER GROUP and the
assignment of the leasehold interest as provided herein to SPR and the FINA
GROUP, any delay rentals approved by all parties to be paid on the leases
assigned from the FRONTIER GROUP to SPR and the FINA GROUP shall be paid 16.67%
by SPR, 33.33% by the FINA GROUP and fifty percent (50%) by the FRONTIER GROUP
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notwithstanding the Working Interest Ownership in such Lease(s) for each group
as set out in Exhibit "B". Should any party(ies) hereto elect not to pay any
delay rental obligation, then the parties consenting to pay such rentals shall
bear such costs proportionately, and receive the benefit thereof proportionately
and all non-participating parties shall forfeit any and all rights to the
leases, lands and interests affected thereby.
ARTICLE 8
SEISMIC PROGRAM
8.1 Geophysical Permit. During the term of this Agreement, SPR and the FINA
GROUP at their sole cost, risk and expense, shall have the exclusive right to
conduct seismic exploration operations within the Contract Area. At such time as
requested by FINA, the FRONTIER GROUP shall deliver at no cost to SPR and the
FINA GROUP all necessary permits pertaining to lands, Oil and Gas Leases or Oil
and Gas Interests owned or controlled by each and every member of the FRONTIER
GROUP as required by SPR and the FINA GROUP or their contractor, in the form
attached hereto as Exhibit "H", to enable SPR and the FINA GROUP to conduct said
seismic exploration operations.
8.2 3-D Survey. As primary consideration for the FRONTIER GROUP's execution
of this Agreement and in consideration for the Assignment of Leasehold interests
described in Article 7 hereof, SPR and the FINA GROUP agrees to pursue the
acquisition of a 3-D seismic survey (the "3-D Survey") covering the Contract
Area, using the parameters set forth on Exhibit "F" attached hereto and made a
part hereof, with the intent and in such manner and to such extent as to
properly image substantially all horizons down to and including the Tex "W" Sand
Series in the subsurface of the Contract Area. FINA shall be designated as the
Operator of the seismic operations and shall conduct the 3-D Survey in a good
and workmanlike manner, but neither FINA, SPR nor any member of the FINA GROUP
shall have any liability to the FRONTIER GROUP for losses sustained or
liabilities incurred except such as may result from the gross negligence or
willful misconduct of SPR or such member of the FINA GROUP. Upon completion of
the 3-D Survey and receipt of a fully processed data set of same SPR and the
FINA GROUP shall make available on the same day it is delivered to or otherwise
available to SPR and any member of the FINA GROUP, to the FRONTIER GROUP a fully
processed data set covering both the Contract Area and the adjacent area
outlined in green on Exhibit "A" and designated as the "3-D Survey License
Area." Said data set shall include full fold data over the Contract Area and the
3-D Survey License Area to the extent SPR and the FINA GROUP has full fold data
available. The associated costs of the entire 3-D Survey shall be borne solely
by SPR and the FINA GROUP. Prior to delivery of said data set as set forth
herein, the FINA GROUP shall make periodic reports, not less than monthly, to
SPR and the Designated Member of the FRONTIER GROUP of the status of said 3-D
Survey.
Said periodic reports shall include (i) weekly reports on all field
operations within the Contract Area and the 3-D Survey License Area. These
reports should include status and updates of permits, leases and options,
and maps with progress for surveying, drilling, layout and shooting, and
other any relevant information; (ii) estimates for commencement and
completion of various activities within the Contract Area and the 3-D
Survey License Area. These estimates should include surveying, drilling,
shooting, and processing and should be updated no less frequently than once
a month; (iii) daily progress and quality control reports during the
shooting phase; and (iv) processing flow chart and parameter testing with
input to parameter selection and processing in the Contract Area and 3-D
Survey License Area to be provided by the FRONTIER GROUP.
8.3 Separate Processing Option. Subject to the prior written consent of the
FINA GROUP, the FRONTIER GROUP may, at its sole option and sole cost, elect to
have that portion of the 3-D Survey covering the Contract Area and/or the 3-D
Survey License Area processed (or reprocessed or both) separately and
independently from the entire 3-D Survey by a third party recognized as a
commercial seismic processor acceptable to SPR and the FINA GROUP provided that
the separate processing can be accomplished without interference or delay to the
processing activities of SPR and the FINA GROUP. If the FRONTIER GROUP so elects
to separately process (or reprocess) such partial information, and the FRONTIER
GROUP receives said processed (or reprocessed) data set prior to the time SPR
and the FINA GROUP receives an initially processed data set, over the Contract
Area, then the FRONTIER GROUP warrants that it shall deliver or cause to be
delivered a complete and fully processed copy of the separately processed (or
reprocessed) data set to SPR and each member of the FINA GROUP, at no cost to
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SPR or the FINA GROUP, by the accepted processor on the same day the separately
processed (or reprocessed) data set is first delivered or otherwise available to
any member of the FRONTIER GROUP. At such time as SPR and the FINA GROUP receive
a processed data set over the Contract Area, the FRONTIER GROUP's obligation to
deliver copies of its processed (or reprocessed) data set over the Contract Area
to SPR and the FINA GROUP shall cease.
8 .4 Acquisition of Other Necessary Geophysical Permits. FINA, as Operator,
shall proceed with diligent efforts to acquire the necessary permits from
adjacent and surrounding land owners to legally shoot the 3-D Survey and, once
such permits are obtained, to complete said survey. In the event SPR and the
FINA GROUP cannot acquire and process the 3-D Survey within 270 days from the
Effective Date of this Agreement, then the following options shall apply:
(A) If at the end of the 270 day period a seismic crew is in the Contract
Area diligently acquiring 3-D seismic data then the time period within
which the data shall be completed and delivered shall be extended for such
time as is necessary in order for FINA to acquire and process said data,
provided that operations for such acquisition and processing shall be
continued with all due diligence and without material interruption; or
(B) If at the end of the 270 day period a crew is not in the Contract Area
acquiring 3-D seismic data and its failure to do so is not caused directly
or indirectly or arising out of or in connection with the fault, action or
inaction by any member of the FRONTIER GROUP, then this Agreement shall
terminate and SPR, the FINA GROUP and the FRONTIER GROUP shall cross-assign
any and all permits which they may have (or in the case of FINA Fee Lands
said permits shall be granted) at that time to acquire 3-D on lands owned
or controlled by such groups within the Contract Area; or
(C) If the failure to have the 3-D seismic data acquired and processed
within the 270 day period is attributable in any manner, whether directly
or indirectly or arising out of or in connection with some action or
inaction or fault of any member of the FRONTIER GROUP, then the time period
within which FINA may acquire and process the 3-D seismic data shall be
automatically extended to the length of time required to complete any
operation as the result of any delay by the FRONTIER GROUP; or
(D) If the 3-D seismic information is not acquired and processed within the
270 day period and such delays are not attributable to the fault or action
or inaction of any member of the FRONTIER GROUP, the parties may agree by
mutual consent to extend the 270 day period, and in such event, to the
extent that the extension of time requires the expenditure of additional
costs in order to maintain Leasehold interests or options or permits on the
FRONTIER GROUP leases, then SPR will bear and pay 16.67% and the FINA GROUP
will bear and pay 33.33% of all such costs, respectively.
8.5 Ownership of Acquired Data. Notwithstanding anything contained herein
to the contrary, no seismic data within the Contract Area or the 3-D Survey
License Area acquired pursuant to this Agreement shall be sold, licensed or
otherwise made available to any person or entity not a party to this Agreement
during the term of this Agreement; provided however, regardless of any provision
of this Agreement to the contrary, that the FRONTIER GROUP shall have the right
to make available to Laurent Oil & Gas, Inc. ("Laurent") such 3-D seismic data
as is called for in the Laurent Agreement under terms as set forth therein, and
in the event Laurent exercises his look-back right (as said rights are set forth
in the Laurent Agreement) as regards to the FRONTIER GROUP's interest herein,
Laurent will have pro rata rights to the 3-D data set forth in this Agreement as
if Laurent were part of the FRONTIER GROUP and a party hereto. All seismic data
and all information related thereto within the Contract Area and the 3-D Survey
License Area acquired pursuant to this Agreement and any and all proceeds, value
and/or other consideration arising therefrom, regardless of the selling party,
shall be owned jointly twenty-five percent (25%) by SPR, fifty percent (50%) by
the FINA GROUP and twenty-five percent (25%) by the FRONTIER GROUP as set forth
proportionateley on Exhibit "B-1" hereto, from the Effective Date through such
time as SPR and the FINA GROUP have recouped all costs they have incurred in
connection with obtaining such seismic data within the area required to obtain
full fold coverage of the Contract Area. After SPR and the FINA GROUP have
recouped all of such costs, said seismic data and all benefits and/or proceeds
derived therefrom, shall be jointly owned 16.67% by SPR, 33.33% by the FINA
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GROUP and fifty percent (50%) by the FRONTIER GROUP.
8.6 Allocation of Seismic Data Sales Proceeds. Following the termination of
this Agreement all seismic data and all information related thereto within the
Contract Area acquired pursuant to this Agreement shall be and remain the joint
property of SPR, the FINA GROUP and the FRONTIER GROUP, and shall be kept
confidential and shall not be licensed, sold, published or disclosed to any
third party, without the prior written approval of a group of SPR and members of
the FINA GROUP and the FRONTIER GROUP, then holding seventy five percent 75% or
more of the total seismic data ownership as set forth on Exhibit "B-1". If after
the termination of this Agreement, the parties holding the requisite interest
agree to license all or a portion of the data, then any monies or benefit
received from the marketing of said data (after approval) shall be shared by
SPR, the FINA GROUP and the FRONTIER GROUP on the basis of their interest
therein at the time of such sale or license. Notwithstanding any provision
hereof to the contrary, SPR and the FINA GROUP shall be the owner of the data
within the 3-D Survey License Area, but the FRONTIER GROUP shall be granted a
license to use such data. Said license shall be in the form attached hereto as
Exhibit "D". All monies and other consideration due any party hereto for the
sale or other disposition of such seismic data shall be paid to the applicable
parties within ten (10) days of the selling party's receipt thereof.
8.7 Applicability After Termination. The provisions of Section 8.5 and 8.6
shall survive and remain valid and binding following termination of this
Agreement.
ARTICLE 9
LEASE ACQUISITION AND DRILLING OPERATIONS
9.1 AMI. Should any party to this Agreement obtain or have the opportunity
to obtain an interest in minerals, an oil and gas lease, an option to lease or
contractual right to explore for and/or produce oil and gas or similar
interest(s) within the Contract Area (the "Available Interests") which interests
are not FRONTIER GROUP Leases or FINA GROUP Leases then SPR and each member of
the FINA GROUP and the FRONTIER GROUP shall have the option to participate in
the acquisition of the Available Interests as to SPR's and each member's
respective share of its group's interest(s) as set forth in Exhibit "B" hereto.
In such event, the party acquiring or having the opportunity to acquire the
Available Interests shall offer in writing, as soon as possible but in any event
within ten (10) business days of acquiring such Available Interest(s), to all
other parties hereto, the option to participate in such acquisition. The cost of
any such acquisition shall be borne fifty percent (50%) by the FRONTIER GROUP,
16.67% by SPR and 33.33% by the FINA GROUP, notwithstanding the division of
working interest for each party or group as set forth on Exhibit "B". SPR and
each group shall have thirty (30) days after receipt of written notice of the
right to participate in the acquisition of the Available Interests (which notice
shall include all information relevant to such determination such as the
acquisition cost and any obligations involved), in which to elect in writing to
purchase all or part of its proportionate share of the Available Interest.
Should any party of either group elect not to participate in the acquisition of
its proportionate share of the Available Interest, then such party's share shall
be made available first to the other members of the group of which such party is
a member. To the extent that the remaining members of such group do not elect to
acquire the interest of any of its non-participating members, then the
Designated Member of such group shall give written notice to SPR and each of the
members of the other group of the availability of such interest. Such notice
shall be given at the same time as the election to participate for all or part
of the available interest is due to be delivered pursuant to this paragraph.
Should SPR elect not to participate in the acquisition of its proportionate
share of the Available Interest, then SPR shall give written notice to each of
the members of the FINA GROUP and the FRONTIER GROUP of the availability to its
interest.
9.2 Election Notice The election by SPR and/or either group to purchase any
share of the Available Interest shall be evidenced by a timely written election
which shall state specifically whether SPR or the group is taking all or only a
part (and if only a part, the percentage being taken) of its share of the
Available Interest, which election shall be submitted with payment by SPR or the
Designated Member of such group of its proportionate share of the acquisition
cost (which shall be 16.67% to SPR, 33.33% to the FINA GROUP and fifty percent
(50%) to the FRONTIER GROUP if SPR, the FINA GROUP and/or the FRONTIER GROUP
take their entire share of the Available Interest). Failure by SPR or the
Designated Member of the applicable group to timely respond or make the required
payment shall be deemed an election by SPR and all members of such group not to
participate. Any party hereto receiving notice of the availability of a share
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of the Available Interest which has been declined by all of the members of the
other group (the "Additional Interest") shall have five (5) days after receipt
of such notice within which to elect whether or not to participate for its
pro-rata share of the Additional Interest by giving written notice of its
election to the SPR and Designated Member of each group. In the event that a
party hereto elects to acquire a portion of the Additional Interest then such
acquiring party shall pay a share of the costs attributable to that interest
equal to the costs which would have been paid had the interest been acquired by
the party to whom it was initially offered. In the event a well is being drilled
pursuant to the terms of a JOA whose contract area includes all or part of the
Available Interest, the time period for the initial election and payment shall
be five (5) working days from the receipt of the pertinent information, instead
of the twenty days previously set out above. In the event SPR and/or both groups
acquire their proportionate share of the Available Interest, said interest
immediately and automatically shall become subject to this Agreement and any
existing JOA's, as applicable, for all purposes. The Designated Members shall be
responsible for the diligent and timely communication of all information and
election notices to the members of their group, SPR and the Designated Member of
the other group.
9.3 Designation of a Prospect Area, Well Proposals and Elections For
Participation. At any time after delivery to all of the parties hereto of the
fully processed data set covering the Contract Area, any party to this
Agreement, who owns a then current working interest therein, may propose
hereunder the designation of a Prospect Area within the Contract Area, and the
drilling of a well within such Prospect Area ("Initial Test Well"). For purposes
hereof "Prospect Area" shall mean a specified geographical area under which is
thought to exist one or more subsurface or geological features which the
parties, through geological interpretation, believe to be capable of structural
or stratigraphic trapping of oil and gas in economic quantities. Any given
Prospect Area shall represent the parties' best efforts to identify and define
the surface area encompassing the entirety of all reservoirs reasonably expected
to be proven by the wellbore of the Initial Test Well. The designation of a
Prospect Area shall be evidenced in writing and may be changed thereafter based
on new information or revisions of interpretations of old information and/or by
actions of a governing body having or asserting jurisdiction. The proposing
party shall notify each party hereto in writing of its proposal and call a
meeting of the parties within ten (10) days after said notification. In the
meeting the proposing party shall present to SPR and the members of each group
all relevant data to support its proposed designation of a Prospect Area and
drilling of the Initial Test Well and will include in its presentation the depth
to be drilled, the primary objective and all other horizons likely to be tested,
detail estimated drilling and completion costs and a drilling prognosis of the
proposed Initial Test Well. The party proposing the designation of a Prospect
Area shall attempt in good faith to obtain the approval of such Prospect Area by
all of the parties to this Agreement. In the event all the parties do not agree
to the designation of the applicable reservoir limits as proposed in any given
Prospect Area, then the vote of the parties holding cumulatively 75% of the
working interest in all depth through the base of the Duval Sand as set forth at
Exhibit "B" hereto as to those depths, and the vote of the parties holding
cumulatively 75% of all the working interests in all depths from the base of the
Duval Sand through the base of the DuLarge Sand as set forth at Exhibit "B"
hereto as to those depths, and the vote of the parties holding cumulatively 75%
of all of the working interest in all depths below the base of the DuLarge Sand
as set forth in Exhibit "B" hereto as to those depths, as regards each of such
reservoirs reasonably expected to be proven by the wellbore of the Initial Test
Well, shall be deemed binding on all of the parties hereto as to the designation
of each such reservoir to be established within the Prospect Area. The Prospect
Area shall encompass the largest overall reservoir limits within its confines.
There shall be no more than three Initial Test Wells proposed or drilling
to casing point election within the Contract Area at a time. Of the three
Initial Test Wells which may be proposed or drilling simultaneously, there may
be no more than (i) two (2) proposed or drilling to a depth above the base of
the DuLarge Sand, or (ii) two (2) below the base of the DuLarge Sand such that
the parties shall have the right to propose or drill one shallow well or one
deep well, as applicable, at all times. In addition thereto, to the extent the
FRONTIER GROUP proposes to drill any wells to the base of the Duval Sand or
shallower, as set forth at Exhibit "B", solely on FRONTIER GROUP Leases and
solely within the areas colored in green on the attached Exhibit "A", it may
propose and drill any number of such wells and such wells shall not be counted
to reduce the number of wells drilled pursuant to this provision. Inasmuch as
SPR or any member of the FINA GROUP proposes to drill any well on the FINA Fee
Lands from the base of the Duval Sand to all deeper depths and/or on FINA GROUP
leases to all depths, it may propose and drill any number of such wells and such
wells shall not be counted to reduce the number of wells drilled pursuant to
this provision. Any proposal made in contravention of this provision shall be
void and require no response by any party.
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9.4 Election Options. The parties not proposing the drilling of the Initial
Test Well shall have the following options, which options must be elected within
the time notices contained in Article 12:
A. (i) elect not to participate in the Initial Test Well as to any depth ("No
Participation"),
i) elect to participate in the Initial Test Well in the manner and
to the total depth proposed ("Full Participation"),
ii) elect to limit its agreement for participation to a shallower
objective (the "Alternate Depth") than the total depth proposal
("Depth Limited Participation") or
iii) propose that the Initial Test Well be drilled to a depth below
the depth originally proposed ("Proposal to Deepen"); provided
however, that any well proposed to be drilled to a proven
underdeveloped location, which location is located solely within
the areas colored in green on Exhibit "A" attached hereto, shall
not be subject to any such proposals to deepen.
The consequences corresponding to the election of each of the options
described in Article 9.4A. above by any party(ies) or either group hereto are as
follows:
B. (i) No Participation. In the event any party elects No Participation in
the Initial Test Well in any Prospect Area and the participating
parties proceed to drill such Initial Test Well, the non-participating
party shall be deemed to have farmed out to the remaining parties its
interest in the reservoir(s) that are proven, by the Initial Test Well
or the stratigraphic equivalent thereof, and that are within the
applicable Prospect Area, on the terms set forth in Section 9.5 below.
(ii) Full Participation. If the parties elect Full Participation each party
shall participate in the Initial Test Well as proposed and shall bear
their respective share of the cost thereof. The parties shall also
enter into a mutually agreeable form of operating agreement for such
well and if no agreement can be reached the operating agreement will
be in the form of the JOA.
(iii)Depth Limited Participation. If any non-proposing party elects Depth
Limited Participation (the "Uphole Participant(s)"), it shall notify
the proposing party of such election and of the Alternate Depth to
which the Uphole Participant has elected to participate. The Uphole
Participat by making such limited election and paying its
proportionate share of drilling costs to the Alternate Depth, shall
have preserved all of its rights to receive a lease or assignment as
provided herein for all depths above 100 feet below the Alternate
Depth in the Prospect Area or the stratigraphic equivalent thereof.
The Uphole Participant will be deemed to have farmed out its interests
to all depths deeper than one hundred (100) feet below the Alternate
Depth or the stratigraphic equivalent thereof, within the Applicable
Prospect Area according to the provisions set forth in Section 9.5
below.
(iv) Proposal to Deepen. Any non-proposing party(ies) may respond to the
original proposal by proposing to drill the well to a depth below the
depth originally proposed (the "Downhole Participant(s)"), by
submitting a proposal for drilling to the deeper depth within the ten
(10) business days of its receipt of the original proposal. The
Proposal to Deepen shall be then deemed a proposal made under and
subject to the time periods and other provisions set forth in this
Article 9 and in Article 12. The Proposal to Deepen shall be
considered, and operations in furtherance thereof conducted, in
priority to the original proposal.
9.5 Farm out Terms. In the event any party shall be deemed to have farmed
out ("Farmor") to the other Parties ("Farmee") its working interest in any
reservoir(s) within the Prospect Area, the interest farmed out shall be limited
to rights which are:
1. within the Prospect Area, and
2. limited to rights from the surface to a depth 100 feet below the base
of the deepest commercially
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productive reservoir in the Initial Test Well, and
3. limited to interests which appear productive in the wellbore of the
Initial Test Well, and
4. limited geographically to locations classified "proven" by the Initial
Test Well pursuant to generally accepted engineering standards as
accepted by the United States Securities and Exchange Commission for
publicly reporting companies.
To the extent interests are thereby farmed out the Farmor shall retain an
overriding royalty interest in such reservoir(s) equal to two percent (2%),
which retained interest shall be reduced in the same proportion as the working
interest farmed out bears to 100%. In the event the parties cannot agree as to
which interests are "proven" by the Initial Test Well, the consulting firm of
Ryder Scott Company Petroleum Engineers of Houston, Texas shall by retained to
make such determination with the cost thereof shared by the parties. The
decision of Ryder Scott Company Petroleum Engineers shall be accepted as
conclusive by all of the parties hereto. At Payout of the Initial Test Well, the
Farmor shall have the option to convert its retained overriding royalty interest
in such well to a working interest in the applicable reservoir(s) equal to
thirty percent (30%) of the working interest originally owned by the Farmor and
farmed out hereunder. In the event the farmor elects to convert its overriding
royalty interest in such well to a working interest at Payout, said working
interest shall be subject to a mutually agreeable form of operating agreement
and if no agreement can be reached the operating agreement shall be in the form
of the JOA. However, the Farmor shall have the option to participate for its
after Payout working interest in such farmed out reservoir(s) within such
Prospect Area in all wells proposed after the Initial Test Well in said Prospect
Area is spud, regardless of whether Payout in the Initial Test Well in such
Prospect Area has been achieved and whether or not Farmor has elected to convert
its overriding royalty interest to a working interest in the Initial Test Well.
9.6 Elections on a Group Basis. If any member(s) in any group elects not to
participate, then the interest of such non-participating member shall be offered
first to the other members of its group in accordance with agreements among such
members. If the remaining member(s) of such group do not assume the interest of
the declining member in their group then the Designated Member of such group
shall send written notice to SPR and all of the members of the other group
stating that such interest is available. The proposing party or its designee,
provided that the proposing party owns a working interest at the deepest depth
proposed to be drilled to in such well, regardless of whether the well is to be
or actually is completed at such depth equal to or greater than any other party
at such deepest depth, shall automatically be designated as the Operator of the
Prospect Area for said Initial Test Well and the applicable Prospect Area for
all drilling and production operations therein. Should the proposing party not
own sufficient working interest to automatically qualify as Operator, then the
Downhole Participants in said Initial Test Well shall elect an Operator for said
well and Prospect Area. For the purposes of this provision as it pertains to
wells drilled on FRONTIER GROUP Leases ONLY, the parties agree that SPR or a
member of the FINA GROUP shall always be designated as Operator of any well
drilled to or below the base of the DuLarge Sand, and that a member of the
FRONTIER GROUP shall always be designated as Operator of all wells drilled to
and completed at or above the base of the DuLarge Sand, as described at Exhibit
"B" hereto, unless otherwise agreed to the contrary in writing by all the
participating parties in said well.
9.7 Payments. In the event a Party elects Depth Limited Participation the
Operator shall bill and the Uphole Participant shall pay pursuant to the JOA,
its share of the costs which would have been necessary to drill, and plug and
abandon the Initial Test Well to the Alternate Depth only, on a stand alone
basis ("Base Costs") for drilling the well to the Alternate Depth. If the well
is plugged and abandoned, upon completion of such activities the Operator shall
bill and the Uphole Participant shall pay or receive a credit as applicable
pursuant to the JOA, for its actual share of the Base Costs for plugging and
abandonment. Any costs whatsoever incurred over Base Costs, including by way of
example but without limitation, costs incurred for additional drilling, for
different or additional above ground or downhole equipment, for sidetrack or
other drilling or equipment problems or for additional time, any of which is
incurred due to drilling beyond the Alternate Depth shall be borne one hundred
percent (100%) by Downhole Participants.
For all purposed of this Article 9, the Operator shall within five (5)
business days from the filing of a completion report with the State of
Louisiana, reimburse the Uphole Participants their proportionate share of
drilling costs to the Alternate Depth in a deepened well if and when any horizon
is completed in such deepened well as a commercial producer at a level deeper
than the level at which the Uphole Participants own a working interest. Any
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Uphole Participant shall have the right to propose a well(s) within the unit
boundary of the completed deepened well to test a shallower horizon to which its
participation had been limited (the "Accelerated Well"), but only to the extent
that the Uphole Participants participating in such Accelerated Well(s) agree to
and pay for the Downhole Participants' (participating in such Accelerated
Well(s)) proportionate share of drilling costs to the casing point election. All
Downhole Participants in the deepened well shall have the right to participate
in such Accelerated Well(s). Should the Uphole Participants participating in
such an Accelerated Well(s) actually drill and pay for the participating
Downhole Participants' share of said drilling costs, then (a) said participating
Uphole Participants shall not be required to contribute or reimburse to any
Downhole Participant any costs for the deepened well, except for costs
associated with a completion attempt(s) to which said participating Uphole
Participants consent to and which are at or above the deepest horizon in which
they own a working interest, and (b) the Downhole Participants participating in
an Accelerated Well shall not be required to contribute or reimburse to the
Uphole Participants any costs for the Accelerated Well, except for costs
associated with a completion attempt(s) to which said participating Downhole
Participants consent to in such Accelerated Well.
If a deepened well is subsequently plugged back and completed at or above
the Alternate Depth, the Operator shall bill, and all Uphole Participants who
have not participated in any Accelerated Well(s) within the unit boundary of the
completed deepened well shall pay, their share of the calculated Base Costs for
(i) the drilling to the Alternate Depth and (ii) (subject to the casing point
election in the Operating Agreement) completion of such deepened well at the
shallower recompleted depth. In such instance, the calculated Base Costs shall
be equal to the costs which would have been incurred had the well been drilled
and completed at the shallower recompleted depth at the time the well was
originally drilled. One hundred percent (100%) of such reimbursed Base Costs
shall be allocated and paid by the Operator of the deepened well to the Downhole
Participants in said deepened well who have not participated in any Accelerated
Well within the unit boundary of the deepened well, prorata based on the ratio
that each such Downhole Participant's working interest bears to the total
working interests of all such Downhole Participants who have not participated in
any Accelerated Well. To the extent that all Downhole Participants in the
deepened well have participated in one or more Accelerated Well(s) within the
unit boundary of the deepened well, then one hundred percent (100%) of such
reimbursed Base Costs shall be allocated proportionateley among the Downhole
Participants in the deepened well based on their working interests.
9.8 Joint Operating Agreements. Any and all operations for the drilling of
the Initial Test Well which are not specifically covered by the terms of this
Agreement, and any and all operations in a Prospect Area (or the contract area
under a specific JOA) subsequent to the drilling of the Initial Test Well shall
be performed pursuant to the terms of the applicable JOA. Each of the parties to
this Agreement who participated in any operation in a well or wells within a
Prospect Area shall also be parties to the applicable JOA. Each Designated
Member shall provide a designation of interest to each other party hereto
outlining the percentage which each member in the Designated Member's respective
group shall participate in any particular ongoing or proposed operation at such
time as said operations(s) are proposed. In addition to the other provisions
which may be contained in each JOA which is entered into or made effective
pursuant to this Agreement, it shall also contain restrictions on certain
drilling activities following the drilling of a well in a Prospect Area as
follows. The JOA shall have no restriction on the number of wells, reworking
operations, completion or other operations which may be proposed at any one
time.
ARTICLE 10
RELATIONSHIP OF THE PARTIES
Except as expressly stated otherwise herein, the rights, duties,
obligations and liabilities of the parties hereunder shall be several, not joint
or collective. It is not the purpose or intention of this Agreement to create
any mining partnership, commercial partnership or other partnership relation and
none shall be inferred from the agreement to file an election to be excluded
from the application of certain United States tax laws. Each party agrees to
elect to be excluded from the application of Subchapter K of Chapter 1 of
Subtitle A of the Internal Revenue Code of 1954, and all amendments thereto.
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ARTICLE 11
ASSIGNABILITY AND CONFIDENTIALITY
11.1 Limited Assignability. The rights, benefits and obligations of this
Agreement are exclusive between SPR, the members of the FINA GROUP and the
members of the FRONTIER GROUP. SPR and the FINA GROUP reserve the right to
approve the assignment of any interest in the Agreement from any member of the
FRONTIER GROUP to any other unrelated party and the FRONTIER GROUP reserves the
same right to approve such an assignment from any member of the FINA GROUP.
Neither SPR, nor the FINA GROUP or the FRONTIER GROUP shall unreasonably deny
any request to assign an interest to an unrelated party, provided that the
unrelated third party is, in the approving group's sole opinion, at least as
financially capable as the assigning party to perform the obligations to be
assigned, or if the assignment provides that the assigning party shall remain as
guarantor of it's assignee. Notwithstanding the above, SPR and the FINA GROUP,
by execution of this Agreement, consents to any assignment from South Coast
Exploration and SOCO Exploration Limited Partnership to Harcor Energy, Inc., and
to any assignments and rights the FRONTIER GROUP may be obligated to convey
pursuant to the Laurent Agreement. It being fully understood and agreed that any
assignment from South Coast Exploration, SOCO Exploration Limited Partnership or
the FRONTIER GROUP will be made expressly subject to this 3-D SEISMIC
PARTICIPATION AGREEMENT and will not affect the rights and interest of SPR or
the FINA GROUP.
11.2 Confidentiality. SPR and each member of the FINA GROUP and the
FRONTIER GROUP agree to hold confidential all information and data arising from
or related to this Agreement and the 3-D Survey, including the terms of the
Agreement itself, and not to divulge any facts hereof to any unrelated party,
except as may be required to satisfy any local, state or federal government
regulation, or for the business purpose of selling an interest in this Agreement
to an unrelated party. This confidentiality provision shall extend to all JOA's
covering the Contract Area and/or any well(s) drilled thereon and will not
terminate until the expiration of this Agreement, or the expiration of any lease
granted or acquired within the Contract Area pursuant hereto, whichever is
later.
ARTICLE 12
NOTICE
Any notices authorized or required herein shall be given by the proposing
party to all other parties hereto and will have an initial response period of
thirty (30) days from receipt of said notice, unless specifically stated
otherwise herein. Should the proposing party not receive a timely response from
SPR or the applicable Designated Member hereto, then in such event, the
proposing party shall notify all other parties hereto that the response period
shall be extended for an additional ten (10) day period allowing SPR or either
group additional time to review or confer with its Designated Member and
respond. In the event there is no response delivered to the proposing party by a
non-proposing party or Designated Member within said ten (10) day extension
period, the proposing party will notify all other parties hereto that a final,
additional forty-eight (48) hour extension period will be granted prior to
deeming any non-responding party(ies) non-consent. It is expressly acknowledged
that this provision does not apply to notices issued pursuant to any JOA entered
into and effective pursuant hereto, in which regard the notice provision shall
be as set forth in said JOA. The aforementioned notice periods (thirty (30)
days, ten (10) days, and forty-eight (48) hours) are not applicable to the
notices and/or election periods described in Sections 1.13, 7.2, 7.3, 8.6, 9.1,
9.2, 9.3, and 9.7 contained herein.
All notices hereunder shall be deemed to be properly given, if in writing,
by facsimile transmission, if followed by postpaid registered or certified mail,
or by courier delivery, addressed to the respective party at the addresses as
set forth below, or such other addresses as they shall respectively hereafter
designate in writing, from time to time:
As to the FINA GROUP: FINA Oil and Chemical Company
P. O. Box 62102
Houston, Texas 77205-2102
or
14950 Heathrow Forest Parkway
Houston Texas 77032
14
<PAGE>
(713) 986-6000
(713) 986-6736 Fax
As to the FRONTIER GROUP: Frontier Natural Gas Corporation
9400 North Broadway Extension
Oklahoma City, Oklahoma 73114
(405) 478-4455
(405) 478-4456 Fax
As to the
SOUTH COAST EXPLORATION COMPANY: South Coast Exploration Company
Two Post Oak Central
1980 Post Oak Boulevard
Suite 2050
Houston, Texas 77056
(713) 960-1077
(713) 960-1157 Fax
As to the SOCO EXPLORATION L.P.: Two Post Oak Central
1980 Post Oak Boulevard
Suite 2050
Houston, Texas 77056
(713) 960-1077
(713) 960-1157 Fax
As to the MATAGORDA PRODUCTION COMPANY:Matagorda Production Company
675 Bering Drive, Suite 850
Houston, Texas 77057
(713) 781-4975
(713) 781-1460 Fax
As to the
POLARIS EXPLORATION CORPORATION: P. O. Box 2080
Beeville, Texas 78104-2080
(512) 362-2149
(512) 362-1826 Fax
As to the DENBURY MANAGEMENT INC.: Denbury Management, Inc.
17304 Preston Road, Suite 200
Dallas, TX 75252
(214) 380-1923
(214) 380-6967 Fax
As to the
SCANA PETROLEUM RESOURCES, INC.: SCANA Petroleum
Resources, Inc.
1200 Smith Street, Suite 500
Houston, Texas 77002-4308
Attn: President
(713) 658-8585 Phone No.
(713) 658-1825 Fax No.
ARTICLE 13
FORCE MAJEURE
15
<PAGE>
If any party is rendered unable, wholly or in part, by force majeure to
carry out its obligations under this Agreement, other than the obligation to
make money payments, that party shall give to SPR and the Designated Member of
each group prompt written notice of the force majeure with reasonably full
particulars concerning it (who shall each, in turn, inform the members of its
group). Thereupon, the obligations of the party giving the notice, so far as
they are affected by the force majeure, shall be suspended during, but no longer
than, the continuance of the force majeure. The affected party shall use all
reasonable diligence to remove the force majeure situation as quickly as
practicable. The requirement that any force majeure shall be remedied with all
reasonable dispatch shall not require the settlement of strikes, lockouts, or
other labor difficulty by the party involved, contrary to its wishes; how all
such difficulties shall be handled shall be entirely within the discretion of
the party concerned. The term "force majeure", as here employed, shall mean an
act of God, strike, lockout, or other industrial disturbance, act of the public
enemy, war, blockade, public riot, lightening, fire, storm, flood, explosion,
governmental action, governmental delay, restraint or inaction, unavailability
of equipment, and any other cause, whether of the kind specifically enumerated
above or otherwise, which is not reasonably within the control of the party
claiming suspension.
ARTICLE 14
ENTIRETY OF AGREEMENT
This Agreement represents the entire understanding and agreement between
SPR, the FINA GROUP, and the FRONTIER GROUP regarding the matters set forth
herein and supersedes any and all prior discussions, proposals, understandings
agreements or representations, if any, by either SPR, the FINA GROUP or the
FRONTIER GROUP to another. Notwithstanding any provision of this Agreement to
the contrary, it is specifically acknowledged and understood that a Joint
Exploration and Development Agreement dated March 29, 1995, by and between FINA
and SPR ("FINA/SPR Agreement") and an Agreement dated May 30, 1996 by and among
FINA, SPR and DENBURY ("FINA/SPR/DENBURY Agreement") also exist. The parties
further acknowledge and understand that an Exploration Agreement dated February
19, 1996 between Polaris Exploration Corporation, South Coast Exploration
Company, SOCO Exploration L.P., Frontier Natural Gas Corporation and Matagorda
Production Company (the "FRONTIER GROUP Agreement") also exists. Each of such
agreements provide for rights and obligations between and among the respective
parties thereto related to operations for obtaining 3-D Seismic, the ownership
of such information, the acquisition and granting of leases or assignments of
interests in leases or minerals and the participation in drilling of wells,
which agreements cover acreage within the Contract Area. This 3-D Seismic
Participation Agreement is not intended in any manner or respect to amend, alter
or add to the provisions of either the FINA/SPR Agreement or the
FINA/SPR/DENBURY Agreement and specifically as related to the rights and
responsibilities of the parties to those agreements, any conflict between the
terms of either the FINA/SPR Agreement or the FINA/SPR/DENBURY Agreement and
this Agreement shall be governed by the terms of the FINA/SPR Agreement or the
FINA/SPR/DENBURY Agreement as applicable. This 3-D Seismic Participation
Agreement is not intended to amend, alter or add to the provisions of the
FRONTIER GROUP'S Agreement, and specifically as between the parties thereto
their relationship shall be governed thereby to the extent possiblThis Agreement
shall be binding upon and inure to the benefit of the parties hereto and their
respective successors and assigns; provided, however, nothing herein contained
shall be construed as permitting an assignment contrary to the foregoing terms,
conditions and provisions of this Agreement.
IN WITNESS WHEREOF, this agreement is executed on this the 20th day of
August, 1996, but effective as of May 30, 1996.
FINA AND CHEMICAL COMPANY
illegible BY: /s/ W. E. Franklin
- ------------- -----------------------------------------
W. E. Franklin
illegible Attorney-in-Fact
- -------------
SCANA PETROLEUM RESOURCES, INC.
illegible BY: /s/ Jim Cantwell
- ------------- -----------------------------------------
Jim Cantwell
illegible President
- -------------
16
<PAGE>
DENBURY MANAGEMENT, INC.
illegible BY: /s/ Matthew Deso
- ------------- -----------------------------------------
Matthew Deso
illegible Vice President
- -------------
FRONTIER NATURAL GAS CORPORATION
ilegible BY: /s/ David W. Berry
- -------------- -----------------------------------------
David W. Berry
illegible President
- --------------
SOUTH COAST EXPLORATION COMPANY
illegible BY: /s/ Ron A. Krenzke
- -------------- -----------------------------------------
Ron A. Krenzke
illegible President
- --------------
SOCO EXPLORATION L.P.
illegible BY: /s/ illegible
- -------------- -----------------------------------------
illegible General Partner
- --------------
MATAGORDA PRODUCTION COMPANY
illegible BY: /s/ Hershel Ferguson
- -------------- -----------------------------------------
Hershel Ferguson
illegible President
- --------------
POLARIS EXPLORATION CORPORATION
illegible BY: /s/ illegible
- -------------- -----------------------------------------
illegible President
- --------------
17
EXHIBIT 11 TO FORM 10-KSB
FRONTIER NATURAL GAS CORPORATION
Computation of Net Income per Common and Common Equivalent Share
Year ended December 31,
-----------------------------
1996 1995
----------- -----------
Common shares issued and outstanding,
beginning 5,058,406 2,418,050
Add: Common stock issued 87,500 11,250
Subscribed stock issued - 90,450
Stock options and warrants(1) - -
Cumulative preferred stock conversion - 1,456,954
Secondary offering 1,996,150 -
----------- -----------
Total equivalent common shares 7,142,056 3,976,704
=========== ===========
Net income (loss) $(5,025,019) $(1,595,478)
Less: Cumulative preferred stock dividend 103,153 395,381
Less: Value of common stock issued for
cumulative preferred stock in excess
of original terms, net of relieved
preferred stock dividend - 2,183,471
----------- -----------
Net income (loss) applicable to common and
common equivalent shares $(5,128,172) $(4,174,330)
=========== ===========
Net income (loss) per common and common
equivalent share $ (0.72) $ (1.05)
=========== ===========
- ------------------------
(1) Common stock equivalents were determined based on the "Treasury Stock
Method" as set forth in Accounting Principles Board Opinion No. 15.
EXHIBIT 21 TO FORM 10-KSB
The subsidiaries of the Registrant are:
Name State of Incorporation
- ------------------------------------------------ ----------------------
Frontier, Inc. Oklahoma
Frontier Acquisition Corp. Oklahoma
Frontier Exploration and Production Corporation Oklahoma
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-mos
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 4,956,656
<SECURITIES> 0
<RECEIVABLES> 377,031
<ALLOWANCES> 10,533
<INVENTORY> 0
<CURRENT-ASSETS> 5,757,890
<PP&E> 6,354,842
<DEPRECIATION> (2,918,918)
<TOTAL-ASSETS> 9,631,192
<CURRENT-LIABILITIES> 1,661,730
<BONDS> 325,394
0
860
<COMMON> 98,659
<OTHER-SE> 6,639,307
<TOTAL-LIABILITY-AND-EQUITY> 9,631,192
<SALES> 3,176,861
<TOTAL-REVENUES> 3,378,792
<CGS> 0
<TOTAL-COSTS> 8,403,811
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 783,872
<INCOME-PRETAX> (5,025,019)
<INCOME-TAX> 0
<INCOME-CONTINUING> (5,025,019)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (5,025,019)
<EPS-PRIMARY> (0.72)
<EPS-DILUTED> (0.72)
</TABLE>
