SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
Commission File Number 0-6580
PEASE OIL AND GAS COMPANY
(Name of small business issuer as specified in its charter)
Nevada 87-0285520
State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
751 Horizon Court, Suite 203,
Grand Junction, Colorado 81506
(Address of principal executive offices) (Zip code)
(970) 245-5917
(Issuer's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
(None)
Securities registered pursuant to Section 12(g) of the Act:
Common Stock (Par Value $.10 Per Share)
Series A Cumulative Convertible Preferred Stock (Par Value $0.01 Per Share)
Common Stock Purchase Warrants (Expire August 13, 1998)
Title of Class
Indicate by check mark whether the issuer (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Exchange Act during the past
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 [ ]
The issuer's revenues for its most recent fiscal year were $4,659,309.
As of March 18, 1998 the issuer had 15,789,955 shares of its $0.10 par
value Common Stock issued and outstanding. Based upon the closing sale price of
$1.06 per share on March 18, 1998. the aggregate market value of the common
stock, the Registrant's only class of voting stock, held by non-affiliates was
$15,836,000.
Transitional Small Business Issuer Disclosure Format Yes [ ] No [X]
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TABLE OF CONTENTS
PART I Page
ITEM 1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
History and Overview . . . . . . . . . . . . . . . . . 1
Gulf Coast Efforts . . . . . . . . . . . . . . . . . . 1
Recent Developments . . . . . . . . . . . . . . . . . . 2
Business Strategy . . . . . . . . . . . . . . . . . . . 2
Operations. . . . . . . . . . . . . . . . . . . . . . . 3
Competition . . . . . . . . . . . . . . . . . . . . . . 4
Markets . . . . . . . . . . . . . . . . . . . . . . . . 4
Regulations . . . . . . . . . . . . . . . . . . . . . . 5
Operational Hazards and Insurance . . . . . . . . . . . 7
Administration. . . . . . . . . . . . . . . . . . . . . 7
ITEM 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Principal Oil and Gas Interests . . . . . . . . . . . . 7
Gulf Coast Properties and Prospects . . . . . . . . . . 8
Colorado Properties . . . . . . . . . . . . . . . . . . 10
Utah Properties . . . . . . . . . . . . . . . . . . . 11
Title to Properties . . . . . . . . . . . . . . . . . . 11
Estimated Proved Reserves . . . . . . . . . . . . . . . 11
Net Quantities of Oil and Gas Produced . . . . . . . . 12
Drilling Activity . . . . . . . . . . . . . . . . . . . 13
ITEM 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . . . . 13
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. . . . . . . 13
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS. . . . . . . . . . . . . . . . . . . . . . . 13
Market Information. . . . . . . . . . . . . . . . . . . 13
Stockholders. . . . . . . . . . . . . . . . . . . . . . 14
Dividends . . . . . . . . . . . . . . . . . . . . . . . 14
Recent Sales of Unregistered Securities . . . . . . . 14
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS . . . . . . . . . . . . . . 18
Liquidity and Capital Reserves. . . . . . . . . . . . . 19
Capital Expenditures . . . . . . . . . . . . . 20
Results of Operations. . . . . . . . . . . . . 21
Other Matters . . . . . . . . . . . . . . . . 27
ITEM 7. FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . . . . . . . 29
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . 49
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT. . . . . . . . 49
ITEM 10. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . 49
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT . 49
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . . . . . . . 49
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . 50
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PART I
ITEM 1 - BUSINESS
HISTORY AND OVERVIEW
Pease Oil and Gas Company ("Company"), was incorporated under the laws of the
state of Nevada on September 11, 1968 to principally engage in the oil and gas
acquisition, development and production business. Prior to 1993, the Company was
a relatively small operator conducting business primarily in Western Colorado
and Eastern Utah. However, on August 23, 1993, the Company acquired Skaer
Enterprises, Inc., a Colorado corporation, its related businesses and related
oil and gas properties (collectively "Skaer"). Skaer was privately owned and
operated, and was considered one of the largest private independent oil and gas
companies in Colorado, operating exclusively in the Denver-Julesburg Basin ("DJ
Basin") of northeastern Colorado. This acquisition substantially expanded the
Company's operations by increasing the number of wells operated and expanding
its services to include oil field services, oil field supplies, natural gas
processing and natural gas marketing. Skaer was acquired for $12,200,000,
including $300,000 of various costs associated with the acquisition. In the
years following the acquisition, the Company invested several million dollars in
an effort to exploit the assets acquired by Skaer and, unfortunately,
experienced marginal success. Recognizing the limited upside potential of these
assets, the Company initiated efforts in 1996 and 1997 to expand its resource
base through the acquisition and exploration of properties located in the Gulf
Coast region of Southern Louisiana and Texas.
GULF COAST EFFORTS
To establish an initial foothold in the Gulf Coast, the Company acquired a
7.8125% After Prospect Payout Working Interest and an additional 10% working
interest in the East Bayou Sorrel Prospect located in Iberville Parish,
Louisiana. These transactions were closed during the first quarter of 1997 at an
aggregate cost of $4.27 million (including $875,000 in common stock). This
prospect contains two discovery wells, the C.E. Schwing #1 and #2, which have
historically produced at an average rate in excess of 2,300 barrels of oil,
2,400 Mcf of natural gas, and 860 barrels of water per day representing
approximately 25% of the Company's current net average daily production. The 3-D
survey discussed later in this section under the caption "Recent Developments"
should greatly enhance the ultimate development and exploration efforts of this
prospect.
On February 4, 1997 the Company entered into a definitive exploration agreement
with National Energy Group, Inc. ("NEGX"), a publicly held company headquartered
in Dallas, Texas, the operator of the East Bayou Sorrel Prospect. The Agreement
provided the Company the right and obligation to participate in certain
exploration projects initiated over the course of a two-year period. The
Company's obligation under the Agreement ends on February 4, 1999. The working
interest percentage committed to under the Agreement was generally 12.5% but has
varied on a prospect by prospect basis, ranging from 9.375 to 20% to date.
During 1997 and through the date of this report, the Company participated in the
drilling of 10 wells under the terms of the Agreement with NEGX. Of the 10 wells
drilled, 7 were dry, 1 in East Bayou Sorrell has been temporarily abandoned
waiting on seismic information, and 2 resulted in modest discoveries. Nine of
the ten wells that commenced drilling in 1997 were based on either 2-D data or
other conventional geologic methods. In order to increase the probability of
future success, most, if not all, of the remaining wells to be drilled under the
term of Agreement will be based on the disciplined use of 3-D seismic and other
advanced exploration technology.
In addition to the agreement with NEGX, the Company has pursued other
exploration opportunities with various industry partners. For instance, during
the third quarter of 1997, the Company signed various exploration agreements
regarding a joint venture with Parallel Petroleum Corporation ("Parallel"), a
publicly held entity headquartered in Midland, Texas. Pursuant to the terms of
the agreements, the Company owns a 12.5% working interest in three separate 3-D
seismic exploratory projects covering 130,000 acres in and around Jackson
County, Texas. The exploration efforts will focus within the Yegua/Frio/Wilcox
geological trend. The Company decided to pursue the joint venture with Parallel
based on Parallel's history of success in the Yegua/Frio/Wilcox Trend where,
between October 1994 and December 1997, utilizing 3-D seismic imaging and other
new technologies, Parallel participated in drilling over 60 exploratory wells,
with a success rate of approximately 80%. Beginning with the seismic operations
which commenced in August 1997, the projects contemplated in the agreements with
Parallel will span the course of the next two to three years with drilling
expected to commence in the second quarter of 1998.
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Contingent on the result of the seismic surveys, as many as 60 or 70 wells may
ultimately be drilled. The Company invested approximately $3.2 million in these
projects in 1997.
During 1997, the Company was also successful in negotiating the right to
participate in an exploration project operated by Amerada Hess Corporation. This
project, known as the Maurice Prospect, is located in Vermilion Parish,
Louisiana, and was purchased from Davis Petroleum ("Davis"), a privately held
corporation located in Houston, Texas, when Davis elected to sell a portion of
its interest in exchange for a farmout agreement on another property owned by
the Company. During 1997, one successful well was drilled and is currently being
recompleted with production expected to commence during the second quarter of
1998. In January 1998, a second well commenced drilling operations and reached
its proposed target depth of 16,300 feet in March 1998. Based on the electric
logs, casing is currently being set and a production test is expected during the
second quarter of 1998. The Company anticipates one or two additional wells will
be drilled on this prospect in 1998.
RECENT DEVELOPMENTS:
Participation in Bayou Sorrel 3-D Area
On January 21, 1998, the Company entered into a definitive agreement with NEGX
to participate as a 14.0625% working interest owner in a 3-D survey covering
54-square mile area surrounding the Bayou Sorrel Field in Iberville Parish,
Louisiana (referred to herein as "Bayou Sorrel 3-D Area"). The 3-D survey was
initiated in 1997 and the initial cost of $1,228,510 included the Company's
proportionate share of the 3-D seismic survey and the existing land costs. This
Bayou Sorrel 3-D Area not only encompasses the Company's current interest in the
East Bayou Sorrel Prospect where, as discussed previously, a 10% working
interest and a 7.8125% After Prospect Payout Working Interest was acquired by
the Company in the first quarter of 1997, but greatly increases the area of
potential future prospects. Although this participation in the Bayou Sorrel 3-D
Area will not increase the Company's ownership in the East Bayou Sorrel
Prospect, it will increase the ownership percentage in any prospects generated
from the 3-D survey outside of the East Bayou Sorrel Prospect and within the
boundaries of the Bayou Sorrel 3-D Area. The 3-D data is currently being
processed and the Company expects to independently participate in the processing
and interpretation of this data. Based on the results of the interpretation,
drilling could commence on new prospects as early as the second quarter of 1998.
Anticipated Sale of The Rocky Mountain Assets
In 1997, the Company's Board of Directors decided that the Company's Rocky
Mountain Assets, including the oil and gas properties, gas plant and service and
supply operations should ultimately be sold. This decision was based on several
factors, including but not limited to, the declining margins on the Rocky
Mountain operations, lack of success in exploiting the assets acquired from
Skaer and the Company's most recent efforts to foster growth have been, and will
continue to be in the foreseeable future, focused in the Gulf Coast.
Although no formal agreements have been reached as of the date of this report,
the Company has been conducting on-going negotiations with several parties
interested in the assets. The depressed and volatile commodity prices
experienced since November 1997 (and continuing through the date of this report)
have hindered the negotiations. However, the Company is committed to selling the
Rocky Mountain Assets and anticipates most, if not all, of the related assets
will be sold sometime in 1998.
BUSINESS STRATEGY
To initiate the Gulf Coast efforts, the Company sought out opportunities to
invest in a diversified portfolio of oil and gas exploration projects and
attempted to mitigate risks of exploration drilling by taking minority interests
in projects with large potential reserves. The Company generally participates as
a minority, non-operating interest holder with industry partners. Although the
Company does not currently operate properties or originate any of these
exploration prospects, it actively participates in the evaluation of
opportunities presented by its industry partners, both at the time of its
initial investment in a prospect and thereafter during the evaluation and
selection of drilling locations. The Company's current and future business
strategy will focus on expanding its reserve base and future cash flows by
cultivating the prior acquisitions, nurturing the strategic alliances and
exploiting the existing exploration opportunities in the Gulf Coast Region.
Specifically, the Company will attempt to execute this strategy by focusing its
immediate exploration efforts and resources on what the Company considers its
three core areas in the Gulf Coast, which are:
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1. The 54-square mile Bayou Sorrel 3-D Area in Iberville Parish,
Louisiana, operated by National Energy Group, Inc.;
2. The Formosa, Texana and Ganado 3-D prospects, encompassing
130,000 acres in and around Jackson County, Texas, operated by
Parallel Petroleum; and
3. The Maurice Prospect in Fayetteville Parish, Louisiana, operated
by Amerada Hess.
In addition, the Company intends to emphasize the following precepts in
implementing its strategy:
o Make disciplined use of advanced exploration technologies -- such as 3-D
seismic and computer-aided exploration ("CAEX") technology;
o Mitigate exploration risk by spreading investment over a significant number
of prospects to improve the probability of success;
o Developing alliances with experienced and competent technical personnel
that have been trained by major oil companies and can demonstrate a
successful track record;
o Reinvesting future operating cash flows into development drilling and
recompletion activities; o Pursue the acquisition of properties and/or
potential merger candidates that could build upon and enhance the Company's
existing asset base;
o Positioning itself with strategic sources of capital and industry partners
that can react to opportunities in the oil and gas business when they
present themselves.
The Company currently employs the services of Baird Petrophysical Group, Inc., a
geophysical and petrophysical consulting firm headed by Ralph W. Baird. Mr.
Baird has almost 30 years of experience providing specialized technical services
to the petroleum industry around the globe. The Company uses Mr. Baird's
services to screen, analyze, advise, and otherwise assist in the interpretation
and evaluation of the Gulf Coast prospects.
The Company recognizes that the ability to implement its business strategies is
largely dependent on the ability to raise additional debt or equity capital to
fund future acquisition, exploration, drilling and development activities. The
Company's Capital resources are discussed more thoroughly in Part II, Item 6, in
Management's Discussion and Analysis.
OPERATIONS
As of December 31, 1997, the Company had varying ownership interests in 185
gross productive wells (164 net) located in five states. The Company operates
176 of the 185 wells, the other wells are operated by independent operators
under contracts that are standard in the industry. As previously mentioned, the
Company has committed to selling its Rocky Mountain assets. If and when this
occurs, the Company's interest for producing properties as of the date of this
report would be reduced to 3 gross (.40 net) non-operated wells located solely
in Southern Louisiana. This divestment would dramatically reduce the Company's
proved reserves, revenues and cash flows.
The following table presents oil and gas reserve information within the
Company's major operating areas as of December 31, 1997:
Net Proved Reserves
REGION Bbls Mcf BOE (6:1)
-------------------- --------- --------- ----------
Rocky Mountains -
principally in the DJ Basin 777,000 3,175,000 1,306,000
Gulf Coast -
principally in S. Louisiana 308,000 1,360,000 535,000
--------- --------- ---------
Total 1,085,000 4,535,000 1,841,000
========= ========= =========
It is a primary objective of the Company to operate most of the oil and gas
properties located in the Rocky Mountain Region in which it has an economic
interest. The Company believes, with the responsibility and authority as
operator, it is in a better position to control costs, safety, and timeliness of
work as well as other critical factors affecting the economics of a well.
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At the present time, oil and natural gas prospects pursued in the Gulf Coast
region by the Company will be as a non-operator.
COMPETITION
The oil and gas industry is highly competitive in many respects, including
identification of attractive oil and gas properties for acquisition, drilling
and development, securing financing for such activities and obtaining the
necessary equipment and personnel to conduct such operations and activities. In
seeking suitable opportunities, the Company competes with a number of other
companies, including large oil and gas companies and other independent operators
with greater financial resources and, in some cases, with more experience. Many
other oil and gas companies in the industry have financial resources, personnel,
and facilities substantially greater than those of the Company. There can be no
assurance that the Company will be able to compete effectively with these other
entities.
MARKETS
Overview - The three principal products currently produced and marketed by the
Company are crude oil, natural gas and natural gas liquids ("NGL's"). The
Company does not currently use commodity futures contracts and price swaps in
the sales or marketing of its natural gas and crude oil.
Crude Oil - Oil produced from the Company's properties is generally transported
by truck or pipeline to unaffiliated third-party purchasers at the prevailing
field price (the "posted price"). Currently, the four primary purchasers of the
Company's crude oil are Plains Marketing & Transportation, Total Petroleum,
Inc., Texaco Trading and Transportation, Inc. and Scurlock-Permian Corporation.
Together these four purchasers buy more than 90% of the Company's annual crude
oil production. The contracts are month-to-month and subject to change. The
market for the Company's crude oil is competitive and therefore the Company does
not believe that the loss of one of its primary purchasers would have a material
adverse effect on the Company's business because other arrangements could be
made to market the Company's crude oil products. The Company does not anticipate
problems in selling future oil production since purchases are made based on
current market conditions and pricing. Oil prices are subject to volatility due
to several factors beyond the Company's control including: political turmoil;
domestic and foreign production levels; OPEC's ability to adhere to production
quotas; and possible governmental control or regulation.
Natural Gas - The Company sells its natural gas production in two principal
ways: a.) at the wellhead to various pipeline purchasers or natural gas
marketing companies; and b.) at the tailgate of its Gas Plant to either Public
Service Company of Colorado ("PSCo") or Hewlett-Packard Company ("HP"). The
wellhead contracts have various terms and conditions, including contract
duration. Under each wellhead contract the purchaser is generally responsible
for gathering, transporting, processing and selling the natural gas and natural
gas liquids and the Company receives a net price at the wellhead.
The residue gas sold at the tailgate of the Company's Gas Plant to PSCo is
subject to a month-to-month contract and the Gas sold to HP is subject to a
contract that expires in 2013. The gas to both parties is priced on an MMBtu
basis at an index spot price. It should be noted that the sale of processed
natural gas to PSCo is not directly related to the Company's former natural gas
marketing and trading contract which expired on July 1, 1996. The market and
trading activities are discussed later in "Management's Discussion and
Analysis".
Natural Gas Liquids - The Company produces two natural gas liquid products at
its Gas Plant, butane-gasoline mix and propane. The butane gasoline mix is sold
to an unaffiliated party at prevailing market prices on a month-to-month basis.
The propane is sold under a month-to-month arrangement with one or more local
propane wholesalers for resale to the local propane market. The Company does not
believe that the loss of the current purchasers of these products would have a
material adverse effect on the Company's business because it believes other,
similar arrangements could be made to market the Company's natural gas liquids.
REGULATIONS
General - All aspects of the oil and gas industry are extensively regulated by
federal, state, and local governments in all areas in which the Company has
operations. The following discussion of regulation of the oil and gas industry
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is necessarily brief and is not intended to constitute a complete discussion of
the various statutes, rules, regulations or governmental orders to which the
Company's operations may be subject.
Price Controls on Liquid Hydrocarbons - There are currently no federal price
controls on liquid hydrocarbons (including oil, natural gas and natural gas
liquids). As a result, the Company sells oil produced from its properties at
unregulated market prices which historically have been volatile.
Federal Regulation of Sales and Transportation of Natural Gas - Historically,
the transportation and sale of natural gas in interstate commerce have been
regulated pursuant to the Natural Gas Act ("NGA"), the Natural Gas Policy Act of
1978 ("NGPA") and regulations promulgated thereunder. The Natural Gas Wellhead
Decontrol Act of 1989 eliminated all regulation of wellhead gas sales effective
January 1, 1993. As a result, the Company's gas sales are no longer regulated.
The transportation and resale in interstate commerce of natural gas produced and
sold by the Company continues to be subject to regulation by the Federal Energy
Regulatory Commission ("FERC") under the NGA. The transportation and resale of
natural gas transported and resold within the state of its production is usually
regulated by the state involved. In Colorado such regulation is by the Colorado
Public Utility Commission. Although federal and state regulation of the
transportation and resale of natural gas produced by the Company currently does
not have any material direct impact on the Company, such regulation does have a
material impact on the market for the Company's natural gas production and the
price the Company receives for its natural gas production. Adverse changes in
the regulation affecting the Company's gas markets could have a material impact
on the Company.
Commencing in the mid-1980's and continuing until the present, the FERC
promulgated several orders designed to correct market distortions and to make
gas markets more flexible and competitive. These orders have had a profound
influence on natural gas markets in the United States and have, among other
things, increased the importance of interstate gas transportation and encouraged
development of a large spot market for gas.
On April 8, 1992, the FERC issued Order No. 636 requiring material restructuring
of the sales and transportation service provided by interstate pipeline
companies. The primary element of Order No. 636 was the mandatory unbundling of
interstate gas transportation services and storage separately from their gas
sales. The unbundled transportation and storage was required to be offered
without favoring gas bought from the pipeline. Order No. 636 did not require
pipelines to stop buying and reselling gas; to the contrary, it contained
specific provisions to allow pipelines to continue unbundled sales of natural
gas. However, after Order No. 636 there was little reason for a pipeline to
continue selling natural gas and most pipelines moved all or almost all of their
gas purchases and sales to affiliated marketing companies.
Order No. 636 does not regulate gas producers such as the Company. However,
Order No. 636 does appear to have achieved FERC's stated goal of fostering
increased competition within all phases of the natural gas industry. Generally
speaking, this increased competition has driven the price down for natural gas
produced by the Company and other producers. It is unclear what further impact
the increased competition will have on the Company as a gas producer and seller
in the future. Increased flexibility and competition provides greater assurance
of access to markets, but has consequently reduced or restrained prices.
In addition to FERC regulation of interstate pipelines under the NGA, various
state commissions also regulate the rates and services of pipelines whose
operations are purely intrastate in nature. To the extent intrastate pipelines
elect to transport gas in interstate commerce under certain provisions of the
NGPA, those transactions are subject to limited FERC regulation under the NGPA
and may ultimately effect the price of natural gas sold by the Company.
There are many legislative proposals pending in Congress and in the legislatures
of various states that, if enacted, might significantly affect the oil and gas
industry. The Company is not able to predict what will be enacted and thus what
effect, if any, such proposals would ultimately have on the Company.
State and Local Regulation of Drilling and Production - State regulatory
authorities have established rules and regulations requiring permits for
drilling, bonds for drilling, reclamation and plugging operations, limitations
on spacing and pooling of wells, and reports concerning operations, among other
matters. The states in which the Company operates also have statutes and
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regulations governing a number of environmental and conservation matters,
including the unitization and pooling of oil and gas properties and
establishment of maximum rates of production from oil and gas wells. For
example, each well in the East Bayou Sorrell prospect is currently restricted to
approximately 1,400 Bbls of oil per day because of such state mandated
restriction. A few states also prorate production to the market demand for oil
and gas. These statutes and regulations limit the rate at which oil and gas
could otherwise be produced or the prices obtained from the Company's
properties.
Also in recent years, pressure has increased in states in which the Company has
been active (especially Colorado) to mandate compensation to surface owners for
the effects of oil and gas operations and to increase regulation of the oil and
gas industry at the local government level. Such local regulation in general is
aimed at increasing the involvement of local governments in the permitting of
oil and gas operations, requiring additional restrictions or conditions on the
conduct of operations to reduce the impact on the surrounding community and
increasing financial assurance requirements. Accordingly, such regulation has
the potential to delay and increase the cost, or even in some cases to prohibit
entirely, the conduct of the Company's drilling activities.
Environmental Regulations - The production, handling, transportation and
disposal of oil and gas and by-products are subject to regulation under federal,
state and local environmental laws. In most instances, the applicable regulatory
requirements relate to water and air pollution control and solid waste
management measures or to restrictions of operations in environmentally
sensitive areas. In connection with its acquisitions, the Company attempts to
perform environmental assessments. However, environmental assessments have not
been performed on all of the Company's properties. To date, expenditures for
environmental control facilities and for remediation have not been significant
in relation to the Company's results of operations. However, it is reasonably
likely that the trend in environmental legislation and regulations will continue
towards stricter standards and may result in significant future costs to the
Company. For instance, efforts have been made in Congress to amend the Resource
Conservation and Recovery Act to reclassify oil and gas production wastes as
"Hazardous Waste," the effect of which would be to further regulate the
handling, transportation and disposal of such waste. If such legislation were to
pass, it could have a significant adverse impact on the operating costs of the
Company, as well as the oil and gas industry in general.
New initiatives regulating the disposal of oil and gas waste are also pending in
certain states, including states in which the Company conducts operations, and
these various initiatives could have a similar impact on the Company. The COGCC
has enacted rules regarding the regulation of disposal of oil field waste,
including waste currently exempt from federal regulation. These rules may
require the termination of production from some of the Company's marginal wells
for which the cost of compliance would exceed the value of remaining production.
In addition, as indicated above, the COGCC has enacted regulations imposing
specific reclamation requirements on operators upon the conclusion of the
operations, and is currently chairing a group including representatives of the
oil and gas industry, environmental groups, surface owners, and local
governments to consider adopting statewide reclamation requirements. The COGCC
is also in the process of preparing new rules governing production pits which
are intended to require closure of unlined pits and certain steel, fiberglass,
cement and other vessels in designated sensitive areas (which will probably
include most of the areas in Colorado that the Company operates) or adequate
proof that such pits or vessels are not leaking. As currently drafted, such
rules would permit operators to comply over a period of at least two years. The
COGCC proposals will be subject to review and comment of water quality agencies
and other interested parties and thus may change from the approach described
above. Management believes that compliance with current applicable laws and
regulations or with proposals in their present form could possibly have a
material adverse impact on the Company, but management is unable to predict the
final form of the pending regulations or their potential impact on the Company.
The Company believes that its operations comply with all applicable legislation
and regulations in all material respects, and that the existence of such
regulations has had no more restrictive effect on the Company's method of
operations than other similar companies in the industry. Although the Company
does not believe its business operations presently impair environmental quality,
compliance with federal, state and local regulations which have been enacted or
adopted regulating the discharge of materials into the environment could have an
adverse effect upon the capital expenditures, earnings and competitive position
of the Company, the extent of which the Company now is unable to assess. The
Company is not aware of any environmental degradation which exists, or the
obligation for remediation of which would arise under applicable state or
federal environmental laws. The Company does not maintain a fund for
environmental or other similar costs. Any such costs or expenses would be paid
by the Company out of operating capital.
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OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
drilling and production of oil and gas, such as blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of
toxic gas and other environmental hazards and risks. These hazards can cause
personal injury and loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
The Company maintains insurance of various types to cover its operations. The
Company's insurance does not cover every potential risk associated with the
drilling and production of oil and gas. In particular, coverage is not
obtainable for certain types of environmental hazards. The occurrence of a
significant adverse event, the risks of which are not fully covered by
insurance, could have a material adverse effect on the Company's financial
condition and results of operations. Moreover, no assurance can be given that
the Company will be able to maintain adequate insurance in the future at rates
it considers reasonable.
ADMINISTRATION
Office Facilities - The Company currently rents approximately 4,000 square feet
in an office facility in Grand Junction, Colorado owned by an unrelated party.
The rental rate is $32,232 per year through June 30, 2000.
Employees - As of March 16, 1998, the Company had 25 full time employees, none
of whom is covered by a collective bargaining agreement. The Company considers
its relations with its employees satisfactory.
ITEM 2 - PROPERTIES
PRINCIPAL OIL AND GAS INTERESTS
Developed Acreage - The Company's producing properties as of December 31, 1997
are located in the following areas shown in the table below:
<TABLE>
<CAPTION>
OIL GAS
------------------- ------------- Developed Acreage
Gross Net(2) Gross Net(2) -----------------
Fields State Wells(1) Wells Wells(1) Wells Gross Net(2)
- ---------------------------- ---------- ------- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C>
Loveland Field ............. Colorado 81 81 -- -- 5,083 5,047
Johnson's Corner ........... Colorado 5 5 -- -- 1,122 1,122
West Peetz Field ........... Colorado 5 5 -- -- 785 785
Yenter Field ............... Colorado 6 6 -- -- 1,655 1,655
Cisco Dome ................. Utah 1 1 38 31 8,877 8,267
All Other Fields ........... CO/NB/UT 40 32 5 3 9,363 7,193
------ ------ ------ ------ ------ ------
Subtotal - ................. Rocky
Mountains (rounded) ..... 138 130 43 34 26,885 24,069
East Bayou Sorrel .......... Louisiana 2 .20 -- -- 847 85
South Lake Arthur .......... Louisiana -- -- 1 .20 349 73
------ ------ ------ ------ ------ ------
Subtotal - Gulf Coast ...... 2 .20 1 . 20 1,196 158
------ ------ ------ ------ ------ ------
Grand Total (rounded
to nearest whole) .......... 140 130 44 34 28,081 24,227
====== ====== ====== ====== ====== ======
</TABLE>
-7-
<PAGE>
Footnotes
(1) Wells which produce both gas and oil in commercial quantities are
classified as "oil" wells for disclosure purposes.
(2) "Net" wells and "net" acres refer to the Company's fractional working
interests multiplied by the number of wells or number of acres.
Substantially all of the Company's producing oil and gas properties are located
on leases held by the Company for as long as production is maintained.
Undeveloped Acreage - The Company's gross and net working interests in leased
undeveloped acreage in the Rocky Mountain Region as of December 31, 1997 is 406
and 366 acres, respectively. All these properties are located in Colorado and
will expire at various times in 1998 unless production has been obtained.
The Company's gross and net working interests in leased (or lease options in
areas where 3-D seismic is being conducted) on undeveloped acreage in the Gulf
Coast Region as of December 31, 1997 is as follows:
Undeveloped Acreage
----------------------
Prospect Description State Gross Net
- -------------------- ----- ----- ---
Bayou Sorrel 3-D Area Louisiana 5,561 782(1)
Bayou Sorrel 3-D Area (Options) Louisiana 121,121 17,033(2)
Maurice Prospect Louisiana 1,024 86(3)
Parallel 3-D Program Texas 37,694 4,712(3)
Parallel 3-D Program (Options) Texas 84,924 10,615(2)
Austin Bayou Texas 3,377 72(3)
------- ------
Totals: 253,701 33,300
======= ======
(1) Substantially all of these leases will expire in 1999 unless
production has been obtained.
(2) Substantially all of these lease options will expire in 1998 unless
they are exercised. The total acres ultimately exercised will be
contingent on the interpretive results of the corresponding 3-D
seismic surveys. The Company estimates that between 20% and 60% of the
options will ultimately be exercised at an approximate cost to the
Company of $100.00 per net acre.
(3) Substantially all of these leases will expire in 2000 unless
production has been obtained.
GULF COAST PROPERTIES AND PROSPECTS
Overview - As stated earlier, in 1996 and 1997 the Company actively initiated
efforts to transform itself into an aggressive Gulf Coast exploration company.
Historically, the 30 year-old company focused on the U.S. Rocky Mountains for
acquisition and development plays, but today it holds a substantial lease
position onshore Texas and Louisiana, also known as the U.S. Gulf Coast. The
Company is aggressively acquiring 3-D seismic surveys and drilling both
development and exploratory wells in the Gulf Coast.
In 1998 and beyond, the Company intends to actively pursue the drilling,
development, and exploration objectives targeting known areas for oil and gas
reservoirs in the U.S. Gulf Coast, mainly Texas and Louisiana. The U.S. Gulf
Coast, although it has been actively explored, remains a prolific area with
excellent upside potential for exploration due to modern proprietary 3-D seismic
surveys, which the Company now owns. The Company believes that the combination
of technology and the availability of leases to drill make this an opportune
time for an aggressive exploration program.
East Bayou Sorrel and Bayou Sorrel Area - During 1997, the Company acquired a
10% working interest and a 7.125% after prospect payout leasehold interest in
the 1996 discovery of a new oil and gas field, East Bayou Sorrel Field located
in Iberville Parish, Louisiana. The acquisition included one discovery well that
-8-
<PAGE>
was drilled in 1996 and the Company and NEGX together drilled an additional
discovery well in 1997 on this prospect. Together these two wells have
historically produced approximately 2,300 bbls of oil, 2,400 Mcf gas and 860
bbls of water per day. A new 3-D seismic survey covering a much larger area (54
square miles, 30,000 acres) than the original East Bayou Sorrel AMI, was
completed in February 1998. The processing is complete and the data is now being
interpreted independently by the Company. Preliminary results appear to confirm
the reservoir at East Bayou Sorrel, and even more encouraging is the apparently
large number of potential undrilled targets contained within the 3-D volume.
Additional development drilling of the East Bayou Sorrel Field, development
drilling of undrilled fault blocks near East Bayou Sorrel Field, as well as
exploratory drilling based on images from the 3-D seismic is expected to be
conducted during 1998 and beyond.
Formosa, Texana and Ganado 3-D Exploration Prospects - During 1997, the Company
secured a 12.5% working interest in three specific on-shore upper Gulf Coast
exploration projects located in and around Jackson County, Texas. The 3-D survey
will cover over 200 square miles (130,000 acres) in and around Jackson County,
Texas. The surveys on two of the projects are already completed and the data is
currently being interpreted by the Company and its partners. The 3-D survey on
the third project is currently being conducted and is expected to be completed
late in 1998. The Company expects that there may be as many as 60 to 70 wells
ultimately drilled on these prospects based on our preliminary evaluation of the
3-D seismic and local geology. Parallel Petroleum of Midland, Texas is the
designated operator for these wells,
The subject lands lie in close proximity to productive oil and gas fields which
produce from the Miocene/Frio intervals. The subject acreage block is bounded by
fields that have cumulatively produced in excess of 2 trillion cubic feet of
natural gas and 500 million barrels of oil.
The typical Yegua well costs approximately $800,000 to drill and complete, and
if successful, has an average reservoir of 10 billion cubic feet of natural gas,
and begins to generate cash flow within 60 days from spud date. The typical Frio
well costs approximately $400,000 to drill and complete, has a reservoir of 1
billion or more cubic feet of natural gas, begins to generate cash flow 60 days
from spud date, and return the original investment in less than one year. The
foregoing estimates naturally depend on flow rates and pricing.
Within the project areas, there is an extremely high potential exploration
opportunity that is being defined with the use of 3-D seismic. The Jackson
County area has proven to be ideal for 3-D seismic as faulting and structures
are easily identified and many stratigraphic reservoirs exhibit hydrocarbon
indicators from the shallowest Miocene sands, throughout the Frio, and into the
Vicksburg and Yegua intervals. The Formosa Grande Prospect Area has numerous
regional down-to-the-coast faults that are easily identified at the top of the
Frio, but also has deep seated faulting that does not exhibit displacement at
the shallower horizons. Very often, these deep faults do create hydrocarbon
traps. Most fields in this trend area exhibit multiple stacked reservoirs.
A Greta level structure map exhibits numerous large four-way closures, primarily
downthrown to regional growth faulting. These large structures have, for the
most part, been exploited, some as early as the 1930s and 1940s. Although it is
not readily apparent in regional mapping, much of the Frio production is
stratigraphic in nature, that is, trapped in channel sands that traverse
structures, or in sands that "pinch out" up onto the flanks of these large
structures. Significant reserves may remain in similar traps, further off
structure than has been developed to date.
Such traps should be readily defined with 3-D seismic data.
The Company's project area appears to be an excellent area to apply 3-D seismic
technology to exploit reserves that have been passed over in existing fields as
well as to discover new reserves in deeper pools and undrained fault segments in
compartmentalized fields.
Maurice Field - In 1997, the Company joined Davis Petroleum and Amerada Hess
Corporation ("AHC") to drill a discovery well at Maurice Field, Vermilion
Parish, Louisiana. The Trahan #1 is currently being completed in the bol mex
sands and is expected to be on production in April 1998. A second Maurice Field
well, the Broussard #1, is currently being completed to produce the Marg tex and
will also test all reservoirs to the bol mex sands. Additional wells will be
drilled during 1998 and 1999 in order to develop the field. A 3-D seismic survey
is also being completed at this time. In addition, the Company, along with AHC,
recently acquired its proportionate share of approximately 50% of the camerina
unit rights. Accordingly, the Company will be able to pursue potential reserves
in the camerina sands in the future. The Company owns an 8.438% working interest
in this field.
-9-
<PAGE>
Austin Bayou Field - During 1997, the Company also participated with Davis
Petroleum and TransTexas in two (2) exploratory wells in Brazoria County, Texas,
located near Danbury, Texas. Although no reserves have been assigned to these
wells as of the date of this report, the first well, the Zinn #1, is currently
being completed for a test in the Oligocene Frio formation and the second well,
the Bennett #1, indicated the presence of gas during its drilling operations.
This gas show is now behind pipe and will be completed and tested at a later
date. Currently the Company and its partners are deepening the Bennett #1 and
drilling a third well, the Kopplin #1. The three wells were proposed based on
newly recorded 3-D seismic data. The Company owns a 2.129% carried working
interest in this field. This carried working interest will revert to a paying
working interest basically once production has been obtained on any of the three
wells.
South Lake Arthur Field - In 1997, the Company and NEGX drilled the Edith Winn
#1 and discovered gas. The well, located in Jefferson Davis Parish, Louisiana
was completed in a Camerina sand. It is currently producing approximately 1,200
Mcf of gas per day. The Company owns a 20.83% working interest in this well but
has no plans for further drilling on this prospect.
ROCKY MOUNTAIN PROPERTIES
Overview - Most of the Company's Rocky Mountain reserves are located in the
Denver-Julesburg ("DJ") Basin which encompasses most of northeast Colorado and
parts of southeast Wyoming, southwest Nebraska and western Kansas. Oil and gas
are produced mainly from Cretaceous sandstones and limestones, with the "D" and
the "J" sandstones being the most prolific producers in the Basin at depths
ranging in general from approximately 5,000 feet to approximately 7,500 feet.
The Company's activities have focused on the historically better producing
zones, the "D" and the "J" sandstones and the Niobrara formation. At December
31, 1997, approximately 70% of the Company's reserves were located in the Rocky
Mountains -- principally in the DJ Basin. A summary of the notable fields in the
DJ Basin, and other Rocky Mountain areas, are as follows:
Loveland Field, Larimer and Weld Counties - Loveland Field is located near the
City of Loveland, Colorado, 40 miles north of Denver. The area is producing both
oil and gas at an average rate in 1997 of approximately 224 barrels of oil
equivalent ("BOE") per day (185 BOE net to the Company). Loveland Gas Plant and
associated Pease facilities are located near the center of the field. Johnson's
Corner Field is located just 4 miles east of Loveland Field. Together, the
Loveland Field, Johnson's Corner Field and Loveland Gas Plant constitute more
than half of Pease's total Rocky Mountain assets.
All of the Company's gas production from the Loveland and Johnson's Corner
fields is processed in the Company's Loveland Gas Plant, which has a rated
capacity of approximately 6,000 Mcf per day. Pipeline systems are in place to
gather gas from the Loveland and Johnson's Corner fields. Approximately 1,000
Mcf of gas per day from the Loveland and Johnson's Corner fields is currently
processed through the Loveland gas plant. The natural gas produced from the
Loveland area is extremely rich in liquid composition with an average heat
content of 1,430 BTU per cubic foot. The ability of the gas plant to recover
natural gas liquids, such as propane and natural gasolines (B-G Mix), from the
gas enhances the value of gas production and significantly increases the
economic viability of additional development in the Loveland and Johnson's
Corner fields.
Among the existing wells, numerous opportunities exist to recomplete in certain
behind-pipe zones using newer stimulation technologies. In many wells, Codell
sandstone and Timpas limestone reserves remain behind-pipe which is available
for production upon recompletion of existing well bores. Among the wells that
have been completed in these zones, the Company believes that original
completions were often inadequate because of limited stimulation. Of the three
benches (separate sedimentary levels) of the Niobrara Formation, the upper bench
has been completed in most wells whereas the middle and lower benches are
available for production upon recompletion in many wells.
Johnson's Corner Field, Larimer County, Colorado - Johnson's Corner Field is an
extension of the Wattenberg Field with Muddy "J" Sandstone gas production. The
wells produce approximately 25 BOE (net to the Company) per day from the "J"
sand. One well has also been completed in the Codell and Niobrara formations and
oil production from all three zones is commingled. Recently two wells were
recompleted in Codell sandstone and the initial results are promising. In
addition, the Company believes there are several additional in-fill development
locations.
-10-
<PAGE>
West Peetz Field, Logan County, Colorado - The Company operates 5 wells in two
leases in the West Peetz field. The wells currently produce about 22 BOPD (net
to the Company) from the J sand. A detailed geological and engineering
evaluation of the field in early 1995 suggested that West Peetz field can be
produced profitably for many years to come and the field has an excellent
potential for secondary recovery. A low-cost simple water injection plan was
evaluated in 1997 and is currently being implemented.
Yenter Field, Logan County, Colorado - Yenter Field is a structural trap which
has produced more than 10 MMBO and 24 BCFG since the 1950s from the "J" sand.
Approximately 80% of wells in the field have been plugged and abandoned. The
Company owns and operates five wells with production of about 25 BOE per day
(net to Company). Water produced with oil from these five wells is injected back
into the reservoir to help maintain reservoir pressures for continued
production. The Company has conducted a complete geological and engineering
study of Yenter Field, which has identified undeveloped potential in additional
sandstone reservoirs and recommended reworking "J" sandstone wells which have
been shut in since the mid 1970s, and upgrading the pressure maintenance
program. The Company desires to acquire additional acreage in the field to
implement a secondary recovery program possibly with horizontal wells.
Cisco Dome Area, Grand County, Utah - In April 1995, the Company purchased an
80% working interest in approximately 8,877 acres in the Cisco Dome Field. The
Cisco Dome Field is located adjacent to the Calf Canyon Field. The property in
the Cisco Dome Field contains 39 wells of which 21 are currently producing gas
from intervals ranging from 2,000 to 3,200 feet. The average aggregate
production from these properties is approximately 310 Mcf and 6 bbls of oil per
day.
Cowboy Field, San Juan County, Utah - The Company has a 100% interest in four
oil wells in Cowboy Field in southeast Utah. The field is within the Paradox
Basin and production is from the Pennsylvanian Ismay Formation.
The Company has behind pipe potential and at least one development drillsite.
TITLE TO PROPERTIES
As is customary in the oil and gas industry, only a perfunctory title
examination is conducted at the time oil and gas leases are acquired by the
Company. Prior to the commencement of drilling operations, a thorough title
examination is conducted. The Company believes that title to its properties is
good and defensible in accordance with standards generally accepted in the oil
and gas industry, subject to such exceptions, which in the opinion of counsel,
are not so material as to detract substantially from the property economics. In
addition, some prospects may be burdened by customary royalty interests, liens
incident to oil and gas operations and liens for taxes and other governmental
charges as well as encumbrances, easements and restrictions. The Company does
not believe that any of these burdens will materially interfere with the use of
the property.
ESTIMATED PROVED RESERVES
The oil and gas reserve and reserve value information is included in Part II,
Item 7 at footnote 11 of the consolidated financial statements, titled "Oil and
Gas Producing Activities". This information is prepared pursuant to Statement of
Financial Accounting Standards No. 69, which includes the estimated net
quantities of the Company's "proved" oil and gas reserves and the standardized
measure of discounted future net cash flows. The reserve information for the
Rocky Mountains is based upon an engineering evaluation by McCartney
Engineering, Inc. The estimated proved reserves information for the Gulf Coast
is based upon an engineering evaluation by Netherland, Sewell & Associates, Inc.
The estimated proved reserves represent forward-looking statements and should be
read in connection with the disclosure on forward-looking statements included
herein under Item 6 in Managements' Discussion and Analysis.
The Company has not filed any reports containing oil and gas reserve estimates
with any federal authority or agency other than the Securities and Exchange
Commission and the Department of Energy. There were no differences in the
reserve estimates reported to these two agencies.
-11-
<PAGE>
All of the Company's oil and gas reserves are located in the Continental United
States. The Table below sets forth the Company's estimated quantities of proved
reserves, and the present value of estimated future net revenues discounted by
10 percent per year using prices being received by the Company at the end of
each of the last three fiscal years on a non-escalated basis. The prices used at
December 31, 1997 for the Rocky Mountain properties averaged $16.15 per barrel
of oil and $1.78 per Mcf of natural gas and $17.11 per barrel of oil and $2.61
per Mcf of natural gas for the Gulf Coast properties:
<TABLE>
<CAPTION>
Rocky Mountain and Gulf Coast
Gulf Coast Reserves Combined as of
Properties Only December 31,
At December 31, --------------------------------
1997 1997 1996 1995
--------------- ---- ---- ----
<S> <C> <C> <C> <C>
Estimated Proved Oil Reserves (Bbls) ..... 308,000 1,085,000 1,175,000 1,294,000
Estimated Proved Gas Reserves (Mcf) ...... 1,360,000 4,535,000 4,833,000 5,851,000
Estimated Future Net Revenues ............ $ 5,796,000 $14,371,000 $20,306,000 $13,680,000
Present Value of Estimated Future
Net Revenues ......................... $ 4,460,000 $ 9,678,000 $11,980,000 $ 8,480,000
</TABLE>
As previously discussed, it should be emphasized that the Company is attempting
to sell or otherwise monitize all the Rocky Moutain assets. Should this occur in
the future, the Company's only remaining reserves, revenues and future cash
flows would be limited to those oil and gas properties located in the Gulf Coast
region.
NET QUANTITIES OF OIL AND GAS PRODUCED
The Company's net oil and gas production for each of the last three years (all
of which was from properties located in the United States) was as follows:
Year Ended December 31,
----------------------------------
1997 1996 1995
---- ---- ----
Oil (Bbls)
Rocky Mountains 80,000 100,000 121,000
Gulf Coast 43,000 -- --
------- ------- -------
Total 123,000 100,000 121,000
======= ======= =======
Gas (Mcf)
Rocky Mountains 392,000 412,000 497,000
Gulf Coast 91,000 -- --
------- ------- -------
Total 483,000 412,000 497,000
======= ======= =======
The average sales price per barrel of oil and Mcf of gas, and average production
costs per barrel of oil equivalent ("BOE") excluding depreciation, depletion and
amortization were as follows:
-12-
<PAGE>
Average Sales Prices Average
Year Ended --------------------------------- Production
December 31 Oil (Bbls) Gas (Mcf) Per BOE Cost Per BOE
----------- --------- -------- ------- ------------
1997:
Gulf Coast ................ $ 19.15 $ 2.94 $ 18.76 $ 2.84
Rocky Mtns ................ $ 18.75 $ 1.46 $ 14.25 $ 9.09
Combined Avg ............... $ 18.89 $ 1.74 $ 15.54 $ 7.29
1996 ........................ $ 20.35 $ 1.26 $ 15.10 $ 8.46
1995 ........................ $ 16.77 $ 1.18 $ 12.85 $ 7.92
DRILLING ACTIVITY
The following table summarizes the Company's oil and gas drilling activities
that were completed during the last three fiscal years, all of which were
located in the continental United States:
Year Ended December 31,
-----------------------------------------------
1997 1996 1995
----------- ------------ ------------
Wells Drilled Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Exploratory
Oil 1 .10 - - - -
Gas 1 .08 - - - -
Non-productive 6 .77 1 .19 - -
---- ----- ---- ---- ---- ----
Total 8 .95 1 .19 - -
==== ===== ==== ==== ==== ====
Development
Oil - - 1 1 - -
Gas - - - - - -
Non-productive - - - - - -
---- ----- ---- ----- ---- ----
Total - - 1 1 - -
==== ===== ==== ===== ==== ====
At December 31, 1997 the Company was in the process of drilling or completing 5
additional wells which are not included in the above schedule. Of these 5 wells,
as of the date of this report, one was dry, one (in East Bayou Sorrell) has been
temporarily abandoned waiting on seismic information, two are being completed
and one is still drilling. In addition, two additional wells commenced drilling
operations during the first quarter of 1998.
ITEM 3 - LEGAL PROCEEDINGS
The Company may from time to time be involved in various claims, lawsuits,
disputes with third parties, actions involving allegations of discrimination, or
breach of contract incidental to the operation of its business. At December 31,
1997 and as of the date of this report, the Company was not involved in any
litigation which it believes could have a materially adverse effect on its
financial condition or results of operations.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the Company's Security holders during the
fourth quarter ended December 31, 1997.
-13-
<PAGE>
Part II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) Market Information - The Company's Common Stock has traded on the Nasdaq
SmallCap Market, under the symbol WPOG, since July 1980. Effective June 11,
1997, in accordance with provisions of the Company's Articles of Incorporation,
all outstanding $0.01 par value Series A Cumulative Convertible Preferred Stock
were automatically converted into Common Stock and Common Stock Purchase
Warrants. Other than the foregoing, there have been no modifications to any
instruments defining the rights of the holders of any class of registered
securities during the period covered by this report. The Company also has a
warrants that are publicly traded on the Nasdaq SmallCap Market, under the
symbol WPOGW. There are approximately 3 million warrants outstanding that give
the holders the right to purchase one share of the Company's common stock of
$6.00 per share. These warrants expire on August 13, 1999.
Bid Quotations - The following table shows the range of high and low bid
quotations for each quarterly period since January 1, 1996, as reported by the
National Association of Securities Dealers, Inc. (such quotations represent
prices between dealers and do not include retail markups, markdowns, or
commissions and do not necessarily represent actual transactions.):
Bid Prices
-------------------------------------
Series A
Common Stock Preferred Stock
Quarter Ended High Low High Low
------------------ ------- ------- ------ -------
December 31, 1997 3 1/2 1 1/2 - -
September 30, 1997 3 1/16 2 7/16 - -
June 30, 1997 3 27/32 2 3/16 13 1/8 13 1/16 (6/11/97)
March 31, 1997 3 9/16 2 1/2 10 10
December 31, 1996 3 5/16 2 1/16 10 3/4 6
September 30, 1996 2 1/8 1 7/32 6 3/4 5 1/4
June 30, 1996 1 11/16 1 5/64 7 4 1/4
March 31, 1996 1 3/8 1 9/32 5 3 1/2
(b) Stockholders - As of March 18, 1998 the Company had at least 350 round lot
shareholders of record for the Company's Common Stock. This does not include the
shareholders whose shares are held in a depository trust in "street" name. As of
March 18, 1998 at least 8,890,000 shares (or 56%) of the issued and outstanding
common stock (of which the number of beneficial round lot owners is not known by
the Company) were held in a depository trust in "street" name.
(c ) Dividends - The Company has not paid cash dividends on its Common Stock in
the past and does not anticipate doing so in the foreseeable future. The Company
is precluded from paying dividends on its Common Stock so long as any dividends
on the Preferred Stock are in arrears.
Under the Company's Articles of Incorporation, as amended ("Articles"), the
Board of Directors has the power, without further action by the holders of the
Common Stock, to designate the relative rights and preferences of the Company's
Preferred Stock, when and if issued. Such rights and preferences could include
preferences as to liquidation, redemption and conversion rights, voting rights,
dividends or other preferences, any of which may be dilutive of the interest of
the holders of the Common Stock. The Board previously designated Series A
Cumulative Convertible Preferred Stock, none of which is outstanding and all of
which has been retired.
The Company has designated 145,300 shares of Series B Preferred, of which
113,333 shares were issued on December 31, 1997, and the balance are reserved
for issuance of payment in kind ("PIK") dividends on outstanding Series B
Preferred. The Series B Preferred is entitled to a dividend of $2.50 per year,
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payable calendar quarterly, which amount may be paid, at the election of the
Company, in cash or in kind. If a dividend is paid in kind, each share of Series
B Preferred issued shall be valued at $50. The dividend is cumulative to the
date of payment. The shares of Series B Preferred have a liquidation preference
equal to $50 plus any unpaid dividends. The Series B Preferred was issued in a
private placement and is not publicly traded nor does the Company expect these
securities to be publicly traded in the future.
Additional classes of Preferred Stock may be designated and issued from time to
time in one or more series with such designations, voting powers or other
preferences and relative other rights or qualifications as are determined by
resolution of the Board of Directors of the Company. The issuance of Preferred
Stock may have the effect of delaying or preventing a change in control of the
Company and may have an adverse effect on the rights of the holders of Common
Stock.
(d) Recent Sales of Unregistered Securities - The Company issued and sold the
following securities without registration under the Securities Act of 1933, as
amended ("Securities Act"), during the fiscal year ended December 31, 1997:
1. Effective January 10, 1997 the Company issued 315,000 shares of its
common stock to three unrelated entities, Atocha Exploration, Inc.,
Potosky Oil and Gas, Inc., and Browning Oil Company, Inc., in
exchange for an undivided interest in a producing oil and gas
prospect designated as the East Bayou Sorrel Prospect in Iberville
Parish, Louisiana.
2. On January 31, 1997 the Company issued 250,000 shares of its common
stock upon exercise of outstanding purchase warrants of $1.25 per
share for a total proceeds of $312,500. The holders of the warrants
received them as part of a "unit" sold in a private placement in
1995 that consisted of common stock and warrants. The Company
relied upon Section 4(2) of the Securities Act and Rule 506 of
Regulation D in claiming exemption from registration requirements
of the Securities Act for securities sold. The shares of common
stock issued upon exercise of the warrants were registered for
resale by the holders in Registration No. 33-94536.
3. Between February 1, 1997 and March 10, 1997, the Company issued
1,500,000 shares of its common stock for $3,750,000 to a group of
private investors each of whom qualified as an accredited investor
as such term is defined in Regulation D adopted by the Securities
and Exchange Commission. The Company paid selling commissions
totaling $300,000 to various participating selling agents. The
Company relied upon Section 4(2) of the Securities Act and Rule 506
of Regulation D in claiming exemption from the registration
requirements of the Securities Act for the securities sold.
4. Between March 14, 1997 and April 15, 1997, the Company sold 52,000
shares of its common stock for $130,000 to a group of private
investors each of whom qualified as an accredited investor as such
term is defined in Regulation D adopted by the Securities and
Exchange Commission. The Company paid selling commissions totaling
$10,400 to various participating selling agents. The Company relied
upon Section 4(2) of the Securities Act and Rule 506 of Regulation
D in claiming exemption from the registration requirements of the
Securities Act for the securities sold.
5. During 1997 holders of $1,025,000 of the Company's outstanding
collateralized convertible 10% debentures ("Debentures")
surrendered such Debentures to the Company for conversion into
341,665 shares of the Company's common stock in accordance with
conversion provisions of the Debentures. The Certificates
representing the shares issued upon conversion bear a restrictive
legend prohibiting transfer without registration under the
-15-
<PAGE>
Securities Act or the availability of an exemption from
registration and "stop transfer" instructions have been issued to
the transfer agent. The shares of common stock issued upon
conversion have been registered for resale by the holders on
Registration No. 333-19589. The Company relied upon Section 3(a)9
of the Securities Act for issuance of the securities.
6. On February 14, 1997, the Company issued 4,000 shares of its common
stock to two consultants of the Company in lieu of cash for
consulting services rendered to the Company valued at $8,000 for
financial reporting purposes. The Certificates representing the
shares issued bear a restrictive legend prohibiting transfer
without registration under the Securities Act or the availability
of an exemption from registration and "stop transfer" instructions
have been issued to the transfer agent.
7. Between March 1, 1997 and April 15, 1997 the Company issued
2,482,500 shares of its common stock upon exercise of a like
number of warrants at $1.25 per warrant for a total proceeds of
$3,103,125. Holders of such warrants acquired the warrants in the
Company's 1996 private placement of Debentures and Warrants. The
warrants would have expired if not previously exercised on April
15, 1997. The Certificates representing the shares issued upon
exercise bear a restrictive legend prohibiting transfer without
registration under the Securities Act or the availability of an
exemption from registration and "stop transfer" instructions have
been issued to the transfer agent. The shares issued upon
exercise of warrants were registered by the Company for resale by
the holders in Registration No. 333-19589. The Company relied
upon Rule 506 of Regulation D in claiming exemption for the
registration requirements of the Securities Act for issuance of
the securities upon exercise of the warrants.
8. Between March 1, 1997 and June 3, 1997, the Company issued 135,000
shares of its common stock upon exercise of outstanding stock
purchase warrants at $0.75 per share for total proceeds of $101,250
to the Company. The Certificates representing the shares issued
upon exercise bear a restrictive legend prohibiting transfer
without registration under the Securities Act or the availability
of an exemption from registration and "stop transfer" instructions
have been issued to the transfer agent. The holder of the warrants
is an affiliate of Beta Capital Group, Inc. with whom the Company
has a consulting agreement and to whom the warrants were issued
in February 1996. The shares of common stock issued upon exercise
of the warrants were registered for resale by the holder in
Registration No. 333-19589.
9. Between June 23, 1997 and September 30, 1997 the Company issued
116,250 shares of its common stock upon exercise of outstanding
stock purchase warrants at $0.75 per share for total proceeds of
$87,188 to the Company. The warrants were originally issued to
Beta Capital Group, Inc. with whom the Company has a consulting
agreement and to whom the warrants were issued in February 1996.
Subsequent to their issuance, Beta re-assigned the warrants to
another holder. The Certificates representing the shares issued
upon exercise bear a restrictive legend prohibiting transfer
without registration under the Securities Act or the availability
of an exemption from registration and "stop transfer"
instructions have been issued to the transfer agent. The shares
of common stock issued upon exercise of the warrants were
registered for resale by the holder in Registration No.
333-19589.
-16-
<PAGE>
10. Between January 1997 and December 17, 1997, the Company issued
208,850 shares of its common stock upon exercise of outstanding
stock purchase warrants issued by the Company between 1994 and
1996 to certain broker/dealers in connection with private
placements of Company securities during such time. The Company
received $308,150 of proceeds upon exercise of the warrants. The
Certificates representing the shares issued upon exercise bear a
restrictive legend prohibiting transfer without registration
under the Securities Act or the availability of an exemption from
registration and "stop transfer" instructions have been issued to
the transfer agent. The shares of common stock issued upon
exercise were registered by the Company for resale by the holders
under Registration Nos. 333-19589 and 33-94536.
11. On June 25, 1997 and October 2, 1997 the Company issued 670 and
1,480 shares, respectively, of its common stock to three former
directors. The shares were issued for services to the Company as
a director (in lieu of cash) and were valued at $6,851 for
financial reporting purposes. The Certificates representing the
shares issued bear a restrictive legend prohibiting transfer
without registration under the Securities Act or the availability
of an exemption from registration and "stop transfer"
instructions have been issued to the transfer agent.
12. On July 14, 1997 the Company issued 3,150 shares of its common
stock to one director in exchange for an overriding royalty
interest in the producing oil and gas prospect designated as the
East Bayou Sorrel Prospect, Iberville Parish, Louisiana. The
shares were valued at $10,000 for financial reporting purposes.
The Certificates representing the shares issued bear a
restrictive legend prohibiting transfer without registration
under the Securities Act or the availability of an exemption from
registration and "stop transfer" instructions have been issued to
the transfer agent.
13. On July 18, 1997, the Company issued 2,240,000 shares of its
common stock for $5,600,000 to a group of private investors each
of whom qualified as an accredited investor as such term is
defined in Regulation D adopted by the Securities and Exchange
Commission. The principal underwriter was San Jacinto Securities,
Inc. and the Company paid selling commissions of $560,000. The
Company relied upon Section 4(2) of the Securities Act and Rule
506 of Regulation D in claiming exemption from the registration
requirements of the Securities Act for the securities sold. The
Certificates representing the shares issued a restrictive legend
prohibiting transfer without registration under the Securities
Act or the availability of an exemption from registration and
"stop transfer" instructions have been issued to the transfer
agent.
14. Between August 29, 1997 and September 9, 1997 the Company issued
42,675 shares of common stock to two former directors upon
exercise of outstanding options. The Company received $45,390 of
proceeds upon exercise of the warrants. The Certificates
representing the shares issued a restrictive legend prohibiting
transfer without registration under the Securities Act or the
availability of an exemption from registration and "stop
transfer" instructions have been issued to the transfer agent.
15. On December 31, 1997, the Company issued 113,333 shares of a
newly created Series B Preferred Stock. The Series B Preferred
Stock is convertible into the Company's common stock at a
discount to the market as defined in the agreement. The terms of
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<PAGE>
the Series B Preferred Stock are more thoroughly discussed in
Footnote 7 of the financial statements included under Item 7 of
this report. The Company received $5,666,650 of proceeds upon the
issuance of the preferred shares. The principal underwriter was
San Jacinto Securities, Inc. and the Company paid selling
commissions of $566,665. The Company is the acting transfer agent
for the preferred shares and the shares are prohibited from
transfer without registration under the Securities Act or the
availability of exemption from registration. Should the preferred
shares ultimately be converted into common stock, the common
stock will also bear a restrictive legend prohibiting the
transfer without registration under the Securities Act or the
availability of an exemption from registration and "stop
transfer" instructions will be issued to the transfer agent.
The Company relied on section 4(2) of The Securities Act in issuing the
securities described in paragraphs 1, 6, 8, 12, 14 and 15 without registration.
Each of the persons who acquired the securities had full information concerning
the business of the officers of the Company, certificates representing the
securities bear a restrictive legend as described above and the securities were
acquired for investment.
ITEM 6 - MANAGEMENT'S DISCUSSION AND ANALYSIS
Liquidity and Capital Resources
At December 31, 1997, the Company's cash balance was $6,547,804 with a positive
working capital position of $5,295,474, compared to a cash balance of $1,995,860
and a positive working capital position of $1,907,694 of December 31, 1996. The
change in the Company's cash balance is summarized as follows:
Cash balance at December 31, 1996 ............................. $ 1,995,860
Sources of Cash:
Proceeds from the sale of common stock ...................... 8,920,000
Proceeds from sale of Series B Preferred Stock ............. 5,099,985
Proceeds from the exercise of common stock options
and warrants ............................................... 3,957,604
Proceeds from the sale of property and equipment ............ 66,056
Cash provided by operating activities ....................... 6,314
------------
Total Sources of Cash ................................ 18,049,959
------------
Uses of Cash:
Acquisition of oil and gas interests in East Bayou Sorrel ... (3,431,955)
Exploration Activities - Gulf Coast ......................... (7,915,522)
Development Activities - Rocky Mountains ................... (734,235)
Other Capital Expenditures .................................. (55,480)
Costs associated with the sale of stock and
exercise of common stock warrants ....................... (874,416)
Payments on long term debt .................................. (391,407)
Purchase of certificate of deposit .......................... (95,000)
------------
Total uses of cash ................................... (13,498,015)
------------
Cash balance at December 31, 1997 ........................... $ 6,547,804
============
As noted, most of the Company's sources of cash during 1997 were derived from
capital raising equity transactions (which were discussed more thoroughly
previously in this report under Item 2(d) in Part II), and were primarily used
to fund the Company's exploration activities in the Gulf Coast. The amounts
spent on specific projects are discussed more thoroughly later in this section
under the caption "Capital Expenditures".
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<PAGE>
As in 1997, the Company will focus its future activities on continuing to
implement an aggressive exploration program in the Gulf Coast region,
principally in Louisiana and Texas. This activity will focus on what the Company
considers its three core areas in the Gulf Coast, which are:
1. The 54-square mile Bayou Sorrel 3-D Area in Iberville Parish,
Louisiana, operated by National Energy Group, Inc. ("NEGX");
2. The Formosa, Texas and Ganado 3-D prospects encompassing 130,000
acres in and around Jackson County, Texas, operated by Parallel
Petroleum ("Parallel"); and
3. The Maurice Prospect in Fayetteville Parish, Louisiana, operated
by Amerada Hess Corporation ("AHC").
Under the existing commitments related to these three areas, the following table
summarizes the range of expected capital requirements for 1998 by program:
Estimated Investment (in millions)
---------------------------------
Operator Minimum Maximum
- -------- ------- -------
East Bayou Sorrel 3-D Area $ 4.3 $ 6.3
Formosa, Texana, and Ganado Prospects 2.0 3.2
Maurice Prospect 1.2 1.5
---- ----
Total $ 7.5 $ 11.0
In addition to the above capital requirements, the Company may incur an
additional $2.0 million in obligations related to the exploration agreement
dated February 4, 1997, as amended on January 16, 1998, by and between the
Company and NEGX. That agreement provided the Company with the right and
obligation to participate with NEGX in various exploration projects, including
the Bayou Sorrell 3-D Area, over a period of two years. The agreement with NEGX
specifies that the Company's minimum obligation is at least $5.0 million per
year in dry hole, or drilling costs. Accordingly, this additional obligation may
be incurred for exploration projects outside of the Bayou Sorrell 3-D Area or
for additional costs which may be incurred for completion and development of
successful projects. The obligation to participate in additional exploration
projects outside of the Bayou Sorrell 3-D Area ends on February 4, 1999.
The Company's current and anticipated cash position will be insufficient to
cover the future working capital and exploration obligations and the Company
will need to seek additional financing. The Company is exploring various
alternatives and future sources of capital may include additional debt or equity
financings, the sale of certain existing assets, or a combination thereof.
However, it cannot be determined at this time, what alternatives may be
available, nor to what extent the potential dilution to the existing
shareholders may be. In addition, if additional sources of financing are not
ultimately available, the Company may have to consider other alternatives,
including cancellation of existing exploration agreements, farmouts, joint
ventures, a merger, and/ or liquidation.
The Company is currently attempting to sell or otherwise monitize its Rocky
Mountain assets. Although no formal agreements have been reached as of the date
of this report, the Company has been conducting on-going negotiations with
several parties interested in the assets. The depressed and volatile commodity
prices experienced since November 1997 (and continuing through the date of this
report) have hindered the negotiations. However, the Company is committed to
selling the Rocky Mountain Assets and anticipates most, if not all, of the
related assets will be sold sometime in 1998 assuming that acceptable terms can
be negotiated with a willing purchaser. The Company's obligations under its
outstanding 10% Collateralized Convertible Debentures (the "Convertible
Debentures") in the principal amount of $3.975 million, together with interest
thereon, is secured by a first priority security interest in substantially all
of the oil and gas reserves in Larimer and Weld Counties, Colorado, which
constituted approximately 60% of all of the Company's Rocky Mountain proved
reserves of oil and gas at December 31, 1997. A portion of any proceeds received
from the Company upon the sale of its Rocky Mountain oil and gas properties
attributable to the properties which secure the Convertible Debentures will not
be available to the Company, as such proceeds must be set aside and reserved as
security for the Company's obligations under the Convertible Debentures. The
Company intends to substitute other oil and gas assets as collateral for the
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<PAGE>
Convertible Debentures, but such substitution requires the written approval of
the holders of at least two-thirds of the oustanding Convertible Debentures. The
Company intends to seek such approval for substitution at such time, if ever, as
an acceptable sale of its Rocky Mountain oil and gas properties is negotiated
and placed under contract. However, it cannot be determined at this time the
amount of capital, if any, that would be available for future exploration and
development activities should the Rocky Mountain assets be sold.
Capital Expenditures
During 1997, the Company incurred $14,606,933 in property and equipment as
follows:
Total %
----- ---
Acquisitions of oil and gas interests in
East Bayou Sorrel ............................. $ 4,266,955 29%
Exploration Activities -
Discovery wells ............................... 2,100,510 14%
Exploratory Dry Holes ......................... 3,645,493 25%
Land, Geologic and Geophysical Costs
on Seismic Programs ......................... 3,147,443 22%
Other Exploration Costs ....................... 606,126 4%
----------- ----
Total Exploration Activities .............. 9,499,572 65%
Workovers or Recompletions of Rocky
Mountain properties .......................... 734,235 5%
----------- ---
Total Oil and Gas properties .............. 14,500,762 99%
Service and Other Field Equipment ................. 102,341 1%
Office Equipment .................................. 3,830 Nil
----------- ---
Total Capital Expenditures ................ $14,606,933 100%
=========== ===
The total costs incurred for exploration activities of $9,499,572 is summarized
below by program operator:
<TABLE>
<CAPTION>
PROGRAM OPERATOR
---------------------------------------------------------
The Co. &
NEGX Parallel AHC Other Total %
---- -------- --- --------- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Category:
Discovery wells ................... $1,542,431 $ -- $ 558,079 $ -- $2,100,510 22%
Exploratory Dry Holes ............. 3,518,690 36,197 -- 90,606 3,645,493 38%
Land, G&G Costs on Seismic ........ -- 3,119,939 -- 27,504 3,147,443 33%
Programs
Other Exploration Costs ........... -- -- 2,889 603,237 606,126 7%
---------- ---------- ---------- ---------- ---------- ---
Total Exploration Costs ..... $5,061,121 $3,156,136 $ 560,968 $ 721,347 $9,499,572 100%
========== ========== ========== ========== ========== ===
</TABLE>
RESULTS OF OPERATIONS
Overview
The Company's largest source of operating revenue is from the sale of produced
oil, natural gas, and natural gas liquids. Therefore, the level of the Company's
revenues and earnings are affected by prices at which natural gas, oil and
natural gas liquids are sold. Therefore, the Company's operating results for any
prior period are not necessarily indicative of future operating results because
of the fluctuations in natural gas, oil and natural gas liquid prices and the
lack of predictability of those fluctuations as well as changes in production
levels.
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<PAGE>
Change In Accounting Principle
During the fourth quarter of 1997, the Company changed its method of accounting
for oil and gas producing activities from the successful efforts method to the
full cost method. The 1996 financial statements presented herein have been
restated to reflect the change.
Through December 31, 1995, the cumulative effect of the change resulted in an
increase in carrying value in oil and gas properties and a corresponding
decrease in the accumulated deficit of $3,068,165. As a result of the change in
accounting method, the net loss applicable to common shareholders decreased by
$138,000 ($0.02 per share) in 1996, and increased by $1,970,500 ($0.15 per
share) in 1997. The majority of the increased loss in 1997 is recognized in the
financial statements under the caption "Impairment Expense-Assets held For Sale"
which is discussed later in this section.
Management believes the full cost method of accounting is preferable because it
will most accurately reflect the results of the Company's future operations. In
connection with the Company's change in strategy from primarily an acquisition
and production company to an exploration and production company, it is now
focusing its efforts in the Gulf Coast region of the United States. The Company
seeks to allocate its capital resources over a diversified portfolio of
exploration and development projects within that area. It seeks to achieve a
balance between the risks of exploratory drilling and the return on investment
by investing in projects with large potential. Dry holes, abandoned properties
and seismic projects are an inherent part of the exploration process. However,
management believes that it is through disciplined, consistent application of
this balanced portfolio strategy that the desired return on its entire
investment will be achieved. Management believes that the full cost method of
accounting is the method used by many independent oil and gas companies of
comparable size to the Company and allows investors to better measure the
performance of the Company. Management further believes that advanced three
dimensional seismic and computer-aided exploration technology has become a much
more significant factor in the success of an exploration program than in the
past. Management believes that expensing these costs when incurred, as is
required under successful efforts, is inconsistent with the value they add to
the exploration process.
Assets Held For Sale
During the fourth quarter of 1997, the Company's Board of Directors determined
that the Company's long-term strategy has shifted to exploration and development
activities in the Gulf Coast region and that the Rocky Mountain assets should
ultimately be divested. If and when these assets are sold, the revenue, costs,
operating margins and cash flows currently generated and discussed under the
captions "Gas Plant Processing", "Oil Field Services and Supply", "Well
Administration and Other Income" would no longer be part of the Company's
operations. Since these assets include a significant portion of the Company's
current operations, the sale of these assets, when and if it occurs, will have
an immediate and material negative impact on the Company's future cash flows and
results of operations.
Total Revenue
Total Revenue from all operations was as follows:
<TABLE>
<CAPTION>
For the Year Ended December 31,
-----------------------------------------------
1997 1996
--------------------- ------------------
Amount % Amount %
<S> <C> <C> <C> <C>
Oil and gas sales ........................ $3,168,042 68% $2,546,676 41%
Natural gas marketing and trading ........ -- -- 2,067,379 34%
Gas plant processing ..................... 691,828 15% 818,356 13%
Oil field services and supply ............ 707,060 15% 618,225 10%
Well administration and other income ..... 92,379 2% 115,028 2%
---------- ---------- ---------- ----------
Total revenue ....................... $4,659,309 100% $6,165,664 100%
========== ========== ========== ==========
</TABLE>
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<PAGE>
The decrease in total revenue is substantially attributable to the expiration of
the Company's natural gas marketing and trading contract with Public Service
Company of Colorado effective July 1, 1996. This contract provided the Company
the opportunity to market, or broker, third party gas, at an above market
premium. This decrease in revenue was partially offset by an increase in oil and
gas revenue that has resulted from the Company's Gulf Coast activities. These
circumstances, along with any known trends or changes that effect revenue on a
line-by-line basis, are discussed in the following paragraphs under their
respective captions.
Oil and Gas
Operating statistics for oil and gas production for the periods presented are as
follows:
For the Year End
December 31,
1997 1996
---- ----
Production:
Oil (Bbls)
Rocky Mtns ......................... 80,000 100,000
Gulf Coast ......................... 43,000 --
----------- -----------
Combined Total ................ 123,000 100,000
----------- ===========
Gas (Mcf)
Rocky Mtns ......................... 392,000 412,000
Gulf Coast ......................... 91,000 --
----------- -----------
Combined Total ............... 483,000 412,000
=========== ===========
BOE (6:1)
Rocky Mtns ......................... 145,000 169,000
Gulf Coast ......................... 59,000 --
----------- -----------
Combined Total ............... 204,000 169,000
=========== ===========
Average Collected Price:
Oil (per Bbl)
Rocky Mtns ......................... $ 18.75 $ 20.35
Gulf Coast ......................... $ 19.15 $ --
----------- -----------
Combined Average ............. $ 18.89 $ 20.35
=========== ===========
Gas (per Mcf)
Rocky Mtns ........................ $ 1.46 $ 1.26
Gulf Coast ........................ $ 2.94 $ --
----------- -----------
Combined Average ............. $ 1.74 $ 1.26
=========== ===========
Per BOE (6:1)
Rocky Mtns ........................ $ 14.25 $ 15.10
Gulf Coast ........................ $ 18.76 $ --
----------- -----------
Combined Average ............. $ 15.54 $ 15.10
=========== ===========
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<PAGE>
1997 1996
---- ----
Operating Margins:
Rocky Mtns:
Revenue -
Rocky Mtns. Oil ............ $ 1,498,800 $ 2,023,419
Rocky Mtns. Gas ............ 571,213 523,257
----------- -----------
$ 2,070,013 $ 2,546,676
Costs ............................... (1,320,758) (1,426,549)
----------- -----------
Operating Margin ............ $ 749,255 $ 1,120,127
Operating Margin Percent .... 36% 44%
Gulf Coast:
Revenue -
Gulf Coast - Oil ............ $ 828,779 $ --
-----------
Gulf Coast - Gas ............ 269,250 --
----------- -----------
$ 1,098,029 $ --
Costs ............................... (165,980) --
----------- -----------
Operating Margin ............ $ 932,049 $ --
Operating Margin Percent .... 85% --
Combined Totals:
Revenue ............................. $ 3,168,042 $ 2,546,676
Costs ............................... (1,486,738) (1,426,549)
----------- -----------
Operating Margin ............ $ 1,681,304 $ 1,120,127
=========== ===========
Operating Margin Percent .... 53% 44%
Production Costs per BOE before
DD&A:
Rocky Mtn Region ................. $ 9.09 $ 8.46
Gulf Coast Region ................ 2.84 --
----------- -----------
Combined Average ............. $ 7.29 $ 8.46
=========== ===========
Change in Revenue Attributable
to:
Production ....................... $ 570,307
Price ............................ 51,059
-----------
Total Increase in Revenue ................ $ 621,366
===========
Most of the decrease in oil and gas production for the Rocky Mountain region can
be attributed to the following: 1) the sale of several marginal, uneconomic, or
nonstrategic oil and gas properties in the second quarter 1996 that accounted
for 3,900 bbls of oil and 4,500 Mcf of gas in the prior year; and 2) the natural
decline in production that is inherent in oil and gas wells. Both these
circumstances were largely offset by new production from the Gulf Coast
acquisitions and discoveries.
The operating costs per BOE for the Rocky Mountain properties increased in 1997
when compared to the same period in 1996, primarily as a result of maintenance
and stimulation procedures that were needed to maintain production. Most of the
wells in the Rocky Mountain region are between 10 and 30 years old and the
Company expects to incur higher costs from time to time since the equipment is
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<PAGE>
aging and the reservoirs are on the latter part of the decline curve. Although
the Company does not expect future costs of the Rocky Mountain properties to
increase, and anticipates that they may even be lower, future costs of the Rocky
Mountain properties are not accurately determinable based on the age of the
wells and corresponding equipment.
Natural Gas Marketing and Trading
The Company had a "take-or-pay" contract with Public Service Company of Colorado
("PSCo") which called for PSCo to purchase from the Company a minimum of 2.92
billion cubic feet ("BCF") of natural gas annually. The price paid the Company
by PSCo was based on the Colorado Interstate Gas Commission's "spot" price, plus
a fixed price bonus. The natural gas marketing and trading activities represent
natural gas that was purchased from third parties and sold to PSCo under the
terms of the contract.
Operating statistics for the Company's Marketing and Trading Activities for the
periods presented are as follows:
For the Year Ended December 31,
1997 1996
------------- ----------
Total Volume Sold (Mcf) 1,223,855
Average Price $ - $ 1.69
----------- ---------
Total Revenue $ - $2,067,379
Costs - (1,745,446)
----------- ----------
Gross Margin $ - $ 321,933
============ ==========
The contract with PSCo expired on June 30, 1996. Historically, the price paid by
PSCo under that contract was at a premium above the market and therefore allowed
for the marketing and trading activities. No marketing and trading revenues have
been generated subsequent to June 30, 1996 and considering the increased
competition fostering within all phases of the natural gas industry, it is
unlikely that the Company will resume marketing and trading activities in the
future. The loss of this premium contract was the single largest item decreasing
the Company's total revenue in 1997. In addition, since the gross margin
represented the net cash flow and income generated from this activity, the loss
of this premium contract price had a negative impact on the Company's 1997
results of operations and cash flows.
Gas Plant Processing Revenues
This category accounts for the natural gas processed and the natural gas liquids
extracted and sold by the Gas Plant facility.
-24-
<PAGE>
Operating statistics for the periods presented are as follows:
For the Year Ended December 31,
-------------------------------
1997 1996
---- ----
Production:
Natural Gas Processed (Mcf) ............... 331,900 363,000
----------- -----------
Liquids Produced -
B-G Mix (gallons) .................... 769,300 894,000
Propane (gallons) .................... 642,500 694,000
----------- -----------
Total liquids produced ........ 1,411,800 1,588,000
=========== ===========
Average Sales Price of Liquids (per gallon) ... $ 0.41 $ 0.45
=========== ===========
Gross Margin: ................................... Amount Amount
----------- -----------
Revenue .............................. $ 691,828 $ 818,356
Costs ................................ (388,851) (464,512)
----------- -----------
Gross Margin .................. $ 302,977 $ 353,844
=========== ===========
Gross Margin Percent .......... 44 % 43%
The decrease in natural gas processing volumes (per Mcf) during 1997 when
compared to 1996, can be substantially attributed to the normal decline in
production from the two fields owned and operated by the Company that supply the
gas plant with the natural gas. The change in revenue in 1997 when compared to
1996 is a direct result of the volume of natural gas processed and the
corresponding changes in liquid prices.
Costs associated with the Gas Plant operations consist of both semi-fixed and
variable costs. The semi-fixed costs consist of direct payroll, utilities,
operating supplies, general and administrative costs, and other items necessary
in the day-to-day operations. The semi-fixed costs are not expected to change
significantly regardless of the volume processed by the Gas Plant. The variable
costs consist primarily of purchased gas, plant fuel and shrink, lubricants,
repair and maintenance. These costs are generally a direct function of the
volume processed by the Gas Plant and are expected to either increase or
decrease proportionately with the corresponding plant production.
Oil Field Services and Oil Field Supply
Operating statistics for the Company's oil field service and supply operations
for the periods presented are as follows:
For the Year Ended December 31,
-------------------------------
1997 1996
----- ----
Revenue $ 707,060 $ 618,225
Costs (651,458) (553,343)
---------- ------------
Net Operating Income $ 55,602 $ 64,882
=========== ===========
Although revenue in these operations increased $88,835, or 14%, in 1997, the net
operating income was not materially different due to additional costs incurred
for repairs and maintenance and low margins realized on supply sales.
-25-
<PAGE>
Well Administration and Other Income
This revenue primarily represents the revenue generated by the Company for
operating oil and gas properties. The decrease in 1997 when compared to 1996 is
primarily attributed to several marginal wells that the Company operated were
sold in 1996.
Consulting Arrangement - Related Party
In March 1996 the Company entered into a three-year consulting agreement with
Beta Capital Group, Inc. ("Beta"). Beta, located in Newport Beach, California,
specializes in emerging companies with both capital needs and market support
requirements. Beta's chairman, Steve Antry, has been a director of the Company
since August 1996. The consulting agreement with Beta provides for minimum
monthly cash payments of $17,500 plus reimbursement for out-of-pocket expenses.
During 1997, the Company granted Beta warrants for an additional 100,000 shares
of common stock. These warrants are exercisable for a period of four years at an
exercise price of $3.75 per share. The Company has determined the value of these
options using the Black Scholes model and has recognized the fair value of
approximately $60,000 as consulting expense in the accompanying statements of
operations for the year ended December 31, 1997. An independent contractor who
works for Beta is also a member of the Company's Board of Directors.
General and Administrative
The increase in general and administrative ("G&A") expenses of approximately
$405,000 in 1997 when compared to 1996 is summarized as follows:
$ 132,000 - Severance to the Company's V.P. of Production and
Engineering who retired in light of the Company's anticipated
divestment of its Rocky Mountain assets.
70,000 - Travel and entertainment costs associated with the Company's
expansion into the Gulf Coast.
62,000 - Payroll costs associated with an increase in base pay and
insurance premiums for virtually all the Company's officers and
employees.
37,000 - For consulting services (principally legal, accounting and
land) associated with the Company's expansion into the Gulf
Coast.
37,000 - Recovery of Bad Debt in 1996 (this reduced G&A expense in
1996 - no such amounts were recovered in 1997)
25,000 - A Directors and Officers Liability Insurance Policy purchased
on July 1, 1996.
12,000 - Directors' compensation.
30,000 - All other, net.
-------
$ 405,000
=======
Although the Company has and will take steps to maintain or monitor future G&A
costs, the Company expects future G&A costs to be at those levels experienced in
1996. Even if the Rocky Mountain assets are ultimately sold, the Company does
not expect any significant reductions in future G&A expenses, at least in the
near term. This is primarily due to any reductions that may be made due to the
divestment will likely be offset by additional administrative costs associated
with the Gulf Coast exploration activities. Accordingly, future G&A costs can be
expected to be approximately $120,000 to $130,000 per month. In connection with
the Company's accounting change from successful efforts to full cost, the
Company capitalized $280,000 and $138,000 in 1997 and 1996, respectively,
certain costs associated with the Gulf Coast exploration activities that would
have been expensed as G&A under successful efforts.
Depreciation, Depletion and Amortization
Depreciation, Depletion and Amortization ("DD&A") for the periods presented by
cost center consisted of the following:
For the Year Ended December 31
1997 1996
------------- ---------
Oil and Gas Properties - Rocky Mountains $ 1,176,865 $ 1,017,859
Oil and Gas Properties - Gulf Coast 1,018,499 -
Gas Plant Operations 232,304 234,534
Service and Supply Operations 146,436 140,132
Furniture and Fixtures 49,219 45,124
Non-Compete Agreements 45,996 45,996
------------ ----------
Total $ 2,669,319 $1,483,645
========== =========
-26-
<PAGE>
As illustrated, the increase in the DD&A in 1997 when compared to 1996 is
substantially attributed to the Gulf Coast oil and gas properties.
Interest Expense
Total interest incurred, and its allocation, for the periods presented is as
follows:
For the Year
Ended December 31,
1997 1996
---- ----
Interest paid or accrued $ 448,705 $ 311,461
Amortization of debt discount 353,310 97,107
Amortization of debt issuance costs 223,003 93,860
----------- ---------
Total interest incurred $ 1,025,018 $ 502,428
Interest capitalized (323,641) -
---------- ---------
Interest expense $ 701,377 $ 502,428
=========== ========
The higher interest incurred in 1997 is reflective of the increase in the
average long-term debt outstanding and amortization of the corresponding debt
issuance/discount costs. Both of these circumstances are directly related to the
convertible debentures sold by the Company pursuant to a private placement of
convertible debentures completed in November 1996.
Impairment - Oil and Gas Properties
As previously discussed, the Company decided to change its accounting method for
oil and gas activities from successful efforts to full cost during the fourth
quarter of 1997. The full cost method regards all costs of acquisition,
exploration, and development activities as being necessary for the ultimate
production of reserves. All of those costs are incurred with the knowledge that
many of them relate to activities that do not result directly in finding and
developing reserves. However, the Company expects that the benefits obtained
from the prospects that do prove successful, together with benefits from past
discoveries, will ultimately recover the costs of all activities, both
successful and unsuccessful. Thus, all costs incurred in those activities are
regarded as integral to the acquisition, discovery, and development of reserves
that ultimately result from the efforts as a whole and are thereby associated
with the Company's proved reserves. Establishing a direct cause-and-effect
relationship between costs incurred and specific reserves discovered, which is
the premise under successful efforts, is not relevant to the full cost concept.
In light of the transformation from Rocky Mountain acquisition and development
to Gulf Coast exploration, the Company believes this method will be a preferable
method of accounting. However, the costs accumulated in the Company's full cost
pool are subject to a "ceiling", as defined by Regulation SX Rule 4-10(e)(4). At
December 31, 1997, the Company's full cost pool consisted of those costs
associated with the Gulf Coast exploration activities. As prescribed by the
corresponding accounting standards for full cost, all the accumulated costs in
excess of the ceiling, are to be expensed by a charge to impairment.
Accordingly, at December 31, 1997, the Company incurred an impairment charge of
$3,946,733 related to its Gulf Coast oil and gas properties. The majority of
this charged was the result of the dry holes drilled in 1997.
The oil and gas prices as of the date of this report were lower than those used
to estimate the reserves at December 31, 1997 by approximately $2.10 per bbl of
oil and $0.35 per Mcf of gas. The prices used for the Gulf Coast reserves at
December 31, 1997 averaged $17.11 per bbl of oil and $2.61 per Mcf of natural
gas. If commodity prices do not recover, at least to the extent being received
as of December 31, 1997, the Company could incur additional impairment charges
during the first quarter of 1998, the extent of which cannot be determined at
this time.
-27-
<PAGE>
Impairment - Assets Held For Sale
As previously discussed, the Company has decided to divest its Rocky Mountain
assets. At the time this decision was made by the Board of Directors, the
Company evaluated these assets for impairment and recognized an impairment
charge of $8,965,972. This charge was recognized during the fourth quarter of
1997 in order to reduce the net carrying value of the assets to the estimated
net realizable value of $4,048,000. This charge was larger than previously
announced on December 24, 1997 in Form 8-K because of the Company's change in
accounting method from successful efforts to full cost. As discussed in Note 2
to the Financial Statements, the cumulative effect of the change resulted in an
increase in the oil and gas properties held for sale of $3,068,165 at December
31, 1995. This cumulative effect increased the impairment recognized in 1997 and
is summarized as follows:
$2,554,861 - Impairment related to the cumulative effect of change in
accounting method ($3,068,165 net of $513,304 in DD&A for
1996 and 1997).
6,411,111 - Remaining impairment related to the assets held for sale.
$8,965,972 - Total Impairment on the Assets Held For Sale.
Dividends and Net Loss Per Common Share
Net loss per common share is computed by dividing the net loss applicable to
common stockholders (which includes accrued but unpaid preferred dividends) by
the weighted average number of common shares outstanding during the year. All
common stock equivalents have been excluded from the computations because their
effect would be anti-dilutive.
The net loss applicable to common stockholders, is determined by adding any
dividends enuring to the benefit of the preferred stockholders to the net loss.
In 1997, the dividends of $89,969 related to the Series A Preferred Stock that
automatically converted into common on June 11, 1997. On December 31, 1997, the
Company issued 113,333 shares of the newly designated Series B 5% PIK Cumulative
Convertible Preferred Stock (the "Series B Preferred Stock").
The Company has authority to issue up to 145,300 shares of Series B Preferred
Stock. The holders of the Series B Preferred Stock are entitled to dividends
equal to $2.50 per annum (currently $283,333 per year) payable quarterly in cash
or additional shares of Series B Preferred Stock at the option of the Company.
This 5% dividend will be charged to the future earnings applicable to common
stockholders. In addition, the Series B Preferred Stock becomes convertible into
common stock after March 31, 1998 at a conversion price equal to a 12% discount
to the average trading price of the common stock prior to conversion. This
discount increases monthly through March 1999 when the discount tops out at 25%.
The discount will also be accounted for as an additional dividend on the Series
B Preferred Stock which will be recognized as a charge to earnings applicable to
common stockholders in the future. Other terms of the Series B Preferred Stock
are more thoroughly discussed in Footnote 7 of the Financial Statements included
under Item 7 of this report.
OTHER MATTERS
Recently Issued Financial Accounting Standards
In June 1997, the FASB issued Statement of Financial Accounting Standards No.
130, "Reporting Comprehensive Income" ("SFAS 130"), which establishes standards
for reporting and display of comprehensive income and its components. The
components of comprehensive income refer to revenues, expenses, gains and losses
that are excluded from net income under current accounting standards, including
foreign currency translation items, minimum pension liability adjustments and
unrealized gains and losses on certain investments in debt and equity
securities. SFAS 130 requires that all items that are recognized under
accounting standards as components of comprehensive income be reported in a
financial statement displayed in equal prominence with the other financial
statements; the total of other comprehensive income for a period is required to
-28-
<PAGE>
be transferred to a component of equity that is separately displayed in a
statement of financial position at the end of an accounting period. SFAS 130 is
effective for both interim and annual periods beginning after December 15, 1997.
The Company does not believe that this SFAS will have any significant impact on
its financial statements.
In June 1997, the FASB issued Statement of Financial Accounting Standards No.
131, "Disclosures about Segments of an Enterprise and Related Information"
("SFAS 131"). SFAS 131 establishes standards for the way public enterprises are
to report information about operating segments in annual financial statements
and requires the reporting of selected information about operating segments in
interim financial reports issued to shareholders. It also establishes standards
for related disclosures about products and services, geographic areas, and major
customers. SFAS 131 is effective for periods beginning after December 15, 1997.
The Company does not believe that this SFAS will currently result in any
significant new disclosures in its financial statements.
Disclosure Regarding Forward-Looking Statements
This report on Form 10-KSB includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended (the
"Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of historical
facts included in this report, including, without limitation, statements under
"Business and Properties" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations" regarding the Company's financial position,
reserve quantities and net present values, business strategy, plans and
objectives of management of the Company for future operations and capital
expenditures, are forward-looking statements and the assumptions upon which such
forward-looking statements are based are believed to be reasonable. The Company
can give no assurance that such expectations and assumptions will prove to be
correct. Reserve estimates of oil and gas properties are generally different
from the quantities of oil and natural gas that are ultimately recovered or
found. This is particularly true for estimates applied to exploratory prospects.
Additionally, any statements contained in this report regarding forward-looking
statements are subject to various known and unknown risks, uncertainties and
contingencies, many of which are beyond the control of the Company. Such things
may cause actual results, performance, achievements or expectations to differ
materially from the anticipated results, performance, achievements or
expectations. Factors that may affect such forward-looking statements include,
but are not limited to: the Company's ability to generate additional capital to
complete its planned drilling and exploration activities; risks inherent in oil
and gas acquisitions, exploration, drilling, development and production; price
volatility of oil and gas; competition; shortages of equipment, services and
supplies; government regulation; environmental matters; financial condition of
the other companies participating in the exploration, development and production
of oil and gas programs; and other matters beyond the Company's control. In
addition, since all of the prospects in the Gulf Coast are currently operated by
another party, the Company may not be in a position to control costs, safety and
timeliness of work as well as other critical factors affecting a producing well
or exploration and development activities. All written and oral forward-looking
statements attributable to the Company or persons acting on its behalf
subsequent to the date of this report are expressly qualified in their entirety
by this disclosure.
Year 2000 Issue
The Company has begun to address possible remedial efforts in connection with
computer software that could be affected by the Year 2000 problem. The Year 2000
problem is the result of computer programs being written using two digits rather
than four to define the applicable year. Any programs that have time-sensitive
software may recognize a date using "00" as the year 1900 rather than the year
2000. This could result in a major system failure or miscalculations. The
Company has been informed by the suppliers of substantially all of the Company's
software that all of those suppliers' software that is used by the Company is
Year 2000 compliant. The Company has no internally generated software. After
reasonable investigation, the Company has not yet identified any Year 2000
problems but will continue to monitor the issue. However, there can be no
assurances that Year 2000 problems will not occur with respect to the company's
computer systems. The Year 2000 problem may impact other entities with which the
Company transacts business, and the Company cannot predict the effect of the
Year 2000 problem on such entities.
-29-
<PAGE>
ITEM 7. FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Independent Auditor's Report. . . . . . . . . . . . . . . . . . . . . . . 30
Consolidated Balance Sheets - December 31, 1997 . . . . . . . . . . . . . 31
Consolidated Statements of Operations - For the Years Ended December
31, 1997 and 1996. . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Consolidated Statements of Stockholders' Equity - For the Years Ended
December 31, 1997 and 1996 . . . . . . . . . . . . . . . . . . . . . . . 33
Consolidated Statements of Cash Flows - For the Years Ended
December 31, 1997 and 1996 . . . . . . . . . . . . . . . . . . . . . . . 34-35
Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . 36-48
-30-
<PAGE>
INDEPENDENT AUDITOR'S REPORT
Board of Directors
Pease Oil and Gas Company
Grand Junction, Colorado
We have audited the accompanying consolidated balance sheet of Pease Oil and Gas
Company and subsidiaries as of December 31, 1997, and the related consolidated
statements of operations, stockholders' equity and cash flows for the years
ended December 31, 1997 and 1996. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Pease Oil and Gas
Company and subsidiaries as of December 31, 1997, and the results of their
operations and their cash flows for the years ended December 31, 1997 and 1996
in conformity with generally accepted accounting principles.
As discussed in Note 2 to the financial statements, the Company adopted the full
cost method of accounting for oil and gas properties during the fourth quarter
of 1997.
/s/ HEIN + ASSOCIATES LLP
Denver, Colorado
March 18, 1998
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<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31, 1997
ASSETS
<S> <C>
CURRENT ASSETS:
Cash and equivalents ..................................................... $ 6,547,804
Trade receivables, net of allowance for bad debts of $24,395 ............. 757,434
Prepaid expenses and other ............................................... 43,979
---------
Total current assets ................................... 7,349,217
---------
ASSETS HELD FOR SALE ........................................................... 4,048,000
---------
OIL AND GAS PROPERTIES, at cost (full cost method):
Unevaluated properties ................................................... 4,522,917
Costs being amortized .................................................... 9,424,932
---------
Total oil and gas properties ................................ 13,947,849
Less accumulated amortization ............................................ (4,965,232)
---------
Net oil and gas properties .................................. 8,982,617
---------
OTHER ASSETS:
Debt issuance costs, net of accumulated amortization of $263,055 ......... 664,318
Deposits and other ....................................................... 167,493
Office equipment and vehicles, net of accumulated depreciation of $176,027 82,498
----------
Total other assets .......................................... 914,309
----------
TOTAL ASSETS ................................................................... $ 21,294,143
==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade .................................................. $ 1,500,239
Accrued production taxes ................................................. 204,108
Other accrued expenses ................................................... 349,396
---------
Total current liabilities ................................... 2,053,743
---------
LONG-TERM LIABILITIES:
Convertible debentures, net of discount of $1,052,297 .................... 2,922,703
Accrued production taxes ................................................. 226,019
---------
Total long-term liabilities ................................. 3,148,722
---------
COMMITMENTS AND CONTINGENCIES (Notes 4, 6, and 11) STOCKHOLDERS' EQUITY:
Preferred Stock, par value $.01 per share, 2,000,000 shares authorized,
113,333 shares of Series B 5% PIK Cumulative Convertible Preferred
Stock issued and outstanding (liquidation preference of $5,666,650).. 1,133
Common Stock, par value $.10 per share, 40,000,000 shares authorized,
issued and outstanding 15,789,955 shares ............................ 1,578,996
Additional paid-in capital ............................................... 36,875,394
Accumulated deficit ...................................................... (22,363,845)
----------
Total stockholders' equity .................................. 16,091,678
----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..................................... $ 21,294,143
==========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
-32-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 1997 and 1996
1997 1996
---- ----
REVENUE:
Oil and gas sales ...................... $ 3,168,042 $ 2,546,676
Gas plant processing ................... 691,828 818,356
Oilfield services and supply ........... 707,060 618,225
Natural gas marketing .................. -- 2,067,379
Well administration and other .......... 92,379 115,028
------------ ------------
Total revenue ............. 4,659,309 6,165,664
------------ ------------
EXPENSES:
Oil and gas production costs ........... 1,486,738 1,426,549
Gas plant .............................. 388,851 464,512
Oilfield services and supply ........... 651,458 553,343
Natural gas marketing .................. -- 1,745,446
Consulting expense-related party ....... 437,236 257,199
General and administrative ............. 1,487,236 1,082,342
Depreciation, depletion and amortization 2,669,319 1,483,645
Impairment expense:
Oil and gas properties ......... 3,946,733 --
Assets held for sale ........... 8,965,972 --
------------ ------------
Total expenses ............ 20,033,543 7,013,036
------------ ------------
LOSS FROM OPERATIONS ......................... (15,374,234) (847,372)
OTHER INCOME (EXPENSES):
Interest expense ....................... (701,377) (502,428)
Interest and other income .............. 180,774 82,557
Loss on sale of assets ................. (230) (6,660)
------------ ------------
NET LOSS ..................................... $(15,895,067) $ (1,273,903)
============ ============
NET LOSS APPLICABLE TO COMMON STOCKHOLDERS ... $(15,985,036) $ (1,476,591)
============ ============
NET LOSS PER COMMON SHARE .................... $ (1.22) $ (0.20)
============ ============
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING ............................ 13,090,000 7,278,000
============ ============
The accompanying notes are an integral part of these
consolidated financial statements.
-33-
<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 1997 and 1996
Preferred Stock Common Stock
--------------------- ------------------------
Shares Amount Shares Amount
------ ------ ------ ------
<S> <C> <C> <C> <C>
BALANCES, January 1, 1996, as previously reported ............ 202,688 $ 2,027 7,180,804 $ 718,081
Adjustment for the cumulative effect on prior
years of applying retroactively the new method
of accounting for oil and gas properties ........... -- -- -- --
-------- ------ --------- --------
BALANCES, January 1, 1996, as adjusted ....................... 202,688 2,027 7,180,804 718,081
Issuance of common stock to officers, directors, and
employees for compensation ........................ -- -- 51,490 5,149
Fair value of warrants granted for debt discount and
issuance costs .................................... -- -- -- --
Conversion of debentures into common stock ................ -- -- 82,353 8,235
Issuance of common stock for engineering services ......... -- -- 15,000 1,500
Exercise of options and warrants to purchase common stock . -- -- 67,500 6,750
Conversion of note payable to director into common stock .. -- -- 60,000 6,000
Conversion of Series A preferred stock to common stock .... (22,750) (228) 69,670 6,967
Offering costs ............................................ -- -- -- --
Net loss .................................................. -- -- -- --
-------- ------ --------- --------
BALANCES, December 31, 1996 .................................. 179,938 1,799 7,526,817 752,682
Fair value of warrants granted for services ............... -- -- -- --
Issuance of common stock for:
Acquisition of oil and gas properties .................. -- -- 318,150 31,815
Exercise of stock options .............................. -- -- 42,675 4,268
Exercise of warrants ................................... -- -- 3,192,600 319,260
Services ............................................... -- -- 6,150 615
Cash in private placements ............................. -- -- 3,792,000 379,200
Conversion of 10% collateralized convertible debentures,
net of discount ..................................... -- -- 341,665 34,166
Conversion of Series A preferred stock ................. (179,938) (1,799) 569,898 56,990
Issuance of Series B preferred stock ...................... 113,333 1,133 -- --
Offering costs ............................................ -- -- -- --
Net loss .................................................. -- -- -- --
-------- ------ ---------- ---------
BALANCES, December 31, 1997 .................................. 113,333 $ 1,133 15,789,955 $ 1,578,996
======== ====== ========== =========
<CAPTION>
Additional Accumulated Total
Paid-In Deficit Stockholders'
Capital (Note 2) Equity
---------- ----------- ------------
<S> <C> <C> <C>
BALANCES, January 1, 1996, as previously reported ............ $ 16,560,194 $ (8,263,040) $ 9,017,262
Adjustment for the cumulative effect on prior
years of applying retroactively the new method
of accounting for oil and gas properties ........... -- 3,068,165 3,068,165
------------ ------------ ------------
BALANCES, January 1, 1996, as adjusted ....................... 16,560,194 (5,194,875) 12,085,427
Issuance of common stock to officers, directors, and
employees for compensation ........................ 57,162 -- 62,311
Fair value of warrants granted for debt discount and
issuance costs .................................... 2,320,000 -- 2,320,000
Conversion of debentures into common stock ................ 61,765 -- 70,000
Issuance of common stock for engineering services ......... 21,477 -- 22,977
Exercise of options and warrants to purchase common stock . 57,625 -- 64,375
Conversion of note payable to director into common stock .. 54,000 -- 60,000
Conversion of Series A preferred stock to common stock .... (6,739) -- --
Offering costs ............................................ (13,155) -- (13,155)
Net loss .................................................. -- (1,273,903) (1,273,903)
------------ ------------ ------------
BALANCES, December 31, 1996 .................................. 19,112,329 (6,468,778) 13,398,032
Fair value of warrants granted for services ............... 240,000 -- 240,000
Issuance of common stock for:
Acquisition of oil and gas properties .................. 853,185 -- 885,000
Exercise of stock options .............................. 41,123 -- 45,391
Exercise of warrants ................................... 3,592,953 -- 3,912,213
Services ............................................... 14,236 -- 14,851
Cash in private placements ............................. 9,100,800 -- 9,480,000
Conversion of 10% collateralized convertible debentures,
net of discount ..................................... 457,888 -- 492,054
Conversion of Series A preferred stock ................. (55,191) -- --
Issuance of Series B preferred stock ...................... 5,665,517 -- 5,666,650
Offering costs ............................................ (2,147,446) -- (2,147,446)
Net loss .................................................. -- (15,895,067) (15,895,067)
------------ ------------ ------------
BALANCES, December 31, 1997 .................................. $ 36,875,394 $(22,363,845) $ 16,091,678
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
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<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1997 and 1996
1997 1996
---- ----
(Note 2)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss .......................................................... $(15,895,067) $ (1,273,903)
Adjustments to reconcile net loss to net cash provided by (used in)
operating activities:
Depreciation, depletion and amortization ............. 2,623,323 1,437,651
Amortization of debt discount and issuance costs ..... 576,313 190,967
Amortization of non-compete agreements ............... 45,996 45,996
Impairment expense:
Assets held for sale .......................... 8,965,972 --
Oil and gas properties ........................ 3,946,733 --
Loss on sale of assets ............................... 230 6,660
Issuance of common stock and warrants for services ... 74,851 85,288
Other ................................................ -- (54,942)
Changes in operating assets and liabilities:
(Increase) decrease in:
Trade receivables ........................... (157,786) 363,667
Inventory .................................. (156,822) 124,502
Prepaid expenses and other ................. 14,685 (14,316)
Increase (decrease) in:
Accounts payable ........................... 9,068 (905,027)
Accrued expenses ........................... (41,182) (109,473)
------------ ------------
Net cash provided by (used in) operating activities .. 6,314 (102,930)
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment ............ (12,137,192) (1,444,098)
Change in other assets ............................................ (95,000) 53,500
Proceeds from sale of property and equipment ...................... 66,056 163,821
------------ ------------
Net cash used in investing activities ................ (12,166,136) (1,226,777)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of Series B preferred stock .................... 5,099,985 --
Proceeds from exercise of stock options and warrants .............. 3,957,604 --
Proceeds from issuance of convertible debentures .................. -- 5,000,000
Repayment of long-term debt ....................................... (391,407) (1,795,670)
Proceeds from sale of common stock ................................ 8,920,000 133,125
Offering costs .................................................... (874,416) (13,155)
Debt issuance costs ............................................... -- (676,008)
------------ ------------
Net cash provided by financing activities ............ 16,711,766 2,648,292
------------ ------------
NET INCREASE IN CASH AND EQUIVALENTS .................................... 4,551,944 1,318,585
CASH AND EQUIVALENTS, beginning of year ................................. 1,995,860 677,275
------------ ------------
CASH AND EQUIVALENTS, end of year ....................................... $ 6,547,804 $ 1,995,860
============ ------------
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-35-
<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1997 and 1996
1997 1996
---- ----
<S> <C> <C>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest ........................................ $ 505,523 $ 192,502
========== ==========
Cash paid for income taxes .................................... $ -- $ --
========== ==========
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND
FINANCING ACTIVITIES:
Fair value of warrants granted for:
Debt issuance costs ..................................... $ -- $ 491,000
Discount on convertible debentures ...................... -- 1,829,000
Oil and gas exploration services ........................ 180,000 --
Conversion of long-term debt, net of discount, to common stock 492,054 130,000
Debt incurred for purchase of vehicles ....................... 50,691 --
Payables for:
Oil and gas properties .................................. 1,077,266 --
Offering costs .......................................... 146,765 --
Issuance of common stock for oil and gas properties .......... 885,000 --
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
-36-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Nature of Operations - Pease Oil and Gas Company (the "Company") explores
for, develops, produces and sells oil and natural gas; transports, processes,
sells and markets natural gas and natural gas liquids at a gas processing plant;
performs oil and gas well completion and operational services; and sells new,
used and reconditioned oil and gas production equipment and oil field supplies.
As discussed in Note 3, the Company intends to divest its gas processing plant
and oil field service and supply businesses. The Company conducts its business
through the following wholly-owned subsidiaries: Loveland Gas Processing
Company, Ltd. ("LGPCo"); Pease Oil Field Services, Inc.; Pease Oil Field Supply,
Inc.; and Pease Operating Company, Inc.
Principles of Consolidation - The accompanying financial statements include
the accounts of the Company and its wholly-owned subsidiaries. All material
intercompany transactions and accounts have been eliminated in consolidation.
Cash and Equivalents - The Company considers all highly liquid investments
purchased with an original maturity of three months or less to be cash
equivalents.
Oil and Gas Properties - The Company's oil and gas producing activities are
accounted for using the full cost method of accounting. The Company has one cost
center (full cost pool) since all of its oil and gas producing activities are
conducted in the United States. Under the full cost method, all costs associated
with the acquisition, development and exploration of oil and gas properties are
capitalized, including payroll and other internal costs that are directly
attributable to these activities. For the years ended December 31, 1997 and
1996, capital expenditures include internal costs of $75,000 and $10,000,
respectively. Proceeds from sales of oil and gas properties are credited to the
full cost pool with no gain or lost recognized unless such adjustments would
significantly alter the relationship between capitalized costs and proved oil
and gas reserves.
Acquisition costs of unproved properties and costs related to exploratory
drilling and seismic activities are initially excluded from amortization. These
costs are periodically evaluated for impairment and transferred to properties
being amortized when either proved reserves are established or the costs are
determined to be impaired.
The capitalized costs related to all evaluated oil and gas properties are
amortized using the units of production method based upon production and
estimates of proved reserve quantities. Future costs to develop proved reserves,
as well as site restoration, dismantlement and abandonment costs, are estimated
based on current costs and are also amortized to expense using the units of
production method.
The capitalized costs of evaluated oil and gas properties (net of
accumulated amortization and related deferred income taxes) are not permitted to
exceed the full cost ceiling. The full cost ceiling involves a quarterly
calculation of the estimated future net cash flows from proved oil and gas
properties, using current prices and costs and an annual discount factor of 10%.
Accordingly, the full cost ceiling may be particularly sensitive in the near
term due to changes in oil and gas prices or production rates.
Impairment of Long-Lived Assets - The Company performs an assessment for
impairment whenever events or changes in circumstances indicate that the
carrying amount of a long-lived asset may not be recoverable. If the net
carrying value exceeds estimated undiscounted future net cash flows, then
impairment is recognized to reduce the carrying value to the estimated fair
value.
Property, Plant and Equipment - Property, plant and equipment is stated at
cost. Depreciation of property, plant and equipment was calculated using the
straight-line method over the estimated useful lives of the assets, as follows:
Years
-----
Gas plant 17
Service equipment and vehicles 4-7
Buildings and office equipment 7-15
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Depreciation expense related to property, plant and equipment amounted to
$429,012 and $419,792 for the years ended December 31, 1997 and 1996,
respectively.
The costs of normal maintenance and repairs are charged to operating
expenses as incurred. Material expenditures which increase the life of an asset
are capitalized and depreciated over the estimated remaining useful life of the
asset. The cost of properties sold, or otherwise disposed of, and the related
accumulated depreciation or amortization are removed from the accounts, and any
gains or losses are reflected in current operations.
Non-compete Agreements - The costs of non-compete agreements were incurred
in connection with the 1993 acquisition of substantially all of the Company's
Rocky Mountain assets. These costs were being amortized over the terms of the
two to ten-year agreements on a straight-line basis. At December 31, 1997, the
remaining net book value of $260,682 was charged to impairment expense in
connection with the anticipated sale of assets discussed in Note 3.
Debt Issuance Costs - Debt issuance costs relate to the $5 million private
placement of convertible debentures discussed in Note 4. These costs are being
amortized using the interest method.
Inventory - Inventory consists primarily of oil and gas production equipment
and oil field supplies. These items are generally held for resale. At December
31, 1997, inventory also includes $99,000 of crude oil, fuel, and propane.
Inventory is carried at the lower of cost or market, cost being determined
generally under the first-in, first-out (FIFO) method of accounting, or where
possible, by specific identification.
Accounting Estimates - The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expenses during
the reporting period. The actual results could differ from those estimates.
The Company's financial statements are based on a number of significant
estimates including the allowance for doubtful accounts, fair value of assets
held for sale, assumptions affecting the fair value of stock options and
warrants, selection of the useful lives for property, plant and equipment, and
oil and gas reserve quantities which are the basis for the calculation of
amortization and impairment of oil and gas properties. Management emphasizes
that reserve estimates are inherently imprecise and that estimates of more
recent discoveries are more imprecise than those for properties with long
production histories.
Income Taxes - Deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect on previously
recorded deferred tax assets and liabilities resulting from a change in tax
rates is recognized in earnings in the period in which the change is enacted.
Revenue Recognition - The Company recognizes gas plant revenues and oil and
gas sales upon delivery to the purchaser. Revenues from oil field services are
recognized as the services are performed. Oil field supply and equipment sales
are recognized when the goods are shipped to the customer.
Net Loss Per Common Share -Net loss per common share is presented in
accordance with the provisions of Statement of Financial Accounting Standards
No. 128, Earnings Per Share (FAS 128). FAS 128 replaces the presentation of
primary and fully diluted earnings per share (EPS), with a presentation of basic
EPS and diluted EPS. Under FAS 128, basic EPS excludes dilution for potential
common shares and is computed by dividing income or loss applicable to common
shareholders by the weighted average number of common shares outstanding for the
period. Diluted EPS reflects the potential dilution that could occur if
securities or other contracts to issue common stock were exercised or converted
into common stock and resulted in the issuance of common stock. Basic and
diluted EPS are the same in 1997 and 1996 as all potential common shares were
antidilutive.
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-Based Compensation - The Company accounts for stock-based compensation
using the intrinsic value method prescribed in Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. Accordingly, compensation cost for stock options granted to
employees is measured as the excess, if any, of the quoted market price of the
Company's common stock at the measurement date (generally, the date of grant)
over the amount an employee must pay to acquire the stock.
In October 1995, the Financial Accounting Standards Board issued a new
statement titled "Accounting for Stock-Based Compensation" (FAS 123). FAS 123
requires that options, warrants, and similar instruments which are granted to
non-employees for goods and services be recorded at fair value on the grant
date. Fair value is generally determined under an option pricing model using the
criteria set forth in FAS 123.
2. CHANGE IN ACCOUNTING PRINCIPLE:
During the fourth quarter of 1997, the Company changed its method of
accounting for oil and gas producing activities from the successful efforts
method to the full cost method. The 1996 financial statements presented herein
have been restated to reflect the change.
Through December 31, 1995, the cumulative effect of the change resulted in
an increase in oil and gas properties and a decrease in the accumulated deficit
of $3,068,165. As a result of the change in accounting method, the net loss
applicable to common shareholders decreased by $138,000 ($.02 per share) in
1996, and increased by $1,970,500 ($.15 per share) in 1997.
Management believes the full cost method of accounting is preferable because
it will more accurately reflect the results of the Company's future operations.
In connection with the Company's change in strategy from primarily an
acquisition and production company to an exploration and production company, it
is now focusing its efforts in the Gulf Coast region of the United States. The
Company seeks to allocate its capital resources over a diversified portfolio of
exploration and development projects within that area. It seeks to achieve a
balance between the risks of exploratory drilling and the return on investment
by investing in projects with large potential. Dry holes, abandoned properties
and seismic projects are an inherent part of the exploration process. However,
management believes that it is through disciplined, consistent application of
this balanced portfolio strategy that the desired return on its entire
investment will be achieved. Management believes that the full cost method of
accounting is the method used by many independent oil and gas companies of
comparable size to the Company and allows investors to better measure the
performance of the Company. Management further believes that advanced three
dimensional seismic and computer-aided exploration technology has become a much
more significant factor in the success of an exploration program than in the
past. Management believes that expensing these costs when incurred, as is
required under successful efforts, is inconsistent with the value they add to
the exploration process.
3. ASSETS HELD FOR SALE:
During the fourth quarter of 1997, the Company's Board of Directors
determined that the Company's long-term strategy has shifted to exploration and
development activities in the Gulf Coast region and that the Rocky Mountain
assets should ultimately be divested. Accordingly, the Company evaluated these
assets for impairment and recognized a charge of $8,965,972 to reduce the net
carrying value of the assets to the estimated fair value of $4,048,000. Some of
the properties that will be divested are collateralized by the convertible
debentures discussed in Note 4. Consequently, a substantial portion of the net
proceeds would be required to be deposited in an account restricted for
repayment of the debentures. Therefore, the assets held for sale are excluded
from current assets in the accompanying balance sheet.
Management expects the divestiture of the majority of these assets will
occur sometime in 1998. The following is a summary of the net carrying value of
assets held for sale at December 31, 1997:
-39-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Oil and gas properties $ 3,089,081
Gas plant 250,000
Service and supply buildings and equipment,
including inventory of $278,272 708,919
-------------
Total $ 4,048,000
=============
For the year ended December 31, 1996, all of the Company's assets were
located in the Rocky Mountain region and, accordingly, all of the 1996 operating
resulting were attributable these assets. The results of operations, exclusive
of the impairment charge, related to assets held for sale for the year ended
December 31, 1997 are as follows:
Revenues $ 3,683,000
Operating costs and expenses (2,368,000)
Depreciation and amortization (1,606,000)
-------------
Loss from operations $ (291,000)
=============
4. DEBT FINANCING ARRANGEMENTS:
Long-Term Debt - Long-term debt at December 31, 1997 consists of the
following:
Convertible debentures, interest at 10%,
collateralized by certain oil and gas properties,
due April 2001 $ 3,975,000
Less unamortized discount (1,052,297)
-------------
Net carrying value $ 2,922,703
=============
Convertible Debentures and Consulting Agreement - In March 1996, the Company
entered into a consulting agreement with a company (the "Consultant") that
specializes in developing and implementing capitalization plans, including the
utilization of debt capital in business operations. The agreement expires in
March 1999, and provides for minimum monthly cash payments of $17,500. In
addition to cash compensation, the Company agreed to grant warrants to purchase
1,000,000 shares of the Company's common stock. The exercise price of the
warrants is $0.75 per share and they expire in March 2001.
In April 1996, the Company, with the assistance of the Consultant, initiated
a private placement to sell up to $5,000,000 of collateralized convertible
debentures in the form of "Units". Each Unit consists of one $50,000 five-year
10% collateralized convertible debenture and detachable warrants to purchase
25,000 shares of the Company's common stock at $1.25 per share (see Note 8 for
additional information with respect to the warrants). In November 1996, the
offering was completed and the Company was successful in selling the entire
$5,000,000 generating net cash proceeds of $4,300,000. The estimated fair value
of the detachable warrants of $1,829,000 is treated as a discount and is being
amortized using the interest method. The debentures are collateralized by a
first priority interest in certain oil and gas properties owned and operated by
the Company.
The debentures are convertible, at the holder's option, into the Company's
common stock for $3.00 per share and may be redeemed by the Company, in whole or
in part, beginning at a premium of 110% of the original principal amount subject
to adjustment beginning on April 25, 1999. During the year ended December 31,
1997, the holders of $1,025,000 of debentures elected to convert to 341,665
shares of common stock. Interest on the debentures is payable quarterly and the
principal balance is due on April 15, 2001.
The Company also agreed to pay the Consultant a fee equal to 2% of the net
proceeds from the private placement and up to 7% of the net proceeds from any
warrants which are exercised during the term of the agreement or up to six
months after termination in certain circumstances. All of the compensation paid
to the Consultant is limited to 15% of the gross proceeds generated from the
private placement, exercise of warrants, or other debt or equity financings that
may be consummated during the term of the agreement. In August 1996, a major
shareholder of the
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Consultant was elected to the Company's Board of Directors.
Notes Payable - Related Parties - In March 1996, the Company's president
agreed to extend the due date of a delinquent $60,000 note payable to him. As
consideration for the extension, the Company's Board of Directors approved
amending the note to provide for conversion to common stock at $1.00 per share.
In December 1996, the president exercised the conversion feature. During 1997,
the Company repaid other outstanding notes payable to the Company's president of
$246,719 plus accrued interest of $42,417.
5. INCOME TAXES:
Deferred tax assets (liabilities) as of December 31, 1997 and 1996 are
comprised of the following:
1997 1996
---- ----
Long-term Assets:
Net operating loss carryforwards ........... $ 5,816,000 $ 3,616,000
Property, plant and equipment ............. 229,000 (3,358,000)
Tax credit carryforwards ................... 294,000 294,000
Percentage depletion carryforwards ......... 120,000 58,000
Other ...................................... 41,000 25,000
----------- -----------
Total ............................. 6,500,000 635,000
Less valuation allowance ................... (6,500,000) (635,000)
----------- -----------
Net long-term asset ............... $ -- $ --
=========== ===========
The Company has provided a valuation allowance for the net operating loss
and credit carryforwards based upon the various expiration dates and the
limitations which exist under IRS Sections 382 and 384.
During the year ended December 31, 1997, the Company increased the
valuation allowance by $5,865,000 primarily due to an increase in the net
operating loss carryforwards which are not considered to be realizable.
At December 31, 1997, the Company had net operating loss carryforwards for
income tax purposes of approximately $15.5 million, which expire primarily in
2008 through 2012. Some of these net operating losses are subject to limitations
under IRS Sections 382 and 384. Additionally, the Company has tax credit
carryforwards at December 31, 1997, of approximately $294,000 and percentage
depletion carryforwards of approximately $320,000.
6. COMMITMENTS AND CONTINGENCIES:
Gas Contracts - The Company operates a natural gas processing plant (the
"Gas Plant"). The Company had a contract with a major utility which called for
the major utility to purchase a minimum of 2.92 billion cubic feet ("BCF") and a
maximum of 3.65 BCF of natural gas annually. The price paid by the major utility
was on an MMBTU basis above the Colorado Interstate Gas Company's Northern
Pipeline "spot" price. The contract expired on June 30, 1996.
Historically, the price paid under this contract was at a premium above the
market which allowed the Company to conduct its marketing and trading
activities. The expiration of this contract and the corresponding loss of the
market premium resulted in the elimination of the Company's marketing and
trading activities beginning in July 1996.
Employment Agreements - During 1994, the Board of Directors approved
employment agreements with the Company's executive officers. The agreements may
be terminated by the officers upon 90 days notice or by the Company without
cause upon 30 days notice. In the event of a termination by the Company without
cause, the Company would be required to pay the officers their respective
salaries for one to three years. If the termination occurs following a change in
control, the Company would be required to make lump sum payments equivalent to
two to three years salary for each of the officers.
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Profit Sharing Plan - The Company has established a 401(k) profit sharing
plan that covers all employees with six months of service who elect to
participate in the Plan. The Plan provides that the employees may elect to
contribute up to 15% of their salary to the Plan. All of the Company's
contributions are discretionary and amounted to $5,668 and $8,926 for the years
ended December 31, 1997 and 1996, respectively.
Environmental - The Company is subject to extensive Federal, state and local
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are expensed. Liabilities
for expenditures of a noncapital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated.
Year 2000 Issue - The Company has begun to address possible remedial efforts
in connection with computer software that could be affected by the Year 2000
problem. The Year 2000 problem is the result of computer programs being written
using two digits rather than four to define the applicable year. Any programs
that have time-sensitive software may recognize a date using "00" as the year
1900 rather than the year 2000. This could result in a major system failure or
miscalculations. The Company has been informed by the suppliers of substantially
all of the Company's software that all of those suppliers' software that is used
by the Company is Year 2000 compliant. The Company has no internally generated
software. After reasonable investigation, the Company has not yet identified any
Year 2000 problem but will continue to monitor the issue. However, there can be
no assurances that Year 2000 problems will not occur with respect to the
company's computer systems. The Year 2000 problem may impact other entities with
which the Company transacts business, and the Company cannot predict the effect
of the Year 2000 problem on such entities.
Contingencies - The Company may from time to time be involved in various
claims, lawsuits, disputes with third parties, actions involving allegations of
discrimination, or breach of contract incidental to the operations of its
business. The Company is not currently involved in any such incidental
litigation which it believes could have a materially adverse effect on its
financial conditions or results of operations.
7. PREFERRED STOCK
The Company has the authority to issue up to 2,000,000 shares of Preferred
Stock, which may be issued in such series and with such preferences as
determined by the Board of Directors. During 1993, the Company issued 1,170,000
shares of Series A Cumulative Convertible Preferred Stock (the "Series A
Preferred Stock"). Each share of Series A Preferred Stock was entitled to
receive dividends at 10% per annum when, as and if declared by the Company's
Board of Directors. Unpaid dividends accrued and were cumulative. During 1997,
the holders of all remaining shares of Series A Preferred Stock elected to
convert to 569,898 shares of common stock pursuant to the original conversion
terms. Upon conversion, the holders also received warrants to purchase 569,898
shares of common stock at $6.00 per share through August 13, 1998, when the
warrants expire.
In December 1997, the Board of Directors authorized a new series of
preferred stock which was designated as the Series B 5% PIK Cumulative
Convertible Preferred Stock (the "Series B Preferred Stock"). The Company has
authority to issue up to 145,300 shares of Series B Preferred Stock. The Series
B Preferred Stock provides for a liquidation preference of $50 per share and the
holders are entitled to dividends at 5% per annum, payable quarterly in cash or
additional shares of Series B Preferred Stock at the option of the Company. The
Series B Preferred Stock became convertible into common stock on March 31, 1998
at a conversion price equal to a 12% discount to the average trading price of
the common stock prior to conversion. This discount increases monthly through
March 1999 when the discount tops out at 25%. The discount will be accounted for
as an additional dividend on the Series B Preferred Stock which will be
recognized as a charge to earnings applicable to common stockholders.
Beginning on a date that is 540 days after the issuance date, the Company
may force the holders to convert to common stock at a conversion price that
generally represents a 25% discount from the fair value of the common stock.
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
If not previously converted, the Company is required to redeem the Series B
Preferred Stock on December 31, 2002 at a price equal to the Liquidation
Preference. On December 31, 1997, the Company issued 113,333 shares of Series B
Preferred Stock for $5,666,650. In connection with the issuance of the preferred
stock, the Company agreed to issue the placement agent warrants to purchase
323,800 shares of the common stock at $1.75 per share.
8. STOCK BASED COMPENSATION:
Stock Option Plans - The Company's shareholders have approved the following
stock option plans that authorize an aggregate of 1,900,000 shares for stock
options that may be granted to officers, directors, employees, and consultants:
100,000 shares in June 1991; 300,000 shares in June 1993; 150,000 shares in June
1994; 350,000 shares in August 1996; and 1,000,000 shares in May 1997.
The plans permit the issuance of incentive and nonstatutory options and
provide for a minimum exercise price equal to 100% of the fair market value of
the Company's common stock on the date of grant. The maximum term of options
granted under the plan is 10 years and options granted to employees expire three
months after the termination of employment. None of the options may be exercised
during the first six months of the option term.
No options may be granted after 10 years from the adoption date of each plan.
The following is a summary of activity under these stock option plans for the
years ended December 31, 1997 and 1996:
<TABLE>
<CAPTION>
1997 1996
----------------------------- ----------------------------
Weighted Weighted
Average Average
Number Exercise Number Exercise
Of Shares Price Of Shares Price
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Outstanding, beginning of year ......................... 621,300 $ 1.02 459,600 $ .94
Canceled ...................................... (24,825) 2.16 -- --
Expired ....................................... (5,000) 3.44 (4,000) 7.19
Granted ....................................... 640,000 2.83 -- 1.39
Exercised ..................................... (42,675) 1.06 165,700 --
---------- ---------
Outstanding, end of year ............................... 1,188,800 1.96 621,300 1.02
========== =========
</TABLE>
For all options granted during 1997 and 1996, the weighted average market
price of the Company's common stock on the grant date was approximately equal to
the weighted average exercise price. At December 31, 1997, options for 788,800
shares were exercisable and options for the remaining 400,000 shares will become
exercisable in May 1998. If not previously exercised, options outstanding at
December 31, 1997, will expire as follows:
Weighted
Average
Number Exercise
Of Shares Price
--------- ---------
Year Ending December 31,
- -----------------------
1998 15,000 $ 2.94
2000 403,925 .78
2001 85,400 1.00
2001 51,975 1.81
2002 or thereafter 632,500 2.83
--------- -------
1,188,800 $ 1.96
========= =======
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Warrants and Non-Qualified Stock Options - The Company has also granted
warrants and non-qualified options which are summarized as follows for the years
ended December 31, 1997 and 1996:
<TABLE>
<CAPTION>
1997 1996
-------------------------- --------------------
Weighted Weighted
Average Average
Number Exercise Number Exercise
Of Shares Price Of Shares Price
--------- -------- --------- --------
<S> <C> <C> <C> <C>
Outstanding, beginning of year ......................................... 7,216,585 $ 2.95 3,359,418 $ 5.00
Granted to:
Beta Capital Group, Inc. (Note 4) ............................... 100,000 3.75 1,000,000 .75
Consultants ..................................................... 50,000 3.00 90,000 .75
Directors for services .......................................... 50,000 3.00 101,500 1.00
Investors in private placement of debentures .................... -- -- 2,500,000 1.25
Brokers and underwriter in private placements ................... 622,750 2.26 223,500 2.00
Issued to underwriter and former holders of preferred
stock upon conversion ........................................... 1,031,159 5.71 69,670 6.00
Expired ............................................................ (5,000) 1.25 (60,000) 6.00
Exercised .......................................................... (3,187,600) 1.22 (67,500) .95
---------- ----------
Outstanding, end of year ............................................... 5,877,894 4.31 7,216,588 2.94
========== ==========
</TABLE>
If not previously exercised, warrants and non-qualified options will expire
as follows:
Weighted
Average
Number Exercise
Year Ending December 31, Of Shares Price
----------------------- --------- ---------
1998 574,436 $ 4.58
1999 3,395,458 5.76
2000 269,950 2.40
2001 990,250 1.08
2002 647,800 2.20
---------- ------
5,877,894 4.31
==========
Pro Forma Stock-Based Compensation Disclosures - The Company applies APB
Opinion 25 and related interpretations in accounting for stock options and
warrants which are granted to employees. Accordingly, no compensation cost has
been recognized for grants of options and warrants to employees since the
exercise prices were not less than the fair value of the Company's common stock
on the grant dates. Had compensation cost been determined based on the fair
value at the grant dates for awards under those plans consistent with the method
of FAS 123, the Company's net loss and loss per share would have been changed to
the pro forma amounts indicated below.
Year Ended December 31,
-------------------------
1997 1996
---- ----
Net loss applicable to common stockholders:
As reported $ (15,985,036) $ (1,614,270)
Pro forma (16,507,036) (1,764,270)
Net loss per common share:
As reported $ (1.22) $ (.20)
Pro forma (1.26) (.22)
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<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted average fair value of options and warrants granted to employees
for the years ended December 31, 1997 and 1996 was $1.63 and $.65, respectively.
The fair value of each employee option and warrant granted in 1997 and 1996 was
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted average assumptions:
Year Ended December 31,
-------------------------
1997 1996
---- ----
Expected volatility 63.7% 64.0%
Risk-free interest rate 6.0% 6.5%
Expected dividends - -
Expected terms (in years) 4.0 3.4
9. FINANCIAL INSTRUMENTS
Statement of Financial Accounting Standards No. 107 requires all entities to
disclose the fair value of certain financial instruments in their financial
statements. Accordingly, at December 31, 1997, management's best estimate is
that the carrying amount of cash, receivables, notes payable to unaffiliated
parties, accounts payable, and accrued expenses approximates fair value due to
the short maturity of these instruments. Management estimates that fair value is
approximately equal to carrying value of the convertible debentures since market
interest rates have not changed significantly since the offering commenced.
10. SIGNIFICANT CONCENTRATIONS:
Substantially all of the Company's accounts receivable at December 31, 1997,
result from crude oil, natural gas sales, and joint interest billings to
companies in the oil and gas industry. This concentration of customers and joint
interest owners may impact the Company's overall credit risk, either positively
or negatively, since these entities may be similarly affected by changes in
economic or other conditions. In determining whether to require collateral from
a significant customer or joint interest owner, the Company analyzes the
entity's net worth, cash flows, earnings, and/or credit ratings. Receivables are
generally not collateralized; however, receivables from joint interest owners
are subject to collection under operating agreements which generally provide
lien rights. Historical credit losses incurred on trade receivables by the
Company have been insignificant.
The Company's Rocky Mountain oil and gas properties are predominantly
located in a single basin in which the gas marketing arrangements are influenced
by local supply and demand. Accordingly, in comparison to the net price received
by gas producers in many other areas of the United States, the Company often
realizes a lower net sales price. Additionally, since the Company's gas plant is
located in this basin and its oil field service and supply operations are
conducted in this basin, the Company is vulnerable to a curtailment in drilling
activity in order to realize the value of oil field inventories and related
operating assets. As discussed in Note 3, the Company is in the process of
divesting these assets and recognized an impairment charge of $8,965,972 in the
fourth quarter of 1997.
For the year ended December 31, 1996, the Company had natural gas sales to
the major utility discussed in Note 6 which accounted for 34% of total revenues.
For the years ended December 31, 1997 and 1996, the Company also had oil sales
to a single customer which accounted for 20% and 11%, respectively, of total
revenues.
At December 31, 1997, substantially all of the Company's cash and temporary
cash investments were held at a single financial institution. The Company does
not maintain insurance to cover the risk that cash and temporary investments
with a single financial institution may be in excess of amounts insured by
federal deposit insurance.
11. OIL AND GAS PRODUCING ACTIVITIES:
Property Acquisitions - In January 1997, the Company completed the
acquisition of a 7.8125% after prospect payout working interest in a producing
oil and gas prospect in Louisiana. The prospect is operated by National Energy
Group, Inc. (NEGX), an independent oil and gas producer. The purchase price was
$1,750,000 which consisted of
-45-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$875,000 in cash and the issuance of 315,000 shares of the Company's common
stock with a fair value of $875,000. In February 1997, the Company entered into
agreements with unaffiliated parties for the purchase of a 10% working interest
in this prospect for $2.5 million.
In February 1997, the Company entered into an agreement with NEGX that
provides the Company with the right and the obligation to participate as a 12.5%
working interest owner in NEGX's defined drilling program. The agreement
provides that the Company will be required to pay 16.7% of the costs to earn its
12.5% interest, under certain circumstances. The Company is also committed to
participate in other prospects operated by NEGX through February 1999 when the
initial term of the agreement expires. Management estimates that the Company's
capital requirements under this agreement will be between $4 million and $6
million for the year ending December 31, 1998.
Full Cost Amortization Expense - Amortization expense amounted to $2,195,364
and $1,017,859 for the years ended December 31, 1997 and 1996, respectively.
Amortization expense per equivalent units of oil and gas produced amounted to
$10.95 and $6.03 for the years ended December 31, 1997 and 1996, respectively.
Natural gas is converted to equivalent units of oil on the basis of six MCF of
gas to one equivalent barrel of oil.
Unevaluated Oil and Gas Properties - At December 31, 1997, unevaluated oil
and gas properties consist of the following:
Unproved property acquisition costs $ 1,303,821
Seismic and lease option costs 3,219,096
---------
$ 4,522,917
=========
All unevaluated costs were incurred during 1997 and management expects that
planned activities for 1998 will enable the evaluation of over 50% of these
costs. Evaluation of the remaining costs is expected to occur primarily in 1999.
Capitalization of Interest - For the year ended December 31, 1997, the
Company capitalized interest costs of $323,642 related to unevaluated oil and
gas properties and other exploration activities. No interest costs were
capitalized in 1996.
Full Cost Ceiling - During the fourth quarter of 1997, the Company
recognized an impairment charge of $3,946,733 due to the full cost ceiling
limitation.
Costs Incurred in Oil and Gas Producing Activities - The following is a
summary of costs incurred in oil and gas producing activities for the years
ended December 31, 1997 and 1996:
1997 1996
------------------ --------------
Property acquisition costs $ 4,266,955 $ 16,022
Development costs 734,235 806,564
Exploration costs 9,499,572 555,685
----------- ------------
Total $ 14,500,762 $ 1,378,271
============== ============
Results of Operations from Oil and Gas Producing Activities - Results of
operations from oil and gas producing activities (excluding natural gas
marketing and trading, well administration fees, general and administrative
expenses, and interest expense) for the years ended December 31, 1997 and 1996
are presented below.
-46-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1997 1996
---- ----
Oil and gas sales $ 3,168,000 $ 2,547,000
Production costs (1,487,000) (1,427,000)
Amortization expense (2,195,000) (1,018,000)
Impairment expense (9,506,000) -
---------- ----------
Results of operations from oil and
gas producing activities $(10,020,000) $ (102,000)
=========== =========
Oil and Gas Reserve Quantities (Unaudited) - Proved oil and gas reserves are
the estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed oil and gas reserves are those reserves
expected to be recovered through existing wells with existing equipment and
operating methods. The reserve data is based on studies prepared by the
Company's consulting petroleum engineers. Reserve estimates require substantial
judgment on the part of petroleum engineers resulting in imprecise
determinations, particularly with respect to new discoveries. Accordingly, it is
expected that the estimates of reserves will change as future production and
development information becomes available. Approximately 33% of the Company's
proved developed reserves are currently non-producing as certain wells require
workovers, and recompletions, at an estimated total cost of $1.8 million. All
proved oil and gas reserves are located in the United States. At December 31,
1997, approximately 70% of the Company's proved oil and gas reserve quantities
are located in the Rocky Mountain Region. As discussed in Note 3, the Company is
in the process of divesting these properties. The following table presents
estimates of the Company's net proved oil and gas reserves, and changes therein
for the years ended December 31, 1997 and 1996.
<TABLE>
<CAPTION>
1997 1996
---------------------------- ------------------------------
Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf)
<S> <C> <C> <C> <C>
Proved reserves, beginning of year ......................... 1,175,000 4,833,000 1,294,000 5,851,000
Purchase of minerals in place ........................... 165,000 209,000 7,000 --
Sale of minerals in place ............................... (16,000) (45,000) (27,000) (26,000)
Extensions, discoveries, and
other additions .................................... 229,000 1,295,000 72,000 455,000
Revisions of previous estimates ......................... (345,000) (1,274,000) (71,000) (1,035,000)
Production .............................................. (123,000) (483,000) (100,000) (412,000)
---------- ---------- ---------- ----------
Proved reserves, end of year ............................... 1,085,000 4,535,000 1,175,000 4,833,000
========== ========== ========== ==========
Proved developed reserves, beginning of year ............... 1,034,000 4,078,000 1,014,000 4,302,000
========== ========== ========== ==========
Proved developed reserves, end of year ..................... 930,000 3,833,000 1,034,000 4,078,000
========== ========== ========== ==========
</TABLE>
During 1996, the Company recognized downward revisions in oil and gas
reserves due to disappointing results from a development well drilled that year.
During 1997, downward revisions were primarily attributable to substantially
lower oil and gas prices in effect at December 31, 1997.
Standardized Measure of Discounted Future Net Cash Flows (Unaudited) -
Statement of Financial Accounting Standards No. 69 prescribes guidelines for
computing a standardized measure of future net cash flows and changes therein
relating to estimated proved reserves. The Company has followed these guidelines
which are briefly discussed below.
Future cash inflows and future production and development costs are determined
by applying year-end prices and costs to the estimated quantities of oil and gas
to be produced. Estimated future income taxes are computed using current
statutory income tax rates including consideration for estimated future
statutory depletion and tax credits. The resulting future net cash flows are
reduced to present value amounts by applying a 10% annual discount factor.
-47-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The assumptions used to compute the standardized measure are those prescribed by
the Financial Accounting Standards Board and, as such, do not necessarily
reflect the Company's expectations for actual revenues to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process, as discussed previously, are equally applicable to
the standardized measure computations since these estimates are the basis for
the valuation process.
The following summary sets forth the Company's future net cash flows relating to
proved oil and gas reserves as of December 31, 1997 and 1996 based on the
standardized measure prescribed in Statement of Financial Accounting Standards
No. 69.
<TABLE>
<CAPTION>
1997 1996
-------------------------------------------- ----
Gulf Rocky
Coast Mountain Total
<S> <C> <C> <C> <C>
Future cash inflows .............. $ 8,560,000 $ 18,202,000 $ 26,762,000 $ 46,727,000
Future production costs .......... (1,237,000) (7,947,000) (9,184,000) (17,220,000)
Future development costs ......... (1,527,000) (1,680,000) (3,207,000) (3,001,000)
Future income tax expense ........ -- -- -- (6,200,000)
------------- ------------ ------------ ------------
Future net cash flows ... 5,796,000 8,575,000 14,371,000 20,306,000
10% annual discount for estimated
timing of cash flow .......... (1,336,000) (3,357,000) (4,693,000) (8,326,000)
------------ ------------ ------------ ------------
Standardized Measure of Discounted
Future Net Cash Flows ......... $ 4,460,000 $ 5,218,000 $ 9,678,000 $ 11,980,000
============ ============ ============ ============
</TABLE>
Changes in Standardized Measure (Unaudited) - The following are the
principal sources of change in the standardized measure of discounted future net
cash flows for the years ended December 31, 1997 and 1996:
1997 1996
---- ----
Standardized measure, beginning of year .... $ 11,980,000 $ 8,480,000
Sale of oil and gas produced, net of
production costs ....................... (1,681,000) (1,120,000)
Purchase of minerals in place .............. 2,231,000 45,000
Sale of minerals in place .................. (121,000) (45,000)
Net changes in prices and production costs . (8,437,000) 8,815,000
Net changes in estimated development costs . (185,000) 233,000
Revisions of previous quantity estimates ... (2,179,000) (3,769,000)
Discoveries, extensions, and other additions 3,214,000 1,089,000
Accretion of discount ...................... 1,198,000 848,000
Changes in income taxes, net ............... 3,658,000 (2,596,000)
------------ ------------
Standardized Measure, end of year .......... $ 9,678,000 $ 11,980,000
============ ============
Gas Plant (Unaudited) - The Company processes most of the natural gas from
its properties in a gas plant owned by the Company. Since the revenues from the
Company's properties are subject to agreements with royalty owners and, in some
cases, other working interest owners, gas processing agreements have been
entered into to set forth the contractual arrangements for processing charges.
Generally, the Company's processing fee consists of ownership of the natural gas
liquids and a portion of the residue gas that results from processing. The
Standardized Measure of Discounted Future Net Cash Flows shown above excludes
the Company's share of the natural gas liquids and residue gas related to the
Company's gas processing activities, as well as marketing and trading
activities.
-48-
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company's reserve engineer has prepared the following estimates for the
reserves related to these activities as of December 31, 1997.
Future net revenues, discounted at 10% $ 791,250
Net quantities:
Natural gas (mcf) 1,183,000
Liquids (bbls) 184,000
-49-
<PAGE>
PART II (Continued)
ITEM 8.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
This item is not applicable to the Registrant.
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT
ITEM 10 EXECUTIVE COMPENSATION
ITEM 11 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
.
ITEM 12 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by Items 9, 10, 11 and 12 are omitted because the
Company will file a definitive Proxy Statement pursuant to Regulation 14A under
the Securities Exchange Act of 1934 not later than April 30, 1998. The
information required by such items will be included in the definitive Proxy
Statement to be so filed for the Company's Annual Meeting of Stockholders
scheduled for June 13, 1998 and is hereby incorporated by reference.
-50-
<PAGE>
PART IV
ITEM 13 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
Exhibit No. Description and Method of Filing
- ---------- --------------------------------
(3.1) Articles of Incorporation, as amended. (1)
(3.2) Plan of Recapitalization. (1)
(3.3) Certificate of Amendment to the Articles of Incorporation filed on
July 6, 1994. (2)
(3.4) Certificate of Amendment to the Articles of Incorporation filed on
December 19, 1994. (2)
(3.5) Certificate of Amendment to Article IV of the Articles of
Incorporation as filed with the Nevada Secretary of State, increasing
the authorized shares of common stock of Registrant to 40,000,000
shares, $0.10 par value, incorporated by reference to Exhibit 3(i) of
the Registrant's Form 8-K dated June 11, 1997.(8)
(3.6) Bylaws, as amended and restated May 11, 1993. (1)
(4.1) Representative's Preferred Stock Purchase Warrant. (1)
(4.2) Warrant Agency Agreement between Willard Pease Oil and Gas Company and
American Securities Transfer, Inc. dated August 23, 1993. (1)
(4.3) Amendment to Warrant Agency Agreement dated as of March 3, 1998,
incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K
dated March 9, 1998.(11)
(4.4) Amendment to the Certificate of Designation of Series B 5% PIK
Cumulative Convertible Preferred Stock, incorporated by reference to
Exhibit 3.2 of Registrant's Form 8-K dated December 31, 1997.(10)
(10.1) Form of Warrants issued to Clemons F. Walker for the purchase of an
aggregate of 98,000 shares of Common Stock. (3)
(10.2) 1990 Stock Option Plan. (1)
(10.3) 1993 Stock Option Plan (1)
(10.4) 1994 Employee Stock Option Plan. (2)
(10.5) Employment Agreement effective September 16, 1994 between Pease Oil
and Gas Company and Willard H. Pease, Jr. (2)
(10.6) Employment Agreement effective December 27, 1994 between Pease Oil and
Gas Company and Patrick J. Duncan. (2)
(10.7) Employment Agreement effective December 27, 1994 between Pease Oil and
Gas Company and James N. Burkhalter. (2)
(10.8) Agreement dated August 15, 1994, between Hewlett-Packard Company,
Loveland Gas Processing Co., Ltd., Pease Oil and Gas Company and Pease
Operating Company. (2)
(10.9) Agreement between Beta Capital Group, Inc., and Pease Oil and Gas
Company dated March 9, 1996. (4)
(10.10) Form of Warrants issued to Beta Capital Group, Inc.(12)
(10.11) 1996 Stock Option Plan.(12)
(10.12) Mortgage, Assignment of Proceeds, Security Agreement and Financing
Statement from Pease Oil and Gas Company to Holders of 1996
Collateralized Subordinated Convertible Debentures dated as of
November 15, 1996.(12)
(10.13) Purchase and Sale Agreement dated December 31, 1996 by and between
Atocha Exploration, Inc., Browning Oil Company, Inc., Potosky Oil and
Gas, Inc. and Pease Oil and Gas Company. (5)
(10.14) Letter Agreement dated February 4, 1997 by and between National Energy
Group, Inc. and Pease Oil and Gas Company. (6)
(10.15) Purchase and Sale Agreement dated February 26, 1997 by and between
Transworld Exploration & Production, Inc. (7)
(10.16) 1997 Long Term Incentive Option Plan
(10.17) Preferred Stock Investment Agreement dated December 31, 1997.(10)
(10.18) Letter Agreement dated 1/16/98 between National Energy Group, Inc. and
Pease Oil and Gas Company.
-51-
<PAGE>
(10.19) Letter Agreement dated 7/22/97 between National Energy Group, Inc.,
Sullivan & Company 3-D Program 1, LLC and Willisco, Inc.
(10.20) Agreement between National Energy Group, Inc. and Acadian Geophysical
Services, Inc.
(10.21) Exploration Agreement dated 8/1/97 between Parallel Petroleum
Corporation, TAC Resources, Inc., Allegro Investments, Inc., Beta Oil
and Gas Company, Pease Oil and Gas Company, Four- Way Texas, LLC,
Meyer Financial Services, inc. and Wes-Tex Drilling Corporation
regarding the Texana Prospect
(10.22) Exploration Agreement dated 8/1/97 between Parallel Petroleum
Corporation, TAC Resources, Inc., Allegro Investments, Inc., Beta Oil
and Gas Company, Pease Oil and Gas Company, Four- Way Texas, LLC,
Meyer Financial Services, inc. and Wes-Tex Drilling Corporation
regarding the Formosa Prospect
(10.23) Exploration Agreement dated 1/1/97 between Parallel Petroleum
Corporation, Sue-Ann Production Company, TAC Resources, Inc., Allegro
Investments, Inc., Beta Oil and Gas Company, Pease Oil and Gas
Company, Meyer Financial Services, Inc., Four-Way Texas, LLC regarding
the Ganado Prospect
(10.24) Retirement, Severance and Termination of Employment Agreement from
James N. Burkhalter dated 1/1/98.
(18) Letter dated March 18, 1998 from Hein + Associates LLP regarding
preferability of full cost accounting method for oil and gas
activities.
(21) List of Subsidiaries. (3)
(23.1) Consent of McCartney Engineering, LLC, Consulting Petroleum Engineers
(23.2) Consent of Netherland, Sewell & Associates, Inc., Consulting Petroleum
Engineers
(23.3) Consent of Hein + Associates LLP, Certified Public Accountants
(27) Financial Data Schedule.
Footnotes for Exhibits:
(1) Incorporated by reference to Registration Statement No. 33-64448 on
Form SB-2.
(2) Incorporated by reference to the Registrant's 1994 Annual Report on
Form 10-KSB for the fiscal year ended December 31, 1994.
(3) Incorporated by reference to Registration Statement No. 33-94536 on
Form SB-2.
(4) Incorporated by reference to the Registrant's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1995.
(5) Incorporated by reference to Form 8-K filed January 10, 1997.
(6) Incorporated by reference to Form 8-K filed February 19, 1997.
(7) Incorporated by reference to Form 8-K filed March 17, 1997.
(8) Incorporated by reference to Form 8-K filed June 11, 1997.
(9) Incorporated by referenced to form 8-K filed December 24, 1997.
(10) Incorporated by reference to Form 8-K filed January 13, 1998.
(11) Incorporated by reference to Form 8-K filed March 9, 1998.
(12) Incorporated by reference to the Registrant's Annual Report on Form
10-KSB for the fiscal year ended December 31, 1996.
(b) Reports on Form 8-K: The Company filed the following reports on Form 8-K for
the period October 1, 1997 through the date of this report:
Item Reported Date Financial Statements
------------- ------------------------ ---------------------
(1) 5 December 24, 1997 None - Not Applicable
(2) 5,7 January 13, 1998 None - Not Applicable
(3) 5,7 March 9, 1998 None - Not Applicable
-52-
<PAGE>
SIGNATURES
In accordance with Section 13 or 15 (d) of the Exchange Act, the Registrant
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
PEASE OIL AND GAS COMPANY
Date: March 30, 1998 By:/s/ Willard H. Pease, Jr.
----------------------------
Willard H. Pease, Jr.
President and Chief Executive Officer
Date: March 30, 1998 By: /s/ Patrick J. Duncan
-------------------------
Patrick J. Duncan
Chief Financial Officer, Treasurer,
and Principal Accounting Officer
In accordance with the Exchange Act, this report has been signed below by the
following persons on behalf of the Registrant and in the capacities and on the
dates indicated.
Date: March 30, 1998 By:/s/ Willard H. Pease, Jr.
----------------------------
Willard H. Pease, Jr., President
and Chairman of the Board
Date: March 30, 1998 By: /s/ Patrick J. Duncan
-------------------------
Patrick J. Duncan
Chief Financial Officer,
Treasurer, and Director
Date: March 30, 1998 By:/s/ Steve A. Antry
---------------------
Steve A. Antry, Director
Date: March 30, 1998 By:/s/ R. Thomas Fetters, Jr.
-----------------------------
R. Thomas Fetters, Jr., Director
Date: March 30, 1998 By:/s/ Stephen L. Fischer
-------------------------
Stephen L. Fischer
Date: March 30, 1998 By:/s/ Homer C. Osborne
-----------------------
Homer C. Osborne, Director
Date: March 30, 1998 By:/s/ James C. Ruane
---------------------
James C. Ruane, Director
Date: March 30, 1998 By:/s/ Clemons F. Walker
------------------------
Clemons F. Walker, Director
Date: March 30, 1998 By:/s/ William F. Warnick
-------------------------
William F. Warnick, Director
-53-
LONG TERM INCENTIVE OPTION PLAN
PEASE OIL AND GAS COMPANY
1. Purpose of Plan. The purpose of this Long Term Incentive Option Plan
("Plan") is to secure and retain the key employees and consultants who are or
will be responsible for the success of Pease Oil and Gas Company ("Company"), to
motivate such persons to provide their best efforts on behalf of the Company, to
encourage stock ownership and to provide such persons with additional
proprietary interests in, and a greater concern for, the welfare of, and an
incentive to remain a full time employee of, the Company over a long term
For purposes of this Plan, the term "Company" shall include where
appropriate in the context used any "parent corporation" or "subsidiary
corporation" of the Company, as those terms are defined in Sections 424(e) and
(f) of the Code, whether in existence on the date of adoption of the Plan or
formed after the adoption of this Plan.
Options issued pursuant to this Plan will constitute nonqualified stock
options within the meaning of the Internal Revenue Code of 1986, as amended
("Nonstatutory Stock Options"), and the term "Option" in this Plan refers to
Nonstatutory Stock Options.
2. Stock Subject to the Plan. The number of shares of the Company's
$0.10 par value common stock ("Common Stock") which shall be reserved for
issuance upon exercise of Options issued under this Plan is 1,000,000 shares.
Such shares may consist, in whole or in part, of unissued shares or treasury
shares. The maximum number of shares of Common Stock issuable pursuant to this
Plan, including shares subject to outstanding options, shall be subject to
adjustment as provided in Section 6 of this Plan.
For purposes of this Plan, market value of shares subject to an option
shall be determined as follows:
(i) If the Common Stock is listed on a national stock exchange
or another securities exchange designated by the Committee, or admitted
to unlisted trading privileges on any such exchange, or if the Common
Stock is quoted on a National Association of Securities Dealers, Inc.
system that reports closing prices, the fair market value shall be the
closing price of the Common Stock as reported by NASDAQ, or if not so
reported then as reported by the Wall Street Journal, on the day the
fair market value is to be determined, or if no such price is reported
for such day, then the determination of such closing price shall be as
of the last immediately preceding day on which the closing price is so
reported; or
(ii) If the Common Stock is not so listed or admitted to
unlisted trading privileges or so quoted, the fair market value shall
be the average of the last reported highest bid and the lowest asked
prices quoted on the NASDAQ or, if not so quoted, then by the National
Quotation Bureau, Inc. on the day the fair market value is determined;
or
1
<PAGE>
(iii) If the Common Stock is not so listed or admitted to
unlisted trading privileges or so quoted, and bid and asked prices are
not reported, the fair market value shall be determined in such
reasonable manner as may be prescribed by the Committee.
If any outstanding Option under this Plan for any reason expires or is
terminated, the shares of Common Stock allocable to the unexercised portion of
such Option may again be optioned under this Plan subject to the limitations,
terms and conditions of this Plan. The Company, and the proper officers of the
Company, shall from time to time take appropriate action required for delivery
of Common Stock, upon any exercise of Options under this Plan.
3. Administration. Administration of the Plan shall be administered by
the Compensation Committee of the Board of Directors of the Company, hereinafter
referred to as the "Committee." The Committee shall consist of at least two
members of the Board of Directors (hereafter "Board") appointed by the Board,
none of whom is or has been an employee of the Company during the one year prior
to acting under the Plan.
Once appointed, the Committee shall continue to serve until otherwise
directed by the Board. From time to time, the Board may increase the size of the
Committee and appoint additional members thereof, remove members (with or
without cause) and appoint new members in substitution therefor, fill vacancies
however caused, or remove all members of the Committee and thereafter directly
administer the Plan.
Members of the Board who are either eligible for Options or who have
been granted Options may vote on any matters affecting the administration of the
Plan or the grant of any Options pursuant to the Plan, except that no such
member shall act upon the granting of an Option to himself, but any such member
may be counted in determining the existence of a quorum at any meeting of the
Board during which action is taken with respect to the granting of Options to
such member.
The decision of a majority of those present at any meeting of the
Committee where a quorum consisting of a majority of the Committee is present
shall constitute the decision of the Committee.
The Committee is authorized and empowered to administer the Plan
insofar as it relates to Options and, consistent with the terms of the Plan, to
(a) select the key employees or consultants to whom Options are to be granted
and to fix the number of shares and other terms and conditions of the Options to
be granted, subject to the requirements and limitations of this Plan; (b)
determine the date upon which Options shall be granted and the terms and
conditions of the granted Options in a manner consistent with the Plan, which
terms need not be identical as between Options or Optionees; (c) interpret the
Plan and the Options granted under the Plan; (d) adopt, amend and rescind rules
and regulations for the administration of the Plan insofar as it relates to
Options; (e) determine whether and the extent to which, if at all, exercise
price of outstanding options should be reduced; and (f) direct the Company to
execute Stock Option agreements pursuant to the Plan.
2
<PAGE>
The Committee shall determine in its discretion whether applicable
laws, regulations or requirements of securities trading exchanges where the
Company's securities are traded make it necessary or appropriate that the
adoption of this Plan be approved by stockholders of the Company. In the event
that stockholders approval is sought, options may be granted subject to such
approval.
All such actions of the Committee shall be binding upon all
participants in the Plan.
4. Eligibility. The persons who shall be eligible to receive grants of
Options under this Plan shall be those key employees and consultants, who may
not be employees, who may be officers or directors of the Company, who are or
who will be responsible for the management, growth and success of the business
of the Company over the long term and who shall be selected by the Committee.
The persons to receive Options under the Plan shall be selected from
time to time by the Committee, with the approval of the Board, and the Committee
shall determine, in its sole discretion, the number of shares to be covered by
the Options to be granted to each person selected. No person may be granted an
Option if such person, at the time the Option is granted, owns shares of Common
Stock possessing more than 10% of the total combined voting power of all classes
of stock of the Company on a fully diluted basis (i.e., considering all
outstanding shares of Common Stock and all shares which the Company is obligated
to issue within three years at the time of action). For purposes of calculating
such stock ownership, the beneficial ownership rules of stock ownership set
forth in regulations adopted under the Securities Exchange Act of 1934, as
amended ("1934 Act") shall apply.
5. Terms and Conditions. The Plan shall become effective upon the
approval and adoption by the Board of Directors. It shall continue in effect for
a period of ten years from the date of its effectiveness.
All Options granted under this Plan shall be subject to the terms and
conditions of this Plan, including all of the following:
(a) Option Price. The Option price per share shall be
determined by the Committee but shall not be less than 90% of the fair
market value of such shares at the time the Option is granted.
(b) Limitations on Grant of Options. No Option shall be
granted which may be exercised sooner than three years nor more than
ten years after the date it was granted. Subject to Section 5(q) below,
Options may not become exercisable (i.e., "vest") as to more than
one-third of the total shares represented by an Option grant in any
year and no Option shall vest before three years from the date of
grant.
3
<PAGE>
(c) Limitations on Exercise of Option. No Optionee granted an
Option under this Plan may exercise an Option unless at all times
during the period beginning on the date of the granting of the Option
and ending on the day three months before the date of such exercise
such Optionee was employed by the Company or a corporation or
subsidiary thereof issuing or assuming the Option in a transaction
referred to in Section 6 of this Plan, provided that if the Optionee
was an employee at the time of grant of the Option and continues to be
employed through the time that the Option is fully vested, then the
Option may be exercised for one year from termination of employment
unless the Optionee takes action which is materially adverse to the
best interests of the Company, determined in the discretion of the
Committee, prior to exercise of the Option..
(d) Payment for Shares. Payment in full, in cash, shall be
made for all shares issued pursuant to the exercise of an Option,
provided that the Committee may permit payment to be made with shares
of the Company's Common Stock owned by the Optionee to be valued at the
fair market value at the date of exercise. All Options shall be
exercised for 100 shares, or a multiple thereof, or for the full number
of shares for which the Option is then exercisable. No Optionee shall
have the right to dividends or other rights of a stockholder with
respect to shares subject to an Option until the Optionee has given
written notice of exercise of the Optionee's Option and paid in full
for such shares.
(e) Manner of Exercise. Any Option granted pursuant to this
Plan may be exercised at such time or times as set forth in the Option,
by the delivery of written notice to any officer of the Company, other
than the Optionee, together with payment in full, for the number of
shares to be purchased pursuant to such exercise. Such notice (i) shall
state the election to exercise the Option, (ii) shall state the number
of shares in respect of which the Option is being exercised, (iii)
shall state the Optionee's address, (iv) shall state the Optionee's
social security number, (v) shall contain such representations and
agreements concerning Optionee's investment intent with respect to such
shares of Common Stock as shall be satisfactory to the Company's
counsel, (vi) shall state that the certificate evidencing the shares
may be stamped with a restrictive legend and the shares evidenced by
such certificate will constitute "restricted securities" as defined in
Rule 144 promulgated under the Securities Act of 1933, as amended (the
"Act") (unless the shares to be acquired are registered under the Act)
and (vii) shall be signed and dated by Optionee.
(f) Conditions of Issuance of Shares. Shares shall not be
issued pursuant to the exercise of an Option unless the exercise of
such Option and the issuance and delivery of such Shares pursuant
thereto shall comply with all relevant provisions of law, including,
without limitation, the Act, the 1934 Act, the rules and regulations
promulgated thereunder, applicable state securities law, and the
requirements of any stock exchange or automated quotation system upon
which the Share may be listed or quoted, and shall be subject to the
approval of legal counsel for the Company with respect to such
compliance.
4
<PAGE>
(g) Limitation on Transfer of Shares. Unless shares issued
upon exercise are at the time of exercise registered under the Act, all
shares of Common Stock acquired by an Optionee upon exercise of an
Option granted under this Plan shall be deemed to be "restricted
securities" as defined in Rule 144 promulgated under the Act and the
certificate evidencing such shares shall contain a legend as follows:
"The securities represented by this certificate may not be
offered for sale, sold or otherwise transferred except
pursuant to an effective registration statement under the
Securities Act of 1933 (the `Act') or pursuant to an exemption
from registration under the Act, the availability of which is
to be established to the satisfaction of the Company."
(h) Other Representations or Warranties. As a further
condition to the exercise of any Option granted under this Plan, the
Company may require each Optionee to make any representation and
warranty to the Company as may be required by any applicable law or
regulation, including making arrangements, approved by the Committee,
for payment of any applicable withholding taxes.
(i) Death of Optionee. If an Optionee (or a transferee of the
Option) dies, any Option previously granted to the Optionee shall be
exercisable by the personal representa tive or administrator of the
deceased Optionee's estate, or by any trustee, heir, legatee or
beneficiary (collectively referred to for convenience as the "legal
representative") who shall have acquired the Option directly from the
Optionee by will or by the laws of descent and distribution at any time
within one year after his death, but not more than ten years after the
date of granting of the Option, provided the deceased Optionee was
entitled to exercise such Option at the time of his death. Prior to the
exercise of any such Option, the legal representative of the deceased
Optionee shall furnish to the Company written notice of such exercise,
together with a certified copy of letters testamentary or other proof
deemed sufficient by the Committee of the right of the legal
representative to exercise such Option in accordance with the
provisions of this Plan.
(j) Retirement. If an Optionee's employment with the Company
terminates by reason of retirement, any Option previously granted to
him shall be exercisable as determined in the sole discretion of the
Committee at any time within three months after the date of such
termination, but not more than ten years after the date of granting of
the Option, and then only to the extent to which it was exercisable at
the time of such termination by retirement; provided, however, that if
the Optionee dies within three months after termination by retirement,
any unexercised Option, to the extent to which it was exercisable at
the time of his death, shall thereafter be exercisable for one year
after the date of his death, but not more than ten years after the date
of granting of the Option.
5
<PAGE>
(k) Disability. If an Optionee becomes disabled within the
meaning of Section 22(e)(3) of the Code, and at the time of such
disability the Optionee is entitled to exercise an Option, the Optionee
shall have the right to exercise such Option within one year after such
disability provided that the Optionee exercises the Option within ten
years after the date of grant, and then only to the extent to which it
was exercisable at the time of such disability.
(l) Optionee's Termination. If an Optionee ceases to serve an
employee of the Company or a subsidiary, as the case may be, for any
reason other than death, retirement or disability, any Option
previously granted to the Optionee which was exercisable at the time of
termination shall terminate three months after the date of such
termination or at such earlier time as provided in the terms of the
Option granted to the Optionee. To the extent that an Option is not
exercised within the time specified herein, the Option shall terminate.
Options which were not exercisable on the date of termination shall
terminate upon termination.
(m) Leave of Absence. For the purposes of this Plan (i) a
leave of absence, duly authorized in writing by the Company for
military service or sickness, or for any other purpose approved by the
Board, if the period of such leave does not exceed 90 days and (ii) a
leave of absence in excess of 90 days, duly authorized in writing by
the Company provided the Optionee's right to re-employment is
guaranteed either by statute or by contract, shall not be deemed a
termination of employment.
(n) Option Agreement. Any Option granted under this Plan shall
be in accordance with the Plan and shall be in the form of the Stock
Option Agreement attached as Exhibit A attached hereto.
(o) Transferability of Options. Except by will or the laws of
descent and distribution, an Option may not be sold, pledged, assigned,
hypothecated, transferred, or disposed of in any manner during the
period ending two years from the date of grant of the Option and
thereafter only (i) after written notice to the Board and (ii) in a
manner which is in compliance with all applicable provisions of the
Act, as amended and the 1934 Act to the reasonable written satisfaction
of the Company, given before transfer is effected. Upon any permitted
sale or other transfer, the transferee shall remain subject to all
terms and conditions of the Plan and the Stock Option Agreement. Upon
any permitted transfer of an Option, the written Stock Option Agreement
shall be delivered to the Company for registration of the transfer to
any transferee.
(p) Exercisability of Options. No Optionee granted an Option
under this Plan shall be entitled to exercise such Option at any time
after the expiration of such Option as specified in the Stock Option
Agreement evidencing the Option.
6
<PAGE>
(q) Vesting Upon Change of Control. An Option granted under
this Plan to an employee shall become exercisable (i.e., "vest") in
full if the employee to whom an Option has been granted is terminated,
has his or her salary involuntarily reduced by more than 10% or has his
or her duties, authority and responsibility materially reduced or
restricted within one year following a change of control of the
Company. For purposes of this Section 5(q), a change of control shall
mean any of the following: (i) at any time the Board of Directors
includes a majority of directors who have served as directors for less
than one year, or (ii) within one year following a merger or other
combination of the principal business of the Company with another
entity, one or more of the four most highly paid executive officers of
the Company is discharged or reassigned to substantially reduced
responsibilities with the surviving entity, or the Optionee's salary
has been voluntarily reduced by 10% or more, or Optionee's duties,
authority and responsibilities have been materially reduce or
restricted..
6. Adjustments Upon Recapitalization, Merger, Etc. If the outstanding
shares of Common Stock of the Company shall at any time be changed or exchanged
by declaration of a stock dividend, split-up, subdivision or combination of
shares, recapitalization, merger, consolidation or other corporate
reorganization in which the Company (including a merger or similar
reorganization which effects a reincorporation of the Company in a different
county or province) is the surviving corporation, the number and kind of shares
subject to this Plan or subject to any Options previously granted, and the
Option prices, shall be appropriately and equitably adjusted, so as to maintain
the proportionate number of shares without changing the aggregate Option price.
In the event of a dissolution or liquidation of the Company, or a merger,
consolidation, sale of all or substantially all of its assets, or other
corporate reorganization in which the Company is not the surviving corporation
and the holder of Common Stock receives securities of another corporation, then
any outstanding Options hereunder shall terminate as of the effective date of
such event; provided that immediately prior to such event each Optionee shall
have the right to exercise any unexpired Option in whole or in part whether or
not the Option would otherwise be exercisable. The Company shall afford each
person who holds an Incentive Stock Option under this Plan with at least 30 days
advance written notice of such event. The existence of this Plan, or of any
Options hereunder, shall not in any way prevent any transaction described in
this section, nor shall anything contained in this Plan prevent the substitution
of a new Option by a surviving corporation.
7. Use of Proceeds. Proceeds from the sale of stock pursuant to Options
granted under this Plan shall constitute general funds of the Company may be
used for such general corporate purposes as the Board shall determine.
8. Reservation of Issuance of Shares. The Company shall at all times
during the duration of this Plan reserve and keep available such number of
shares of Common Stock as will be sufficient to satisfy the requirements of all
Options granted pursuant to this Plan, and shall pay all original issue and
transfer taxes with respect to the issuance of shares pursuant to the exercise
7
<PAGE>
of such Options, and shall pay all of the fees and expenses necessarily incurred
in connection with the exercise of such Options and the issuance of such shares.
9. Amendments. The Board of Directors may amend, alter, or discontinue
this Plan, but no amendment, alteration or discontinuation shall be made which
would impair the rights of any Optionee under any Options previously granted,
without the Optionee's consent.
Any such amendment or termination of the Plan shall not affect Options
already granted and such Options shall remain in full force and effect as if the
Plan had not been amended or terminated, unless mutually agreed otherwise
between the Optionee and the Company in a writing signed by both parties.
10. Indemnification. In addition to such other rights of
indemnification as they may have as directors, the members of the Committee and
the Board shall be indemnified by the Company against reasonable expenses,
including attorneys' fees actually incurred in connection with the defense of
any action, suit or proceeding, or in connection with any appeal therefrom, to
which they or any of them may be a party by reason of any action taken or
failure to act under or in connection with this Plan or any Option granted
hereunder, or shares purchased pursuant to the exercise of Options under this
Plan, and against all amounts paid by them in settlement thereof (provided such
settlement is approved by independent legal counsel selected by the Company) or
paid by them in satisfaction of judgment in any action, suit or proceeding,
except in relation to matters as to which it shall be adjudged in such action,
suit or proceeding, that such member of the Board of Directors is liable for
gross negligence, fraud or willful misconduct in the performance of the
director's duties so long as within 60 days after institution of any such
action, suit or proceeding, the director shall in writing offer the Company the
opportunity, at its own expense, to handle and defend such action, suit or
proceeding.
11. Miscellaneous. Unless the context requires otherwise, words
denoting the singular may be construed as denoting the plural, and words
denoting the plural may be construed as denoting the singular, and words of one
gender may be construed as denoting such other gender
8
<PAGE>
as is appropriate. Paragraph headings are not to be considered part of this Plan
and are included solely for convenience and are not intended to be full or
accurate descriptions of the contents thereof.
Adopted by Directors:
PEASE OIL AND GAS COMPANY
organized under the laws of Nevada
ATTEST:
By __________________________________
Willard H. Pease, Jr., Chairman
- --------------------------------------
Patrick J. Duncan, Secretary
S E A L
9
January 16, 1998
Mr. Willard Pease, Jr., President
Pease Oil and Gas Company
751 Horizon Court, Suite 203
P.O. Box 60219
Grand Junction, CO 81506-8758
Re: Letter Agreement
3D Seismic Survey Participation and
Amendment of Agreement dated February 4, 1997
Dear Mr. Pease:
Pursuant to our discussions, this Letter Agreement shall act to express
the mutual understanding and agreement by and between National Energy Group,
Inc. ("NEG") and Pease Oil and Gas Company ("Pease") with respect to
participation in that certain 3D seismic survey currently being conducted by NEG
over an approximate 54 square mile area located in Iberville Parish, Louisiana
(the "3D Survey") as more particularly described on Exhibit "A", attached hereto
and incorporated herein, and subject to the terms and conditions hereof.
WHEREAS, NEG and Pease are parties to that certain Letter Agreement
dated February 4, 1997 pertaining to Pease's participation in certain Prospects
of NEG (the "February 4, 1997 Agreement") incorporated by reference herein; and
WHEREAS, NEG is a party to that certain agreement dated July 22, 1997
by and between NEG and Sullivan and Company 3D Program I, L.L.C. ("Sullivan")
pertaining to the 3D Survey and certain obligations to Sullivan in connection
therewith (the "Sullivan Agreement"), incorporated by reference herein as
Exhibit "A-1"; and
WHEREAS, NEG and Acadian Geophysical Services, Inc. are parties to that
certain Geophysical Services Agreement dated October 10, 1997 providing for
various services and a 3D seismic data survey within the 3D Survey Area (the
"Geophysical Services Agreement"), incorporated by reference herein as Exhibit
"A-2"; and
WHEREAS, NEG and Pease desire to amend certain aspects of the February
4, 1997 Agreement as more particularly described below, provide for Pease's
participation in the 3D Survey and create an area of mutual interest within the
area encompassed by the 3D Survey (the "3D Survey Area").
NOW THEREFORE, in consideration of the mutual covenants and agreements
herein contained and good and valuable consideration, the sufficiency of which
is hereby acknowledged, the parties agree as follows:
1. Participation. NEG and Pease agree that Pease shall (i) have the right and
the obligation to participate in the 3D Survey with NEG as the Operator,
(ii) increase its participation and obligation from 1/8th interest to
3/16ths interest with respect to the NW Bayou Sorrel and Berry Bayou
Prospects described in the February 4, 1997 Agreement, and (iii) purchase a
14.0625% interest in any leases acquired from Panaco, Inc. by agreement
dated November 11, 1996 (the "Panaco Acquisition") only as to depths below
the L4 Sand, the base of which is defined as occurring at a measured log
depth of 11.340 feet in the NEG Schwing #1 well located in 2-T10S-R11E,
Iberville Parish, Louisiana (the "L4 Sand"); provided Pease:
1.1 shall, upon execution and delivery of this Letter Agreement,
pay an amount equal to $1,228,510.00, as more particularly
described on Schedule 1 hereto;
1.2 shall pay, within fifteen (15) days of receipt of an invoice
from NEG, 14.0625% of all costs relating to the 3D Survey
incurred by NEG after December 31, 1997;
1.3 shall ratify and agree to be bound by the terms and conditions
of the Sullivan Agreement and accept liabilities for its
14.0625% proportionate share thereof;
1.4 shall ratify and agree to be bound by all permits, leases
and/or other agreements now existing or hereafter acquired by
NEG relating to the 3D Survey and accept liability for its
14.0625% proportionate share thereof;
1.5 shall ratify and agree to be bound by the terms and conditions
of the Geophysical Services Agreement and accept liabilities
for its 14.0625% proportionate share thereof;
1.6 shall ratify and agree to be bound by the terms and conditions
of any agreement and/or amendments to the existing Agreement
between NEG and Sandefer Oil & Gas Inc. ("SOG") dated January
1, 1996 (the "SOG Agreement") and the Consulting Agreement
between SOG and Potosky Oil & Gas Inc. and Atocha Exploration,
Inc. dated January 1, 1996, each of which are incorporated by
reference herein, which may relate to the 3D Survey and/or the
3D Survey Area; provided that NEG shall bear the burden of the
SOG Deferred Leasehold Interest described in Paragraph 17 of
the SOG Agreement;
1.7 shall enter into a Joint Operating Agreement ("JOA") on all
leases owned and Prospects developed within the 3D Survey
Area, it being understood and agreed that such JOA shall be in
the form of JOA attached hereto as Exhibit "B"; and
1.8 shall agree to amend the February 4, 1997 Agreement in
accordance with the terms and conditions hereof.
2. Interest. Subject to the conditions described in Paragraph 1 above,
Pease shall earn and become entitled to receive from NEG an interest in
any Prospect developed within the 3D Survey Area on a promoted basis as
follows:
2.1 The February 4, 1997 Agreement shall be, and hereby is amended
to provide that Pease's interest in the NW Bayou Sorrel
Prospect, Berry Bayou Prospect, and any other Prospect
developed within the 3D Survey Area (save and except (i) that
portion of the Louisiana State Lease #2102 which is or may be
located in the producing units of the Schwing #1, Schwing #2
and Schwing #3 wells in Iberville Parish, Louisiana, (ii) any
existing units or wells drilled within the 3D Survey Area
acquired from Panaco, Inc. pursuant to the Panaco Acquisition
and all rights above the L4 Sand in such existing units, and
(iii) any Prospect within the existing East Bayou Sorrel Area
of Mutual Interest, other than those Prospects at depths below
the L4 Sand included in the Panaco Acquisition and fall within
such East Bayou Sorrel Area of Mutual Interest) shall be
increased to include a participation interest equal to
14.0625% for such Prospects; provided that Pease shall be
obligated to pay to NEG 18.75% of costs to casing point for
the initial well in each Prospect, 18.75% of the Prospect fee
for each Prospect and 18.75% of all land costs incurred prior
to December 31, 1997. All land costs for each such Prospect
incurred after December 31, 1997 and not otherwise provided
for herein or in the February 4, 1997 Agreement shall be
billed to Pease at its participation interest percentage of
14.0625%, and NEG and Pease agree that Pease shall forfeit all
right to participate in any lease acquired within the 3D
Survey Area after December 31, 1997 for which it has not made
full payment to NEG within fifteen (15) business days of
receipt of an invoice from NEG pertaining to such lease
acquisition costs; provided, however, that Pease shall not be
subject to such forfeiture unless Pease shall have received
from NEG within 48 hours of such forfeiture a "final notice"
that NEG is not in receipt of payment of such land costs. NEG
agrees that it shall assign to Pease its full interest in
leases already acquired and shall furnish copies of all 3D
Survey Area lease acquisitions and any lease purchase reports
described herein on or before April 1, 1998; and
2.2 Pease shall acquire 14.0625% of NEG's ownership interest in
and Pease shall be given copies of any data collected,
processed and delivered to NEG relating to the 3D Survey (the
"Data") pursuant to the Geophysical Services Agreement within
seven (7) days of receipt of such Data by NEG; provided that
Pease shall be prohibited from selling, licensing or in any
manner disseminating the Data to any third parties which are
not a party to this Letter Agreement for a period of five (5)
years from the date of execution hereof without the express
written consent of NEG; provided further, in the event either
party hereto shall sell or license any of the Data to any such
third party, the other party hereto shall be entitled to its
proportionate share of any proceeds derived therefrom. NEG
shall use its best efforts to maintain the Data in a
reasonably prudent manner.
3. Acknowledgement. Each of NEG and Pease hereby acknowledges and
agree that (i) the February 4, 1997 Agreement shall be, and hereby is
amended with, and only with, respect to the subject matter hereof
pertaining to Pease's participation in the 3D Survey and any Prospects
generated therefrom described in Paragraph 2 hereof, (ii) nothing
contained herein shall act or be construed to increase the
participation interest of Pease in any Prospect described in the
February 4, 1997 Agreement (other than as provided in Paragraph 2
hereof) without the express written agreement of the parties hereto,
and (iii) all other provisions of the February 4, 1997 Agreement shall
remain in full force and effect in accordance with its terms.
4. Term. The term of this Letter Agreement shall be for a period of
five (5) years from the date of execution hereof.
5. CHOICE OF LAW. THIS LETTER AGREEMENT, THE LEGAL RELATIONSHIP OF THE
PARTIES AND ALL RIGHTS AND OBLIGATIONS HEREUNDER SHALL BE GOVERNED BY
AND INTERPRETED, CONSTRUED, APPLIED AND ENFORCED IN ACCORDANCE WITH THE
LAWS OF THE STATE OF TEXAS, WITHOUT REFERENCE TO THE LAWS OF ANY OTHER
JURISDICTION.
6. Mediation/Arbitration. In the event of a dispute between the
parties to this Letter Agreement, the parties agree not to seek any
relief nor file any action in a court of law or equity, but shall
participate in good faith negotiations in mediation in Dallas, Texas
with a mediator experienced in oil and gas transactions certified by
the American Arbitration Association or comparable organization, the
costs of such mediator to be borne equally by each of the parties. In
the event a resolution is not agreed, the parties further agree to
participate in binding arbitration in Dallas, Texas with arbitrator(s)
experienced in oil and gas transactions pursuant to the rules of the
American Arbitration Association or similar organization, the costs of
which may be awarded to the prevailing party together with a binding
and nonappealable judgment on the award which may be entered in any
court having competent jurisdiction.
7. Notices. Any notice required hereunder shall be in writing; delivered
to or sent by U.S. Mail, postage pre-paid, or nationally recognized
commercial carrier service, postage or delivery charges pre-paid, or by
telecopy with a copy delivered to the U.S. Mail, postage pre-paid,
addressed as follows (or such other address as may be specified by five
(5) days prior written notice to the other party hereto):
NEG: PEASE:
National Energy Group, Inc. Pease Oil and Gas Company
4925 Greenville Avenue 751 Horizon Court, Suite 203
Suite 1400 P.O. Box 60219
Dallas, Texas 75206-4095 Grand Junction, Colorado 81506
Attn: Mr. William T. Jones Attn: Mr. Willard Pease, Jr.
Sr Vice President-Operations President
Phone: (214) 692-9211 Phone: (970) 245-5917
Fax: (214) 692-9310 Fax: (970) 243-8840
8. Assignment. This Letter Agreement shall inure to the benefit of and be
binding upon NEG and Pease and their respective successors and assigns.
9. Completeness. This Letter Agreement supersedes all prior written or
oral agreements and understandings between the parties and constitutes
the complete agreement between the parties with respect to the subject
matter hereof. This Letter Agreement cannot be modified or amended
except by written instrument duly executed by NEG and Pease.
If the foregoing expresses our mutual understanding and agreement,
please so indicate by executing in the appropriate space below and returning one
(1) fully executed copy to the undersigned.
Sincerely,
William T. Jones
Senior Vice President - Operations
PDD:mjg
ACCEPTED AND AGREED this
______ day of January, 1998.
Pease Oil and Gas Company
- ---------------------------------
By: Willard H. Pease, Jr.
Title: President and CEO
C:\MJG\LETTERS\WillardPease,Jr.-011698
July 22, 1997
VIA FACSIMILES (918) 584-4220, (713) 496-3555
AND FEDERAL EXPRESS
Mr. R. J. Sullivan, Jr., Manager
Sullivan and Company 3 D Program I, L.L.C.
3031 First Place Tower
15 East Fifth Street
Tulsa, OK 74103-4331
Mr. Buzz Bainbridge, President
Willisco, Inc.
15995 North Barker's Landing
Suite 200
Houston, TX 77079-2418
Re: Letter of Agreement
Bayou Sorrel Prospect
Iberville Parish, Louisiana
Gentlemen:
This Letter Agreement shall evidence the mutual understanding and agreement of
National Energy Group, Inc. ("NEG"), and Sullivan and Company 3 D Program I,
L.L.C. ("Sullivan") and Willisco, Inc. ("Willisco") with respect to various
discussions, proposals and agreements among the parties relating to a 3 D
seismic survey, known as the Bayou Sorrel 3 D Survey Project (the "Project").
Sullivan and Willisco are sometimes hereinafter collectively referred to as
("Sullivan / Willisco").
NOW THEREFORE, in consideration of the mutual covenants and agreements
herein contained and good and valuable consideration, the receipt and
sufficiency of which is hereby acknowledged, the parties hereto agree as
follows:
(1) The Project shall be comprised of an approximate 55 square
mile area encompassing the lands and leaseholds more fully
described on the map designated as Exhibit "A", attached
hereto and incorporated herein.
<PAGE>
Mr. R. J. Sullivan, Jr., Manager
Sullivan and Company 3 D Program I, L.L.C.
Mr. Buzz Bainbridge, President
Willisco, Inc.
July 22, 1997
Page Two
(2) Sullivan and Willisco shall assign to NEG 100% of all permits,
leasehold agreements, options and/or other forms of interests
relating to ownership and/or authority to conduct the Project
survey (the "Permits") more fully described on Exhibit "B",
attached hereto and incorporated herein, which are presently
controlled by Sullivan and/or Willisco or at anytime
hereinafter acquired; provided that Sullivan/Willisco agree
that as of the date of execution hereof, neither shall execute
any additional Permits without the express written consent of
NEG.
(3) In consideration hereof, NEG shall make a cash payment to
Sullivan / Willisco in the aggregate amount of $625,000 (which
amount shall be subject to audit by NEG and supported by
actual, direct third party charges paid by Sullivan and/or
Willisco), together with assignment of a 3% overriding royalty
interest (the "ORRI") up to and including an amount which
shall not exceed $625,000, net of severance taxes, to be
derived from production attributable to all leases owned of
record on June 6, 1997, and those leases acquired and or
renewed between June 6, 1997 and June 30, 2000 in the Project
area, except for and excluding those certain leases in the
East Bayou Sorrel Field and existing, current production
attributable to the Bayou Sorrel Field, all of which are more
fully described on Exhibit "C", attached hereto and
incorporated herein.
(4) NEG shall own all data acquired and processed in the Project
area (the "Data") until the earlier of (i) a period of thirty
(30) months following completion of the field survey by the
seismic crews accessing the Data or (ii) a period of thirty
(30) months after July 1, 1998, at which time the Data shall
become an undivided joint ownership of NEG in an amount equal
to 50% and to Sullivan / Willisco in an aggregate amount equal
to 50%; provided that Sullivan / Willisco acknowledge and
agree that the ownership interest acquired by NEG and/or
Sullivan / Willisco may be in the form of a license in the
event NEG shall determine that it is in its best interest to
participate in a speculative 3-D seismic survey, rather than a
proprietary 3-D seismic survey over the Project.
(5) NEG shall have a fourteen (14) day period following receipt of
a fully executed copy of this Letter Agreement to review all
materials, maps, financial records, Permits, Data or other
information (the "Information") related to the Project which
it deems necessary and proper to conduct its due diligence
investigation of the Project (the "Due Diligence Review").
(6) Neither party shall engage in any activities, directly or
indirectly, which shall act to circumvent the other with
respect to the subject matter hereof, and Sullivan / Willisco
specifically agree that for a period of two (2) years after
January 1, 1998 it shall not engage in any activities,
directly or indirectly, which compete with NEG in the Project
area; provided that following execution and delivery of this
Letter Agreement, NEG shall be permitted to contact any and
all parties within the Project area, including those parties
which have executed Permits with Sullivan / Willisco or have
been contacted by Sullivan / Willisco with respect to the
Project.
<PAGE>
Mr. R. J. Sullivan, Jr., Manager
Sullivan and Company 3 D Program I, L.L.C.
Mr. Buzz Bainbridge, President
Willisco, Inc.
July 22, 1997
Page Three
(7) Subject only to the Due Diligence Review of NEG, the parties
hereto agree to execute, deliver and perform as contemplated
herein, including, but not limited to, the execution, delivery
and performance of such documents and take such actions as the
other party or parties may reasonably request in order to more
effectively consummate the transaction's contemplated hereby;
provided that in the event NEG shall discover during its Due
Diligence Review a material fact or facts which shall have a
material effect on the Project as contemplated herein, then in
such event, NEG shall have the right, upon written notice to
Sullivan / Willisco, to terminate this Letter Agreement and
any obligations contained herein, except with respect to the
confidentiality of the Information as provided herein.
(8) MISCELLANEOUS.
a. This Letter Agreement and the Information described herein shall be
confidential and shall remain confidential and shall not be disclosed
to any third party, except as otherwise contemplated herein; as may be
mutually agreed in writing, or to the extent required by law, rule,
regulation of governmental agencies or court order.
b. THIS LETTER AGREEMENT AND ALL OF THE RIGHTS AND OBLIGATIONS OF THE
PARTIES ARISING FROM OR RELATING TO THE SUBJECT MATTER HEREOF OR THE
TRANSACTIONS CONTEMPLATED HEREBY SHALL BE GOVERNED BY, CONSTRUED AND
ENFORCED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, EXCLUDING
THE CONFLICT OF LAWS AND RULES OF SUCH STATE.
c. This Letter Agreement supersedes any prior agreements between the
parties with respect to the subject matter of hereof.
d. In the event any dispute regarding this Letter Agreement cannot be
reconciled by the parties, then they shall attempt to resolve any such
dispute through (i) mediation, using a mutually acceptable mediator,
and, if necessary, through (ii) binding arbitration, using a mutually
acceptable arbitrator. No dispute related hereto shall be brought
before any court of law or equity. Any arbitration will be conducted
in Dallas County, Texas using the commercial rules of the American
Arbitration Association.
<PAGE>
Mr. R. J. Sullivan, Jr., Manager
Sullivan and Company 3 D Program I, L.L.C.
Mr. Buzz Bainbridge, President
Willisco, Inc.
July 22, 1997
Page Four
If the foregoing reflects our mutual understanding and agreement of the subject
matter contained herein, please so indicate by executing in the appropriate
space below. This Letter Agreement shall be effective as of June 6, 1997.
Sincerely,
NATIONAL ENERGY GROUP, INC.
By:
Miles D. Bender
President and CEO
MDB:ljg
ACCEPTED AND AGREED to
this day of July, 1997.
SULLIVAN AND COMPANY 3 D PROGRAM I, L.L.C.
By:
R. J. Sullivan, Jr.
Program Manager
WILLISCO, INC.
By:
Buzz Bainbridge
President
GEOPHYSICAL SERVICES AGREEMENT
This Geophysical Services Agreement (the "Agreement") is made this
____ day of ________________, 1997 by and between National Energy Group, Inc.
("NEG") and Acadian Geophysical Services, Inc. ("ACADIAN") concerning our mutual
understanding concerning Land and Transition Zone Seismic Services to be
performed by ACADIAN for the benefit of NEG:
WITNESSETH:
WHEREAS, NEG owns or has acquired the rights to certain lands and
leases comprising an approximately fifty-four (54) square mile area located in
Iberville Parish, Louisiana for which it desires certain geophysical services,
including a three dimensional seismic survey; and
WHEREAS, ACADIAN is engaged in the business of conducting geophysical
services and has experience conducting seismic surveys of a nature required by
NEG; and
WHEREAS, NEG desires to engage ACADIAN to conduct a three dimensional
seismic survey and other certain geophysical services in Iberville Parish,
Louisiana (the "3D Survey") under the terms and conditions contained herein.
NOW THEREFORE, in consideration of the mutual covenants and agreements
contained herein and other valuable consideration, the sufficiency of which is
hereby acknowledged, and intending to be legally bound hereby, the parties
hereto agree as follows:
1. Definitions. The following terms as used in this Agreement and any
amendments or schedules hereto shall be defined and have the meanings
specified or referred to in this Paragraph 1:
"3D Survey" shall mean Three dimensional seismic survey comprised
of surveying and gathering seismic data by placing Receiver
Stations and Source Points in a series of rectangles as
described in the recitals hereof.
"Bin Size" shall mean a rectangle 110 ft. x 110 ft.
"Charge Size" shall mean the amount (weight) of the Source Type that
is to be placed in the Shot Hole. Charge sizes may vary
throughout the 3D Survey.
"Confidential Information" shall have the meaning described in
Paragraph 12 hereof.
"Data" shall have the meaning described in Paragraph 11 hereof.
"Design Parameters" shall have the meaning described in Paragraph 3
hereof.
"Geophone" shall mean an electronic device placed on the surface of the
earth to record seismic energy.
"Geophones per Group" shall mean the number of Geophones that are
connected together and considered as one Receiver Station.
"Hole Depth" shall mean the total depth of the Shot Hole to be drilled.
"Land and Transition Zone Seismic Services" shall mean services
performed by ACADIAN on dry land, marsh lands and on lands
with water depths that do not exceed 20 feet in depth.
"Loss or Losses" shall have the meaning described in Paragraph 13
hereof.
"MS" shall mean milliseconds.
"Pentolite" shall mean a generic term for explosives used as an energy
source for conducting seismic surveys.
"Receiver Line" shall mean Receiver Stations placed along a horizontal
straight line on the surface of the earth.
"Receiver Station Spacing" shall mean the horizontal distance between
two adjacent Receiver Stations.
"ReceiverStation" shall mean a point on the surface of the earth where
a Geophone is placed to record seismic energy (also known as a
"receiver group" or "group.")
"Record" shall mean all seismic data recorded onto digital tape from
all Recording Channels when one Source Point is discharged.
"Record Length" shall mean the time (in seconds) that seismic energy
is recorded on digital tape from one Source Point discharge.
"Recording Channel" shall mean one Receiver Station with Geophones
placed in position to record seismic energy.
"Representatives" shall have the meaning described in Paragraph 12
hereof.
"Sample Rate" shall mean the length of time between two adjacent pieces
of seismic data on one Record.
"Shot Hole" shall mean a vertical hole, drilled into the earth and into
which the Source Type is placed.
"Source Line Interval" shall mean the distance between two adjacent
Source Lines.
"Source Line" shall mean the horizontal line along which Source Points
are located.
"Source Point" shall mean a point, within the outer boundary of the 3D
Survey, at which a Shot Hole is drilled and then loaded with a
Source Type (also known as a Shot Point).
"Source Point Spacing" shall mean the horizontal distance between two
adjacent Source Points (also known as Shot Point Spacing or
Shot Point Interval).
"Source Type" shall mean the type of energy source to be used to
acquire seismic data. Pentolite, defined above, is the Source
Type to be used in this 3D Survey.
"Spread" shall mean a rectangle with dimensions of 11800 ft. x 26180
ft. Within the Spread are 10 parallel Receiver Lines. Each
Receiver Line has 120 Geophone Groups spaced 220 feet apart.
The distance between adjacent Receiver Lines is 1320 feet.
"Survival Period" shall have the meaning described in Paragraph 15
hereof.
"Swath" shall mean one Spread plus the Source Points located between
the two most interior Receiver Lines within the Spread.
2. General Scope of Geophysical Services. It is the intention of the
parties hereto that ACADIAN shall conduct the 3D Survey over the lands
and leases located in Iberville Parish, Louisiana as requested by NEG.
ACADIAN shall be responsible for the direction and supervision of all
activities related to the 3D Survey including, but not limited to,
survey crews, seismic drilling activities and recording of Data.
ACADIAN further agrees that it shall deliver the field tapes of the 3D
Survey Data to NEG or NEG's designee at least once each week, together
with all notes of the survey crew and observer related thereto.
3. Survey Design Parameters. ACADIAN agrees that it shall, for the benefit
of NEG, conduct the 3D Survey and provide other related services as
described herein pursuant to the following design parameters,
consistent with commonly accepted industry standards (the "Design
Parameters"):
(i) No. of Channels Recording
(10 Lines x 120 Channels Max)....................1200
(ii) Source Line Interval (Brick Pattern).............1320 feet
(iii) Receiver Line Intervals..........................1320 feet
(iv) Source Point Spacing............................. 220 feet
(v) Receiver Station Spacing ........................ 220 feet
(vi) Total No. of Source Points.......................2520
(vii) Bin Size..........................................110 x 110
(viii) Source Type......................................Pentolite
(ix) Shot Hole Depth...................................100 feet
(x) Charge Size .......................................11 #
(xi) Record Length ......................................8 Sec.
(xii) No of Geophones per Group...........................6
(xiii) Sample Rate.........................................2 MS
NEG shall retain the right at all times, upon written notice to
ACADIAN, to amend or modify such Design Parameters to include
additional Receiver Lines into the Spread; provided that any such
increase shall be invoiced to NEG at ACADIAN's actual cost plus thirty
percent (30%) and added to each Swath for which the increase is
requested. ACADIAN shall be responsible for advising NEG that land and
weather conditions are not suitable for performing the geophysical
services to be provided hereunder, at which time NEG shall make the
final decision as to whether ACADIAN shall proceed. Notwithstanding the
foregoing, in the event ACADIAN determines weather, land or any other
condition to be unsafe, it may suspend operations until such time that
the unsafe condition no longer exists.
4. Additional Services. In addition to the 3D Survey, ACADIAN shall
perform other related services as directed in writing from time to time
by NEG including, but not limited to, securing various municipal,
leasehold and governmental agency permits; provided that NEG agrees to
pay the expenses, costs and fees associated with such services
requested by NEG. It is further agreed that NEG shall pay or reimburse
ACADIAN for the following costs and expenses:
(i) standby survey crews requested by NEG shall be invoiced at a
rate of $ 650.00 per day/per crew;
(ii) additional survey Shot Holes or Shot Holes in excess of
Design Parameters shall be invoiced at a rate of $457.00 per
Shot Hole; and
(iii) applicable local, state and federal taxes on equipment, goods
and services provided by ACADIAN.
5. ACADIAN's Execution Statement. "Acadian Geophysical Services, Inc.
proposes to begin recording on/or before December 1, 1997, and surveying as
soon as permits are returned and conditions are approved by NEG. Recording
operations will begin when sufficient lead time has been obtained by the
drilling crew. We anticipate two (2) months to complete the recording,
depending on option chosen and/or any permit and/or weather days." "Prior
to the startup of each operation phase, the Health, Safety and
Environmental engineer assigned to the crew will conduct a complete
operation safety and environmental review session. The purpose of these
orientation sessions is to assure that all personnel are fully apprised of
the specific safety requirements of their assigned task, and the proper use
of equipment to minimize the environmental impact caused by this survey.
These sessions will continue on a regular basis to insure that our
employees and subcontractors place the highest priority on health, safety
and environment."
"Acadian Geophysical Services, Inc. has employed quality geophysical
personnel whom have many years of combined experience."
"PROTECTION OF THE ENVIRONMENT WILL BE A TOP PRIORITY. Party 100 will be
supervised by Mr. Nicky Blakeney. Mr. Blaine LeBlanc, President of Domestic
Acquisition Services, will also play a directional role in overall
positions."
"Acadian Geophysical Services, Inc. includes safety as an integral part of
its overall business philosophy and its daily field operations. Since the
Company's objective is to fulfill each contract productively while
generating the highest quality data, it is imperative that accidents which
injure persons, damage equipment or otherwise impair Company operations be
avoided. In this way, safe job performance and the attendant safety,
welfare and health of each employee are keys to efficient, cost-effective
production."
"The responsibility for maintaining safety working conditions is
distributed throughout the entire Acadian Geophysical Services, Inc.
workforce. Senior Company management is charged with strategic planning
which incorporates the broad issues of a safe working environment, proper
placement of employees, proper employee safety training, proper equipment
provision, and review of all work related accidents. Operational managers
are charged with communicating safety standards to supervisors, monitoring
employee adherence to Company safety policy, investigating accidents,
setting the party level safety example, and implementing procedural changes
recommended by the Corporate Safety manager. The local Safety manager is in
place to help formulate and update site specific policy, provide training,
conduct inspections and report program results to local management and to
the Corporate Safety Manager. Supervisors, due to their close association
with field employees, have the most significant employment training, hazard
recognition and correction, inspection of employee work practices, ensuring
the use of protective equipment, accident investigation, maintaining good
site housekeeping and the immediate presentation of an example of safe
work. Individual field employees, whose population is the most numerous,
are responsible for learning safe work practices, following Company safety
policies, reporting unsafe conditions or near-miss incidents to the
Supervisor, and maintaining themselves fit for work."
6. NEG Obligations. NEG agrees that it shall provide ACADIAN with such
permits, agreements with third parties and rights to conduct the 3D
Survey over the lands and leaseholds requested by NEG not otherwise to
be provided by ACADIAN. Additionally, NEG shall furnish to ACADIAN maps
of suitable scale to allow advance logistical planning, program
assignment, survey tract indemnification and construction of a Shot
Hole point location map by ACADIAN.
7. Costs and Expenses. Each of NEG and ACADIAN shall bear their own costs
and expenses with respect to their respective businesses and
operations, except as otherwise specifically contained herein or in
amendments hereto. NEG, however, agrees to pay, provide or reimburse
ACADIAN for the following costs and expenses; provided that such costs
and expenses have the specific written approval of NEG prior to their
expenditure by ACADIAN:
(i) cost plus ten percent (10%) of any specialized equipment that may
be required to gain access to areas which due to the nature of the
terrain are inaccessible to normal crews and equipment, including but
not limited to, terra floatation tires, airboat drills or other
specialty equipment required by permit restrictions or otherwise
necessary;
(ii) cost plus ten percent (10%) associated with map purchases, map
copies, Data shipments or other special services;
(iii) cost plus ten percent (10%) associated with special services to
satisfy ecological, environmental and governmental mandates, rules and
regulations;
(iv) cost plus ten percent (10%) related to rental of specialized
safety equipment; and
(v) cost plus ten percent (10%) of resurvey; provided that any such
costs due to the negligence of ACADIAN or its Representatives
(hereinafter defined) shall be borne exclusively by ACADIAN.
8. Compensation. In consideration of the services to be provided by
ACADIAN hereunder, NEG agrees to compensate ACADIAN as follows:
(i) 3D Survey and related services, approximately
54 square miles......................$90,940.00 per sq. mile
(ii) Recording crew standby time
per mile (maximum 10 hr. day).........$ 1,900.00 per hour
(Standby will be charged for weather days and/or any permit
delays not caused by any fault of ACADIAN.) *
(iii) Testing experimental per hour ........$ 2,100.00 per hour
(iv) Drilling rig standby time
(per crew)............................$ 1,200.00 per day
(Standby will be charged at the above stated rate if a drill
crew is required to stand by for redrills.) *
(v) Permit Agents
per day/per agent (subject to approval by NEG)$375.00 per day
(Cost of permit agents and vehicle used in securing permits or
related services.)
*First twenty (20) hours per month at ACADIAN's
expense; all other downtime not attributable to the
negligence of ACADIAN shall be at the sole cost and
expense of NEG.
9. Invoicing. ACADIAN shall invoice NEG for services provided hereunder,
and NEG agrees to pay the non-disputed portion of any such invoice
within thirty (30) days thereafter; provided that the following
schedule of payments shall reflect the parties' understanding and
agreement with respect to such invoicing:
(i) Upon execution and delivery of this Agreement..$ 491,076.00
(ii) Upon commencement of surveying operations
in the 3D Survey area..........................$ 736,614.00
(iii) Upon commencement of drilling operations ......$1,227,690.00
(iv) Remaining SD&A costs invoiced on a Swath-by-Swath basis upon
successful completion of every second (2nd) Swath; provided
that the final two (2) Swaths shall be adjusted to reflect any
changes in the overall size or scope of the 3D Survey as
directed by NEG.
10. Relationship of the Parties. ACADIAN shall provide its services to NEG
under the terms of this Agreement as an independent contractor. Except upon
the express written consent of the other, ACADIAN has no authority to
execute and/or deliver documents which purport to bind NEG, and NEG has no
authority to execute and/or deliver documents which purport to bind
ACADIAN. Neither party shall function or hold itself out to be the agent of
the other, nor shall this Agreement be deemed to create a partnership or
joint venture of any type; provided, however, that NEG hereby grants to
ACADIAN the limited power and authority to acquire certain permits to
conduct geophysical services as directed by NEG whose land and leases lie
within the area comprising the area of geophysical services to be rendered
by ACADIAN pursuant to this Agreement. All compensation paid to ACADIAN
shall be without any deductions including: withholding for federal or state
income or other taxes, social security, worker's compensation insurance, or
health or accident insurance, for which ACADIAN agrees to be solely
responsible. ACADIAN shall not receive nor be eligible for any employee
benefits made available to others who perform services for NEG.
11. Ownership and Use of Data. ACADIAN is performing its services for the
exclusive benefit of NEG. Accordingly, all data (geological,
geophysical or otherwise) and the compilations, analyses, notes, charts
and interpretations made by ACADIAN or others ("Data") with respect to
the geophysical services performed by ACADIAN on NEG's behalf shall at
all times be the property of NEG. ACADIAN shall have no right to use,
license or otherwise disseminate any portion of the Data for itself or
to any third party without the express written consent of NEG.
12 Confidentiality. This Agreement and the Data shall be deemed to be
confidential and proprietary to NEG ("the "Confidential Information"), the
disclosure of which to unauthorized third parties could result in
irreparable harm to NEG. Accordingly, ACADIAN for itself and for its
affiliates, officers, contractors, consultants, invitees, employees, agents
or advisors (collectively, the "Representatives") warrants and agrees to
maintain the confidentiality of, and not disclose the Confidential
Information to any party without the express written consent of NEG;
provided that this Paragraph 12 shall not restrict
(a) disclosure of any Confidential Information required by applicable
statute, rule or regulation of any court of competent jurisdiction;
provided that NEG is given notice and an adequate opportunity to contest
such disclosure, and
(b) any disclosure of Confidential Information which is available publicly
as of the date of this Agreement or which, after the date of this
Agreement, becomes available publicly through no fault or action on the
part of ACADIAN or its Representatives other than as provided herein.
13. Indemnity by ACADIAN. ACADIAN for itself and for its
Representatives and on behalf of its successors and assigns, agrees to
indemnify and hold NEG harmless from and with respect to any and all
losses, damages, costs, expenses, obligations, liabilities,
deficiencies, taxes, interest on taxes or penalties, including without
limitation the reasonable fees and disbursements of counsel and costs
of responding to any governmental audit, inquiry or investigation and
including without limitation all claims, liabilities or obligations
arising from or related to the actions or failure to act in conducting
the geophysical services requested by NEG, including (without limiting
the generality of the foregoing) environmental and third party claims
related to or arising directly or indirectly out of any of the
following (any of which shall be referred to herein singularly as a
"Loss" and collectively as the "Losses"):
(i) Any and all claims, counterclaims, liabilities and obligations
arising from or related to ACADIAN or its Representatives' negligence
in conducting its operations and geophysical services on behalf of NEG;
(ii) Any claim, counterclaim, liability or obligation arising from or
related to surface or subsurface damages caused by the negligence or
willful misconduct of ACADIAN or its Representatives in conducting its
geophysical services on behalf of NEG; and
(iii) Any claim, counterclaim, liability or obligation arising from or
related to environmental damages caused by the negligence or willful
misconduct of ACADIAN or its Representatives in conducting its
geophysical services on behalf of NEG.
14. Indemnity by NEG. NEG agrees to indemnify and hold ACADIAN and its
Representatives harmless from and with respect to any and all Losses
related to or arising out of any of the following:
(i) Any and all claims, counterclaims, liabilities and obligations
arising from or related to NEG's operations in the area where ACADIAN
is conducting its geophysical services on behalf of NEG;
(ii) Any and all claims, counterclaims, liabilities or obligations
related to surface or subsurface damages caused by the operations of
NEG in the area where ACADIAN is conducting its geophysical services on
behalf of NEG; and
(iii) Any claim, counterclaim, liability or obligation related to
environmental damages caused by NEG in the area where ACADIAN is
conducting its geophysical services on behalf of NEG.
15. Survival of Indemnities. The obligation of indemnification set out in
Paragraphs 13 and 14 hereof shall survive for a period of three (3) years
following the execution and delivery of this Agreement (the "Survival Period").
Any claim for any Loss or Losses must be asserted in writing prior to the end of
the Survival Period, and if asserted in writing during the Survival Period, such
claims shall survive until resolved; and if such claims are not so asserted, the
party asserting such claim shall be forever estopped and prohibited from
asserting any such claim hereunder.
16. Miscellaneous.
16.1 Notices. All notices, demands and other communications to the
parties hereto as may be required hereunder shall be in writing or by
written telecommunication, and shall be deemed to have been duly given
if delivered personally or if mailed by certified mail, return receipt
requested, postage prepaid, or if sent by overnight courier, or sent by
written telecommunication, as follows:
IF TO NEG: IF TO ACADIAN:
National Energy Group, Inc. Acadian Geophysical Services, Inc.
4925 Greenville Avenue, Suite 1400 6760 A Cemetary Highway
Dallas, Texas 75206-4095 St. Martinville, Louisiana 70582
Telephone: (214) 692-9211 Telephone: (318) 394-7444
Facsimile: (214) 692-5055 Facsimile: (318) 394-7424
Attn: Mr. Miles D. Bender, President Attn: Blaine LeBlanc, President
16.2 Successors and Assigns. All provisions of this Agreement, whether
or not such provisions shall specifically so provide, shall be binding
upon and inure to the benefit of ACADIAN and NEG and their respective
successors and assigns. ACADIAN shall not assign any portion of this
Agreement without the express written consent of NEG, which consent
will not be unreasonably withheld.
16.3 Entire Agreement. This Agreement constitutes the entire agreement
of ACADIAN and NEG with respect to the matters governed herein and
supersedes all prior agreements, arrangements, statements, promises,
information, understandings, representations and warranties, whether
oral or written, express or implied, with respect to the subject matter
hereof.
16.4 GOVERNING LAW. THE VALIDITY AND CONSTRUCTION OF THIS AGREEMENT
SHALL BE GOVERNED BY THE INTERNAL LAWS (AND NOT THE CHOICE-OF-LAW
RULES) OF THE STATE OF TEXAS.
16.5 No Implied Rights or Remedies. Except as otherwise expressly
provided herein, nothing herein expressed or implied is intended or
shall be construed to confer upon or to give any person, firm or
corporation, except NEG and ACADIAN, any rights or remedies under or by
reason of this Agreement.
16.6 Construction. The language used in this Agreement will be deemed
to be the language chosen by the parties hereto to express their mutual
intent, and no rule of strict construction will be applied against any
party.
16.7 MEDIATION, ARBITRATION. IN THE EVENT OF A DISPUTE BETWEEN THE
PARTIES TO THIS AGREEMENT, THE PARTIES AGREE TO PARTICIPATE IN GOOD
FAITH IN A MINIMUM OF FOUR (4) HOURS OF MEDIATION IN DALLAS, TEXAS WITH
AN ATTORNEY-MEDIATOR TRAINED AND CERTIFIED BY THE AMERICAN ARBITRATION
ASSOCIATION, THE UNITED STATES ARBITRATION AND MEDIATION SERVICE, OR
ANY COMPARABLE ORGANIZATION, AND TO ABIDE BY THE MEDIATION PROCEDURES
AND DECISION OF SUCH ORGANIZATION. THE PARTIES AGREE TO EQUALLY BEAR
THE COSTS OF THE MEDIATION. IN THE EVENT THE PARTIES CANNOT RESOLVE
THEIR DISPUTE THROUGH MEDIATION AS DESCRIBED HEREIN, THE PARTIES AGREE
TO PARTICIPATE IN BINDING ARBITRATION PURSUANT TO THE RULES OF THE
AMERICAN ARBITRATION ASSOCIATION OR MUTUALLY AGREEABLE SIMILAR
ORGANIZATION. SUCH ARBITRATION SHALL BE HELD IN DALLAS, TEXAS, SHALL BE
BINDING AND NONAPPEALABLE AND A JUDGMENT ON THE AWARD TO THE PREVAILING
PARTY (INCLUSIVE OF REASONABLE ATTORNEY=S FEES AND COSTS) MAY BE
ENTERED IN ANY COURT HAVING COMPETENT JURISDICTION.
IN WITNESS WHEREOF, and intending to be legally bound hereby, ACADIAN
and NEG have caused this Agreement to be duly executed and delivered as of the
date and year first hereinabove written.
"ACADIAN"
ACADIAN GEOPHYSICAL
ATTEST: _______________________ SERVICES INC.
TITLE: _________________________ By:__________________________
Name: Blaine LeBlanc
Title: President
"NEG"
NATIONAL ENERGY GROUP, INC.
ATTEST:______________________
TITLE:______________________ By:______________________________
Name: William T. Jones
Title: Senior Vice President Operations
EXPLORATION AGREEMENT
Texana Project
Jackson County, Texas
This Exploration Agreement (the "Agreement") is entered into as of July
15, 1997, by and between TAC Resources, Inc. ("TAC"), Parallel Petroleum
Corporation ("Parallel"), Unit Petroleum Company ("Unit"), Beta Oil & Gas, Inc.
("Beta") and Pease Oil and Gas Company ("Pease") all hereinafter collectively
referred to as (the "Parties").
WITNESSETH:
WHEREAS, TAC has acquired seismic and lease options, oil and gas leases
and seismic permits covering an area of approximately 25,000 acres located in
Jackson County, Texas, as depicted on the plat attached hereto as Exhibit "A".
WHEREAS, Parallel, Unit, Beta and Pease propose to acquire undivided
interests in and to the rights granted by such agreements, and to participate in
conducting a 3-D seismic program upon the lands covered thereby.
NOW, THEREFORE, in consideration of the premises, the mutual agreements
and obligations set forth herein, and the mutual benefits to be received
hereunder, the Parties agree as follows:
ARTICLE 1. DEFINITIONS
For the purpose of this Agreement, the following terms shall have the
meanings designated below:
1.1 Area of Mutual Interest "AMI" means the lands outlined on the plat
attached hereto as Exhibit "A".
1.2 "AMI Interests" means any interest in the oil, gas or other
minerals in and under the AMI, including leasehold interests under oil and gas
leases, oil and gas lease options, interests of the farmee under farmout
agreement, and other such interests or rights similar or dissimilar to those
mentioned, including, but not limited to, seismic permits. AMI Interest does
not, however, include nonpossessory interests in the oil, gas and other minerals
in and under the AMI, such as royalty interests, overriding royalty interests,
net profits interests, or other such interests whether similar or dissimilar to
those mentioned.
1.3 "Existing AMI Interests" means the Seismic and Lease Options, Oil
and Gas Leases and Seismic Permits which have been acquired by TAC as of August
1, 1997.
1.4 "Subsequently Acquired AMI Interests" means all AMI Interests
acquired after August 1, 1997.
1.5 "Contract Lands" means lands located within the AMI which are
covered by AMI Interests.
1.6 "Initial Interest" means a Party's ownership in Existing AMI
Interests, and the amount of interest a party is entitled to acquire in
Subsequently Acquired AMI Interests, subject to the provisions hereof.
1.7 "Jointly Owned AMI Interest" means an AMI Interest in which the
Parties own an interest pursuant to the terms of this Agreement.
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1.8 "Lease Burden" means any royalty, overriding royalty interest, net
profits interest, production payment, carried interest, reversionary working
interest or other charges upon a leasehold interest or the production therefrom.
1.9 "Losses" means any and all losses, liabilities, claims, demands,
penalties, fines, settlements, damages, actions, or suits of whatsoever kind and
nature (but expressly excluding consequential damages), whether or not subject
to litigation, including without limitation (i) claims or penalties arising from
products liability, negligence, statutory liability or violation of any
applicable law or in tort (strict, absolute or otherwise) and (ii) loss of or
damage to any property, and all reasonabl out-of-pocket costs, disbursements and
expenses (including, without limitation, legal, accounting, consulting and
investigation expenses and litigation costs) imposed on, incurred by or asserted
against an indemnified Party in connection therewith.
1.10 "Operator" shall have the meaning as it is given in the Operating
Agreement in the form attached hereto as Exhibit "B".
1.11 "Party" or "Parties" means TAC, Parallel, Unit, Beta and Pease and any
other person or entity, singularly or as a group, which hereafter becomes a
party hereto or is otherwise subject to the terms hereof.
1.12 "Pre-Existing Data" means such data which includes, but is not limited
to: seismic records and related seismic data, electronic and mud logs, cores and
core analyses, field studies (less and except any proprietary methodology or
process used by any Party in such studies), production tests, engineering,
geological, geophysical, paleontological data, interpretive data and maps
prepared by any Party in existence as of the date of this Agreement.
1.13 "Proportionate Share" except as otherwise provided for herein, shall
be calculated by dividing a Party's Initial Interest by the aggregate of the
Initial Interests of all Parties who are to share an interest or an obligation
pursuant to the terms hereof. In circumstances where one or more Parties do not
participate in such an interest or obligation, "Proportionate Share" shall be
determined by dividing a Party's Initial Interest by the total Initial Interests
of all Party's participating therein.
1.14 "Prospect" means an area within the AMI which is designated as a
Prospect pursuant to Article 4.1 hereof and within which there is expected to
occur, based on information developed as a result of 3-D Seismic Operations, a
commercial accumulation of oil and/or gas in a specific structural or
stratigraphic trap.
1.15 "Subsequently Created Burden" means a lease burden which is created by
a party subsequent to its acquisition of the interest which is subject to the
burden, except the overriding royalty interest provided for in Article 2.5
hereof.
1.16 "Costs Prior to Leasehold Acquisition" means all costs of any type
whatsoever which pertain to this project, covering lands located within or
outside the AMI, including, but not limited to costs of seismic permits, seismic
and lease options, oil and gas leases, and renewals thereof, land brokerage,
legal costs, surface damages, surveying, seismic acquisition and interpretation,
etc., which are incurred prior to Leasehold Acquisition conducted under the
provisions of Article 4 hereof.
1.17 Other terms are defined elsewhere in this Agreement.
ARTICLE 2. INTERESTS AND SHARE OF COSTS OF THE PARTIES
2.1 Area of Mutual Interest. The Parties hereby establish an Area of Mutual
Interest "AMI", same to be comprised of the area outlined on the attached
Exhibit "A", and which shall cover AMI Interests located therein. This AMI shall
continue for a term of three (3) years, or the expiration of the last Jointly
Owned AMI Interest, whichever is earlier. e 2.2 "Interests and Share of Costs of
the Parties" The Parties hereby agree to own, as their Initial Interest; and
agree to bear the costs set out below, as follows:
<TABLE>
Party Initial Interest Share of Costs Share of Costs for
Prior to Leasehold Leasehold Acquisition
Acquisition and Subsequent Operations
<S> <C> <C> <C>
TAC .2500000 .0625000 .2500000
Parallel .1750000 .21875 .1750000
Unit .2500000 .31250 .2500000
Beta .2000000 .2500000 .2000000
Pease .1250000 .1562500 .1250000
</TABLE>
TAC has acquired and now owns the Existing AMI Interests. Parallel, Unit, Beta
and Pease agree that their costs in the Existing AMI Interests shall be based on
$75.00 per net mineral acre on seismic and lease options, and cost plus 25% on
oil and gas leases and seismic permits. The Existing AMI Interests are presently
comprised of approximately 23,183.908 net mineral acres covered by seismic and
lease option, and 300.5 net mineral acres covered by seismic permit where cost
was $25.00/net mineral acre. Based on the foregoing, the current total cost of
Existing AMI Interests is One million seven hundred forty-eight thousand one
hundred eighty-three and 73/100 Dollars ($1,748,183.73). Parallel, Unit, Beta
and Pease agree to pay TAC their portion of such cost, as referenced above, in
the Existing AMI Interests upon execution of this Agreement. Parallel, Unit,
Beta and Pease hereby agree that TAC shall have the exclusive right to acquire
AMI Interests through August 1, 1997, and that same shall be treated i all
respects as Existing AMI Interests. Parallel, Unit, Beta and Pease agree that
they shall be obligated to accept such interests in the same percentages and pay
TAC for such interests at the same terms stated herein. Payment for such
interests shall be due within fifteen (15) days after receipt of written notice
as set out in Article 2.4. Interests available to TAC which costs exceed those
stated above shall be offered to the other Parties as per the procedure set
forth in Article 2.4 below.
2.3 Recording. TAC agrees to file for record in the office of the Jackson
County Clerk, all Memorandums of Seismic and Lease Options covering the Existing
AMI Interests within fifteen (15) days of the date this Agreement is executed by
all Parties.
2.4 Subsequently Acquired AMI Interests. Any Party acquiring a Subsequently
Acquired AMI Interest, directly or indirectly, shall notify the other Parties
hereto. Such notice shall set forth (i) a description of the interest acquired,
(ii) the total cost of the interest, including all land and legal costs
associated with the acquisition thereof, (iii) the Proportionate Share of the
notified Party and its cost therein, and (iv) any other pertinent terms of such
acquisition, including, but not limited to, copies of the instruments of
conveyance, copies of leases, assignments, subleases, farmout and other
contracts affecting the AMI Interests, copies of paid drafts or checks, itemized
invoices of actual costs incurred by the acquiring Party. Parties shall have
fifteen (15) days from the receipt of this notice to acquire their Proportionate
Share of the Subsequently Acquired AMI Interest. A Party's election to acquire
shall be given in writing and accompanied by Party's payment of its total cost
for such interest. If a Party's election and payment are not received within
such fifteen (15) day period, it shall be conclusively presumed that such Party
has elected not to acquire its Proportionate Share of the Subsequently Acquired
AMI Interest and has forfeited its right thereto. A Party's failure to exercise
its option as to any particular notice shall not constitute a waiver or release
of its right to acquire any interest described in any subsequent notice
delivered hereunder.
2.5 Existing Burdens. Each Party's interest under this agreement in the AMI
Interests, and oil and gas leases which may be acquired thereunder, shall be
subject to and burdened by its proportionate share of all existing operating
agreements, existing and pending pooling and spacing orders and all Lease
Burdens other than Subsequently Created Burdens. TAC represents that, except as
hereinafter provided, it has not burdened the Existing AMI Interests acquired or
to be acquired with any liens or Subsequently Created Burdens. Each Party agrees
to perform its Proportionate Share of the obligations under the AMI Interests
acquired pursuant to this Agreement and the other obligations described in this
Article, but only to the extent that such obligations arise after the
acquisition of such AMI Interests by such Party. Notwithstanding the foregoing,
the Parties agree that they shall bear, their Proportionate Share of an
overriding royalty interest to be owned by Bayou Black Royalty Company, Inc. on
all oil and gas leases acquired pursuant to this Agreement (including leases
acquired by exercising lease options in which the Parties own an interest, and
in extensions and renewals thereof ) equal to two percent (2%) of eight-eighths
(8/8ths), provided that such overriding royalty interest shall be reduced in the
proportion that the undivided mineral interest covered by any such lease bears
to the entire mineral interest in the lands covered by such lease.
2.6 Expiring Options. If any lease options covered hereby will expire prior
to completion of the Seismic Operations contemplated herein, Operator shall use
its best efforts to renew such option for a sufficient period of time to
complete the proposed 3-D Seismic Operations thereon and exercise the lease
option thereunder. The acquisition of such renewal shall be handled under the
acquisition, notice and election provisions of Article 2.4.
2.7 Assignments. Upon receipt of payment for AMI Interests, TAC shall
assign to the Parties hereto their Initial Interest in and to all right, title
and interest owned by TAC in such AMI Interests. Such assignment shall be
recordable in form, shall be subject to this agreement, shall provide for
warranty by, through and under TAC, but not otherwise, and shall be subject to
the terms and provisions of the AMI Interests assigned.
2.8 AMI Interests Located In and Out of Existing AMI. If an AMI Interest is
found to cover lands located both within and outside the existing AMI, the
entirety of such AMI Interest shall be offered to the other Parties under the
acquisition, notice and election provisions of Article 2.3 and Article 2.4, and
if the other Parties elect to participate in the acquisition thereof, the
description of the lands comprising the AMI shall be deemed to be amended to
extend and cover all of the lands covered by such interest. The option of the
Parties to participate in the acquisition of such interests shall be limited to
the entirety of the interest acquired.
ARTICLE 3. SEISMIC OPERATIONS
3.1 Existing Seismic, Geologic and Other Subsurface Data. Except as
prohibited by law or by agreements with third parties, upon request, each Party
owning existing seismic data pertaining to lands located within the AMI shall
furnish copies of all such data to the other Parties, together with any geologic
or other subsurface data that could be useful in the interpretation thereof. The
Party receiving such data shall bear the expense of copying it. The Party owning
any seismic or other data which may not be copied, due to legal prohibitions or
by agreements with third parties, shall, upon request, make such data available
to the Party requesting such data during normal business hours.
3.2 Ownership of Pre-Existing Data. Ownership of the Pre-Existing Data
and all reprocessed Pre-Existing Data shall at all times remain vested in the
Party who contributes the Pre-Existing Data for use by the Parties, and the
Parties agree to acknowledge such ownership, including, but not limited to, the
filing with any appropriate governmental authority of such acknowledgment. The
Parties expressly reserve the right to sell, license, or trade the Pre-Existing
Data which it contributes hereunder, to the extent that it has such right to
sell, license or trade the Pre-Existing Data, through its own efforts, or
through the efforts of others duly authorized by such Party and the benefits and
advantages, including monetary consideration, which such Party receives as a
result of such activities shall be the sole property of such Party.
3.3 Management of the 3-D Seismic Operations. Operator shall
exclusively manage and conduct the 3-D Seismic Operations contemplated hereunder
and all operations incident thereto, including, but not limited to, the
acquisition of all geoscientific data, the performance of all 3-D seismic
surveys and other geoscientific work incident thereto (other than analysis
and/or interpretation), and, subject to the Operating Agreements, the drilling
of all wells on the Prospects. Operator shall perform all such work through
employees, representatives, and contractors of its selection, and Operator shall
and does hereby agree to utilize reasonable prudence and economic judgment in
contracting with third party contractors or subcontractors. As manager of 3-D
Seismic Operations, Operator shall devote such of its time, attention and
efforts to the conduct thereof as it shall in good faith determine reasonably
necessary, but shall otherwise be free to engage in and pursue all other current
and future business projects, programs, prospects, opportunities, investments
and activities without obligation of any kind to or right of participation
therein by the other Parties hereto. In performing its duties under this
Agreement, Operator shall serve as an independent contractor and not as an agent
or employee of the other Parties hereto. Operator shall utilize reasonable
prudence and economic judgment in incurring costs, and shall further conduct the
3-D Seismic Operations and perform all of its duties under this Agreement as a
reasonable, prudent operator, in a good and workmanlike manner with due
diligence and dispatch, in accordance with good oilfield and exploratory
practice, and in compliance with all applicable laws and regulations, BUT SHALL
HAVE NO LIABILITY TO THE OTHER PARTIES HERETO OR ANY OTHER OWNER OF RIGHTS OR
INTERESTS UNDER THIS AGREEMENT FOR ANY LOSSES SUSTAINED OR LIABILITIES INCURRED
IN CONNECTION WITH THE 3-D SEISMIC OPERATIONS AND/OR THE CONDUCT OF ANY
ACTIVITIES UNDER OR CONTEMPLATED BY THIS AGREEMENT, SAVE AND EXCEPT AS MAY BE
OCCASIONED BY THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF OPERATOR. EACH OF
THE OTHER PARTIES HERETO ACKNOWLEDGES THAT (A) IT HAS READ AND AGREED TO THE
FOREGOING EXCULPATION OF OPERATOR AS A NEGOTIATED AND BARGAINED FOR ASPECT OF
THIS TRANSACTION, (B) THIS EXCULPATION PROVISION IS CONSPICUOUS.
3.4 Ongoing and Future Seismic Operations. The Parties agree to conduct
such operations on all or substantially all of the Contract Lands. The Parties
may, subject to the unanimous written consent of all Parties, agree to reduce or
increase the acreage on which such operations will be conducted when technical,
legal or operational considerations indicate that such reduction or increase is
warranted. In any event, the Parties agree to pay their respective shares of the
total costs of the 3-D Seismic Operations conducted on all land covered by AMI
Interests as set forth in Article 2.2 hereof. Operator shall furnish the other
Parties hereto with copies of all applicable contracts and other information
pertaining to all 3-D Seismic Operations conducted hereunder. The Parties shall
own their Proportionate Share of the geophysical data obtained by and resulting
from the 3-D Seismic Operations conducted on the Contract Lands, including, but
not limited to all tapes, seismic sections and any and all other data generated
by such 3-D Seismic Operations. Each Party shall have access to such data and
shall receive copies thereof. The Parties agree to work together in a spirit of
cooperation and in good faith in planning and causing the 3-D Seismic Operations
to be conducted as contemplated herein as well as in sharing the data collected
therefrom and the interpretations thereof. Such interpretations, by any Party,
shall in no way be deemed a representation to any other Party that such
interpretations are accurate or correct. Such interpretations shall be given
merely as a means of sharing such Party's analysis and ideas regarding such
data.
3.5 Confidentiality of Seismic Data. Except as provided below, each
Party agrees to keep all seismic data obtained pursuant to Article 3.3
confidential for a period of five (5) years from the date hereof. After the
expiration of five (5) years from the date hereof any Party may sell the data it
acquired pursuant to Article 3.2. Each Party owning an interest in such data
shall receive its Proportionate Share of the proceeds of any such sale. Any data
acquired from another Party pursuant to Article 3.1 shall forever be kept
confidential by the Parties; provided, however, that the Party who originally
contributed such data may share, sell or otherwise dispose of such data that
does not pertain to a Prospect to a third party after the expiration of one (1)
year from the date hereof, and the other Parties shall have no interest in the
proceeds from such sale. Notwithstanding the foregoing, a Party may disclose
seismic data to (A) a prospective purchaser or farmee of such Party's interest,
provided (i) such disclosure is limited to the Prospect under consideration for
sale or farmout, (ii) the prospective purchaser or farmee must review such data
in the affected Party's offices and may not copy such data until such time as it
has acquired or earned an interest in the Contract Lands, and (iii) such
prospective purchaser or farmee must execute a confidentiality agreement to
prevent further disclosure and unauthorized use of such data; or (B) a third
party who is entitled thereto pursuant to the terms of a lease, lease option or
seismic permit. Any Party may disclose such data to its agents, staff,
representatives and consultants in the normal conduct of its business.
3.6 Review of Seismic Data. The Parties agree to cooperate in good
faith in reviewing the seismic data acquired hereunder. Such data should be
reviewed by the Parties as soon as practicable after the data is available so
that the Parties can make decisions regarding the exercise of lease options.
ARTICLE 4. LEASEHOLD ACQUISITION
4.1 Designation of Prospects. As soon as practicable after the data has
been processed and interpreted, Operator shall establish Prospects within the
AMI. Operator shall designate such Prospects on a map which reflects the outline
of the lands to be included within each such Prospect. Promptly after
designating such Prospects, Operator shall furnish the other Parties with such
maps which reflect the designated Prospects, together with a description of the
seismic data, prospective feature and any interpretative data or other maps upon
which such Prospect is based. The other Parties shall have fifteen (15) days
after receipt of such notice in which to elect in writing whether or not they
will participate in the designated Prospects. If a Party fails to furnish
Operator with its written election to participate within such fifteen (15) day
period, it shall be conclusively presumed to have elected not to participate in
the Prospect or Prospects so designated. Any Party not participating in a
Prospect shall promptly assign all of its interest in the lands lying within
such Prospect to the Parties participating in such Prospect. A Party's election
hereunder may be on a Prospect by Prospect basis, and a Party's failure to
participate in any or all Prospects contained in any particular notice shall not
constitute a waiver or release of the right to participate in a Prospect or
Prospects described in any subsequent notice delivered hereunder.
4.2 Acquisition of Leases Within Prospects. The Parties participating
in a Prospect will acquire and pay their Proportionate Share for leases covering
each Prospect upon the terms provided in the applicable lease options or upon
such other terms as the Parties may mutually agree upon if some lands within the
Prospect are unleased and not covered by a lease option. As soon as possible
after designating Prospects, Operator shall provide written notice to the
Parties participating in such Prospects of the leases to be acquired therein,
which notice shall set forth (i) a description of the lands and interests to be
acquired, (ii) the total cost of such interests, including all land and legal
costs associated with the acquisition thereof, (iii) the Proportionate Share of
the notified Party and its cost therein, and (iv) any other pertinent terms of
such acquisition, including, but not limited to, copies of the instruments and
other contracts affecting same. Payment for such leases shall be due within
fifteen (15) days after receipt of the above notice.
4.3 Minimum Acreage Obligation. In the event the lease options covering
a Prospect require minimum acreage selection in excess of the acreage included
within the boundaries of the Prospect, then each Party participating in such
Prospect must acquire and pay its Proportionate Share of the cost of the acreage
necessary to fulfill such minimum acreage selection requirements.
ARTICLE 5. SALE, FARMOUT OR OTHER DISPOSITION OF AMI INTERESTS TO A THIRD PARTY
Any Party may sell, assign, farmout or otherwise dispose of all or any
portion of its interest acquired pursuant to or in connection with this
Agreement without consent of any other Party.
ARTICLE 6. SUBSEQUENT OPERATIONS
6.1 Operator. Operator shall have the right, subject to the terms and
provisions of the attached Operating Agreement, to be the Operator for all
operations conducted within the AMI, and the Parties hereby agree to execute
separate Operating Agreements designating Operator, as Operator, as required.
6.2 Operating Agreement. Except as provided herein, all operations
conducted within the AMI shall be conducted in accordance with the terms of an
Operating Agreement substantially in the form attached hereto as Exhibit "B". A
separate Operating Agreement shall be executed for each Prospect, with the first
well drilled in such Prospect to be designated as the "Initial Well". The share
of costs which each Party must bear and the interest of each Party in the
production from each well drilled under the Prospect Operating Agreement will be
determined on a well-by-well basis in accordance with the terms hereof as
modified by the terms of the Operating Agreement. In the event of conflict
between the terms and provisions hereof and those contained in the Operating
Agreement, the terms and provisions hereof shall prevail.
6.3 Limitation on Number of Wells Drilling. Not more than three (3) wells
shall be drilling on the Contract Lands at any time unless it is necessary to
commence a well in order to perpetuate a lease or otherwise satisfy the terms of
a continuous drilling obligation.
6.4 Non-Consent Election on Initial Well. If a Party elects not to
participate in the drilling of the Initial Well in a Prospect established under
Article 4.1 hereof, such Party shall relinquish all of its rights and interests
in that Prospect to the Parties participating in the drilling of such well. A
Party so relinquishing its interest shall promptly execute a recordable
assignment of its relinquished interest to the Parties entitled thereto. The
interest so assigned shall be free of any Subsequently Created Burdens.
ARTICLE 7. MISCELLANEOUS
7.1 Indemnification with Regard to Existing Matters. TAC agrees to
fully indemnify, defend and hold harmless all other Parties to this Agreement
against all Losses arising out of, in connection with, or relating to TAC's sole
ownership or operation of the Existing AMI prior to the date of this Agreement,
including, but not limited to, breach of contract or monetary damage, regardless
of fault or strict liability imposed by statute, rule or regulation, so long and
only in the event that all actions, activities and/or conduct giving rise to the
claim for such Losses relate to activities of TAC which occurred in the period
prior to the date of this Agreement.
7.2 Legal Relationship. This agreement is not intended to create, and
shall not be construed to create, a partnership or other relationship whereby
one party is liable for the actions or debts of another party; it being
understood and agreed that the rights and liabilities of all parties are several
and not joint or collective.
7.3 Entire Agreement. This agreement constitutes the entire agreement
among the parties hereto with respect to the subject matter hereof, superseding
any and all prior agreements, understandings, discussions, negotiations and
commitments of any kind.
7.4 Amendment. The provisions of this agreement may be amended,
supplemented, or waived only if in writing signed by all parties hereto.
7.5 Construction. The parties to this agreement all acknowledge and
agree that this agreement was drafted jointly by them, and that in the event of
any ambiguity, this agreement shall not be construed against any of them on the
basis of the fact or presumption that one party had a greater or lesser hand in
the drafting of the agreement than another party, but rather the terms shall be
given a reasonable interpretation.
7.6 Governing Law. Except to the extent preempted by federal law, this
agreement is to be construed and interpreted in accordance with, and governed
by, the laws of the State of Texas.
7.7 Binding Agreement. This agreement shall bind and inure to the
benefit of the parties hereto and their respective heirs, successors, legal
representatives and assigns.
7.8 Section and Subsection Headings. The article, section and
subsection headings contained in this agreement are for the purpose of
convenience only and are not intended to define or limit the contents hereof or
otherwise be considered in construing and enforcing this agreement.
7.9 Waivers. Any failure by any party hereto to comply with any of its
obligations, agreements or conditions herein contained may be waived in writing,
but not in any other manner, by the party to whom such compliance is owed. No
waiver of, or consent to a change in, any provision of this agreement shall be
deemed to be, or shall constitute, a waiver of or consent to a change in the
provisions hereof (whether or not similar), nor shall such waiver constitute a
continuing waiver unless expressly provided.
7.10 Further Assurances. The parties hereto agree to deliver or cause
to be delivered to each other at all such times as shall be reasonably required,
all such additional instruments, agreements, and other documents, and to perform
all such actions, as any of them may reasonably request for the purpose of
performing any provision of this agreement or evidencing the transactions
contemplated by this agreement.
7.11 Severability. If any term or provision of this agreement or any
application of this agreement is held invalid or unenforceable, the remainder of
this agreement and any other application of the terms and provisions of this
agreement shall not be affected by that holding, but shall be valid and
enforceable.
7.12 Exhibits. All exhibits attached hereto or referred to in this
agreement are incorporated herein and made a part of this agreement.
7.13 Term. The term of this agreement shall be three (3) years from the
date hereof or until the last expiration of the last Jointly Owned AMI Interest
acquired hereunder, whichever is earlier, with the exception of the
confidentiality requirements of Article 3.5 which shall survive and extend past
that period.
7.14 Notices. All notices, consents and other communications under this
Agreement shall be in writing and shall be deemed to have been duly given (a)
when delivered by hand, (b) when sent by facsimile (with receipt confirmed),
provided that a copy is promptly mailed thereafter by first class postage
prepaid registered or certified mail, return receipt requested, (c) when
received by the addressee, if sent by Express Mail, Federal Express, other
express delivery service (receipt requested) or by such other means as the
Parties named below may agree from time to time or (d) five (5) days after being
mailed in the USA, by first class postage prepaid registered or certified mail,
return receipt requested; in each case to the appropriate address and telecopier
number set forth below (or to such other address or telecopier number as a Party
may designate as to itself by notice to the other Parties).
TAC Resources, Inc.
P. O. Box 206
Victoria, TX 77902
Attn: Bill Bishop
Telephone Number: (512)573-4969
Telecopier Number: (512)573-9840
Parallel Petroleum Corporation
110 N. Marienfield, Suite 465
Midland, TX 79701
Attn: Larry Oldham
Telephone Number: (915)684-3727
Telecopier Number: (915)684-3905
Unit Petroleum Company
24 Greenway Plaza, Suite 501
Houston, TX 77046
Attn: Jim Kahlden
Telephone Number: (713)960-8870
Telecopier Number: (713)960-8801
Beta Oil & Gas, Inc.
901 Dove Street, Suite 230
Newport Beach, CA 92660
Attn: Steve Antry
Telephone Number: (714)752-5212
Telecopier Number: (714)752-5757
Pease Oil and Gas Company
751 Horizon Court, Suite 203
P. O. Box 60219
Grand Junction, CO 81506-8758
Attn: Willard Pease, Jr.
Telephone Number: (970)245-5917
Telecopier Number: (970)243-8840
Each Party shall have the right upon giving thirty (30) days prior written
notice to the other Parties, in the manner herein provided, to change its
address and telecopier number for the purpose of notice.
7.15 Transfers Subject to this Agreement. Any sale, agreement, transfer
or other disposition of an interest in the Contract Lands, however accomplished,
either voluntarily or involuntarily, by operations of law or otherwise, shall be
subject to the terms of this Agreement. Any instruments which convey any
interest in the Contract Lands shall be made expressly subject to the Agreement.
7.16 Counterparts. This agreement may be executed in multiple
counterparts, all of which when taken together shall constitute one and the same
agreement.
7.17 Public Announcements. Each Party hereto agrees that prior to
making any public announcement or statement with respect to the transaction
contemplated in this Agreement, the Party desiring to make such public
announcement or statement shall consult with the other Parties hereto and
exercise their best efforts to (i) agree upon the text of a joint public
announcement or statement to be made by the Parties, (ii) obtain approval of the
other Parties hereto to the extent of a public announcement or statement to be
made solely by one of the Parties, as the case may be. Approval shall be
requested pursuant to Article 7.14 hereof, and any such announcement or
statement shall be deemed approved if no reply to the contrary is received
within twenty-four (24) hours (Saturdays, Sundays and federal legal holidays
excluded) after receipt of such request by the other Parties. Nothing contained
in this paragraph shall be construed to require any Party to obtain approval of
the other Parties hereto to disclose information with respect to the transaction
contemplated by this Agreement to any governmental body to the extent required
by applicable law or by any applicable rules.
7.18 Expenses. Except as specified herein and as the Parties may
otherwise agree, each Party shall be solely responsible for all expenses
incurred by it in connection with any and all transactions that are contemplated
by this Agreement.
7.19 Force Majeure. Should any Party be prevented, wholly or in part,
from complying with any express or implied obligation of this Agreement (other
than the obligation to make money payments), from conducting any operations
provided for under this Agreement, including by way of illustration but not
limitation, the conducting of the 3-D Seismic Operations by reason of scarcity
of or inability to obtain or to use labor, water, equipment or materials in the
open market or transportation thereof fro any cause (other than financial)
beyond the control of such Party, or operation of "Force Majeure, any State or
Federal law or any order, ruling or regulation of governmental authority, then
while so prevented, such Party's obligation to comply with such provision or
obligation shall be suspended, and such Party shall not be liable in damages or
otherwise to the other Parties for failure to comply therewith, provided that
the Party claiming suspension shall give written notice and full particulars of
the reason of such inability to perform its obligations to the other Parties
within thirty (30) days after the occurrence of the cause relied on by the Party
claiming suspension.
7.20 Arbitration. The Parties agree that any and all disputes arising
under or relating to this Agreement shall be referred to arbitration pursuant to
the commercial rules of arbitration of the American Arbitration Association.
Venue for such arbitration shall be Houston, Texas USA.
IN WITNESS WHEREOF, this agreement is executed on the date first above written.
TAC Resources, Inc.
By:________________________________
Bill Bishop, President
Parallel Petroleum Corporation
By:_______________________________
Larry C. Oldham, President
Unit Petroleum Company
By:_______________________________
Phillip M. Keeley, Sr., Sr. Vice-President
Beta Oil & Gas, Inc.
By:________________________________
Steve Antry, President
Pease Oil and Gas Company
By:________________________________
Willard Pease, Jr., President
EXPLORATION AGREEMENT
Formosa Grande Project
Jackson and Calhoun Counties, Texas
This Exploration Agreement (the "Agreement") is entered into as of August
1, 1997, by and between Parallel Petroleum Corporation ("Parallel"), TAC
Resources, Inc. ("TAC"), Allegro Investments, Inc. ("Allegro"), Beta Oil & Gas,
Inc. ("Beta"), Pease Oil and Gas Company ("Pease"), Four-Way Texas L.L.C.
("Four-Way"), Meyer Financial Services, Inc. ("Meyer") and Wes-Tex Drilling
Corp. ("Wes-Tex") all hereinafter collectively referred to as (the "Parties").
WITNESSETH:
WHEREAS, Parallel has acquired, for itself and for the benefit of TAC
and Allegro, seismic and lease options, oil and gas leases and seismic permits
covering an area of approximately 90,000 acres located in Jackson and Calhoun
Counties, Texas, as depicted on the plat attached hereto as Exhibit "A".
WHEREAS, Beta, Pease, Four-Way, Meyer and Wes-Tex propose to acquire
undivided interests in and to the rights granted by such agreements, and to
participate in conducting a 3-D seismic program upon the lands covered thereby.
NOW, THEREFORE, in consideration of the premises, the mutual agreements
and obligations set forth herein, and the mutual benefits to be received
hereunder, the Parties agree as follows:
ARTICLE 1. DEFINITIONS
For the purpose of this Agreement, the following terms shall have the
meanings designated below:
1.1 Area of Mutual Interest "AMI" means the lands outlined on the plat
attached hereto as Exhibit "A".
1.2 "AMI Interests" means any interest in the oil, gas or other
minerals in and under the AMI, including leasehold interests under oil and gas
leases, oil and gas lease options, interests of the farmee under farmout
agreement, and other such interests or rights similar or dissimilar to those
mentioned, including, but not limited to, seismic permits. AMI Interest does
not, however, include nonpossessory interests in the oil, gas and other minerals
in and under the AMI, such as royalty interests, overriding royalty interests,
net profits interests, or other such interests whether similar or dissimilar to
those mentioned.
1.3 "Existing AMI Interests" means the Seismic and Lease Options, Oil
and Gas Leases and Seismic Permits which have been acquired by Parallel as of
December 1, 1997.
1.4 "Subsequently Acquired AMI Interests" means all AMI Interests
acquired after December 1, 1997.
1.5 "Contract Lands" means lands located within the AMI which are
covered by AMI Interests.
1.6 "Initial Interest" means a Party's ownership in Existing AMI
Interests, and the amount of interest a party is entitled to acquire in
Subsequently Acquired AMI Interests, subject to the provisions hereof.
1.7 "Jointly Owned AMI Interest" means an AMI Interest in which the
Parties own an interest pursuant to the terms of this Agreement.
1.8 "Lease Burden" means any royalty, overriding royalty interest, net
profits interest, production payment, carried interest, reversionary working
interest or other charges upon a leasehold interest or the production therefrom.
<PAGE>
1.9 "Losses" means any and all losses, liabilities, claims, demands,
penalties, fines, settlements, damages, actions, or suits of whatsoever kind and
nature (but expressly excluding consequential damages), whether or not subject
to litigation, including without limitation (I) claims or penalties arising from
products liability, negligence, statutory liability or violation of any
applicable law or in tort (strict, absolute or otherwise) and (ii) loss of or
damage to any property, and all reasonable out-of-pocket costs, disbursements
and expenses (including, without limitation, legal, accounting, consulting and
investigation expenses and litigation costs) imposed on, incurred by or asserted
against an indemnified Party in connection therewith.
1.10 "Operator" shall mean Parallel Petroleum Corporation.
1.11 "Party" or "Parties" means Parallel, TAC, Allegro, Beta, Pease,
Four-Way, Meyer, Wes-Tex and any other person or entity, singularly or as a
group, which hereafter becomes a party hereto or is otherwise subject to the
terms hereof.
1.12 "Pre-Existing Data" means such data which includes, but is not
limited to: seismic records and related seismic data, electronic and mud logs,
cores and core analyses, field studies (less and except any proprietary
methodology or process used by any Party in such studies), production tests,
engineering, geological, geophysical, paleontological data, interpretive data
and maps prepared by any Party in existence as of the date of this Agreement.
1.13 "Proportionate Share" except as otherwise provided for herein,
shall be calculated by dividing a Party's Initial Interest by the aggregate of
the Initial Interests of all Parties who are to share an interest or an
obligation pursuant to the terms hereof.
1.14 "Prospect" means an area within the AMI which is designated as a
Prospect pursuant to Article 6.3 hereof and within which there is expected to
occur, based on information developed as a result of 3-D Seismic Operations, a
commercial accumulation of oil and/or gas in a specific structural or
stratigraphic trap.
1.15 "Subsequently Created Burden" means a lease burden which is
created by a party subsequent to its acquisition of the interest which is
subject to the burden.
1.16 "Costs Prior to Leasehold Acquisition" means all costs of any type
whatsoever which pertain to this project, covering lands located within or
outside the AMI, including, but not limited to costs of seismic permits, seismic
and lease options, oil and gas leases, and renewals and/or extensions thereof,
land brokerage, legal costs, surface damages, surveying, seismic acquisition,
processing and interpretation, etc., which are incurred prior to Leasehold
Acquisition conducted under the provisions of Article 4 hereof.
1.17 Other terms are defined elsewhere in this Agreement.
ARTICLE 2. INTERESTS AND SHARE OF COSTS OF THE PARTIES
2.1 Area of Mutual Interest. The Parties hereby establish an Area of
Mutual Interest "AMI", same to be comprised of the area outlined on the attached
Exhibit "A", and which shall cover AMI Interests located therein. This AMI shall
continue for a term of seven (7) years, or the expiration of the last Jointly
Owned AMI Interest, whichever is earlier.
2.2 "Interests and Share of Costs of the Parties" The Parties hereby
agree to own, as their Initial Interest, and agree to bear the costs set out
below, as follows:
<PAGE>
<TABLE>
<CAPTION>
Party Initial Interest Share of Costs Share of Costs
Prior to Leasehold for Leasehold
Acquisition Acquisition and
Subsequent Operations
<S> <C> <C> <C>
Parallel .5312500 .5000000 .5312500
TAC .0625000 -0- .0625000
Allegro .0312500 -0- .0312500
Beta .2000000 .2666666 .2000000
Pease .1250000 .1666667 .1250000
Four-Way .0200000 .0266667 .0200000
Meyer .0100000 .0133 .0100000
Wes-Tex .0200000 .0266667 .0200000
</TABLE>
Parallel, TAC and Allegro have acquired and presently own the Existing AMI
Interests. Beta, Pease, Four- Way, Meyer and Wes-Tex agree that their respective
costs in the Existing AMI Interests shall be based on $100.00 per net mineral
acre on seismic and lease options, and cost plus 33.33333% on oil and gas leases
and seismic permits. The Existing AMI Interests are presently comprised of
approximately 73,102.116 net mineral acres covered by seismic and lease option,
522.896 net mineral acres covered by seismic permit where cost was $5,228.96,
and 146.890 net mineral acres covered by oil and gas lease where cost was
$7,344.50. Based on the foregoing, the current total cost of Existing AMI
Interests is Seven million three hundred twenty-two thousand seven hundred
eighty-five and 06/100 Dollars ($7,322,785.06). Beta, Pease, Four-Way, Meyer and
Wes-Tex agree to pay Parallel their Proportionate Share of such cost, as
referenced above, in the Existing AMI Interests upon execution of this
Agreement. Beta, Pease, Four-Way, Meyer and Wes-Tex hereby agree that Parallel
shall have the exclusive right to acquire AMI Interests through December 1,
1997, and that same shall be treated in all respects as Existing AMI Interests.
Beta, Pease, Four-Way, Meyer and Wes-Tex agree that they shall be obligated to
accept such interests in the same percentages and pay Parallel for such
interests at the same terms stated herein. Payment for such interests shall be
due within fifteen (15) days after receipt of written notice as set out in
Article 2.4. Interests available to Parallel which costs exceed those stated
above shall be offered to the other Parties as per the procedure set forth in
Article 2.4 below.
2.3 Recording. Parallel agrees to file for record in the office of the
Jackson County Clerk, all Memorandums of Seismic and Lease Options covering the
Existing AMI Interests within fifteen (15) days of the date this Agreement is
executed by all Parties.
2.4 Subsequently Acquired AMI Interests. Any Party acquiring a
Subsequently Acquired AMI Interest, directly or indirectly, shall notify the
other Parties hereto. Such notice shall set forth (i) a description of the
interest acquired, (ii) the total cost of the interest, including all land and
legal costs associated with the acquisition thereof, (iii) the Proportionate
Share of the notified Party and its cost therein, and (iv) any other pertinent
terms of such acquisition, including, but not limited to, copies of the
instruments of conveyance, copies of leases, assignments, subleases, farmout and
other contracts affecting the AMI Interests, copies of paid drafts or checks,
itemized invoices of actual costs incurred by the acquiring Party. Parties shall
have fifteen (15) days from the receipt of this notice to acquire their
Proportionate Share of the Subsequently Acquired AMI Interest. A Party's
election to acquire shall be given in writing and accompanied by Party's payment
of its total cost for such interest. If a Party's election and payment are not
received within such fifteen (15) day period, it shall be conclusively presumed
that such Party has elected not to acquire its Proportionate Share of the
Subsequently Acquired AMI Interest
<PAGE>
and has forfeited its right thereto. A Party's failure to exercise its option as
to any particular notice shall not constitute a waiver or release of its right
to acquire any interest described in any subsequent notice delivered hereunder.
2.5 Existing Burdens. Each Party's interest under this agreement in the
AMI Interests, and oil and gas leases which may be acquired thereunder, shall be
subject to and burdened by its proportionate share of all existing operating
agreements, existing and pending pooling and spacing orders and all Lease
Burdens other than Subsequently Created Burdens. Parallel, TAC and Allegro
represent that they have not burdened the Existing AMI Interests acquired or to
be acquired with any liens or Subsequently Created Burdens. Each Party agrees to
perform its Proportionate Share of the obligations under the AMI Interests
acquired pursuant to this Agreement and the other obligations described in this
Article, but only to the extent that such obligations arise after the
acquisition of such AMI Interests by such Party.
2.6 Expiring Options. If any lease options covered hereby will expire
prior to completion of the Seismic Operations contemplated herein, Operator
shall use its best efforts to renew and/or extend such option for a sufficient
period of time to complete the proposed 3-D Seismic Operations thereon and
exercise the lease option thereunder. Payment for extensions and/or renewals
shall be due within fifteen (15) days after receipt of an invoice therefore.
2.7 Assignments. Upon receipt of payment for AMI Interests, Parallel
shall assign to the Parties hereto their Initial Interest in such AMI Interests.
Such assignment shall be recordable in form, shall be subject to this agreement,
shall provide for warranty by, through and under Parallel, but not otherwise,
and shall be subject to the terms and provisions of the AMI Interests assigned.
Notwithstanding such assignments, the Parties hereby grant Operator full right
and authority to conduct Leasehold Acquisition on their behalf under the
provisions of Article 4 hereof.
2.8 AMI Interests Located In and Out of Existing AMI. If an AMI
Interest is found to cover lands located both within and outside the existing
AMI, the entirety of such AMI Interest shall be offered to the other Parties
under the acquisition, notice and election provisions of Article 2.4, and if the
other Parties elect to participate in the acquisition thereof, the description
of the lands comprising the AMI shall be deemed to be amended to extend and
cover all of the lands covered by such interest. The option of the Parties to
participate in the acquisition of such interests shall be limited to the
entirety of the interest acquired.
2.9 Option to Cash Call: Notwithstanding the provisions for the
payments required in Articles 2.2, 2.4, 2.6 and 4, Operator shall the right to
require the other Parties to pay their Proportionate Share of the estimated
costs as provided in such Articles in advance. Such advanced payment shall be
paid within fifteen (15) days of receipt of an invoice therefor.
ARTICLE 3. SEISMIC OPERATIONS
3.1 Existing Seismic, Geologic and Other Subsurface Data. Except as
prohibited by law or by agreements with third parties, upon request, each Party
owning existing seismic data pertaining to lands located within the AMI shall
furnish copies of all such data to the other Parties, together with any geologic
or other subsurface data that could be useful in the interpretation thereof. The
Party receiving such data shall bear the expense of copying it. The Party owning
any seismic or other data which may not be copied, due to legal prohibitions or
by agreements with third parties, shall, upon request, make such data available
to the Party requesting such data during normal business hours.
3.2 Ownership of Pre-Existing Data. Ownership of the Pre-Existing Data
and all reprocessed PreExisting Data shall at all times remain vested in the
Party who contributes the Pre-Existing Data for use by the Parties, and the
Parties agree to acknowledge such ownership, including, but not limited to, the
filing
<PAGE>
with any appropriate governmental authority of such acknowledgment. The Parties
expressly reserve the right to sell, license, or trade the Pre-Existing Data
which it contributes hereunder, to the extent that it has such right to sell,
license or trade the Pre-Existing Data, through its own efforts, or through the
efforts of others duly authorized by such Party and the benefits and advantages,
including monetary consideration, which such Party receives as a result of such
activities shall be the sole property of such Party.
3.3 Management of the 3-D Seismic Operations. Operator shall
exclusively manage and conduct the 3-D Seismic Operations contemplated hereunder
and all operations incident thereto, including, but not limited to, the
acquisition of all geoscientific data, the performance of all 3-D seismic
surveys and other geoscientific work incident thereto, and, subject to the
Operating Agreements, the drilling of all wells on the Prospects. Operator shall
perform all such work through employees, representatives, and contractors of its
selection, and Operator shall and does hereby agree to utilize reasonable
prudence and economic judgment in contracting with third party contractors or
subcontractors. As manager of 3-D Seismic Operations, Operator shall devote such
of its time, attention and efforts to the conduct thereof as it shall in good
faith determine reasonably necessary, but shall otherwise be free to engage in
and pursue all other current and future business projects, programs, prospects,
opportunities, investments and activities without obligation of any kind to or
right of participation therein by the other Parties hereto. In performing its
duties under this Agreement, Operator shall serve as an independent contractor
and not as an agent or employee of the other Parties hereto. Operator shall
utilize reasonable prudence and economic judgment in incurring costs, and shall
further conduct the 3-D Seismic Operations and perform all of its duties under
this Agreement as a reasonable, prudent operator, in a good and workmanlike
manner with due diligence and dispatch, in accordance with good oilfield and
exploratory practice, and in compliance with all applicable laws and
regulations, BUT SHALL HAVE NO LIABILITY TO THE OTHER PARTIES HERETO OR ANY
OTHER OWNER OF RIGHTS OR INTERESTS UNDER THIS AGREEMENT FOR ANY LOSSES SUSTAINED
OR LIABILITIES INCURRED IN CONNECTION WITH THE 3-D SEISMIC OPERATIONS AND/OR THE
CONDUCT OF ANY ACTIVITIES UNDER OR CONTEMPLATED BY THIS AGREEMENT, SAVE AND
EXCEPT AS MAY BE OCCASIONED BY THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF
OPERATOR. EACH OF THE OTHER PARTIES HERETO ACKNOWLEDGES THAT (A) IT HAS READ AND
AGREED TO THE FOREGOING EXCULPATION OF OPERATOR AS A NEGOTIATED AND BARGAINED
FOR ASPECT OF THIS TRANSACTION, (B) THIS EXCULPATION PROVISION IS CONSPICUOUS.
3.4 Ongoing and Future Seismic Operations. The Parties agree to conduct
such operations on all or substantially all of the Contract Lands. The Parties
may, subject to their unanimous written consent, agree to reduce or increase the
acreage on which such operations will be conducted when technical, legal or
operational considerations indicate that such reduction or increase is
warranted. In any event, the Parties agree to pay Operator their respective
shares of the total costs of the 3-D Seismic Operations conducted on all land
covered by AMI Interests as set forth in Article 2.2 hereof. Payment for 3-D
Seismic Operations shall be due within fifteen (15) days after receipt of each
invoice therefore. Operator shall furnish the other Parties hereto with copies
of all applicable contracts and other information pertaining to all 3-D Seismic
Operations conducted hereunder. The Parties shall own their Proportionate Share
of the geophysical data obtained by and resulting from the 3-D Seismic
Operations conducted on the Contract Lands, including, but not limited to all
tapes, seismic sections and any and all other data generated by such 3-D Seismic
Operations. Each Party shall have access to such data and shall receive copies
thereof. The Parties agree to work together in a spirit of cooperation and in
good faith in planning and causing the 3-D Seismic Operations to be conducted as
contemplated herein as well as in sharing the data collected therefrom and the
interpretations thereof. Such interpretations, by any Party, shall in no way be
deemed a representation to any other Party that such interpretations are
accurate or correct. Such interpretations shall be given merely as a means of
sharing such Party's analysis and ideas regarding such data.
3.5 Confidentiality of Seismic Data. Except as provided below, each
Party agrees to keep all seismic data obtained pursuant to Article 3.3
confidential for a period of seven (7) years from the date hereof. After the
expiration of five (5) years from the date hereof any Party may sell the data it
acquired pursuant to Article 3.3. Each Party owning an interest in such data
shall receive its Proportionate Share of the proceeds of any such sale. Any data
acquired from another Party pursuant to Article 3.1 shall forever be kept
confidential by the Parties; provided, however, that the Party who originally
contributed such data may share, sell or otherwise may share, sell or otherwise
<PAGE>
dispose of such data that does not pertain to a Prospect to a third party after
the expiration of one (1) year from the date hereof, and the other Parties shall
have no interest in the proceeds from such sale. Notwithstanding the foregoing,
a Party may disclose seismic data to (A) a prospective purchaser or farmee of
such Party's interest, provided (i) such disclosure is limited to the Prospect
under consideration for sale or farmout, (ii) the prospective purchaser or
farmee must review such data in the affected Party's offices and may not copy
such data until such time as it has acquired or earned an interest in the
Contract Lands, and (iii) such prospective purchaser or farmee must execute a
confidentiality agreement to prevent further disclosure and unauthorized use of
such data; or (B) a third party who is entitled thereto pursuant to the terms of
a lease, lease option or seismic permit. Any Party may disclose such data to its
agents, staff, representatives and consultants in the normal conduct of its
business.
3.6 Review of Seismic Data. The Parties agree to cooperate in good
faith in reviewing the seismic data acquired hereunder. Such data should be
reviewed by the Parties as soon as practicable after the data is available so
that the Parties can make decisions regarding the exercise of lease options.
ARTICLE 4. LEASEHOLD ACQUISITION
As soon as is practicable after the 3-D seismic data has been processed
and interpreted, Operator shall, in its sole discretion, acquire leases within
the AMI, and the Parties agree to pay their Proportionate Share of cost therein,
including all land and legal costs associated with the acquisition thereof. Upon
receipt of payment, which shall be due within fifteen (15) days after receipt of
each invoice therefore, Operator shall promptly execute and deliver recordable
assignments to the Parties reflecting their respective interests in the leases
acquired.
ARTICLE 5. FORFEITURE
Payments due hereunder for Existing AMI Interests under Article 2.2,
renewals and/or extensions acquired under Article 2.6, Seismic Operations under
Article 3.4, and Lease Acquisition under Article 4 shall be mandatory. A Party
failing to timely make any such payment shall be in breach of this Agreement;
and, in the event such payment is not received by Operator, or other Party
entitled thereto, within sixty (60) days after written demand therefore has been
received, such Party shall, without the necessity of any further proceeding,
forfeit all of its right, title and interest under this Agreement to Operator.
Any Party so forfeiting its interest hereunder, hereby appoints Operator as its
Agent and Attorney-in-Fact for the sole and limited purpose of executing an
instrument of conveyance vesting title to the forfeited interest in Operator and
filing same in the appropriate public records.
ARTICLE 6. SALE, FARMOUT OR OTHER DISPOSITION OF AMI INTERESTS TO A THIRD PARTY
Any Party may sell, assign, farmout or otherwise dispose of all or any
portion of its interest acquired pursuant to or in connection with this
Agreement without consent of any other Party. Operator shall be furnished with a
copy of the assignment or other instrument disposing of such interest within ten
(10) days from the date thereof.
ARTICLE 7. SUBSEQUENT OPERATIONS
7.1 Operator. Operator shall have the right, subject to the terms and
provisions of the attached Operating Agreement, to be the Operator for all
operations conducted within the AMI, and the Parties hereby agree to execute
separate Operating Agreements designating Operator, as Operator, as required.
<PAGE>
7.2 Operating Agreement. Except as provided herein, all operations
conducted within the AMI shall be conducted in accordance with the terms of an
Operating Agreement substantially in the form attached hereto as Exhibit "B". A
separate Operating Agreement shall be executed for each Prospect, with the first
well drilled in such Prospect to be designated as the "Initial Well". The share
of costs which each Party must bear and the interest of each Party in the
production from each well drilled under the Prospect Operating Agreement will be
determined on a well-by-well basis in accordance with the terms hereof as
modified by the terms of the Operating Agreement. In the event of conflict
between the terms and provisions hereof and those contained in the Operating
Agreement, the terms and provisions hereof shall prevail.
7.3 Designation of Prospects. As soon as practicable after the data has
been processed and interpreted, Operator shall furnish the other Parties with
maps which reflect designated Prospects, together with a description of the
seismic data, prospective feature and any interpretative data or other maps upon
which such Prospect is based.
7.4 Non-Consent Election on Initial Well. If a Party elects not to
participate in the drilling of the Initial Well in a Prospect, such Party shall
relinquish all of its rights and interests in that Prospect to the Parties
participating in the drilling of such well which elect to acquire their
Proportionate Share of the relinquished interest. A condition precedent to such
relinquishment shall be the reimbursement of the relinquishing Party's leasehold
cost in the relinquished interest by the Parties electing to participate in such
interest, which cost shall be specifically limited to that incurred by such
Party under Article 4 hereof. A Party so relinquishing its interest shall
promptly execute a recordable assignment of its relinquished interest to the
Parties entitled thereto, which interest shall be free of any Subsequently
Created Burdens. Upon receipt of such assignment the Parties receiving the
relinquished interest shall reimburse the relinquishing Party their respective
Proportionate Share of the relinquishing Party's cost in the interest so
assigned.
7.5 Limitation on Number of Wells Drilling. Not more than three (3)
wells shall be drilling on the Contract Lands at any time unless it is necessary
to commence a well in order to perpetuate a lease or otherwise satisfy the terms
of a continuous drilling obligation.
ARTICLE 8. MISCELLANEOUS
8.1 Legal Relationship. This agreement is not intended to create, and
shall not be construed to create, a partnership or other relationship whereby
one party is liable for the actions or debts of another party; it being
understood and agreed that the rights and liabilities of all parties are several
and not joint or collective.
8.2 Entire Agreement. This agreement constitutes the entire agreement
among the parties hereto with respect to the subject matter hereof, superseding
any and all prior agreements, understandings, discussions, negotiations and
commitments of any kind.
8.3 Amendment. The provisions of this agreement may be amended,
supplemented, or waived only if in writing signed by all parties hereto.
8.4 Construction. The parties to this agreement all acknowledge and
agree that this agreement was drafted jointly by them, and that in the event of
any ambiguity, this agreement shall not be construed against any of them on the
basis of the fact or presumption that one party had a greater or lesser hand in
the drafting of the agreement than another party, but rather the terms shall be
given a reasonable interpretation.
8.5 Governing Law. Except to the extent preempted by federal law, this
agreement is to be construed and interpreted in accordance with, and governed
by, the laws of the State of Texas.
<PAGE>
8.6 Binding Agreement. This agreement shall bind and inure to the
benefit of the parties hereto and their respective heirs, successors, legal
representatives and assigns.
8.7 Section and Subsection Headings. The article, section and
subsection headings contained in this agreement are for the purpose of
convenience only and are not intended to define or limit the contents hereof or
otherwise be considered in construing and enforcing this agreement.
8.8 Waivers. Any failure by any party hereto to comply with any of its
obligations, agreements or conditions herein contained may be waived in writing,
but not in any other manner, by the party to whom such compliance is owed. No
waiver of, or consent to a change in, any provision of this agreement shall be
deemed to be, or shall constitute, a waiver of or consent to a change in the
provisions hereof (whether or not similar), nor shall such waiver constitute a
continuing waiver unless expressly provided.
8.9 Further Assurances. The parties hereto agree to deliver or cause to
be delivered to each other at all such times as shall be reasonably required,
all such additional instruments, agreements, and other documents, and to perform
all such actions, as any of them may reasonably request for the purpose of
performing any provision of this agreement or evidencing the transactions
contemplated by this agreement.
8.10 Severability. If any term or provision of this agreement or any
application of this agreement is held invalid or unenforceable, the remainder of
this agreement and any other application of the terms and provisions of this
agreement shall not be affected by that holding, but shall be valid and
enforceable.
8.11 Exhibits. All exhibits attached hereto or referred to in this
agreement are incorporated herein and made a part of this agreement.
8.12 Term. The term of this agreement shall be seven (7) years from the
date hereof or until the last expiration of the last Jointly Owned AMI Interest
acquired hereunder, whichever is earlier, with the exception of the
confidentiality requirements of Article 3.5 which shall survive and extend past
that period.
8.13 Notices. All notices, consents and other communications under this
Agreement shall be in writing and shall be deemed to have been duly given (a)
when delivered by hand, (b) when sent by facsimile (with receipt confirmed),
provided that a copy is promptly mailed thereafter by first class postage
prepaid registered or certified mail, return receipt requested, (c) when
received by the addressee, if sent by Express Mail, Federal Express, other
express delivery service (receipt requested) or by such other means as the
Parties named below may agree from time to time or (d) five (5) days after being
mailed in the USA, by first class postage prepaid registered or certified mail,
return receipt requested; in each case to the appropriate address and telecopier
number set forth below (or to such other address or telecopier number as a Party
may designate as to itself by notice to the other Parties).
Parallel Petroleum Corporation
110 N. Marienfield, Suite 465
Midland, TX 79701
Attn: Larry Oldham
Telephone Number: (915)684-3727
Telecopier Number: (915)684-3905
TAC Resources, Inc.
P. O. Box 206
Victoria, TX 77902
Attn: Bill Bishop
Telephone Number: (512)573-4969
Telecopier Number: (512)573-9840
Allegro Investments, Inc.
1908 N. Laurent, Suite 370
Victoria, TX 77901
<PAGE>
Attn: Chris Thompson
Telephone Number: (512)573-5619
Telecopier Number: (512)576-9643
Beta Oil & Gas, Inc.
901 Dove Street, Suite 230
Newport Beach, CA 92660
Attn: Steve Antry
Telephone Number: (714)752-5212
Telecopier Number: (714)752-5757
Pease Oil and Gas Company
751 Horizon Court, Suite 203
P. O. Box 60219
Grand Junction, CO 81506-8758
Attn: Willard Pease, Jr.
Telephone Number: (970)245-5917
Telecopier Number: (970)243-8840
Four-Way Texas L.L.C.
c/o Kissing Bridge Company
11296 State Road
Glenwood, NY 14069
Attn: Bob James
Telephone Number: (716)592-4963
Telecopier Number: (716)592-4228
Meyer Financial Services, Inc.
1005 Liberty Building
Buffalo, NY 14202
Attn: Paul Meyer
Telephone Number: (716)842-2215
Telecopier Number: (716)842-2220
Wes-Tex Drilling Corp.
P. O. Box 3739
Abilene, TX 79604
Attn: Myrle Greathouse
Telephone Number: (915)677-9121
Telecopier Number: (915)677-5140
Each Party shall have the right upon giving thirty (30) days prior written
notice to the other Parties, in the manner herein provided, to change its
address and telecopier number for the purpose of notice.
8.14 Transfers Subject to this Agreement. Any sale, agreement, transfer
or other disposition of an interest in the Contract Lands, however accomplished,
either voluntarily or involuntarily, by operations of law or otherwise, shall be
subject to the terms of this Agreement. Any instruments which convey any
interest in the Contract Lands shall be made expressly subject to the Agreement.
8.15 Counterparts. This agreement may be executed in multiple
counterparts, all of which when taken together shall constitute one and the same
agreement.
8.16 Public Announcements. Each Party hereto agrees that prior to
making any public announcement or statement with respect to the transaction
contemplated in this Agreement, the Party desiring to make such public
announcement or statement shall consult with the other Parties hereto and
exercise their best efforts to (i) agree upon the text of a joint public
announcement or statement to be made by the Parties, (ii)obtain approval of the
<PAGE>
other Parties hereto to the extent of a public announcement or statement to be
made solely by one of the Parties, as the case may be. Approval shall be
requested pursuant to Article 8.13 hereof, and any such announcement or
statement shall be deemed approved if no reply to the contrary is received
within twenty-four (24) hours (Saturdays, Sundays and federal legal holidays
excluded) after receipt of such request by the other Parties. Nothing contained
in this paragraph shall be construed to require any Party to obtain approval of
the other Parties hereto to disclose information with respect to the transaction
contemplated by this Agreement to any governmental body to the extent required
by applicable law or by any applicable rules.
8.17 Expenses. Except as specified herein and as the Parties may
otherwise agree, each Party shall be solely responsible for all expenses
incurred by it in connection with any and all transactions that are contemplated
by this Agreement.
8.18 Force Majeure. Should any Party be prevented, wholly or in part,
from complying with any express or implied obligation of this Agreement (other
than the obligation to make money payments), from conducting any operations
provided for under this Agreement, including by way of illustration but not
limitation, the conducting of the 3-D Seismic Operations by reason of scarcity
of or inability to obtain or to use labor, water, equipment or materials in the
open market or transportation thereof from any cause (other than financial)
beyond the control of such Party, or operation of "Force Majeure, any State or
Federal law or any order, ruling or regulation of governmental authority, then
while so prevented, such Party's obligation to comply with such provision or
obligation shall be suspended, and such Party shall not be liable in damages or
otherwise to the other Parties for failure to comply therewith, provided that
the Party claiming suspension shall give written notice and full particulars of
the reason of such inability to perform its obligations to the other Parties
within thirty (30) days after the occurrence of the cause relied on by the Party
claiming suspension.
8.19 Arbitration. The Parties agree that any and all disputes arising
under or relating to this Agreement shall be referred to arbitration pursuant to
the commercial rules of arbitration of the American Arbitration Association.
Venue for such arbitration shall be Houston, Texas USA.
IN WITNESS WHEREOF, this agreement is executed on the date first above written.
Parallel Petroleum Corporation
By:_______________________________
Larry C. Oldham, President
TAC Resources, Inc.
By:_______________________________
Bill Bishop, President
Allegro Investments, Inc.
By:________________________________
John R. Thompson, President
<PAGE>
Beta Oil & Gas, Inc.
By:________________________________
Steve Antry, President
Pease Oil and Gas Company
By:________________________________
Willard Pease, Jr., President
Four-Way Texas, L.L.C.
By:________________________________
Robert M. James, President
Meyer Financial Services, Inc.
By:________________________________
Paul Meyer, President
Wes-Tex Drilling Corp.
By:________________________________
Myrle Greathouse, Chairman of the Board
EXPLORATION AGREEMENT
This Agreement is made and entered into this 1st day of November, 1997, by
and between PARALLEL PETROLEUM CORPORATION ("Parallel"), SUE-ANN PRODUCTION
COMPANY ("Sue-Ann"), TAC RESOURCES, INC. ("TAC"), ALLEGRO INVESTMENTS, INC.
("Allegro"), (said Parties being sometimes hereinafter collectively referred to
as "Parallel/Sue- Ann"), BETA OIL & GAS, INC. ("Beta"), PEASE OIL & GAS COMPANY
("Pease"), MEYER FINANCIAL SERVICES, INC. ("Meyer"), and FOUR-WAY TEXAS, L.L.C.
("Four-Way") (said parties being sometimes hereinafter collectively referred to
as "Beta/Pease");
WITNESSETH:
WHEREAS, Parallel/Sue-Ann have identified the lands outlined on the map
attached as Exhibit "A" hereto, except the lands and depths covered by the
Leases described on Exhibit "B" hereto (the "Excluded Lands") , as an area that
they desire to jointly explore for the production of oil and gas;
WHEREAS, Parallel/Sue-Ann have acquired the Leases and Seismic Options
(as those terms are defined below) described in Exhibits "C-1" and "C-2" hereto
(such Leases and Options being collectively referred to as the "Existing Leases
and Options") covering the interests in the lands described in such agreements;
WHEREAS, Parallel/Sue-Ann desire to conduct 3-D Seismic Operations
across most of the Contract Lands; and
WHEREAS, Beta, Pease, Meyer and Four-Way desire to acquire the
undivided interests in the Existing Leases and Options and participate in the
3-D Seismic Operations to be conducted by Parallel/Sue-Ann, all as described
below;
NOW, THEREFORE, in consideration of the premises, the mutual covenants,
agreements and obligations set forth herein, and the mutual benefits to be
received hereunder, the Parties hereto agree as follows:
ARTICLE 1. DEFINITIONS
For the purposes of this Agreement, the following terms shall have the
meanings designated below:
1.1 "3-D Seismic Operations" means all operations which are necessary
to produce a three-dimensional seismic data grid over the portion of the
Contract Lands on which the Parties conduct such operations, including the
processing and interpretation of such data.
1.2 "Contract Lands" shall mean the lands lying within the area
outlined by the bold, solid line on Exhibit "A" hereto, except the Excluded
Lands; provided, however, the "Contract Lands" may be enlarged or contracted to
the same extent that all of the Parties agree to expand or contract the 3-D
Seismic Operations to be conducted pursuant to Section 4.2 hereof.
1.3 "Existing Leases and Options" means those Leases and Seismic
Options (as such terms are defined below) which are described in Exhibits "C-1"
and "C-2" hereto, including any such Leases and Options which are renewed or
extended pursuant to Article 2.3 hereof.
1.4 "Initial Interest" means a Party's initial interest hereunder as
set forth in Article 3.1 hereof.
1.5 "Jointly-Owned Lease" means a Lease (as defined below) in which two
or more of the Parties own an interest pursuant to the terms of this Agreement.
1.6 "Lease" means oil and gas lease, oil, gas and mineral lease,
unleased mineral interest, or sublease thereof, operating rights or other rights
or partial interest therein, which authorize the owner thereof to explore any
portion of the Contract Lands for (and/or produce) oil and/or gas therefrom, and
the right to acquire any of the foregoing. This term also includes top leases,
farmout agreements or any other type of agreement under which the right to
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explore and/or develop a portion of the Contract Lands can be earned including
Seismic Options (as defined below).
1.7 "Lease Burden" means any production sale contract, lien,
encumbrance, royalty, overriding royalty interest, net profits interest,
production payment, carried interest, reversionary working interest or other
charge upon a leasehold interest or the production therefrom.
1.8 "Net Mineral Acres" are calculated by multiplying the undivided
interest in the minerals covered by a Lease or Seismic Option times the number
of gross acres covered by such Lease or Seismic Option times a Party's undivided
interest in such Lease or Seismic Option.
1.9 "Party" means either Parallel, Sue-Ann, TAC, Allegro, Beta, Pease,
Meyer or Four- Way or any other person or entity which hereafter becomes a party
hereto or is otherwise subject to the terms hereof.
1.10 "Proportionate share", except as otherwise provided for
hereinbelow, shall be calculated by dividing a Party's Initial Interest
percentage by the aggregate of the Initial Interests of all of the Parties who
are to share an interest or an obligation pursuant to the terms hereof. In
circumstances where one or more Parties do not participate in a project or
acquisition, "proportionate share" shall be determined with reference to the
Parties who participate in such project or acquisition.
1.11 "Prospect" means an area, designated as a Prospect pursuant to
Article 5.1 hereof, within which there is expected to occur, based upon the
information developed as a result of 3-D Seismic Operations, a commercial
accumulation of oil and/or gas in a specific structural or stratigraphic trap.
1.12 "Seismic Option" or "Option" means an agreement which entitles a
Party to conduct 3-D Seismic Operations on a portion of the Contract Lands with
an option to acquire a Lease covering all or a portion of such lands.
1.13 "Subsequently Created Burden" means a Lease Burden which is
created by a Party subsequent to its acquisition of the interest which is
subject to the burden.
1.14 Other terms are defined elsewhere in this Agreement.
ARTICLE 2. ACQUISITION OF INTEREST IN EXISTING LEASES AND OPTIONS
2.1 Initial Acquisition. Beta, Pease, Meyer and Four-Way agree to
acquire from Parallel the following interest set forth opposite their name in
the Existing Leases and Options:
Beta ............................................... 20%
Pease ...............................................12.5%
Meyer ............................................. 2%
Four-Way .......................................... 1%
For such interests, Beta, Pease, Meyer and Four-Way agree to pay Parallel the
sum of One Hundred Thirty-Three and 33/100 Dollars ($133.33) per Net Mineral
Acre covered by the respective undivided interests in the Existing Leases and
Options so acquired by such Parties. Parallel has represented to Beta, Pease,
Meyer and Four-Way that the Existing Leases and Options described in Exhibits
"C-1" and "C-2" hereto cover at least 17,654 Net Mineral Acres. Accordingly,
Beta, Pease, Meyer and Four-Way initially shall pay Parallel the sum set forth
opposite their name for the interest each acquires under this Article 2.1:
Beta ....................................... $470,773.00
Pease ..................................... $294,216.00
Meyer ..................................... $47,077.00
Four-Way .................................. $23,539.00
Beta, Pease, Meyer and Four-Way shall pay Parallel such sums upon the complete
execution hereof. Upon receipt of such payment, each such Party will be assigned
its respective percentage interest (as set forth above in this Article 2.1) in
the Existing Leases and Options. In the event it is determined
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that the Existing Leases and Options cover less than 17,654 Net Mineral Acres,
Parallel shall refund to Beta, Pease, Meyer and Four-Way the amounts that such
Parties overpaid for their respective Initial Interests acquired under this
Article 2.1. If it is determined that the Existing Leases and Options cover more
than 17,654 Net Mineral Acres, Beta, Pease, Meyer and Four-Way shall pay
Parallel an additional sum equal to their proportionate share of the number of
Net Mineral Acres covered by the Existing Leases and Options in excess of 17,654
Net Mineral Acres.
2.2 Subsequently-Acquired Leases and Options. All of the Parties hereto
agree to acquire and pay their proportionate share (as provided hereinbelow) of
the cost of any Leases or Seismic Options, including a Lease or an option in
renewal of an expiring Lease or Option as provided in Article 2.3 (a
"Subsequently-Acquired Lease or Option"), which are acquired by a Party from an
unaffiliated third party prior to the conclusion of 3-D Seismic Operations. For
the purposes of this Article 2.2, the proportionate shares of the interests and
costs of a Subsequently-Acquired Lease or Option of the Parties comprising
Parallel/Sue-Ann shall be as follows:
Parallel............................................... 79.125%
Sue-Ann................................................ 16.875%
TAC.................................................. 1.000%
Allegro.............................................. 3.000%
Beta, Pease, Meyer and Four-Way agree to purchase their proportionate share of
such Subsequently- Acquired Leases or Options from Parallel for a price equal to
the actual total cost thereof plus one-third (1/3) of such total cost thereof.
The Party initially acquiring such interest shall promptly notify the other
Parties comprising Parallel/Sue-Ann of the acquisition of such interest. Such
notice shall contain the same information as is required in Article 6.3 for an
AMI Interest. The other Parties comprising Parallel/Sue-Ann shall promptly
reimburse the acquiring Party for their proportionate share of the actual total
cost thereof. Upon receipt of a Party's proportionate share of the costs of
acquiring such interest, the acquiring party shall promptly assign to such Party
its proportionate share of such interest (as set forth above in this Article
2.2). Upon Parallel's acquisition of its proportionate share of a
Subsequently-Acquired Lease or Option, it shall notify Beta, Pease, Meyer and
Four-Way of such acquisition and invoice them for their proportionate share
thereof at a price equal to the total cost of acquiring such Lease or Option
plus one-third (1/3) of such total cost. Upon receipt of the purchase price from
such Party Parallel shall promptly assign to such Party its proportionate share
of such interest.
2.3 Expiring Options. If any Leases or Options covered hereby will
expire prior to the completion of the 3-D Seismic Operations contemplated herein
and the exercise of the Options to acquire Leases under such Options, the Party
originally acquiring such expiring Lease or Option shall use its best efforts to
renew such Leases or Options for a sufficient period of time to complete the
proposed 3-D Seismic Operations thereon and exercise any such Options
thereunder. All such renewals shall be treated in the same manner as set forth
in Article 2.2, above, pertaining to Subsequently-Acquired Leases and Options.
ARTICLE 3. INTERESTS OF THE PARTIES
3.1 Initial Interests of the Parties. The Initial Interests of the
Parties hereunder will be as follows:
Parallel.......................................... 43.625%
Sue-Ann........................................... 16.875%
TAC.............................................. 1.000%
Allegro.......................................... 3.000%
Beta.............................................. 20.000%
Pease............................................. 12.500%
Meyer .......................................... 2.000%
Four-Way ....................................... 1.000%
All Existing Leases and Options will be owned by the Parties in accordance with
their respective Initial Interests. All Subsequently-Acquired Seismic Options
will be owned in the same proportions as the Parties' Initial Interests,
provided that each Party has paid its proportionate share of the cost thereof as
provided in Section 2.2. If a Party fails to pay for its proportionate share of
a Subsequently-Acquired Seismic Option, such Seismic Option will be owned by the
Parties who paid their original proportionate share of the costs thereof.
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Such Parties will pay their proportionate share of the total cost thereof and
such interests shall be owned by such Parties in the proportions that their
respective Initial Interests hereunder bear to the aggregate of such Parties'
Initial Interests.
3.2 Existing Burdens. Each Party's interest under this Agreement, in
the Leases and Seismic Options covered hereby and the Leases acquired and to be
acquired pursuant hereto, shall be subject to and burdened by its proportionate
share of all existing operating agreements, existing and pending pooling and
spacing orders and all Lease Burdens other than Subsequently Created Burdens.
Each Party hereto hereby assumes and agrees to perform its proportionate share
of the obligations under all Leases and Seismic Options and the Leases acquired
pursuant to this Agreement and the other obligations described in this Article,
but only to the extent that such obligations arise after the acquisition of such
Leases and Seismic Options by such Party.
ARTICLE 4. SEISMIC OPERATIONS
4.1 Existing Seismic, Geologic and Other Subsurface Data. Except as
prohibited by law or by agreements with third parties, upon request, each Party
owning existing seismic data pertaining to the Contract Lands shall furnish
copies of all of such data to any Party requesting such data, together with any
geologic or other subsurface data that could be useful in the interpretation of
such seismic data. The Party requesting such data shall bear the expense of
copying it. The Party owning any seismic or other data which may not be copied
shall, upon request, make such data available to the Party requesting such data
during normal business hours.
4.2 3-D Seismic Operations. Parallel shall serve as Operator in
conducting all 3-D Seismic Operations. All Parties agree to conduct such
operations on all or substantially all of the Contract Lands. The Parties may,
by unanimous agreement, reduce the number of sections on which such operations
will be conducted (for example, where technical, legal or operational
considerations indicate that such reduction is warranted). Beta and Pease desire
to participate in such 3-D Seismic Operations. The Parties shall bear the
following proportions of the total cost of all 3-D Seismic Operations:
Parallel........................................ 31.79166%
Sue-Ann......................................... 16.87500%
TAC............................................ 1.00000%
Allegro....................................... 3.00000%
Beta............................................ 26.66667%
Pease........................................... 16.66667%
Meyer.......................................... 2.66667%
Four-Way ..................................... 1.33333%
Subject to Article 5.1.1, the data that is obtained from such 3-D Seismic
Operations shall be owned by the Parties in the proportions of their Initial
Interests hereunder. The Parties agree to work together in a spirit of
cooperation and in good faith in planning and causing the 3-D Seismic Operations
to be conducted as contemplated and provided herein, as well as in sharing the
data collected therefrom and the interpretations thereof. Such interpretations
shall in no way be deemed a representation that such interpretations are
accurate or correct. Such interpretations shall be given merely as a means of
sharing such Party's analysis and ideas regarding such data.
4.3 Confidentiality of Seismic Data. Except as provided below, each
Party agrees to keep all seismic data obtained pursuant to Article 4.2
confidential for a period of seven (7) years from the date hereof. After the
expiration of seven (7) years from the date hereof, any Party may sell the data
it acquired pursuant to Article 4.2. Each Party owning an interest in such data
shall receive its proportionate share of the proceeds of any such sale. Any data
acquired from another Party pursuant to Article 4.1 shall forever be kept
confidential by the Parties; provided, however, that the Party who originally
contributed such data may share, sell or otherwise dispose of such data that
does not pertain to a Prospect to a third party after the expiration of one (1)
year from the date hereof, and the other Parties shall have no interest in the
proceeds from such sale. Notwithstanding the foregoing, a Party may disclose
seismic data to a prospective purchaser or farmee of such Party's interest,
provided (i) such disclosure is limited to the Prospect under consideration for
sale or farmout, (ii) the prospective purchaser or farmee must review such data
in the affected Party's offices and may not copy such data, and (iii) such
prospective purchaser or farmee must execute a confidentiality agreement to
prevent further disclosure and unauthorized use of such data.
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4.4 Review of Seismic Data. The Parties agree to cooperate in good
faith in reviewing the seismic data obtained hereunder. Such data should be
reviewed by the Parties as soon as practicable after the data for a particular
area is available so that the Parties can make a decision as to whether or not
to exercise any of the Options to acquire Leases under any of the Seismic
Options pertaining to such area.
ARTICLE 5. EXERCISE OF OPTIONS
5.1 Designation of Prospects. The Parties shall cooperate in good faith
to establish Prospects within the Contract Lands as soon as practicable after
the data for an area has been processed and interpreted. Any Party may designate
a Prospect within seven (7) years from the date hereof by giving the other
Parties written notice of such designation. Such notice shall contain a map
which reflects the outline of the lands to be included within such Prospect,
together with a description of the seismic data, prospective feature and any
interpretative data or maps upon which such Prospect is based. The Parties
receiving notice of the designation of a Prospect shall have fourteen (14) days
after receipt of such notice in which to elect in writing whether or not they
will participate in such Prospect. Any Party which has not furnished the Party
designating a Prospect with its written election to participate in a Prospect
within said fourteen-day period conclusively shall be presumed to have elected
not to participate in the Prospect so designated. Any Party not participating in
a Prospect shall promptly assign all of its interest in the Options or Leases
covering lands lying within such Prospect to the Parties participating in such
Prospect, in the proportions of their respective interests therein.
5.1.1 Extension; Additional Seismic Operations. In the event a
Prospect includes lands lying on the border of the Contract Lands, one
or more of the Parties participating in such Prospect may propose the
conducting of additional 3-D Seismic Operations to obtain seismic data
on lands lying outside of the Contract Lands but reasonably anticipated
to be underlain by the feature for which such Prospect was designated.
In the event all Parties participating in such Prospect agree to
participate in the additional seismic operations, the Prospect shall be
enlarged to cover the lands included in such proposed additional
shooting and all such Parties shall bear their proportionate share of
the costs of such additional seismic operations. A Party participating
in the original Prospect may elect not to participate in expanding the
Prospect by conducting additional 3-D Seismic Operations, in which
event the lands covered by the additional 3-D Seismic Operations shall
constitute a separate Prospect in which only the Parties conducting
such operations will participate. Notwithstanding the foregoing, the
expanded Prospect shall not include any lands on which (i) the Parties
electing to participate in the expanded Prospect are unable to obtain a
Lease or an Option from a third party or (ii) a Party owns a Lease or
Option which has been committed to an agreement with a third party
prior to the date hereof.
5.2 Acquisition of Leases Within Prospects. The Parties participating
in a Prospect will acquire and pay for Leases covering lands within such
Prospects upon the terms provided for in the applicable Seismic Options or upon
such other terms as the Parties can mutually agree upon if some Leases are not
governed by the terms of a Seismic Option.
5.3 Minimum Acreage Obligation. In the event the Leases acquired by
Parties electing to participate in Prospects do not satisfy the minimum acreage
selection requirements under one or more of the Seismic Options, then each Party
must acquire and pay for its proportionate share of the Leases which must be
acquired in order to fulfill any such minimum acreage selection requirements.
ARTICLE 6. AREA OF MUTUAL INTEREST
6.1 Establishment of Area of Mutual Interest. The Contract Lands are
hereby established as an Area of Mutual Interest for a term of seven (7) years
from the date of this Agreement. Thereafter, those lands lying within a Prospect
which has been designated as provided in Article 5.1 shall be established as an
Area of Mutual Interest for the Parties then owning an interest in such Prospect
for as long as any Jointly-Owned Lease covering lands within such Prospect is in
force and effect as to such land.
6.2 Acquisition of Interest. After all of the 3-D Seismic Operations
have been completed (through the interpretation of the data obtained therefrom),
except as otherwise provided in this
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Article 6, if during the term of the Area of Mutual Interest a Party (the
"Acquiring Party") acquires from an unaffiliated third party a Lease covering
lands lying within such Area of Mutual Interest (an "AMI Interest"), the other
Parties (the "Non-Acquiring Parties") shall have the first and prior right to
acquire their proportionate share of such interest upon the terms set forth
below. If an AMI Interest covers lands lying within a Prospect in which a Party
has elected not to participate pursuant to Articles 5.1 or 8.4 hereof, such
Party shall offer one hundred percent (100%) of such interest to the Parties
participating in such Prospect.
6.3 Notification. The Acquiring Party shall notify the Non-Acquiring
Parties in writing of the acquisition of an AMI Interest. Such notice shall set
forth (i) a description of the interest acquired, (ii) the total cost of the
interest, including all land and legal costs associated with the acquisition
thereof, (iii) the proportionate share of such interest that the Non-Acquiring
Parties are entitled to acquire, and (iv) any other pertinent terms of such
acquisition, including copies of such Leases, assignments, bank drafts or other
evidence of payment for such interest.
6.4 Election Period. The Non-Acquiring Parties shall have ten (10) days
from the receipt of such notice to elect to acquire. If any Non-Acquiring Party
elects to acquire its proportionate share of the AMI Interest, such election
shall be given in writing to the Acquiring Party within ten (10) days after
receipt of notice of the acquisition of the interest. If the Acquiring Party has
not received an election in writing from a Non-Acquiring Party within said
ten-day period, such Non- Acquiring Party conclusively shall be presumed to have
elected not to acquire its proportionate share of the AMI Interest.
6.5 Binding Obligation. An election by a Non-Acquiring Party to acquire
its proportionate share of a AMI Interest shall constitute a binding obligation
of such Non-Acquiring Party to pay its proportionate share of the total cost of
the AMI Interest within thirty (30) days from the date that the Non-Acquiring
Party receives notice of the acquisition of such interest. If the Non- Acquiring
Party elects to acquire its proportionate share of an AMI Interest, the notice
of acquisition shall be deemed to be an invoice for the Non-Acquiring Party's
proportionate share of the total cost of such interest. If a Party fails to pay
its proportionate share of the cost of such an AMI Interest within said
thirty-day period, such Party shall then be conclusively deemed to have elected
not to acquire its proportionate share of such interest and the Acquiring
Parties shall have the right to acquire their proportionate share of such
interest.
6.6 Assignment of AMI Interest. The Acquiring Party shall execute and
deliver an Assignment to each Non-Acquiring Party which elects to acquire its
proportionate share of an AMI Interest as soon as practical after receiving the
Non-Acquiring Party's proportionate share of the total cost thereof.
6.7 Renewal and Extension Leases. Except as required in Article 2.3, if
a Party shall at any time acquire a renewal or extension of a Jointly-Owned
Lease (a "Renewal or Extension Lease"), each Non-Acquiring Party shall have the
first and prior right to acquire its proportionate share thereof. The
acquisition of a Renewal or Extension Lease pursuant to this Article 6.7 shall
be treated just as if it was an AMI Interest under Article 6.3 hereof. For the
purposes of this provision, the term "Renewal or Extension Lease" shall mean any
Lease which is acquired before the expiration of a prior Jointly-Owned Lease or
taken or contracted for within one (1) year from the expiration of a
Jointly-Owned Lease, but shall not include an Option acquired in renewal of an
Expiring Option as provided in Article 2.3.
ARTICLE 7. SALE, FARMOUT OR OTHER DISPOSITION
OF AN INTEREST TO A THIRD PARTY
Any Party may farm out or otherwise dispose of all or a portion of its
interest in any Jointly- Owned Lease to a third party. The Party desiring to
sell, farm out or otherwise dispose of such interest must notify the other
Parties in writing of all of the terms of such trade.
ARTICLE 8. SUBSEQUENT OPERATIONS
8.1 Operator. Sue-Ann shall have the first and prior right to be the
Operator for all operations conducted on the Contract Lands except the 3-D
Seismic Operations, provided that it has elected to participate in the
acquisition of the Leases covering the portion of the Contract Lands on which
such operations are to be conducted. Except as otherwise hereinabove provided, a
majority in interest of the Parties participating in a well may mutually agree
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that any of them or some third party may serve as Operator for any such well.
Except as otherwise agreed by the Parties, any Party participating in a Prospect
may, by forty-five (45) days' prior written notice to the other participating
Parties, cause the commencement of drilling operations on the Initial Well to be
drilled on such Prospect; subject, however, to the provisions of Article 8.3.
8.2 Operating Agreement. Except as provided herein, all operations
conducted on the Contract Lands shall be conducted in accordance with the terms
of an Operating Agreement substantially in the form attached as Exhibit "D"
hereto. A separate Operating Agreement shall be executed for each Prospect, with
the first well drilled in such Prospect to be designated as the Initial Well. A
commencement date for such Initial Well will be included in the Operating
Agreement upon execution only if agreed to by all participating Parties at that
time; otherwise, the commencement date will be determined pursuant to Article
8.1. The share of costs which each Party must bear and the interest of each
Party in the production from each well drilled under the Operating Agreement
will be determined on a well-by-well basis.
8.3 Limitation on Number of Wells Drilling. Only two (2) exploratory
wells shall be drilling on the Contract Lands at any time unless it is necessary
to commence a well while another well is being drilled in order to perpetuate a
Lease or otherwise satisfy the terms of a continuous drilling obligation.
8.4 Non-Consent Election on the Drilling of a Well. If a Party elects
not to participate in the drilling of any well in a Prospect established under
Section 5.1 hereof, such Party shall relinquish all of its rights and interests
in that Prospect proportionately to the other Parties who elect to participate
in the drilling of such well save and except such non-consenting Party's
interest in any wells in such Prospect in which such Party participated in
drilling and the proration unit or spacing unit therefor, provided that the well
in which such Party elected not to participate is commenced within the time
prescribed provided in the applicable Operating Agreement.
ARTICLE 9. REMEDIES FOR NON-PAYMENT
All of the payments required to be made by a Party hereunder shall be
made on or before such payments are due. The failure of any Party to pay an
amount due hereunder by the date that it is due shall constitute a breach of
this Agreement. The remedies for failure to make the payments required by
Article 6.5 (pertaining to the acquisition of an AMI Interest), Article 6.7
(pertaining to Renewal and Extension Leases) and the payments required under an
applicable Operating Agreement shall be governed by the provisions of such
Articles or the Operating Agreement (as the case may be). For all other payments
to be made hereunder, the Party to whom such a payment is not made when due
shall have the right to make written demand on the Party from whom such payment
is past due. If the Party receiving such written demand fails to make the
required payment within sixty (60) days from the date that it receives such
written demand, such Party shall relinquish all of its interest under this
Agreement (including, but not limited to all of the interest that it acquired
pursuant to the terms hereof in any Leases, Options, seismic data and wells
drilled on the Contract Lands) to the Party to whom such payment is owed. The
Party so relinquishing its interest hereby designates the Party to whom such
payment is owed as its agent and attorney-in-fact for the limited purpose of
such instrument of conveyance as is necessary to convey the relinquished
interests to the Party to whom the payment is owed. The Party receiving such
relinquished interest shall then offer the other Parties their proportionate
share of such relinquished interest. Each of the other Parties who pay their
proportionate share of the sum of money that was owed by the Party relinquishing
its interest to the Party offering such interest within fourteen (14) days from
its receipt of such offer, shall be entitled to their proportionate share of
such relinquished interests and the Party offering such interest shall, as soon
as practicable, execute an instrument conveying such interest to such Parties.
ARTICLE 10. MISCELLANEOUS
10.1 Term and Applicability of Agreement. Except as otherwise provided
for herein, the provisions of this Agreement shall remain in force and effect
for a term of seven (7) years from the date hereof except that it shall apply to
each Jointly-Owned Lease and the lands included within the Prospect in which the
lands covered by such Jointly-Owned Lease are situated for as long as such
Jointly-Owned Lease remains in force and effect.
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10.2 Governing Law. The laws of the State of Texas shall apply in
all matters concerning this Agreement.
10.3 Entire Agreement. This Agreement, including all of the exhibits
attached hereto, constitute the entire agreement of the Parties concerning the
subject matter hereof, and there are no other understandings, obligations,
relationships or agreements, written or oral, pertaining to the subject matter
of this Agreement. This Agreement supersedes, replaces and shall be in lieu of
that certain Exploration Agreement dated October 22, 1996, between Parallel and
Sue-Ann, insofar only as this Agreement covers the lands and depths covered by
the Exploration Agreement dated October 22, 1996. Otherwise, the Exploration
Agreement dated October 22, 1996 shall remain in force as to the lands and
depths covered thereby which are not covered by this Agreement.
10.4 Inurement. This Agreement shall be binding upon and shall inure to
the benefit of the successors and assigns of the Parties and the terms and
provisions hereof shall constitute covenants running with the lands subject
hereto to the extent that such provisions apply to such lands.
10.5 Notices. All notices required to be given hereunder shall be given
in writing. Any such notice shall be deemed to be given upon receipt thereof by
the Party who is to receive the notice. The receipt of a notice by electronic
facsimile (fax) shall be considered as delivery of such notice. If notice by fax
is received other than during normal business hours, it shall be deemed received
on the next business day. All notices required hereunder shall be given to the
Parties as follows:
If to Parallel: Parallel Petroleum Corporation
110 N. Marienfeld, Suite 465
Midland, Texas 79701
Attn: Mr. Larry C. Oldham
or
Fax No.: 915-684-3905
If to Sue-Ann: Sue-Ann Production Company
1908 N. Laurent, Suite 570
Victoria, Texas 77901
Attn: Mr. Richard Marshall
or
Fax No.: 512-576-6099
If to Beta: Beta Oil & Gas, Inc.
901 Dove Street, Suite 230
Newport Beach, California 92660
Attn: Mr. Steve Antry
or
Fax No.: 714-752-5757
If to Pease: Pease Oil & Gas Company
751 Horizon Court
Grand Junction, CO 81506-8758
Attn: Mr. Willard Pease, Jr.
or
Fax No.: 970-243-8840
If to TAC: TAC Resources, Inc.
P.O. Box 206
Victoria, Texas 77902
Attn: Mr. Bill Bishop
or
Fax No.: 512-573-9840
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If to Allegro: Allegro Investments, Inc.
1908 N. Laurent, Suite 370
Victoria, Texas 77901
Attn: Mr. Chris Thompson
or
Fax No.: 512-576-9643
If to Meyer: Meyer Financial Services, Inc.
5645 Harris Hill Road
Williamsville, NY 14221
Attn: Mr. Jeffrey Meyer
or
Fax No.: 716-741-1075
If to Four-Way: Four-Way Texas, L.L.C.
c/o Kissing Bridge Company
11296 State Road
Glenwood, NY 14069
Attn: Mr. Bob James
or
Fax No.: 716-592-4228
10.6 Transfers Subject to this Agreement. Any sale, agreement, transfer
or other disposition of an interest in the Contract Lands however accomplished,
either voluntarily or involuntarily, by operation of law or otherwise, shall be
subject to the terms of this Agreement. Any instruments which convey any
interest in the Contract Lands shall be made expressly subject to this
Agreement.
10.7 Singular and Plural. When the context requires, the use of a
singular noun or pronoun shall be deemed plural and vice versa.
10.8 Further Assurances. Each of the Parties agrees to perform such
other acts and execute and deliver such other instruments as may be necessary in
order to effectuate the terms of this Agreement.
10.9 Relationship of the Parties. The Parties do not intend to create a
partnership by entering into this Agreement. The Parties agree that for the
purposes of federal income taxation, they are not to be taxed as a partnership
and each Party will elect to be excluded from the application of all of the
provisions of Subchapter "K", Chapter 1, Subtitle "A", of the Internal Revenue
Code of 1986, as amended ("Code"), as permitted and authorized by Section 761 of
the Code and the regulations promulgated thereunder. The liability of the
Parties hereunder shall be several, not joint or collective.
10.10 Memorandum of Operating Agreement. The Parties agree to execute
and record in the Records of Jackson County, Texas, a Memorandum of this
Exploration Agreement, in the form attached as Exhibit "E" hereto.
IN WITNESS WHEREOF, the Parties have executed this Agreement in
multiple counterparts as of the date first above written.
PARALLEL PETROLEUM CORPORATION
By:
Printed Name:
Title:
-9-
<PAGE>
SUE-ANN PRODUCTION COMPANY
By:
Printed Name:
Title:
TAC RESOURCES, INC.
By:
Printed Name:
Title:
ALLEGRO INVESTMENTS, INC.
By:
Printed Name:
Title:
BETA OIL & GAS, INC.
By:
Printed Name:
Title:
PEASE OIL & GAS COMPANY
By:
Printed Name:
Title:
MEYER FINANCIAL SERVICES, INC.
By:
Printed Name:
Title:
FOUR-WAY TEXAS, L.L.C.
By:
Printed Name:
Title:
-10-
<PAGE>
STATE OF TEXAS )
)
COUNTY OF MIDLAND )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of Parallel Petroleum Corporation, a Texas corporation,
on behalf of said corporation.
Notary Public, State of Texas
STATE OF TEXAS )
)
COUNTY OF )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of Sue-Ann Production Company, a ________________
corporation, on behalf of said corporation.
Notary Public, State of Texas
STATE OF TEXAS )
)
COUNTY OF )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of TAC Resources, Inc., a _______________ corporation,
on behalf of said corporation.
Notary Public, State of Texas
STATE OF )
)
COUNTY OF )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of Allegro Investments, Inc., a _______________
corporation, on behalf of said corporation.
Notary Public, State of
-11-
<PAGE>
STATE OF )
)
COUNTY OF )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of Beta Oil & Gas, Inc., a _______________ corporation,
on behalf of said corporation.
Notary Public, State of
STATE OF )
)
COUNTY OF )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of Pease Oil & Gas Company, a _________________
corporation, on behalf of said corporation.
Notary Public, State of
STATE OF )
)
COUNTY OF )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of Meyer Financial Services, Inc., a _______________
corporation, on behalf of said corporation.
Notary Public, State of
STATE OF )
)
COUNTY OF )
This instrument was acknowledged before me this _______ day of
_______________, 1997, by ___________________________________________________,
_______________________ of Four-Way Texas, L.L.C., a _______________ limited
liability company, on behalf of said limited liability company.
Notary Public, State of
-12-
<PAGE>
EXHIBIT "A"
(Contract Lands)
<PAGE>
EXHIBIT "B"
<TABLE>
Gross
Lessor Date Acres Net Acres Vol./Page
- ------ ---- ----- --------- ---------
<S> <C> <C> <C> <C> <C>
*Florence Groberg, et al ......03/01/33 354 354 86/286
**Maggie Branch, et vir ......12/03/34 1804.83 1804.83 92/623
*Otto Hultquist ...............08/04/34 167.5 167.5 90/597
*T.N. Mauritz, et al ("A") ....07/10/35 209.5 209.5 94/436
*T.N. Mauritz, et al ("B") ....12/26/32 110.5 110.5 84/81
*Martin Hultquist, et ux ......07/10/35 200 200 94/429
*Hanna Ross et al .............07/22/35 143 143 96/246
*A.T. Ross, et ux .............12/16/34 100 100 92/224
*Florence V. Tunison, et al ...08/14/34 909 909 91/540
*Mortgage Land & Investment ...07/10/35 321.25 321.25 94/440
Co ..................................
*Lillian A. Silliman, et vir ..12/10/32 241.25 241.25 83/602
*F. Wayne Silliman, et ux .....09/13/49 121.25 121.25 189/73
*T.C. Robertson, et al ........12/11/34 200 200 92/218
*Bohus Simicek, et ux .........09/23/40 165 165 No Recording
*A.J. Dahlstrom, et ux ........08/01/47 16 16 171/25
*C.A. Barron, et ux ...........07/22/54 100 100 244/378
***W.W. McCrory, et ux ........02/06/34 184.5 184.5 71/463
------ ------
5347.58 5347.58
</TABLE>
* From the surface down to 8,000 feet.
** From the surface down to 6,620 feet.
*** From the surface down to 7,600 feet (as to 102.5 acres) is
subject to farmout agreement with Ka-Hugh International.
<PAGE>
RETIREMENT, SEVERANCE AND TERMINATION
OF EMPLOYMENT AGREEMENT
THIS RETIREMENT, SEVERANCE AND TERMINATION OF EMPLOYMENT AGREEMENT is
between Pease Oil and Gas Company, a Nevada corporation ("Company") and J. N.
"Newt" Burkhalter ("Employee"), shall be effective January 1, 1998 and is made
with reference to the following agreed facts.
A. Employee has been employed as a full time executive officer of the
Company pursuant to an Employment Agreement dated as of December 27, 1994 (the
"Employment Agreement").
B. Pursuant to a change in the business of the Company and the fact
Employee has reached the age of 62, the, Employee shall retire and not be
employed by the Company after December 31, 1997.
C. The parties desire and intend to set forth the terms upon which the
Employment Agreement shall be terminated.
FOR CONSIDERATION, the receipt and sufficiency of which is hereby
acknowledge, the Company and Employee agree as follows:
1. Retirement and Cessation of Employment. The Employee shall continue
to be employed as a full time employee and as an Executive Vice President of the
Company through December 31, 1997. Since the Employee has reached the age of 62,
on January 1, 1998, the Employee will retire from the Company and shall tender,
in writing, his resignation as an officer of the Company and its subsidiaries.
2. Severance Compensation. Commencing January 1998, the Employee, or
his assignee, will be compensated at a rate of $4,500 per month for the first
twelve (12) months and $3,785 for the next twenty (20) months, for a total of
$129,700 dollars, unless this Agreement is previously terminated due to the
death. Each monthly payment will be tendered by the Company on or about the
tenth of each month. Upon the death of the Employee, at the end of the month
next following such event, the Company shall pay to the estate of the Employee,
an amount equal to the difference between $82,500 and the gross amounts
previously paid to Employee pursuant to this paragraph 2 of this Agreement.
3. Options. The stock purchase options previously granted and currently
held by the Employee, as identified on Exhibit A, shall each retain the original
terms in accordance with applicable provisions of the Company's Stock Option
Plans.
4. Transfer of Assets. Effective at the time of cessation of full time
employment, the Company shall transfer to the Employee the Company assets
described on Exhibit B. Employee acknowledges that the Company shall treat the
estimated fair market value of the assets as 1997 income to Employee and shall
so notify taxing authorities.
5. Special Training. At a time selected by the Employee, but not later
than July 1, 1998, the Company shall pay up to $2,500 in tuition and expenses
necessary for Employee to attend the M.M.S.' basic course on oil and gas well
completion and workover or similar course.
1
<PAGE>
6. Use of Office Space. The Company shall make reasonable efforts to
provide Employee office space at the offices of the Company for so long as the
Company has extra space not being used for other Company business purposes. The
space provided may or may not consist of the space that Employee is currently
occupying and the Company is under no obligation to provide office space should
its business requirements change. Employee may use such offices for conducting
Company business or other unrelated business and shall at all times conduct
himself in a manner consistent with the best interests of the Company and the
other employees. The Employee shall install and pay for his own phone line and
reimburse the Company for ancillary uses of existing office equipment owned by
the Company (e.g., copier, phone, facsimile, etc.).
7. Future Consulting Services. During the term of this Agreement, the
Employee agrees to be available, on a reasonable and mutually agreeable basis,
to perform consulting services on an as needed basis for the Company or
affiliates of the Company. It is specifically agreed that there is no obligation
in this Agreement for the Company to retain the Employee on a consulting basis
and any such consulting services shall be performed in accordance with one or
more separate consulting agreements which may be entered into from time to time
in the future.
8. Service as a Director. The parties acknowledge that until November
7, 1997, Employee served as a director of the Company and its subsidiaries, and
that Employee resigned as a director, on his own volition, effective that date.
By signing this Agreement, the Company and the Employee confirm that the
resignation by the Employee was not a condition of, nor conditional upon, this
Agreement.
9. Termination of Prior Employment Agreement. The rights and
obligations of the parties as set forth in the Employment Agreement hereby are
terminated and shall be of no further effect and, other than as set forth in
this Agreement, the Company shall have no other obligations whatsoever to the
Employee. Employee hereby waives and releases any obligation by the Company
under the Employment Agreement and any other claims which Employee might
otherwise assert against the Company or its officers or directors except as set
forth in this Agreement.
10. General Release. Employee, on his own behalf, and on behalf of his
heirs and assigns, hereby fully and forever unconditionally releases and
discharges the Company, all of its past and present parent, subsidiary,
affiliated and related corporations, their predecessors, successors and assigns,
together with their divisions and departments, and all past or present officers,
directors, employees, insurers and agents of any of them, (hereinafter referred
to collectively as "Releasees"), of and from, and covenants not to sue or assert
against Releasees, for any purpose, all claims, administrative complaints,
demands, actions and causes of action, of every kind and nature whatsoever,
whether at law or in equity, arising from or in any way related to my employment
by the Company including the termination thereof, based in whole or in part upon
any act or omission concerning on or before the date of this general release,
whether negligent or intentional, without regard to Employee's present actual
knowledge of the act or omission, which Employee may now have, or which
Employee, or any person acting on his behalf may at any future time have or
claim to have, including specifically, but not by way of limitation, unpaid
wages, unpaid benefits, matters which may arise at common law, such as breach of
contract, express or implied, promissory estoppel, wrongful discharge, tortious
interference with contractual rights, infliction of emotional distress,
defamation, or under federal, state or local laws, such as the Fair Labor
Standards Act, the Employee Retirement Income Security Act, the National Labor
Relations Act, Title VII of the Civil Rights Act of 1964, the Age Discrimination
in Employment Act, the Rehabilitation Act of 1973, the Americans with
Disabilities Act, the Family and Medical Leave Act, the Pregnancy Disability
2
<PAGE>
Act, the Equal Pay Act, and the Colorado Civil Rights Act, excepting only
retirement benefits described herein, COBRA rights, unemployment compensation
and worker's compensation. Employee warrants that he has not assigned or
transferred any right or claim described in this general release. Employee
expressly assumes all risk that the facts and law concerning this general
release may be other than as presently known to Employee, and acknowledges that,
in signing this general release, Employee is not relying on any information
provided by Releasees or upon Releasees to provide information not known to
Employee. Employee acknowledges that he has been advised to consult an attorney
regarding this release. This release shall be governed by and construed in
accordance with the laws of Colorado. In the event of any dispute under this
release, the prevailing party shall be entitled to recover all costs and
reasonable attorneys' fees incurred in connection therewith.
11. Binding Arbitration. Any controversy arising out of or relating to
this Agreement or any modification or extension of this Agreement, including any
claim for damages and/or rescission, shall be settled by binding arbitration in
Grand Junction, Colorado in accordance with the Commercial Arbitration rules of
the American Arbitration Association before a panel of one arbitrator. If the
parties to this agreement cannot agree on the choice of a single arbitrator,
then the panel shall consist of three arbitrators, one to be selected by the
Company, one to be selected by the Employee, and the third to be selected by the
other two arbitrators. The arbitrator(s) sitting in any such controversy shall
have no power to alter or modify any express provisions of the Agreement or to
render any award which by its terms effects any such alteration, or
modification. This section shall survive the termination of the Agreement.
12. Entire Agreement. This Agreement is the entire agreement between
the parties and supersedes all prior understandings or agreements with respect
to the matters referred to herein. This Agreement may not be altered or amended
except by a written agreement signed by the parties.
WHEREFORE, the parties have signed this Agreement on December 31, 1997,
to become effective January 1, 1998.
PEASE OIL AND GAS COMPANY
By __________________________________
Willard H. Pease, Jr., President
EMPLOYEE:
- -----------------------------------------
J. N. "Newt" Burkhalter
WITNESSED:
By ______________________________________
Patrick J. Duncan, Corporate Secretary
3
<PAGE>
EXHIBIT A
Option
Options Exercise Expiration
Outstanding Price Grant Date of Option
- ----------- ------- ------------ ----------
48,000 0.83 May 16, 1995 May 15, 2000
40,000 0.70 June 16, 1995 June 25, 2000
27,000 1.00 March 9, 1996 March 8, 2001
35,000 2.97 January 27, 1997 January 26, 2002
-------
150,000
4
<PAGE>
EXHIBIT B
Asset
Description Quantity Number Agreed
- ----------- -------- ------ ------
Compaq 486/33 Computer 1 10009 $ 400
Compaq SVGA Monitor 1 10047 150
Epson LQ-1070+Dot Matrix Printer 1 10062 100
1991 Ford F150 4WD SuperCab XLT lariat P/U
VIN #1FTEX14H9MKA46203 13001 3,500
Butcher Block Desk 1 20006 500
Butcher Block Credenza 1 20007 250
2 Drawer Wood File Cabinet 1 20014 100
2 Drawer Wood File Cabinet 1 20015 100
2 Drawer Wood File Cabinet 1 20016 100
2 Drawer Metal File Cabinet 1 20019 50
Butcher Block Credenza 1 20020 100
3 Drawer Lateral Wooden File Cabinet 1 20183 100
Office Chairs w/Purple Upholstery 2 NA 100
Reclining Office Chair 1 NA 100
Butcher Block Book Case 2 NA 100
Walnut Colored Wooden Book Case 1 NA 100
-----------
$ 5,850
5
March 18, 1998
Pease Oil and Gas Company
751 Horizon Court, Suite 203
Grand Junction, CO 81506
We are providing this letter to you for inclusion as an exhibit to your
Form-10KSB filing pursuant to Item 602 of Regulation S-B.
We have read management's justification for the change in accounting from the
successful efforts method to the full cost method contained the Company's Form
10-KSB for the year ended December 31, 1997. Based on our reading of the data
and discussions with Company officials about the business judgment and business
planning factors relating to the change, we believe management's justification
to be reasonable. Accordingly, in reliance on management's determination as
regards elements of business judgment and business planning, we concur that the
newly adopted accounting principle described above is preferable in the
Company's circumstances to the method previously applied.
/s/ Hein + Associates LLP
HEIN + ASSOCIATES LLP
CONSENT OF McCARTNEY ENGINEERING, LLC
As oil and gas consultants, McCartney Engineering, LLC hereby consent to: (a)
the use of our reserve report dated February 20, 1998 entitled "Pease Oil and
Gas Company's Estimated Remaining Reserves and Future Net Revenue Pursuant to
SEC Guidelines as of December 31, 1997"; and (b) all references to our firm
included in or made a part of Pease Oil and Gas Company's Annual Report on Form
10-KSB to be filed with the Securities and Exchange Commission on or about March
31, 1998.
McCARTNEY ENGINEERING, LLC
/s/ Jack McCartney
President
Original on Netherland, Sewell & Associates, Inc. Letterhead
CONSENT OF NETHERLAND SEWELL AND ASSOCIATES, INC.
As oil and gas consultants, Netherland Sewell and Associates, Inc. hereby
consent to: (a) the use of our reserve report dated March 5, 1998 entitled
"Estimate of Reserves and Future Revenue to the Pease Oil and Gas Company
Interest in Certain Oil and Gas Properties as of January 1, 1998"; and (b) all
references to our firm included in or made a part of Pease Oil and Gas Company's
Annual Report on Form 10-KSB to be filed with the Securities and Exchange
Commission on or about March 31, 1998.
NETHERLAND SEWELL AND ASSOCIATES, INC.
/s/ Danny D. Simmons
Senior Vice President
Houston, Texas
March 27, 1998
INDEPENDENT CERTIFIED PUBLIC ACCOUNTANT'S CONSENT
We consent to the incorporation by reference in the Registration Statement of
Pease Oil and Gas Company on Form S-3 (SEC File No. 333-31921 with an effective
date of August 22, 1997) of our report dated March 18, 1998 on our audits of
the consolidated financial statements of Pease Oil and Gas Company as of
December 31, 1997, and for the years ended December 31, 1997 and 1996, which
report is included in this Annual Report of Pease Oil and Gas Company on Form
10-KSB.
/s/ HEIN + ASSOCIATES LLP
Denver, Colorado
March 30, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 6,547,804
<SECURITIES> 0
<RECEIVABLES> 781,829
<ALLOWANCES> 24,395
<INVENTORY> 0
<CURRENT-ASSETS> 7,349,217
<PP&E> 17,995,849
<DEPRECIATION> 4,965,232
<TOTAL-ASSETS> 21,294,143
<CURRENT-LIABILITIES> 2,053,743
<BONDS> 2,922,703
0
1,133
<COMMON> 1,578,996
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 21,294,143
<SALES> 4,566,930
<TOTAL-REVENUES> 4,659,309
<CGS> 2,527,048
<TOTAL-COSTS> 20,033,543
<OTHER-EXPENSES> 230
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 701,377
<INCOME-PRETAX> (15,895,067)
<INCOME-TAX> 0
<INCOME-CONTINUING> (15,895,067)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (15,985,036)
<EPS-PRIMARY> (1.22)
<EPS-DILUTED> (1.22)
</TABLE>
