SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
or
[ ]TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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)
Title of Class
Check whether the issuer (1) filed all reports required to be
filed by Section 13 or 15(d) of the Exchange Act during the past
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 [ ]
Check if disclosure of delinquent filers in response to Item 405
of Regulation S-B, is not contained in this form and no
disclosure will be continued, to the best of registrant's
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any
amendment to the Form 10-KSB. [ ]
The issuer's revenues for its most recent fiscal year were
$9,040,260.
As of March 25, 1996, Registrant had 7,218,854 shares of its
$0.10 par value Common Stock and 202,688 shares of its $0.01 par
value Series A Cumulative Convertible Preferred Stock
outstanding. As of March 25, 1996 the aggregate market value of
the common stock held by non-affiliates was $8,899,166. This
calculation is based upon the closing sales price of $1.3437 per
share on March 25, 1996.
TABLE OF CONTENTS AND CROSS REFERENCE SHEET
PART I
Item 1 Description of Business
Item 2 Description of Property
Item 3 Legal Proceedings
Item 4 Submission of Matters to a Vote of Security
Holders
PART II
Item 5 Market for Common Equity and Related
Stockholder Matters
Item 6 Management's Discussion and Analysis
Item 7 Financial Statements
Item 8 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure
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.
Item 13 Exhibits and Reports on Form 8-K
PART I
ITEM 1 - BUSINESS
GENERAL
Pease Oil and Gas Company ("Company"), was incorporated
under the laws of the state of Nevada on September 11, 1968.
The Company's address is 751 Horizon Court, Suite 203, Grand
Junction, Colorado 81506 and its telephone number is (970)
245-5917. The Company is engaged in the oil and gas
acquisition, exploration, development and production
business in the western United States, primarily in
Colorado, Nebraska, Utah, and Wyoming. During 1993, the
Company substantially expanded its operations into providing
oil field services, oil field supplies, natural gas
processing and natural gas marketing. This expansion was
accomplished through an acquisition of an independently
owned oil and gas Company and is discussed more thoroughly
in the following paragraphs.
ACQUISITIONS IN 1993
Skaer Enterprises, Inc.
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.
Skaer was acquired for $12,200,000, including various costs
associated with the acquisition of $300,000. This
acquisition was financed through: i) the issuance of 900,000
shares of preferred stock in a public offering which
generated net proceeds of $7,965,000; ii) the issuance of
restricted common and preferred stock to the sellers with an
agreed value of $1,900,000; and iii) a $2,400,000 loan from
a bank.
Skaer conducted its operations directly and through a
wholly-owned subsidiary corporation, an affiliated
corporation, a limited partnership, and through assets owned
by Skaer affiliates.
The acquisition of Skaer dramatically changed the complexion
of the Company for Skaer was a very diversified independent
oil and gas company. In conducting its business, Skaer
acquired oil and gas prospects and leases, drilled for oil
and gas, performed oil and gas well completion and operation
services, transported natural gas through a gathering system
and pipeline, processed and sold natural gas at a gas
processing plant and traded natural gas. Skaer also sold
oil and gas equipment and supplies and repaired equipment
through two retail stores, and provided its well completion
and support services to others. Skaer also had historically
retained a large majority working and net revenue interest
in most of its oil and gas drilling prospects.
Skaer had been a private family owned and operated business
for more than 20 years, had executive offices in Denver,
Colorado, a gas processing plant near Loveland, Colorado,
and oil field servicing and supply businesses located in
both Loveland and Sterling, Colorado. Skaer's producing oil
and gas properties and reserves were in 43 fields including
Loveland Field with 80 wells. Loveland Field alone
represented 64% of Skaer's reserves. The gas gathering and
pipeline system transported natural gas from two fields
within four miles of the Loveland Gas processing plant.
The businesses and assets acquired from Skaer consisted of
the following:
Skaer Enterprises Inc. ("SEI"). SEI was a Colorado
corporation engaged in oil and gas exploration, production,
operations, marketing, and oil and gas field servicing in
the DJ Basin where Skaer owned oil and gas interests.
Loveland Gas Processing Co. ("LGPCo"). LGPCo, a Colorado
limited partnership, was 95% owned by Skaer at the time of
the acquisition (in August 1994, a subsidiary of the Company
purchased the remaining 5% for $225,000). LGPCo owns and
operates the natural gas refrigeration and compression
facility ("Gas Plant") with a design capacity to process up
to six million cubic feet of natural gas per day. The Gas
Plant purchases, gathers, processes and sells natural gas
and natural gas liquids ("NGLs") from two fields.
ATSCO Inc. ("ATSCO"). ATSCO, a wholly-owned subsidiary of
Skaer, operated all oil and gas wells in which Skaer held an
interest and was designated as the "operator."
Well Services Division. The well services division was an
operating division of SEI and provided a wide range of oil
field services, including workover rigs, hot oil trucks,
vacuum trucks, oil field trucking and other associated
services to SEI and to third parties.
Vacuum Truck Services. Colorado Vacuum Truck Company
("CVTC"). CVTC, an affiliate corporation, provided oil
field services to SEI and to third parties. The Company
acquired all the assets and related business of CVTC,
including two vacuum trucks.
Equipment Business. A.T. Skaer Company, an affiliated
business of SEI, provided new and used oil field equipment
and supplies to SEI and to third parties through two retail
outlets. A.T. Skaer also had one magneto repair shop, a
downhole pump shop and an oil field equipment and rolling
stock repair shop.
Other Oil Properties. The Company also acquired all working
interests in SEI oil and gas wells, which were owned by
members of the SEI family prior to acquisition by the
Company.
Grand Junction Well Service
In June 1993, the Company acquired Grand Junction Well
Service ("GJWS") from the Company's President and CEO,
Willard H. Pease, Jr. The transaction was consummated by
merging GJWS into a newly-formed subsidiary corporation,
Rocky Mountain Well Services, Inc. In the merger, the
Company issued Mr. Pease 46,667 shares of its Common Stock
and a 6% secured convertible promissory note in the
principal amount of $175,000 for a total value of $350,000
(the estimated fair market value of GJWS's assets and
business.) The note was originally payable in three
principal installments of $45,000 on October 1, 1994 (which
was paid) $65,000 on April 1, 1995 and $65,000 April 1,
1996. The installments due in 1995 and 1996 were
subsequently extended to October 1, 1997 and October 1,
1998, respectively. The unpaid principal of the note is
convertible at the election of the Company's President into
Common Stock at $5.00 per share. The transaction was
approved unanimously by the disinterested directors of the
Company.
Mergers of Acquired Entities
In November 1993, the operating company acquired in the
Skaer acquisition, ATSCO, Inc., changed its name to Pease
Operating Company, Inc. All Skaer producing oil and gas
properties were merged into the Company on January 1, 1994.
Two wholly owned subsidiaries, Pease Oil Field Services,
Inc. and Pease Oil Field Supply, Inc. were formed to operate
the oil field service and supply businesses. Rocky Mountain
Well Services, Inc. was merged into Pease Oil Field
Services, Inc. on January 1, 1994. The Company continues to
operate its natural gas refrigeration processing plant
through Loveland Gas Processing Co., Ltd.
RECENT DEVELOPMENTS
The following is information pertaining to certain matters
that have occurred since the Company filed its Quarterly
Report on Form 10-QSB for the quarter ended September 30,
1995.
In March 1996, the Company entered into a consulting
agreement with Beta Capital Group, Inc. ("Beta"). Beta is
located in Newport Beach, California and specializes in
emerging companies that have both capital needs and market
support requirements. Steve Antry, Beta's President, is
from a third generation oil and gas background and was an
officer of Benton Oil and Gas between 1989 and 1992 and
marketed Swift Energy's Income Funds between 1987 and 1989.
The Company has joined forces with Beta in an effort to
raise significant debt or equity capital in the very near
future and launch a horizontal drilling and development
program in Loveland Field, Colorado, and to possibly
participate with other industry participants in select
drilling ventures in Louisiana, the Gulf of Mexico or
elsewhere in the continental United States. Management
firmly believes that this union with Beta will put the
Company well on its way to realizing its goal of growth and
expansion.
FUTURE BUSINESS STRATEGY
The Company's business strategy is to expand its reserve
base and cash flow primarily through:
> Raising significant capital to take advantage of
leading edge technologies such as horizontal drilling
and 3-D seismic exploration projects;
> Positioning itself with strategic sources of capital
and partners that can react to opportunities in the oil
and gas business when they present themselves;
> Developing alliances with major oil and gas finders
that have been trained by the major oil companies;
> Participating in projects that have opportunities
involving relatively small amounts of capital that
could potentially generated significant rates of
return. These projects include areas with large field
potentials in the Rocky Mountains, Transition Zone
Louisiana, and the Gulf of Mexico;
> Implementing the Company's investment strategy to
carefully consider, analyze, and exploit the potential
value of the Company's existing assets to increase the
rate of return to its shareholders;
> Reinvesting operating cash flows into development
drilling and recompletion activities;
> Expanding the Company's operations outside the D-J
Basin;
> Continuing the implementation of asset rationalization
and operating efficiencies designed to improve
operating margins and lower per unit operating cost;
> Acquiring properties that build upon and enhance the
Company's existing asset base;
> Developing a long term track record regarding stock
price performance and a reasonable rate of return to
the shareholder.
The Company recognizes that the ability to implement its
business strategies is largely dependent on the ability to
increase its operating cash flows by raising additional debt
or equity capital to fund future drilling and development
activities. Since the acquisition of Skaer in 1993, the
Company has suffered from undercapitalization, lacking the
necessary working capital to properly exploit the assets
acquired from Skaer or explore other opportunities.
Management believes it will be necessary to raise additional
equity or debt capital to overcome the Company's
undercapitalization. Management further believes that the
union with Beta will provide the vehicle necessary to
overcome this obstacle. For instance, it is anticipated the
Company, with Beta's assistance, will be raising capital in
the second quarter of 1996. The proceeds from these
efforts, if successful, will be used for working capital,
horizontal drilling in Loveland Field, Colorado, and
possibly to participate with other industry participants in
drilling ventures in Louisiana, the Gulf of Mexico or
elsewhere in the continental United States.
The Company's Liquidity and Capital resources are discussed
more thoroughly in Part II, Item 6, in Management's
Discussion and Analysis.
OPERATIONS
The Company is primarily engaged in oil and gas property
acquisition, exploration, development and production
activities. Through the 1993 acquisitions, the Company
expanded its operations to include oil field servicing,
sales of new and used oil field equipment, and natural gas
processing and marketing. The Company's principal
activities are conducted in the Rocky Mountain region of
the United States, principally in Colorado and Utah.
As of December 31, 1995, the Company had varying ownership
interests in 238 gross productive wells (191 net) located in
five states. The Company operates 228 of the 238 wells,
with the other wells are being operated by independent
operators under contracts that are standard in the industry.
The following table presents information on the Company's
major operating areas as of December 31, 1995:
Net Proved Reserves
------------------
STATE REGION Bbls Mcf
- ----- ------ ------ -----
CO, WY, NE DJ Basin 1,079,000 4,876,000
Utah Greater Cisco
and Four Corners 177,000 857,000
Wyoming Big Horn Basin 34,000 -
CO & AR Various 4,000 118,000
--------- ---------
Total 1,294,000 5,851,000
========= =========
It is the primary objective of the Company to operate most
of the oil and gas properties 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.
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 $20,653 per year through June 30, 1997.
Employees - As of March 25, 1996, the Company had 35 full
time employees, none of whom is covered by a collective
bargaining agreement. The Company considers its relations
with its employees satisfactory.
COMPETITION
The oil and gas industry is highly competitive in all
phases. The Company encounters strong competition from
other independent oil and gas companies in acquiring
economically desirable prospects as well as in marketing
production therefrom and obtaining external financing. Many
of the Company's competitors may have financial resources,
personnel, and facilities substantially greater than those
of the Company.
Because there has been a decrease in exploration for and
development of oil and gas properties, there is increased
competition for lower risk development opportunities and for
available sources of financing. In addition, the marketing
and sale of natural gas and processed gas are competitive.
Accordingly, the competitive environment in which the
Company operates is unsettled.
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.
Total revenues generated from the sales of crude oil,
natural gas, natural gas marketing, and NGL's which are
produced and/or marketed by the Company constituted 23%,
10%, 43%, and 9% of the Company's total revenues for the
year ended December 31, 1995.
Crude Oil - Oil produced from the Company's properties is
generally sold by truck to unaffiliated third-party
purchasers at the prevailing field price ("the posted
price"). Currently, the three primary purchasers of the
Company's crude oil are Total Petroleum, Inc., Texaco
Trading and Transportation, Inc. and Scurlock-Permian
Corporation. Together these three purchasers buy more than
80% of the Company's annual crude oil sales. The market for
the Company's crude oil is competitive, which has resulted
in bonuses above posted price. In 1994 the Company
negotiated an increase in the bonus paid for its crude oil
from $0.35 to $0.65 per barrel above the posted price. The
contracts are month-to-month and subject to change. 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: at the wellhead to various pipeline
purchasers or natural gas marketing companies; and at the
tailgate of its Gas Plant to Public Service Company of
Colorado ("PSCo"). 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 is subject to a contract that expires on June 30,
1996. The gas is priced on an MMBtu basis above the
Colorado Interstate Gas Company's northern pipeline index
spot price.
Natural Gas Marketing - The Company has a "take-or-pay"
contract with Public Service Company of Colorado ("PSCo")
which calls for PSCo to purchase from the Company a minimum
of 2.92 billion cubic feet of natural gas annually. The
Company's current annual production is significantly below
this minimum level of take by PSCo. Accordingly, the
Company will purchase the excess gas available for the
contract from other third party producers and sell it to
PSCo under the terms of the contract. The contract with
PSCo expires in June 1996.
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 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 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 in the DJ Basin. 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. Order No. 636 and related FERC orders
are subject to pending court appeal, and additional
challenges may arise as a result of individual pipeline
implementation of Order No. 636. The outcome of these
appeals and their impact on the Company cannot be predicted.
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 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. A few states also
prorate production to the market demand for oil and gas.
For instance, in 1991, the State of Oklahoma enacted
legislation restricting the output of certain high-volume
gas wells in response to prevailing low gas prices and the
States of Texas and Louisiana have considered similar
regulatory initiatives. To the Company's knowledge, none of
the states in which the Company currently operates, nor any
of the other states in the Rocky Mountain region, are
currently considering such limitations. Nevertheless, any
limitation substantially similar to that enacted by Oklahoma
would not have a material impact on the Company's level of
production, whether for oil or gas, since the Company's
wells do not produce at a level high enough to meet the
threshold for restriction contained in the legislation.
However, if similar legislation with lower thresholds were
to be enacted in the states in which the Company operates,
it could affect the Company's ability to market its
production. Some states have enacted statutes prescribing
ceiling prices for gas sold within the state. If such
statutes and regulations were enacted in Colorado, Wyoming,
Nebraska or Utah, they could limit the rate at which oil and
gas could otherwise be produced or the prices obtained from
the Company's properties.
During the 1993 session of the Colorado legislature, a
coalition of surface owner organizations attempted to
persuade the legislators to enact a bill requiring the
payment of damages to surface owners. Such legislation
could increase the cost of the Company's operations and
erode the traditional rights of the oil and gas industry in
Colorado to make reasonable use of the surface to conduct
drilling and development activities. Although the bill was
withdrawn by the surface owners after it was significantly
amended, and no such legislation has been presented since
1993 (to the Company's knowledge), surface owner groups have
indicated they may seek a statewide constitutional ballot
initiative to mandate compensation to surface owners and
will attempt to increase regulation of the oil and gas
industry at the local government level. The involvement of
such local governments could not prohibit the conduct of
drilling activities within their boundaries which were the
subject of permits issued by the Colorado Oil and Gas
Conservation Commission ("COGCC") but that they could
regulate such activities under their land use authority.
Accordingly, under these decisions, local municipalities and
counties may take the position that they have the authority
to impose restrictions or conditions on the conduct of such
operations which could materially increase the cost of such
operations or even render them entirely uneconomic. In 1993
and 1991 the Cities of Thornton, Broomfield, and Greeley,
the Town of Frederick and Boulder County, enacted such
ordinances. The Company does not have any properties within
these boundaries. However, Weld County, the location of a
small portion of the Company's properties, is currently
considering such an ordinance and has circulated drafts for
industry and public review. The Company is not able to
predict which jurisdictions may adopt such regulations, what
form they will take or the ultimate effects of such
enactments on its operations. However, in general these
ordinances are 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, the ordinances have the
potential to delay and increase the cost, or even in some
cases to prohibit entirely, the conduct of the Company's
drilling activities.
In response to the concerns of surface owner groups, the
COGCC has adopted regulations for the D-J Basin governing
notices to and consultation with surface owners prior to the
conduct of drilling operations, imposing specific
reclamation requirements on operators upon the conclusion of
operations, and containing bonding provisions to enforce
these new requirements. The COGCC in 1994 modified its
rules to require the mandatory installation of surface
casing to depths below known fresh water aquifers in the D-J
Basin and is continuing to consider additional measures for
protection of surface owners, enhanced financial assurance
requirements, and modifications to its rules concerning
safety and plugging and abandonment. The rules adopted or
modified by the COGCC to date have not had a material impact
on the Company but it is not possible to predict what
additional changes will be made or what their financial or
operational impact will be on the Company.
Under the sponsorship of the Colorado Department of Natural
Resources, legislation was approved in the 1994 session of
the Colorado legislature to enhance the authority of the
COGCC to regulate oil and gas operations. Representatives
of the oil and gas industry were involved in the drafting of
this legislation, along with representatives of the
agricultural industry, local governments and environmental
groups, and are working closely with the COGCC on the
consideration and drafting of new rules to address the
concerns that have been raised about the effects of oil and
gas operations. Although the Company believes that it
generally conducts its operation in accordance with the
procedures contemplated in the pending regulatory
initiatives, management is not able to predict the final
form of the initiatives or their impact on the Company.
Recently, Wyoming increased its bonding and financial
requirements for operators acquiring existing properties.
These new requirements are not expected to have a
significant impact on the Company or its operations.
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 formulation
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.
Wyoming has recently established more stringent
environmental regulations to ensure compliance with federal
regulations. These new regulations are not expected to have
a significant impact on the Company or its operations.
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.
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.
ITEM 2 - PROPERTIES
PRINCIPAL OIL AND GAS INTERESTS
<TABLE>
Developed Acreage - The Company currently owns producing oil and gas wells in Arkansas,
Colorado, Utah, Nebraska, and Wyoming. The Company's producing properties as of December
31, 1995 are located in the following areas shown in the table below:
<CAPTION>
OIL GAS Developed Acreage
--------------- ------------- -----------------
<S> <C> <S> <C> <S>
Fields State Gross Net(2) Gross Net(2) Gross Net(2)
Wells(1) Wells Wells(1) Wells Acreage Acreage
Loveland Unit Colorado 74 71 3,563 3,488
Loveland Field Colorado 14 13 1,520 1,520
Pod Field Colorado 5 4 600 600
Yenter Field Colorado 5 5 1,655 1,655
Johnson's Corner Colorado 5 4 1,122 1,122
Twin Mills Field Colorado 1 1 160 80
Rago North Field Colorado 8 1 640 93
Peetz West Field Colorado 5 4 785 785
Weasel Field Colorado 1 - 320 290
Xenia North Field Colorado 1 1 120 83
Little Beaver Unit Colorado 24 19 1 1 3,080 3,003
Other Fields CO/NB/WY 28 18 3 2 6,842 5,376
Cowboy Utah 4 4 1 1 1,200 1,199
Calf Canyon Unit Utah 11 7 640 421
Westwater Utah 1 1 360 220
Enos Creek Wyoming 4 3 280 215
Arkansas Arkansas 2 1 40 10
Cisco Dome Utah 1 1 38 30 8,877 8,267
Willow Creek Wyoming 1 1 2,820 1,378
---- ------ ---- ---- ----- -----
Totals 194 158 (3) 44 33(3) 34,624 29,805
==== ====== ==== ==== ====== ======
<FN>
<F1>
(1) Wells which produce both gas and oil in commercial quantities are classified as "oil"
wells for disclosure purposes.
<F2>
(2) "Net" wells and "net" acres refer to the Company's fractional working interests
multiplied by the number of wells or number of acres.
<F3>
(3) Total may not foot due to rounding.
</FN>
The majority 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 as of December 31,
1995 is 1,002 and 817 acres, respectively. All these
properties are located in Colorado and will expire at
various times through 1997 unless production has been
obtained.
COLORADO PROPERTIES
The Denver-Julesburg ("DJ") Basin 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. The Company's activities have focused on the
historically better producing zones, the "D" and the "J"
sandstones and the Niobrara formation. Ninety percent of
the Company's reserves are now in the DJ Basin. A summary
of the fields in the DJ Basin are as follows with emphasis
on the Loveland Field:
Loveland Field, Larimer and Weld Counties - Loveland Field
is located near the City of Loveland, Colorado, 40 miles
north of Denver. It contains the Company's most important
properties, producing both oil and gas at an average rate of
approximately 326 barrels of oil equivalent ("BOE") per day
(266 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 2 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 assets.
The Company, with 90 producing wells, now owns and operates
nearly all of the active Loveland Field wells. A majority of
the wells in the main part of the field have been unitized
by the Company as Loveland Field Unit. This was done to
facilitate the drilling of infill wells without the
restrictions of setbacks from lease or section lines imposed
by state regulations and to consolidate operating
facilities. The unitization also simplifies field operations
and enhances the ability to drill extended length horizontal
wells.
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. There is also an interconnect into the Wattenberg
pipeline system of K N Energy, which gives the gas plant
access to third-party gas from the extensive Wattenberg
field complex. Approximately 1,000 Mcf of gas per day from
the Loveland and Johnson's Corner fields is currently
processed through the Loveland gas plant. Third party gas
has been processed at the plant in the recent past, but is
not currently under contract. 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.
Loveland structure is a simple asymmetric anticlinal feature
with multiple pay zones. The field primarily produces from
the Niobrara, Timpas, Codell, and Lakota formations with
minor production from Muddy "J", Fuson, Lyons and shallow
Hygiene sandstones.
The Niobrara Formation is about 300 ft. thick and is
laterally uniform across the field. It is by far the most
important pay zone in the field. The formation can be
divided into three zones based on the occurrence of high
resistivity chalks, informally called upper, middle and
lower benches. Generally, the limestone benches in the
Niobrara are naturally fractured and range from 20 to 50
feet thick. The formation is tight. Economic production rate
is sustained with the presence of natural fractures or by
effective artificial hydraulic fracturing operations.
Timpas Limestone is 18-22 ft in thickness. The rock itself
is tight. The production depends upon the presence of
fractures. Many of the early wells drilled in the Loveland
Field were completed in Timpas. Some had cumulative
production of 20,000 to 60,000 BO and initial production
rate of several hundred barrels a day. Most of the wells
drilled after 1968, however, were not completed in Timpas.
Codell Sandstone is a fine-grained, somewhat shaly siltstone
with a gross thickness of about 30 ft. The Codell Sandstone
in Loveland Field is perhaps among the best in the Denver-Julesburg basin in
terms of pay thickness and petrophysical properties. Codell wells have
similar predictable performances across the field.
Lakota Sandstone consists of conglomerates and fluvial
channel sandstones. With initial production in 1962, Lakota
has produced approximately 700,000 BO from six wells in the
central portion of the Loveland field. Although current
production is minimal, secondary recovery appears to be
warranted and a waterflooding plan is under consideration
with an expected recovery of 150,000 BO.
Since the acquisition from Skaer Enterprises in 1993,
Loveland Field, the Loveland Gas Plant, and the nearby
Johnson's Corner field have been, and will continue to be,
the focus of the Company's development plan. Through the
Company's geological and engineering departments as well as
by contracting outside consulting firms, the Company has
been maintaining an active geological, engineering,
operational and economic study program on a routine basis
and exploring the feasibility of using various proven new
technologies. Although the Company's development drilling
operations in Loveland Field was largely curtailed in 1995
because of insufficient capital, a number of research
projects continued, include detailed computer-aided
geological interpretation and mapping. Several important
understandings of the Loveland Field came into being as a
result of such study and exploration.
Fractures are the most important factor in the Loveland
field area and the distribution of fractures are uneven,
exhibiting strong heterogeneity. The fracture systems in the
Loveland field appear to be anastomosing micro-fracture
clusters or swarms that are limited in length and the
fractures are more abundant in the east side of the field
along a structural bend. The field has been developed
generally on 40-acre spacing following a traditional grid.
Studies of well performance and production history
demonstrate that without connected open natural fractures,
a well could only drain an area of a limited radius, perhaps
as little as 50 feet, even with a "big frac job". We are
confident that numerous isolated pockets or swarms of
fracture systems remain undrained between the 40-acre wells.
Another important understanding of Loveland Field is the
fracture orientation. In the past, the fractures in the
Loveland Field were thought to be oriented in a north-south
direction. As a result, in 1992, Skaer Enterprises drilled
the only horizontal well in Loveland field and directed the
well in a near east-west direction in order to penetrate a
maximum number of fractures. However, in 1994, the Company
drilled 4 new vertical infill wells and utilized an advanced
logging technology known as Schlumberger FMI (Formation
Micro Image). These photo-like logs revealed that the
fractures are vertical and, unlike the earlier belief, are
consistently oriented in an east-west direction. This
knowledge is extremely valuable for designing future
horizontal wells.
Loveland Field area has an excellent potential for further
low-risk development. Since the Skaer acquisition, the
Company set out to implement several development programs by
employing modern technologies, such as obtaining the FMI
logs in the new in-fill wells and use of modern large-scale
hydraulic fracturing and stimulation technologies in a 13
well Codell recompletion program in 1994. The Company is
currently actively involved in making financial and
technical arrangements and preparations to implement a
horizontal-lateral drilling program, a 3-D seismic program
and a recompletion program.
Horizontal drilling had its origin from the development of
fractured tight reservoirs, such as the Niobrara and Austin
Chalk. Thousands of horizontal wells drilled in different
parts of the world have proved that horizontal wells are an
effective tool to develop fractured reservoirs. Our study of
fractured Niobrara fields with similar geological and
reservoir characteristics, such as Silo Field, shows that,
in general, horizontal wells produce approximately three to
five times more reserves than vertical wells. Management
believes that Loveland Field has excellent conditions for a
horizontal program. The horizontal program consists of
drilling cased-hole laterals using existing vertical well
bores and drilling new horizontal wells. The advantage of
using the existing well bore over new wells is the lower
cost and possibility of multiple completions. Currently, the
Company intends to use some of the existing vertical well
bores to drill 1,000 to 3,000 feet deep cased-hole laterals.
Drilling of multiple lateral legs into same or different
target zones from a single vertical well bore is also in
design process. Prospective target zones include the upper
bench, lower bench, Timpas and Codell. Numerous locations
are available that are expected to encounter additional
fracture systems.
Concurrent to the initiation of the horizontal program, the
Company plans to conduct a 3-D seismic program. The past
practice of drilling wells following an arbitrary grid as in
Loveland Field is wasteful, inefficient, and defies the
heterogeneous nature of fractured reservoirs. The 3-D
seismic program makes it possible to delineate the
distribution and trend of fractures. With this type of
information, future horizontal drilling will be more
targeted. The 3-D seismic technology has proven to be
successful and cost effective in other DJ Niobrara fields.
Other fast developing technology that can be applied in
Loveland Field is cross-well tomography.
Among the existing wells, numerous opportunities exist to
recomplete in certain behind-pipe zones using newer
stimulation technologies. In many wells, Codell sandstone
remains behind-pipe and is available for recompletion. Among
the wells that have been completed in this zone, the
original completions were inadequate because of limited
stimulation. Timpas Limestone has only a total of 26
completions among 174 wells. Although the production appears
erratic, the highly productive nature of a few of the wells
indicates further recompletion possibility. Our recent
geological and engineering study of Timpas has identified
several wells to be prime candidates for recompletion. Work
is currently under way to test these wells and the initial
results appear promising. Depending on the final outcome of
the first few recompletions, there are as many as 20-30
wells that can likely be recompleted in this zone. Of the
three benches of the Niobrara Formation, the upper bench has
been completed in most wells whereas the middle and lower
benches are available for 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 40 BOE per day from the "J" sand. One well
has also been completed in the Codell and Niobrara
formations and production from all three zones is co-mingled. There are many
additional in-fill development locations as well as Niobrara/Codell behind
pipe reserves in four wells.
West Peetz Field, Logan County, Colorado - The Company
operates 5 wells in two leases in the West Peetz field. The
wells currently produce about 20 BOPD 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 has been recommended and is
currently under consideration.
Pod Field, Washington County, Colorado - In Pod Field, the
Company has a 100% working interest and operates five wells
which produce from the "J" sand. A geological and
engineering evaluation of the field conducted in 1995
indicates the presence of undeveloped gas reserves in the
Niobrara Formation.
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 35 barrels of oil per day ("BOPD"). Water produced
with oil from these five wells is injected back into the
reservoir to help maintain reservoir pressures for continued
production. Skaer acquired this production from Chevron USA
and increased production by resizing downhole equipment and
installing larger volume pumping units. 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.
North Minto Field, Logan County, Colorado - North Minto is a
"J" Sandstone field and was unitized for secondary recovery
in 1989. One well was producing approximately 8 BOPD during
1993. The injection well had been shut-in during October
1992. The Company completed geologic and engineering
reviews of the field after the acquisition and consequently
re-established the injection program which increased
production to 32 BOPD. In 1996, the Company will attempt to
restore two wells back into production to benefit from the
waterflood. Additional leases have been acquired as a result
of this study and two additional drill sites have reserve
potential in the North Minto Unit.
Little Beaver "D" Sandstone Unit, Washington County,
Colorado - Little Beaver "D" Sandstone Waterflood Unit has
15 wells producing approximately 77 BOE per day. The
Company conducted an in-house geologic study in early 1995
and a waterflood study using ORBIS Engineering of Denver,
Colorado. Although three to four additional "D" Sandstone
drill sites have been identified and there is reasonably
good potential for gas in the "J" sand, the studies
concluded that the field has largely been depleted. The
Company decided in early 1996 to attempt to sell this
property at an auction in April 1996.
Lower Horse Draw Field, Rio Blanco County, Colorado - The
Company has interests in two wells that produce gas from the
Mancos B fractured silty shale in the Lower Horse Draw
Field. Proved developed reserves include 162,000 Mcf of gas
net to the Company, and one potential location with 350,000
Mcf of gas in reserves.
UTAH PROPERTIES
Calf Canyon Field, Grand County, Utah - Calf Canyon Field is
located on the southeast flank of the Uinta Basin in Utah.
In December 1993, the Company formed a federal unit in the
field and commenced a waterflood for secondary recovery from
the Cretaceous Cedar Mountain Formation. Independent
reservoir engineers have estimated an additional 350,000 to
750,000 barrels of oil may be recoverable with a successful
water flood project. Because no comparable project has been
undertaken in the immediate area, these estimates are not
considered proved reserves. After injecting approximately
90,000 bbls of water to date, the wells are starting to
indicate a slight response to the project. The Company
intends to increase the water injection volume in the second
or third quarter of 1996. Cretaceous Dakota, and Jurassic
Morrison and Salt Wash sandstones are also prospective at
Calf Canyon, with both behind pipe reserves and three
undrilled development locations.
Cisco Dome Field, 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. Currently, the average aggregate production
from these properties is approximately 500 Mcf and 12 bbls
of oil per day as well as a small amount of oil. Management
of the Company has extensive knowledge and experience with
operations in and near this field. Accordingly, Management
believes that this acquisition will benefit the Company by
increasing production and reducing the cost of current
operations on a well-by-well basis when the operations are
combined with the Calf Canyon Field.
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.
WYOMING PROPERTIES
Enos Creek Field, Hot Springs County, Wyoming - Enos Creek
Field is located in the southwestern Big Horn Basin of
central Wyoming. In early 1992, the Company entered into a
farmout agreement with an industry partner to co-develop
Enos Creek Prospect. During the summer of 1992, the Company
and its partners drilled a side track well from an existing
wellbore targeted at a separate fault block in the geologic
structure. The well penetrated three oil zones while
drilling, one in the Curtis Formation and two in the
Phosphoria Formation.
Present production is approximately 5 barrels of oil per day
(3 barrels net to the Company's interest) from the
Phosphoria Formation.
Enos Creek Field has additional drilling potential for the
Pennsylvania Tensleep Formation which was not penetrated in
the 1992 drilling. The Company intends to recomplete a well
adjacent to existing well in the Tensleep Formation in the
second or third quarter of 1996. In addition, the Company
will continue to investigate the potential development of
this field by using 3-D seismic when funds are available.
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 indefeasible 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 10 of the
consolidated financial statements, titled Supplemental Oil
and Gas Disclosures. 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 is based upon an independent engineering
evaluation by McCartney Engineering, Inc. 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.
The Table below sets forth the Company's estimated
quantities of proved reserves all of which are located in
the Continental U.S., and the present value of estimated
future net revenues from these reserves on a non-escalated
basis using year-end prices ($17.66 per barrel and $1.70 per
MCF as of December 31, 1995) discounted by 10 percent per
year as of the end of each of the last three fiscal years:
</TABLE>
<TABLE>
December 31,
----------------------------------------
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Estimated Proved Oil Reserves (Bbls) 1,294,000 1,352,000 1,045,000
Estimated Proved Gas Reserves (Mcf) 5,851,000 5,724,000 5,854,000
Estimated Total Future Cash Inflows $ 32,620,000 $ 32,422,000 $ 24,836,000
Present Value of Estimated Future
Net Revenues(before the estimated
future income tax expenses) $ 10,280,000 $ 9,863,000 $ 6,636,000
</TABLE>
The table above does not include the reserve values associated with the Gas
Plant. The Gas Plant reserves are disclosed in Part II, Item 7 of footnote 10.
There has been no major discovery or other favorable or adverse event that is
believed to have caused a significant change in the estimated proved reserves
subsequent to December 31, 1995.
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:
<TABLE>
Year Ended December 31,
----------------------------------
1995 1994 1993
--------- -------- ---------
<S> <C> <C> <C> <C>
Oil (Bbls) 121,000 155,000 55,000
Gas (Mcf) 497,000 543,000 190,000
</TABLE>
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:
<TABLE>
Average Average Average
Year Ended Sales Price Sales Price Production
December 31 Oil (Bbls) Gas (Mcf) Cost Per BOE
----------- ----------- ----------- ------------
<C> <C> <C> <C>
1995 $16.77 $1.18 $7.87
1994 $15.94 $1.36 $8.90
1993 $15.00 $2.19 $8.79
The above table represents activities related only to oil
and gas production. It does not include any activity or
residual value added from the Gas Plant.
DRILLING ACTIVITY
The following table summarizes the Company's oil and gas
drilling activities, all of which were located in the
continental United States, during the last three fiscal
years:
</TABLE>
<TABLE>
Year Ended December 31,
---------------------------------------------
1995 1994 1993
------------ ------------ -------------
<S> <C> <C> <S>
Wells Drilled Gross Net Gross Net Gross Net
------------- ----- --- ----- --- ----- ----
Exploratory
Oil - - - - - -
Gas - - - - - -
Non-productive - - 1 .25 - -
----- ----- ----- ----- ----- -----
Total - - 1 .25 - -
===== ===== ===== ===== ===== =====
Development
Oil - - 4 3.92 - -
Gas - - - - - -
Non-productive - - - - - -
----- ----- ----- ----- ----- -----
Total - - 4 3.92 - -
===== ===== ===== ===== ===== =====
The Company was not participating in any drilling activity
at December 31, 1995 or at March 25,1996.
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. The
Company is not currently involved in any such incidental
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 ending December 31, 1995.
Part II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
(a) Market Information - The Company's Common Stock has
been quoted on the NASDAQ Small-cap Market, under the symbol
WPOG, since July 1980. The Company's Preferred Stock,
having the symbol WPOGP, has traded on the NASDAQ Small-cap
Market since August 1993.
Bid Quotations - The following table shows the range of high
and low bid quotations for each quarterly period since
January 1, 1994, 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.):
</TABLE>
<TABLE>
Bid Prices
------------------------------------------
Common Stock Preferred Stock
------------------------------------------
Quarter Ended High Low High Low
------------------ ------- -------- -------- -------
<C> <C> <C> <C> <C> <C> <C>
December 31, 1995 9/16 13/32 4 5/8 3 7/8
September 30, 1995 7/8 1/2 4 5/8 4 5/8
June 30, 1995 31/32 5/8 5 7/8 4 3/4
March 31, 1995 1 3/4 23/32 5 7/8 3 5/8
December 31, 1994 3 5/8 1 5/8 8 1/2 4 3/4
September 30, 1994 3 1 3/4 8 1/2 6 7/8
June 30, 1994 2 3/8 2 8 3/8 7
March 31, 1994 2 3/8 1 7/8 8 1/2 7 1/2
</TABLE>
(b) Stockholders - As of March 25, 1996, the Company had
1,014 holders of record of the Company's Common Stock and
24 holders of record of the Company's Preferred Stock. This
does not include the holders that have their shares held in
a depository trust in "street" name. As of March 25, 1996
at least 4,066,780 shares (or 56%) of the issued and
outstanding common stock and at least 172,568 shares (or
85%) of the issued and outstanding preferred stock was 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 amounts are owed under the Company's secured bank loan
agreement or any dividends on the Preferred Stock are in
arrears.
Holders of shares of Preferred Stock are entitled to
receive, when, as and if declared by the Board of Directors
out of funds at the time legally available therefor, cash
dividends at an annual rate of 10% (equal to $1.00 per share
annually), payable quarterly in arrears. Cumulative
dividends accrue and are payable to holders of record as
they appear on the stock books of the Company on such record
dates as are fixed by the Board of Directors.
The Preferred Stock was issued in August 1993 and the
Company declared and paid five consecutive dividends for the
quarters ended September 30, 1993 through September 30,
1994. In December 1994, the Board of Directors voted not to
declare the quarterly cash dividend to holders of the
Company's Preferred Stock for the fourth quarter of 1994.
The decision to not pay the quarterly dividend was a result
of the Company's continuing operating losses, the cash and
working capital position, and the Company's belief that its
primary lender would not approve the payment thereof. In
March 1995, the Board of Directors voted to suspend payment
on any future Preferred Stock dividends indefinitely.
However, pursuant to the terms of the Preferred Stock,
dividends will continue to accrue on a monthly basis.
Dividends paid in the future, if any, on the Preferred Stock
will be contingent on many factors including, but not
limited to, whether or not a dividend can be justified
through the cash flow and earnings generated from future
operations.
The Preferred Stock will have priority as to dividends over
the Common Stock and any series or class of the Company's
stock hereafter issued, and no dividend (other than
dividends payable solely in Common Stock or any other series
or class of the Company's stock hereafter issued that ranks
junior as to dividends to the Preferred Stock) may be
declared, paid or set apart for payment on, and no purchase,
redemption or other acquisition may be made by the Company
of, any Common Stock or other stock unless all accrued
andunpaid dividends on the Preferred Stock have been paid or
declared and set apart for payment.
ITEM 6 - MANAGEMENT'S DISCUSSION AND ANALYSIS
SELECTED FINANCIAL DATA
<TABLE>
YEAR ENDED DECEMBER 31,
Statement of Operations Data: (In Thousands Except the Per Share Data)
----------------------------------------
1995 1994
---- -----
<S> <C> <C>
Oil and Gas Sales $ 2,624 $ 3,221
Gas Plant Revenue 5,008 6,738
Total Operating Revenues 9,040 12,069
Net Loss (765) (1,707)
Preferred Stock Dividend:
Declared - (868)
In Arrears (203) (290)
Converted in tender offer (117)
Non-cash inducement to convert to common stock (1,524) -
------- -------
Total (1,844) (1,158)
------- -------
Net Loss Applicable to Common Stockholders $(2,609) $(2,865)
======= =======
Per Share Data:
Before non-cash inducement $ (0.18) $ (2.32)
Non-cash inducement (0.24) -
------- -------
Net Loss Applicable to Common Stockholders $ (0.42) (2.32)
======= =======
Cash Dividends Declared Per Common Share None None
======= =======
</TABLE>
<TABLE>
Balance Sheet Data:
As of December 31,
------------------
1995 1994
-------- ---------
<S> <C> <C>
Working capital (deficit) $ (500) $ (429)
Total assets $13,440 $15,839
Long-term liabilities $ 1,603 $ 2,652
Stockholders' equity $ 9,017 $ 9,354
LIQUIDITY, CAPITAL RESOURCES AND CAPITAL EXPENDITURES:
Liquidity and Capital Resources
At December 31, 1995, the Company's cash balance was
$677,275 with a working capital deficit of $500,180
compared to as cash balance of $532,916 and a working
capital deficit of $429,417 at December 31, 1994. The
change in the Company's cash balance is summarized as
follows:
Cash balance at December 31, 1994 $ 532,916
Cash provided by operating activities 380,175
Capital expenditures (387,403)
Proceeds from sale of property
and equipment 823,631
Redemption of certificates of deposit 43,000
Payments on long-term debt (943,341)
Net proceeds from issuance of
common stock 228,297
-------
Cash balance at December 31, 1995 $ 677,275
=======
In addition to the components effecting cash, the increase
in the working capital deficit can be substantially
attributed to the increase in the current maturities of
long-term debt from $1,027,000 at December 31, 1994 to
$1,100,474 at December 31, 1995.
Early in 1995, the Company initiated a corporate
restructuring that focused on: eliminating areas of its
business that were losing money; reducing operating costs;
increasing efficiencies; and generating funds for working
capital. These initiatives included:
1) The disposition of approximately 35 wells that
generated operating loses of approximately $134,000 in
1994. These properties were sold during 1995 and
generated net proceeds of approximately $215,000 and
the Company recognized a gain of approximately $55,000
on the transaction. Because of the losses suffered by
these properties in 1994, Management does not expect
any negative financial impact on the Company's future
operations from the disposition of the properties and
believes that the actions taken will increase the net
margin generated from oil and gas operations;
2) A substantial downsizing of the Company's oil field
service and supply operations. As is more fully
discussed and illustrated in the Results of Operations
section, the Company's Oil Field Service and Oil Field
Supply operating margins have been historically low and
even unprofitable. The burden of these low margins or
operating losses have been compounded with the risks
inherent in these operations, the capital investment
required to maintain and operate and the uncertainty of
the future prospects in light of the overall decrease
in natural gas prices and drilling activity.
Downsizing these operations is not expected to have a
material negative effect on the Company's overall
results of operations. However, as a result of the
downsizing, the Company was able to generate net
proceeds of approximately $600,000 from the sale of
service equipment and supply store inventory. On an
aggregate basis, the Company realized a gain of
approximately $20,000 on the disposition of the service
and supply assets;
3) Closing the administrative office in Denver, Colorado
which eliminated annual payroll costs associated with
its accounting and administrative staff of
approximately $140,000. The Company also expects
savings of an additional $60,000 annually from costs
duplicated as a result of the Company maintaining two
administrative offices (such as rent, telephone,
insurance and office supplies).
Prior to the restructuring initiatives discussed above, the
Company also addressed one of the single largest cash
demands burdening the Company - the preferred stock
dividend. In light of the Company's continuing operating
losses, deteriorating working capital position, and belief
that the Company's primary lender would not approve a
payment thereon, the Company's Board of Directors voted in
December, 1994 to not declare the quarterly cash dividend to
holders of the Company's Series A Cumulative Convertible
Preferred Stock ("Preferred Stock") for the fourth quarter
of 1994. In March 1995, the Board of Directors voted to
suspend payment on any future Preferred Stock dividends
indefinitely. However, pursuant to the terms underlying the
Preferred Stock, dividends will continue to accrue on a
monthly basis. Dividends paid in the future, if any, on the
Preferred Stock will be contingent on many factors,
including but not limited to, whether or not a dividend can
be justified through the cash flow and earnings generated
from future operations.
Since the future payment of Preferred Stock dividends was so
uncertain, and the Company wanted to preserve its working
capital, in January 1995, the Company extended a tender
offer to the Preferred Stockholders. On February 28, 1995,
the Company completed the tender offer to its Preferred
Stockholders whereby the holders of the Company's Preferred
Stock were given the opportunity to convert each share of
Preferred Stock, and all then accrued and undeclared
dividends (including the full dividend for the quarters
ending December 31, 1995 and March 31, 1995) into 4.5 shares
of the Company's Common Stock and warrants to purchase 2.625
shares of Common Stock at $5.00 per share through December
31, 1996 and $6.00 per share through August 13, 1998, (the
date the warrants expire). As a result of the tender offer,
933,492 shares of the Preferred Stock converted into
4,200,716 shares of the Company's Common Stock and warrants
to purchase 2,450,417 shares of Common Stock. In addition,
21,600 shares of Preferred Stock converted into 56,739
shares of Common Stock prior to the tender offer.
Accordingly, as of March 25, 1996 there remains 202,688
shares of Preferred Stock outstanding. These events
substantially changed the capital structure of the Company
and alleviated the burden of approximately 83% of Preferred
Stock dividends.
In July 1995, the Company completed a private placement of
250,000 "Units" at $1.50 each. Each unit consisted of two
shares of common stock and one warrant to purchase one share
of common stock at $1.25 per share. The warrants are
exercisable after July 31, 1995, expire on April 30, 1997,
and are redeemable by the Company at $0.25 per warrant. As
of December 31, 1995, the Company had received proceeds of
$306,250 related to this private placement and the remaining
$68,750 was received in February 1996.
The success of the Company is largely dependent on its
ability to raise additional debt or equity capital to fund
future drilling and development activities. Since the
acquisition of Skaer in August of 1993, the Company has
suffered from undercapitalization, lacking the necessary
funds to properly exploit the assets acquired from Skaer.
Over the past 18 months, management has pursued various
avenues in search of a strategic partner to facilitate the
Company's growth.
As a result of these efforts, in March 1996, the Company
entered into a consulting agreement with Beta Capital Group,
Inc. ("Beta"). Beta is located in Newport Beach, California
and specializes in emerging companies that have both capital
needs and market support requirements. Steve Antry, Beta's
President, is from a third generation oil and gas background
and was an officer of Benton Oil and Gas between 1989 and
1992 and marketed Swift Energy's Income Funds between 1987
and 1989.
The Company has joined forces with Beta in an effort to
raise significant debt or equity capital in the very near
future. For instance, it is anticipated the Company, with
Beta's assistance, will be raising capital in the second
quarter of 1996. The proceeds from these efforts, if
successful, will be used for working capital, horizontal
drilling in Loveland Field, Colorado, and possibly to
participate with other industry participants in select
drilling ventures in Louisiana, the Gulf of Mexico or
elsewhere in the continental United States. The capital
raising discussed above is only the first of a series of
financings the Company is contemplating with Beta's
assistance. Accordingly, Management firmly believes that
this union with Beta, will put the Company well on its way
to realizing its goal of growth and expansion.
The initial term of Beta's agreement is for two years and
provides for minimum monthly cash consulting fees of
$17,500. However, these fees can be terminated if the
Company has not completed an initial financing of at least
$1,000,000 within 90 days after a financing document is
prepared and available for distribution. The contract may
also be canceled if a second financing of at least
$2,000,000 in either debt or equity is not completed by
March 1997. The Company anticipates that the initial
financing for the first $1,000,000 will begin in April 1996
and be completed within the second quarter of 1996.
In addition to Beta's cash compensation, the Company also
agreed to grant Beta warrants to purchase 1,000,000 shares
of the Company's common stock. The exercise price of the
warrants is $.75 per share and the warrants expire in March
2001. However, the Company may elect to cancel warrants for
500,000 shares if the initial $1 million dollar financing
currently contemplated for the second quarter of 1996 is not
completed by September 1996. If the initial $1 million
dollar financing is completed, but a second financing for at
least $2 million is not completed by March 1997, the Company
may elect to cancel warrants for 250,000 shares. If Beta
fails to meet other performance criteria set forth in the
agreement, the Company may elect to cancel warrants for an
additional 250,000 shares in March 1998. If the performance
criteria in the Consulting agreement are met during the
first two years, Beta can elect to extend the agreement for
one additional year.
The Company also agreed to pay Beta a fee equal to 2% of the
net proceeds from any debt or equity financing procured by
Beta and up to 7% from 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.
The cash compensation and expense reimbursements paid to
Beta will be limited to 15% of gross proceeds generated from
any financing procured by Beta plus the gross proceeds
generated from the exercise of any warrants that may be
consummated and completed during the term of the agreement.
Upon completion of the initial financing, the Company agreed
to nominate to the Board of Directors up to two individuals
should they choose to become Directors. Upon completion of
the second financing, the Company and Beta may mutually
agree on the addition of another Board member who is
affiliated with a substantial future equity investor in the
Company.
Regardless of the outcome of the contemplated financings
discussed above, Management believes the current cash flows
will support continued operations. The Company has not yet
determined what actions it will take if the contemplated
financings should be unsuccessful or if the current cash
flows will not support continued operations. However,
potential actions may include (i) selling existing oil and
gas properties; (ii) reducing , downsizing, discontinuing
and/or spinning-off other assets and operations of the
Company; and (iii) attempting to raise additional capital
through private placements, joint ventures or debt financing
with partners other than Beta.
</TABLE>
<TABLE>
Long-term Debt
During the year ended December 31, 1995, the Company's payments on long term debt were as
follows:
<CAPTION>
Payments
----------------------------------------
Principal Interest Total
--------- -------- ----------
<C> <C> <C>
Bank primary lender $ 826,156 $ 249,707 $1,075,863
All others 117,185 24,028 141,213
------- ------- ---------
$ 943,341 $ 273,735 $1,217,076
======= ======= =========
</TABLE>
As a result of the debt servicing in 1995 the Company's
debt-to-equity ratio decreased from 35% at December 31, 1994
to 26% at December 31, 1995.
As of December 31, 1995, the Company had violated a
financial covenant related to cash flow with its primary
lender. In March 1996, the bank agreed to restructure the
former cash flow requirement to provide for less restrictive
cash flow coverage and waived the former covenant violation.
With the restructured covenants, Management believes it is
reasonably possible that there will be no covenant
violations in 1996.
Capital Expenditures
During 1995, the Company invested $387,403 in property and
equipment and is summarized as follows:
Gas Plant $ 174,262
Oil and Gas Properties 161,218
Service Equipment and
Rolling Stock 42,605
Office Equipment 9,318
-------
$ 387,403
=======
The costs in the Gas Plant category were incurred in
connection with the Gas Plant expansion activities intended
to accommodate and process additional third party gas. The
Gas Plant expansion activities are discussed in more detail
in the Results of Operations section under the caption Gas
Plant Liquids and Gas. Approximately $60,000 of the costs
incurred in the Oil and Gas Properties category were
incurred to purchase the 80% working interest in the Cisco
Dome Field in Grand County, Utah, and the remaining balance
represents costs for workovers and equipment acquisitions
related to maintaining or enhancing the current production
in the oil and gas operations.
RESULTS OF OPERATIONS:
Overview
The Company's largest source of operating income is from the
sale of produced oil, 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. As a result, 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.
Total Revenue
Total Revenue from all operations was as follows:
<TABLE>
For the Years Ended December 31,
-----------------------------------------
1995 1994
---------------- -----------------
Amount % Amount %
------ --- ------ ---
<S> <C> <C> <C> <C>
Gas Plant:
Marketing and trading $ 3,872,565 42% $ 5,849,878 48%
Processing 1,135,050 13% 888,743 8%
--------- --- ---------- ---
Total gas plant 5,007,615 55% 6,738,621 56%
Oil and gas sales 2,623,782 29% 3,220,761 27%
Oil field services 740,709 8% 1,279,013 11%
Oil field supply and equipment 562,032 6% 720,928 5%
Well administration and other income 106,122 2% 109,376 1%
---------- ---- ---------- ---
Total revenue $ 9,040,260 100% $12,068,699 100%
========== ==== ========== ====
</TABLE>
The decrease in total revenue is primarily a result of lower
volumes of natural gas delivered and accounted for under the
caption Gas Plant-Marketing and Trading, lower natural gas
prices, a decrease in production and a loss of revenue
resulting from the Company's downsizing of its service and
supply operations. These circumstances, along with any
known trends or changes that effect revenue on a line-by-line basis are
discussed in following paragraphs under their respective captions.
Gas Plant Marketing and Trading
The Company has a "take-or-pay" contract with Public Service
Company of Colorado ("PSCo") which calls 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 is based on the Colorado Interstate Gas
Commission's "spot" price plus a fixed price bonus. The
contract is currently filled by the Company by two different
methods. The Company fills a portion of this contract with
marketing and trading activities which represent gas
purchased from third parties and sold to PSCo under the
terms of the contract. In both 1995 and 1994, the price
between the amount paid the third party producers and the
amount received from PSCo under the "take-or-pay" contract
was a constant price per MMBtu. However, the volumes sold
and the price paid by PSCo do vary on a monthly basis.
Operating statistics for the two years are as follows:
For the Year Ended
December 31,
--------------------------
1995 1994
--------- ----------
Total Volume Sold (Mcf) 2,586,205 2,979,572
Average Price $ 1.50 $ 1.96
----------- -----------
Total Revenue $ 3,872,565 $ 5,849,878
Costs (3,404,169) (5,315,241)
----------- -----------
Gross Margin $ 468,396 $ 534,637
=========== ===========
The lower volumes sold in 1995, as compared to 1994, is a
result of the Company displacing the brokered gas volume in
order to process third party gas through its gas plant
during 1995 (see the discussion below under the caption Gas
Plant Liquids and Gas).
The lower prices received by the Company in 1995 are
primarily related to the competitive environment fostered by
FERC Order No. 636, constrictions on moving and selling gas
in eastern markets and a lower demand for natural gas in the
DJ Basin. The constrictions for moving gas to the eastern
markets became even more apparent in 1995 when a record high
"basis" differential was created between the natural gas
prices in the Rocky Mountain region and the eastern markets.
The price of gas in the eastern markets was significantly
higher than that in the Rocky Mountain region. As a result
of this basis differential, a few major pipeline companies
in the Rocky Mountain region are contemplating expanding
their compression capabilities or possibly building new
pipelines in the Rocky Mountain region for east coast
distribution. Should these events occur, Management
believes the basis differential would eventually tighten, or
even disappear, and all Rocky Mountain producers would
realize higher gas prices at the wellhead. However, until
that time, the Company expects gas prices in the DJ Basin
and the entire Rocky Mountain region to continue to be
depressed due to the restructuring and unbundling of
services mandated by FERC Order No. 636, constrictions on
moving and selling gas in eastern markets and other factors
beyond the Company's control.
The contract with PSCo expires on June 30, 1996.
Historically, the price paid by PSCo under this contract has
been at a premium above the market and therefore has allowed
for the marketing and trading activities. With the
increasing competition fostering within all phases of the
natural gas industry, compounded by FERC Order No. 636, it
is unlikely that the contract will be renewed at an above
market premium. Accordingly, since the gross margin
represents the net cash flow and income generated from this
activity, the loss of this premium contract price will have
a very material and negative impact on the Company's future
operations.
Gas Plant Liquids and Gas
These categories account for the natural gas sold at the
tailgate of the Gas Plant and the natural gas liquids
extracted and sold by the Gas Plant facility. During 1994
the revenues generated from these products were a result of
the Company's own production from the Loveland and Johnson's
Corner Fields. However, between February 1995 and September
1995, the Company purchased third party gas in an effort to
increase the Gas Plants utilization.
Operating statistics for the two years are as follows:
<TABLE>
For the Year Ended December 31
-----------------------------------
1995 1994
-------------- --------------
<S> <C> <C> <C> <C> <C>
Average Average
Production: Volumes Price Volumes Price
------- ------- ------- -------
Natural Gas Sold (Mcf) 444,171 $ 0.72 329,044 $ 0.68
B-G Mix (gallons) 1,354,018 $ 0.33 1,270,770 $ 0.29
Propane (gallons) 1,053,852 $ 0.35 960,310 $ 0.31
</TABLE>
<TABLE>
Operating Margin: Amount Amount
<S> <C> <C>
Revenue $ 1,135,050 $ 888,743
Costs (942,867) (573,206)
---------- ---------
Gross Margin $ 192,183 $ 315,537
========== =========
Gross Margin Percent 17% 36%
</TABLE>
The increase in processing volumes and revenue can be
substantially attributed to the Company purchased and
processed third party gas between February 1995 and
September 1995.
Costs associated with the Gas Plants 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 average
approximately $435,000 annually and 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, and costs of gas marketing and buying. 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. The costs in 1995 have increased both in
amount and as a percentage of revenue, when compared to
1994, as a result of the Company purchasing and processing
third party gas between February 1995 and September 1995.
Prior to that time, most of the gas processed by the Gas
Plant was from wells the Company owned. Accordingly, the
variable costs, as a percentage of revenue, increased
significantly in 1995.
During the third quarter of 1995 the Company experienced
several operational problems caused by processing higher
volumes of gas. On several occasions, these operational
problems forced the Gas Plant to either shut down or take
the incoming gas to flare. In order to identify and correct
the operational problems, the Company elected not to
purchase and process any significant amount of third party
gas beginning October 1, 1995. Management believes the
operational problems encountered in the third quarter of
1995 have been corrected but as of the date of this report
the Company is not processing any third party gas. In light
of the uncertainty of the PSCo gas contract discussed
previously under the caption Gas Plant Marketing and
Trading, and the increasing competitive environment in the
natural gas market, it is uncertain at this time if the
Company will be able to compete with other gas plants and
purchasers of natural gas from the Wattenburg Field.
Accordingly, it cannot be determined at this time when, or
if, the Company will process any additional third party gas.
Oil and Gas
Operating statistics for oil and gas producing activities
for the two years are as follows:
<TABLE>
1995 1994
-------- --------
<S> <C> <C>
Production:
Oil (bbls) 121,456 155,541
Gas (Mcf) 496,537 543,428
Average Collected Price:
Oil (per Bbl) $16.77 $15.94
Gas (per Mcf) $ 1.18 $ 1.36
Operating Margin:
Revenue $2,623,782 $3,220,761
Costs (1,617,318) (2,189,780)
----------- -----------
Gross Margin $1,006,464 $1,030,981
=========== ===========
Gross Margin Percent 38% 32%
Change in oil and gas revenue
attributed to:
Production $ (607,280)
Price 10,301
---------
$ (596,979)
==========
Average Production Cost per
BOE before DD&A $7.87 $8.90
</TABLE>
It should be noted that the Company was able to maintain the
gross margin on its oil and gas producing activities despite
the 22% decrease in oil production and a 14% decrease in gas
production. This is primarily a result of the Company's
efforts to manage production and control costs.
Approximately 30% of the decrease in production is a result
of the natural decline of oil and gas wells and the
remaining decrease is attributable to the sale of 35 wells
in 1995. The wells sold in 1995 lost approximately $134,000
in 1994.
Oil Field Services and Oil Field Supply
Operating statistics for the Company's service and supply
operations for the two years ended are as follows:
<TABLE>
Service Operations Supply Operations
For the Year For the Year
Ended December 31, Ended December 31,
------------------------- -------------------------
1995 1994 1995 1994
---- ---- ---- ----
<S> <C> <C> <C> <C>
Revenue $ 740,709 $1,279,013 $ 562,032 $ 720,928
Costs (721,794) (1,183,501) (669,794) (663,500)
Depreciation (144,664) (294,860) (12,716) (12,120)
--------- ---------- ---------- ----------
Net Operating
Income (Loss) $ (125,749) $ (199,348) $ (120,478) $ 45,308
========= ========== ========== ==========
</TABLE>
It should be noted that substantially all of the net
operating losses in 1995 were incurred prior to the Company
completing its restructuring. Management of the Company
recognized that the margins in the oil field service and
supply business have been historically low and even
unprofitable. The burden of these low margins or operating
losses were compounded with the risks inherent in these
operations, the capital investment required to maintain and
operate, and the uncertainty of the future prospects in
light of the overall decrease in natural gas prices and
drilling activity. Accordingly, as stated previously, the
Company initiated and completed a plan of restructuring
during 1995 that included a significant downsizing of its
service and supply operations. A summary of the
restructuring for both operations is discussed in the
following paragraphs.
Service Operations
Historically, the Company's service business has operated
out of two locations - Loveland and Sterling Colorado. The
services provided included: servicing rigs, vacuum trucks,
roustabout services and hot oiling services. The operations
serviced both the Company's needs and those of third
parties. The restructuring was focused on reducing the
service rig, vacuum truck and roustabout operations to a
point where the Company can service its own needs
efficiently and at the lowest possible cost while performing
only limited services for third parties. Any services of
this type to third parties will be limited to those
circumstances when the equipment and man power is not needed
in the Company's operations. The Company did retain its hot
oiler fleet and intends to continue providing this service
to third parties on a full time basis. Although management
anticipates the future revenues generated from the service
operations will be reduced to approximately $350,000
annually, it is not expected to have a material negative
effect on the Company's overall results of operations in
light of the historically low margins and/or operating
losses.
Supply Operations
Historically, the Company's supply business has also
operated out of two locations - Loveland and Sterling,
Colorado. The restructuring was focused on consolidating
the operations to one location (Loveland, Colorado),
eliminating duplicate costs and ultimately reducing the
amount of inventory. Although management expects total
revenues to decrease to approximately $300,000 annually, it
is not expected to have a material negative effect on the
Company's overall results of operations in light of the
historically low margins and/or operating losses.
Well Administration and Other Income:
This revenue primarily represents the revenue generated by
the Company for operating oil and gas properties. There has
been no significant change in the average monthly revenue
between 1994 and 1995 and Management does not expect any
significant change in the future.
General and Administrative Expenses:
General and Administrative Costs decreased 35% from
$1,617,107 in 1994 compared to $1,059,306 for 1995. The
decrease can be substantially attributed to the considerable
effort put forth by Management of the Company to decrease
and control general and administrative expenses for 1995.
For example:
a) measures taken included downsizing of personnel, using
contract services for temporary assignments,
eliminating unnecessary services or supplies, and
evaluating certain types of costs for efficiency and
need;
b) two officers, with salaries aggregating $130,000
annually, resigned in 1994 and were not replaced;
c) in connection with the restructuring announced in the
second quarter of 1995, the Company closed its
administrative office in Denver, Colorado and has
eliminated annual payroll costs associated with its
accounting and administrative staff of approximately
$140,000;
d) the closing of the administrative office in Denver,
Colorado is anticipated to save the Company an
additional $60,000 annually from costs that were
duplicated as a result of the Company maintaining two
administrative offices (such as rent, telephone,
insurance and office supplies).
Management is continually evaluating ways to further cut
general and administrative costs. However, there can be no
assurance that future general and administrative costs will
be further curtailed nor can there be any assurance that
general and administrative costs may not increase in future
periods. The consulting contract entered into with Beta, in
March 1996 is expected to increase annual expenses at least
$320,000.
Depreciation, Depletion and Amortization:
Depreciation, Depletion and Amortization ("DD & A")
consisted of the following for 1995 and 1994:
1995 1994
-------- --------
Oil and Gas Properties $ 741,924 $ 884,100
Gas Plant and Other Buildings 245,953 270,640
Rolling Stock 124,443 215,930
Other Field Equipment 41,730 105,050
Furniture and Fixtures 46,437 42,870
Non-Compete Agreements 91,827 96,000
--------- --------
Total $1,292,314 $1,614,590
=========== ===========
DD&A per BOE for oil and gas properties remained relatively
constant at $3.73 per BOE in 1995 compared to $3.59 per BOE
in 1994. The decrease in DD&A for the Rolling Stock and
Other Field Equipment can be attributed to the disposition
of the corresponding assets during the restructuring of the
Service and Supply operations.
Impairment of Oil and Gas Properties:
In March 1995, the Financial Accounting Standards Board
issued statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment for all Long-Lived Assets,
including proved oil and gas properties. During the fourth
quarter of 1994, the Company adopted SFAS No. 121, which
requires the Company to assess impairment whenever events or
changes in circumstances indicate that the carrying amount
of a long-lived asset may not be recoverable. When an
assessment for impairment of oil and gas properties is
performed, the Company is required to compare the net
carrying value of proved oil and gas properties on a lease-by-lease basis
(the lowest level at which cash flows can be
determined on a consistent basis) to the related estimates
of undiscounted future net cash flows for such properties.
If the net carrying value exceeds the net cash flows, then
impairment is recognized to reduce the carrying value to the
estimated fair value. At December 31, 1994, the estimated
fair value of the impaired properties was determined by
using 1994 year-end prices and costs and discounting the
estimated cash flows using a discount rate commensurate with
the risks involved which management estimated at 10%
annually. As a result of this change, the Company
recognized impairment expense of $934,211 in 1994, which
resulted in an increase in net loss per share of
approximately $.73. Management believes this impairment
charge primarily results from the change in accounting
rather than a change in the economic and operating
conditions related to the properties. The allowance for
impairment is included in accumulated depreciation and
depletion in the accompanying balance sheet.
Under the current (and anticipated) operating conditions and
environment, no significant impairment charges are
anticipated in 1996. However, because of the many
uncertainties surrounding the Company's operating
environment, including oil and gas producing and development
activities, future prices of oil and gas, lifting costs,
actual production, the regulatory environment or other
economic and political factors and conditions, there can be
no assurance of the actual charges that will be incurred in
the future for impairment under SFAS No. 121.
Dry Hole and Abandonment of Oil and Gas Properties:
Dry hole and abandonment costs incurred by the Company in
1995 were $18,786 compared to $315,809 in 1994. In 1994,
the Company drilled one dry hole at a cost of approximately
$226,378. The remaining costs were incurred in connection
with plugging and abandonment charges for seven other
properties. In 1995, these charges related to plugging and
abandonment costs incurred with two properties that had
become uneconomical.
Because of the adoption of the new accounting policy and the
corresponding impairment charge discussed previously in this
section under the caption "Impairment of Oil and Gas
Properties", the Company does not anticipate that any
significant abandonment charges will be incurred in 1996.
However, because of the many uncertainties surrounding the
Company's operating environment, including oil and gas
producing and development activities, future prices of oil
and gas, lifting costs, actual production, the regulatory
environment and other economic and political factors, there
can be no assurance of the actual costs that will be
incurred in the future related to abandonments.
Interest Expense:
Total interest expense for 1995 was $306,435 compared to
$324,251 in 1994. Interest expense in 1995 did not decrease
proportionately with the Company's long-term debt because of
the higher interest rates incurred in 1995 with the credit
facility with the Company's primary lender. In March 1995,
the Bank increased the interest rate on the credit facility
from prime plus 1% to prime plus 3% in connection with a
restructuring of the financial covenants contained therein.
The balance of this loan at December 31, 1995 was $1,762,802
and is payable in monthly installments of principal and
interest through August 1997.
Gain on Sale of Assets:
The Company recognized a gain on sale of assets in 1995 of
$75,073 compared to $55,372 in 1994. Substantially all of
the gain in 1995 was related to the disposition of 35 oil
and gas properties and the sale of the service and supply
equipment during the Company's restructuring. Substantially
all of the gain in 1994 was related to the sale of one oil
and gas lease in November 1994.
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.
In connection with the 1995 conversion of preferred stock to
common stock, the Company experienced a significant change
in its capital structure. The pro forma effect of these
changes, as if the conversions occurred on January 1, 1994,
would have resulted in a reduction in the 1994 loss
applicable to common stockholders from ($2.32) per share to
($.35) per share. The pro forma effect, as if the
conversions occurred on January 1, 1995, would have resulted
in a reduction in net loss applicable to common stockholders
before non-cash inducement from ($.18) per share to ($.14)
per share. The pro forma loss per share calculations give
effect to 4,257,455 common shares which were issued in the
conversion and the elimination of dividends related to the
converted preferred shares of approximately $933,000 for
1994 and $117,000 for 1995. However, the pro forma
information does not give effect to the inducement discussed
in the following paragraph.
The Company completed a tender offer to the Company's
preferred stockholders in February 1995. In connection
therewith, the Company offered the preferred holders 4.5
common shares for each preferred share owned. The 4.5
shares represented an increase from the original terms of
the preferred stock which provided for 2.625 common shares
for each preferred share. Under a recently issued
accounting pronouncement, the Company was required to reduce
earnings available to common stockholders to convert their
shares. Since the Company issued an additional 1,750,000
common shares in the tender offer compared to the shares
that would have been issued under the original terms of the
preferred stock, the Company was required to deduct the fair
value of these additional shares of $1,523,906 from earnings
available to common stockholders. This non-cash charge
resulted in the reduction of earnings per share by $.24 for
the year ended December 31, 1995.
While this charge is intended to show the cost of the
inducement to the owners of the Company's common shares
immediately before the tender offer, management does not
believe that it accurately reflects the impact of the tender
offer on the Company's common stockholders. As disclosed to
the preferred stockholders in connection with the tender
offer, the book value per share of common stock increased
from a negative amount to approximately $1.00 per share as a
result of the tender offer. Therefore, management believes
that, even though the current accounting rules require the
$.24 charge per common share, there are other significant
offsetting factors by which the common shareholders
benefited from this conversion which are not reflected in
the 1995 earnings per share presentation.
Impact of Recently Issued Accounting Standards:
In October 1995, the Financial Accounting Standards Board
issued a new statement titled "Accounting for Stock-Based
Compensation" (SFAS 123). The new statement is effective
for fiscal years beginning after December 15, 1995. SFAS
123 encourages, but does not require, companies to recognize
compensation expense for grants of stock, stock options, and
other equity instruments to employees based on fair value.
Companies that do not adopt the fair value accounting rules
must disclose the impact of adopting the new method in the
notes to the financial statements. Transactions in equity
instruments with non-employees for goods or services must be
accounted for on the fair value method. For transactions
with employees, the Company currently does not intend to
adopt the fair value accounting under SFAS 123, and will be
subject only to the related disclosure requirements.
PART II - OTHER INFORMATION
ITEM 7. FINANCIAL STATEMENTS
The Consolidated Financial Statements that constitute Item 7
are included at the end of this report beginning on Page F-1.
ITEM 8. NOT APPLICABLE
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND
CONTROL PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE
EXCHANGE ACT
Directors
The following table sets forth the names and ages of the
current directors and executive officers of the Company, the
principal offices and positions with the Company held by
each person and the date such person became a director or
executive officer of the Company. The executive officers of
the Company are elected annually by the Board of Directors.
The Board of Directors is divided into three approximately
equal classes. The directors serve three year terms and
until their successors are elected. Each year the
stockholders elect one class of directors. The executive
officers serve terms of one year or until their death,
resignation or removal by the Board of Directors. There are
no family relationships between any of the directors and
executive officers. In addition, there was no arrangement
or understanding between any executive officer and any other
person pursuant to which any person was selected as an
executive officer.
The directors and executive officers of the Company are as follows:
<TABLE>
Served as Director
Or Executive
Name Age Position With the Company Officer Since
- -------------------- --- ------------------------- -------------
<S> <C> <S> <C> <C> <S> <C> <S> <C>
Willard H. Pease, Jr. (1) 36 President, Chief Executive Officer 1983
and Director (Term Expires 1996)
James N. Burkhalter 60 Vice President of Engineering and 1993
Production and Director
(Term Expires 1997)
Patrick J. Duncan (1) 33 Chief Financial Officer, Treasurer, 1994
Corporate Secretary and Director
(Term Expires 1997)
Homer C. Osborne (2) 67 Director (Term Expires 1998) 1994
James C. Ruane (2) 62 Director (Term Expires 1998) 1980
Robert V. Timlin 65 Director (Term Expires 1997) 1981
William F. Warnick (2) 49 Director (Term Expires 1996) 1988
<FN>
<F1>
(1) Member of the Audit Committee of the Board of Directors.
<F2>
(2) Member of the Compensation Committee.
</FN>
</TABLE>
Willard H. Pease, Jr. has been President and Chief
Executive Officer of the Company since 1990. Mr. Pease was
Executive Vice President and Chief Operating Officer of the
Company from 1983 to 1990. Mr. Pease is responsible for the
Company's corporate finance, managing the day-to-day
operations of the Company and is principally responsible for
the Company's oil and gas exploration and production
activities. Mr. Pease has worked in the oil field business
for over 16 years. Mr. Pease received a B.A. degree in
management with additional educational focuses in geology in
1983.
James N. Burkhalter has been Vice President of
Engineering and Production of the Company since 1993, and is
responsible for the Company's engineering, production,
regulatory compliance, and gas plant operations. Prior to
joining the Company Mr. Burkhalter was owner and president
of Burkhalter Engineering, an engineering firm which he
formed in 1975. Mr. Burkhalter has been Chairman of the
Colorado Board of Registration for Professional Engineers
and Surveyors, serving eight years. From 1959 to 1975 Mr.
Burkhalter worked for Amoco and Rocky Mountain Natural Gas
as a petroleum engineer. Mr. Burkhalter received a B.S.
degree in petroleum engineering in 1959 from the Colorado
School of Mines.
Patrick J. Duncan has been the Chief Financial Officer
of the Company since September, 1994, the Company's
Corporate Secretary since April 1995 and the Company's
Treasurer since March 1996. Mr. Duncan is responsible for
all the financial, accounting and administrative reporting
and compliance required by his individual job titles. Mr.
Duncan was an Audit Manager with HEIN + ASSOCIATES,
Certified Public Accountants, from 1991 until joining the
Company as the Company's Controller in April 1994. From
1988 until 1991, Mr. Duncan was an Audit Supervisor with
Coopers & Lybrand, Certified Public Accountants. Mr. Duncan
received a B.S. degree from the University of Wyoming in
1985.
Homer C. Osborne was an officer and director of Garrett
Computing System, Inc., a petroleum engineering and
computing firm, from 1967 until 1976, at which time he
organized Osborne Oil Company as a wholly-owned subsidiary
of Garrett Computing Systems, Inc. Mr. Osborne has operated
Osborne Oil Company as a separate entity since 1976.
James C. Ruane has owned and operated Goodall's Charter
Bus Service, Inc., a bus chartering business representing
Grey Lines in the San Diego area, since 1958. Mr.
Ruane has been an oil and gas investor for over 20 years.
Robert V. Timlin has been self-employed as a consulting
petroleum engineer since 1989. Mr. Timlin has been involved
in the oil and gas industry for over 30 years and has served
in managerial capacity with several companies, including HMT
Management Inc., an oil and gas management firm, from 1983
to 1988; T&M Casing Service, Inc., from 1975 to 1983; Dowell
Studer, Inc., and Husky Oil Company. Mr. Timlin has
received an Associates Degree in petroleum engineering in
1957.
William F. Warnick is a practicing attorney in Lubbock,
Texas. Mr. Warnick serves as the Texas Attorney General's
appointee to the Texas School Board Land Commission and is a
member of the American, Texas, and Lubbock Bar Associations.
He is an oil and gas investor and has served in various
management positions of private independent oil and gas
companies. Mr. Warnick received a B.A. degree in finance
and a J.D. degree in 1971.
COMPLIANCE WITH SECTION 16(a) OF THE SECURITIES EXCHANGE ACT
OF 1934
Section 16(a) of the Securities Exchange Act of 1934
requires the Company's officers and directors, and persons
who own more than ten percent of the Company's Common Stock,
to file reports of ownership and changes in ownership with
the Securities and Exchange Commission ("SEC"). Officers,
directors and greater than ten percent stockholders are
required by SEC regulations to furnish the Company with
copies of all Section 16(a) forms they file.
The following disclosure is based solely upon a review of
the Forms 3 and 4 and any amendments thereto furnished to
the Company during the Company's fiscal year ended December
31, 1995, and Forms 5 and amendments thereto furnished to
the Company with respect to such fiscal year, or written
representations that no Forms 5 were required to be filed by
such persons. Based on this review the following persons
who were directors, officers and beneficial owners of more
than 10% of the Company's outstanding Common Stock during
such fiscal year filed late reports on Forms 3 and 4.
James N. Burkhalter filed two late reports on Form 4
reporting a total of four transactions. Patrick J. Duncan
filed three late reports on Form 4 reporting a total of six
transactions. Robbie R. Gries filed one late report on Form
4 reporting four transactions. Homer C. Osborne filed one
late report on Form 4 reporting two transactions. Willard
H. Pease, Jr., filed four late reports on Form 4 reporting a
total of 17 transactions. James C. Ruane filed one late
report on Form 4 reporting two transactions. Robert V.
Timlin filed one late report on Form 4 reporting five
transactions. William F. Warnick filed one late report on
Form 4 reporting six transactions.
ITEM 10-EXECUTIVE COMPENSATION
Summary Compensation Table
The Summary Compensation Table shows certain compensation
information for services rendered in all capacities during
each of the last three fiscal years by the Chief Executive
Officer. No executive officer's salary and bonus exceeded
$100,000 in 1995. The following information for the Chief
Executive Officer includes the dollar value of base
salaries, bonus awards, the number of stock options granted
and certain other compensation, if any, whether paid or
deferred.
SUMMARY COMPENSATION TABLE
<TABLE>
Annual Compensation (1)
-----------------------------
Name and Principal Other Annual
Position at 12/31/95 Year Salary Bonus Compensation
- -------------------- ---- ------ ----- ------------
<S> <C> <S> <C> <C> <S>
Willard H. Pease, Jr. 1995 $75,000 None None
President and Chief 1994 $75,000 None None
Executive Officer 1993 $75,500 None None
</TABLE>
<TABLE>
Long-Term Compensation
Awards
-----------------------------
Restricted Number of
Name and Principal Stock Options All Other
Position at 12/31/95 Year Awards Granted Compensation
- -------------------- ---- ---------- ---------- -------------
<S> <C> <S> <C> <S> <C> <S>
Willard H. Pease, Jr. 1995 None 139,600 None
President and Chief 1994 None - None
Executive Officer 1993 None 62,000 None
<FN>
<F1>
(1) No bonuses have been paid to Mr. Pease. In addition, no amounts have been shown as
Other Annual Compensation because the aggregate incremental cost to the Company of
personal benefits provided to Mr. Pease did not exceed the lesser of $50,000 or 10%
of his annual salary in any given year.
</FN>
</TABLE>
Option Grants in the Last Fiscal Year
Set forth below is information relating to grants of stock options to the
Chief Executive Officer pursuant to the Company's Stock Option Plans during
the fiscal year ended December 31, 1995.
<TABLE>
Individual Grants
-----------------------------------------------------------------
% of Total
Options
SARs
Options/ Granted to Exercise or
SARs Employees Base Price Expiration
Name Granted (#) Fiscal Year ($/Sh)(3) Date
------------------- ----------- ----------- ----------- ----------
<S> <C> <S> <C> <C> <C> <C> <C>
Willard H. Pease, Jr. 99,600 (1) 22.9% $0.83 05/15/00
President and Chief 40,000 (2) 9.2% $0.70 06/15/00
Executive Officer
</TABLE>
<TABLE>
Value of
Number of Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
at FY-End (#) at FY-End ($)
------------------------------ ----------------------------
Name Exercisable Unexercisable Exercisable Unexercisable
-------------------- ----------- ------------- ----------- -------------
<S> <C> <S> <C> <C> <C> <C>
Willard H. Pease, Jr. 99,600 0 0 (4) 0
President and Chief 40,000 0 0 (4) 0
Executive Officer
</TABLE>
(1) These options became exercisable on November 16, 1995
(2) These Options became exercisable on December 16, 1995
(3) The exercise price for all options listed above was 100% of the
market price of the Common Stock on the date of grant of the
options.
(4) None of the exercisable options held by Mr. Pease were in-the-money
at December 31, 1995.
Aggregated Option Exercises in the Last Fiscal Year and the
Fiscal Year-End Option Values
Set forth below is information with respect to the
unexercised options to purchase the Company's Common Stock
held by Willard H. Pease, Jr. at December 31, 1995. No
options were exercised during fiscal 1995.
<TABLE>
Value of Unexercised
Number of Unexercised in-the-Money Options
Options at FY-End (#) At FY-End ($)(1)(2)
---------------------------- ----------------------------
Name Exercisable Unexercisable Exercisable Unexercisable
-------------------- ----------- ------------- ----------- -------------
<S> <C> <S> <C> <S> <C> <S>
Willard H. Pease, Jr. 139,600 -0- -0- -0-
President and Chief
Executive Officer
</TABLE>
(1) Mr. Pease did not exercise any options during 1995.
(2) None of the exercisable options held by Mr. Pease were in-the-money at
December 31, 1995.
Compensation of Directors
Directors who are employees do not receive additional
compensation for service as directors. Other directors
each receive $350 per meeting attended and $50 per meeting
conducted via telephone conference. Directors may elect to
receive the compensation either in cash or stock.
Employment Contract with a Director
The Company has entered into an employment agreement with a
Director, Willard Pease, Jr., who is also the Company's
President and Chief Executive Officer. The employment
agreement may be terminated by the Company without cause on
30 days notice provided the Company continues to pay the
salary of Mr. Pease for 36 months. The salary must be paid
in a lump sum if the termination occurs after a change in
control of the Company as defined in the employment
agreement. Mr. Pease may terminate the employment
agreement on 90 days written notice. The base salary of
Mr. Pease under the employment agreement is $75,000 per
year.
ITEM 11- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT
The following table sets forth certain information
regarding the beneficial ownership of the Company's Common
Stock, its only class of outstanding voting securities as
of March 25, 1996, by (i) each person who is known to the
Company to own beneficially more than 5% of the outstanding
Common Stock with the address of each such person, (ii)
each of the Company's directors and officers, and (iii) all
officers and directors as a group:
<TABLE>
Name and Address of
Beneficial Owner or Amount and Nature of
Name of Officer or Director Beneficial Ownership(1) Percentof Class
--------------------------- ----------------------- ---------------
<S> <C> <S><C> <C> <S> <C> <C>
Willard H. Pease, Jr.
P.O. Box 1874
Grand Junction, CO 81502 702,139 Shares(2) 9.4%
James C. Ruane
5010 Market St.
San Diego, CA 92102 235,644 Shares(3) 3.2%
Patrick J. Duncan
P.O. Box 1874
Grand Junction, CO 81502 134,531 Shares(4) 1.8%
James N. Burkhalter
P.O. Box 1874
Loveland, CO 80537 130,709 Shares (5) 1.8%
William F. Warnick
2022 Broadway
Lubbock, TX 79401 47,508 Shares(6) 0.7%
Robert V. Timlin
1989 South Balsam
Lakewood, CO 80277 37,095 Shares(7) 0.5%
Homer C. Osborne
1200 Preston Road #900
Dallas, TX 75230 22,342 Shares (8) 0.3%
All Officers and Directors as a
group (seven persons) 1,309,968 Shares (9) 16.6%
</TABLE>
<TABLE>
Name and Address of
Beneficial Owner or Amount and Nature of
Name of Officer or Director Beneficial Ownership(1) Percentof Class
--------------------------- ----------------------- ---------------
<S> <C> <C> <C> <S> <C> <C>
Chester LF Paulson & Jacqueline M.
Paulson JTWROS
811 SW Front Avenue
Suite 200
Portland, OR 97204-3376 523,750 Shares (10) 7.1%
Beta Capital Group, Inc.
901 Dove Drive, Suite 230
Newport Beach, CA 92660 1,000,000 Shares (11) 12.2%
(1) Beneficial owners listed have sole voting and
investment power with respect to the shares unless
otherwise indicated.
(2) Includes 61,173 shares that are owned directly by Mr.
Pease, over which shares Mr. Pease has sole voting and
investment power, 364,966 shares are owned by entities
affiliated with Mr. Pease over which shares Mr. Pease
has sole voting and investment power, 148,500 shares
underlying presently exercisable options owned by Mr.
Pease, 101,500 shares underlying presently exercisable
warrants owned by Mr. Pease and 26,000 shares
underlying a convertible promissory note owned by Mr.
Pease.
(3) Includes 4,560 shares held by Mr. Ruane as trustee
for two trusts, over which shares Mr. Ruane may be
deemed to have shared voting and investment power,
11,250 shares underlying convertible preferred stock,
44,584 shares underlying presently exercisable warrants
to purchase common stock, and 56,675 shares underlying
presently exercisable options.
(4) Includes 3,281 shares underlying presently exercisable
warrants and 105,000 shares underlying presently
exercisable options.
(5) Includes 115,000 shares underlying presently
exercisable options.
(6) Includes 32,675 shares underlying presently exercisable
options.
(7) Includes 32,675 shares underlying presently exercisable
options.
(8) Represents 17,975 shares underlying presently
exercisable options.
(9) Includes 508,500 shares underlying presently
exercisable options, 149,365 shares underlying
presently exercisable warrants, 11,250 shares
underlying convertible preferred stock, and 26,000
shares underlying a convertible note.
(10) Includes 178,480 shares underlying presently
exercisable warrants.
(11) Represents 1,000,000 shares underlying presently
exercisable warrants.
ITEM 12-CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
From time to time, various officers and directors of the
Company and their affiliates have participated in the
drilling of oil and gas wells which were drilled and
operated by the Company. All such persons and entities
have taken working interests in the wells and have paid the
drilling, completion and related costs of the wells on the
same basis as the Company and all other working interest
owners. On occasions of such participation the Company
retained the maximum interest in the well that it could
justify, given its cash availability and the risk involved.
In May 1995, James C. Ruane, a director of the Company
purchased 66,667 shares of Common Stock and 33,334 warrants
to purchase shares of Common Stock for $50,000 on the same
terms as other nonaffiliated purchasers.
At December 31, 1994, the Company owed certain affiliates
of Willard H. Pease, Jr. $116,719 principal plus $26,539 in
accrued interest for oil and gas revenue attributable to
interests in wells operated by the Company that are owned
by the individuals and related entities. Of the principal
amount, $2,877 was incurred in 1994, $4,603 was incurred in
1993, $20,992 was incurred in 1992, $85,518 was incurred in
1991 and $2,728 was incurred in 1990. At December 31,
1995, the Company also owed $60,000 to Willard H. Pease,
Jr. This loan is unsecured, bears interest at 8% per annum
and is due January 1997.
Until June 1993, Willard H. Pease, Jr. owned an oil well
servicing business, Grand Junction Well Services, Inc.
("GJWS"), which operated a workover and completion rig. In
June 1993, the Company acquired GJWS from Mr. Pease by
merging GJWS into a newly-formed subsidiary of the Company.
In the merger, the Company issued Mr. Pease 46,667 shares
of Common Stock and the Company's 6% secured convertible
promissory note in the principal amount of $175,000, for a
total value of $350,000, which was the estimated fair
market value of the GJWS assets and business. The note was
originally payable in three annual principal installments
of $45,000 on October 1, 1994, $65,000 on April 1, 1995 and
$65,000 on April 1, 1996. The October 1, 1994 principal
payment of $45,000 was paid and the remaining installments
were extended to October 1, 1997 and October 1, 1998,
respectively. The unpaid principal portion of $130,000 is
convertible at the election of Mr. Pease into Common Stock
at $5.00 per share. The transaction was approved
unanimously by the disinterested directors of the Company.
Mr. Pease remained a guarantor of the GJWS debt, which
totaled $37,000 on the date of acquisition, to a bank. As
a result of the transaction, the obligation of the Company
to GJWS, totaling approximately $188,000 at March 31, 1994,
was eliminated, reducing the Company's obligation to Mr.
Pease and affiliates by approximately $13,000.
In August 1994, Willard H. Pease, Jr. and entities
affiliated with Mr. Pease, exchanged promissory notes with
an aggregate principal balance of $150,000 for $150,000
principal amount of 12% Convertible Unsecured Promissory
Notes ("Notes"). The Notes were automatically converted by
their terms into 93,750 shares of the Company's Common
Stock on September 30, 1994. The Notes and the conversion
thereof were on the exact same terms as the Company's 12%
Convertible Unsecured Promissory Notes ("Private Notes")
that the Company sold in a private offering during August
and September, 1994. An entity affiliated with Mr. Pease
also purchased on the same terms as other unaffiliated
purchasers $50,000 principal amount of the Private Notes.
These Private Notes were automatically converted by their
terms into 31,250 shares of the Company's Common Stock on
September 30, 1994.
In August 1994, Patrick J. Duncan the Chief Financial
Officer, Treasurer, and Corporate Secretary of the Company,
purchased $25,000 of the Private Notes on the same terms as
other nonaffiliated purchasers. Mr. Duncan's Private Notes
were automatically converted by their terms into 15,625
shares of the Company's Common Stock on September 30, 1994.
All existing loans or similar advances to, and transactions
with, officers and their affiliates were approved or
ratified by the independent and disinterested directors.
Any future material transactions with officers, directors
and owners of 5% or more of the Company's outstanding
Common Stock or any affiliate of any such person shall be
on terms no less favorable to the Company than could be
obtained from independent unaffiliated third parties and
must be approved by a majority of the independent
disinterested directors.
PART IV
ITEM 13 - EXHIBITS AND REPORTS ON FORM 8-K
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) 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
January 5, 1995. (2)
(4.4) Certificate of Designation of Series A Cumulative
Convertible Preferred Stock. (1)
(4.5) Certificate of Amendment of Certificate of
Designation of Series A Cumulative Convertible
Preferred Stock filed on August 16, 1993. (2)
(4.6) Second Certificate of Amendment of Certificate of
Designation of Series A Cumulative Convertible
Preferred Stock filed on November 1, 1994. (2)
(10.1) Residue Gas Sales and Purchase Agreement dated
June 22, 1986, between Western Gas Supply Company
and Loveland Gas Processing, Ltd., and Amendments
dated July 30, 1986, August 12, 1986, September
11, 1986, April 16, 1987, April 1, 1988, January
2, 1992, March 26, 1992 and May 1, 1992. (1)
(10.2) Amendment dated December 1, 1993, between Public
Service Company of Colorado and Loveland Gas
Processing Co., Ltd., to Residue Gas Sales and
Purchase Agreement dated June 22, 1986, between
Western Gas Supply Company and Loveland Gas
Processing, Ltd. (2)
(10.3) Gas Purchase and Sale Contract dated November 1,
1988, between Fuel Resources Development Co. as
seller and Loveland Gas Processing Co., Ltd., as
buyer, pertaining to the purchase of gas, and
Amendments dated November 1, 1990, January 24,
1991, May 1, 1991, July 5, 1991, August 1, 1991,
April 1, 1992 and August 1, 1992. (1)
(10.4) Purchase Order No. 5 dated January 1, 1994 from
Loveland Gas Processing Co., Ltd. to Fuel
Resources Development Co. that amends the Gas
Purchase and Sale Contract dated November 1, 1988,
between Fuel Resources Development Co. and
Loveland Gas Processing, Ltd. (2)
(10.5) Form of Warrants issued to Ronin Group Ltd., and
Clemons F. Walker for the purchase of an aggregate
of 240,000 shares of Common Stock. (3)
(10.6) 1990 Stock Option Plan. (1)
(10.7) 1993 Stock Option Plan (1)
(10.8) 1994 Employee Stock Option Plan. (2)
(10.9) Form of 12% Convertible Unsecured Promissory Notes
issued by Pease Oil and Gas Company in 1994
Private Placement. (2)
(10.10) Form of Warrants issued to brokers Sales Agents in
1994 Private Placements. (2)
(10.11) Employment Agreement effective September 16, 1994
between Pease Oil and Gas Company and Willard H.
Pease, Jr. (2)
(10.12) Employment Agreement effective December 27, 1994
between Pease Oil and Gas Company and Patrick J.
Duncan. (2)
(10.13) Employment Agreement effective December 27, 1994
between Pease Oil and Gas Company and James N.
Burkhalter. (2)
(10.14) Credit Agreement dated as of August 18, 1993, by
and among Willard Pease Oil and Gas Company, Skaer
Enterprises, Inc. and Colorado National Bank. (2)
(10.15) Mortgage, Assignment of Proceeds, Security
Agreement and Financing Statement from Skaer
Enterprises, Inc. To Colorado National Bank dated
August 23, 1993. (2)
(10.16) First Amendment to Credit Agreement dated December
30, 1994, by and among Willard Pease Oil and Gas
Company, Skaer Enterprises, Inc. and Colorado
National Bank. (2)
(10.17) Second Amendment to Credit Agreement dated March
31, 1995, by and between Pease Oil and Gas Company
and Colorado National Bank. (2)
(10.18) Interconnect Agreement dated January 1, 1995,
between KN Front Range Gathering Company and
Loveland Gas Processing Co., Ltd.(2)
(10.19) Gas Gathering Agreement dated February 1, 1995,
between KN Front Range Gathering Company and
Loveland Gas Processing Co., Ltd. (2)
(10.20) Agreement dated August 15, 1994, between Hewlett-Packard Company,
Loveland Gas Processing Co., Ltd., Pease Oil and Gas Company and Pease
Operating Company. (2)
(10.21) Purchase and Sale Agreement dated April 24, 1995
among Pease Oil and Gas Company, Thermo
Cogeneration Partnership, L.P and Seahawk Energy,
Inc. (3)
(10.22) Agreement between Beta Capital Group, Inc., and
Pease Oil and Gas Company dated March 9, 1996.
(21) List of Subsidiaries.
(27) Financial Data Schedule.
Footnotes:
(1) Incorporated by reference to Registration Statement No. 33-64448
on Form SB-2.
(2) Incorporated by reference to the Company's 1994 Annual Report on
Form 10-KSB.
(3) Incorporated by reference to Registration Statement No. 33-94536 on
Form SB-2.
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 29, 1996 By:/s/ Willard H. Pease, Jr.
Willard H. Pease, Jr.
President and Chief Executive
Officer
Date: March 29, 1996 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 29, 1996 By:/s/ Willard H. Pease, Jr.
Willard H. Pease, Jr., President
and Chairman of the Board
Date: March 29, 1996 By: /s/ Patrick J. Duncan
Patrick J. Duncan
Chief Financial Officer,
Treasurer, and Director
Date: March 29, 1996 By:/s/ James N. Burkhalter
James N. Burkhalter, Vice-
President Engineering
and Production, Director
Date: March 29, 1996 By:/s/ Homer C. Osborne
Homer C. Osborne, Director
Date: March 29, 1996 By:/s/ James C. Ruane
James C. Ruane, Director
Date: March 29, 1996 By:/s/ Robert V. Timlin
Robert V. Timlin, Director
Date: March 29, 1996 By:/s/ William F. Warnick
William F. Warnick, Director
</TABLE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Independent Auditor's Report............................................... F-2
Consolidated Balance Sheet - December 31, 1995 ............................ F-3
Consolidated Statements of Operations - For the Years Ended
December 31, 1995 and 1994........................................... F-5
Consolidated Statements of Stockholders' Equity - For the Years
Ended December 31, 1995 and 1994..................................... F-7
Consolidated Statements of Cash Flows - For the Years Ended
December 31, 1995 and 1994........................................... F-8
Notes to Consolidated Financial Statements................................. F-10
F-1
<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, 1995, and the related consolidated
statements of operations, stockholders' equity and cash flows for the years
ended December 31, 1995 and 1994. 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, 1995, and the results of their
operations and their cash flows for the years ended December 31, 1995 and 1994
in conformity with generally accepted accounting principles.
As discussed in Note 1, the Company changed its method of accounting for
long-lived assets during the fourth quarter of 1994.
HEIN + ASSOCIATES LLP
Denver, Colorado
March 2, 1996
F-2
<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1995
ASSETS
<S> <C>
CURRENT ASSETS:
Cash and equivalents .................................. $ 677,275
Trade receivables, net of allowance of $51,000 ........ 963,315
Inventory ............................................. 532,289
Prepaid expenses and other ............................ 77,844
Common stock subscription receivable, 91,667 shares ... 68,750
------------
Total current assets ..................... 2,319,473
------------
OIL AND GAS PROPERTIES, at cost (successful efforts method):
Undeveloped properties ................................ 377,606
Developed properties .................................. 9,149,516
------------
Total oil and gas properties ............. 9,527,122
Less accumulated depreciation and depletion ........... (3,608,917)
------------
Net oil and gas properties ............... 5,918,205
------------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Gas plant ............................................. 4,095,227
Service equipment and vehicles ........................ 855,025
Buildings and office equipment ........................ 529,703
------------
Total property, plant and equipment ...... 5,479,955
Less accumulated depreciation ......................... (1,034,731)
------------
Net property, plant and equipment ........ 4,445,224
------------
OTHER ASSETS:
Assets held for sale .................................. 92,432
Non-compete agreements, net of accumulated amortization
of $207,326 .................................... 352,674
Other ................................................. 311,718
------------
Total other assets ....................... 756,824
------------
TOTAL ASSETS ................................................. $ 13,439,726
============
The accompanying notes are an integral
part of these consolidated financial statements.
F-3
<PAGE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1995
(continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
<S> <C>
CURRENT LIABILITIES:
Current maturities of long-term debt .................. $1,100,474
Accounts payable, trade:
Natural gas purchases .......................... 899,878
Other .......................................... 272,689
Accrued production taxes .............................. 303,287
Other accrued expenses ................................ 243,325
-----------
Total current liabilities ................ 2,819,653
-----------
LONG-TERM LIABILITIES:
Long-term debt, less current maturities:
Related parties ................................ 338,741
Other .......................................... 884,418
Accrued production taxes .............................. 379,652
-----------
Total long-term liabilities .............. 1,602,811
-----------
COMMITMENTS AND CONTINGENCIES (NOTES 5 and 9)
STOCKHOLDERS' EQUITY:
Preferred Stock, par value $.01 per share,
2,000,000 shares authorized, 202,688 shares
of Series A Cumulative Convertible Preferred
Stock issued and outstanding (liquidation
preference of $2,280,000) ...................... 2,027
Common Stock, par value $.10 per share, 25,000,000 shares
authorized, 7,180,804 shares issued and outstanding 718,081
Additional paid-in capital ............................ 16,560,194
Accumulated deficit ................................... (8,263,040)
------------
Total stockholders' equity ............... 9,017,262
------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ................... $ 13,439,726
============
</TABLE>
The accompanying notes are an integral
part of these consolidated financial statements.
F-4
<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED
DECEMBER 31,
-------------------------
1995 1994
----------- ---------
<S> <C> <C>
REVENUE:
Gas plant:
Marketing and trading ........... $ 3,872,565 $ 5,849,878
Processing ...................... 1,135,050 888,743
----------- -----------
Total gas plant ........ 5,007,615 6,738,621
Oil and gas sales ....................... 2,623,782 3,220,761
Oil field services ...................... 740,709 1,279,013
Oil field supply and equipment .......... 562,032 720,928
Well administration and other income .... 106,122 109,376
----------- -----------
Total revenue .......... 9,040,260 12,068,699
----------- -----------
OPERATING COSTS AND EXPENSES:
Gas plant:
Marketing and trading ........... 3,404,169 5,315,241
Processing ...................... 942,867 573,206
----------- -----------
Total gas plant ........ 4,347,036 5,888,447
Oil and gas production .................. 1,617,318 2,189,780
Oil field services ...................... 721,794 1,183,501
Oil field supply and equipment .......... 669,794 663,500
General and administrative .............. 1,059,306 1,617,107
Depreciation, depletion and
amortization ...................... 1,292,314 1,614,590
Impairment of oil and gas properties .... -- 934,211
Dry holes, plugging, and abandonment .... 18,786 315,809
Restructuring costs ..................... 226,986 --
------------ -----------
Total operating costs
and expenses ........ 9,953,334 14,406,945
------------ -----------
LOSS FROM OPERATIONS ............................. (913,074) (2,338,246)
------------ -----------
OTHER INCOME (EXPENSES):
Interest expense ........................ (306,435) (324,251)
Gain on sale of assets .................. 75,073 55,372
------------ -----------
Net ............................. (231,362) (268,879)
------------ -----------
LOSS BEFORE INCOME TAXES ......................... (1,144,436) (2,607,125)
Income tax benefit ...................... 379,000 900,000
------------ -----------
NET LOSS ......................................... $ (765,436) (1,707,125)
============ ===========
The accompanying notes are an integral
part of these consolidated financial statements.
F-5
<PAGE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(continued)
FOR THE YEARS ENDED
DECEMBER 31,
-------------------------
1995 1994
----------- ---------
<S> <C> <C>
NET LOSS ....................................... $ (765,436) $ (1,707,125)
Preferred stock dividends:
Declared ...................... -- (868,335)
Converted in tender offer ..... (117,000) --
In arrears .................... (202,688) (289,742)
------------ ------------
Total preferred stock
dividends ........ (319,688) (1,158,077)
------------ ------------
Loss before non-cash
inducement ....... (1,085,124) (2,865,202)
Non-cash inducement in tender offer
(Note 1) .......................... (1,523,906) --
------------ ------------
NET LOSS APPLICABLE TO COMMON STOCKHOLDERS ..... $ (2,609,030) $ (2,865,202)
============ ============
NET LOSS PER COMMON SHARE:
Before non-cash inducement ............ $ (.18) $ (2.32)
Non-cash inducement (Note 1) .......... (.24) --
------------ ------------
$ (.42) $ (2.32)
============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING ............. 6,190,000 1,235,000
============ ============
</TABLE>
The accompanying notes are an integral
part of these consolidated financial statements.
F-6
<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1994
Preferred Stock Common Stock Additional
--------------------- -------------------------- Paid-in
Shares Amount Shares Amount Capital
--------- -------- --------- ----------- -----------
BALANCES, January 1, 1994 ...................... 1,157,780 $ 11,578 993,934 $ 99,394 $ 15,927,036
Proceeds from sale of debentures
converted to common stock ................ -- -- 909,219 90,922 1,363,828
Proceeds from sale of common
stock for cash ........................... -- -- 289,125 28,912 433,688
Offering costs ............................... -- -- -- -- (252,494)
Exchange of notes payable for
common stock .............................. -- -- 93,750 9,375 140,625
Return of common stock for
cancellation of receivables................ -- -- -- -- --
Preferred dividends declared for
$.75 per share ............................. -- -- -- -- (868,355)
Net loss ..................................... -- -- -- -- --
--------- -------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCES, December 31, 1994 .................... 1,157,780 11,578 2,286,028 228,603 16,744,348
========= ======== =========== =========== ============
Conversion of preferred stock to
common stock:
In tender offer ........................... (933,492) (9,335) 4,200,716 420,072 (410,737)
Other ..................................... (21,600) (216) 56,739 5,673 (5,457)
Acquisition of oil and gas
properties for common stock ................ -- -- 65,000 6,500 53,422
Sale of common stock in private
placement .................................. -- -- 500,000 50,000 325,000
Offering costs ............................... -- -- -- -- (77,953)
Issuance of common stock to
directors and employees for
services and other ......................... -- -- 21,036 2,104 11,327
Settlement of trade payable for
common stock ............................... -- -- 63,206 6,321 (30,948)
Cancellation of treasury shares .............. -- -- (11,921) (1,192) (48,808)
Net loss ..................................... -- -- -- -- --
--------- --------- --------- ---------- -----------
BALANCES, December 31, 1995 .................... 202,688 $ 2,027 7,180,804 $ 718,081 $ 16,560,194
========= ========= ========= =========== ===========
<PAGE>
<CAPTION>
Treasury Stock Stock Total
Accumulated ----------------------- Subscriptions Stockholders'
Deficit Shares Amount Receivable Equity
----------- --------- ----------- ------------- ------------
<S> <C> <C> <C> <C> <C> <S> <C> <S> <C> <S> <C>
BALANCES, January 1, 1994 .......................... $ (5,790,479) 12,241 $ (52,600) $ (109,709) $ 10,085,220
Proceeds from sale of debentures
converted to common stock .................... -- -- -- -- 1,454,750
Proceeds from sale of common
stock for cash ............................... -- -- -- -- 462,600
Offering costs ................................... -- -- -- -- (252,494)
Exchange of notes payable for
common stock .................................. -- -- -- -- 150,000
Return of common stock for
cancellation of receivable .................... -- 16,474 (79,988) 109,709 29,721
Preferred dividends declared for
$.75 per share ................................. -- -- -- -- (868,355)
Net loss ......................................... (1,707,125) -- -- -- (1,707,125)
----------- -------- ----------- ----------- ------------
BALANCES, December 31, 1994 ........................ (7,497,604) 28,715 (132,588) -- 9,354,337
=========== ======== =========== =========== ============
Conversion of preferred stock to
common stock:
In tender offer ............................... -- -- -- -- --
Other ......................................... -- -- -- -- --
Acquisition of oil and gas
properties for common stock .................... -- -- -- -- 59,922
Sale of common stock in private
placement ...................................... -- -- -- -- 375,000
Offering costs ................................... -- -- -- -- (77,953)
Issuance of common stock to
directors and employees for
services and other ............................. -- -- -- -- 13,431
Settlement of trade payable for
common stock ................................... -- -- -- -- 57,961)
Cancellation of treasury shares .................. -- (11,921) 50,000 -- --
Net loss ........................................ (765,436) -- -- -- (765,436)
----------- --------- ---------- ---------- -----------
BALANCES, December 31, 1995 ........................ $ (8,263,040) -- $ -- $ -- $ 9,017,262
=========== ========= ========== ========== ===========
</TABLE>
The accompanying notes are an integral
part of these consolidated financial statements.
F-7
<PAGE>
<TABLE>
<CAPTION>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(continued)
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED
DECEMBER 31,
--------------------------
1995 1994
----------- ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss ......................................... $ (765,436) $(1,707,125)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Provision for depreciation and depletion .... 1,200,487 1,518,590
Amortization of intangible assets ........... 109,381 120,588
Abandonment and impairment of oil and gas
properties ............................... -- 1,250,020
Deferred income taxes ....................... (400,000) (900,000)
Gain on sale of property and equipment ...... (75,073) (55,372)
Provision for bad debts ..................... 35,176 101,755
Issuance of common stock for services and
settlement of payable ..................... 71,392 --
Other ....................................... (41,770) (64,604)
Changes in operating assets and liabilities:
(Increase) decrease in:
Trade receivables .................... 625,286 (241,509)
Inventory ............................ 296,824 (57,170)
Prepaid expenses and other ........... 14,001 12,683
Increase (decrease) in:
Accounts payable ..................... (529,581) 1,015,685
Accrued expenses ..................... (160,512) (220,196)
----------- -----------
Net cash provided by operating activities ... 380,175 773,345
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment .. (387,403) (2,466,757)
Purchase of restricted investments ............... -- (160,000)
Proceeds from redemption of certificate of deposit 43,000 31,000
Proceeds from sale of property and equipment ..... 823,631 91,032
----------- -----------
Net cash provided by (used in) investing
activities ................................ 479,228 (2,504,725)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt ..................... -- 1,522,877
Repayment of long-term debt ...................... (943,341) (1,139,028)
Proceeds from sale of common stock ............... 281,250 462,600
Proceeds from sale of debentures ................. -- 1,454,750
Offering costs ................................... (52,953) (252,494)
Preferred stock dividends paid ................... -- (1,158,018)
----------- -----------
Net cash provided by (used in financing
activities ............................... (715,044) 890,687
----------- -----------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS ......... 144,359 (840,693)
CASH AND EQUIVALENTS, beginning of year ............. 532,916 1,373,609
----------- -----------
CASH AND EQUIVALENTS, end of year ................... $ 677,275 $ 532,916
=========== ===========
<PAGE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
--------------------------
1995 1994
----------- ------------
<S> <C> <C>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash paid for interest ........................... $ 273,735 $ 255,265
=========== ===========
Cash paid for income taxes ....................... $ 21,000 $-
=========== ===========
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES:
Long-term debt incurred for purchase
of vehicles .................................. $ 24,992 $ 96,667
Acquisition of oil and gas properties
for common stock ............................. 59,922 --
Common stock subscription receivable ............. 68,750 --
Treasury stock acquired for cancellation
of trade receivables ......................... -- 9,988
Offset of trade receivables to reduce
related party debt ........................... -- 25,705
Offset of accrued expenses to reduce
common stock subscriptions ................... -- 109,709
Exchange of notes payable to former
director for 93,750 shares of ................ -- 150,000
Contract payable for purchase of minority
interest in LGPCo ............................ -- 160,000
Return of 14,000 shares of common stock
by director for stock subscription
receivable .................................. -- 70,000
</TABLE>
The accompanying notes are an integral
part of these consolidated financial statements.
F-9
<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, markets and trades 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.
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 - For purposes of the statements of cash flows, the
Company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Oil and Gas Producing Activities - The Company follows the "successful
efforts" method of accounting for its oil and gas properties. Under
this method of accounting, all property acquisition costs and costs of
exploratory and development wells are capitalized when incurred,
pending determination of whether the well has found proved reserves.
If an exploratory well has not found proved reserves, the costs of
drilling the well are charged to expense. The costs of development
wells are capitalized whether productive or nonproductive. Geological
and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Management estimates
that the salvage value of lease and well equipment will approximately
offset the future liability for plugging and abandonment of the
related wells. Accordingly, no accrual for such costs has been
recorded.
Depletion and depreciation of capitalized costs for producing oil and gas
properties is provided using the units-of-production method based upon
proved reserves. Depletion and depreciation expense for the Company's
oil and gas properties amounted to $741,924 and $884,100 for the years
ended December 31, 1995 and 1994, respectively.
Impairment of Long-Lived Assets - In March 1995, the Financial Accounting
Standards Board issued statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets." SFAS No.
121 changes the Company's method of determining impairment for all
long-lived assets, including proved oil and gas properties. During the
fourth quarter of 1994, the Company adopted SFAS No. 121, which
requires the Company to assess impairment whenever events or changes
in circumstances indicate that the carrying amount of a long-lived
asset may not be recoverable. When an assessment for impairment of oil
and gas properties is performed, the Company is required to compare
the net carrying value of proved oil and gas properties on a
lease-by-lease basis (the lowest level at which cash flows can be
determined on a consistent basis) to the related estimates of
undiscounted future net cash flows for such properties. If the net
carrying value exceeds the net cash flows, then impairment is
recognized to reduce the carrying value to the estimated fair value.
At December 31, 1994, the estimated fair value of the impaired
properties was determined by using 1994
F-10
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
year-end prices and costs and discounting the estimated cash
flows using a discount rate commensurate with the risks involved which
management estimated at 10% annually. As a result of this change, the
Company recognized impairment expense of approximately $900,000 in
1994, which resulted in an increase in net loss per share of
approximately $.73. Management believes this impairment charge
primarily results from the change in accounting rather than a change
in the economic and operating conditions related to the properties.
The allowance for impairment is included in accumulated depreciation
and depletion in the accompanying balance sheet.
Property, Plant and Equipment - Property, plant, and equipment is stated at
cost. Depreciation of property, plant and equipment is 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
Depreciation expense related to property, plant and equipment
amounted to $458,563 and $634,490 for the years ended December 31,
1995 and 1994, respectively.
The cost of normal maintenance and repairs is 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 assets. These costs are being amortized over the terms of
the two to ten-year agreements on a straight-line basis. Amortization
expense related to the non-compete agreements was $91,827 and $96,000
for the years ended December 31, 1995 and 1994, respectively.
Inventory - Inventory consists primarily of oil and gas production
equipment and oil field supplies. These items are generally held for
resale. At December 31, 1995, inventory also includes approximately
$100,000 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. The Company has classified $200,000 of used
oil field equipment inventory as long-term (included with other
assets), because based on current inventory usage, it is not expected
to be sold within the next year.
Accounting Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts
reported in the financial statements and the accompanying notes. The
actual results could differ from those estimates.
F-11
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company's financial statements are based on a number of
significant estimates including the allowance for doubtful accounts,
accrued production taxes, realizability of intangible assets,
selection of the useful lives for property, plant and equipment, and
oil and gas reserve quantities which are the basis for the calculation
of depreciation, depletion, and impairment of oil and gas properties.
The Company's reserve estimates are determined by an independent
petroleum engineering firm. However, 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. At December 31, 1995, approximately 50% of
the Company's oil and gas reserves are attributable to non-producing
properties. Accordingly, the Company's estimates are expected to
change as future information becomes available.
As mandated under SFAS No. 121, the Company is required under certain
to circumstances evaluate the possible impairment of the carrying
value of its long-lived assets. For proved oil and gas properties,
this involves a comparison to the estimated future undiscounted cash
flows, which is the primary basis for determining the related fair
values for such properties. In addition to the uncertainties inherent
in the reserve estimation process, these amounts are affected by
historical and projected prices for oil and natural gas which have
typically been volatile. It is reasonably possible that the Company's
oil and gas reserve estimates will materially change in the
forthcoming year.
At December 31, 1995, the Company's gas plant had a net carrying value
of approximately $3,600,000. The determination of impairment of the
gas plant may change in the future based on the Company's ability to
continue to develop its properties whereby sufficient quantities of
natural gas and liquids are available to operate the plant profitably.
Additionally, at December 31, 1995, the Company has net capitalized
costs of approximately $242,000 related to a waterflood project in
progress. If this project is ultimately unsuccessful, these costs will
be charged to operations.
Income Taxes - Income taxes are provided for in accordance with Statement
of Financial Accounting Standards No. 109, "Accounting for Income
Taxes." SFAS No. 109 requires an asset and liability approach in the
recognition of deferred tax liabilities and assets for the expected
future tax consequences of temporary differences between the carrying
amounts and the tax bases of the Company's assets and liabilities.
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.
F-12
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 equiva lents have been excluded from the computations
because their effect would be anti-dilutive.
In connection with the 1995 conversion of preferred stock to
common stock discussed in Note 6, the Company experienced a
significant change in its capital structure. The pro forma effect of
these changes, as if the conversions occurred on January 1, 1994,
would have resulted in a reduction in the 1994 loss applicable to
common stockholders from ($2.32) per share to ($.35) per share. The
pro forma effect, as if the conversions occurred on January 1, 1995,
would have resulted in a reduction in net loss applicable to common
stockholders before non-cash inducement from ($.18) per share to
($.14) per share. The pro forma loss per share calculations give
effect to 4,257,455 common shares which were issued in the conversion
and the elimination of dividends related to the converted preferred
shares of approximately $933,000 for 1994 and $117,000 for 1995.
However, the pro forma information does not give effect to the
inducement discussed in the following paragraph.
The Company completed a tender offer to the Company's preferred
stockholders in February 1995. In connection therewith, the Company
offered the preferred holders 4.5 common shares for each preferred
share owned. The 4.5 shares represented an increase from the original
terms of the preferred stock which provided for 2.625 common shares
for each preferred share. Under a recently issued accounting
pronouncement, the Company was required to reduce earnings available
to common stockholders by the fair value of the additional shares
which were issued to induce the preferred stockholders to convert
their shares. Since the Company issued an additional 1,750,000 common
shares in the tender offer compared to the shares that would have been
issued under the original terms of the preferred stock, the Company
was required to deduct the fair value of these additional shares of
$1,523,906 from earnings available to common stockholders. This
non-cash charge resulted in the reduction of earnings per share by
$.24 for the year ended December 31, 1995.
While this charge is intended to show the cost of the inducement
to the owners of the Company's common shares immediately before the
tender offer, management does not believe that it accurately reflects
the impact of the tender offer on the Company's common stockholders.
As disclosed to the preferred stockholders in connection with the
tender offer, the book value per share of common stock increased from
a negative amount to approximately $1.00 per share as a result of the
tender offer. Therefore, management believes that, even though the
current accounting rules require the $.24 charge per common share,
there are other significant offsetting factors by which the common
shareholders benefited from this conversion which are not reflected in
the 1995 earnings per share presentation.
Impact of Recently Issued Accounting Standards - In October 1995,
the Financial Accounting Standards Board issued a new statement titled
"Accounting for Stock-Based Compensation" (SFAS 123). The new
statement is effective for fiscal years beginning after December 15,
1995. SFAS 123 encourages, but does not require, companies to
recognize compensation expense for grants of stock, stock options, and
other equity instruments to employees based on fair value. Companies
that do not adopt the fair value accounting rules must disclose the
impact of adopting the new method in the notes to the financial
statements. Transactions in equity instruments with non-employees for
goods or services must be accounted for on the fair value method. For
transactions with employees, the Company currently does
F-13
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
not intend to adopt the fair value accounting under SFAS 123, and
will be subject only to the related disclosure requirements.
Reclassifications - Certain reclassifications have been made to the 1994
financial statements to conform to the presentation in 1995. The
reclassifications had no effect on the 1994 net loss.
2. RESTRUCTURING:
In light of declining natural gas prices, declining rig counts,
lackluster margins and the competitive environment inherent in the oil
and gas industry, the Company has taken steps to reduce operating
costs, increase efficiencies, reduce operating risks and generate
additional working capital. During the second quarter of 1995, the
Company announced a restructuring program that included substantially
downsizing its service and supply businesses and closing its
administrative office in Denver, Colorado. As a result of this
restructuring, 35 of the Company's 70 employees were terminated,
service equipment was sold for net proceeds of approximately $602,300,
and the Company is continuing efforts to liquidate land and buildings
with a carrying value of $92,432 at December 31, 1995.
As of December 31, 1995, the Company has recognized $226,986 of
costs incurred in connection with both the tender offer discussed in
Note 6, and the restructuring discussed above. The costs recognized in
the restructuring consist primarily of severance pay, a loss on the
abandonment of the office lease, and a $90,000 loss from the
liquidation of inventory at an auction.
The operating revenues and net operating loss of the service and
supply businesses, exclusive of restructuring charges and gains on
sales of assets, were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1995 1994
---------- ------------
<S> <C> <C>
Revenues ............. $ 1,302,741 $ 1,999,941
Operating costs ...... (1,391,588) (1,847,001)
Depreciation ......... (157,380) (306,980)
----------- -----------
Net operating loss $ (246,227) $ (154,040)
=========== ===========
</TABLE>
Substantially, all of the 1995 net operating loss from these
operations was incurred prior to completion of the restructuring
discussed above.
F-14
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. LONG-TERM DEBT:
Long-term debt at December 31, 1995 consists of the following:
Unaffiliated Parties:
Note payable to a bank, which was restructured in March 1995
as described below. $1,762,802 Interest was computed at the
bank's prime rate plus 3% (11.5% at December 31, 1995).
Collateralized by substantially all of the Company's oil and
gas properties and the gas plant. The note prohibits the
payment of dividends to common stockholders, has other
financial covenants. $ 1,762,802
Convertible 12% debentures due May 1996. The debentures are
unsecured and are convertible into 82,353 shares of common
stock. 70,000
Other installment notes. Interest at 6.9% to 9.75%, monthly
principal and interest payments of approximately $3,440
through June 1999. All of the notes are collateralized by
vehicles. 85,423
Contract payable, $4,444 credited monthly against gas
purchases, due July 1997, collateralized by certificate of
deposit. 66,667
----------
Total unaffiliated parties 1,984,892
Related Parties:
Note payable to the Company's president and CEO. Interest at
6%, annual ,000 principal payments of $65,000 due January
1997 and 1998. The note is convertible into common stock at
$5.00 per share and is collateralized by equipment. 130,000
Unsecured notes payable to the Company's president and CEO
and various entities ,717 controlled by him. Interest at 8%
to 10% with principal and interest due January 1, 1997. 176,717
Accrued interest 32,024
----------
Total related parties 338,741
----------
Total long-term debt 2,323,633
Less current maturities (1,100,474)
---------
Total long-term debt, less current maturities $1,223,159
=========
F-16
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In March 1995, the credit agreement related to the
$1,762,802 note payable described above was restructured
whereby the Company is required to pay monthly principal
payments of the greater of $81,905 through September 1996
($69,167 from October 1996 to maturity in September 1997),
or 40% of net oil and gas revenues from properties acquired
in the Skaer acquisition plus $60,000 per month. Since
September 1995, when this provision was first applied, the
Company has been making principal payments of $81,905. In
connection with the restructuring, the interest rate was
also increased to prime plus 3%.
In May 1995, the Company retired $22,500 of the
convertible debentures discussed in Note 3 and renegotiated
the terms of the remaining $70,000 of debentures to provide
for an extended maturity date of May 1996. The conversion
price was reduced from $6.25 to $.85 per share of common
stock, and the interest rate was increased from 10% to 12%.
The aggregate maturities of long-term debt are as
follows:
<TABLE>
<CAPTION>
Year Ending Related
December 31, Parties Others Total
------------ ---------- ---------- ----------
<S> <C> <C> <C>
1996 ........ $ -- $1,100,474 $1,100,474
1997 ........ 273,741 864,465 1,138,206
1998 ........ 65,000 14,204 79,204
1999 ........ -- 5,749 5,749
---------- ---------- ----------
$ 338,741 $1,984,892 $2,323,633
========== ========== ==========
</TABLE>
4. INCOME TAXES:
The Company's income tax benefit consists of the
following:
Years Ended December 31,
-------------------------
1995 1994
---------- -----------
Current provision ....... $ (21,000) $ --
Deferred benefit ........ 400,000 900,000
-------- ---------
Total ..... $ 379,000 $ 900,000
========= ==========
F-16
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the income tax benefit at the
statutory rate to the income tax benefit reported in the
accompanying financial statements is as follows:
<TABLE>
<CAPTION>
Years Ended December 31,
------------------------
1995 1994
<S> <C> <C>
--------- ---------
Computed tax benefit at the
expectd statutory rate ............ $ 389,100 $ 886,400
State income taxes and other ........... 10,900 13,600
Federal income taxes assessed
in audit ......................... (21,000) --
Total ..................... $ 379,000 $ 900,000
</TABLE>
Deferred tax assets (liabilities) as of December 31,
1995 are comprised of the following:
<TABLE>
<CAPTION>
<S> <C>
Long-term Assets:
Net operating loss carryforwards .................. $ 3,350,000
Tax credit carryforwards .......................... 140,000
Percentage depletion carryforwards ............... 60,000
Other ............................................. 45,000
-----------
Total ...................................... 3,595,000
Less valuation allowance ............................ (1,385,000)
-----------
2,210,000
Long-term liability for property and equipment ........ (2,210,000)
-----------
Net long-term liability ...................... $ --
===========
</TABLE>
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.
At December 31, 1995, the Company has net operating
loss carryforwards for income tax purposes of approximately
$9,000,000, which expire primarily in 2008 through 2010.
Approximately $4,000,000 of these net operating losses are
subject to limitations under IRS Sections 382 and 384. These
losses may only offset future taxable income to the extent
of approximately $350,000 per year and generally may not
offset any gain on the sale of assets acquired in the
acquisition of Skaer Enterprises, Inc. Additionally, the
Company has tax credit carryforwards at December 31, 1995,
of approximately $140,000 and percentage depletion
carryforwards of approximately $150,000.
F-17
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. COMMITMENTS AND CONTINGENCIES:
Gas Contracts - The Company operates a natural gas processing
plant (the "Gas Plant"). The Gas Plant has a contract with a
major utility which calls 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 is on an MMBTU basis above the Colorado
Interstate Gas Company's Northern Pipeline "spot" price. The
contract has an expiration date of June 30, 1996.
Historically, the price paid under this contract has
been at a premium above the market and has allowed the
Company to conduct its marketing and trading activities. The
loss of this market premium would substantially curtail or
eliminate the Company's marketing and trading activities,
which may have a material adverse impact on the Company's
future operations. Management intends to enter into
negotiations with the major utility as soon as possible in
order secure a favorable long-term contract and to explore
alternatives with other purchasers of natural gas in order
to maximize the Company's natural gas revenue.
The Company also has a contract with an independent
producer that requires purchases of gas quantities at a
fixed margin per MMBTU for any difference between plant
sales and the contract volumes with the utility. These
contracts also expire in June 1996, and are subject to
standard industry cancellation or interruption provisions.
The revenue and corresponding costs incurred pursuant to
these contracts have been reflected as Gas Marketing and
Trading in the consolidated statements of operations.
Leases - The Company leases its office facilities under
noncancellable operating leases. The total minimum
commitments under these leases amounted to approximately
$42,000 as of December 31, 1995. Total rent expense under
all operating leases for the years ended December 31, 1995
and 1994, was $90,569 and $62,423, respectively.
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.
Profit Sharing Plan - The Company has established a 401(k) profit
sharing plan that covers all employees with one month 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 $2,996 and
$9,648 for the years ended December 31, 1995 and 1994,
respectively.
F-18
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 condition or results of
operations.
6. STOCKHOLDERS' EQUITY:
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 "Preferred Stock").
At December 31, 1995, the Preferred Stock had a liquidation
preference of $11.25 per share ($10 liquidation value plus $1.25 of
dividends in arrears), and each share of Preferred Stock was
convertible into 2.812 shares of common stock and warrants to purchase
2.812 common shares. Each warrant currently entitles the holder to
purchase one share of common stock at $5.00 per share through 1996,
and at $6.00 per share through August 13, 1998, when the warrants
expire. The Preferred Stock will automatically convert into common
stock if the reported sale of Preferred Stock equals or exceeds $13.00
per share for ten consecutive days. The Company may redeem the
Preferred Stock at $10.00 per share plus any dividends in arrears, at
any time after August 13, 1995. Each share of Preferred Stock is
entitled to receive dividends at 10% per annum when, as and if
declared by the Company's Board of Directors. Unpaid dividends accrue
and are cumulative.
At December 31, 1994, there were 1,157,780 shares of Preferred
Stock issued and outstanding. The Board of Directors elected to forego
the declaration of the regular quarterly dividend for the fourth
quarter of 1994, resulting in preferred dividends in arrears of $.25
per share for an aggregate of $289,742 at December 31, 1994.
In February 1995, the Company completed a tender offer to the
preferred stockholders whereby the holders of the Preferred Stock were
given the opportunity to convert each share of Preferred Stock and all
accrued and undeclared dividends (including the full dividend for the
quarters ended December 31, 1994 and March 31, 1995) into 4.5 shares
of the Company's common stock. As a result of this tender offer,
933,492 shares of the preferred stock converted into 4,200,716 shares
of the Company's common stock. Additionally, pursuant to the terms of
the Preferred Stock, during 1995 holders of 21,600 shares of Preferred
Stock elected to convert their shares into 56,739 shares of common
stock.
F-19
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In connection with the tender offer, for each share of preferred
stock that was converted, warrants to purchase 2.625 shares of the
Company's common stock were issued, resulting in the issuance of
warrants for an aggregate of 2,450,000 shares. The exercise price of
the warrants is $5.00 per share through 1996 and increases to $6.00
per share through August 13, 1998 when the warrants expire.
Through December 31, 1995, the Board of Directors has elected to
forego the declaration of the regular quarterly dividend for five
consecutive quarters resulting in dividends in arrears of
approximately $253,000 ($1.25 per share) related to 202,688
outstanding shares of Preferred Stock. The terms of the Preferred
Stock provide that the holders of the Preferred Stock are entitled to
elect two additional directors if the aggregate amount of unpaid
dividends equals six quarterly dividends on such shares. The Company
is also prohibited from entering into certain transactions without an
affirmative vote of the preferred stockholders. Otherwise, the
preferred stockholders have no voting rights.
Private Placements - On September 30, 1994, the Company completed a private
placement of a total of $1,454,750 (including a total of $231,250
purchased by officers, directors, and affiliates) of 12% Convertible
Unsecured Promissory Notes (the "Notes") from which the Company
realized net proceeds of approximately $1,307,403. Effective September
30, 1994, the Notes were automatically converted into 909,219 shares
of the Company's Common Stock, with a fair value of $1.60 per share.
In October 1994, the Company completed a private placement of
289,125 shares of Common Stock at a price of $1.60 per share resulting
in gross proceeds of $462,600 (net proceeds of approximately
$357,500).
In July 1995, the Company completed a private placement of
250,000 "Units" at $1.50 each. Each unit consists of two shares of
common stock and one warrant to purchase one share of common stock at
$1.25 per share. The warrants are exercisable after July 31, 1995,
expire on April 30, 1997, and are redeemable by the Company at $0.25
per warrant. As of December 31, 1995, the Company had received
proceeds of $306,250 related to this private placement and the
remaining $68,750 was received in February 1996.
Settlement of Trade Payable - In August 1995, the Company agreed to issue
80,000 shares of its common stock, including 16,794 shares previously
held in treasury, in settlement of a trade payable for approximately
$58,000.
Conversion of Related Party Notes Payable - In September 1994, $150,000 of
uncollateralized 8% notes payable to related entities controlled by
the Company's President and CEO were converted into 93,750 shares of
the Company's common stock, with a fair value of $1.60 per share.
StockOption and Stock Appreciation Right Plans - The Company is authorized
to grant options to pur chase up to 550,000 shares of the Company's
common stock under its existing stock plans. The exercise price of
each option granted must equal or exceed the fair market value of the
Company's common stock on the date the options are granted. The
options expire five years from the date of grant and to date no
options have been exercised.
F-20
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In May 1995, the Board of Directors agreed to cancel options for
224,000 shares which were exercisable at prices ranging from $2.25 to
$7.91 per share. The Board concurrently granted new options for
295,600 shares at an exercise price of $.83 per share. Additionally,
options for 99,000 shares expired in 1995, primarily due to the
termination of employees. At December 31, 1995, outstanding stock
options are summarized as follows:
<TABLE>
<CAPTION>
NON-STATUTORY OPTIONS INCENTIVE STOCK OPTIONS
----------------------------- ---------------------------------
Exercise Number Expiration Exercise Number Expiration
Price of Shares Date Price of Shares Date
-------- --------- ---------- --------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Director ............. $ 7.19 4,000 June 1996 $ -- -- --
Director ............. 3.44 5,000 March 1997 -- -- --
Director ............. 2.94 15,000 October -- -- --
1998
Officers and directors .83 112,000 May 2000 .83 183,600 May 2000
Officers and directors -- -- .70 120,000 June 2000
Employees ............ -- -- .70 20,000 June 2000
------- -------
Total ............. 136,000 323,600
======= =======
</TABLE>
Warrants - During 1995, the Board of Directors granted warrants to purchase
200,000 shares to a consulting firm. Warrants for 50,000 shares are
exercisable for $.85 per share and the remaining 150,000 shares are
exercisable for $1.25 per share. These warrants become exercisable in
increments of 50,000 shares when the average trading price (for a
period of 20 business days) of the Company's common stock amounts to
$1.00, $1.50, $1.75, and $2.00. If not previously exercised, these
warrants expire on December 31, 1996.
In June 1995, the Company granted warrants to consultants for
40,000 shares of common stock. The warrants are exercisable for $.70
per share and expire in June 2000. In August 1995, the Company granted
warrants to consultants for a total of 100,000 shares of common stock.
The warrants are exercisable for $.75 per share and, if not previously
exercised, they will expire in August 2000.
In connection with private placements in 1994, the Company issued
warrants to purchase 83,188 shares of the Company's Common Stock at an
exercise price of $1.92 per share to brokers who sold the Notes and
shares in the private placements. Subject to certain conditions, the
warrants are redeemable at the option of the Company for $.25 per
warrant. If not previously exercised, the warrants expire in August
1998.
F-21
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In May 1995, the Board of Directors canceled warrants to a
consultant to purchase 15,000 shares of the Company's common stock for
$6.00 per share. The Board concurrently granted a new warrant to this
individual to purchase 18,000 shares of common stock for $.83 per
share. If not previously exercised, this warrant expires in May 2000.
In connection with the Company's 1993 Preferred Stock offering,
the Company issued warrants to the underwriter to purchase 90,000
shares of preferred stock at $12.00 per share. If not previously
exercised, these warrants will expire in August 1998. In 1993, the
Company also granted warrants to a consultant for the purchase of
60,000 shares of common stock. The warrants are exercisable for $6.00
per share and expire in November 1996.
Non-Qualified Stock Options - In November 1994, the Company granted
non-qualified stock options to a former director to purchase 50,000
shares of common stock at approximately $3.34 per share. If not
previously exercised, these options expire in November 1999. During
1995, the Company granted non-qualified options to a former director
to purchase 77,000 shares of common stock for approximately $3.61 per
share. If not previously exercised, these options expire in April
2000.
Also see Note 9 for common stock, warrants, and options issued
after year-end.
7. 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, 1995,
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 differs
from carrying value for the following instruments:
<TABLE>
<CAPTION>
Carrying Estimated
Value Fair Value
---------- -----------
<S> <C> <C>
Long-term portion of accrued production
taxes ................................. $374,652 $330,000
Notes payable to related parties ............ 338,741 300,000
</TABLE>
Fair value of the above debt instruments was estimated using a
market rate of interest equivalent to that charged by the Company's
primary lender.
8. SIGNIFICANT CONCENTRATIONS:
Substantially all of the Company's accounts receivable at
December 31, 1995, 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
F-22
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
or negatively, since these entities may be similarly affected by
changes in economic or other conditions. In determining whether or not
to require collateral from a customer or joint interest owner, the
Company analyzes the entity's net worth, cash flows, earnings, and
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 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.
At December 31, 1995, the Company had a receivable from a major
public utility for $506,000, which was collected in January 1996. For
the years ended December 31, 1995 and 1994, the Company had natural
gas sales to this customer which accounted for 46% and 53% of total
revenues, respectively. The Company is in the process of renegotiating
its contract with this purchaser (see Note 5).
A substantial portion of the Company's debt financing shown in
Note 3 was obtained from a single lender. At December 31, 1995, the
Company has temporary cash investments of $470,000 with a single
financial institution.
9. SUBSEQUENT EVENTS (UNAUDITED):
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 initial term
of the agreement is for two years and provides for minimum monthly
cash payments of $17,500. However, these payments can be terminated if
the Company has not completed a private placement of convertible debt
securities for at least $1,000,000 (the "Series A Financing") within
90 days of the date of the related private placement memorandum.
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 $.75 per share and they expire
in March 2001. However, the Company may elect to cancel warrants for
500,000 shares if the Series A Financing is not completed by September
1996. If the Series A Financing is completed, but a second offering
for at least $2 million of debt and/or equity securities (the "Series
B Financing") is not completed by March 1997, the Company may elect to
cancel warrants for 250,000 shares. If the Consultant fails to meet
other performance criteria set forth in the agreement, the Company may
elect to cancel warrants for an additional 250,000 shares in March
1998. If the Consultant meets the performance criteria, the Consultant
can elect to extend the agreement for one year.
F-23
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company also agreed to pay the Consultant a fee equal to 2%
of the net proceeds from the Series A and B Financings and up to 7%
from 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 Series A
Financing, Series B financing, exercise of warrants, or other debt or
equity financings that may be consummated during the term of the
agreement.
Upon completion of the Series A Financing, the Company agreed to
use its best efforts to increase the size of its Board of Directors
whereby two representatives of the Consultant may at their election,
become members of the Board. Upon completion of the Series B
Financing, the Company and the Consultant may mutually agree on the
addition of another Board member who is affiliated with a substantial
equity investor in the Company.
Common Stock, Stock Options, and Warrants - In March 1996, the
Board of Directors granted 38,050 shares of the Company's common stock
to officers and employees as compensation for past services. The
estimated fair value of the shares of approximately $35,000 is
included in accrued expenses at December 31, 1995.
In March 1996, the Board also granted options and warrants to
purchase common to officers, directors, employees, and a consultant.
All of the options and warrants expire in March 2001 and are
summarized as follows:
<TABLE>
<CAPTION>
OPTIONS WARRANTS
------------------- -------------------
Exercise Number Exercise Number
Price of Shares Price of Shares
--------- --------- -------- ---------
<S> <C> <C> <C> <C>
President ................. $ 1.00 8,900 $ .75 101,500
Other Officers ............ 1.00 56,000 -- --
Directors ................. 1.00 4,000 -- --
Employees ................. 1.00 17,500 -- --
Consultant ................ -- -- .75 40,000
</TABLE>
10. SUPPLEMENTAL OIL AND GAS DISCLOSURES:
CostsIncurred 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, 1995 and 1994:
<TABLE>
<CAPTION>
1995 1994
---------- ----------
<S> <C> <C>
Property acquisition costs ..... $ 60,000 $ 2,000
Development costs .............. 161,000 1,923,000
Exploration costs .............. -- 213,000
---------- ----------
Total ...................... $ 221,000 $2,138,000
========== ==========
</TABLE>
F-24
<PAGE>
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, 1995 and 1994 are presented below.
<TABLE>
<CAPTION>
1995 1994
---------- -----------
<S> <C> <C>
Oil and gas sales:
LGPCo ..................................... $ 373,000 $ 484,000
Unaffiliated entities ..................... 2,251,000 2,737,000
----------- -----------
Total oil and gas sales ................ 2,624,000 3,221,000
Exploration and abandonment expenses ........... (19,000) (316,000)
Production costs ............................... (1,617,000) (2,190,000)
Depletion, depreciation and impairment ......... (742,000) (1,818,000)
Imputed income tax benefit (provision) ......... (91,000) 408,000
----------- -----------
Results of operations from oil and
gas producing activities .................. $ 155,000 $ (695,000)
=========== ===========
</TABLE>
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 independent petroleum engineers. Reserve esti mates require
substantial judgment on the part of petroleum engineers resulting in
imprecise determina tions, 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 30% of the Company's proved developed
reserves are currently non-producing as certain wells require
workovers, recompletions, or construction of a gathering system to an
existing gas pipeline at an estimated total cost of $1.5 million. All
proved oil and gas reserves are located in the United States. The
following table presents estimates of the Company's net proved oil and
gas reserves, and changes therein for the years ended December 31,
1995 and 1994.
F-25
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in Net Quantities of Proved Reserves (Unaudited)
<TABLE>
<CAPTION>
1995 1994
----------------------------- -----------------------------
Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf)
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Proved reserves, beginning of year ..................... 1,352,000 5,724,000 1,045,000 5,854,000
Purchase of minerals in place ........................ 38,000 447,000 -- --
Sale of minerals in place ............................ (14,000) (107,000) -- --
Extensions, discoveries, and
other additions .................................... 82,000 382.000 401,000 1,987,000
Revisions of previous estimates ...................... (43,000) (98,000) 61,000 (1,574,000)
Production ........................................... (121,000) (497,000) (155,000) (543,000)
---------- ---------- ---------- ----------
Proved reserves, end of year ........................... 1,294,000 5,851,000 1,352,000 5,724,000
========== ========== ========== ==========
Proved developed reserves, end of year ................. 1,014,000 4,302,000 794,000 4,206,000
========== ========== ========== ==========
</TABLE>
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.
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.
F-26
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following summary sets forth the Company's future net cash
flows relating to proved oil and gas reserves as of December 31, 1995
and 1994 based on the standardized measure prescribed in Statement of
Financial Accounting Standards No. 69.
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
Future cash inflows .................................................... $ 32,620,000 $ 32,422,000
Future production costs ................................................ (13,871,000) (14,085,000)
Future development costs ............................................... (3,269,000) (4,321,000)
Future income tax expense .............................................. (1,800,000) (3,363,000)
------------ ------------
Future net cash flows ............................................ 13,680,000 10,653,000
10% annual discount for estimated
timing of cash flow ............................................... (5,200,000) (4,153,000)
------------ ------------
Standardized Measure of Discounted
Future Net Cash Flows ............................................. $ 8,480,000 $ 6,500,000
============ ============
</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, 1995 and 1994:
<TABLE>
<CAPTION>
1995 1994
------------ -----------
<S> <C> <C>
Standardized measure, beginning of year .... $ 6,500,000 $ 5,294,000
Sale of oil and gas produced, net of ....... 1,000)
production costs ...................... (1,006,000) (1,031,000)
Purchase of minerals in place .............. 228,000 --
Sale of minerals in place .................. (80,000) --
Net changes in prices and production costs . 617,000 1,871,000
Net changes in estimated development costs . 785,000 (1,257,000)
Revisions of previous quantity estimates ... (803,000) (171,000)
Discoveries, extensions, and other additions 620,000 2,018,000
Accretion of discount ...................... 650,000 529,000
Changes in income taxes, net ............... 969,000 (753,000)
----------- -----------
Standardized Measure, end of year .......... $ 8,480,000 $ 6,500,000
=========== ===========
</TABLE>
F-28
<PAGE>
PEASE OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
The Company's independent engineer has prepared the following
estimates for the reserves related to these activities as of December
31, 1995.
Future net revenues, discounted at 10% .......... $1,068,000
==========
Net quantities:
Natural gas (mcf) ............................ 3,035,000
Liquids (bbls) .............................. 371,000
F-28
<PAGE>
Pease Oil and Gas Company
and Subsidiaries
Consolidated Financial Statements
December 31, 1995
<PAGE>
CONSULTING AGREEMENT
This Consulting Agreement (this "Agreement") is made and entered into as of
March 9, 1996 by and between Pease Oil and Gas Company, or the surviving entity
in any merger of the Company or any entity which receives all or substantially
all of its assets (hereinafter referred to as the "Company"), and Beta Capital
Group, Inc., or any entity or individuals which or who receive all or
substantially all of its assets (hereinafter referred to as the "Consultant").
RECITALS
WHEREAS, Consultant has certain experience and contacts associated with
developing and implementing capitalization plans, including utilization of debt
capital in business operations; and
WHEREAS, the Consultant and the Company over the past six months have met and
discussed potential opportunities that may exist, and as a result of those
discussions agreed in concept to the mutual promises and covenants contained
hereon on February 12, 1996; and
WHEREAS, the Company wishes to engage the Consultant as described herein to
assist the Company in the business operations of the Company and Consultant
desires to provide such services to the Company;
NOW, THEREFORE, in consideration of the mutual promises and covenants herein
contained, the parties hereby memorialize those concepts agreed to on February
12, 1996 and agree as follows:
1. CONSULTING SERVICES
Attached hereto as Exhibit A is a description of the services to be
provided by the Consultant hereunder (the "Consulting Services"). Consultant
hereby agrees to utilize its best efforts in performing the Consulting Services;
however, the Consultant makes no warranties, representation or guarantees to the
other regarding the funds to be raised, any appreciation of Company stock price,
the results of the Consulting Services to be provided herein.
2. TERM OF AGREEMENT
Subject to the following, this Agreement shall be in full force and
effect commencing on the earlier of March 9, 1996 or the signing of this
Agreement and concluding two years thereafter, unless extended as hereinafter
provided.
(A) Cancellation by Company. This Agreement can be unilaterally
canceled by the Company on 15 days written notice if (a) 90 days after
the date a private offering memorandum for use in the Series A offering
contemplated by Exhibit A is completed by the Company, at least $1.0
million in gross proceeds has not been raised by the Company, (b) if
after one year from the effective date of this contract, at least
one-half
<PAGE>
of the Company's presently outstanding callable $1.25 warrants are not
callable and have not been callable during the past year because the
market price of the Company's common stock has not increased to a point
where the Company is entitled to call the warrants for redemption, (c)
if after one year from the effective date of this contract, (i) the
Series A warrants described in Exhibit A are not callable or have not
been callable during the past year because the market price of the
Company's common stock has not increased to a point where the Company
is entitled to call the warrants for redemption, and (ii) at least $0.5
million in gross proceeds has not been received by the Company through
the exercise of warrants to purchase Company common stock unless the
Company elects not to call or interferes with the call of the warrants,
or (d) if the total consulting fees paid under Exhibit B, including
compensation for the broker relations consultant, as described in
Section 10, and the reimbursed expenses actually paid by the Company
under Exhibit C, exceed 15% of the sum of (i) the net amounts received
by the Company from the Series A and Series B financings described or
contemplated in Exhibit A and (ii) from exercise of any warrants. The
provisions set forth in 2(A)(d) shall be computed on an annual basis
commencing on the anniversary date of this Agreement. In the event the
Consultant has received funds in excess of 15% as described above, the
Company shall give Consultant written notice, and Consultant will have
30 days to cure the overpayment. Furthermore, the provisions set forth
in 2(A)(d) shall be subject to additional authorized expenditures as
approved and ratified prior to expenditure by the Company.
(B) Extension by Consultant. This Agreement can be unilaterally
extended by Consultant for up to one year (until February 28, 1999) if
at least $5.0 million in gross proceeds has been raised by the Company
from the sale of Series A or Series B debt and/or the exercise of
Series A or Series B warrants as described or contemplated on Exhibit A
and (i) the Company's reported common stock market price has been at
least $3.00 per share for two consecutive weeks between June 1, 1997
and February 28, 1998 and (ii) the Company has received at least an
additional $500,000 in gross proceeds from the exercise of warrants
described or contemplated on Exhibit A or other equity investment in
the Company.
(C) Other Terminations. Either party shall have the right to terminate
this Agreement without notice in the event of bankruptcy, insolvency,
or assignment for the benefit of creditors of the other party or, with
10 days prior written notice, if the other party shall have failed to
comply with its obligations under the terms of this Agreement,
including, without limitation, any responsibilities for payment of fee
or performance of services set forth herein.
3. TIME DEVOTED BY CONSULTANT
It is expected that Steve Antry, President of Consultant, shall
initially devote a majority of his time to the Consulting Service described in
this Agreement, in particular during the time when the Company is undertaking to
offer and sell the Series A and Series B debt described on Exhibit A or other
2
<PAGE>
alternate financing arrangements to which the parties mutually agree;
thereafter, the Consultant shall devote such time as is reasonably deemed
necessary by the Consultant and the Company to perform the obligations of
Consultant hereunder. Consultant reasonably shall make available the services of
Steve Antry during the term of this Agreement, unless Mr. Antry has suffered
death or disability and the Company has raised at least $6.0 million from the
financings described or contemplated in Exhibit A and/or from the exercise of
warrants or from other equity investments. It is agreed by the parties that the
amount of time devoted to the business of the Company by other partners,
independent contractors or employees of the Consultant may vary from time to
time and that other employees of the Consultant may provide consulting services
for other clients during the term of this Agreement. Consultant shall provide
written reports to the Board of Directors of the Company describing the
consulting services performed for the Company on a monthly or other basis as may
be mutually agreed upon by the Consultant and the Company.
4. PLACE WHERE SERVICES WILL BE PERFORMED
The Consultant will perform most services in accordance with this
Agreement at offices of the Consultant. Consultant will be available, at the
expense of the Company, to perform services at such other places as the
Consultant and Company shall mutually agree, given the nature and extent of the
services described on Exhibit A.
5. COMPENSATION TO CONSULTANT
The Consultant's compensation for the Consulting Services performed
under this Agreement shall be the fees and compensation described on Exhibit B.
All direct expenses related to the Consulting Services being performed incurred
by Consultant and the broker relations consultant described in Section 10 in
performing the Consulting Services hereunder shall be reimbursed by the Company,
including, but not limited to, telephone and other communications expenses
incurred by Consultant or the broker relations consultant, photocopying,
printing and postage; and for travel, lodging and entertainment. Consultant
agrees to obtain prior approval from the Company for any single expense in
excess of $1,000 which is not itemized on the two-year reimbursable expense
budget set forth on Exhibit C. In addition, Consultant agrees to obtain prior
approval, at least in concept, for any single expense or activity in excess of
$1,000 regardless of whether such expense is itemized on the two-year
reimbursable expense budget set forth on Exhibit C. Company and Consultant agree
that all the services of the broker relations consultant, and cash monthly
consulting fees and reimbursed expenses as budgeted on Exhibit C will not exceed
15% of the Company's net proceeds from the Series A and Series B financings
described or contemplated on Exhibit A, and other financings that may be
contemplated and mutually agreed upon, plus the net proceeds to the Company from
the exercise of any warrants. In the event this Agreement is extended for an
additional year by the Consultant under Section 2, it is agreed that the Exhibit
C budget shall serve as the reimbursable expense budget for the third year,
subject to the 15% limitation described in this Section 5. For the purposes of
this calculation expenditures and proceeds are agreed to be cumulative for the
term of the contract.
3
<PAGE>
The Company shall pay separately the costs and expenses it incurs in
connection with the financing activities described on Exhibit A, including the
Company's legal fees and independent due diligence reports or evaluations.
The Company shall pay consulting fees to Consultant on a monthly basis,
in advance, by the first day of each month, with the first monthly fee of
$12,500 due on signing of this Agreement. The Company shall prepay the last
month's consulting fee at the earlier of (1) receipt of proceeds of at least
$12,500 from the exercise of Team Warrants (as described in Section (5) of
Exhibit B) or (2) upon receipt by the Company of at least $1.0 million in gross
proceeds from the exercise of outstanding Warrants or proceeds from the Series A
and/or Series B debt financings or, other alternate financings that may be
contemplated and mutually agreed upon.
Company and Consultant agree that any additional consulting or similar
services performed by the Consultant for the Company not contemplated by this
Agreement or agreed to by the parties shall be negotiated before performance and
any fee or compensation to be earned by Consultant from the Company or
obligation to pay by Company shall be set forth in a writing signed by the
obligated party. This includes any acquisitions that may result from
introduction by Consultant or Consultant's contacts inclusive of and not limited
to those defined as Consultant's confidential information in Section 7.
6. INDEPENDENT CONTRACTOR
Consultant and the broker relations consultant shall each be, and shall
each be deemed to be, an independent contractor in the performance of the
Consulting Services under this Agreement. Consultant shall have no power to
enter into any agreement on behalf of, or otherwise bind, Company. Consultant
shall be free to pursue, conduct and carry on for its own account (or for the
account of others) such activities, employments, ventures, businesses, or other
pursuits as may determine in its sole, absolute and unfettered discretion,
provided that, Consultant agrees not to engage in any activity, venture,
business or pursuit that is harmful to the business of the Company. Nothing
contained in this Agreement shall be construed to imply that Consultant, or any
employee, agent or other authorized representative of Consultant, is a partner,
joint venturer, agent, officer, employee, or other representative of Company and
neither the Consultant nor any representative of the Consultant shall represent
to anyone to the contrary; provided that Steve Antry may become a director of
the Company as described in Section 11.
7. CONFIDENTIAL INFORMATION
Consultant recognizes that, in the course of providing services to
Company hereunder, Company may divulge information relating to its business
affairs, financial affairs and future plans that Company considers confidential
and proprietary (collectively, "Confidential Information"), and Consultant
agrees that Consultant will use such Confidential Information only within the
scope of Consultant providing services to Company hereunder, and will neither
disclose to, nor permit, any person or entity, other than Company and its
principals, agents, employees and
4
<PAGE>
other paid experts and professionals who agree to be bound by the terms of this
paragraph, to view or have access to the Confidential Information.
Notwithstanding anything contained herein to the contrary, the term
"Confidential Information" shall not include the following: (i) information
previously known to Consultant, (ii) information rightfully received by
Consultant from a third party holding such Confidential Information legally and
without a continuing restriction on its use, or (iii) information which is or
becomes a part of the public domain through no breach by Consultant of this
Agreement. Notwithstanding anything to the contrary hereunder, Consultant shall
not be liable for (i) any inadvertent or accidental disclosure if Consultant has
exercised the same degree of care as Consultant would take to preserve or
safeguard his own proprietary information, or (ii) disclosure of the
Confidential Information which is within the public domain at the time of
disclosure, or is or becomes publicly available without breach of this Agreement
by Consultant, or is received by Consultant from a third party holding the
Confidential Information legally and having the legal right to disseminate it
without breach of this Agreement by Consultant or is disclosed by Consultant
with the written approval of the President of Company, or is disclosed by
Company to others on a nonrestricted basis. Upon expiration of this Agreement,
Consultant shall, at the request of Company, return all Confidential Information
and other materials belonging to Company which are in Consultant's possession.
The Consultant and the Company acknowledge that each will have access
to proprietary information regarding their respective business operations and
agree to keep all such information secret and confidential and not to use or
disclose any such information to any individual or organization without the
non-disclosing party's prior written consent. Consultant hereby designates its
sources of funding, sources of acquisitions, advisors, agents identified by
Consultant to Company as Consultant's confidential information. The parties
agree that from time to time Consultant or the Company may designate certain
additional information as confidential for purposes of this Agreement.
8. NON-CIRCUMVENTION AND NON-DISCLOSURE
The Company hereby irrevocably agrees not to circumvent or disclose to
others, either directly or indirectly, the clients, sources of funding, sources
of acquisitions, advisers, agents, brokers, associates or other contacts that
Consultant or its affiliates have, provided that the Company may make disclosure
required by law and shall notify Consultant before any such disclosure is made.
The Company hereby confirms that the identity of any or all of the
entities introduced to the Company by Consultant which did not have a previous
relationship with the Company or have not been previously engaged in business
negotiations with the Company are considered proprietary to the Consultant and
its affiliates and shall remain so for the term of this Agreement and for one
year beyond the term of this Agreement. The Company agrees not to complete a
financing with any of such entities unless this Agreement is in force. The
Company and the Consultant agree that financings not described on Exhibit A
completed with persons or entities not first identified to the Company by
Consultant or completed without substantial involvement or assistance by the
5
<PAGE>
Consultant shall not be considered proprietary to the Consultant. For instance,
bank financings by the Company, financings completed through relationships or
assistance by persons not associated or affiliated with Consultant, mezzanine
financings with which Consultant had no material involvement and similar
financings would not be covered by this Section 8 of this Agreement. The parties
agree that any financings not contemplated by this Agreement for which
Consultant may claim compensation shall be discussed by the parties before
involvement by the Consultant and the Company's agreement to deem such
financings covered by this Agreement shall be reduced to writing.
If the Company completes a financing within one year after it has
terminated this Agreement in accordance with its rights under subparagraph (A)
of Section 2 above, or, should circumvention to any of such entities be
attempted by the Company or should the Company seek to disclose the identity of
any such entities for purposes inconsistent with this Agreement, the Consultant,
in addition to having the right to invoke other legal or equitable remedies,
shall be compensated by the Company in an amount equal to what such compensation
would have been had this Agreement been in full force and effect at the time of
such action by the Company, or if larger, the amount which Consultant would have
received had such financing with the other entity been completed with the advise
and assistance of Consultant. Any amount payable hereunder shall be due
immediately upon any attempted circumvention and/or disclosure together with any
court costs, attorney fees, or other charges or damages reasonably incurred in
connection with enforcement of rights under this paragraph.
9. INDEMNIFICATION
The Company hereby agrees to indemnify and hold Consultant harmless
from any and all liabilities incurred by Consultant under the Securities Act of
1933, as amended, and the Securities Exchange Act of 1934, as amended
(collectively referred to as the "Act"), the various state securities acts, or
otherwise, insofar as such liabilities arise out of or are based upon (i) any
material misstatement or omission contained in any offering documents provided
by the Company (ii) any actions by the Company, direct or indirect, in
connection with any offering by the Company, in violation of any applicable
federal or state securities laws or regulations, or (iii) a breach of this
Agreement by the Company. The Company's obligation to indemnify Consultant shall
not extend to any liability under the Act or any state securities act arising or
alleged as a result of unlawful activities by Consultant or activity alleged not
to be in compliance with the requirements of the Act or various state securities
acts.
Consultant hereby agrees to indemnify and hold the Company harmless
from any and all liabilities incurred by the Company under the Act, the various
state securities acts, or otherwise, insofar as such liabilities arise out of
and are based upon (i) any actions by Consultant, direct or indirect, in
connection with any offering by the Company, in violation of any applicable
federal or state securities laws or regulations, or (ii) any breach of this
Agreement by Consultant.
6
<PAGE>
10. BROKER RELATIONS CONSULTANT
The Company agrees that Steve Fischer, or another individual agreed on
by the Company, shall be retained by Consultant as an independent contractor of
Consultant to perform as broker relations services to benefit the Company. The
Company shall reimburse Consultant for $5,000 per month for these additional
services for a period of up to two years commencing when $1.0 million in gross
proceeds is received by the Company from the Series A debt financing described
or contemplated on Exhibit A. The Company agrees that the arrangement for the
broker relations consultant will be extended for an additional one year if the
Consultant extends this Agreement as authorized under Section 2(B) above.
11. BOARD SEATS
The Company agrees to use its best efforts to increase the size of its
Board of Directors at the earliest practicable time (including using its best
efforts to obtain shareholder approval of an amendment to its Articles of
Incorporation if it becomes necessary to increase the size of the Board of
Directors above 10 members) and to add Mr. Richard Houlihan and Mr. Steve Antry
as directors of the Company if such persons are willing to serve as directors at
the time that the Series A financing described on Exhibit A is completed or
anytime thereafter during the term of this Agreement. Upon completion of the
Series B debt financing described on Exhibit A, the Company and the Consultant
shall mutually agree on one additional Board Member affiliated with a
substantial equity investor in the Company to become a director at the earliest
practicable time. The Company agrees to purchase of appropriate Directors and
Officers Liability Insurance Policy to provide coverage for directors of the
Company, including coverage for expenses and liabilities incurred in connection
with defense or payment of a claim under the Act, provided that appropriate
coverage acceptable to the Board of Directors of the Company can be obtained for
an annual premium not greater than $50,000 per year. Such insurance shall be
acquired, if available, by the end of 1996. The Board of Directors of the
Company will consider compensation for outside directors of the Company with a
view toward increasing compensation to a level comparable to what other
similarly sized public companies pay outside directors.
12. COMPANY MATTERS
The Company specifically makes no warranties, representations or
guarantees to Consultant regarding the Company's business or its past, present
or future business plans.
13. MISCELLANEOUS
(A) Any controversy arising out of or relating to this Agreement or any
modification or extension thereof, including any claim for damages
and/or rescission, shall be settled by arbitration in Las Vegas, Nevada
in accordance with the Commercial Arbitration rules of the American
Arbitration Association before a panel of one arbitrator. The
arbitrator 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
7
<PAGE>
alteration, or modification. This Section 13 shall survive the
termination of the Agreement.
(B) This Agreement shall be binding upon and shall inure to the benefit
of the parties hereto, their heirs, administrators, successors and
assigns. This Agreement shall not be assignable by either party hereto
without the prior written consent of the other.
(C) This Agreement contains the entire understanding of the parties and
supersedes all prior agreements between them.
(D) In the event of a dispute related to or arising from the terms of
this Agreement, the prevailing party shall be entitled to all
attorney's fees and costs.
(E) This Agreement shall be constructed and interpreted in accordance
with and governed by the laws of the State of California.
(F) No supplement, modification or amendment of this Agreement shall be
binding unless executed in writing by the parties. No waiver of any of
the provisions of this Agreement shall be deemed, or shall constitute,
a waiver of any other provision, whether or not similar, nor shall any
waiver constitute a continuing waiver. No waiver shall be binding
unless executed in writing by the party making the waiver.
(G) If any provision hereof is held to be illegal, invalid or
unenforceable under present or future laws, effective during the term
hereof, such provisions shall be fully severable. This Agreement shall
be construed and enforced as if such illegal, invalid or unenforceable
provision had never comprised a part hereof, and the remaining
provisions hereof shall remain in full force and effect and shall not
be affected by the illegal, invalid or unenforceable provision or by
its severance here from.
(H) The obligation of the Company to pay compensation to Consultant
under this Agreement is subject to the ratification and approval of
this Agreement by a majority of the directors of the Company at a
regular or special meeting of the Board of Directors. If such approval
has not been received by March 15, 1996, either party may, upon notice
to the other, terminate the Agreement with no further obligation.
IN WITNESS WHEREOF, the parties hereto have placed their signatures hereon on
the day and year first above written.
PEASE OIL AND GAS COMPANY BETA CAPITAL GROUP, INC.
By: /s/ Willard H. Pease, Jr. /s/ Steve Antry
------------------------- -----------------------------
Willard H. Pease, Jr., President Steve Antry, President
8
<PAGE>
EXHIBIT A
DESCRIPTION OF BETA CAPITAL'S CONSULTING SERVICES
Consultant shall perform the following services pursuant to the terms of this
Agreement:
(1) Locating potential sources of debt and equity capital which is presently
contemplated to include the provisions set forth below. The parties may
mutually agree to revise the nature and terms of these financings and
references in the Agreement shall be modified consistent with any such
revisions.
(a) Private Bond "Series A"
o $1.0 million minimum to $1.5 million maximum of 10%
convertible debt.
o 10% commission will be paid to retail broker or brokers
(with 5% warrants at $2.00).
o Five year term.
o Interest only for five years; principal due at the end of
five years.
o Convertible at $3.00 per share into public stock at
investor's option.
o Bond will a call feature by the Company of $3.00 if the
stock trades at $4.00 per share for five consecutive
business days.
o Each $4.00 of convertible debt sold will include three
warrants exercisable at $1.25, callable at $1.75 (the call
feature will not be enforceable before six months after
issuances).
o Underlying securities will be registered (piggyback
registration) at the Company's next registration.
o Bond A to become senior debt pari passu to Bond B when bank
debt repaid (accomplished via proceeds of Bond B).
o The initial $1.0 million is an immediate raise (targeted 30
days after offering memorandum is prepared by legal
counsel).
(b) Registered Bond "Series B"
o $2.5 million minimum $5.0 million maximum 10% senior debt.
o 10% commission will be paid to retail broker or brokers
(with 5% warrants at $2.00).
o Five year term.
o Interest only for five years; principal due at the end of
five years.
o Convertible at $4.00 per share into public stock at
investor's option.
o Bond will have a call feature by the Company of $4.00 if the
stock trades at $5.00 per share for five consecutive days.
o One warrant for each $2.00 sold. Exercise price will be 25%
premium above the market price at close of offering.
Callable at a 50% premium above market when trading is at
that level for five consecutive days
o Underlying securities will be registered (shelf
registration).
Exhibit A, Page 1
<PAGE>
o Bond A to be made senior debt pari passu to Bond B when bank
debt repaid (accomplished via proceeds of Bond B).
(2) Coordinating and assisting in the preparation of financing offering
documentation;
(3) Utilizing Consultant's broker-dealer database and network;
(4) Performing ongoing marketing efforts via selected licensed brokers in
connection with the raising of capital;
(5) Monitoring and assisting Company in development of road show presentations
and meetings for purposes of raising capital;
(6) Identification of Market Markers;
(7) Performing ongoing marketing efforts via selected licensed brokers in
connection with stock promotion; and
(8) Participation of Steve Antry at meetings of the Board of Directors, when
practicable. It is understood that no director's fees or other compensation
will be paid to Mr. Antry or Consultant for the participation of Mr. Antry
at meetings of the Board of Directors regardless of whether Mr. Antry or
Beta serves as a consultant or as an advisor to the Board of Directors.
Exhibit A, Page 2
<PAGE>
EXHIBIT B
TERMS OF COMPENSATION
The Consultant's compensation hereunder shall be divided into the
following components:
(1) Private Financing Compensation: Consultant shall receive an
amount equal to 2% of the gross amount of all private equity
and/or debt financing received directly or indirectly by the
Company during the term of this Agreement if the financing is
(a) one of the financings described on Exhibit A, (b) the
receipt of proceeds from exercise of warrants, or (c)
Consultant is the identifying or procuring cause of the
financing, or (d) any financing not contemplated by this
Agreement if the Company has agreed to pay the compensation.
The foregoing compensation shall be payable when the Company
receives the equity or debt financing. Up to one-third can be
assigned by Consultant to the broker relations consultant.
(2) Public Financing Compensation: Consultant shall receive an
amount equal to 2% of the amount of any public offering as a
nonrefundable expense allowance on each public equity or debt
financing which is commenced during the term of this Agreement
if the financing is (a) one of the financings described on
Exhibit A, (b) the receipt of proceeds from the exercise of
warrants, or (c) Consultant is the identifying or procuring
cause of the financing, and (d) any financing not contemplated
by this Agreement if the Company has agreed to pay the
compensation. Up to one-third can be assigned by Consultant to
the broker relations consultant. The timing of payment of this
nonaccountable expense allowance will be discussed at the
onset of each offering, but will never be later than 50% at
the escrow break, and 50% thirty days thereafter.
(3) Consulting Fee: A monthly consulting fee equal to $12,500 per
month earned upon the effective date of the contract and
payable on the first of each month with the exception of first
and last month's fees due upon signing as follows: $12,500 at
signing (first month), and $12,500 at the earlier of receipt
of (1) proceeds from the exercise of at least $12,500 from the
exercise of Team Warrants, or (2) $1,000,000 of any gross
proceeds.
(4) Bonus Fee: A 5% Bonus Fee will be paid to Consultant for each
warrant exercise, inclusive of existing warrants, of which up
to one-third can be assigned to the broker relations
consultant. This fee will be paid to Consultant at the time
the warrants are exercised during the term of this Agreement
and for up to six months after the expiration or termination
of this Agreement if the stock price was at a level entitling
the Company to call the warrants during the term of this
Agreement.
(5) Equity Compensation: One million common stock purchase
warrants exercisable at $0.75 per share will be granted to
Consultant upon signing this Agreement, of which up to 50% are
assignable to other team members and certain key brokers.
Exhibit B, Page 1
<PAGE>
Shares of common stock issuable upon exercise of these
warrants will be included as "piggyback" in the shelf
registration described on Exhibit A and the warrants shall
have a five year term, commencing on the date of this
Agreement and shall include the following cancellation
provisions:
WARRANTS CANCELLATION PROVISIONS
(a) 250,000 Not cancelable.
(b) 250,000 If $1.0 million in gross proceeds in the Series A
financing has not been raised within six months from the
effective date of this Agreement, the warrant shall be
deemed cancelled.
(c) 250,000 If $1.0 million gross proceeds from Series A
financing has not been raised within six months from the
effective date or if $2.0 million of gross proceeds from the
Series B financing (or any agreed alternative) is not raised
within one year of the completion of $1.0 million of gross
proceeds from the Series A financing or if the Agreement is
cancelled under Section 2(A) prior to raising $2.0 million
in Series B financing (or agreed upon alternative), this
warrant shall be deemed cancelled.
(d) 250,000 If the consulting agreement is not extended into
year three under Section 2(B) of the Agreement, this warrant
shall be deemed cancelled.
(6) In the event the Company chooses not to accept or otherwise
takes action (other than action required under applicable
state corporate law or the Act or the Securities Exchange Act
of 1934 upon the written advice of Company counsel, unless
Consultant's counsel disagrees in writing with the advice)
which has the effect of preventing a proposed financing or the
stock price appreciation goals from occurring, or otherwise
terminates this Agreement except in accordance with the terms
of this Agreement, all warrants shall be immediately vested.
Exhibit B, Page 2
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT C
PEASE OIL AND GAS COMPANY
ANNUAL PROJECTED REIMBURSABLE EXPENSES
<S> <C>
BETA TRAVEL EXPENSES:
Two Conferences ........................................... $ 20,000
Boston/New York roadshows ................................. 8,000
Six other major city corporate presentations .............. 14,000
Due diligence to Newport Beach, California or
Grand Junction, Colorado or corporate presentations
by outside participants (average 6 trips per annum
6,000
OTHER MARKETING EXPENSES:
Phone and fax charges ..................................... 15,000
(Salaries and commissions to telemarketers and
staff paid by BCG, Inc.; refers to direct charges
only)
Marketing materials and supplies .......................... 10,000
Initial mailout ........................................... 5,000
Subsequent mailouts ....................................... 15,000
Local PR .................................................. 12,000
--------
105,000
10% contingency fees ...................................... 10,500
--------
Total estimated expenses ........................................... $115,500
========
</TABLE>
Exhibit C, Page 1
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 677,275
<SECURITIES> 0
<RECEIVABLES> 1,014,759
<ALLOWANCES> 51,444
<INVENTORY> 532,289
<CURRENT-ASSETS> 2,319,473
<PP&E> 15,007,007
<DEPRECIATION> 4,643,648
<TOTAL-ASSETS> 13,439,726
<CURRENT-LIABILITIES> 2,819,653
<BONDS> 0
0
2,027
<COMMON> 708,134
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 13,439,726
<SALES> 8,934,138
<TOTAL-REVENUES> 9,040,260
<CGS> 7,355,942
<TOTAL-COSTS> 7,355,942
<OTHER-EXPENSES> 4,425,675
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 306,435
<INCOME-PRETAX> (1,144,436)
<INCOME-TAX> (379,000)
<INCOME-CONTINUING> (765,436)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (765,436)
<EPS-PRIMARY> (0.42)
<EPS-DILUTED> (0.42)
</TABLE>
