Edgar Filing: PYR ENERGY CORP

U.S. 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 August 31, 2004

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________________ to _________________

Commission File No. 0-20879

PYR ENERGY CORPORATION
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(Name of small business issuer in its charter)

Maryland 95-4580642
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(State or jurisdiction of incorporation or (I.R.S. Employer
organization) Identification No.)

1675 Broadway, Suite 2450, Denver, CO 80202
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(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (303) 825-3748

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Name of each exchange on which registered
$.001 Par Value Common Stock American Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act:
None
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(Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such report), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-B (ss. 229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-KSB or any amendment to this Form 10-KSB.

The registrant's revenues for the fiscal year ended August 31, 2004 were
$863,087. As of November 17, 2004, the registrant had 31,564,426 common shares
outstanding, and the aggregate market value of the common shares held by
non-affiliates was approximately $18,751,862*. This calculation is based upon
the closing sale price of $0.96 per share on November 17, 2004.

* Without asserting that any of the issuer's directors or executive
officers, or the entities that own 2,978,428 and 7,141,329 shares of common
stock are affiliates, the shares of which they are beneficial owners have been
deemed to be owned by affiliates solely for this calculation.

TABLE OF CONTENTS
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Page
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PART I.........................................................................1

ITEM 1 and ITEM 2. DESCRIPTION OF BUSINESS AND PROPERTIES..................1

ITEM 3. LEGAL PROCEEDINGS..............................................21

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............21

PART II.......................................................................21

ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND SMALL BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES.......21

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS.....23

ITEM 7. FINANCIAL STATEMENTS...........................................30

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE............................30

ITEM 8A. CONTROLS AND PROCEDURES........................................30

ITEM 8B. OTHER INFORMATION..............................................31

PART III......................................................................31

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
PERSONS; COMPLIANCE WITH SECTION 16(I) OF THE EXCHANGE ACT.....31

ITEM 10. EXECUTIVE COMPENSATION.........................................33

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS.....................35

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................37

ITEM 13. EXHIBITS.......................................................37

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.........................38

SIGNATURES....................................................................39

CONSOLIDATED FINANCIAL STATEMENTS............................................F-1

PART I

ITEM 1 and ITEM 2. DESCRIPTION OF BUSINESS AND PROPERTIES

General

PYR Energy Corporation (referred to as "PYR," the "Company," "we," "us" and
"our") is an independent oil and gas exploration and production company, engaged
in the exploration, development and acquisition of crude oil and natural gas
reserves. Our current focus is on the Rocky Mountain, Texas and Gulf Coast
regions as described below. During the fiscal years ended August 31, 2003 and
2004, we focused our exploration efforts and advanced technical expertise on the
pre-drill phases of our high potential exploration projects in the Rocky
Mountain region. In November 2003, we signed an agreement with industry partners
to test our projects in the Wyoming Overthrust. The Mallard Prospect commenced
drilling in mid-July 2004. The Cumberland Prospect commenced drilling in early
November 2004. We have partnered with Suncor Energy Natural Gas America, Inc.
(SENGAI) for our Rogers Pass Project in the Montana Foothills and expect a well
to be spud by year end. In May 2004, we acquired interests from Venus
Exploration, Inc. ("Venus") in certain producing properties and undeveloped
acreage for approximately $3,230,000 (excluding acquisition expenses and subject
to retention, by the Venus Exploration Trust, of a net profits interest covering
the non-productive exploration projects) with estimated proved reserves of 4.78
Bcfe. This equates to $0.67 per Mcf, with a PV-10 value of $6.94 million. The
Venus assets acquired include interests in 80 non-operated wells in Utah,
Oklahoma and Texas. New drilling and workovers have been conducted since the
acquisition date and include two recent discoveries. As a result of the
acquisition of the Venus assets, PYR has undertaken a transformation from a
development stage company to a producing oil and gas company. Previously our
primary drilling activity had been in the San Joaquin Basin of California and on
our East Lost Hills project.

The Company was incorporated in March 1996 in the state of Delaware under
the name Mar Ventures Inc. Effective as of August 6, 1997, the Company purchased
all the ownership interests of PYR Energy, LLC, an oil and gas exploration
company. On November 12, 1997, the name of the Company was changed to PYR Energy
Corporation. Effective July 2, 2001, the Company was re-incorporated in Maryland
through the merger of the Company into a wholly owned subsidiary, PYR Energy
Corporation, a Maryland corporation. On February 18, 2004, PYR Cumberland LLC,
PYR Mallard LLC, and PYR Pintail LLC were formed as wholly owned subsidiaries of
PYR Energy Corporation. The purpose of these entities is to own and develop
certain assets related to designated individual exploration projects.

The Company's offices are located at 1675 Broadway, Suite 2450, Denver,
Colorado 80202. The telephone number is (303) 825-3748, the facsimile number is
(303) 825-3768 and the Company's web site is www.pyrenergy.com. The Company's
periodic and current reports filed with the Securities and Exchange Commission
can be found on the Company's website.

Developments Since Beginning of Fiscal 2004

The following is a summary of the current status of our exploration projects:

Wyoming Overthrust Prospects:

In December 2003, we entered into an agreement with two private oil and gas
exploration companies (the "Participants") covering two of our exploration
projects in the Overthrust of southwestern Wyoming.

The first agreement relates to the Mallard Prospect, which is located
adjacent to the south end of the Whitney Canyon - Carter Creek field. The
agreement requires the Participants to drill the initial test well at the
Mallard Prospect to earn part of our acreage position within a designated area
of mutual interest ("AMI"). We currently control 4,160 net leasehold acres
within the AMI. The Participants have paid us approximately $450,000 in prospect
fees and pro-rata development costs. The Mallard well started drilling in
mid-July and intermediate casing was set to 9,735 feet in the Thaynes Formation.
The Bureau of Land Management ("BLM") has suspended drilling activities at
Mallard, effective December 1, 2004, due to wildlife critical winter range
restrictions. As a result, the well will be temporarily suspended and secured in
compliance with applicable federal and state regulations, until the wildlife
restrictions are lifted in mid - 2005. We are participating with a 5% working
interest in the drilling of Mallard, and will be carried to casing point, at an
estimated total depth of 15,500 feet, for an additional 23.75% working interest.
After casing point, we will have a 28.75% working interest in the initial test
well and all subsequent wells in the prospect.

The second agreement relates to the Cumberland Prospect, which is also
located in the Overthrust of Southwestern Wyoming, approximately 5 miles
northeast of the Ryckman Creek field. We believe the Cumberland prospect is
geologically on trend with Nugget productive fields previously drilled and
produced by others. Drilling at the Cumberland prospect started in early
November 2004, and the well is currently drilling ahead. The Participants paid
us $186,016 in prospect fees and pro-rata development costs. An additional
$86,004 will be paid upon the well reaching casing point. We will participate
with a 10% working interest in the drilling, and will be carried for an
additional 22.5% working interest to casing point in the initial test well.
After casing point, we will have a 32.5% working interest in the initial well
and all subsequent wells in the Prospect. The anticipated total depth of the
well is estimated to be 10,600 feet. We control 6,233 net leasehold acres within
the Cumberland area of mutual interest.

We have recently leased approximately 1,820 net acres, covering the
majority of the abandoned Ryckman Creek field, in the Overthrust of southwestern
Wyoming. Ryckman Creek, located 5 miles southwest of our Cumberland prospect,
was discovered in 1975 and produced approximately 250 Bcfe prior to abandonment.
We believe that significant remaining recoverable gas reserves were stranded in
Ryckman Creek upon abandonment. Due to winter activity restrictions, it is
anticipated that a well may be drilled at Ryckman Creek in mid-2005.

Montana Foothills Project:

In March 2004, we signed an Exploration Option Agreement with a subsidiary
of Suncor Energy, Incorporated, covering our Rogers Pass exploration project in
the foothills of west-central Montana. We currently control approximately
241,800 gross and 226,300 net leasehold acres in the Rogers Pass project.
Pursuant to our agreement with the subsidiary of Suncor Energy, Suncor Energy
Natural Gas America, Inc. ("SENGAI"), SENGAI paid us a $500,000 option fee for a
technical evaluation period of up to three months. On August 31, 2004 SENGAI
exercised its option to drill an initial test well at Rogers Pass, and paid us
$750,000 in the form of a prospect fee (received in September 2004). It is
anticipated that the initial test well will be spud prior to December 31, 2004.

Interests Acquired from Venus Exploration, Inc.:

In May 2004, we acquired interests in certain producing properties,
including 4.78 Bcfe of estimated proved reserves, for approximately $3,230,000
(excluding acquisition expenses and subject to retention, by the Venus
Exploration Trust, of a net profits interest covering the non-productive
exploration projects) from Venus Exploration, Inc. ("Venus"). This equates to
$0.67 per Mcf, with a PV-10 value of $6.94 million. The purchase also provides
for us to pay a net profits interest payable to the Venus Exploration Trust. The
net profits interest, which applies only to the exploration and exploitation
projects on the Venus acreage being acquired, varies from 25% to 50% with
respect to different Venus exploration and exploitation project areas, and
decreases by one-half of its original amount after a total of $3,300,000 in net
profits proceeds has been paid to the Trust. Venus was in Chapter 11 Bankruptcy,
and the properties were acquired through public auction as approved by the
United States Bankruptcy Court. To finance the purchase, we primarily used
existing cash reserves and also a portion of the proceeds from a private
placement of common stock.

Oil and gas interests acquired from Venus include producing oil and gas
properties, exploitation drilling projects, and exploration acreage. The Venus
assets acquired include interests in 80 non-operated wells in Utah, Oklahoma and
Texas. As of August 31, 2004, net production from the acquired properties was
approximately 1.42 MMcfe per day. Workovers of these existing properties
increased daily production by 392 Mcfe, or approximately 42%, during the fourth
quarter ended August 31, 2004.

Southeast Alberta Shallow Gas Redevelopment Project:

wellbores in the region were prematurely suspended and/or abandoned due to water
coning and production. These premature well abandonments suggest that
significant additional reserves may remain in a number of shallow gas reservoirs
in local areas within the Southeastern Alberta. To date, one well has been
re-completed as a producer and one well has been drilled and found to be
non-productive.

Markets and Major Customers

Sales from our ownership interests in producing properties to major
unaffiliated customers (customers accounting for 10 percent or more of gross
revenue), all representing purchasers of oil and gas, for the years ended August
31, 2004 and 2003 are as follows:

2004 2003
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ChevronTexaco 22% 100%
Shell Trading U.S. 20% -
Big West Oil LLC 16% -
Sunoco Inc. 13% -

In the fiscal years ended August 31, 2003 and 2002, sales of production
from our ownership interest in the ELH #1 well at East Lost Hills to
ChevronTexaco accounted for all our revenues. The May 2004 acquisition of
interests in certain producing properties from Venus Exploration, Inc. ("Venus")
resulted in the increase of oil and gas purchasers. We are not confined to, nor
dependent upon, any one purchaser or small group of purchasers. Accordingly, the
loss of a single purchaser would not materially affect the Company's business
because we believe we would be able to find another purchaser.

Employees and Office Space

At August 31, 2004, we had eight full time employees. We believe that our
relationship with our employees is satisfactory. None of our employees is
covered by a collective bargaining agreement. We lease approximately 3,800
square feet of office space in Denver, Colorado for our executive and
administrative offices. We have an additional office in San Antonio, Texas, in
which we lease approximately 4,300 square feet.

Business Strategy

Our objective is to increase stockholder value per share by adding
reserves, production, cash flow, earnings and net asset value. To accomplish
this objective, we intend to capitalize on our technical expertise in
identifying, evaluating and participating in the exploratory drilling and
development of deep, structurally complex formations. We also intend to build on
our experience and our competitive strengths, which include:

o our inventory of Texas, Rocky Mountain, and California exploration
projects,

o our control of pre-drill exploration phases,

o our expertise in advanced seismic imaging, and

o our ability to identify suitable development and exploitation drilling
opportunities.

To implement our strategy, we seek to:

o Execute Exploration Drilling on Our Undrilled Projects. We control
interests in several exploration projects in the Texas Gulf Coast,
select areas of the Rocky Mountains, and the San Joaquin Basin of
California. In the Rocky Mountains, our most notable projects are
Cumberland, Mallard, and Ryckman Creek located in southwestern
Wyoming, and our Montana Foothills project. We have recently commenced
drilling of our Mallard and Cumberland projects. After signing our
exploration agreement with SENGAI for our Montana Foothills project,
we expect SENGAI to commence drilling a well by year end. In the Texas
Gulf Coast, we have interests in several exploration projects and PUD
("Proved Undeveloped") locations related to recent discoveries to be
drilled in the future.

o Continue to Internally Generate Exploration Prospects. We believe that
by continuing to generate exploration prospects with a special
emphasis on applying our seismic expertise to deep, structurally
complex formations, we can identify prospects with significant oil and
gas reserve potential. We then assemble acreage positions on these
prospects. This enables us to control costs during the pre-drill
phases of exploration and to sell a portion of our interests to
industry participants, while potentially retaining a carried interest
in the initial exploratory drilling.

o Evaluate Low Risk, Shallow Exploitation and Development Drilling
Opportunities. As part of our ongoing strategy, we are evaluating
lower risk drilling opportunities relative to our higher risk,
internally generated, exploration projects. If found to be
appropriate, these opportunities can provide the Company with suitable
internal rates of return on investment, geographic and risk
diversification, and exposure to reserves and potential cash flow. To
this end, while we have evaluated numerous opportunities, we have
recently signed joint venture agreements that provide the Company with
shallow gas re-completion opportunities in southeast Alberta, Canada.
We continue to review and evaluate additional development and
exploitation opportunities as they arise.

o Continue A Disciplined Acquisition Process. As part of our ongoing
strategy, we diligently look for properties or opportunities with
significant upside in our core areas. Through our personal contacts,
industry knowledge and expertise, we look to find under-worked
properties or missed structures, that with little cost, but strong
operatorship, may be productive.

Significant Projects

Our exploration activities are focused primarily in select areas of the
Rocky Mountains, Texas and Gulf Coast, Southeast Alberta, and in the San Joaquin
Basin of California. Advanced seismic imaging of the structural and
stratigraphic complexities common to these regions provides us with the enhanced
ability to identify significant oil and gas reserve potential. A number of these
projects offer multiple drilling opportunities with individual wells having the
potential of encountering multiple reservoirs.

The following is a summary of our exploration areas and significant
projects. While actively pursuing specific exploration activities in each of the
following areas, we continually review additional opportunities in these core
areas and in other areas that meet our exploration criteria.

Rocky Mountain Exploration

Montana Foothills Project. This extensive natural gas exploration project,
located in west-central Montana, is part of the southern Alberta basin, and has
been classified as the southern extension of the Alberta Foothills producing
province. The USGS and numerous Canadian industry sources have estimated
significant recoverable reserves for the Montana portion of the Foothills trend.
Based on extensive geologic and seismic analysis, we have identified numerous
structural culminations of similar size, geometry, and kinematic history as
prolific Canadian foothills fields, such as Waterton and Turner Valley.

The geologic setting and hydrocarbon potential of this area was not
recognized by the industry until the early 1980s. At that time, a number of
companies initiated exploration efforts, including Exxon, Arco, Chevron, Amoco,
Conoco, and Unocal. This initial exploration phase culminated in a deep test by
Unocal, the Unocal #1-B30, drilled in 1989 to a depth of 17,817 feet, which was
plugged and abandoned after testing. Although this well was unsuccessful, recent
improvements in seismic imaging and pre-stack processing have resulted in our
belief that this test well was drilled based upon a misleading seismic image and
was located significantly off-structure. Within the Rogers Pass acreage block,
we have undertaken extensive seismic analysis and geological study, resulting in
the identification of multiple untested, prospective structures.

In March 2004, we signed an Exploration Option Agreement with a subsidiary
of Suncor Energy, Incorporated, covering our Rogers Pass exploration project We
currently control approximately 241,800 gross and 226,300 net leasehold acres in
the Rogers Pass project. Pursuant to our agreement with the subsidiary of Suncor
Energy, Suncor Energy Natural Gas America, Inc. ("SENGAI"), SENGAI has paid us a
$500,000 option fee for a technical evaluation period of up to three months. On
August 31, 2004 SENGAI exercised its option to drill an initial test well at
Rogers Pass, and paid us $750,000 in the form of a prospect fee (received in

September 2004). It is anticipated that the initial test well will be spud prior
to December 31, 2004. SENGAI will bear 100% of the costs of the well, to a depth
sufficient to evaluate the Mississippian, to earn a 100% working interest in
100,000 acres of the project area. SENGAI will have the option to pay a second
prospect fee of $1,250,000 and drill a second test well, to be spud by December
31, 2005. By paying this second prospect fee and bearing 100% of the costs of
the second well, SENGAI will earn a 100% working interest in the remaining
acreage within the project area. We will retain a 12.5% overriding royalty
interest, subject to amortized recovery of gas plant and certain transportation
costs, covering all earned acreage within the Rogers Pass project area.

Mallard Project. The Mallard project, located within the Overthrust Belt of
southwest Wyoming, is a sour gas and condensate exploration prospect in Uinta
County, Wyoming. We believe that Mallard is within the Paleozoic trend of
productive fields on the Absaroka thrust. Mallard directly offsets and is
adjacent to the giant sour gas field of Whitney Canyon-Carter Creek.

We interpret the Mallard prospect to occupy a separate fault block,
adjacent to the Whitney Canyon field, generated by a complex imbricated system
of faults splaying off of the Absaroka thrust. Paleozoic targets at the Mallard
prospect include the Mississippian Mission Canyon, as well as numerous secondary
objectives in the Ordovician, Pennsylvanian, and Permian sections.

The agreement we entered into with two private companies ("the
Participants") in December 2003 requires the Participants to drill the initial
test well at the Mallard Prospect to earn part of our acreage position within a
designated area of mutual interest. We currently control 4,160 net leasehold
acres within the AMI. The partners have paid us approximately $450,000 in
prospect fees and pro-rata development costs. The Mallard well started drilling
in mid-July. Intermediate casing was set to 9,735 feet in the Thaynes Formation.
The Bureau of Land Management has suspended drilling activities at Mallard,
effective December 1, 2004, due to wildlife critical winter range restrictions.
As a result, the well will be temporarily suspended and secured in compliance
with applicable federal and state regulations, until the wildlife restrictions
are lifted in mid - 2005. We are participating with a 5% working interest in the
drilling of Mallard, and will be carried to casing point, at an estimated total
depth of 15,500 feet, for an additional 23.75% working interest. After casing
point, we will have a 28.75% working interest in the initial test well and all
subsequent wells in the prospect.

Cumberland Project. The Cumberland project, located within the Overthrust
Belt of southwest Wyoming, is a gas-condensate exploration prospect in Uinta
County, Wyoming. Cumberland is at the northern end of the historically
productive Nugget trend on the hangingwall of the Absaroka thrust fault. We
believe that the prospect is along geologic trend of and just north of Ryckman
Creek field, which was discovered in 1975.

The Cumberland prospect can be best characterized as a classic hangingwall
anticlinal trap, similar to the many known Nugget sandstone accumulations that
have produced significant quantities of hydrocarbons from Pineview to Ryckman
Creek. The Cumberland culmination is the result of structural deformation
related to back-thrusting off of the Absaroka thrust, a similar geometry to that
exhibited at East Painter Reservoir field.

Drilling at the Cumberland prospect started in early November 2004, and the
well is currently drilling ahead. The partners paid us $186,016 in prospect fees
and pro-rata development costs. An additional $86,004 will be paid upon the well
reaching casing point. We will participate with a 10% working interest in the
drilling, and will be carried for an additional 22.5% working interest to casing
point in the initial test well. After casing point, we will have a 32.5% working
interest in the initial well and all subsequent wells in the Prospect. The
anticipated total depth of the well is estimated to be 10,600 feet. We control
6,233 net leasehold acres within the Cumberland area of mutual interest.

Ryckman Creek Project. We have recently leased approximately 1,820 net
acres, covering the majority of the abandoned Ryckman Creek field, in the
Overthrust of southwestern Wyoming. Ryckman Creek, located 5 miles southwest of
our Cumberland prospect, was discovered in 1975 and produced approximately 250
Bcfe prior to abandonment. We believe that significant remaining recoverable gas
reserves were stranded in Ryckman Creek upon abandonment. We are currently
analyzing production and geologic data to determine potential reserves in
multiple zones, including the Twin Creek, Nugget, and Thaynes Formations, in the
field. Due to winter activity restrictions, it is anticipated that a well may be
drilled at Ryckman Creek in mid-2005, and based on our analysis, we may decide
to sell part of our 100% working interest in the project.

Interests Acquired from Venus Exploration, Inc.:

In May 2004, we acquired interests from Venus Exploration, Inc. ("Venus")
in certain producing properties with estimated proved reserves of 4.784 Bcfe for
approximately $3,230,000 (excluding acquisition expenses and subject to
retention, by the Venus Exploration Trust, of a net profits interest covering
the non-productive exploration projects). This equates to $0.67 per Mcf, with a
PV-10 value of $6.94 million. The purchase also provides for us to pay a net
profits interest payable to the Venus Exploration Trust. The net profits
interest, which applies only to the exploration and exploitation projects on the
Venus acreage being acquired, varies from 25% to 50% with respect to different
Venus exploration and exploitation project areas, and decreases by one-half of
its original amount after a total of $3,300,000 in net profits proceeds has been
paid to the Trust. Venus was in Chapter 11 Bankruptcy, and the properties were
acquired through public auction as approved by the United States Bankruptcy
Court. To finance the purchase, we primarily used existing cash reserves and
also a portion of the proceeds from a private placement of common stock.

Oil and gas interests acquired from Venus include producing oil and gas
properties, exploitation drilling projects, and exploration acreage. The assets
acquired include interests in 80 non-operated wells in Utah, Oklahoma and Texas.
As of August 31, 2004, net production from the acquired properties was
approximately 1.42 MMcfe per day. Workovers of these existing properties
conducted since the acquisition date have increased daily production by 392
Mcfe, or approximately 42% during the fourth quarter ended August 31, 2004.

In Texas, we have interests in three projects that were drilled and
completed over this past summer. Two of the three wells, the Nome and Madison
Prospects, were completed as producers and are currently flowing to sales lines.
These two successful projects are, upon reaching payout, subject to a 50% net
profits interest payable to the Venus Exploration Trust.

Tortuga Grande prospect, located in east Texas, is a re-entry of an
existing well, drilled on a large turtle structure, to test the productivity of
the Cotton Valley Sand section at depths ranging from 13,000 to 14,500 feet.
Drilled originally in 1984 for deeper targets, the Brady #1 is the only deep
well on the structure, and had shows in the Cotton Valley Sand, but was never
fracture stimulated. Log analysis of the re-entry indicates that the well
contains approximately 322 feet of potential pay greater than 8% porosity. The
middle Cotton Valley Sand section was fracture stimulated and tested. Results of
the test were inconclusive and the partners continue to evaluate the test data.
The partners may decide at a future date to drill another well to test the
Cotton Valley within the project area. Should this occur, PYR would be
responsible for 20% of the costs of any additional well. In all additional
locations within the Tortuga Grande area of mutual interest, we will participate
with a cost bearing 20% working interest. We currently control approximately
5,600 net leasehold acres within the project.

Nome Field was discovered in 1994, and our interpretation of subsequently
acquired 3D seismic over the field indicates the presence of numerous
undeveloped fault blocks. Multiple structural closures and associated bright
spot locations have been identified at Nome based on the 3D seismic. PYR owns a
1.5% overriding royalty interest with an additional 8.33% working interest,
after project payout, in the project. Production in the Sun Fee #1 well, from
the upper Yegua, was initiated in late May 2004, and current well production has
stabilized at rates in excess of 11 MMcf/d with approximately 700 Bc/d. It is
estimated that the well has produced in excess of 1.5 Bcfe since inception.
After project payout, it is estimated that the well will add approximately
1MMcfe of net daily production to PYR, given current production rates. Although
we have yet to receive confirmation from the operator, we believe, based on
production levels and product prices, that the well and project have reached
payout, and that PYR is currently a working interest participant in the well. We
and our partners control approximately 4,200 acres of gross leasehold acres in
the project.

We are currently in dispute with the operator of the Sun Fee #1, Sampson
Lone Star L.P., concerning the pooling of certain lands into the production
unit. The pooling of these lands in which the Company does not own an interest,
comprises approximately 32% of the unit area, and may result in a reduction of
working interest and net revenue interest, relative to production from the Sun
Fee #1, attributable to the Company. If the current pooling were to stand, our
working interest in the well would be reduced from 8.33% to 5.66%. The Company
strongly believes that the lands in question are 'Non-Productive', and therefore
not eligible for pooling, based on all available geological, seismic, and
existing well data. As a result of this dispute, we will vigorously pursue and
defend our rights to our proportionate share of production and revenue from the
Sun Fee #1 with all legal avenues and remedies available. For this reason, the
Company has not signed any of the proposed production and revenue division
orders, and has not received any revenue, attributable to the well, to date. If

we undertake legal action against the operator relative to this issue, which we
currently intend, it may result in all revenues attributable to the Sun Fee #1
well being held in suspense until the legal action is completed. As of August
31, 2004, we accrued $68,478 in royalty interest revenues from the Sun Fee #1,
which began producing in late May 2004. The amount accrued reflects the royalty
interest percentage stated in the division order we received from the operator.

Madison prospect, located in the northern part of the Constitution Field,
is an exploitation project to test multiple sand intervals within the expanded
Yegua section, downthrown to a major growth fault. The prospect involves
sidetracking an existing cased hole updip to test multiple sand targets at a
location offsetting, but significantly high to Doyle sand production from the
Texaco #1 Doyle well within the field. The location is also offset to the Texaco
#1 Sanders Gas Unit well, which tested the Doyle sand interval at a rate of
1,176 Bc/d and 2.7 MMcf/d with no water. This well was subsequently plugged and
abandoned in the Doyle interval and never produced from the zone. The Sanders
Gas Unit location represents a proved undeveloped location for Doyle sand, 183
feet structurally high to the equivalent produced zone in the Texaco Doyle #1
well. The current well has been drilled to total depth, production casing has
been run, and the well is currently producing at restricted rates of
approximately 2.1 MMcf/d with 450 Bc/d. We own a 0.5% overriding royalty
interest that converts to a 12.5% working interest in the project after payout
of the initial test well. The operator has converted an existing wellbore within
the project area into a water disposal well, and is planning to drill an offset
development well within the next few months. The cost of the water disposal well
will be covered under the payout account, and we will participate for 12.5%
working interest in the drilling of the development well.

The Cotton Creek prospect, located in Jefferson County, Texas, is adjacent
to the Nome project. The prospect is located approximately one mile west of the
productive Sun Fee #1 well in the same structural fault block. PYR owns a 50%
working interest in the project and controls with its partner approximately 500
acres of leasehold.

The South Wharton prospect, located in Wharton County, Texas, is an
exploration project designed to test several stratigraphic intervals within the
expanded Yegua section in multiple structural features as defined by 3D seismic
data. Drilling targets are estimated to be at depths between 11,000 and 13,500
feet. PYR owns a 58% working interest in the project and in excess of 1,065
gross acres are currently under lease.

The Merganser prospect, located in Leon County, Texas, targets Cotton
Valley and Bossier sandstone reservoirs in an undrilled structural feature
defined by 3D seismic data. The prospect occupies a fault-bounded
salt-withdrawal trough resulting in potential significant thickening of the
Bossier and Cotton Valley sand sections. The prospect location is structurally
and stratigraphically downdip from Cotton Valley production as well as updip
from recent Bossier productive discoveries. PYR owns 100% of the prospect and
controls in excess of 1,500 gross acres of leasehold.

Southeast Alberta Shallow Gas Redevelopment Project:

We have entered into two joint ventures, the Atlas Joint Venture and the
Blue River Joint Venture, to redevelop shallow gas reserves in southeastern
Alberta, Canada. Southeastern Alberta has been the site of significant shallow
gas development drilling and production over the last two decades. We have
undertaken geologic and engineering studies of the region, and believe that many
wellbores in the region were prematurely suspended and/or abandoned due to water
coning and production. These premature well abandonments suggest the possibility
that significant additional reserves may remain in a number of shallow gas
reservoirs in local areas within the Southeastern Alberta.

We own a 5% working interest in the Atlas Joint Venture, which has
identified multiple potential re-entry and redevelopment opportunities for which
the Joint Venture intends to acquire the right to participate. The first well
has been re-entered, re-perforated, and completed in the upper Bow Island sand.
The well is currently producing into a sales line during long term testing. An
offset wellbore is currently being permitted for re-entry based on results from
the initial well. A number of other prospects are being leased and permitted at
this time.

We also own a 25% working interest in the Blue River Joint Venture, which
intends to operate in different areas of southeastern Alberta. Initial
investigation indicates multiple wells that exhibit an appropriate production
type decline curve, potential disposal interval, and gas reservoir. We are
currently undertaking detailed geologic and production analysis to refine
certain areas, for which the Joint Venture will undertake to acquire and develop
prospects for recompletion or drilling.

San Joaquin Basin, California

Wedge Prospect. This is a seismically identified Temblor prospect located
northwest of and adjacent to the East Lost Hills deep gas discovery. During the
first fiscal quarter of 2001, we acquired approximately 17 miles of proprietary,
high effort 2D seismic data and combined this data with existing 2D seismic data
in order to refine what we interpret as the up-dip extension of the East Lost
Hills structure. Our seismic interpretation shows that the same trend at East
Lost Hills extends approximately ten miles further northwest of the East Lost
Hills Area of Mutual Interest and can be encountered as much as 3,000 feet
higher. Despite repeated attempts to facilitate drilling interest at Wedge
during 2003, no industry interest was generated sufficient to put together a
drilling partnership during the year. As a result, PYR re-evaluated its acreage
position at Wedge and made the decision to consolidate the leasehold by
abandoning non-core prospect acreage in the project area. We currently control
approximately 3,500 gross and net acres here. Our approach is to sell down our
working interest to industry partners, and retain a 25% to 50% working interest
in this prospect.

Bulldog Prospect. This project is a 2D seismically identified natural gas
and condensate prospect located adjacent to the giant Kettleman North Dome field
in the San Joaquin Basin. This prospect can be best characterized as a classic
footwall fault trap, similar to the many known footwall fault trap accumulations
that have produced significant quantities of hydrocarbons throughout the San
Joaquin basin. During 2003, we re-evaluated our acreage position at Bulldog and
consolidated the leasehold by releasing approximately 3,200 non-core acres in
the project area. We currently control approximately 11,900 gross and net acres
here. We expect to sell down our working interest in this project and retain a
25% to 50% working interest in the prospect acreage.

Blizzard Prospect. This project is a 3D seismic derived exploration and
exploitation program offsetting the Rio Viejo field at the south end of the San
Joaquin Basin. A linear sand body, stratigraphically higher than any of the
productive Rio Viejo sands, has been identified, north of the field, on the
seismic data and represents an exploration opportunity for new reserves.
Additionally, analysis of the seismic data over the field suggests that up to
two additional undrilled field exploitation locations may exist. PYR owns 100%
of the prospect and controls approximately 2,500 net and gross acres.

Certain Definitions

Unless otherwise indicated in this document, oil equivalents are determined
using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate
or natural gas liquids so that six Mcf of natural gas are referred to as one
barrel of oil equivalent.

AMI. Area of Mutual Interest

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.

Bbl/d. One Bbl per day

Bc/d. Barrels of condensate daily

Bcf. One Billion cubic feet of natural gas at standard atmospheric
conditions.

Bcfe. One billion cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas
being equivalent to one barrel of oil.

Btu or British thermal unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.

Capital Expenditures. Costs associated with exploratory and development
drilling (including exploratory dry holes); leasehold acquisitions; seismic
data acquisitions; geological, geophysical and land related overhead
expenditures; delay rentals; producing property acquisitions; other
miscellaneous capital expenditures; compression equipment and pipeline
costs.

Carried through the tanks. The owner of this type of interest in the
drilling of a well incurs no liability for costs associated with the well
until the well is drilled, completed and connected to commercial
production/processing facilities.

Completion. The installation of permanent equipment for the production of
oil or natural gas.

Condensate. Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.

Developed Acreage. The number of acres that are allocated or assignable to
producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.

Exploitation. The continuing development of a known producing formation in
a previously discovered field. To make complete or maximize the ultimate
recovery of oil or natural gas from the field by work including development
wells, secondary recovery equipment or other suitable processes and
technology.

Exploration. The search for natural accumulations of oil and natural gas by
any geological, geophysical or other suitable means.

Exploratory Well. A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir, or to extend a known
reservoir.

Field. An area consisting of either a single reservoir or multiple
reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.

Finding and Development Costs. The total capital expenditures, including
acquisition costs, and exploration and abandonment costs, for oil and gas
activities divided by the amount of proved reserves added in the specified
period.

Gross Acres or Gross Wells. The total acres or wells, as the case may be,
in which we have a working interest.

Lease. An instrument which grants to another (the lessee) the exclusive
right to enter to explore for, drill for, produce, store and remove oil and
natural gas on the mineral interest, in consideration for which the lessor
is entitled to certain rents and royalties payable under the terms of the
lease. Typically, the duration of the lessee's authorization is for a
stated term of years and "for so long thereafter" as minerals are
producing.

Mcf. One thousand cubic feet of natural gas at standard atmospheric
conditions.

Mcf/d. One Mcf per day.

Mcfe. One thousand cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.

MMcf. One million cubic feet of natural gas.

Net Acres or Net Wells. A net acre or well is deemed to exist when the sum
of our fractional ownership working interests in gross acres or wells, as
the case may be, equals one. The number of net acres or wells is the sum of
the fractional working interests owned in gross acres or wells, as the case
may be, expressed as whole numbers and fractions thereof.

Operator. The individual or company responsible to the working interest
owners for the exploration, development and production of an oil or natural
gas well or lease.

Participant Group. The individuals and/or companies that, together,
comprise the ownership of 100% of the working interest in a specific well
or project.

PV-10 value. The present value of estimated future revenues to be generated
from the production of proved reserves calculated in accordance with SEC
guidelines, net of estimated lease operating expense, production taxes and
future development costs, using prices and costs as of the date of
estimation without future escalation, without giving effect to non-property
related expenses such as general and administrative expenses, debt service
and depreciation, depletion and amortization or federal income taxes and
discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of
the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for
the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with
reasonable certainty to be commercially recoverable in future years from
known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves (PUD). Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required for recompletion.

Re-entry. Entering an existing well bore to redrill or repair.

Reserves. Natural gas and crude oil, condensate and natural gas liquids on
a net revenue interest basis, found to be commercially recoverable.

Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible natural gas and/ or oil that is confined
by impermeable rock or water barriers and is separate from other
reservoirs.

Royalty. An interest in an oil and natural gas lease that gives the owner
of the interest the right to receive a portion of the production from the
leased acreage, or of the proceeds of the sale thereof, but generally does
not require the owner to pay any portion of the costs of drilling or
operating the wells on the leased acreage. Royalties may be either
landowner's royalties, which are reserved by the owner of the leased
acreage at the time the lease is granted, or overriding royalties, which
are usually reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.

Sidetrack. An operation involving the use of a portion of an existing well
to drill a second hole at some desired angle into previously undrilled
areas. From this directional start, a new hole is drilled to the desired
formation depth and casing is set in the new hole and tied back to the
casing from the existing well.

3-D Seismic. The method by which a three dimensional image of the earth's
subsurface is created through the interpretation of reflection seismic data
collected over a surface grid. 3-D seismic surveys allow for a more
detailed understanding of the subsurface than do conventional surveys and
contribute significantly to field appraisal, exploitation and production.

Undeveloped Acreage. Lease acres on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether or not such acreage
contains proved reserves.

Working Interest. An interest in an oil and gas lease that gives the owner
of the interest the right to drill and produce oil and gas on the leased
acreage and requires the owner to pay a share of the costs of drilling and
production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the
production accruing to the owners of royalties.

Production and Productive Wells

Acquisition of the Venus assets in May 2004 resulted in the addition of
production and reserves to the Company. The following table summarizes the
Company's productive wells as of August 31, 2004. Productive wells are producing
wells and wells capable of production. Gross wells are the total number of wells
in which the Company has an interest. Net wells are the sum of the Company's
respective fractional interests owned in the gross wells.

Productive Gas wells as of August 31, 2004

Gross Net
----- ---

Location Oil Gas Total Oil Gas Total

Canada - 1 1 - 0.05 0.05

California 3 - 3 0.24 - 0.24

Oklahoma 6 18 24 2.21 0.40 2.60

Texas 39 11 50 14.34 2.96 17.30

Utah 5 - 5 1.59 - 1.59
-------------------------------------------------------

TOTAL 53 30 83 18.38 3.41 21.78

Drilling Activities

During the past two fiscal years, we participated in the drilling of the
following exploration and development wells:

o During the fiscal year ended August 31 2004, we participated in the
drilling of two exploration wells in the expanded Yegua trend of South
Texas (carried), one exploration well in the Cotton Valley section of
East Texas, one exploration well in the Wyoming Overthrust (5% WI with
carry), and one exploration well in SE Alberta. As of November 2004,
the two exploration wells in South Texas have been classified as
discoveries and are producing into sales lines. The well in Wyoming
(Mallard Prospect) was drilling until the BLM suspended operations on
December 1, 2004, and the well in Southeast Alberta was tested and
determined to be non-productive. Additionally in fiscal year 2004, the
Company participated in several well workovers in Texas, Oklahoma, and
Utah.

o During the fiscal year ended August 31, 2003, we participated in the
drilling of an exploratory well in the DJ Basin of Colorado. This
well, which was drilled to a depth of approximately 4,800 feet was
found to contain non-commercial deliverability of hydrocarbons and was
plugged and abandoned.

Although there is no assurance that any additional wells will be drilled,
we anticipate we may drill additional exploration and development wells during
fiscal 2005 on our projects in the Texas Gulf Coast and Rocky Mountains. The
actual number of wells drilled will be dependent on several factors, including
the results of our ongoing exploration efforts and the availability of capital.

Reserves

August 31, 2004 estimates of `Total Proved' reserves were 5.502 Bcfe, which
represents a 15% increase versus May 31, 2004 estimates of 4.784 Bcfe. Increased
estimates for `total proved' reserves result from revisions on multiple
properties including new PDP and PUD additions related to exploration drilling
in the expanded Yegua trend of south Texas. For the year ended August 31, 2004,
proved developed producing reserves are estimated at 2.627 Bcfe, while proved
developed non-producing reserves are estimated at 1.575 Bcfe. Proved undeveloped
reserves are estimated at 1.302 Bcfe. At August 31, 2004, present value,
discounted at 10% ("PV-10") is $11,043,501 for total proved reserves, and
$5,333,374 for proved developed producing reserves, as compared with PV-10 at
May 31, 2004 of $6,941,526 for total proved reserves and $3,088,755 for proved
developed producing reserves. This increase in present value is a reflection of
higher prices at fiscal year end plus reserve additions and revisions. At August
31, 2003, the Company had no `Proved' reserves on its books.

Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment and the existence
of development plans. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of such estimates.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered. Further, the estimated future net
revenues from proved reserves and the present value thereof are based upon
certain assumptions, including geologic success, prices, future production
levels and cost that may not prove correct over time. Predictions about prices
and future production levels are subject to great uncertainty, and the
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they are based.

Property Impairment

The Company utilizes the full cost accounting method of accounting for oil
and gas activities and has separate cost centers for the United States and
Canada. As required for oil and gas companies that utilize the full cost method
of accounting, we capitalize all costs associated with acquisition, exploration
and development activities by cost center. In the United States, capitalized
costs, excluding costs of investments in unproved properties and major
development projects, are subject to a "ceiling test limitation." Under the
ceiling test, capitalized costs may not exceed an amount equal to the present
value, discounted at 10%, of the estimated future net cash flows from proved oil
and gas reserves. If capitalized costs exceed this ceiling, an impairment is
recognized. The Company's full cost center in Canada currently contains only
non-producing acreage (used for exploration and development activities). The
cost of these leases is included in unevaluated costs and is recorded at the
lower of cost or fair market value. If the capitalized cost of these properties
is less than the fair market value, an impairment is recognized.

For the year ending August 31, 2004, no property impairment charge was
recorded.

Acreage

We currently control through lease, farmout, and option, the following
approximate acreage position as detailed below:

Developed And Undeveloped Acreage

As of August 31, 2004

Gross Acres Net Acres

State Developed Undeveloped Developed Undeveloped
----------------------------------------------------------------

California 1,044 20,115 111 --

Canada 640 5,000 32 250

Louisiana -- 2,547 -- 2,317

Montana -- 241,800 -- 226,300

Oklahoma 5,659 -- 197 --

Texas 25,633 11,302 9,610 7,853

Utah 4,943 -- 1,504 --

Wyoming -- 10,553 -- 10,553
--------------------------------------------------------------

TOTAL 87,919 291,317 11,454 247,273
==============================================================

Competition

We compete with numerous companies in virtually all facets of our business,
including many companies that have significantly greater resources. These
competitors may be able to pay more for desirable leases and to evaluate, bid
for and purchase a greater number of properties than our financial or personnel
resources permit. Our ability to establish and increase reserves in the future
will be dependent on our ability to select and acquire suitable producing
properties and prospects for future exploration and development. The
availability of a market for oil and gas production depends upon numerous
factors beyond the control of producers, including but not limited to the
availability of other domestic or imported production, the locations and
capacity of pipelines, and the effect of federal and state regulation on that
production.

Government Regulation of the Oil and Gas Industry

General. Our business is affected by numerous laws and regulations,
including energy, environmental, conservation, tax and other laws and
regulations relating to the energy industry. Failure to comply with these laws
and regulations may result in the assessment of administrative, civil and
criminal penalties, the imposition of injunctive relief or both. Moreover,
changes in any of these laws and regulations could have a material adverse
effect on our business. In view of the many uncertainties with respect to
current and future laws and regulations, including their applicability to us, we
cannot predict the overall effect of such laws and regulations on our future
operations.

We do not currently operate any properties. We believe that operations
where we own interests comply in all material respects with applicable laws and
regulations and that the existence and enforcement of these laws and regulations
have no more restrictive an effect on our operations than on other similar
companies in the energy industry.

The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing and by reference to the full
text of the laws and regulations described.

Federal Regulation of the Sale and Transportation of Oil and Gas. Various
aspects of our oil and gas operations are or will be regulated by agencies of
the federal government. The Federal Energy Regulatory Commission, or FERC,
regulates the transportation and sale for resale of natural gas in interstate
commerce pursuant to the Natural Gas Act of 1938, or NGA, and the Natural Gas
Policy Act of 1978, or NGPA. In the past, the federal government has regulated
the prices at which oil and gas could be sold. While "first sales" by producers
of natural gas, and all sales of crude oil, condensate and natural gas liquids
can currently be made at uncontrolled market prices, Congress could reenact
price controls in the future. Deregulation of wellhead sales in the natural gas
industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted
the Natural Gas Wellhead Decontrol Act.

The Decontrol Act removed all NGA and NGPA price and non-price controls
affecting wellhead sales of natural gas effective January 1, 1993, and resulted
in a series of Orders being issued by FERC requiring interstate pipelines to
provide transportation services separately, or "unbundled," from the pipelines'
sales of gas and to provide open access transportation on a nondiscriminatory
basis that is equal for all natural gas shippers.

We do not believe that we will be affected by these or any other FERC rules
or orders materially differently than other natural gas producers and marketers
with which we compete.

The FERC also has issued numerous orders confirming the sale and
abandonment of natural gas gathering facilities previously owned by interstate
pipelines and acknowledging that if the FERC does not have jurisdiction over
services provided on those facilities, then those facilities and services may be
subject to regulation by state authorities in accordance with state law. A
number of states have either enacted new laws or are considering the adequacy of
existing laws affecting gathering rates and/or services. Other state regulation
of gathering facilities generally includes various safety, environmental, and in
some circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation. Thus, natural gas gathering may receive greater
regulatory scrutiny of state agencies in the future. Our anticipated gathering
operations could be adversely affected should they be subject in the future to
increased state regulation of rates or services, although we do not believe that
we would be affected by such regulation any differently than other natural gas
producers or gatherers. In addition, the FERC's approval of transfers of
previously-regulated gathering systems to independent or pipeline affiliated
gathering companies that are not subject to FERC regulation may affect
competition for gathering or natural gas marketing services in areas served by
those systems and thus may affect both the costs and the nature of gathering
services that will be available to interested producers or shippers in the
future.

We conduct certain operations on federal oil and gas leases, which are
administered by the Minerals Management Service, or MMS. Federal leases contain
relatively standard terms and require compliance with detailed MMS regulations
and orders, which are subject to change. Among other restrictions, the MMS has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend those regulations to prohibit the flaring of liquid hydrocarbons and
oil without prior authorization. Under certain circumstances, the MMS may
require any of our operations on federal leases to be suspended or terminated.
Any such suspension or termination could materially and adversely affect our
financial condition, cash flows and operations. The MMS issued a final rule that
amended its regulations governing the valuation of crude oil produced from
federal leases. This rule, which became effective June 1, 2000, provides that
the MMS will collect royalties based on the market value of oil produced from
federal leases, and was further modified by amendments to the June 2000 MMS
rules, effective July 1, 2004. Also, there is currently pending new proposed MMS
Federal Gas Valuation rules concerning calculation of transportation costs,
including the allowed rate of return in the calculation of actual transportation
costs in non-arm's length arrangements. We cannot predict whether this new gas
rule will become effective, nor can we predict whether the MMS will take further
action on oil and gas valuation matters. However, we do not believe that any
such rules will affect us any differently than other producers and marketers of
crude oil with which we will compete.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC, the MMS, state commissions and
the courts. We cannot predict when or whether any such proposals may become
effective. In the past, the natural gas industry has been heavily regulated.
There is no assurance that the regulatory approach currently pursued by various
agencies will continue indefinitely. Notwithstanding the foregoing, we do not
anticipate that compliance with existing federal, state and local laws, rules
and regulations will have a material or significantly adverse effect upon our
capital expenditures, earnings or competitive position. No material portion of
our business is subject to re-negotiation of profits or termination of contracts
or subcontracts at the election of the federal government.

State Regulation. Our operations also are subject to regulation at the
state and, in some cases, county, municipal and local governmental levels. This
regulation includes requiring permits for the drilling of wells, maintaining
bonding requirements in order to drill or operate wells and regulating the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled, the plugging and
abandonment of wells and the disposal of fluids used and produced in connection
with operations. Our operations also are or will be subject to various
conservation laws and regulations. These include (1) the size of drilling and
spacing units or proration units, (2) the density of wells that may be drilled,
and (3) the unitization or pooling of oil and gas properties. In addition, state
conservation laws, which frequently establish maximum rates of production from
oil and gas wells, generally prohibit the venting or flaring of gas and impose
certain requirements regarding the ratability of production. State regulation of
gathering facilities generally includes various safety, environmental and, in
some circumstances, nondiscriminatory take requirements, but (except as noted
above) does not generally entail rate regulation. These regulatory burdens may
affect profitability, but we are unable to predict the future cost or impact of
complying with such regulations.

Environmental Matters. Operations on properties in which we have an
interest are subject to extensive federal, state and local environmental laws
that regulate the discharge or disposal of materials or substances into the
environment and otherwise are intended to protect the environment. Numerous
governmental agencies issue rules and regulations to implement and enforce such
laws, which are often difficult and costly to comply with and which carry
substantial administrative, civil and criminal penalties and in some cases
injunctive relief for failure to comply. Some laws, rules and regulations
relating to the protection of the environment may, in certain circumstances,
impose "strict liability" for environmental contamination. These laws render a
person or company liable for environmental and natural resource damages, cleanup
costs and, in the case of oil spills in certain states, consequential damages
without regard to negligence or fault. Other laws, rules and regulations may
require the rate of oil and gas production to be below the economically optimal
rate or may even prohibit exploration or production activities in
environmentally sensitive areas. In addition, state laws often require some form
of remedial action, such as closure of inactive pits and plugging of abandoned
wells, to prevent pollution from former or suspended operations. Legislation has
been proposed in the past and continues to be evaluated in Congress from time to
time that would reclassify certain oil and gas exploration and production wastes
as "hazardous wastes." This reclassification would make these wastes subject to
much more stringent storage, treatment, disposal and clean-up requirements,
which could have a significant adverse impact on operating costs. Initiatives to
further regulate the disposal of oil and gas wastes are also proposed in certain
states from time to time and may include initiatives at the county, municipal
and local government levels. These various initiatives could have a similar
adverse impact on operating costs. The regulatory burden of environmental laws
and regulations increases our cost and risk of doing business and consequently
affects our profitability.

The federal Comprehensive Environmental Response, Compensation and
Liability Act, or CERCLA, also known as the "Superfund" law, imposes liability,
without regard to fault, on certain classes of persons with respect to the
release of a "hazardous substance" into the environment. These persons include
the current or prior owner or operator of the disposal site or sites where the
release occurred and companies that transported, disposed or arranged for the
transport or disposal of the hazardous substances found at the site. Persons who
are or were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for the federal or state
government to pursue such claims. It is also not uncommon for neighboring
landowners and other third parties to file claims for personal injury or
property or natural resource damages allegedly caused by the hazardous
substances released into the environment. Under CERCLA, certain oil and gas
materials and products are, by definition, excluded from the term "hazardous
substances." At least two federal courts have held that certain wastes
associated with the production of crude oil may be classified as hazardous
substances under CERCLA. Similarly, under the federal Resource, Conservation and
Recovery Act, or RCRA, which governs the generation, treatment, storage and
disposal of "solid wastes" and "hazardous wastes," certain oil and gas materials
and wastes are exempt from the definition of "hazardous wastes." This exemption
continues to be subject to judicial interpretation and increasingly stringent
state interpretation. During the normal course of operations on properties in
which we have an interest, exempt and non-exempt wastes, including hazardous
wastes, that are subject to RCRA and comparable state statutes and implementing
regulations are generated or have been generated in the past. The federal
Environmental Protection Agency and various state agencies continue to
promulgate regulations that limit the disposal and permitting options for
certain hazardous and non-hazardous wastes.

Our operations will involve the use of gas fired compressors to transport
collected gas. These compressors are subject to federal and state regulations
for the control of air emissions. Title V status for a facility results in
significant increased testing, monitoring and administrative and compliance
costs. To date, other compressor facilities have not triggered Title V
requirements due to the design of the facility and the use of state-of-the-art
engines and pollution control equipment that serve to reduce air emissions.
However, in the future, additional facilities could become subject to Title V
requirements as compressor facilities are expanded or if regulatory
interpretations of Title V applicability change. Stack testing and emissions
monitoring costs will grow as these facilities are expanded and if they trigger
Title V. We believe that the operator of the properties in which we have an
interest is in substantial compliance with applicable laws, rules and
regulations relating to the control of air emissions at all facilities on those
properties.

Although we maintain insurance against some, but not all, of the risks
described above, including insuring the costs of clean-up operations, public
liability and physical damage, there is no assurance that our insurance will be
adequate to cover all such costs, that the insurance will continue to be
available in the future or that the insurance will be available at premium
levels that justify our purchase. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on our
financial condition and operations.

Compliance with environmental requirements, including financial assurance
requirements and the costs associated with the cleanup of any spill, could have
a material adverse effect on our capital expenditures, earnings or competitive
position. We do believe, however, that our operators are in substantial
compliance with current applicable environmental laws and regulations.
Nevertheless, changes in environmental laws have the potential to adversely
affect operations. At this time, we have no plans to make any material capital
expenditures for environmental control facilities.

Title to Properties

As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time we acquire leases or enter into other
agreements to obtain control over interests in acreage believed to be suitable
for drilling operations. In many instances, our partners have acquired rights to
the prospective acreage and we have a contractual right to have our interests in
that acreage assigned to us. In some cases, we are in the process of having
those interests so assigned. Prior to the commencement of drilling operations, a
thorough title examination of the drill site tract is conducted by independent
attorneys. Once production from a given well is established, the operator will
prepare a division order title report indicating the proper parties and
percentages for payment of production proceeds, including royalties. We believe
that titles to our leasehold properties are good and defensible in accordance
with standards generally acceptable in the oil and gas industry.

Risk Factors

In evaluating the Company, careful consideration should be given to the
following risk factors, in addition to the other information included or
incorporated by reference in this annual report. In addition, the
"Forward-Looking Statements" located herein, describe additional uncertainties
associated with our business and the forward-looking statements included or
incorporated by reference. Each of these risk factors could adversely affect our
business, operating results and financial condition, as well as adversely affect
the value of an investment in our common stock.

We have a limited operating history in the oil and gas business. Our
operations to date have consisted solely of evaluating geological and
geophysical information, acquiring acreage positions, generating exploration
prospects, and drilling a limited number of wells on deep oil and gas prospects.
We currently have nine full-time employees. Our future financial results depend
primarily on (1) our ability to discover commercial quantities of oil and gas;
(2) the market price for oil and gas; (3) our ability to continue to generate
potential exploration prospects; and (4) our ability to fully implement our
exploration and development program. We cannot predict that our future
operations will be profitable. In addition, our operating results may vary
significantly during any financial period. These variations may be caused by
significant periods of time between discovery and development of oil or gas
reserves, if any, in commercial quantities.

Our cash resources are not unlimited. We need to increase our sources of
revenue and/or funding in order to sustain operations for the long run. There is
no assurance that this will occur.

We may not discover commercially productive reserves. Our future success
depends on our ability to economically locate oil and gas reserves in commercial
quantities. Except to the extent that we acquire properties containing proved
reserves or that we conduct successful exploration and development activities,
or both, our proved reserves, if any, will decline as reserves are produced. Our
ability to locate reserves is dependent upon a number of factors, including our
participation in multiple exploration projects and our technological capability
to locate oil and gas in commercial quantities. We cannot predict that we will
have the opportunity to participate in projects that economically produce
commercial quantities of oil and gas in amounts necessary to meet our business
plan or that the projects in which we elect to participate will be successful.
There can be no assurance that our planned projects will result in significant
reserves or that we will have future success in drilling productive wells at
economical reserve replacement costs.

Exploratory drilling is an uncertain process with many risks. Exploratory
drilling involves numerous risks, including the risk that we will not find any
commercially productive oil or gas reservoirs. The cost of drilling, completing
and operating wells is often uncertain, and a number of factors can delay or
prevent drilling operations, including:

o unexpected drilling conditions,
o pressure or irregularities in formations,
o equipment failures or accidents,
o adverse weather conditions,
o compliance with governmental requirements,
o shortages or delays in the availability of drilling rigs and the
delivery of equipment, and
o shortages of trained oilfield service personnel.

Our future drilling activities may not be successful, nor can we be sure
that our overall drilling success rate or our drilling success rate for
activities within a particular area will not decline. Unsuccessful drilling
activities could have a material adverse effect on our results of operations and
financial condition. Also, we may not be able to obtain any options or lease
rights in potential drilling locations that we identify. Although we have
identified a number of potential exploration projects, we cannot be sure that we
will ever drill them or that we will produce oil or gas from them or any other
potential exploration projects.

Our exploration and development activities are subject to reservoir and
operational risks. Even when oil and gas is found in what is believed to be
commercial quantities, reservoir risks, which may be heightened in new
discoveries, may lead to increased costs and decreased production. These risks
include the inability to sustain deliverability at commercially productive
levels as a result of decreased reservoir pressures, large amounts of water, or
other factors that might be encountered. As a result of these types of risks,
most lenders will not loan funds secured by reserves from newly discovered
reservoirs, which would have a negative impact on our future liquidity.
Operational risks include hazards such as fires, explosions, craterings,
blowouts (such as the blowout experienced at our initial exploratory well),
uncontrollable flows of oil, gas or well fluids, pollution, releases of toxic
gas and encountering formations with abnormal pressures. In addition, we may be
liable for environmental damage caused by previous owners of property we own or
lease. As a result, we may face substantial liabilities to third parties or
governmental entities, which could reduce or eliminate funds available for
exploration, development or acquisitions or cause us to incur substantial
losses.

We expect to maintain insurance against some, but not all, of the risks
associated with drilling and production in amounts that we believe to be
reasonable in accordance with customary industry practices. The occurrence of a
significant event, however, that is not fully insured could have a material
adverse effect on our financial condition and results of operations.

Our operations require large amounts of capital. Our current development
plans will require us to make large capital expenditures for the exploration and
development of our oil and gas projects. Under our current capital expenditure
budget, we expect to spend a minimum of approximately $2,000,000 on exploration
and development activities during our fiscal year ending August 31, 2005. Also,
we must secure substantial capital to explore and develop our other potential
projects. Historically, we have funded our capital expenditures through the
issuance of equity. Volatility in the price of our common stock, which may be
significantly influenced by our drilling and production activity, may impede our
ability to raise money quickly, if at all, through the issuance of equity at
acceptable prices. Future cash flows and the availability of financing will be
subject to a number of variables, such as:

o our success in locating and producing reserves in other projects,
o the level of production from existing wells, and
o prices of oil and gas.

Issuing equity securities to satisfy our financing requirements could cause
substantial dilution to our existing stockholders. Debt financing, if obtained,
could lead to:

o a substantial portion of our operating cash flow being dedicated to
the payment of principal and interest,
o our being more vulnerable to competitive pressures and economic
downturns, and
o restrictions on our operations.

If our revenues were to decrease due to lower oil and gas prices, decreased
production or other reasons, and if we could not obtain capital through a credit
facility or otherwise, our ability to execute our development plans, obtain and
replace reserves, or maintain production levels could be greatly limited.

We depend heavily on exploration success and subsequent success in
developing our exploration projects. Our future growth plans rely heavily on
discovering reserves and initiating production in the San Joaquin Basin, Texas,
Gulf Coast and in the Rocky Mountains. Our development plan includes the need to
discover reserves and establish commercial production through exploratory
drilling and development of our existing properties. We cannot be sure, though,
that our planned projects will lead to significant reserves that can be
economically extracted or that we will be able to drill productive wells at
anticipated finding and development costs. If we are able to record reserves,
our reserves will decline as they are depleted, except to the extent that we
conduct successful exploration or development activities or acquire other
properties containing proved reserves.

We depend on industry alliances. We attempt to limit financial exposure on
a project-by-project basis by forming industry alliances where our technical
expertise can be complemented with the financial resources and operating
expertise of more established companies. While entering into these alliances
limits our financial exposure, it also limits our potential revenue from
successful projects. Industry alliances also have the potential to expose us to
uncertainty if our industry partners are acquired or have priorities in areas
other than our projects. Despite these risks, we believe that if we are not able
to form industry alliances, our ability to fully implement our business plan
could be limited, which could have a material adverse effect on our business.

Our non-operator status limits our control over our oil and gas projects.
We focus primarily on creating exploration opportunities and forming industry
alliances to develop those opportunities. As a result, we have only a limited
ability to exercise control over a significant portion of a project's operations
or the associated costs of those operations. The success of a project is
dependent upon a number of factors that are outside our areas of expertise and
control. These factors include:

o the availability of leases with favorable terms and the availability
of required permitting for projects,
o the availability of future capital resources to us and the other
participants to be used for purchasing leases and drilling wells,
o the approval of other participants for the purchasing of leases and
the drilling of wells on the projects, and
o the economic conditions at the time of drilling, including the
prevailing and anticipated prices for oil and gas.

Our reliance on other project participants and our limited ability to
directly control project costs could have a material adverse effect on our
expected rates of return.

Oil and gas prices are volatile and an extended decline in prices could
hurt our business prospects. Our future profitability and rate of growth and the
anticipated carrying value of our oil and gas properties will depend heavily on
then prevailing market prices for oil and gas. We expect the markets for oil and
gas to continue to be volatile. If we are successful in continuing to establish
production, any substantial or extended decline in the price of oil or gas
could:

o have a material adverse effect on our results of operations,
o limit our ability to attract capital,
o make the formations we are targeting significantly less economically
attractive,
o reduce our cash flow and borrowing capacity, and
o reduce the value and the amount of any future reserves.

Various factors beyond our control will affect prices of oil and gas, including:

o worldwide and domestic supplies of oil and gas,
o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls,
o political instability or armed conflict in oil or gas producing
regions,
o the price and level of foreign imports,
o worldwide economic conditions,
o marketability of production,
o the level of consumer demand,
o the price, availability and acceptance of alternative fuels,
o the availability of processing and pipeline capacity,
o weather conditions, and
o actions of federal, state, local and foreign authorities.

These external factors and the volatile nature of the energy markets make
it difficult to estimate future prices of oil and gas. In addition, sales of oil
and gas are seasonal in nature, leading to substantial differences in cash flow
at various times throughout the year.

Accounting rules may require write-downs. Under full cost accounting rules,
capitalized costs of proved oil and gas properties may not exceed the present
value of estimated future net revenues from proved reserves, discounted at 10%.
Application of the ceiling test generally requires pricing future revenue at the
unescalated prices in effect as of the end of each fiscal quarter and requires a
write-down for accounting purposes if the ceiling is exceeded. If a write-down
is required, it would result in a charge to earnings, but would not impact cash
flow from operating activities. Once incurred, a write-down of oil and gas
properties is not reversible at a later date.

We face risks related to title to the leases we enter into that may result
in additional costs and affect our operating results. It is customary in the oil
and gas industry to acquire a leasehold interest in a property based upon a
preliminary title investigation. In many instances, our partners have acquired
rights to the prospective acreage and we have a contractual right to have our
interests in that acreage assigned to us. In some cases, we are in the process
of having those interests so assigned. If the title to the leases acquired is
defective, or title to the leases one of our partners acquires for our benefit
is defective, we could lose the money already spent on acquisition and
development, or incur substantial costs to cure the title defect, including any
necessary litigation. If a title defect cannot be cured or if one of our
partners does not assign to us our interest in a lease acquired for our benefit,
we will not have the right to participate in the development of or production
from the leased properties. In addition, it is possible that the terms of our
oil and gas leases may be interpreted differently depending on the state in
which the property is located. For instance, royalty calculations can be
substantially different from state to state, depending on each state's
interpretation of lease language concerning the costs of production. We cannot
guarantee that there will be no litigation concerning the proper interpretation
of the terms of our leases. Adverse decisions in any litigation of this kind
could result in material costs or the loss of one or more leases.

Limitations on the Effectiveness of Controls. Our management, including our
Chief Executive Officer and Chief Financial Officer, does not expect that our
disclosure controls or our internal controls will prevent all possible error or
fraud. A control system, no matter how well conceived and operated, can provide
only reasonable, not absolute, assurance that the objectives of the control
system are met. Further the design of a control system must reflect the fact
that there are resource constraints, and the benefits of controls must be
considered relative to their costs. Because of the inherent limitations in all
control systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within our company have been
detected. These inherent limitations include the realities that judgments in
decision making can be faulty, and that breakdowns can occur because of simple
error or mistake. Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by management
override of the control. The design of any system of controls also is based in
part upon certain assumptions about the likelihood of future events, and there
can be no assurance that any design will succeed in achieving its stated goals
under all potential future conditions; over time, controls may become inadequate
because of changes in conditions, or the degree of compliance with the policies
or procedures may deteriorate. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur and
not be detected.

Our industry is highly competitive and many of our competitors have more
resources than we do. We compete in oil and gas exploration with a number of
other companies. Many of these competitors have financial and technological
resources vastly exceeding those available to us. We cannot be sure that we will
be successful in acquiring and developing profitable properties in the face of
this competition. In addition, from time to time, there may be competition for,
and shortage of, exploration, drilling and production equipment. These shortages
could lead to an increase in costs and delays in operations that could have a
material adverse effect on our business and our ability to develop our
properties. Problems of this nature also could prevent us from producing any oil
and gas we discover at the rate we desire to do so.

Technological changes could put us at a competitive disadvantage. The oil
and gas industry is characterized by rapid and significant technological
advancements and introductions of new products and services using new
technologies. As new technologies develop, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement those new
technologies at a substantial cost. If other oil and gas exploration and
development companies implement new technologies before we do, those companies
may be able to provide enhanced capabilities and superior quality compared with
what we are able to provide. We may not be able to respond to these competitive
pressures and implement new technologies on a timely basis or at an acceptable
cost. If we are unable to utilize the most advanced commercially available
technologies, our business could be materially and adversely affected.

Our industry is heavily regulated. Federal, state and local authorities
extensively regulate the oil and gas industry. Legislation and regulations
affecting the industry are under constant review for amendment or expansion,
raising the possibility of changes that may affect, among other things, the
pricing or marketing of oil and gas production. State and local authorities
regulate various aspects of oil and gas drilling and production activities,
including the drilling of wells (through permit and bonding requirements), the
spacing of wells, the unitization or pooling of oil and gas properties,
environmental matters, safety standards, the sharing of markets, production
limitations, plugging and abandonment, and restoration. The overall regulatory
burden on the industry increases the cost of doing business, which, in turn,
decreases profitability.

Our operations must comply with complex environmental regulations. Our
operations are subject to complex and constantly changing environmental laws and
regulations adopted by federal, state and local governmental authorities. New
laws or regulations, or changes to current requirements, could have a material
adverse effect on our business. We will continue to be subject to uncertainty
associated with new regulatory interpretations and inconsistent interpretations
between state and federal agencies. We could face significant liabilities to the
government and third parties for discharges of oil, natural gas, produced water
or other pollutants into the air, soil or water, and we could have to spend
substantial amounts on investigations, litigation and remediation. We cannot be
sure that existing environmental laws or regulations, as currently interpreted
or enforced, or as they may be interpreted, enforced or altered in the future,
will not have a material adverse effect on our results of operations and
financial condition.

Our business depends on transportation facilities owned by others. The
marketability of our anticipated gas production depends in part on the
availability, proximity and capacity of pipeline systems owned or operated by
third parties. Federal and state regulation of oil and gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions could adversely affect our ability to produce,
gather and transport oil and natural gas.

Attempts to grow our business could have an adverse effect. Because of our
small size, we desire to grow rapidly in order to achieve certain economies of
scale. Although there is no assurance that this rapid growth will occur, to the
extent that it does occur, it will place a significant strain on our financial,
technical, operational and administrative resources. As we increase our services
and enlarge the number of projects we are evaluating or in which we are
participating, there will be additional demands on our financial, technical and
administrative resources. The failure to continue to upgrade our technical,
administrative, operating and financial control systems or the occurrence of
unexpected expansion difficulties, including the recruitment and retention of
geoscientists and engineers, could have a material adverse effect on our
business, financial condition and results of operations.

We may not be able to retain our listing on the American Stock Exchange.
The American Stock Exchange has certain listing requirements in order for a
company to continue to have their securities traded on this exchange. Although
the American Stock Exchange does not identify a specific minimum price per share
that a company's stock must trade above, a company may risk delisting if their
common stock trades at a low price per share for a substantial period of time.
Should our stock trade at a low share price for a substantial period of time, or
our net tangible equity be below certain levels, we may not be able to retain
our listing.

We depend on key personnel. We are highly dependent on the services of D.
Scott Singdahlsen, our President and Chief Executive Officer, and our other
geological and geophysical staff members. The loss of the services of any of
these persons could hurt our business. We do not have an employment contract
with Mr. Singdahlsen or any other employee.

Disclosure Regarding Forward-Looking Statements And Cautionary Statements

This annual report contains forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934, including statements regarding, among other items, our
business and growth strategies, anticipated trends in our business and our
future results of operations, market conditions in the oil and gas industry, our
ability to make and integrate acquisitions, the outcome of litigation, if any,
and the impact of governmental regulation. These forward-looking statements are
based largely on our expectations and are subject to a number of risks and
uncertainties, many of which are beyond our control. Actual results could differ
materially from these forward-looking statements as a result of, among other
things:

o failure to obtain, or a decline in, oil or gas production, or a
decline in oil or gas prices,
o incorrect estimates of required capital expenditures,
o increases in the cost of drilling, completion and gas collection or
other costs of production and operations,

o an inability to meet growth projections, and
o other risk factors set forth under "Risk Factors" in this annual
report. In addition, the words "believe," "may," "could," "will,"
"when," "estimate," "continue," "anticipate," "intend," "expect" and
similar expressions, as they relate to PYR, our business or our
management, are intended to identify forward-looking statements.

ITEM 3. LEGAL PROCEEDINGS

The Company is not a party to any, nor are any of the Company's properties
subject to, a pending legal proceeding.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The following matters were submitted to a vote of security holders at the
annual meeting of stockholders which was held on June 11, 2004:

The stockholders voted to re-elect D. Scott Singdahlsen, S.L. Huchison,
David Kilpatrick and Bryce W. Rhodes to continue as directors of the Company. A
total of 22,018,007 votes were represented with respect to this matter, with
voting on each specific nominee as follows:

BROKER
FOR AGAINST WITHHELD NON-VOTES
--- ------- -------- ---------
D. Scott Singdahlsen 21,819,589 0 119,148 -
S.L. Huchison 21,745,789 0 122,148 -
David Kilpatrick 21,822,059 0 195,948 -
Bryce W. Rhodes 21,822,589 0 119,678 -

A proposal to approve the private placement of 3,000,000 shares of
restricted common stock at a price of $1.09 per share was approved by the
stockholders. A total of 11,747,005 votes were represented with a total of
11,456,714 (97%) shares voting for the proposal , 196,836 shares voting against
the proposal, and 93,455 shares abstaining from voting.

A proposal to approve the increase in the number of shares issuable
pursuant to options granted under the 2000 Stock Option Plan from 1,500,000
shares to 2,250,000 shares was approved by the stockholders. A total of
11,747,005 votes were represented with a total of 10,407,525 (88%) shares voting
for the proposal, 1,234,026 shares voting against the proposal, and 105,454
shares abstaining from voting.

A proposal to ratify the selection of Hein+Associates LLP as our Certified
Public Accountants was approved by the stockholders. A total of 21,941,737 votes
were represented with a total of 21,734,058 (99%) shares voting for the
proposal, 171,472 shares voting against the proposal, and 36,207 shares
abstaining from voting.

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market For Common Equity

Our common stock has been listed on the American Stock Exchange under the
market symbol "PYR" since December 8, 1999. The following table sets forth the
range of high and low sales prices per share of our common stock for the periods
indicated.

High Low
---- ---
Fiscal Year Ended August 31, 2003
First Quarter.................. $1.00 $0.43
Second Quarter................. 0.42 0.22
Third Quarter.................. 0.68 0.25
Fourth Quarter................. 0.82 0.36
Fiscal Year Ended August 31, 2004
First Quarter.................. $0.83 $0.45
Second Quarter................. 1.81 0.53
Third Quarter.................. 1.70 1.04
Fourth Quarter................. 1.32 0.75

On November 17, 2004, the last reported sales price of our common stock on
the American Stock Exchange was $0.96 per share.

Stockholders Of Record

As of November 17, 2004, the number of record holders of our common stock
was approximately 536.

Dividends

We have not declared or paid, and do not anticipate declaring or paying in
the near future, any dividends on our common stock.

Recent Sales Of Unregistered Securities; Use Of Proceeds From Registered
Securities

None.

Equity Compensation Plan Information

Equity Compensation Plan Information
-------------------------------------------------------------------------------------------------------------------
Number of Securities
Remaining Available for
Future Issuance under
Number of Securities to be Equity Compensation
Issued Upon Exercise of Weighted-Average Exercise Plans (Excluding
Outstanding Options, Price of Outstanding Options, Securities Reflected in
Plan Category Warrants and Rights Warrants and Rights Column (a))*
------------- ------------------- ------------------- ------------
(a) (b) (c)

Equity compensation plans
approved by security holders 2,858,834 $1.64 731,000

Equity compensation plans not
approved by security holders -0- -- -0-

Total 2,858,834 731,000

-------------------------
* At August 31, 2004

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS

The following discussion should be read in conjunction with the
Consolidated Financial Statements and Notes thereto referred to in "Item 8.
Financial Statements and Supplemental Data," and "Items 1. and 2. Business and
Properties - Disclosures Regarding Forward-Looking Statements" of this Form
10-KSB.

Overview

We are an independent oil and gas exploration and production company
engaged in the exploration, development and acquisition of crude oil and natural
gas reserves. Our strategic focus is the application of advanced seismic imaging
and computer aided exploration technologies in the systematic search for
commercial hydrocarbon reserves, primarily in the onshore western United States.
We attempt to leverage our technical experience and expertise with seismic data
to identify exploration and exploitation projects with significant potential
economic return. We intend to participate in selected exploration projects as a
working interest owner, currently as a non-operator, sharing both risk and
rewards with our partners. Our financial results depend on our ability to sell
prospect interests to outside industry participants. We will not be able to
commence additional exploratory drilling operations without outside industry
participation. We have pursued, and will continue to pursue, exploration
opportunities in regions where we believe significant opportunity for discovery
of oil and gas exists. By attempting to reduce drilling risk through seismic
technology, we seek to improve the expected return on investment in our oil and
gas exploration projects.

Our future financial results continue to depend primarily on (1) our
ability to discover commercial quantities of hydrocarbons; (2) the market price
for oil and gas; (3) our ability to continue to source and screen potential
projects; and (4) our ability to fully implement our exploration and development
program with respect to these and other matters. There can be no assurance that
we will be successful in any of these respects or that the prices of oil and gas
prevailing at the time of production will be at a level allowing for profitable
production.

Two major financial developments that occurred during the fiscal year
included the acquisition of interests from Venus Exploration, Inc. ("Venus") in
certain producing properties with estimated proved reserves of 4.784 Bcfe for
approximately $3,230,000 (excluding acquisition expenses and subject to
retention, by the Venus Exploration Trust, of a net profits interest covering
the non-productive exploration projects), and the private placement of our
common stock, which raised $8,175,000 in gross proceeds.

Liquidity and Capital Resources

Our primary sources of liquidity historically have been from placements of
common stock and convertible notes, and to a much lesser extent, cash provided
by operating activities. Our primary use of capital has been for the
acquisition, development, and exploration of oil and natural gas properties. As
we pursue growth, we continually monitor the capital resources available to us
to meet our future financial obligations, planned capital expenditure activities
and liquidity. Our future success in growing proved reserves and production is
highly dependent on capital resources available to us and our success in finding
or acquiring additional reserves. At August 31, 2004, we had approximately
$6,061,967 in working capital.

During the fiscal year ended August 31, 2004, our capitalized costs for oil
and gas properties increased by approximately $3,564,000. The increase is
principally due to the acquisition of assets from Venus Exploration Inc.
("Venus"), and also includes net costs for drilling and completion, geological
and geophysical costs, delay rentals, and other related direct costs with
respect to our exploration and development projects, as well as an increase of
$211,876 in asset retirement obligations related to the properties acquired from
Venus, less depreciation of asset retirement obligation assets of approximately
$113,462. No impairment was charged against our capitalized oil and gas
properties within the United States cost center for the year ended August 31,
2004, as determined by the ceiling test performed pursuant to Regulation S-X
Rule 4-10(c)(2). Additionally, there was no charge to impairment for the year
ended August 31, 2004, against our unevaluated capitalized costs in Canada,
which are recorded at the lower of cost or fair market value.

During the year ended August 31, 2003, our capitalized costs for oil and
gas properties decreased by approximately $1,484,000. The decrease is the result
of an impairment taken against our oil and gas properties in the amount of
$3,234,000 during the year, net of approximately $1,474,000 of costs incurred
for drilling and completion, geological and geophysical costs, delay rentals and
other related direct costs with respect to our exploration and development
projects, and net asset retirement obligation assets of approximately $276,000.

In early May 2004, we received subscriptions for an aggregate of $8,175,000
in gross proceeds from a private placement of our common stock. The private
placement (the "Placement") consisted of the sale of 7.5 million shares of
common stock, priced at $1.09 per share, to a group of twelve institutional and
accredited individual investors pursuant to exemptions from registration under
Sections 3(b) and 4(2) of the Securities Act of 1933, as amended. The first
tranche of the Placement, consisting of 4.5 million shares and $4,905,000 in
gross proceeds, was received and accepted in early May 2004. The second tranche
of the Placement, consisting of 3.0 million shares and $3,270,000 in gross
proceeds, was approved by our stockholders at our Annual Meeting of Stockholders
on June 11, 2004. We received the funds from the second tranche in late June
2004. Proceeds from the Placement will be used for general corporate purposes,
partial funding of the acquisition of assets from Venus Exploration, Inc., and
project development and drilling costs associated with our exploration and
exploitation portfolio. The resale of these shares acquired in the Placement has
subsequently been registered through a Registration Statement that has become
effective with the SEC.

In May 2004, we acquired interests in certain producing properties for
approximately $3,230,000 (excluding acquisition expenses and subject to
retention, by the Venus Exploration Trust, of a net profits interest covering
the non-productive exploration projects) from Venus. Venus was in Chapter 11
Bankruptcy, and the properties were acquired through public auction as approved
by the United States Bankruptcy Court. To finance the purchase, we primarily
used existing cash reserves and also a portion of the proceeds from the
Placement. The purchase also provides for a net profits interest payable to the
Venus Exploration Trust. The net profits interest, which applies only to the
exploration and exploitation projects on the Venus acreage being acquired,
varies from 25% to 50% with respect to different Venus exploration and
exploitation project areas, and decreases by one-half of its original amount
after a total of $3,300,000 in net profits proceeds has been paid to the Trust.
As of November 17, 2004, zero proceeds have been paid into the Trust.

It is anticipated that the continuation and future development of our
business will require additional, and possibly substantial, capital
expenditures. We have no reliable source for additional funds for administration
and operations to the extent our existing funds have been utilized. In addition,
our capital expenditure budget for the fiscal year ending August 31, 2005 will
depend on our success in selling additional prospects for cash, the level of
industry participation in our exploration projects, the availability of debt or
equity financing, and the results of our activities. We anticipate spending a
minimum of approximately $2,000,000 on exploration and development activities
during our fiscal year ending August 31, 2005. To limit capital expenditures, we
intend to form industry alliances and exchange an appropriate portion of our
interest for cash and/or a carried interest in our exploration projects. We may
need to raise additional funds to cover capital expenditures. These funds may
come from cash flow, equity or debt financings, a credit facility, or sales of
interests in our properties, although there is no assurance additional funding
will be available or that it will be available on satisfactory terms.

Capital Expenditures

During fiscal 2004, we incurred approximately $3,823,000 of capital costs
related to the properties we acquired from Venus Exploration, Inc. This amount
includes capitalized acquisition costs, costs associated with undeveloped
leasehold, drilling, workover, and geological and geophysical costs. We incurred
approximately $1,570,000 for costs related to our other exploration projects
including continued acreage lease obligations and associated geological and
geophysical costs, as well as drilling costs for the Mallard well. Revenues from
oil and gas production during 2004 were approximately $863,000.

During fiscal 2004, the Company signed an Exploration Option Agreement with
Suncor Energy Natural Gas America, Inc. ("SENGAI"), covering our Rogers Pass
exploration project in the Foothills of west-central Montana. Pursuant to our
agreement, SENGAI paid us a (non-refundable) $500,000 option fee for a technical
evaluation period of up to three months. At August 31, 2004, SENGAI elected to
proceed to drill the first test well, and we received the $750,000 election fee
in early September 2004 (this amount is recorded as a receivable at August 31,
2004). Also during fiscal 2004, we entered into an agreement with two private
oil and gas exploration companies covering two of our exploration projects in
the Overthrust of southwestern Wyoming. In conjunction with this agreement, the
partners paid us $631,585 in prospect fees and pro-rata development costs. All
of the above proceeds were credited to the full cost pool as of August 31, 2004,
pursuant to the full cost accounting method of accounting for oil and gas
activities. The receipt of such funds allows the Company to lower the risk and
capital costs associated with the exploration of significant undeveloped
acreage.

During fiscal 2003, we incurred approximately $451,000 of capital costs
relating to our East Lost Hills Project. We incurred approximately $1,023,000
for costs related to our other exploration projects including continued acreage
lease obligations and associated geological and geophysical costs. Revenues from
oil and gas production during 2003 were $195,000.

We currently anticipate that we will participate in the drilling of up to
four exploration wells during our fiscal year ending August 31, 2005, although
the number of wells may increase as additional projects are added to our
portfolio. However, there can be no assurance that any such wells will be
drilled and if drilled that any of these wells will be successful.

The following table summarizes the Company's obligations and commitments,
as of August 31, 2004 to make future payments under its convertible notes
payable and office lease for the periods specified:

Payments Due By Period

Contractual Year Ended Fiscal Years Fiscal Years Fiscal Years
Obligations Total August 31, 2005 2006-2008 2009-2010 2011 and After
----------- ----- --------------- --------- --------- --------------

Convertible Notes $8,474,313 $ -- $ -- $8,474,313 $ --

Office Lease,
Denver, CO 210,219 46,715 163,504 -- --

Office Lease,
San Antonio, TX 36,000 36,000 -- -- --

Copier Lease 2,331 2,331 -- -- --
Subscriber
Agreement to
Computer Service 13,475 13,475 -- -- --
---------- ---------- ---------- ---------- -------
Total Contractual
Cash Obligations $8,736,338 $ 98,521 $ 163,504 $8,474,313 $ --

The above schedule assumes convertible note interest payments will be added to
the principal amount (which is at the discretion of the Company), and the entire
balance will be paid in full on maturity of May 24, 2009, and there will be no
conversion of debt to common stock. In addition to the above obligations, if we
elect to continue holding all our existing leases on a delayed rental basis, we
would have to pay approximately $490,000 during the year ending August 31, 2005.
The Company considers on a quarterly basis whether to continue holding all or
part of each acreage block by making delay rental payments on existing leases.

Results of Operations

The twelve months ended August 31, 2004 ("2004") compared with the twelve months
ended August 31, 2003 ("2003")

Operations during the fiscal year ended August 31, 2004 resulted in a net
loss of $1,359,354 compared to a net loss of $5,237,613 for the fiscal year
ended August 31, 2003.

Oil and Gas Revenues and Expenses. During the year ended August 31, 2004,
we recorded $863,087 in total oil and gas revenues. Of this amount, we recorded
$333,769 from the sale of 60,285 mcf of natural gas for an average price of
$5.54 per mcf, and $529,318 from the sale of 13,973 bbls of hydrocarbon liquids
for an average price of $37.88 per bbl. The portion of fiscal year 2004 oil and
gas revenues related to the May 2004 property acquisition from Venus
Exploration, Inc. ("Venus"), was $694,182. As the acquisition from Venus was

recorded as a purchase transaction, only four months of operations related to
these properties were recorded in 2004. During the year ended August 31, 2003,
we recorded $153,479 from the sale of 34,773 mcf of natural gas for an average
price of $4.41 per mcf, and $41,688 for the sale of 1,583 bbls of hydrocarbon
liquids for an average price of $26.33 per bbl. 2003 revenues relate totally to
the Company's interest in East Lost Hills in California. Comparable revenues for
this prospect in 2004 were $168,905. Lease operating expenses in 2004 were
$335,508 compared to $95,334 in 2003.

Interest Income. We recorded $27,431 and $53,520 in interest income for the
years ended August 31, 2004 and 2003, respectively. Lower interest income in
2004 resulted from lower average cash balances for the majority of 2004, offset
partially by interest on the funds received from the private placement of our
common stock in May 2004.

General and Administrative Expenses. General and administrative expenses in
2004 were $1,324,079 compared to $1,265,912 in 2003. The increase principally
reflects additional audit and legal fees incurred in conjunction with the
property acquisition from Venus Exploration Inc.

Depreciation Depletion and Amortization. We recorded $46,386 in
depreciation, depletion and amortization expense from oil and gas properties for
the year ended August 31, 2004. We recorded no depreciation, depletion and
amortization expense from oil and gas properties for the year ended August 31,
2003, due to an impairment taken against our entire amortizable full cost pool
at August 31, 2003, and accordingly, there were no costs to amortize. The
increase in depreciation, depletion and amortization expense was attributable to
the properties acquired from Venus Exploration, Inc. We recorded $13,111 and
$11,191 in depreciation expense associated with capitalized office furniture and
equipment during 2004 and 2003, respectively. Depreciation of Asset Retirement
Obligation assets for the years ended August 31, 2004 and August 31, 2003, was
$113,462 and $151,284, respectively. For further discussion of the Asset
Retirement Obligation, see Note 4 to the Financial Statements included in this
Form 10-KSB.

Accretion Expense. We recorded $99,684 and $76,918, respectively, for the
years ended August 31, 2004 and August 31, 2003, of accretion of the unamortized
discount of the Asset Retirement Obligation liability. The increase in accretion
expense was attributable to the properties acquired from Venus Exploration, Inc.
For further discussion of the Asset Retirement Obligation, see Note 4 to the
Financial Statements included in this Form 10-KSB.

Dry Hole, Impairment and Abandonments. We recorded no impairment expense
for the year ended August 31, 2004. For the year ended August 31, 2003, we
recorded an impairment expense of $3,234,029, of which $451,285 related to costs
incurred in the East Lost Hills prospect, and the remainder, $2,782,744, related
to other undeveloped prospects in California and the Rocky Mountain region,
which were determined by management to be impaired as of August 31, 2003.

Interest Expense. During 2004, we recorded interest expense of $326,886
compared to $310,457 in 2003. The interest expense for each year is associated
with the May 24, 2002 sale of outstanding convertible notes due on May 24, 2009.
The Company elected to add $319,376 and $303,975 of accrued interest to the
balance of the debt for the years ended August 31, 2004 and August 31, 2003,
respectively. We have reflected the outstanding balance of these notes as
Convertible Notes under Long Term Debt on our August 31, 2004 and 2003 balance
sheets.

The twelve months ended August 31, 2003 ("2003") compared with the twelve months
ended August 31, 2002 ("2002")

Operations during the fiscal year ended August 31, 2003 resulted in a net
loss of $5,237,613 compared to a net loss of $13,129,828 for the fiscal year
ended August 31, 2002.

Oil and Gas Revenues and Expenses. During the year ended August 31, 2003,
we recorded $153,479 from the sale of 34,773 mcf of natural gas for an average
price of $4.41 per mcf, and $41,688 for the sale of 1,583 bbls of hydrocarbon
liquids for an average price of $26.33 per bbl. During the year ended August 31,
2002, we recorded $106,637 from the sale of 39,468 mcf of natural gas for an
average price of $2.60 per mcf, and $29,932 from the sale of 1,600 bbls of
hydrocarbon liquids for an average price of $18.71 per bbl. Lease operating
expenses in 2003 were $95,334 compared to $91,384 in 2002.

Interest Income. We recorded $53,520 and $145,645 in interest income for
the years ended August 31, 2003 and 2002, respectively. Lower interest income in
2003 resulted from lower average cash balances in 2003 than in 2002, as cash was
utilized throughout 2003 to fund the Company's operations.

General and Administrative Expenses. General and administrative expenses in
2003 were $1,265,912 compared to $1,496,329 in 2002. The lower expense in 2003
reflects reduced salary and wage expenses following staff resignations, and
lower costs incurred for financial advisory services in 2003 compared to 2002.

Depreciation Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the years
ended August 31, 2003 and August 31, 2002. The ELH#1 well continued producing
throughout 2003 and 2002; however, because we have recorded an impairment
against our entire amortizable full cost pool at both August 31, 2003 and 2002
there were no costs to amortize. We recorded $11,191 and $14,605 in depreciation
expense associated with capitalized office furniture and equipment during 2003
and 2002, respectively. Included in depreciation expense reported for 2003, is
$151,284 of depreciation of Asset Retirement Obligation assets. For further
discussion of the Asset Retirement Obligation, see Note 4 to the Financial
Statements included in this Form 10-KSB.

Accretion Expense. We recorded $76,918 and $0, respectively, for the years
ended August 31, 2003 and August 31, 2002, of accretion of the unamortized
discount of the Asset Retirement Obligation liability. For further discussion of
the Asset Retirement Obligation, see Note 4 to the Financial Statements included
in this Form 10-KSB.

Dry Hole, Impairment and Abandonments. In 2003 we recorded an impairment
expense of $3,234,029, of which $451,285 related to costs incurred in the East
Lost Hills prospect, and the remainder, $2,782,744, related to other undeveloped
prospects in California and the Rocky Mountain region, which were determined by
management to be impaired as of August 31, 2003. In 2002, we recorded an
impairment expense of $11,722,830, primarily for the remaining basis in our East
Lost Hills project. Additionally, approximately $54,000 of the 2002 impairment
charge related to a Colorado exploration project where an unsuccessful
exploration well was drilled in October 2002. Although properties may be
considered as evaluated for purposes of the ceiling test and included in the
impairment calculation, until these properties are completely abandoned, we may
continue to incur related costs. Until we can establish economic reserves, of
which there is no assurance, additional costs associated with these properties
are charged directly to impairment expense as incurred.

Interest Expense. During 2003, we recorded interest expense of $310,457
compared to $82,894 in 2002. The increase reflects the existence of $6,000,000
in convertible notes for the entirety of 2003 compared to only 3.25 months of
2002. The notes are due May 24, 2009, and call for semi-annual interest payments
at an annual rate of 4.99% and are convertible into common stock at a conversion
price of $1.30 per share. The interest can be paid in cash or added to the
principal amount at the option of the Company. During 2003, the Company elected
to add $303,975 of accrued interest to the balance of the debt. We have
reflected the outstanding balance of these notes as Convertible Notes under Long
Term Debt on our August 31, 2003 and 2002 balance sheets.

Cash Flow

The fiscal year ended August 31, 2004 ("2004") compared with the fiscal
year ended August 31, 2003 ("2003")

Cash Flows From Operating Activities

Net cash used by operating activities was $1,087,131 and $1,180,944 for the
fiscal years ended August 31, 2004 and August 31, 2003, respectively. A
discussion of these and other items are presented below.

Net loss. See discussion of net loss in "Results of Operations" section
above.

Depreciation and amortization. Depreciation and amortization expense
increased to $172,959 for the year ended August 31, 2004, compared to $162,475
for the year ended August 31, 2003. The 2004 expense includes depreciation of
Asset Retirement Obligation assets of $113,462, and $46,386 of depletion of oil
and gas properties. The increase in fiscal 2004 is due to certain properties
acquired in May 2004 from Venus Exploration, Inc. The 2003 expense includes
depreciation of Asset Retirement Obligation assets of $151,283, and $76,917 of
accretion of unamortized discount of the Asset Retirement Obligation liability.
The increase in fiscal 2003 is due to the adoption of SFAS 143, "Accounting for
Asset Retirement Obligations". For further discussion of the Asset Retirement
Obligation, see the Notes to the Financial Statements included in this Form
10-KSB.

Impairment, dry hole and abandonments. During the year ended August 31,
2004, we recorded no impairment expense as compared to $3,234,029 during the
year ended August 31, 2003. The 2003 impairment related principally to costs
incurred to drill and complete wells in the East Lost Hills project.

Accounts receivable. For the years ended August 31, 2004 and August 31,
2003, accounts receivable increased $477,176 and $0, respectively. The increase
in 2004 related principally to receivables generated from the properties
acquired from Venus Exploration, Inc. in May 2004.

Accrued interest converted into debt. For the year ended August 31, 2004,
accrued interest converted into debt was $319,376 compared to $303,975 for the
year ended August 31, 2003. Both amounts reflect interest accrued on the
$6,000,000 convertible notes issued May 24, 2002.

Accretion of asset retirement obligation. During the years ended August 31,
2004 and August 31, 2003, accretion of unamortized discount of the Asset
Retirement Obligation liability was $99,684 and $76,918, respectively. The
increase in fiscal 2004 is due to certain properties acquired in May 2004 from
Venus Exploration, Inc. The increase in fiscal 2003 is due to the adoption of
SFAS 143, "Accounting for Asset Retirement Obligations". For further discussion
of the Asset Retirement Obligation, see the Notes to the Financial Statements
included in this Form 10-KSB.

Prepaid expenses and other. During the year ended August 31, 2004, prepaid
expenses increased $45,680, compared to a decrease of $805 during the year ended
August 31, 2003. The increase in 2004 primarily reflects higher director and
officer liability insurance premiums.

Accounts payable and accruals. During the year ended August 31, 2004,
accounts payable and accruals increased $209,873 compared to a decrease of
$25,895 during the year ended August 31, 2003. The change primarily reflects
increased payables activity as a result of the properties acquired from Venus in
May 2004.

Cash Flows From Investing Activities

Cash paid for oil and gas properties. During the year ended August 31,
2004, we paid $5,103,383 for oil and gas properties, compared to $1,670,943,
during the year ended August 31, 2003. The increase in 2004 principally reflects
the acquisition of properties from Venus in May 2004.

Proceeds from sale of exploration options. During the year ended August 31,
2004, we signed an Exploration Option Agreement with Suncor Energy Natural Gas
America, Inc. ("SENGAI"), covering our Rogers Pass exploration project in the
Foothills of west-central Montana. Pursuant to our agreement, SENGAI paid us a
(non-refundable) $500,000 option fee for a technical evaluation period of up to
three months. At August 31, 2004, SENGAI elected to proceed to drill the first
test well, and we received the election fee in early September 2004. We received
$0 in proceeds from the sale of exploration options during the year ended August
31, 2003.

Proceeds from sale of oil and gas properties. During the year ended August
31, 2004, we entered into an agreement with two private oil and gas exploration
companies covering two of our exploration projects in the Overthrust of
southwestern Wyoming. In conjunction with this agreement, the partners paid us
$631,585 in prospect fees and pro-rata development costs. We received $0 in
proceeds from the sale of oil and gas properties during the year ended August
31, 2003.

Cash Flows From Financing Activities

Cash provided by financing activities was $7,449,681 and $0 for the years
ended August 31, 2004 and August 31, 2003, respectively. The increase in 2004
primarily reflects the private placement sale of 7.5 million shares of common
stock, priced at $1.09 per share, to a group of twelve institutional and
accredited individual investors pursuant to exemptions from registration under
Sections 3(b) and 4(2) of the Securities Exchange Act of 1934, as amended.

Critical Accounting Policies And Estimates

We believe the following critical accounting policies affect our more
significant judgments and estimates used in the preparation of our Financial
Statements.

Reserve Estimates:

Our estimates of oil and natural gas reserves, by necessity, are
projections based on geological and engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that are difficult to measure.
The accuracy of any reserve estimate is a function of the quality of available
data, engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and natural gas reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies and
assumptions governing future oil and natural gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and natural
gas attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected from there may vary substantially. Any significant variance in the
assumptions could materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of our oil and gas properties
and/or the rate of depletion of the oil and gas properties. Actual production,
revenues and expenditures with respect to our reserves will likely vary from
estimates, and such variances may be material.

Many factors will affect actual net cash flows, including the following:
the amount and timing of actual production; supply and demand for natural gas;
curtailments or increases in consumption by natural gas purchasers; and changes
in governmental regulations or taxation.

Property, Equipment and Depreciation:

We follow the full cost method to account for our oil and gas exploration
and development activities. Under the full cost method, all costs incurred which
are directly related to oil and gas exploration and development are capitalized
and subjected to depreciation and depletion. Depletable costs also include
estimates of future development costs of proved reserves. Costs related to
undeveloped oil and gas properties may be excluded from depletable costs until
those properties are evaluated as either proved or unproved. The net capitalized
costs are subject to a ceiling limitation based on the estimated present value
of discounted future net cash flows from proved reserves. As a result, we are
required to estimate our proved reserves at the end of each quarter, which is
subject to the uncertainties described in the previous section. Gains or losses
upon disposition of oil and gas properties are treated as adjustments to
capitalized costs, unless the disposition represents a significant portion of
the Company's proved reserves.

Revenue Recognition:

The Company recognizes oil and gas revenues from its interests in producing
wells as oil and gas is produced and sold from these wells. The Company has no
gas balancing arrangements in place. Oil and gas sold is not significantly
different from the Company's product entitlement.

Recent Accounting Pronouncements

In June 2001, the FASB issued SFAS No. 141, "Business Combinations" ("SFAS
No. 141") and SFAS No. 142, "Goodwill and Intangible Assets" ("SFAS No. 142").
SFAS Nos. 141 and 142 became effective on July 1, 2001 and January 1, 2002,
respectively. SFAS No. 141 requires all business combinations initiated after
June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS
No. 141 requires companies to disaggregate and report separately from goodwill
certain intangible assets. SFAS No. 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under SFAS No. 142,
goodwill and certain other intangible assets are not amortized, but rather are
reviewed annually for impairment. One interpretation that was considered
relative to these standards was that oil and gas mineral rights held under lease
and other contractual arrangements representing the right to extract such

reserves for both undeveloped and developed leaseholds should be classified
separately from oil and gas properties, as intangible assets on the Company's
consolidated balance sheets. In April 2004, the Financial Accounting Standards
Board amended SFAS Nos. 141 and 142 and clarified the interpretation by defining
mineral rights, such as oil and gas mineral rights, as tangible assets.
Accordingly, the guidelines for accounting for intangible assets as provided in
SFAS No. 142 would not apply to oil and gas mineral rights. In accordance with
this new guideline, the Company will continue to classify its contractual rights
to extract oil and gas reserves as tangible oil and gas properties.

ITEM 7. FINANCIAL STATEMENTS

The Consolidated Financial Statements and schedules that constitute Item 7
are attached at the end of Annual Report on Form 10-KSB. An index to these
Financial Statements and schedules is also included in Item 14(a) of this Annual
Report on Form 10-KSB.

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

As previously reprinted in the Company's Form 8-K, the Company changed
auditors in 2004. There were no disagreements with either of our auditors on
accounting or financial disclosures.

ITEM 8A. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, the Company conducted
an evaluation of the Company's disclosure controls and procedures (as defined in
Rules 13a-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")).
Based on this evaluation, the Company concluded that, subject to the limitations
described below, the Company's disclosure controls and procedures are effective
to ensure that information required to be disclosed by the Company in annual
reports that it files under the Exchange Act is recorded, processed, summarized,
and reported within the time periods specified in Securities and Exchange
Commission rules and forms. There was no change in the Company's internal
controls over financial reporting during the Company's most recently completed
fiscal quarter that has materially affected, or is reasonably likely to
materially affect, the Company's internal control over financial reporting
period.

In connection with the audit of the Company's financial statement for the
fiscal year ended August 31, 2004, the independent auditors informed the Company
that they had discovered a material weakness in the Company's internal control
over financial reporting. The material weakness consists of the Company's
failure to record within its general ledger on a timely basis the issuance of
common stock and warrants. The financial implication of this inadvertent
oversight was an increase in stockholders' equity and oil and gas property by
approximately $372,000. The impact on net loss and net loss per share was
negligible.

On an interim basis, the Company has instituted the following corrective
action: the Chairman of the Compensation Committee will make direct contact with
the Vice President of Strategic Development to report any issuance of common
stock, warrants, options, or other securities for recording in the Company's
general ledger.

Going forward, the Company intends to implement changes promptly to address
this issue. The Company will consider implementing the following corrective
actions as well as additional procedures:

o Establishing procedures for the timely and direct reporting by the
Board's Compensation Committee to the finance department upon the
granting of common stock, warrants, options, or other securities; and

o The assignment of a specific individual to communicate with the
Compensation Committee and report on the same day grants of common
stock, warrants, options, or other securities to those officers and
directors required to file changes in beneficial ownership reports
under Section 16 of the Exchange Act with the Securities and Exchange
Commission.

The Company will continue to evaluate the effectiveness of its disclosure
controls and internal controls and procedures on an ongoing basis, and will take
further action as appropriate.

ITEM 8B. OTHER INFORMATION

Not applicable.

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT

The directors and executive officers of the Company, their respective
positions and ages, and the year in which each director was first elected, are
set forth in the following table. Each director has been elected to hold office
until the next annual meeting of stockholders and thereafter until his successor
is elected and has qualified. Additional information concerning each of these
individuals follows the table.

Name Age Position with the Company Director Since
---- --- ------------------------- --------------

D. Scott Singdahlsen 46 Chief Executive Officer, Chief Financial 1997
Officer, President, and Chairman Of the Board

David Kilpatrick 54 Director 2002

Bryce W. Rhodes 51 Director 1999

Dennis M. Swenson 69 Director 2004

Tucker L. Franciscus 36 Vice President Strategic Development ---

Kenneth R. Berry, Jr. 52 Vice President-Land ---

D. Scott Singdahlsen has served as President, Chief Executive Officer, and
Chairman of the Board of the Company since August 1997. Mr. Singdahlsen
co-founded PYR Energy, LLC in 1996, and served as General Manager and
Exploration Coordinator. In 1992, Mr. Singdahlsen co-founded Interactive Earth
Sciences Corporation, a 3-D seismic management and interpretation consulting
firm in Denver, where he served as vice president and president and lead seismic
interpretation specialist from 1992 to 1996. Prior to forming Interactive Earth
Sciences Corporation, Mr. Singdahlsen was employed as a Development Geologist
for Chevron USA in the Rocky Mountain region. At Chevron, Mr. Singdahlsen was
involved in 3-D seismic reservoir characterization projects and geostatistical
analysis. Mr. Singdahlsen started his career at UNOCAL as an Exploration
Geologist in Midland, Texas. Mr. Singdahlsen earned a B.A. in Geology from
Hamilton College and a M.S. in Structural Geology from Montana State University.

David B. Kilpatrick has been a Director of the Company since June, 2002. He
is currently President of Kilpatrick Energy Group, which provides strategic
management consulting services to the oil and gas industry. He currently serves
as a Director of the publicly traded Cheniere Energy and privately held Ensyn
Petroleum International, Ltd. Prior to the 1998 merger with Texaco, he was
President and Chief Operating Officer of Monterey Resources, Inc., the largest
independent oil and gas producer in California. Mr. Kilpatrick has served as
President of the California Independent Petroleum Association and is a member of
its Board of Directors and also serves as a Director of the Independent Oil
Producers Agency. He earned a Bachelor of Science degree in Petroleum
Engineering from the University of Southern California and a Bachelor's Degree
in Geology and Physics from Whittier College.

Bryce W. Rhodes has been a Director of the Company since April 1999, when
he was nominated and elected to the Board in connection with the sale by the
Company of convertible promissory notes issued in a private placement

transaction in October and November 1998. From 1996 until September 2003, Mr.
Rhodes has served as President and CEO of Whittier Energy Company ("WEC"), an
oil and gas investment company. In September 2003, WEC merged with Olympic
Resources, Inc. and Mr. Rhodes was appointed as President and Chief Executive
Officer. Mr. Rhodes served as Investment Manager of WEC from 1990 until 1996.
Mr. Rhodes received B.A. degrees in Geology and Biology from the University of
California, Santa Cruz, in 1976 and an MBA degree from Stanford University in
1979.

Dennis M. Swenson joined as a Director in October 2004, and serves as the
Audit Committee Chairman and a member of the Compensation Committee. From 1992
through 1995, Mr. Swenson was an independent consultant. Mr. Swenson was
Executive Vice President, Chief Financial Officer, Secretary and Treasurer, of
StarTek, Inc., a NYSE traded company with headquarters in Denver, Colorado from
1996 through retirement in 2001. Mr. Swenson was employed at Ernst & Young in
Denver from 1960 to 1973, and was a partner at Ernst & Young from 1973 to 1991.
He has a Bachelor's Degree in Accounting from Brigham Young University and an
MBA Degree from the University of Denver.

Tucker L. Franciscus, Vice President of Strategic Development, joined PYR
in September 2004. Mr. Franciscus joined the firm from Stifel Nicolaus &
Company, where he oversaw their Investment Banking Energy Group practice between
2001 and 2004. Mr. Franciscus was responsible for mergers and acquisitions,
equity and debt offerings, and private placements for all of Stifel's energy
clients. Prior to working at Stifel, Mr. Franciscus was the senior associate and
manager for the Global Energy Group at J.P. Morgan in New York and an associate
in the Deutsche Banc BT Wolfensohn Mergers & Acquisitions Group. Mr. Franciscus
has executed equity, debt, mergers and acquisitions and other financing
transactions in various industries including defense, energy, media and telecom.
For five years preceding his banking experience, Mr. Franciscus worked in
various marketing and finance positions in the oil and gas sector, including
Synder Oil and KN Energy (Interenergy). Additionally, he was a commissioned
Infantry Officer in the U.S. Army and continues to serve in the reserves. Mr.
Franciscus has an MBA from the Daniels college of Business at the University of
Denver and a Bachelor of Arts from Ohio Wesleyan University.

Kenneth R. Berry, Jr. has served as Vice President of land since August
1999, and as land manager for the Company since October 1997. Mr. Berry is
responsible for the management of all land issues including leasing and
permitting. Prior to joining the Company, Mr. Berry served as the managing land
consultant for Swift Energy Company in the Rocky Mountain region. Mr. Berry
began his career in the land department with Tenneco Oil Company after earning a
B.A. degree in Petroleum Land Management at the University of Texas - Austin.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"), requires the Company's directors, executive officers and
holders of more than 10% of the Company's common stock to file with the
Securities and Exchange Commission initial reports of ownership and reports of
changes in ownership of common stock and other equity securities of the Company.
The Company believes that during the year ended August 31, 2004, its officers,
directors and holders of more than 10% of the Company's common stock complied
with all Section 16(a) filing requirements, except that Ken Berry, a Vice
President, was late filing a Form 4 with respect to his receipt of stock options
on September 9, 2003 and August 26, 2004. In making these statements, the
Company has relied upon representations and its review of copies of the Section
16(a) reports filed for the fiscal year ended August 31, 2004 on behalf of the
Company's directors, officers and holders of more than 10% of the Company's
common stock.

Employee Code of Conduct and Code of Ethics and Reporting of Accounting Concerns

The Company adopted an Employee Code of Conduct (the "Code of Conduct"). We
require all employees to adhere to the Code of Conduct in addressing legal and
ethical issues encountered in conducting their work. The Code of Conduct
requires that our employees avoid conflicts of interest, comply with all laws
and other legal requirements, conduct business in an honest and ethical manner
and otherwise act with integrity and in the Company's best interest.

The Company also adopted a Code of Ethics for our Chief Executive Officer,
our Chief Financial Officer, our Controller and all other financial officers and
executives. This Code of Ethics supplements our Code of Conduct and is intended
to promote honest and ethical conduct, full and accurate reporting, and
compliance with laws as well as other matters. The Code of Conduct and Code of
Ethics are filed with the SEC as exhibits to this Annual Report.

Further, the Audit Committee of the Board of Directors has established
"whistle-blower procedures" which provides a process for the confidential and
anonymous submission, receipt, retention and treatment of complaints regarding
accounting, internal accounting controls or auditing matters. These procedures
provide substantial protections to employees who report company misconduct.

Audit Committee Financial Expert

The Company's Board of Directors has determined that Mr. Dennis M. Swenson
is the Company's audit committee financial expert.

Identification of Audit Committee

The Board of Directors currently has an Audit Committee consisting of
Messrs. Swenson (Chairman), Kilpatrick and Rhodes. The Audit Committee is
responsible for the selection and retention of our independent auditors, reviews
the scope of the audit functions of the independent auditor, and reviews audit
reports rendered by our independent auditors. The Audit Committee oversees the
Company's financial reporting process on behalf of the Board of Directors.
Management has the primary responsibility for the financial statements,
accounting policies and procedures, and the reporting process, including the
systems of internal controls. In fulfilling its oversight responsibilities, the
Committee reviewed and discussed with management the audited financial
statements in this Annual Report on Form 10-KSB for the year ended August 31,
2004 and the unaudited financial statements included in the Quarterly Reports on
Form 10-Q for the first three quarters of the fiscal year ended August 31, 2004.

ITEM 10. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth in summary form the compensation received
during each of the last three completed fiscal years ended August 31, 2004 by D.
Scott Singdahlsen, our Chief Executive Officer, President, Chief Financial
Officer and Chairman of The Board. Other than Mr. Singdahlsen, none of our
executive officers received total salary and bonus exceeding $100,000 during the
last the fiscal year ended August 31, 2004.

Summary Compensation Table
----------------------------------------------------------------------------------------------------------------------------
Annual Compensation Long-Term Compensation
------------------------------------------ --------------------------------------------------
Awards Payouts
------------------------ --------
Other Annual Restricted Securities LTIP All Other
Fiscal Salary Bonus Compensation Stock Underlying Payouts Compensation
Name and Principal Position Year ($)(1) ($)(2) ($)(3) Awards ($) Options(#) ($)(4) ($)(5)
--------------------------- ---- ------ ------ ------ ---------- ---------- ------ ------

D. Scott Singdahlsen 2004 $175,000 $-0- -0- -0- -0- -0- -0-
Chief Executive Officer,
Chief Financial Officer, 2003 $175,000 $-0- -0- -0- 281,750 -0- -0-
President and Chairman
Of the Board 2002 $175,000 $-0- -0- -0- -0- -0- -0-

(1) The dollar value of base salary (cash and non-cash) received during the
year indicated.

(2) The dollar value of bonus (cash and non-cash) received during the year
indicated.

(3) During the period covered by the Summary Compensation Table, we did not pay
any other annual compensation not properly categorized as salary or bonus,
including perquisites and other personal benefits, securities or property.

(4) We do not have in effect any plan that is intended to serve as incentive
for performance to occur over a period longer than one fiscal year except
for our 1997 and 2000 Stock Option Plans.

(5) All other compensation received that we could not properly report in any
other column of the Summary Compensation Table including annual Company
contributions or other allocations to vested and unvested defined
contribution plans, and the dollar value of any insurance premiums paid by,
or on behalf of, the Company with respect to term life insurance for the
benefit of the named executive officer, and, the full dollar value of the
remainder of the premiums paid by, or on behalf of, the Company.

Option Grants

There were no individual grants of stock options made during the fiscal
year ended August 31, 2004 to any executive officers. However, since the end of
the fiscal year, Mr. Singdahlsen has received 200,000 shares with an exercise
price of $0.96 that expire in 2014. One fifth are exercisable each November for
the next five years.

Aggregated Option Exercises And Fiscal Year-End Option Value Table

The following table provides certain summary information concerning stock
option exercises during the fiscal year ended August 31, 2004 by the named
executive officer and the value of unexercised stock options held by the named
executive officer as of August 31, 2004.

Aggregated Option Exercises in last Fiscal Year And Year-End Option Values(1)
------------------------------------------------------------------------------------------------------------------
Number of Securities
Underlying Unexercised Value of Unexercised
Options at Fiscal In-the-Money Options at
Year-End (#)(4) Fiscal Year-End ($)(5)
---------------------------- ---------------------------
Shares Acquired Value Realized
Name on Exercise(2) ($)(3) Exercisable Unexercisable Exercisable Unexercisable
---- -------------- ------ ----------- ------------- ----------- -------------

D. Scott Singdahlsen $-0- $-0- 303,917 192,833 $-0- $38,667

(1) No stock appreciation rights are held by any of the named executive
officers.

(2) The number of shares received upon exercise of options during the year
ended August 31, 2004.

(3) With respect to options exercised during the year ended August 31, 2004,
the dollar value of the difference between the option exercise price and
the market value of the option shares purchased on the date of the exercise
of the options.

(4) The total number of unexercised options held as of August 31, 2004,
separated between those options that were exercisable and those options
that were not exercisable on that date.

(5) For all unexercised options held as of August 31, 2004, the aggregate
dollar value of the excess of the market value of the stock underlying
those options over the exercise price of those unexercised options. These
values are shown separately for those options that were exercisable and
those options that were not yet exercisable on August 31, 2004 based on the
closing sale price of our common stock on the last business day before that
date, which was $0.87 per share.

Employee Retirement Plans, Long-Term Incentive Plans and Pension Plans

Excluding the Company's stock option plans, we do not have any long-term
incentive plan to serve as incentive for performance to occur over a period
longer than one fiscal year.

1997 Stock Option Plan

In August 1997, our 1997 Stock Option Plan (the "1997 Plan") was adopted by
the Board of Directors and subsequently approved by the stockholders. Pursuant
to the 1997 Plan, we may grant options to purchase an aggregate of 1,000,000
shares of common stock to key employees, directors, and other persons who have
contributed or are contributing to our success. The options granted pursuant to
the 1997 Plan may be either incentive options qualifying for beneficial tax
treatment for the recipient or they may be nonqualified options. The 1997 Plan
may be administered by the Board of Directors or by an option committee.
Administration of the 1997 Plan includes determination of the terms of options
granted under the 1997 Plan. At August 31, 2004, options to purchase 90,000
shares were outstanding under the Plan and 626,500 options were available to be
granted under the 1997 Plan.

2000 Stock Option Plan

In March 1999, our 2000 Stock Option Plan (the "2000 Plan") was adopted by
the Board of Directors and subsequently approved by the stockholders. Pursuant
to the 2000 Plan, we may grant options to purchase shares of our common stock to
key employees, directors, and other persons who have contributed or are
contributing to our success. We initially could grant options to purchase up to
500,000 shares pursuant to the 2000 Plan. In June 2001, our stockholders
approved an amendment which allows us to grant options to purchase up to
1,500,000 shares pursuant to the 2000 Plan. In June 2004, our stockholders
approved an amendment to increase from 1,500,000 to 2,250,000 the number of
shares of common stock issuable pursuant to options granted under the 2000 Plan.
The options granted pursuant to the 2000 Plan may be either incentive options
qualifying for beneficial tax treatment for the recipient or non-qualified
options. The 2000 Plan may be administered by the Board of Directors or by an
option committee. Administration of the 2000 Plan includes determination of the
terms of options granted under the 2000 Plan. As of August 31, 2004, options to
purchase 2,093,834 shares were outstanding under the 2000 Plan and 90,000
options were available to be granted pursuant to the 2000 Plan.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee is made up of three directors: Messrs. Swenson,
Kilpatrick and Rhodes. None of the members of the Committee have been executive
officers of the Company. In addition, no member of the Committee is, or was
during the fiscal year ended August 31, 2004, an executive officer of another
company whose board of directors has a comparable committee on which one of the
Company's executive officers serves.

Employment Contracts And Termination of Employment And Change-In-Control
Arrangements

We do not have any written employment contracts with any of our officers or
other employees. We have no compensatory plan or arrangement that results or
will result from the resignation, retirement, or any other termination of an
executive officer's employment or from a change-in-control or a change in an
executive officer's responsibilities following a change-in-control, except that
both the 1997 Plan and the 2000 Plan provide for vesting of all outstanding
options in the event of the occurrence of a change-in-control.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

Stock Ownership Of Directors And Principal Stockholders

As of November 19, 2004, there were 31,564,426 shares of common stock
outstanding. The following table sets forth certain information as of that date
with respect to the beneficial ownership of common stock by each director and
nominee for director, by all executive officers and directors as a group, and by
each other person known by us to be the beneficial owner of more than five
percent of our outstanding shares of common stock:

Number of Shares Percentage of
Name and Address of Beneficial Owner Beneficially Owned(1) Shares Outstanding
------------------------------------ --------------------- ------------------

D. Scott Singdahlsen 2,053,917(2) 6.5%
1675 Broadway, Suite 2450
Denver, Colorado 80202

Bryce W. Rhodes 122,414(3) *
c/o Whittier Energy Company
7770 El Camino Real
Carlsbad, CA 92009

David B. Kilpatrick 45,000(4) *
9105 St. Cloud Lane
Bakersfield, CA 93311

Dennis M. Swenson 25,000(5) *
5360 Lakeshore Drive
Littleton, CO 80123

All Executive Officers and Directors as a group 2,592,896(1)(2)(3)(4)(5)(6) 8.0%
(five persons)

Victory Oil Company 2,978,428(7) 9.4%
222 West Sixth Street, Suite 1010
San Pedro, California 90731

Eastbourne Capital Management, L.L.C. 7,141,329(8) 22.6%
1101 Fifth Avenue, Suite 160
San Rafael, CA 94901
---------------------------

(*) Less than one percent.

(1) "Beneficial ownership" is defined in the regulations promulgated by the
U.S. Securities and Exchange Commission as having or sharing, directly or
indirectly (1) voting power, which includes the power to vote or to direct
the voting, or (2) investment power, which includes the power to dispose or
to direct the disposition of shares of the common stock of an issuer. The
definition of beneficial ownership includes shares underlying options or
warrants to purchase common stock, or other securities convertible into
common stock, that currently are exercisable or convertible or that will
become exercisable or convertible within 60 days. Unless otherwise
indicated, the beneficial owner has sole voting and investment power.

(2) The shares shown for Mr. Singdahlsen include 200,000 shares owned by Mr.
Singdahlsen's two minor children. Also includes options to purchase 100,000
shares at $4.40 per share until May 15, 2005, options to purchase 100,000
shares at $5.98 per share until November 27, 2005, options to purchase
10,000 shares at $1.82 per share until April 12, 2007, options to purchase
66,667 shares at $0.29 per share until February 4, 2010, and options to
purchase 27,250 shares at $1.30 per share until February 4, 2010.

(3) Includes 13,000 shares of common stock owned by Mr. Rhodes and 64,414
shares of common stock owned by Adventure Seekers Travel, Inc. Adventure
Seekers is owned by Mr. Rhodes' wife and Mr. Rhodes is the President of
Adventure Seekers. Also includes options to purchase 20,000 shares at $1.65
per share until April 11, 2007 and options to purchase 25,000 shares at
$1.15 per share until October 14, 2009 that currently are exercisable.

Excludes 171,625 shares that are held by Whittier Energy Company. Mr.
Rhodes is a President and CEO of Whittier Energy Company. Mr. Rhodes
disclaims beneficial ownership of the shares beneficially owned by Whittier
Energy Company

(4) Includes options to purchase 20,000 shares at $1.72 per share until June 4,
2007, and options to purchase 25,000 shares at $1.15 per share until
October 14, 2009 that currently are exercisable that are owned by Mr.
Kilpatrick.

(5) Includes options to purchase 25,000 shares at $1.24 per share until October
1, 2009 that are exercisable. The options expire five years from the date
that they become exercisable by Mr. Swenson.

(6) Includes the following securities held directly or indirectly by Kenneth R.
Berry, Jr., who is Vice President of Land: an aggregate of 84,065 shares
owned by various entities, IRAs, and trusts with which Mr. Berry, or his
spouse or minor daughter, is associated; and options to purchase 262,500
shares of common stock at exercise prices ranging from $.29 to $5.44 per
share that currently are exercisable or that will become exercisable within
the next 60 days.

(7) Based on information contained in an amendment to Schedule 13D filed with
the SEC on July 16, 2001.

(8) Based on information contained in an amendment to Schedule 13D filed with
the SEC on March 3, 2004. The shares reflected include the shares
beneficially owned by Eastbourne Capital Management, L.L.C., a registered
investment adviser, Richard Jon Barry, Manager of Eastbourne and the
following companies to which Eastbourne is investment adviser: Black Bear
Offshore Master Fund Limited, a Cayman Island exempted company, Black Bear
Fund I, L.P. and Black Bear Fund II, LLC. These shares include the
equivalent shares of common stock underlying $6,303,975 of convertible
notes held by Black Bear Offshore Master Fund Limited, Black Bear Fund I,
L.P. and Black Bear Fund II, LLC.

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On May 24, 2002, certain investment entities managed by Eastbourne Capital
Management, LLC purchased $6 million of convertible notes from the Company. The
notes provide for semi-annual interest payments at an annual rate of 4.99% and
are convertible into common stock at the rate of $1.30 per share. At the time of
the transaction, these entities had aggregate ownership in PYR Energy
Corporation of approximately 15%. Concurrent with the sale, we agreed to add
Messrs. Eric Sippel and Borden Putnam, of Eastbourne, to our Board of Directors.
Messrs. Sippel and Putnam resigned from the board in August 2003, although
Eastbourne still has the right to designate two individuals to serve on the
Board.

During the fiscal year ended August 31, 2004, there were no other
transactions between the Company and its directors, executive officers or known
holders of greater than five percent of the Company's common stock in which the
amount involved exceeded $60,000 and in which any of the foregoing persons had
or will have a material interest.

ITEM 13. EXHIBITS

Exhibit Index

Number Description
------ -----------

3.1 Articles Of Incorporation filed with the Maryland Secretary Of State
on June 18, 2001.(1)

3.2 Articles of Merger filed with the Maryland Secretary Of State on July
3, 2001 in connection with Maryland reincorporation.(1)

3.3 Bylaws(1)

31 Rule 13a - 14(a) Certifications of Chief Executive Officer and Chief
Financial Officer

32 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002

99.1 Employee Code of Conduct

99.2 Code of Ethics for Chief Executive Officer, Chief Financial Officer
and Controller

----------

(1) Incorporated by reference from the Registrant's Form 10-KSB for the year
ended August 31, 2001.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

Hein + Associates, LLP, the Company's principal accountants, billed the
Company $47,210 for the year ended August 31, 2004. Hein + Associates, LLP was
hired in November 2003 as the Corporation's certified independent accountant.
Hein's professional services, as of August 31, 2004, included review of
financial statements included in the Company's Forms 10-Q, and services provided
in connection with regulatory filings. Wheeler Wasoff, P.C., the Company's
certified independent accountant prior to November 2003, billed the Company
$28,352 for the year ended August 31, 2003, for the audit of the Company's
annual financial statements and review of financial statements included in the
Company's Forms 10-Q, as well as for services normally provided by Wheeler
Wasoff, P.C. in connection with statutory and regulatory filings or engagements
for fiscal 2003. In 2004 Wheeler Wasoff, P.C. has been retained to provide
guidance on tax matters and other issues as needed.

Audit-Related Fees

For the year ended August 31, 2004, Hein + Associates, LLP also audited the
historical summary of oil and gas operations of Venus Exploration Inc., which
was included in a Form 8-K as filed by the Company, and issued currently dated
consents in connection with the Company's Form S-3 filings. For these services
Hein + Associates LLP, billed the Company $28,757. During 2004 Wheeler Wasoff,
P.C. billed the Company $5,300 related to the re-issuance of their 2003 report
and issuance of currently dated consents related to the filing of the Company's
Form S-3SB registration statements and a transition of auditors. Wheeler Wasoff,
P.C. did not provide the Company with any services for assurance and related
services that were not reasonably related to the performance of the audit or
review of the Company's financial statements and are not reported above under
"--Audit Fees."

Tax Fees

For the years ended August 31, 2004 and August 31, 2003, Wheeler Wasoff,
P.C. billed the Company $3,325 and $2,150, respectively, for professional
services for tax compliance, tax advice, and tax planning. There were no amounts
billed by Hein + Associates, LLP for professional services for tax compliance,
tax advice, and tax planning for those fiscal years.

All Other Fees

For the years ended August 31, 2004 and August 31, 2003, Hein + Associates,
LLP and Wheeler Wasoff, P.C. did not bill the Company for products and services
other than those described above.

Audit Committee Pre-Approval Policies

The audit committee currently does not have any pre-approval policies or
procedures concerning services performed by Hein + Associates, LLP or Wheeler
Wasoff, P.C. All the services performed by Hein + Associates, LLP and Wheeler
Wasoff, P.C. that are described above were pre-approved by the audit committee.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant
has caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.

PYR ENERGY CORPORATION

Date: December 2, 2004 By: /s/ D. Scott Singdahlsen
--------------------------------------
D. Scott Singdahlsen
Chief Executive Officer

In accordance with the requirements of 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.

Signatures Title Date
---------------------------- ------------------------------------------- -----------------

/s/ D. Scott Singdahlsen Chief Executive Officer, President, Chief December 2, 2004
---------------------------- Financial Officer and Chairman Of The Board
D. Scott Singdahlsen

/s/ Dennis M. Swenson Director December 2, 2004
----------------------
Dennis M. Swenson

/s/ David Kilpatrick Director December 2, 2004
----------------------------
David Kilpatrick

/s/ Bryce W. Rhodes Director December 2, 2004
----------------------------
Bryce W. Rhodes

PYR ENERGY CORPORATION

INDEX

Report of Independent Public Accounting Firms.........................F-2 - F-3

Consolidated Balance Sheets
August 31, 2004 and 2003...........................................F-4

Consolidated Statements of Operations
Years Ended August 31, 2004 and 2003...............................F-5

Consolidated Statements of Stockholders' Equity
For the Period from September 1, 2002..............................F-6

Consolidated Statements of Cash Flows
Years Ended August 31, 2004 and 2003.........................F-7 - F-8

Notes to Consolidated Financial Statements...........................F-9 - F-20

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
PYR Energy Corporation
Denver, Colorado

We have audited the consolidated balance sheet of PYR Energy Corporation and
subsidiaries as of August 31, 2004, and the related consolidated statements of
operations, stockholders' equity and cash flows for the year then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.

We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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 audit provided 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 PYR Energy
Corporation and subsidiaries as of August 31, 2004, and the results of their
operations and their cash flows for the year then ended August 31, 2004, in
conformity with U.S. generally accepted accounting principles.

/s/ HEIN & ASSOCIATES LLP
-------------------------
HEIN & ASSOCIATES LLP

Denver, Colorado
November 10, 2004

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To The Board of Directors and Stockholders
PYR ENERGY CORPORATION

We have audited the accompanying balance sheet of PYR Energy Corporation (a
development stage company) as of August 31, 2003, and the related statements of
operations, stockholders' equity and cash flows for the year then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.

We conducted our audit in accordance with standards of the Public Company
Accounting Oversight Board (United States). 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 audit provides a
reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PYR Energy Corporation as of
August 31, 2003, and the results of its operations and its cash flows for the
year then ended, in conformity with accounting principles generally accepted in
the United States of America.

/s/ Wheeler Wasoff, P.C.
------------------------
Wheeler Wasoff, P.C.

Denver, Colorado
November 25, 2003

F-3

PYR ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

AUGUST 31,
----------------------------
2004 2003
------------ ------------
ASSETS
CURRENT ASSETS:

Cash $ 6,038,156 $ 3,657,938
Oil and Gas Receivables 477,176 --
Other receivable 750,000 --
Prepaid expenses and other assets 102,239 46,559
------------ ------------
Total current assets 7,367,571 3,704,497
------------ ------------

PROPERTY AND EQUIPMENT, AT COST
Furniture and equipment, net 26,736 29,313
Oil and gas properties under full cost, net 8,851,351 5,287,837
------------ ------------
8,878,087 5,317,150
------------ ------------
OTHER ASSETS:
Deferred financing costs and other assets 65,070 68,257
------------ ------------
65,070 68,257
------------ ------------

TOTAL ASSETS $ 16,310,728 $ 9,089,904
============ ============

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 83,042 $ 25,070
Accrued expenses:
Ad valorem tax payable 65,068 69,034
Accrued interest payable 89,644 85,321
Other accrued liabilities 199,688 130,371
------------ ------------
354,400 309,796
Asset retirement obligation 868,163 727,231
------------ ------------
Total current liabilities 1,305,605 1,037,027
------------ ------------

LONG-TERM LIABILITIES:
Convertible Notes 6,623,351 6,303,975
Asset retirement obligation 289,489 118,862
------------ ------------
Total long-term liabilities 6,912,840 6,422,837

COMMITMENTS AND CONTINGENCIES (Note 8)

STOCKHOLDERS' EQUITY:
Preferred stock, $.001 par value; authorized 1,000,000 shares;
issued and outstanding - none -- --
Common stock, $.001 par value; authorized 75,000,000 shares; issued and
outstanding - 31,564,426 at 8/31/04 and 23,701,357 shares at 8/31/03 31,564 23,701
Capital in excess of par value 43,221,391 35,407,657
Accumulated deficit (35,160,672) (33,801,318)
------------ ------------
Total stockholders' equity 8,092,283 1,630,040
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 16,310,728 $ 9,089,904
============ ============

The accompanying notes are an integral part of the financial statements.

F-4

PYR ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED AUGUST 31,
----------------------------
2004 2003
------------ ------------

REVENUES:
Oil and gas revenues $ 863,087 $ 195,167
------------ ------------
863,087 195,167
------------ ------------

OPERATING EXPENSES:
Lease operating expenses 335,508 95,334
Accretion expense 99,684 76,918
Impairment -- 3,234,029
Depreciation and amortization 172,959 162,475
General and administrative 1,324,079 1,265,912
------------ ------------
Total operating expenses 1,932,230 4,834,668
------------ ------------

LOSS FROM OPERATIONS (1,069,143) (4,639,501)

OTHER INCOME (EXPENSE):
Interest income 27,431 53,520
Other income 9,244 --
Interest (expense) (326,886) (310,457)
------------ ------------
Total other income (expense) (290,211) (256,937)
------------ ------------

LOSS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (1,359,354) (4,896,438)

Cumulative effect of change in accounting principle -- (341,175)
------------ ------------

NET LOSS $ (1,359,354) $ (5,237,613)
============ ============

NET LOSS PER COMMON SHARE -BASIC AND DILUTED $ (.05) $ (.22)
============ ============

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 25,789,698 23,701,357
============ ============

The accompanying notes are an integral part of the financial statements.

F-5

PYR ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
PERIOD FROM SEPTEMBER 1, 2002 TO AUGUST 31, 2004

COMMON STOCK CAPITAL IN
--------------------------- EXCESS OF ACCUMULATED
SHARES AMOUNT PAR VALUE DEFICIT
------------ ------------ ------------ ------------

BALANCE, September 1, 2002 23,701,357 $ 23,701 $ 35,407,657 $(28,563,705)

Net (loss) -- -- -- (5,237,613)
------------ ------------ ------------ ------------

BALANCE, August 31, 2003 23,701,357 23,701 35,407,657 (33,801,318)
Issuance of common stock and warrants for
property and rights to oil and gas
technology 311,403 311 371,605 --

Exercise of common stock options for cash 51,666 52 14,931 --
Sale of common stock for cash and
underwriter warrants, net 7,500,000 7,500 7,427,198 --
Net (loss) -- -- -- (1,359,354)
------------ ------------ ------------ ------------

BALANCE, August 31, 2004 31,564,426 $ 31,564 $ 43,221,391 $(35,160,672)
============ ============ ============ ============

The accompanying notes are an integral part of the financial statements.

F-6

PYR ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED AUGUST 31,
--------------------------
2004 2003
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $(1,359,354) $(5,237,613)
Adjustments to reconcile net loss to net cash used by operating
activities
Cumulative effect of change in accounting principle -- 341,175
Depreciation and amortization 172,959 162,475
Impairment -- 3,234,029
Amortization of financing costs 3,187 3,187
Interest expense converted into debt 319,376 303,975
Accretion of asset retirement obligation 99,684 76,918
Changes in assets and liabilities
(Increase) in accounts receivable (477,176) --
(Increase) decrease in prepaids and other receivables (45,680) 805
Increase in accounts payable 57,972 7,898
Increase (decrease) in accrued expenses 151,901 (33,793)
Other (10,000) (40,000)
----------- -----------
Net cash used by operating activities (1,087,131) (1,180,944)
----------- -----------

CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (10,534) (6,261)
Cash paid for oil and gas properties (5,103,383) (1,670,943)
Proceeds from sale of exploration options 500,000 --
Proceeds from sale of oil and gas properties 631,585 --
----------- -----------
Net cash used in investing activities (3,982,332) (1,677,204)
----------- -----------

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of common stock 8,175,000 --
Proceeds from exercise of options 14,983 --
Cash paid for offering costs (740,302) --
----------- -----------
Net cash provided by financing activities 7,449,681 --
----------- -----------

NET INCREASE (DECREASE) IN CASH 2,380,218 (2,858,148)

CASH, BEGINNING OF PERIODS 3,657,938 6,516,086
----------- -----------

CASH, END OF PERIODS $ 6,038,156 $ 3,657,938
=========== ===========

The accompanying notes are an integral part of the financial statements.

F-7

PYR ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(continued)
YEARS ENDED AUGUST 31, 2004 AND 2003

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

During the years ended August 31, 2004 and 2003, the Company made no cash
payments for interest or income taxes.

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

During the year ended August 31, 2004, the Company issued warrants to the
underwriter, valued at $352,500, as partial consideration for the private
placement of common stock; issued common stock, valued at $337,916, for oil
and gas properties and technology rights; issued a warrant for common
stock, valued at $34,000, for rights to oil and gas technology; sold the
rights to drill on one of its properties to a third party for $750,000,
which was collected subsequent to year end; and increased the asset
retirement obligation by $211,875.

During the year ended August 31, 2003, the asset retirement obligation
increased by $769,175.

The accompanying notes are an integral part of the financial statements.

F-8

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
------------------------------------------------------------

Organization And Business - PYR Energy Corporation (the "Company") is an
independent oil and gas company primarily engaged in the exploration for,
acquisition, development and production of, crude oil and natural gas. The
Company's current activities are principally conducted in the Rocky
Mountains, Texas, and Gulf Coast regions of the United States.

On February 18, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail
LLC were formed as wholly owned subsidiaries of PYR Energy Corporation. The
purpose of these entities is to own and develop certain assets related to
designated individual exploration projects.

On May 7, 2004, PYR acquired certain oil and gas assets of Venus
Exploration, Inc. ("Venus") out of Bankruptcy. The Venus assets acquired
include interests in 80 non-operated wells in Utah, Oklahoma and Texas. New
drilling and workovers have been conducted since the acquisition date and
include two recent discoveries. Prior to this acquisition, the Company was
considered to be a development stage Company. As a result of the increased
revenues related to the properties acquired, the Company is no longer
considered to be a development stage company (see Note 2).

Basis Of Presentation - The accompanying consolidated financial statements
for the year ended August 31, 2004 include the Company and its three wholly
owned subsidiaries, which were formed in 2004. All significant
inter-company transactions have been eliminated upon consolidation.

Cash Equivalents - For purposes of reporting cash flows, the Company
considers as cash equivalents all highly liquid investments with a maturity
of three months or less at the time of purchase. On occasion, the Company
has cash in banks in excess of federally insured amounts. See
"Concentration of Credit Risks" below.

Receivables and Credit Policies - The Company has certain trade receivables
consisting of oil and gas sales obligations due under normal trade terms.
Management regularly reviews trade receivables and reduces the carrying
amount by a valuation allowance that reflects management's best estimate of
the amount that may not be collectible.

Other Receivables - During fiscal 2004, an unaffiliated third party
exercised an option to drill. As a result of this exercise, the Company
recorded a $750,000 receivable for this option. This was collected
subsequent to year end.

Property And Equipment - Furniture and equipment is recorded at cost.
Depreciation and amortization of assets is provided by use of the
straight-line method over the estimated useful lives of the related assets
of three to five years. Expenditures for replacements, renewals, and
betterments are capitalized. Maintenance and repairs are charged to
operations as incurred. Long-lived assets, other than oil and gas
properties, are evaluated for impairment to determine if current
circumstances and market conditions indicate the carrying amount may not be
recoverable. The Company has not recognized any impairment losses on
non-oil and gas long-lived assets.

Oil And Gas Properties - The Company utilizes the full cost method of
accounting for oil and gas activities. Under this method, subject to a
limitation based on estimated value, all costs associated with property
acquisition, exploration and development, including costs of unsuccessful
exploration, are capitalized within a cost center. The Company's oil and
gas properties are located within the United States and Canada. Properties
within these respective countries constitute separate cost centers. No gain
or loss is recognized upon the sale or abandonment of undeveloped or
producing oil and gas properties unless the sale represents a significant
portion of oil and gas properties and the gain significantly alters the
relationship between capitalized costs and proved oil and gas reserves of
the cost center. Depreciation, depletion and amortization of oil and gas
properties is computed on the units of production method based on proved
reserves. Amortizable costs include estimates of future development costs
of proved undeveloped reserves.

Capitalized costs of oil and gas properties may not exceed an amount equal
to the present value, discounted at 10%, of the estimated future net cash
flows from proved oil and gas reserves plus the cost, or estimated fair
market value, if lower, of unproved properties. Should capitalized costs
exceed this ceiling, an impairment is recognized. The present value of

F-9

estimated future net cash flows is computed by applying year end prices of
oil and natural gas to estimated future production of proved oil and gas
reserves as of year end, less estimated future expenditures to be incurred
in developing and producing the proved reserves and assuming continuation
of existing economic conditions. A reserve is provided for estimated future
costs of site restoration, dismantlement and abandonment activities (see
Note 4).

The Company utilizes the full cost accounting method of accounting for oil
and gas activities and has separate cost centers for the United States and
Canada. See Note 9 for additional discussion.

The Company leases non-producing acreage for its exploration and
development activities. The cost of these leases is included in unevaluated
oil and gas property costs recorded at the lower of cost or fair market
value.

During 2004, the Company acquired the rights to certain proven oil and gas
drilling technology for unlimited use on specified areas of interest. The
cost of these rights are being included as part of the Company's full cost
pools.

Revenue Recognition - The Company recognizes oil and gas revenues from its
interests in producing wells as oil and gas is produced and sold from these
wells. The Company has no gas balancing arrangements in place. Oil and gas
sold is not significantly different from the Company's product entitlement.

Income Taxes - The Company has adopted the provisions of SFAS 109,
Accounting for Income Taxes. SFAS 109 requires recognition of deferred tax
liabilities and assets for the expected future tax consequences of events
that have been included in the financial statements or tax returns. Under
this method, deferred tax liabilities and assets are determined based on
the difference between the financial statement and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which the
differences are expected to reverse.

Temporary differences between the time of reporting certain items for
financial and tax reporting purposes consist primarily of exploration and
development costs on oil and gas properties, and impairment pursuant to the
ceiling test limitation.

Use Of Estimates - The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date
of the financial statements and reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.

The Company's financial statements are based on a number of significant
estimates, including reliability of receivables, selection of the useful
lives for property and equipment, timing and costs associated with its
retirement obligations and oil and gas reserve quantities which are the
basis for the calculation of depreciation, depletion and impairment of oil
and gas properties.

The oil and gas industry is subject, by its nature, to environmental
hazards and clean-up costs. At this time, management knows of no
substantial costs from environmental accidents or events for which it may
be currently liable. In addition, the Company's oil and gas business makes
it vulnerable to changes in wellhead prices of crude oil and natural gas.
Such prices have been volatile in the past and can be expected to be
volatile in the future. By definition, proved reserves are based on current
oil and gas prices and estimated reserves, which is considered a
significant estimate by the Company, which is subject to changes. Price
declines reduce the estimated quantity of proved reserves and increase
annual amortization expense (which is based on proved reserves) and may
impact the impairment analysis of the Company's full cost pool.

(Loss) Per Share - (Loss) per common share is computed based on the
weighted average number of common shares outstanding during each period.
Convertible equity instruments, such as convertible notes payable, stock
options and warrants, are not considered in the calculation of net loss per
share as their inclusion would be anti-dilutive.

Share Based Compensation - In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation (SFAS 123), effective for fiscal
years beginning after December 15, 1995. This statement defines a fair
value method of accounting for employee stock options and encourages
entities to adopt that method of accounting for its stock compensation
plans. SFAS 123 allows an entity to continue to measure compensation costs

F-10

for these plans using the intrinsic value based method of accounting as
prescribed in Accounting Pronouncement Bulletin Opinion No. 25, Accounting
for Stock Issued to Employees (APB 25). The Company has elected to continue
to account for its employee stock compensation plans as prescribed under
APB 25. Had compensation cost for the Company's stock-based compensation
plans been determined based on the fair value at the grant dates for awards
under those plans consistent with the method prescribed in SFAS 123, the
Company's net (loss) and (loss) per share for the years ended August 31,
2004 and 2003 would have been increased to the pro forma amounts indicated
below:

2004 2003
----------- -----------
Net (loss):
As reported $(1,359,354) $(5,237,613)
Pro forma equity compensation expense (1,049,540) (711,165)
----------- -----------

Pro forma net loss $(2,408,894) $(5,948,778)
=========== ===========

Net pro forma loss per share:
As reported $ (0.05) $ (0.22)
=========== ===========
Pro forma $ (0.09) $ (0.25)
=========== ===========

See Note 7 with respect to assumptions used.

Gas Balancing - The Company uses the sales method of accounting for gas
balancing of gas production, and would recognize a liability if the
existing proven reserves were not adequate to cover the current imbalance
situation. As of August 31, 2004, the Company's gas production is in
balance.

Fair Value - The carrying amount reported in the balance sheet for cash,
prepaid expenses, accounts payable and accrued liabilities approximates
fair value because of the immediate or short-term maturity of these
financial instruments.

In May 2002, the Company completed the sale of $6,000,000, 4.99%
convertible promissory notes, due May 2009. The notes are convertible,
together with accrued interest, into shares of the Company's common stock
at the rate of $1.30 per share, at the option of the holder. The company
considers the notes to be stated at fair value due to arms length
negotiation of the transaction and the conversion feature.

Concentration Of Risk - Financial instruments which potentially subject the
Company to concentrations of credit risk consist of cash and receivables.
The Company maintains cash accounts at one financial institution. The
Company periodically evaluates the credit worthiness of financial
institutions, and maintains cash accounts only in large high quality
financial institutions, thereby minimizing exposure for deposits in excess
of federally insured amounts. The Company believes that credit risk
associated cash is remote.

The Company has concentrated its United States exploration and production
activities primarily in the Rocky Mountain, Texas and Gulf Coast regions.
Efforts in Canada are focused on southeast Alberta. All significant
activities in these segments have been with industry partners.

As of August 31, 2004, there were no reserves associated with the Canadian
cost center. The Company's oil and gas prospects in Canada consist of
undeveloped properties of approximately $557,000, and there were neither
revenues nor expenses recognized in conjunction with this cost center. The
Company is pursing the exploration of its Canadian prospects, and
management believes that the carrying cost of these prospects is
recoverable. Should the Company be unsuccessful in its Canadian exploration
activities, the carrying cost of these prospects will be charged to
operations.

F-11

Customers accounting for 10 percent or more of gross revenue, all
representing purchasers of oil and gas, for the years ended August 31, 2004
and 2003 are as follows:

2004 2003
------- --------

A 22% 100%
B 20% -
C 16% -
D 13% -

Fourth Quarter Adjustment - During the fourth quarter, the Company
discovered that certain issuance of common stock and warrants for
acquisition of properties and rights to oil and gas technology had
inadvertently not been recorded. Therefore, in the fourth quarter, the
Company increased stockholders' equity and oil and gas properties by
approximately $372,000. The impact on net loss and net loss per share of
this oversight was negligible.

Reclassification - Certain reclassifications have been made to the 2003
financial statements to conform to 2004 presentation. Such
reclassifications had no effect on net loss.

Recent Accounting Pronouncements - In June 2001, the FASB issued SFAS No.
141, "Business Combinations" ("SFAS No. 141") and SFAS No. 142, "Goodwill
and Intangible Assets" ("SFAS No. 142"). SFAS Nos. 141 and 142 became
effective on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141
requires all business combinations initiated after June 30, 2001 to be
accounted for using the purchase method. Additionally, SFAS No. 141
requires companies to disaggregate and report separately from goodwill
certain intangible assets. SFAS No. 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under SFAS No. 142,
goodwill and certain other intangible assets are not amortized, but rather
are reviewed annually for impairment. One interpretation that was
considered relative to these standards was that oil and gas mineral rights
held under lease and other contractual arrangements representing the right
to extract such reserves for both undeveloped and developed leaseholds
should be classified separately from oil and gas properties, as intangible
assets on the Company's consolidated balance sheets. In April 2004, the
Financial Accounting Standards Board amended SFAS Nos. 141 and 142 and
clarified the interpretation by defining mineral rights, such as oil and
gas mineral rights, as tangible assets. Accordingly, the guidelines for
accounting for intangible assets as provided in SFAS No. 142 would not
apply to oil and gas mineral rights. In accordance with this new guideline,
the Company will continue to classify its contractual rights to extract oil
and gas reserves as tangible oil and gas properties.

2. ACQUISITION OF PROPERTIES:
--------------------------

In 2004, the Company acquired certain oil and gas properties from Venus
Exploration for cash consideration of $3,230,000. The purchase also
provides for the Company to pay a net profits interest payable to the Venus
Exploration Trust ("Trust"). The net profits interest, which applies only
to the exploration and exploitation projects on the Venus acreage being
acquired, varies from 25% to 50% with respect to different Venus
exploration and exploitation project areas, and decreases by one-half of
its original amount after a total of $3,300,000 in net profits proceeds has
been paid to the Trust. Venus was in Chapter 11 Bankruptcy, and the
properties were acquired through public auction as approved by the United
States Bankruptcy Court. This acquisition was considered a purchase
transaction and the properties acquired were recorded based on the
consideration paid as of the closing date of May 8, 2004. Therefore, the
statement of operations includes the revenues and operating expenses of the
Venus properties for the period from May 2004 to August 2004.

F-12

Below is certain unaudited pro forma information based on historical
financial information assuming the acquisition had occurred as of the
beginning of fiscal 2004 and 2003:

2004 2003
----------- -----------

Revenues $ 1,847,000 $ 1,977,000
Net loss before cumulative effect of
accounting change $(1,055,000) $(4,411,000)
Net loss $(1,055,000) $(4,752,000)
Net loss per share $ (.04) $ (.17)

The above, however, is not necessarily indicative of results which would
have occurred if the transaction had closed as of the earlier date nor of
future results of operations.

To finance the purchase and to provide additional working capital, the
Company issued shares of its common stock as described in Note 7.

3. PROPERTY AND EQUIPMENT:
-----------------------

Oil and Gas Properties - Oil and gas properties at August 31, 2004 and 2003
consisted of the following:

2004 2003
------------ ------------

Oil and gas properties, full cost method

Unevaluated costs, not subject to amortization $ 5,494,323 $ 5,011,121
Evaluated costs 32,739,846 29,411,814
------------ ------------
38,234,169 34,422,935

Less accumulated depreciation, depletion,
amortization and impairment (29,382,818) (29,135,097)
------------ ------------

$ 8,851,351 $ 5,287,838
============ ============

Property acquisition costs include costs incurred to purchase, lease, or
otherwise acquire a property. Exploration costs include the costs of
geological and geophysical activity, and drilling and equipping exploratory
wells. The Company reviews and determines the cost basis of drilling
prospects on a drilling location basis.

For the year ended August 31, 2004, the Company did not recognize any
impairment expense against the capitalized oil and gas properties in the
United States., as determined by the ceiling test performed pursuant to
Regulation S-X Rule 4-10(c)(2). Additionally, for the year ended August 31,
2004, the Company did not recognize any impairment expense against the
capitalized oil and gas properties in Canada, based upon management's
determination that no impairment of undeveloped properties had occurred.
For the year ended August 31, 2003, the Company recognized impairment
expense of $451,285 for the East Lost Hills project and $2,782,744 for the
Company's undeveloped properties.

Depreciation, depletion, and amortization of oil and gas properties for the
years ended August 31, 2004 and 2003 was $159,848 and $151,284, or $6.65
and $20.50 per barrel of oil equivalent production, respectively.
Depreciation of assets recognized in accordance with the Asset Retirement
Obligation calculation is included in these amounts (see below).

Information relating to the Company's costs incurred in its oil and gas
operations during the years ended August 31, 2004 and 2003 is summarized as
follows:

F-13

2004 2003
---------- ----------

Property acquisition costs $4,646,880 $ 867,276
Exploration costs 466,529 139,117
Development costs 126,684 467,644
---------- ----------

$5,240,093 $1,474,037
========== ==========

Furniture and Equipment - Furniture and equipment at August 31, 2004 and
2003 consisted of the following:

2004 2003
--------- ---------

Furniture and equipment $ 138,699 $ 128,165
Less accumulated depreciation (111,963) (98,852)
--------- ---------

$ 26,736 $ 29,313
========= =========

Depreciation expense associated with capitalized office furniture and
equipment during fiscal 2004 and 2003 was $13,111 and $11,191 respectively.

4. ASSET RETIREMENT OBLIGATIONS:
-----------------------------

In 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets
and the associated asset retirement costs. This statement requires
companies to record the present value of obligations associated with the
retirement of tangible long-lived assets in the period in which it is
incurred. The liability is capitalized as part of the related long-lived
asset's carrying amount. Over time, accretion of the liability is
recognized as an operating expense and the capitalized cost is depreciated
over the expected useful life of the related asset. The Company's asset
retirement obligations relate primarily to the plugging, dismantlement,
removal, site reclamation and similar activities of its oil and gas
properties. Prior to adoption of this statement, such obligations were
accrued ratably over the productive lives of the assets through
depreciation, depletion and amortization of oil and gas properties without
recording a separate liability for such amounts.

The transition adjustment related to adopting SFAS 143 on September 1, 2002
was recognized as a cumulative effect of a change in accounting principle
for the year ended August 31, 2003. The cumulative effect on net loss of
adopting SFAS No. 143 for the year ended August 31, 2003 was a net
unfavorable effect of $341,175. At the time of adoption, total net assets
increased $428,000, and total liabilities increased $769,175. The amounts
recognized upon adoption are based upon numerous estimates and assumptions,
including future retirement costs, future recoverable quantities of oil and
gas, future inflation rates and the credit-adjusted risk-free interest
rate.

F-14

The following table summarizes activity related to the accounting for asset
retirement obligations for the fiscal years ended August 31, 2004 and
August 31, 2003:

2004 2003
----------- -----------

Asset retirement obligations, beginning of fiscal year $ 846,093 $ 769,175
Liabilities incurred 211,875 --
Liabilities settled -- --
Accretion of asset retirement obligation including revision
of estimates 99,684 76,918
----------- -----------

Asset retirement obligations, end of fiscal year 1,157,652 846,093
Less current portion (868,163) (727,231)
----------- -----------

Long-term portion $ 289,489 $ 118,862
=========== ===========

5. CONVERTIBLE NOTES PAYABLE:
--------------------------

In May 2002, the Company completed the sale of $6,000,000, 4.99%
convertible promissory notes, due May 2009. The notes are convertible,
together with accrued interest, into shares of the Company's common stock
at the rate of $1.30 per share, at the option of the holder. No beneficial
interest has been accrued to the notes, as the conversion price
approximates the fair market value of the common shares as of the
transaction date. Interest is payable semiannually in May and November.

At the option of the Company, accrued interest can be paid in cash or added
to the principal amount of the notes. At November 24, 2003 and May 24, 2004
the Company elected to add accrued interest of $158,677 and $160,799,
respectively, to the balance of the notes. As of August 31, 2004 the
balance of the notes is $6,623,351.

6. INCOME TAXES:
-------------

The Company follows the asset and liability method of accounting for
deferred income taxes. Deferred tax assets and liabilities are determined
based on the temporary differences between the financial statement and tax
basis of assets and liabilities. At August 31, 2004, the Company had
approximately $31,000,000 of net operating losses and $60,000 of statutory
depletion carry forward for tax return purposes.

The income tax expense recorded in the consolidated statements of
operations consists of the following:

Years Ended August 31,
--------------------------
2004 2003
----------- ------------

Current $ -- $ --
Deferred -- --
----------- ------------

$ -- $ --
=========== ============

The effective income tax rate differs from the U.S. Federal statutory
income tax rate due to the following:

Years Ended August 31,
----------------------
2004 2003
-------- --------

Federal statutory income tax rate (34%) (34%)
Increase in valuation allowance 34% 34%
-------- --------

Effective rate - -
======== ========

F-15

The principal sources of temporary differences resulting in deferred tax
assets and tax liabilities at August 31, 2004 are as follows:

2004
------------

Deferred tax assets:
Property impaired for financial reporting, but capitalized for
tax; offset by intangible drilling and other exploration costs
capitalized for financial reporting purposes but deducted for
tax purposes $ 2,500,000
Asset retirement obligation 400,000
Tax loss carryforward 11,400,000
------------

Total deferred tax assets 14,300,000

Deferred tax liabilities --
------------
Net deferred tax asset 14,300,000
Valuation allowance (14,300,000)
------------

Net deferred taxes $ --
============

The valuation allowance increased by approximately $500,000 and $1,900,000
in 2004 and 2003, respectively.

7. STOCKHOLDERS' EQUITY:
---------------------

Preferred Stock -In April 1999, the stockholders of the Company approved an
amendment to the Certificate of Incorporation pursuant to which the company
was authorized to issue 1,000,000 shares of preferred stock, with a par
value of $.001 per share. Such shares of preferred stock may be issued with
such preferences and rights as determined by the Board of Directors.

Common Stock - During the year ended August 31, 2004, the Company completed
the sale of 7,500,000 shares of common stock pursuant to a private
placement at a price of $1.09 per share. The first tranche of the
Placement, consisting of 4.5 million shares and $4,905,000 in gross
proceeds, was received and accepted in early May 2004. The second tranche
of the Placement, consisting of 3.0 million shares and $3,270,000 in gross
proceeds, was received and accepted in late June 2004. Costs of the
offering were $1,092,803, which included warrants valued at $352,500.

During the year ended August 31, 2004, the Company issued 125,000 shares of
common stock for an interest in oil and gas properties, valued as of the
date of the transaction at $90,000 ($.72 per share). The Company also
issued 186,403 shares of common stock for an interest in rights to oil and
gas technology, valued as of the date of the transaction at $247,916 ($1.33
per share).

Warrants - During the year ended August 31, 2004, the Company issued a
warrant to purchase 100,000 shares of common stock at an exercise price of
$.65 per share through December 1, 2006, for rights to oil and gas
technology. The warrants are valued at $34,000, based on the Black-Scholes
option pricing model, and this amount was included in oil and gas
properties for the year ended August 31, 2004. During fiscal 2004, the
Company also issued warrants in partial payment of a commission for
financial advisory services performed in connection with the private
placement of common stock in May and June, 2004. Included in this issuance
was (i) a warrant to purchase 225,000 shares of common stock at an exercise
price of $1.30 per share and (ii) a warrant to purchase 150,000 shares of
common stock at an exercise price of $1.24 per share. These warrants expire
on May 5, 2009 and June 11, 2009, respectively. The warrants are valued at
$229,500 and $123,000, respectively, based on the Black-Scholes option
pricing model, and these amounts were included as costs associated with the
private placement in additional paid-in capital for the year ended August
31, 2004.

F-16

At August 31, 2004, the status of outstanding warrants is as follows:

Issue Shares Exercise Expiration
Date Exercisable Price Date
---------------- ----------- -------- ----------------
May 9, 2002 200,000 $1.49 May 8, 2007
December 1, 2003 100,000 $0.65 December 1, 2006
May 5, 2004 225,000 $1.30 May 5, 2009
June 11, 2004 150,000 $1.24 June 11, 2009

At August 31, 2004, the weighted average remaining contractual life of
outstanding warrants was 3.6 years.

Stock Options - Under two stock option plans, options to purchase common
stock may be granted until 2010. Stock options are granted to employees at
exercise prices equal to the fair market value of the Company's stock at
the dates of grants. Generally, options vest 1/3 each year for a period of
three years from grant date and can have a maximum term of up to 10 years.
Options are issued to key employees and other persons who contribute to the
success of the Company. The Company has reserved 3,250,000 shares of common
stock for these plans. At August 31, 2004 and 2003, options to purchase
731,000 and 0 shares, respectively, were available to be granted pursuant
to the stock option plans.

The status of outstanding options granted pursuant to the plans are as
follows:

Number of Weighted Avg. Weighted Avg.
Shares Exercise Price Fair Value
--------- -------------- -------------

Options Outstanding - September 1, 2002
(858,165 exercisable) 1,391,500 $ 3.03
Granted 940,000 $ .70 $ .22
Exercised - -
Expired (115,000) $ 2.41
---------

Options Outstanding - August 31, 2003
(1,031,498 exercisable) 2,216,500 $ 2.07
Granted 843,000 $ .95 $ .61
Exercised (51,666) $ .29
Expired (824,000) $ 1.87
---------

Options Outstanding - August 31, 2004
(1,076,168 exercisable) 2,183,384 $ 1.76
=========

The calculated value of stock options granted under these plans, following
calculation methods prescribed by SFAS 123, uses the Black-Scholes stock
option pricing model with the following assumptions used:

2004 2003
---------- --------

Expected option life-years 3-5 7
Risk-free interest rate 3.1 - 3.9% 3.0 %
Dividend yield 0 0
Volatility 62 - 125% 107%

F-17

At August 31, 2004 and 2003, the number of options exercisable was
1,076,168 and 1,031,498, respectively, and the weighted average exercise
price of these options was $1.64 and $2.99, respectively.

Options Outstanding
------------------------------
Remaining Options
August 31, Contractual Life Exercisable at
Exercise Price 2004 (years) August 31, 2004
-------------- --------- ---------------- ---------------

$0.29 377,884 6 91,668
$0.49 - $0.92 490,000 4-5 190,000
$1.09 - $1.30 630,500 4 154,500
$1.65 - $1.82 240,000 3 195,000
$4.00 235,000 1 235,000
$5.43 - $5.98 210,000 1 210,000
--------- -----------

Total 2,183,384 1,076,168
========= ===========

8. COMMITMENTS AND CONTINGENCIES:
------------------------------

Office Leases - The Company currently leases space in Denver, Colorado and
San Antonio, Texas. Total minimum rental payments for non-cancelable
operating leases are as follows;

2005 $ 98,521
2006 70,123
2007 70,023
2008 23,237
----------

$ 261,904
==========

Rent expense was approximately $114,000 and $100,000 for the years ended
August 31, 2004 and 2003, respectively. In September 2004, the Company
renegotiated its Denver office lease, which is reflected in the table
above.

Delay Rentals - In conjunction with the Company's working interests in
undeveloped oil and gas prospects, the Company must pay approximately
$490,000 in delay rentals and other costs during the fiscal year ending
August 31, 2005 to maintain the right to explore these prospects. The
Company continually evaluates its leasehold interests, therefore certain
leases may be abandoned by the Company in the normal course of business.

Environmental - Oil and gas producing activities are subject to extensive
Federal, state and local environmental laws and regulations. These laws,
which are constantly changing, regulate the discharge of materials into the
environment and may require the Company to remove or mitigate the
environmental effects of the disposal or release of petroleum or chemical
substances at various sites. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. Expenditures that
relate to an existing condition caused by past operations and that have no
future economic benefits are expensed. Liabilities for expenditures of a
noncapital nature are recorded when environmental assessment and/or
remediation is probable, and the costs can be reasonably estimated.

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.

F-18

9. UNAUDITED OIL AND GAS RESERVE INFORMATION:
------------------------------------------

At August 31, 2004, the estimated oil and gas reserves presented herein
were derived from a report prepared by Ryder Scott Company, an independent
petroleum engineering firm. All reserves are located within the continental
United States. The Company had no oil and gas reserves at August 31, 2003.
The Company cautions that there are many inherent uncertainties in
estimating proved reserve quantities and in projecting future production
rates and the timing of development expenditures. Accordingly, these
estimates are likely to change as future information becomes available, and
these changes could be material.

The oil and gas reserve estimates presented below include all activity from
the Company's oil and gas properties for 2004. Proved reserves at the end
of the year are from the Company's Venus properties only. The Company had
no proved reserves as of August 31, 2003. The Company realized production
from its East Lost Hills prospect in 2003 and 2004, but has not recorded
any proved reserves as it had been previously determined that reserves from
this prospect were not economic to produce. Revisions of previous estimates
for 2004 is solely the result of the current year production from the East
Lost Hills prospect, and these amounts are also included in production for
2004.

Proved oil and gas reserves are the estimated quantities of crude oil,
condensate, 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 reserves are reserves expected to be recovered through
existing wells with existing equipment and operating methods.

Analysis Of Changes In Proved Reserves - Estimated quantities of proved
developed and undeveloped reserves, as well as the changes during the year
ended August 31, 2004, are as follows:

Oil and
Natural Gas Natural
Liquids Gas
(Bbls) (Mcf)
---------- ----------

Proved reserves at August 31, 2003 -- --
Purchase of reserves 629,573 1,064,205
Revisions of previous estimates 12,044 20,362
Extensions and discoveries 57,219 370,927
Sales of reserves in place -- --
Improved recovery -- --
Production (13,971) (62,494)
---------- ----------
Proved reserves at August 31, 2004 684,865 1,393,000
========== ==========

Proved developed reserves - end of year 559,629 842,000
========== ==========

The table below sets forth a standardized measure of the estimated
discounted future net cash flows attributable to the Company's proved oil
and gas reserves. Estimated future cash inflows were computed by applying
year end (August 31) prices of oil and gas (with consideration of price
changes only to the extent provided by contractual arrangements) averaging
$40.97/bbl and $4.49/mcf to the estimated future production of proved oil
and gas reserves at August 31, 2004. The future production and development
costs represent the estimated future expenditures to be incurred in
developing and producing the proved reserves, assuming continuation of
existing economic conditions. Future corporate overhead expenses and
interest expense have not been included. Discounting the annual net cash
flows at 10% illustrates the impact of timing on these future cash flows.

F-19

Standardized Measure of Estimated Discounted Future Net Cash Flows
------------------------------------------------------------------

2004
------------

Future cash inflows $ 34,192,000
Future cash outflows:
Production cost (13,519,000)
Development cost (2,426,000)
------------
Future net cash , before income taxes 18,247,000
Future income taxes --
------------
Future net cash flows 18,247,000
Adjustment to discount future annual net cash flows at 10% (7,203,000)
------------
Standardized measure of discounted future net cash flows $ 11,044,000
============

The following table summarizes the principal factors comprising the changes
in the standardized measure of estimated discounted net cash flows for the
year ended August 31, 2004.

Changes in Standardized Measure of Estimated Discounted Net Cash Flows
----------------------------------------------------------------------

2004
------------

Standardized measure, beginning of period $ --
Purchase of reserves 6,942,000
Sales of oil and gas, net of production cost (528,000)
Net change in sales prices, net of production cost 2,725,000
Discoveries, extensions and improved recoveries, net of
future development cost 1,464,000
Development costs incurred --
Change in future development costs (692,000)
Sales of reserves in place --
Revisions of quantity estimates 314,000
Accretion of discount --
Other 819,000
------------
Standardized measure, end of period $ 11,044,000
============

F-20