U.S. Securities And Exchange Commission
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended August 31, 2002
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [No Fee Required]
For the transition period from ____________ to ____________
Commission File No. 0-20879
PYR ENERGY CORPORATION
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(Name of registrant as specified in its charter)
Maryland 95-4580642
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(State or jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
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-K (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-K or any amendment to this Form 10-K. [ X ]
As of November 26, 2002, the registrant had 23,701,357 common shares
outstanding, and the aggregate market value of the common shares held by
non-affiliates was approximately $6,554,000* This calculation is based upon the
closing sale price of 45 cents per share on November 26, 2002.
* Without asserting that any of the issuer's directors or executive officers, or
the entities that own 3,113,923 and 3,634,000 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.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III, Items 11 and 12 is incorporated by
reference from the registrant's definitive proxy statement relating to its 2002
annual meeting of stockholders to be filed within 120 days after August 31,
2002.
TABLE OF CONTENTS
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Page
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Part I.........................................................................1
Item 1. and Item 2. Business And Properties..............................1
Item 3. Legal Proceedings...............................................23
Item 4. Submission Of Matters To A Vote Of Security Holders.............23
Part II.......................................................................23
Item 5. Market For Common Equity And Related Stockholder Matters........23
Item 6. Selected Financial Data.........................................24
Item 7. Management's Discussion And Analysis Of Financial
Condition And Results Of Operations.............................25
Item 7A. Quantitative And Qualitative Disclosures About Market Risk......29
Item 8. Financial Statements And Supplemental Data......................30
Item 9. Changes In And Disagreements With Accountants On
Accounting And Financial Disclosure.............................30
Part III......................................................................30
Item 10. Directors And Executive Officers Of Registrant..................30
Item 11. Executive Compensation..........................................32
Item 12. Security Ownership Of Certain Beneficial Owners And
Management......................................................32
Item 13. Certain Relationships And Related Transactions..................33
Item 14. Controls and Procedures.........................................33
Part IV.......................................................................33
Item 15. Exhibits, Financial Schedules And Reports On Form 8-K...........33
Signatures....................................................................35
Certifications................................................................36
Index to Consolidated Financial Statements...................................F-1
PART I
ITEM 1. and ITEM 2. BUSINESS AND PROPERTIES
General
PYR Energy Corporation (referred to as "PYR", the "Company", "we", "us" and
"our") is a development stage independent oil and gas exploration company with a
strategic focus on exploring for and developing significant oil and gas reserves
in deep, structurally complex formations. To date, the primary focus of our
drilling activity has been in the San Joaquin Basin of California and on our
East Lost Hills project there. We initiated this project in 1997 and brought in
industry partners and commenced initial drilling in 1998. During the fiscal year
ended August 31, 2002, we have focused our exploration efforts on the pre-drill
phases of our other high potential exploration projects in the San Joaquin Basin
and in the Rocky Mountain region. We continue to acquire acreage positions in
exploration areas we have identified as having significant oil and gas reserve
potential.
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.
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.
Developments During Fiscal 2002
Property Impairment
During the fiscal year ended August 31, 2002, the Company recognized
property impairments totaling $11,723,000 in conjunction with its capitalized
oil and gas properties. This non-cash accounting charge includes the remaining
capitalized balance at the Company's East Lost Hills project of $11,669,000,
which includes drilling and completion costs as well as land, geological and
geophysical costs. The remaining amount of the impairment includes capital costs
associated primarily with a project that the Company has in the Denver Basin of
Colorado. See below, "--Drilling Activities". As a result of this write-down,
the Company reported a net loss for the year of $13,129,828. For additional
information, see below, "--Property Impairment" and Note 1 to the Financial
Statements included in this Form 10-K.
East Lost Hills, San Joaquin Basin, California
During our fiscal year ended August 31, 2002, our East Lost Hills project
was subject to continued setbacks and delays. Although the 1998 blow-out of the
original test well, the Bellevue #1-17, evidenced high volumes and
deliverability of hydrocarbons, the project has still not established meaningful
commercial production.
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Berkley Petroleum Inc., a wholly owned subsidiary of Anadarko Petroleum
Corporation, the operator at East Lost Hills, has informed the participant group
that it no longer intends to participate in additional operations at East Lost
Hills. We are also aware of ongoing litigation between the operator and one of
the participants, and feel that this litigation has had a detrimental impact on
the project and may have contributed to lack of progress in moving the project
forward. In addition, certain leaseholds in the project have expired or will
expire in the near future.
We have continued to evaluate our ongoing participation in the East Lost
Hills project. Although we do not believe that we have adequately evaluated the
Temblor potential at East Lost Hills, the historical cost structure of
operations and the ongoing uncertainties make it very difficult to continue to
participate in this project. We will seek to limit capital expenditures at East
Lost Hills until such a point in time as many of the ongoing problems associated
with the play are mitigated. There is no assurance that additional operations
will occur at East Lost Hills. If additional operations are proposed, we will
carefully evaluate to what extent, if any, we will participate in those
operations.
During fiscal 2002, we participated in three additional wells at East Lost
Hills that were proposed and approved by the participant group in fiscal 2001.
Two of these wells, the ELH #4 and the ELH #9, are operated by Berkley Petroleum
Inc. We have a 12.1193% working interest in each of these wells. The ELH #4 well
is approximately four miles southeast of the ELH#1 well with the ELH #9 well
located approximately six miles southeast of the ELH #1 well.
The ELH #4 well was drilled and completed to a depth of approximately
20,500 feet. Although the well flowed natural gas and liquid hydrocarbons upon
initial production testing, we believe that mechanical difficulties related to
the influx of wellbore debris has prevented an adequate and full evaluation of
the reservoir potential. During initial production testing of the ELH #4, coil
tubing was used to attempt to clean out debris in the wellbore. During these
clean-out operations, a portion of the coil tubing separated and became stuck in
the wellbore. Retrieval operations have not been initiated, and it is uncertain
whether or not the coil tubing can be removed from the wellbore. The well is
currently shut-in. Although the participant group has not approved or consented,
the operator has formally proposed to plug and abandon the well.
The ELH #9 well was drilled and completed to a depth of approximately
20,100 feet. Initially, the well was production tested in the Kreyenhagen shale
underlying the Temblor formation. Non-commercial hydrocarbons were encountered
and tested from this zone, and the participants agreed to move up hole and test
the lower Temblor section. These zones were perforated by wireline and limited
production of hydrocarbons were encountered. We believe that the perforation and
testing methodology may have been inadequate to fully evaluate the reservoir
potential and that the production results are inconclusive. This well is
currently shut-in. Although the participant group has not approved or consented,
the operator has formally proposed to plug and abandon the well.
The third well, the AERA Energy LLC #1-22 NWLH, located approximately 3.5
miles northwest of the ELH #1 well, was drilled to a total depth of 20,457 feet.
The well encountered hydrocarbon shows and gas flow from several zones in the
Temblor and casing has been installed in preparation for production testing. We
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have determined to prioritize our financial resources on other prospects, and
have elected to non-consent the completion and production testing operations. We
participated in the drilling of this well through a pooling arrangement at a
4.04% working interest.
Funding and Financing
On May 24, 2002, we received $6 million in gross proceeds from the sale of
convertible notes due May 24, 2009. These notes call for semi-annual interest
payments at an annual rate of 4.99% and are convertible into shares of 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 discretion of the Company. The notes
were issued to three investment funds pursuant to exemptions from registration
under Section 3(b) and/or 4(2) of the Securities Act of 1933, as amended. We
have reflected the outstanding balance of these notes as Convertible Notes under
Long Term Debt on our August 31, 2002 balance sheet.
During the fiscal year ended August 31, 2002, we entered into an agreement
with Stonington Corporation regarding the retention of Stonington to provide
general corporate advisory services and to act as an agent and financial advisor
in connection with raising project financing for the exploration and development
of certain exploration projects we have in the San Joaquin Basin of California
and the Rocky Mountains. We do not intend to sell additional equity in order to
finance the drilling of exploration wells, but intend to establish a separate
entity that will purchase a portion of our working interests in these projects.
Markets and Major Customers
Sales of production from our ownership interest in the ELH #1 well at East
Lost Hills to ChevronTexaco accounted for all of our revenues. These revenues
currently are accruing at approximately $10,000 per month net to our interest.
ChevronTexaco has gas gathering and processing capabilities and water disposal
facilities in the area. Based on the general demand for gas, if for some
unforeseen reason we were to lose ChevronTexaco as a customer, we believe that
we would be able to find another customer. However, ChevronTexaco limits the
amount of water it accepts at its water disposal facilities. If we are unable to
dispose of produced water at the ChevronTexaco water disposal facility and if we
are not successful in finding an alternative disposal method, we may not be able
to dispose of water and, therefore could not produce and sell natural gas.
Employees and Office Space
At August 31, 2002, we had seven full time employees. We believe that our
relationship with our employees is satisfactory. None of our employees are
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.
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:
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o our inventory of California and Rocky Mountain drilling and
exploration projects,
o our control of pre-drill exploration phases, and
o our expertise in advanced seismic imaging.
To implement our strategy, we seek to:
o Carefully evaluate to what extent, if any, we will continue to
participate in operations at East Lost Hills. The East Lost Hills
project has been extremely time, labor and finance intensive. Although
we feel there is potential for significant gas reserves, meaningful
production has not been established. Because of the current cost
structure, continual cost overruns, the lack of a set direction for
development and the fragmentation of the participant group, additional
operations may not occur. Even in the event additional operations are
proposed, we may elect not to participate in additional operations.
o Initiate Exploration Drilling on Our Other Projects. We control
interests in several other exploration projects in the San Joaquin
Basin and in select areas of the Rocky Mountains. The most notable
projects in the San Joaquin Basin are our Wedge and Bulldog prospects,
which are large target reserve, deep Temblor gas prospects located to
the northwest of our East Lost Hills acreage, and our Blizzard
prospect which is a light oil Stevens target. In the Rocky Mountains,
our most notable projects are Cumberland and Mallard, located in
southwestern Wyoming, and our Montana Foothills project. In order to
be able to drill initial test wells in these projects, we are in the
process of establishing a drilling fund and intend to sell a portion
of our working interests in these projects to the drilling fund in
exchange for a carried working interest in initial test wells.
By combining participation of the drilling fund with potential
industry partners, we expect to commence drilling exploration wells in
up to five of these projects during calendar 2003.
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.
Significant Projects
Our exploration activities are focused primarily in the San Joaquin Basin
of California and in select areas of the Rocky Mountains. 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.
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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.
San Joaquin Basin, California
The San Joaquin Basin is one of the most productive oil and gas producing
basins in the continental United States. Located about 100 miles northwest of
Los Angeles, the basin contains 20 fields classified as giant, with each having
produced over 100 million barrels of oil equivalent.
The San Joaquin Basin contains six of the 25 largest oil fields in the
United States. All six of these fields were discovered between 1890 and 1911.
The basin accounts for 34% of California's actively producing fields, yet
produces more than 78% of the state's total oil and gas production. Most of the
production within the basin is located along the western and southern end of
Kern County.
The San Joaquin Basin has been dominated by major oil companies with large
fee acreage holdings and has generally been under-explored by independent
exploration and production companies. The large fields in the basin were
discovered on surface anticlines and produce predominantly heavy oil from depths
of less than 5,000 feet. As a consequence, basin operators have focused on
engineering technologies related to enhanced production practices, including
steam floods and, most recently, horizontal drilling. Deep basin targets, both
structural and stratigraphic in nature, remain largely untested with modern
seismic technology and the drill bit. Our analysis of seismic data combined with
recent discoveries of hydrocarbons at depth, leads us to believe that multiple
deep exploration opportunities exist in the San Joaquin Basin.
East Lost Hills. During 1997, we identified and undertook technical
analysis of a deep, large, untested structure in the footwall of the Lost Hills
thrust. This prospect lies directly east of and structurally below the existing
Lost Hills field, which has produced in excess of 350 million barrels of oil
equivalent from shallow depths.
In early 1998, we entered into an exploration agreement with a number of
joint interest partners to participate in the drilling of an initial exploration
well. We received cash for our share of acreage in this project and retained a
working interest of 10.575%. Of our total working interest, 6.475% was carried
in the initial well. During November 2000, we purchased an additional working
interest of 1.5443% at East Lost Hills to bring our current working interest to
12.1193%.
On May 15, 1998, drilling began on the Bellevue Resources et al. #1-17 East
Lost Hills initial exploration well, located in Kern County, California. The
well had a target depth of 19,000 feet. On November 23, 1998, the well had just
penetrated the uppermost Temblor sand at 17,600 feet when it blew out and
ignited. On December 18, 1998, the Bellevue #1-17R relief well began drilling.
The relief well was drilled to 16,668 feet, where it intersected the Bellevue
#1-17 well bore. On May 29, 1999, the Bellevue #1-17 well was controlled by
pumping heavy mud and cement into the well bore. The Bellevue #1-17 well bore
has been plugged and abandoned, and the Bellevue #1-17R well was sidetracked as
a replacement well into the targeted Temblor formation. The Bellevue #1-17R well
production tested nominal amounts of hydrocarbons and is temporarily shut-in
awaiting a decision to connect to commercial production facilities.
On August 26, 1999, we and other working interest owners began drilling the
ELH #1 well, approximately two miles northwest of the Bellevue #1-17R well. On
April 12, 2000, this well had drilled to a total depth of 19,724 feet.
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Production testing began on May 28, 2000. On July 6, 2000, based on the results
of the production testing and other analysis, we announced a natural gas
discovery at the East Lost Hills field. Onsite production facilities, 8.4 miles
of natural gas pipeline and 4.2 miles of water disposal pipeline were installed
and, on February 6, 2001, we commenced commercial production of natural gas and
liquid hydrocarbons from this well. Production from this well continued
throughout fiscal 2002.
Since shortly after commencing production on February 6, 2001, the
production from the ELH #1 well has been constrained by the lack of adequate
capacity for disposal of the produced water. Production water has been and
continues to flow through a disposal pipeline connected to disposal facilities
owned by ChevronTexaco. ChevronTexaco limits the amount of water accepted at its
disposal facility. During the fourth fiscal quarter, the ELH #1 well produced a
total of approximately 145 mmcfe, averaging approximately 1.6 mmcfe per day.
Water production during this period averaged approximately 6,175 barrels per
day.
The ELH #4 well commenced drilling on November 26, 2000 at a location
approximately four miles southeast of the ELH #1 well. This well reached a total
depth of 20,500 feet on January 17, 2002. After installing final casing, the
operator released the drilling rig and shut in the well. During July 2002, the
Kreyenhagen and lower Temblor zones were perforated via wireline for production
testing. The well did flow nominal amounts of natural gas and liquid
hydrocarbons along with debris and water. Because the rig had been released and
removed, the operator brought in a coil tubing unit to attempt to clean out the
debris from the wellbore. During this operation, a portion of the coil tubing
separated from the assembly and became lodged in the wellbore. It is uncertain
whether or not the component of coil tubing can be retrieved. The well is
currently shut-in and although the participant group has not consented or
otherwise agreed, the operator has formally proposed plugging this well.
The ELH #9 well, located approximately six miles southeast of the ELH #1
well, commenced drilling operations on July 17, 2001. On April 10, 2002, the
well reached total depth of approximately 21,100 feet. Final casing was
installed and the operator released the drilling rig on April 27, 2002. During
July 2002, the Kreyenhagen zone was perforated via wireline for production
testing. This testing resulted in delivery of non-commercial volumes of
hydrocarbons and attempts to stimulate the test zones were unsuccessful. The
lower Temblor was then perforated for production testing. During production
testing, the well flowed nominal amounts of hydrocarbons, water and debris
resulting in plugging of perforations and the wellbore. Coil tubing was used to
clean out the debris and further testing resulted in deliverability of
hydrocarbons in nominal amounts. Due to the perforation and testing methods
used, we view these production tests as inconclusive and do not reflect full
evaluation of the lower Temblor potential. Although there may be additional
productive Temblor zones above the lower Temblor, additional testing has not
been proposed. The operator has formally proposed the plugging of this well,
however the participants have not yet consented or otherwise agreed to this
proposal.
During fiscal 2002, we participated in the drilling of a third well at East
Lost Hills. The Aera Energy LLC NWLH 1-22 well located in Section 22, T25S-R20E
commenced drilling on August 23, 2001. This well is approximately three and a
half miles northwest of the ELH #1 well. We participated in the drilling of this
well, operated by Aera Energy LLC, through a pooling arrangement at a 4.04%
working interest. On August 18, 2002, this well reached total depth of 20,457
feet. The participants intend to complete the well for production testing,
however we have been notified by the operator that certain participants do not
currently have the financial ability to proceed with the completion and are
attempting to raise additional funds or bring in additional participants. Since
late August 2002, the drilling rig has remained on location on standby rate in
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anticipation of the commencement of completion operations. Because we have
determined to prioritize our financial resources on other prospects, we have
notified the operator of our non-consent election in the completion of this
well.
Pyramid Power Prospect. In April 1999, we purchased a working interest in
the Pyramid Power deep natural gas exploration project in the San Joaquin Basin.
This project is outside the East Lost Hills joint venture area. The initial test
well, located in Section 9, T25S-R18E, commenced drilling on November 22, 2001.
On July 17, 2002, the well reached total depth of 20,465 feet. Upon running
final casing, the rig was released. Berkley Petroleum Inc., a wholly owned
subsidiary of Anadarko Petroleum Corporation was operator of the well during
drilling. Upon release of the rig, Oxy Lost Hills Inc. ("Oxy") took over as
operator and Oxy will operate the completion and production testing of this
well. We originally owned a working interest in this project of 3.75%, but have
committed to assign 25% of that interest to Oxy. The new working interest of
2.81% continues to be carried through the tanks in this initial test well. The
participants at Pyramid Power jointly control approximately 16,100 gross and
14,700 net acres over the prospect.
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. We currently control approximately 12,100 gross and approximately 11,600
net acres here. Our approach is to sell down our working interest 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. We currently control approximately 15,600 gross and approximately
15,100 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 and in
a 14,000 foot test well we expect to drill during calendar 2003.
Rocky Mountain Exploration
Montana Foothills Project. This extensive natural gas exploration project,
located in northwestern 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 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 in 1989. 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.
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We currently control approximately 241,800 gross and 226,300 net acres in
this project and are currently presenting this project to potential industry
participants in order to sell down our working interest and generate exploratory
drilling activity. We anticipate retaining a working interest in this project of
between 20% and 40%.
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. The
prospect lies along 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.
We currently control approximately 5,400 gross and net acres in the project
and expect to sell down our working interest to between 25% and 50%. We have
recently received approval for our drilling permit from the State of Wyoming and
we intend to commence the drilling of an initial exploration well during 2003.
Mallard Project. The Mallard project, located within the Overthrust Belt of
SW Wyoming, is a sour gas and condensate exploration prospect in Uinta County,
Wyoming. 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 spaying 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.
We currently control approximately 3,900 gross and net acres in the project
and expect to sell down our working interest to between 25% and 50%. We intend
to commence the drilling of an initial exploration well during 2003.
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. As used in this document, the term "Mcf" means
thousand cubic feet.
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.
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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.
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.
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.
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.
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.
Reserves. Natural gas and crude oil, condensate and natural gas liquids on
a net revenue interest basis, found to be commercially recoverable.
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.
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.
9
Production and Productive Wells
On February 6, 2001, we commenced our first production from the ELH #1 well
at East Lost Hills and this production continued throughout fiscal 2002. At
August 31, 2002, the Company had production from only the ELH #1 well. During
the fiscal year ended August 31, 2002, the Company's net share of production
from this well was 39,468 mcf of natural gas and 1,600 barrels of liquid
hydrocarbons.
Drilling Activities
During the past three fiscal years, we participated in the drilling of the
following exploration and development wells:
o During the fiscal year ended August 31, 2002, we continued our
participation in three gross (0.283 net) development wells at East
Lost Hills. We also participated in one gross (0.00 net) exploration
well at the Pyramid Power prospect with a carried through the tanks
working interest. The ELH #4 well reached a total depth of
approximately 20,500 feet on November 17, 2001. The ELH #9 well
reached a total depth of approximately 21,100 feet on April 10, 2002
and the Aera Energy LLC NWLH 1-22 well reached a total depth of 20,457
feet on August 16, 2002.
o During the fiscal year ended August 31, 2001, we participated in the
drilling of three gross (0.283 net) development wells, all at East
Lost Hills. The ELH #4 well commenced drilling on November 26, 2000.
The ELH #9 well commenced drilling on July 18, 2001, and on August 23,
2001, the Aera Energy LLC NWLH 1-22 well commenced drilling.
o During the fiscal year ended August 31, 2000, we participated in the
drilling of one gross (0.121 net) exploration well and one gross
(0.121 net) development well that commenced drilling during that
fiscal year. The exploration well is the ELH #3 and the development
well is the ELH #2. The ELH #2 well reached total depth in December
2000 and was completed and production tested. This well has been
suspended pending potential connection to processing facilities. The
ELH #3 well was found to contain hydrocarbons in non-commercial
amounts.
In addition, in October 2002 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 commence drilling up to five exploration wells during
fiscal 2003 on our exploration projects other than East Lost Hills. We do not
expect to participate in the drilling of any additional wells at East Lost Hills
during 2003. 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
We commenced our first production from the ELH #1 well at East Lost Hills
on February 6, 2001. Concurrent with the end of our fiscal year ended August 31,
2001, we engaged Netherland, Sewell & Associates, Inc., independent petroleum
engineers, to prepare a reserve report for the reserves related to our ownership
interest in the East Lost Hills project. Based on this historical data of
10
constrained production and drilling costs affected by significant mechanical
difficulties, the reserve report concludes that it would be uneconomic to
produce oil and gas reserves at East Lost Hills. Therefore, at August 31, 2001,
the reserve report from our independent petroleum engineers shows no proved
reserves. No additional meaningful production was established during fiscal 2002
and, accordingly, no reserve report was prepared as of the August 31, 2002
fiscal year end. Previous to August 31, 2001, all of our oil and gas properties
were classified as undeveloped, and no reserve reports were warranted.
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
As required for oil and gas companies that utilize the full cost method of
accounting for oil and gas activities, we capitalize all costs associated with
acquisition, exploration and development activities. 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.
As described above under "--Reserves," we had no proved reserves as of
August 31, 2002. As a result, we are required to record an impairment against
our entire amortizable cost pool. This charge has no impact on our cash or cash
flows. At August 31, 2002, our amortizable cost pool was comprised of East Lost
Hills drilling and completion costs associated with our working interests in the
ELH #4, ELH #9, and the Aera NWLH 1-22 wells and allocated land, geological and
geophysical costs in the aggregate amount of approximately $11,669,000, and
capital costs associated primarily with a Colorado DJ Basin project in the
amount of approximately $54,000. Additional discussion of the charge, including
information regarding the methodology prescribed for computing the full cost
ceiling, is presented in Note 1 to our Financial Statements in this Annual
Report on Form 10-K.
Acreage
We currently control through lease, farmout, and option, the following
approximate acreage position as detailed below:
State Gross Acres Net Acres
----- ----------- ---------
California 65,000 35,000
Montana 242,000 226,000
Wyoming 12,000 12,000
------- -------
TOTAL 319,000 273,000
======= =======
11
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.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B,
636-C and 636-D ("Order No. 636"), which require interstate pipelines to provide
transportation services separately, or "unbundled," from the pipelines' sales of
gas. Also, Order No. 636 requires pipelines to provide open access
12
transportation on a nondiscriminatory basis that is equal for all natural gas
shippers. Although Order No. 636 does not directly regulate our production
activities, the FERC has stated that it intends for Order No. 636 to foster
increased competition within all phases of the natural gas industry. It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on our activities.
The courts have largely affirmed the significant features of Order No. 636
and numerous related orders pertaining to the individual pipelines, although
certain appeals remain pending and the FERC continues to review and modify their
open access regulations. In particular, the FERC is conducting a broad review of
its transportation regulations, including how they operate in conjunction with
state proposals for retail gas market restructuring, whether to eliminate
cost-of-service rates for short-term transportation, whether to allocate all
short-term capacity on the basis of competitive auctions, and whether changes to
long-term transportation policies may also be appropriate to avoid a market bias
toward short-term contracts. In February 2000, the FERC issued Order No. 637
amending certain regulations governing interstate natural gas pipeline companies
in response to the development of more competitive markets for natural gas and
natural gas transportation. The goal of Order No. 637 is to "fine tune" the open
access regulations implemented by Order No. 636 to accommodate subsequent
changes in the market. Key provisions of Order No. 637 include: (1) waiving the
price ceiling for short-term capacity release transactions until September 30,
2002, subject to review and possible extension of the program at that time; (2)
permitting value-oriented peak/off peak rates to better allocate revenue
responsibility between short-term and long-term markets; (3) permitting
term-differentiated rates, in order to better allocate risks between shippers
and the pipeline; (4) revising the regulations related to scheduling procedures,
capacity, segmentation, imbalance management, and penalties; (5) retaining the
right of first refusal ("ROFR") and the five year matching cap for long-term
shippers at maximum rates, but significantly narrowing the ROFR for customers
that the FERC does not deem to be captive; and (6) adopting new website
reporting requirements that include daily transactional data on all firm and
interruptible contracts and daily reporting of scheduled quantities at points or
segments. The new reporting requirements became effective September 1, 2000. We
cannot predict what action the FERC will take on these matters in the future,
nor can we accurately predict whether the FERC's actions will, over the long
term, achieve the goal of increasing competition in markets in which our natural
gas, once produced, is sold. However, we do not believe that we will be affected
by any action taken materially differently than other natural gas producers and
marketers with which we compete.
Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines are
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows pipelines to make rate changes to track
changes in the Producer Price Index for Finished Goods, minus one percent,
became effective January 1, 1995. We do not believe that these rules affect us
any differently than other oil producers and marketers with which we will
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
13
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 recently issued a final
rule that amended its regulations governing the valuation of crude oil produced
from federal leases. This new 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. The lawfulness of the new rule has been challenged
in federal court. We cannot predict whether this new rule will be upheld in
federal court, nor can we predict whether the MMS will take further action on
this matter. However, we do not believe that this new rule 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. Further, pursuant to a 1996 law passed by the
California State Assembly, certain segments of the power generation industry in
the state were deregulated. Toward the end of calendar 2000, this statute, along
14
with the significantly increased demand for natural gas, the increased price of
natural gas and other fuels, and the overall increase in the demand for and cost
of power generation had created a major crisis in California. The crisis
threatened to bankrupt many electric utilities because of state-imposed limits
on the ability to pass costs through to the utilities' customers. Because of a
general decline in demand for natural gas, the build up of natural gas in
storage and the resulting decrease in natural gas prices, the energy crisis in
California does not currently exist. However, because natural gas-driven
turbines generate a substantial portion of California's electricity supply, it
is possible that laws or regulations imposed at the state or federal level
intended to alleviate a potential future crisis would have a material adverse
impact on natural gas prices, marketing activities, operations or production.
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
15
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.
16
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 seven 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.
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
17
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 $3 million on exploration
and development activities during our fiscal year ending August 31, 2003. 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. We currently do not have any sources of additional financing.
Future cash flows and the availability of financing will be subject to a number
of variables, such as:
o the success of our natural gas project in the San Joaquin Basin,
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.
18
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 and in
the Rocky Mountains. This lack of diverse business operations subjects us to a
high degree of risk.
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:
19
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 commenced our first oil and gas
production on February 6, 2001, resulting in a change of classification of a
component of our capitalized oil and gas properties from undeveloped to
developed. We engaged an independent engineering firm to conduct a reserve
analysis and to prepare a reserve report for the East Lost Hills project. This
report reflected no economic reserves at our fiscal year ended August 31, 2001.
As a result, we recorded a write-down of approximately $13,340,000 to reduce the
carrying value of our oil and gas properties. No additional meaningful
production was established during our fiscal year ended August 31, 2002, and we
recorded an additional impairment of $11,723,000 against our oil and gas
properties. Additional discussion of this charge is presented in Note 1 to our
Financial Statements in this Annual Report on Form 10-K.
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,
20
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.
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.
21
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.
We have not been notified of any listing concerns by the American Stock
Exchange. However, should our stock trade at a low share price for a substantial
period of time, 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.
22
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any other current or pending legal proceeding
(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
There were no matters submitted to a vote of the Company's security holders
during the fourth quarter of the fiscal year ended August 31, 2002.
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. Before then it was included for
quotation on the OTC Bulletin Board under the symbol "PYRX." 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, 2001
First Quarter..................... $7.625 $4.500
Second Quarter.................... 9.960 6.000
Third Quarter..................... 9.900 5.070
Fourth Quarter.................... 8.700 1.750
Fiscal Year Ended August 31, 2002
First Quarter..................... $2.830 $1.500
Second Quarter.................... 2.700 1.800
Third Quarter..................... 2.250 1.150
Fourth Quarter.................... 2.350 0.700
On November 26, 2002, the last reported sales price of our common stock on
the AMEX was 45 cents.
Stockholders Of Record
As of November 26, 2002, the number of record holders of our common stock
was approximately 600 and the number of beneficial owners of our common stock
was approximately 3,300.
23
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
On May 24, 2002, we received $6 million in gross proceeds from the sale of
convertible notes due May 24, 2009. These notes call for semi-annual interest
payments at an annual rate of 4.99% and are convertible into shares of 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 discretion of the Company. The notes
were issued to three investment funds pursuant to exemptions from registration
under Section 3(b) and/or 4(2) of the Securities Act of 1933, as amended.
Proceeds from the notes will be used for capital expenditures related to our oil
and gas activities, for administrative costs and for other related costs.
On January 5, 2001, our "shelf" registration statement (SEC file number
333-51764), pertaining to the sale from time to time of up to $75 million of our
securities, was declared effective by the Securities and Exchange Commission.
The securities that may be offered by the Company pursuant to this registration
statement may include shares of common stock, shares of preferred stock, which
may be issued in the form of depositary shares evidenced by depositary receipts,
warrants to purchase common stock, preferred stock or any combination of those
securities, or any combination of any of these securities.
On March 9, 2001, we received a total of $11.6 million in gross proceeds
from the sale of 1,450,000 shares of our common stock. The common stock was sold
pursuant to a prospectus supplement with respect to the shelf registration
statement. We incurred offering expenses of $160,470 in this offering, so that
we received net proceeds of $11,439,530 from this sale of common stock. These
expenses do not include any direct or indirect payments to directors, officers,
persons owning 10% or more of any class of equity securities, or affiliates of
the Company. Because these securities were sold directly by the Company in an
offering that did not involve an underwriter, we did not pay any underwriting
discounts or commissions, finder's fees or other expenses to or for
underwriters.
Through August 31, 2002, approximately $11,288,000 of the proceeds from
this sale of common stock have been used as described in the prospectus
supplement to fund our planned exploration and development activities, primarily
in the San Joaquin Basin of California. As of August 31, 2002, the balance of
the net proceeds continue to be held for those purposes.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the
Company for each of the last five fiscal years ended August 31:
Fiscal Year Ended August 31,
----------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Operating Revenues ..................... $ 278,214 $ 1,624,096 $ 165,411 $ 116,713 $ 46,145
Net (loss) from operations ............. (13,129,828) (13,142,291) (982,547) (1,140,407) (110,807)
Net income (loss( per share) ........... (.55) (.59) (.07) (.11) (.012)
Total assets at the end of each period . 13,400,250 22,067,184 19,942,090 10,762,521 2,939,602
Long-term debt at the end of each period 6,000,000 -0- -0- 1,062 2,661
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read in conjunction with the 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-K.
Overview
We are a development stage independent oil and gas exploration company
whose 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
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.
Liquidity and Capital Resources
At August 31, 2002, we had approximately $6,030,854 in working capital.
During the fiscal year ended August 31, 2002, our capitalized costs for
undeveloped oil and gas properties decreased by approximately $4,206,000. The
decrease is the result of an impairment taken against our oil and gas properties
in the amount of $11,723,000 and $250,000 in seismic sales credited to the full
cost pool during the fiscal year ended August 31, 2002. The decrease was offset
by approximately $7,767,000 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.
During the fiscal year ended August 31, 2001, our capitalized costs for
undeveloped oil and gas properties decreased by approximately $316,000. The
decrease is the result of an impairment taken against our oil and gas properties
in the amount of $13,340,000, offset by approximately $13,024,000 of costs
incurred for drilling and completion, the cost of acquiring an additional
1.5433% working interest in our East Lost Hills project, transportation pipeline
costs, production facilities costs, delay rentals, and other related direct
costs with respect to our exploration and development projects.
25
During the fiscal year ended August 31, 2000, our capitalized costs for
undeveloped oil and gas properties increased by approximately $6,230,000. This
net increase is comprised of total costs of approximately $6,430,000 for
drilling costs, costs associated with acquiring and retaining exploration
acreage, seismic costs associated with undeveloped oil and gas projects, and
reclassification of costs paid during the fiscal year ended August 31, 1999 for
claims relating to the 1998 blowout, offset by a property impairment of $200,000
recorded against our Cal Canal project.
During the quarter ended November 30, 2000, the holders of our Series A
Convertible Preferred Stock converted all of the remaining outstanding shares of
Series A Convertible Preferred Stock into shares of common stock at a conversion
price of $.60 per share. This resulted in a cashless transaction whereby 14,263
shares of Series A Convertible Preferred Stock were converted into a total of
2,377,234 shares of common stock. At November 30, 2000, there were no remaining
shares of Series A Convertible Preferred Stock outstanding. In November 2000,
warrants to purchase 100,000 shares of common stock issued in connection with
the private placement of the Series A Convertible Preferred Stock were exercised
at the exercise price of $0.75 per share. In December 2000, warrants to purchase
an additional 16,667 shares of common stock were exercised. We received $87,500
in cash as the result of these exercises. There are no additional outstanding
warrants associated with this private placement.
During the quarter ended November 30, 2000, warrants issued in conjunction
with a private placement that was completed in May 1999 were exercised to
purchase a total of 17,125 shares of our common stock at a purchase price of
$2.50 per share. Total proceeds received from this warrant exercise were
$42,813. Previously during the fiscal year ended August 31, 2000, warrants
issued in the May 1999 private placement had been exercised to purchase a total
of 164,063 shares of our common stock for total proceeds of $410,157. During
December 2000, all the remaining outstanding warrants from the May 1999 private
placement were exercised to purchase an aggregate of 256,312 shares of common
stock, resulting in aggregate proceeds to us of $640,781.
During November 2000 and January 2001, warrants issued in conjunction with
the August 2000 private placement were exercised to purchase 144,286 shares of
common stock at an exercise price of $4.80 per share. This resulted in proceeds
to us of $692,573.
During January 2001, the holders of the remaining outstanding warrants
issued in connection with a private placement that was completed in May 2000
exercised their warrants to purchase an aggregate of 22,000 shares of common
stock for $93,500.
On March 12, 2001, we received an aggregate $11,600,000 in gross proceeds
through the sale of 1,450,000 shares of our common stock. The common stock was
sold pursuant to a shelf registration statement and prospectus supplement. After
costs and expenses, we received a net of $11,440,000. Investors consisted of a
total of ten separate funds managed by four California based institutions.
In May 2002, we received $6,000,000 in gross proceeds from the sale of
convertible notes which resulted in long term debt of $6,000,000 at August 31,
2002. We had no outstanding long-term debt at August 31, 2001. We have not
entered into any commodity swap arrangements or hedging transactions. Although
we have no current plans to do so, we may enter into commodity swap and hedging
transactions in the future in conjunction with oil and gas production.
26
It is anticipated that the future development of our business will require
additional, and possibly substantial, capital expenditures. Our capital
expenditure budget for the fiscal year ending August 31, 2003 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, including continuing results at
our East Lost Hills project. We anticipate spending a minimum of approximately
$3 million for capital expenditures relating to our existing drilling
commitments and related development expenses, and other exploration costs. 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.
Capital Expenditures
During fiscal 2002, we incurred approximately $5,825,000 for costs relating
to drilling and completing wells at our East Lost Hills Project. We incurred
approximately $1,942,000 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 2002 were
$132,569.
During fiscal 2001, we incurred approximately $10,922,000 for costs
relating to drilling and completing wells at our East Lost Hills Project, and
for acquiring an additional 1.554% working interest at East Lost Hills. We
incurred approximately $2,102,000 for costs related to our other exploration
projects including continued leasing and optioning of acreage. We generated
$1,201,979 in revenues from oil and gas production during 2001.
During fiscal 2000, we incurred approximately $1,319,000 for costs related
to continued leasing and optioning of acreage and approximately $4,038,000 for
drilling and seismic costs associated with deep exploratory drilling at our East
Lost Hills project. We had no revenues from oil and gas production during 2000.
We currently anticipate that we will participate in the drilling of up to
five exploration wells during our fiscal year ending August 31, 2003, 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.
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.
Results of Operations
The twelve months ended August 31, 2002 ("2002") compared with the twelve
months ended August 31, 2001 ("2001")
Operations during the fiscal year ended August 31, 2002 resulted in a net
loss of $13,129,828 compared with a net loss $13,142,291 for the fiscal year
ended August 31, 2001.
27
Oil and Gas Revenues and Expenses. During the year ended August 31, 2002,
we recorded $102,637 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 barrel. Lease operating expenses
during this period were $91,384. During the year ended August 31, 2001, we
recorded $1,055,382 from the sale of 99,535 mcf of natural gas for an average
price of $10.60 per mcf and $146,597 from the sale of 5,804 bbls of hydrocarbon
liquids for an average price of $25.26 per barrel. Lease operating expenses
during this period were $102,018. Production commenced at the East Lost Hills
ELH #1 well on February 6, 2001. Prior to this date, none of our oil or gas
properties was producing.
Interest Income. We recorded $145,645 and $422,117 in interest income for
the years ended August 31, 2002 and August 31, 2001, respectively. Interest
income was higher in the prior fiscal year due to interest earned on cash
balances remaining from the common stock offering in March 2001 and the private
placement completed in August of 2000.
General and Administrative Expense. We incurred $1,496,329 and $1,306,635
in general and administrative expenses during 2002 and 2001, respectively. The
increase results primarily from the value of warrants issued in conjunction with
a financial advisory agreement.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the years
ended August 31, 2002 or August 31, 2001. Although the ELH #1 began producing
during 2001, we recorded an impairment against our entire amortizable full cost
pool both at August 31, 2002 and August 31, 2001, and therefore had no costs to
amortize. We recorded $14,605 and $17,823 in depreciation expense associated
with capitalized office furniture and equipment during the years ended August
31, 2002 and August 31, 2001, respectively.
Dry Hole, Impairment and Abandonments. 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 current year impairment
charge related primarily 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. In 2001, we recorded an
impairment of $13,339,911 against our oil and gas properties as the result of
the capitalized costs of a portion of our oil and gas properties exceeding the
present value of estimated future net revenues of proved reserves. The costs
from this impairment related primarily to our East Lost Hills project, and
included costs for our Southeast Maricopa project and our interests in the Cal
Canal and Lucky Dog prospects in the approximate amount of $2,812,000.
Interest Expense. We recorded $82,894 in interest expense for the year
ended August 31, 2002 and no interest expense for the year ended August 31,
2001. The current year interest expense results from the May 24, 2002 sale of
convertible notes, for which we received $6 million in gross proceeds. 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 discretion of the Company. We have reflected the outstanding
balance of these notes as Convertible Notes under Long Term Debt on our August
31, 2002 balance sheet.
28
The twelve months ended August 31, 2001 ("2001") compared with the twelve
months ended August 31, 2000 ("2000")
Operations during the fiscal year ended August 31, 2001 resulted in a net
loss of $13,142,291 compared with a net loss $982,547 for the fiscal year ended
August 31, 2000.
Oil and Gas Revenues and Expenses. Production commenced at the East Lost
Hills ELH #1 well on February 6, 2001. We recorded $1,055,382 from the sale of
99,535 mcf of natural gas for an average price of $10.60 per mcf and $146,597
from the sale of 5,804 bbls of hydrocarbon liquids for an average price of
$25.26 per barrel during the year ended August 31, 2001. Lease operating
expenses during this period were $102,018. We recorded no revenues or expenses
from oil and gas operations for the year ended August 31, 2000. None of our oil
or gas properties was producing before February 6, 2001.
Interest Income. We recorded $422,117 and $165,411 in interest income for
the years ended August 31, 2001 and August 31, 2000, respectively. The increase
in the year ended August 31, 2001 is attributable to interest earned on cash
balances remaining from the common stock offering in March 2001 and the private
placement completed in August of 2000.
General and Administrative Expense. We incurred $1,306,635 and $929,420 in
general and administrative expenses during 2001 and 2000, respectively. The
increase is primarily attributable to unrecoverable financing costs and
increases in personnel and salaries.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the years
ended August 31, 2001 or August 31, 2000. Although we commenced our first
production during 2001, we recorded an impairment against our entire amortizable
full cost pool at August 31, 2001, and therefore had no costs to amortize. In
the prior year, none of our oil and gas properties were producing, and therefore
no DD&A expense was recognized. We recorded $17,823 and $18,327 in depreciation
expense associated with capitalized office furniture and equipment during the
years ended August 31, 2001 and August 31, 2000, respectively.
Dry Hole, Impairment and Abandonments. In 2001, we recorded an impairment
of $13,340,000 against our oil and gas properties as the result of the
capitalized costs of a portion of our oil and gas properties exceeding the
present value of estimated future net revenues of proved reserves. The costs
from this impairment relating to our East Lost Hills project include drilling
and completion costs associated with our working interests in the ELH #1, ELH
#2, ELH #3, Bellevue 1-17 and 1-17R wells and allocated land, geological and
geophysical costs. In addition, we have recorded property impairments with
respect to our Southeast Maricopa project and our interests in the Cal Canal and
Lucky Dog prospects in the approximate amount of $2,812,000. In 2000, we
recorded an impairment of $200,000 against our Cal Canal project.
Interest Expense. We recorded no interest expense for the year ended August
31, 2001 and nominal interest expense for the year ended August 31, 2000.
ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required under Item 7A is not applicable.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The Financial Statements and schedules that constitute Item 8 are attached
at the end of Annual Report on Form 10-K. An index to these Financial Statements
and schedules is also included in Item 14(a) of this Annual Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT
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 44 Chief Executive Officer, 1997
President, and Chairman
Of the Board
Andrew P. Calerich 38 Chief Financial Officer, Vice ---
President and Secretary
S. L. Hutchison 69 Director 1999
David Kilpatrick 52 Director 2002
Borden Putnam 48 Director 2002
Bryce W. Rhodes 49 Director 1999
Eric M. Sippel 41 Director 2002
Kenneth R. Berry, Jr. 50 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
30
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.
Andrew P. Calerich has served as Chief Financial Officer of the Company
since August 1997, as Secretary of the Company since May 1998 and as Vice
President since August of 1999. From 1993 to 1997, Mr. Calerich was a business
consultant specializing in accounting for public and private oil and gas
producers in Denver. From 1990 to 1993, Mr. Calerich was employed as corporate
Controller at a public oil and gas company in Denver. Mr. Calerich began his
professional career in public accounting at Arthur Andersen & Company. Mr.
Calerich is a Certified Public Accountant and earned B.S. degrees in both
Accounting and Business Administration at Regis College.
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 California oil and gas industry. 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. Previously, he served as Western Division Manager of Monterey's
corporate predecessor, Santa Fe Energy Resources, from 1990 to 1996. 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. In the past, he has served on
the Board of Directors of the Western States Petroleum Association and the
Conservation Committee of California Oil and Gas Producers. 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.
Borden Putnam became a Director of the Company in May of 2002. Mr. Putnam
has been an analyst with Eastbourne Capital Management, L.L.C. since July 2001.
Prior to Eastbourne, Mr. Putnam was a principal and analyst at RS Investment
Management from 1996 to 2001. From 1991 to 1996, Mr. Putnam was VP of Geology
for an international mining consulting firm and from 1982 to 1991, he was a
manager and district manager with Newmont Exploration. Mr. Putnam began his
career as a geologist with AMAX Exploration in 1975. He is a Registered
Professional Geologist, and holds B.S. and M.S. degrees in Geology and
Geochemistry from the New Mexico Institute of Mining and Technology. Mr. Putnam
is a member of the Society of Economic Geologists, AAPG, and SME.
S. L. Hutchison 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. Since 1979, Mr. Hutchison has served
as Vice President and Chief Financial Officer of Victory Oil Company, an oil and
gas production company based in California, and other companies in the Victory
Group of Companies. Also during that period, Mr. Hutchison has served as
Vice-President and Chief Financial Officer and a Director of Crail Capital, a
real estate investment company that is owned by Victory Oil Company, and Victex,
Inc., a real estate and oil and gas company. Mr. Hutchison also serves as Chief
Financial Officer and a director of each of the Crail Johnson Foundation and the
Independent Oil Producers Agency, and is the Treasurer and a director of the Los
Angeles Maritime Institute. Mr. Hutchison received a Bachelor's degree in
accounting from the University of Washington in 1954.
31
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. Since 1996, Mr. Rhodes has served as
Vice President of Whittier Energy Company ("WEC"), an oil and gas investment
company. 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.
Eric Sippel became a Director of the Company in May of 2002. Mr. Sippel
joined Eastbourne Capital Management, L.L.C. as its Chief Operating Officer and
General Counsel in 2000. Prior to that, he was a partner at the law firm of
Shartsis, Friese & Ginsburg LLP, in San Francisco, California, where he
practiced law from 1990-1999. Mr. Sippel currently serves on the Board of
Directors of Blacklight Power, Inc., a private company. He received his B.A.
degree with Honors in General Scholarship from Wesleyan University in 1983 and
his J.D. degree with Distinction from Stanford Law School in 1986.
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, 2002, its officers,
directors and holders of more than 10% of the Company's common stock complied
with all Section 16(a) filing requirements. 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, 2002 on behalf of the
Company's directors, officers and holders of more than 10% of the Company's
common stock.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference to the
information to be provided in the Company's definitive proxy statement for the
2003 annual meeting of shareholders, which is to be filed within 120 days after
our fiscal year end on August 31, 2002.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is incorporated by reference to the
information to be provided in the Company's definitive proxy statement for the
2003 annual meeting of shareholders, which is to be filed within 120 days after
our fiscal year end on August 31, 2002.
32
ITEM 13. 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.
During the fiscal year ended August 31, 2002, 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 14. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures
Based on an evaluation carried out under the supervision, and with the
participation of the management of the Company, including the Chief Executive
Officer and the Chief Financial Officer, during the 90 day period prior to the
filing of this report, the Company's Chief Executive Officer and Chief Financial
Officer believe the Company's disclosure controls and procedures, as defined in
Securities Exchange Act Rules 13a-14 and 15d-14, are, to the best of their
respective knowledge, effective.
(b) Changes in internal controls
Subsequent to the date of this evaluation, the Chief Executive Officer and
Chief Financial Officer are not aware of any significant changes in the
Company's internal controls, including any corrective actions with regard to
significant deficiencies and material weaknesses, or in other factors that could
significantly affect these controls to ensure that information required to be
disclosed by the Company, in reports that it files or submits under the
Securities Act of 1934, is recorded, processed, summarized and reported within
the time periods specified in Securities and Exchange Commission rules and
regulations.
PART IV
ITEM 15. EXHIBITS, FINANCIAL SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements And Financial Statement Schedules
33
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
INDEX
Independent Auditor's Report F-2
Balance Sheets
August 31, 2002 and 2001 F-3
Statements of Operations
Years Ended August 31, 2002, 2001, and 2000 and
Cumulative Amounts from Inception to August 31, 2002 F-4
Statements of Members'/ Stockholders' Equity
Period from Inception (May 31, 1996) to
December 31, 1996, Eight Months Ended August 31, 1997 and
Years Ended August 31, 1999, 2000, 2001 and 2002 F-5 - F-8
Statements of Cash Flows
Years Ended August 31, 2002, 2001, and 2000 and F-9 - F-10
Cumulative Amounts from Inception to August 31, 2002
Notes to Financial Statements F-11 - F-23
All other schedules are omitted because the required information is not
present in amounts sufficient to require submission of the schedule or because
the information required is included in the Financial Statements and Notes
thereto.
(a)(3) 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)
99.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
(1) Incorporated by reference from the Registrant's Form 10-K for the year
ended August 31, 2001.
(b) Reports On Form 8-K.
--------------------
During the fourth quarter of the fiscal year ended August 31, 2002, the
Company filed one Current Report on Form 8-K dated July 16, 2002. This event
consisted of the dissemination of a press release by the Company and was
reported under "ITEM 5. OTHER EVENTS".
34
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: November 26, 2002 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, November 26, 2002
------------------------ President and Chairman
D. Scott Singdahlsen Of The Board
/s/ S. L. Hutchison Director November 26, 2002
------------------------
S. L. Hutchison
/s/ David Kilpatrick Director November 26, 2002
------------------------
David Kilpatrick
/s/ Borden Putnam Director November 26, 2002
------------------------
Borden Putnam
/s/ Bryce W. Rhodes Director November 26, 2002
------------------------
Bryce W. Rhodes
/s/ Eric M. Sippel Director November 26, 2002
------------------------
Eric M. Sippel
/s/ Andrew P. Calerich Vice-President, Chief November 26, 2002
------------------------ Financial Officer
Andrew P. Calerich and Secretary
35
CERTIFICATIONS
I, D. Scott Singdahlsen, certify that:
1. I have reviewed this annual report on Form 10-K of PYR Energy
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 26, 2002 /s/ D. Scott Singdahlsen
----------------------------------
D. Scott Singdahlsen
Chief Executive Officer
I, Andrew P. Calerich, certify that:
1. I have reviewed this annual report on Form 10-K of PYR Energy
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent functions):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 26, 2002 /s/ Andrew P. Calerich
----------------------------------
Andrew P. Calerich
Chief Financial Officer
PYR ENERGY CORPORATION
(A Development Stage Company)
INDEX
Independent Auditor's Report F-2
Balance Sheets
August 31, 2002 and 2001 F-3
Statements of Operations
Years Ended August 31, 2002, 2001 and 2000 and
Cumulative Amounts from Inception to August 31, 2002 F-4
Statements of Members'/ Stockholders' Equity
Period from Inception (May 31, 1996) to
December 31, 1996, Eight Months Ended August 31, 1997 and
Five Years Ended August 31, 2002 F-5 - F-8
Statements of Cash Flows
Years Ended August 31, 2002, 2001 and 2000 and F-9 - F-10
Cumulative Amounts from Inception to August 31, 2002
Notes to Financial Statements F-11 - F-23
F - 1
INDEPENDENT AUDITOR'S REPORT
To The Board of Directors and Stockholders
PYR ENERGY CORPORATION
We have audited the accompanying balance sheets of PYR Energy Corporation (a
development stage company) as of August 31, 2002 and 2001, and the related
statements of operations, stockholders' equity and cash flows for each of the
three years in the period ended August 31, 2002 and cumulative amounts from
inception to August 31, 2002. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PYR Energy Corporation as of
August 31, 2002 and 2001, and the results of its operations and its cash flows
for each of the three years in the period ended August 31, 2002 and cumulative
amounts from inception to August 31, 2002 in conformity with accounting
principles generally accepted in the United States of America.
/s/ Wheeler Wasoff, P.C.
------------------------
Wheeler Wasoff, P.C.
Denver, Colorado
October 28, 2002
F - 2
PYR ENERGY CORPORATION
(A Development Stage Company)
BALANCE SHEETS
AUGUST 31, 2002 and 2001
ASSETS
2002 2001
------------ ------------
CURRENT ASSETS
Cash $ 6,516,086 $ 9,800,842
Accounts receivable -- 1,173,751
Prepaid expenses 47,365 74,636
------------ ------------
Total Current Assets 6,563,451 11,049,229
PROPERTY AND EQUIPMENT 6,805,355 11,017,955
OTHER 31,444 --
------------ ------------
$ 13,400,250 $ 22,067,184
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 532,597 $ 2,263,368
------------ ------------
Total Current Liabilities 532,597 2,263,368
------------ ------------
CONVERTIBLE NOTES PAYABLE 6,000,000 --
------------ ------------
COMMITMENTS AND CONTINGENCIES (Note 7)
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value; authorized 1,000,000 shares
Series A authorized 25,000 shares; issued and outstanding none -- --
Common stock, $.001 par value; authorized 75,000,000 shares
Issued and outstanding 23,701,357 shares (2002) and 23,691,357 shares (2001) 23,701 23,691
Capital in excess of par value 35,407,657 35,214,002
Deficit accumulated during the development stage (28,563,705) (15,433,877)
------------ ------------
6,867,653 19,803,816
------------ ------------
$ 13,400,250 $ 22,067,184
============ ============
The accompanying notes are an integral part of the financial statements.
F - 3
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF OPERATIONS
Cumulative from
Inception to
Years ended August 31, August 31,
2002 2001 2000 2002
------------ ------------ ------------ ------------
REVENUES
Oil and gas production $ 132,569 $ 1,201,979 $ -- $ 1,334,548
Interest income 145,645 422,117 165,411 891,627
Other -- -- -- 127,528
------------ ------------ ------------ ------------
278,214 1,624,096 165,411 2,353,703
------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 91,384 102,018 -- 193,402
Impairment, dry hole, and abandonments 11,722,830 13,339,911 200,000 25,584,110
Depreciation and amortization 14,605 17,823 18,327 98,601
General and administrative 1,496,329 1,306,635 929,420 5,294,424
Interest 82,894 -- 211 267,200
------------ ------------ ------------ ------------
13,408,042 14,766,387 1,147,958 31,437,737
------------ ------------ ------------ ------------
OTHER INCOME
Gain on sale of oil and gas prospects -- -- -- 556,197
------------ ------------ ------------ ------------
(13,129,828) (13,142,291) (982,547) (28,527,837)
INCOME APPLICABLE TO
PREDECESSOR LLC (Note 1) -- -- -- (35,868)
------------ ------------ ------------ ------------
NET (LOSS) (13,129,828) (13,142,291) (982,547) (28,563,705)
Less dividends on preferred stock -- (62,880) (178,621) (292,411)
------------ ------------ ------------ ------------
NET (LOSS) TO COMMON STOCKHOLDERS $(13,129,828) $(13,205,171) $ (1,161,168) $(28,856,116)
============ ============ ============ ============
NET (LOSS) PER COMMON SHARE
BASIC AND DILUTED (Note 1) $ (.55) $ (.59) $ (.07) $ (2.07)
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING
BASIC AND DILUTED (Note 1) 23,693,521 22,226,906 16,069,869 13,935,299
============ ============ ============ ============
The accompanying notes are an integral part of the financial statements.
F - 4
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY
PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996,
EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002
Deficit
Accumulated
Preferred Stock Common Stock Capital in During the
Members' ------------------- ------------------------- Excess of Development
Equity Shares Amount Shares Amount Par Value Stage
----------- -------- -------- ----------- ----------- ----------- -----------
Inception, May 31, 1996 $ -- -- $ -- -- $ -- $ -- $ --
Initial member contributions - cash 5,000 -- -- -- -- -- --
Member contribution- services 12,000 -- -- -- -- -- --
Distributions to members (24,000) -- -- -- -- -- --
Net income 18,963 -- -- -- -- -- --
----------- -------- -------- ----------- ----------- ----------- -----------
Balance, December 31, 1996 11,963 -- -- -- -- -- --
Member contributions - cash 23,000 -- -- -- -- -- --
Member contribution - services 24,000 -- -- -- -- -- --
Distributions to members (42,000) -- -- -- -- -- --
Net income - January 1, 1997 to
August 5, 1997 16,905 -- -- -- -- -- --
Issuance of common stock to members
of PYR Energy, LLC upon merger
($.008 per share) (33,868) -- -- 4,000,000 4,000 29,868 --
Recapitalization of shares issued
by Mar prior to merger -- -- -- 1,059,804 1,060 (724) --
Sales of common stock pursuant to
private placement at $.25 per share -- -- -- 2,095,000 2,095 521,655 --
Sale of common stock pursuant to
private placement at $.75 per share -- -- -- 2,000,000 2,000 1,498,000 --
Costs of private placements offerings -- -- -- -- -- (280,711) --
Net (loss) August 6, 1997 to August
31, 1997 -- -- -- -- -- -- (57,825)
----------- -------- -------- ----------- ----------- ----------- -----------
Balance, August 31, 1997 -- -- -- 9,154,804 9,155 1,768,088 (57,825)
Net (loss) -- -- -- -- -- -- (110,807)
Balance, August 31, 1998 $ -- -- $ -- 9,154,804 $ 9,155 $ 1,768,088 $ (168,632)
----------- -------- -------- ----------- ----------- ----------- -----------
The accompanying notes are an integral part of the financial statements.
F - 5
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY (continued)
PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996,
EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002
Deficit
Accumulated
Preferred Stock Common Stock Capital in During the
----------------------- ------------------------- Excess of Development
Shares Amount Shares Amount Par Value Stage
----------- -------- ------------ --------- ------------ ------------
Balance Forward -- $ -- 9,154,804 $ 9,155 $ 1,768,088 $ (168,632)
Issuance of preferred stock for convertible
notes 25,000 25 -- -- 2,499,976 --
Unamortized convertible note financing costs -- -- -- -- (73,319) --
Issuance of common stock for interest on
convertible debt, at $2.19 per share -- -- 53,326 53 116,769 --
Issuance of common stock warrants for
financing costs -- -- -- -- 56,833 --
Conversion of preferred stock to common stock
at $.60 per share (2,021) (2) 336,833 337 (335) --
Sale of common stock pursuant to private
placement for cash of $1.60 per share -- -- 4,375,000 4,375 6,995,625 --
Costs of private placement -- -- -- -- (83,155) --
Exercise of private placement warrants for
cash of $2.50 per share -- -- 3,125 3 7,809 --
Issuance of common stock for property, valued
at $.75 per share -- -- 266,666 267 199,733 --
Issuance of common stock for property, valued
at $2.00 per share -- -- 218,866 219 437,513 --
Preferred dividends paid -- -- -- -- (50,910) --
Net (loss) -- -- -- -- -- (1,140,407)
----------- -------- ------------ --------- ------------ ------------
Balance August 31, 1999 22,979 $ 23 14,408,620 $ 14,409 $ 11,874,627 $ (1,309,039)
----------- -------- ------------ --------- ------------ ------------
The accompanying notes are an integral part of the financial statements.
F - 6
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY (continued)
PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996,
EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002
Deficit
Accumulated
Preferred Stock Common Stock Capital in During the
------------------------ ---------------------------- Excess of Development
Shares Amount Shares Amounts Par Value Stage
------------ -------- ------------ ------------ ------------ ------------
Balance Forward 22,979 $ 23 14,408,620 $ 14,409 $ 11,874,627 $ (1,309,039)
Issuance of common stock for services
(valued at $4.00 per share) -- -- 5,000 5 19,995 --
Conversion of preferred stock to common
stock at $.60 per share (8,716) (9) 1,452,597 1,452 (1,443) --
Exercise of warrants for cash of $.75
per share -- -- 58,333 58 43,692 --
Exercise of private placement warrants
for cash of $2.50 per share -- -- 160,938 161 402,184 --
Issuance of common stock for payment of
preferred dividends (valued at $4.30
per share) -- -- 24,914 25 (25) --
Issuance of common stock for payment of
preferred dividends (valued at $5.24
per share) -- -- 13,617 14 (14) --
Sale of common stock pursuant to private
placement for cash of $3.25 per share -- -- 220,000 220 714,780 --
Cost of private placement -- -- -- -- (11,857) --
Exercise of common stock options -- -- 27,500 28 26,285
Retirement of common stock received for
option exercise -- -- (2,500) (3) (10,310)
Sale of common stock pursuant to private
placement for cash of $3.50 per share -- -- 2,700,000 2,700 9,447,300 --
Issuance of common stock warrants for
offering costs -- -- -- -- 110,606 --
Costs of private placement -- -- -- -- (567,436) --
Net (loss) -- -- -- -- -- (982,547)
------------ -------- ------------ ------------ ------------ ------------
Balance August 31, 2000 14,263 $ 14 19,069,019 $ 19,069 $ 22,048,384 $ (2,291,586)
------------ -------- ------------ ------------ ------------ ------------
The accompanying notes are an integral part of the financial statements.
F - 7
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY (continued)
PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996,
EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002
Deficit
Accumulated
Preferred Stock Common Stock Capital in During the
---------------------- ---------------------------- Excess of Development
Shares Amounts Shares Amounts Par Value Stage
--------- --------- ------------ ------------ ------------ ------------
Balance Forward 14,263 $ 14 19,069,019 $ 19,069 $ 22,048,384 $ (2,291,586)
Conversion of preferred stock to common
stock (14,263) (14) 2,377,234 2,377 (2,363) --
Exercise of warrants for cash of $.75 per
share -- -- 116,667 117 87,384 --
Exercise of private placement warrants for
cash of $2.50 to $4.80 per share -- -- 439,723 439 1,469,226 --
Issuance of common stock for payment of
preferred dividends (valued at $6.40
per share) -- -- 9,825 10 (10) --
Exercise of common stock options for cash
at $.69 to $3.66 per share -- -- 246,000 246 288,272
Retirement of common stock received for
option exercise -- -- (17,111) (17) (114,971)
Sale of common stock for cash of $8.00
per share -- -- 1,450,000 1,450 11,598,550 --
Costs of common stock sale -- -- -- -- (160,470) --
Net (loss) -- -- -- -- -- (13,142,291)
--------- --------- ------------ ------------ ------------ ------------
Balance August 31, 2001 -- -- 23,691,357 23,691 35,214,002 (15,433,877)
Exercise of common stock options for cash
at $1.50 per share -- -- 10,000 10 14,990 --
Issuance of common stock warrants for
services -- -- -- -- 178,665 --
Net (loss) -- -- -- -- -- (13,129,828)
--------- --------- ------------ ------------ ------------ ------------
Balance August 31, 2002 -- $ -- 23,701,357 $ 23,701 $ 35,407,657 $(28,563,705)
========= ========= ============ ============ ============ ============
The accompanying notes are an integral part of the financial statements.
F - 8
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS
Cumulative
Years Ended August 31, Amounts from
2002 2001 2000 Inception
------------ ------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) $(13,129,828) $(13,142,291) $ (982,547) $(28,527,837)
Adjustments to reconcile net (loss) to
net cash (used) by operating activities
Depreciation and amortization 14,605 17,823 18,327 98,602
Contributed services -- -- -- 36,000
Gain on sale of oil and gas prospects -- -- -- (556,197)
Impairment, dry hole and abandonments 11,722,830 13,339,911 200,000 25,584,110
Common stock issued for interest and services -- -- 20,000 136,822
Warrants issued for services 178,665 -- -- 178,665
Amortization of financing costs 867 -- -- 27,806
Amortization of marketable securities -- -- -- (20,263)
Changes in assets and liabilities
Decrease (increase) in accounts receivable 1,173,751 (1,173,751) 2,516 (566)
Decrease (increase) in prepaids 27,270 (53,801) (6,644) (51,917)
(Decrease) increase in accounts payable (1,172,192) 22,303 (105,802) (1,090,286)
Other (6,916) 1,946 -- 1,279
------------ ------------ ------------ ------------
Net cash (used) by operating activities (1,190,948) (987,860) (854,150) (4,183,782)
------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (11,293) (30,757) (4,200) (132,205)
Cash paid for oil and gas properties (8,325,204) (11,329,468) (5,929,267) (30,811,699)
Proceeds from sale of oil and gas properties 250,000 -- -- 1,300,078
Cash paid for marketable securities -- -- -- (5,090,799)
Proceeds from sale of marketable securities -- -- 5,111,062 5,111,062
Cash received (paid) for reimbursable property costs -- 381,605 -- (28,395)
------------ ------------ ------------ ------------
Net cash (used) in investing activities (8,086,497) (10,978,620) (822,405) (29,651,958)
------------ ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Members capital contributions -- -- -- 28,000
Distributions to members -- -- -- (66,000)
Cash from short-term borrowings -- -- -- 285,000
Repayment of short-term borrowings -- -- -- (285,000)
Cash received upon recapitalization and merger -- -- -- 336
Proceeds from sale of common stock -- 11,600,000 10,165,000 30,788,750
Proceeds from sale of convertible debt 6,000,000 -- -- 8,500,001
Proceeds from exercise of warrants -- 1,557,166 446,095 2,011,073
Proceeds from exercise of options 15,000 173,530 16,000 204,530
Cash paid for offering and financing costs (22,311) (160,470) (468,687) (1,058,759)
Payments on capital lease -- (920) (1,742) (5,195)
Preferred dividends paid -- -- -- (50,910)
------------ ------------ ------------ ------------
Net cash provided by financing activities 5,992,689 13,169,306 10,156,666 40,351,826
------------ ------------ ------------ ------------
NET (DECREASE) INCREASE IN CASH (3,284,756) 1,202,826 8,480,111 6,516,086
CASH, BEGINNING OF PERIODS 9,800,842 8,598,016 117,905 --
------------ ------------ ------------ ------------
CASH, END OF PERIODS $ 6,516,086 $ 9,800,842 $ 8,598,016 $ 6,516,086
============ ============ ============ ============
The accompanying notes are an integral part of the financial statements.
F - 9
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS (continued)
YEARS ENDED AUGUST 31, 2002, 2001 and 2000 and
PERIOD FROM INCEPTION TO AUGUST 31, 2002
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
During the years ended August 31, 2002, 2001 and 2000, the Company paid
cash for interest of $0, $0, and $211 respectively, on a capital lease.
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
During the year ended August 31, 2002, the Company issued warrants, valued
at $178,665, in conjunction with a financial advisory services agreement.
During the year ended August 31, 2001, the Company issued 9,825 shares of
common stock as payment of dividends on preferred stock.
During the year ended August 31, 2000, the Company issued common stock,
valued at $20,000, for services; issued warrants, valued at $110,606, as
partial consideration for a finders fee in connection with a private
placement sale of common stock; and issued 38,531 shares of common stock as
payment of dividends on preferred stock.
During the year ended August 31, 1999, the Company issued common stock,
valued at $637,732, as partial consideration for oil and gas properties;
issued common stock, valued at $116,822 for interest on convertible debt;
and issued warrants, valued at $56,833, as partial consideration for a
finders fee in connection with the sale of convertible debt.
During the year ended August 31, 1998, the Company entered into a capital
lease obligation of $5,195 for office equipment.
During 1996 and 1997 the President of the Company performed services for
PYR LLC valued at $12,000 and $24,000, respectively. The value of these
services was charged to members' equity as a non-cash capital contribution.
In August 1997, 4,000,000 shares of common stock were issued to the members
of PYR Energy, LLC ("PYR LLC") in exchange for 100 percent of the ownership
interests in PYR LLC, for which the net members' equity in PYR LLC was
$33,868. These shares were issued pursuant to a plan of reorganization and
merger effective August 6, 1997 (Note 1).
The accompanying notes are an integral part of the financial statements.
F - 10
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 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 State of California and the
Rocky Mountain region of the United States. As of August 31, 2002, the
Company is considered a development stage company as defined by Statement
of Financial Accounting Standards No. 7 (SFAS 7).
The Company's predecessor, Mar Ventures Inc. ("Mar"), was incorporated
under the laws of the State of Delaware on March 27, 1996 for the purpose
of producing and marketing traditional television programming and marketing
its film library. Mar was a public company which had no significant
operations as of July 31, 1997. On August 6, 1997 Mar acquired all the
interests in PYR Energy LLC ("PYR LLC") (a Colorado limited liability
company organized on May 31, 1996), a development stage company as defined
by SFAS No. 7. PYR LLC, an independent exploration company, was engaged in
the acquisition of oil and gas properties for exploration and exploitation
in the Rocky Mountain region and California. Effective August 6, 1997, Mar
transferred to its former president substantially all its assets and
liabilities that were related to its film library operations.
Upon completion of the acquisition of PYR LLC by Mar, PYR LLC ceased to
exist as a separate entity. Mar remained as the legal surviving entity and,
effective November 12, 1997, Mar changed its name to PYR Energy
Corporation. For financial reporting purposes, the business combination was
accounted for as an additional capitalization of Mar (a reverse acquisition
with PYR LLC as the acquirer). The operations of PYR LLC are the only
continuing operations of the Company. Effective July 02, 2001, the Company
was reincorporated in Maryland through the merger of the Company into a
wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation
The Company is an exploration stage oil and gas company. The Company's
efforts, since August 1997, have consisted of financing activities and the
acquisition of unproven properties and related seismic data. The Company
has entered into participation and farm-in agreements with industry
partners on certain of its properties pursuant to which these partners have
acquired, for cash, interests in the Company's properties. During the year
ended August 31, 1998, drilling of two test wells was commenced, with one
well being plugged and abandoned and the other suffering a blowout. During
the years ended August 31, 1999 and 2000, the Company continued its
acquisition of unproven properties and related seismic data with industry
partners, and participated in exploration of the properties, including the
drilling of exploratory wells. During the year ended August 31, 2001,
initial production of oil and gas commenced from the Company's East Lost
Hills prospect. Although initial production resulted in test revenue from
oil and gas sales of $1,201,979 being earned through August 31, 2001, a
reserve report prepared as of August 31, 2001 by an independent petroleum
engineering firm concluded that reserves from the Company's producing
properties were not economic to produce. (See Notes 2 and 3). Accordingly,
based on the ceiling test limitation required for oil and gas companies
utilizing the full cost method of accounting, the Company recognized an
impairment of $13,339,911 on its oil and gas properties at August 31, 2001.
F - 11
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
During the year ended August 31, 2002, the Company participated in ongoing
drilling operations at East Lost Hills and continued to refine seismic data
and obtain the rights for additional exploration acreage in its other
California and Rocky Mountain projects. Due to the uncertainty of whether
or not additional activity will occur at its East Lost Hills project, and
because of the uncertainty as to whether or not the Company will
participate should additional activity occur, at August 31, 2002 the
Company recognized an impairment expense of $11,722,830, primarily for the
remaining basis in its East Lost Hills project.
PROPERTY AND EQUIPMENT
Furniture and equipment is recorded at cost. Depreciation and amortization
of assets under capital lease 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, which constitutes one cost center. 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. A reserve report prepared as of August 31, 2001 by an
independent petroleum engineering firm concluded that reserves from the
Company's producing properties are not currently economic to produce and,
therefore, at August 31, 2001, the Company had no proved reserves. The
Company had not established additional production as of August 31, 2002
and, accordingly, did not prepare a reserve report.
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
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. The Company has not accrued costs for
future site restoration, dismantlement and abandonment costs related to oil
and gas properties because the Company estimates that such costs will be
offset by the salvage value of the equipment sold upon abandonment of such
properties.
F - 12
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Due to the uncertainty of whether or not additional activity will occur at
its East Lost Hills project, and because of the uncertainty as to whether
or not the Company will participate should additional activity occur, at
August 31, 2002 the Company recognized an impairment expense of
$11,722,830, primarily for the remaining basis in its East Lost Hills
project.
At August 31, 2001, the ceiling test limitation resulted in the Company's
recognizing an impairment expense of $13,339,911 on its oil and gas
properties. At August 31, 2000 and 1999, the Company had determined that an
impairment loss of $200,000 and $285,229, respectively, on evaluated oil
and gas properties be recognized.
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.
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.
At August 31, 2002, the Company had a net operating loss carryforward of
approximately $22,530,000 that may be offset against future taxable income
through 2022. These carryforwards are subject to review by the Internal
Revenue Service.
The Company has fully reserved the $4,900,000 tax benefit of operating loss
carryforwards, by a valuation allowance of the same amount, because the
likelihood of realization of the tax benefit cannot be determined. Of the
total tax benefit, $1,800,000 is attributable to 2002.
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.
F - 13
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 -ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
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. Price declines reduce the
estimated quantity of proved reserves and increase annual amortization
expense (which is based on proved reserves).
(LOSS) PER SHARE
(Loss) per common share is computed based on the weighted average number of
common shares outstanding during each period. Common shares issued to the
members of PYR LLC upon completion of the merger are considered outstanding
for all periods presented. 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
antidilutive.
SHARE BASED COMPENSATION
In October 1995, SFAS 123, "Accounting for Stock-Based Compensation", was
issued. This standard defines a fair value based method of accounting for
an employee stock option or similar equity instrument. This statement gives
entities a choice of recognizing related compensation expense by adopting
the new fair value method or to continue to measure compensation using the
intrinsic value approach under Accounting Principles Board (APB) Opinion
No. 25. The Company has elected to utilize APB 25 for measurement; and
will, pursuant to SFAS 123, disclose supplementally the pro forma effects
on net income and earnings per share of using the new measurement criteria.
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 below, "Concentration of Credit
Risks".
RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("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. SFAS 143 generally requires obligations associated with
asset retirements to be recognized earlier and displayed as liabilities
rather than as contra-assets. The pronouncement is effective for financial
statements issued for fiscal years beginning after June 15, 2002.
Management does not believe that the adoption of SFAS 143 will have any
impact on its financial position or results of operations.
In August 2001, FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS 144 addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. SFAS 144
establishes a single accounting model for long-lived assets to be disposed
of by sale. The pronouncement is effective for financial statements issued
for fiscal years beginning after December 15, 2001. Management does not
believe that the adoption of SFAS 144 will have any impact on its financial
position or results of operations.
F - 14
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 -ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
In June 2002, FASB issued SFAS 146, "Accounting for Costs Associated with
Exit or Disposal Activities." SFAS 146 addresses financial accounting and
reporting for costs associated with exit or disposal activities and
nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an
Activity." SFAS 146 generally requires a liability for a cost associated
with an exit or disposal activity to be recognized and measured initially
at its fair value in the period in which the liability is incurred. The
pronouncement is effective for exit or disposal activities initiated after
December 31, 2002. Management does not believe that the adoption of SFAS
146 will have any impact on its financial position or results of
operations.
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.
CONCENTRATION OF CREDIT 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.
RECLASSIFICATION
Certain reclassifications have been made to 2001 and 2000 amounts to
conform to the 2002 presentation.
NOTE 2 - ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE
Accounts receivable at August 31, 2001 included $1,173,155 of net revenue
due from operator for oil and gas sales for the initial period from
February to August 2001. At August 31, 2001, the Company had not received
any payments for production from the operator. During 2002, the Company and
the operator agreed to offset the receivable against payments due to the
operator for cash calls and other liabilities in an amount equal to the
revenue due. As of August 31, 2001, the Company's liability due to the
operator exceeded accounts receivable for oil and gas sales by $774,037,
including $456,585 for drilling costs not billed as of August 31, 2001.
Accounts payable and accrued liabilities at August 31, 2002 and 2001 are as
follows:
2002 2001
---------- ----------
Due to operators $ 339,475 $1,947,192
Trade payables 49,132 254,213
Ad Valorem Tax 61,963 61,963
Accrued interest 82,027 --
---------- ----------
$ 532,597 $2,263,368
========== ==========
F - 15
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 3 - PROPERTY AND EQUIPMENT
Property and equipment at August 31, 2002 and 2001 consisted of the
following:
2002 2001
------------ ------------
Oil and gas properties, full cost method
Unevaluated costs, not subject to
amortization or ceiling test $ 6,771,111 $ 10,977,317
Evaluated costs 25,547,971 13,825,140
Furniture and equipment 121,904 118,208
------------ ------------
32,440,986 24,920,665
Less accumulated depreciation,
amortization, and impairment (25,635,631) (13,902,710)
------------ ------------
$ 6,805,355 $ 11,017,955
============ ============
Information relating to the Company's costs incurred in its oil and gas
operations during the years ended August 31, 2002, 2001, and 2000 is
summarized as follows:
2002 2001 2000
----------- ----------- -----------
Property acquisition costs,
unproved properties $ 1,790,820 $ 4,114,449 $ 1,318,813
Exploration costs 1,519,819 2,448,990 4,610,454
Development costs 4,455,986 6,460,201 --
----------- ----------- -----------
$ 7,766,625 $13,023,640 $ 5,929,267
=========== =========== ===========
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.
At August 31, 2002, the Company recognized an impairment expense of
$11,722,830, primarily for the remaining basis in its East Lost Hills
project. It is uncertain as to whether or not additional activity will
occur at its East Lost Hills project, and it is uncertain as to whether or
not the Company will participate should additional activity occur.
During the year ended August 31, 2001, the Company earned its initial
revenues from its oil and gas producing activities. A reserve report
prepared as of August 31, 2001 by an independent petroleum engineering firm
concluded that reserves from the Company's producing properties are not
economic to produce, and, therefore, at August 31, 2001, the Company had no
proved reserves. Therefore, the Company has recorded an impairment of
$13,339,911 based on the ceiling test limitation. The Company recorded
impairment losses on undeveloped oil and gas properties of $200,000 for the
year ended August 31, 2000.
F - 16
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 3 - PROPERTY AND EQUIPMENT (continued)
At August 31, 2002, 2001, and 2000, accumulated charges to impairment were
$25,547,970, $13,825,140, and $485,229, respectively.
Depreciation expense for the years ended August 31, 2002, 2001, and 2000
was $14,605, $17,823, and $18,327, respectively.
In November 2000, the Company purchased from a privately held non-related
entity an additional 1.544% interest in the East Lost Hills project. At
August 31, 2002, the Company had a 12.1193% interest in East Lost Hills.
NOTE 4 - 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.
NOTE 5 - 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. The Board of Directors authorized the designation of a "Series A
Preferred Stock," consisting of 25,000 shares, face value of $100 per share
and a 10% cumulative dividend payable in cash or shares of common stock on
January 1 and July 1 of each year. Holders of Series A Preferred Stock
receive preference in the event of any liquidation, dissolution or winding
up of the Company. The shares of Series A Preferred Stock were convertible
into shares of common stock of the Company at an initial conversion price
of $.60 per share. No beneficial interest has been accrued to the preferred
stockholders as the conversion price of $.60 per share was substantially in
excess of the fair market value of the common shares as of the transaction
date.
In April 1999, the holders of $2,500,000 of 10% convertible notes, due
October 1999, converted the notes to 25,000 shares of Series A Preferred
Stock. As of August 31, 2001, all shares of Series A Preferred Stock were
converted to 4,166,664 shares of common stock at the initial conversion
price of $.60 per share.
COMMON STOCK
Effective August 6, 1997, Mar completed a merger with PYR LLC (Note 1). In
conjunction with the merger, the members of PYR LLC received 4,000,000
shares of common stock of Mar. These shares were recorded at the net
members' equity of PYR LLC as of that date of $33,868. The 1,059,804 Mar
shares outstanding as of the date of merger were recapitalized to the net
assets of Mar of $336. For financial statement reporting purposes, this
transaction was treated as a reverse acquisition whereby PYR LLC was
considered the surviving and reporting entity. For legal purposes, however,
Mar remained as the surviving entity; therefore, the capital structure of
the Company was accordingly restated.
F - 17
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 5 - STOCKHOLDERS' EQUITY (continued)
In July 1997, the Company completed the sale of common stock and warrants
pursuant to a private placement as follows:
o 2,095,000 units, at a price of $.25 per unit, consisting of 2,095,000
shares of common stock, warrants to purchase 1,047,500 shares of
common stock at an exercise price of $1.25 per share before October
31, 1997, and warrants to purchase 1,047,500 shares of common stock at
an exercise price of $1.75 per share before January 31, 1998.
Subsequent to the offering, each of the warrant expiration dates was
extended one or more times, and all the warrants ultimately expired
without having been exercised.
In August 1997, the Company completed the sale of common stock and warrants
pursuant to a private placement as follows:
o 2,000,000 units, at a price of $.75 per unit, consisting of 2,000,000
shares of common stock, warrants to purchase 1,000,000 shares of
common stock at an exercise price of $1.25 per share before October
31, 1997, and warrants to purchase 1,000,000 shares of common stock at
an exercise price of $1.75 per share before January 31, 1998.
Subsequent to the offering, each of the warrant expiration dates was
extended one or more times, and all the warrants ultimately expired
without having been exercised.
Proceeds from these offerings were $523,750 and $1,500,000, respectively,
before costs of the offerings of $280,711.
In May 1999, the Company completed the sale of 437,500 units of common
stock and warrants pursuant to a private placement at a price of $16 per
unit. Each unit consisted of 10 shares of common stock and one warrant to
purchase one share of common stock at an exercise price of $2.50 per share
for a period of five years. The Company may repurchase the warrants for
$.001 per warrant at any time after the weighted average trading price of
the Company's common stock has been at least $6.00 per share for a 45-day
period. Proceeds from the offering were $7,000,000, before costs of the
offering of $83,155.
During the year ended August 31, 1999, the Company issued shares of common
stock, valued at the non-discounted trading market price as of the date of
the transaction, in conjunction with the assignment to the Company of
certain undeveloped oil and gas prospects located in California as follows:
o 266,666 shares, valued at $.75 per share, as full consideration for
property received.
o 218,866 shares, valued at $2.00 per share, as partial consideration
for property received.
In April 1999, the Company issued 53,326 shares of common stock for accrued
interest on convertible notes of $116,822. The shares issued were valued at
$2.19 per share, the non-discounted trading price of the Company's common
stock at the transaction date.
In May 2000, the Company completed the sale of 22,000 units of common stock
and warrants pursuant to a private placement at a price of $32.50 per unit.
Each unit consisted of 10 shares of common stock and one warrant to
purchase one share of common stock at an exercise price of $4.25 per share
for a period of three years. The Company may repurchase the warrants for
$.001 per warrant at any time after the weighted average trading price of
the Company's common stock has been at least $7.50 per share for a 30 day
period. Proceeds from the offering were $715,000, before costs of the
offering of $11,857.
F - 18
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 5 - STOCKHOLDERS' EQUITY (continued)
In August 2000, the Company completed the sale of 540,000 units of common
stock and warrants pursuant to a private placement at a price of $17.50 per
unit. Each unit consisted of five shares of common stock and one warrant to
purchase one share of common stock at an exercise price of $4.80 per share
for a period of three years. The Company may repurchase the warrants for
$.001 per warrant at any time after the weighted average trading price of
the Company's common stock has been at least $10.00 per share for a 30 day
period. Proceeds from the offering were $9,450,000, before costs of the
offering of $567,436, which included warrants valued at $110,606.
During the year ended August 31, 2000, the Company issued 5,000 shares of
common stock for services, valued at the non-discounted trading market
price as of the date of the transaction of $20,000 ($4.00 per share).
During the year ended August 31, 2001, the Company sold 1,450,000 shares of
common stock pursuant to a shelf registration at a price of $8.00 per
share. Proceeds from the offering were $11,600,000 before costs of
$160,470.
During the year ended August 31, 2002, options to acquire 10,000 shares of
common stock, at $1.50 per share, were exercised.
WARRANTS
In 2000, the Company issued warrants to purchase 70,875 shares of common
stock at an exercise price of $5.50 per share through July 31, 2003 as
partial consideration for a finder's fee in conjunction with the private
placement of common stock. The warrants are valued at $110,606, using the
Black-Scholes option pricing model. In May 2000, in conjunction with the
sale of units of common stock and warrants as described above, the Company
issued warrants to purchase 22,000 shares of common stock at an exercise
price of $4.25 through May 19, 2003. In August 2000, in conjunction with
the sale of units and common stock, the Company issued warrants to purchase
540,000 shares of common stock at an exercise price of $4.80 through July
31, 2003. At August 31, 2002, 395,714 warrants were outstanding.
In May 2002, the Company issued warrants to purchase 200,000 shares of
common stock at an exercise price of $1.49 per share through May 8, 2007,
as partial consideration for a financial advisory services agreement. The
warrants are valued at $178,665, based on the Black-Scholes option pricing
model, and this amount is included in general and administrative expenses
as of August 31, 2002.
At August 31, 2002, the status of outstanding warrants is as follows:
Issue Shares Exercise Expiration
Date Exercisable Price Date
---- ----------- ----- ----
July 31, 2000 395,714 $4.80 July 31, 2003
August 1, 2000 70,875 $5.50 July 31, 2003
May 9, 2002 200,000 $1.49 May 8, 2007
At August 31, 2002, the per share weighted average exercise price of
outstanding warrants was $3.88 per share and the weighted average remaining
contractual life was 2.0 years.
F - 19
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 6 - STOCK OPTION PLAN
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 2,500,000 shares of common
stock for these plans. At August 31, 2002 and 2001, options to purchase
825,000 and 1,000,000 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, 1999 821,000 $1.20 $ .74
(149,000 exercisable)
Granted 379,000 $3.06 $2.37
Exercised (27,500) $ .96
-------
Options Outstanding - August 31, 2000 1,172,500 $2.12 $1.26
(447,500 exercisable)
Granted 300,000 $6.10 $3.66
Exercised (246,000) $1.17
--------
Options Outstanding - August 31, 2001 1,226,500 $3.31 $1.94
(537,333 exercisable)
Granted 315,000 $1.66 $1.18
Exercised (10,000) $1.50
Expired (140,000) $2.57
--------
Options Outstanding - August 31, 2002
(858,165 exercisable) 1,391,500 $3.03 $1.90
=========
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:
2002 2001 2000
---- ---- ----
Expected option life-years 5 5 2-5
Risk-free interest rate 4.375% 5.75% 5.50%
Dividend yield 0 0 0
Volatility 82-89% 68-75% 71-81%
At August 31, 2002, the number of options exercisable was 858,165, the
weighted average exercise price of these options was $2.57, the weighted
average remaining contractual life of the options was 1.97 years and the
exercise price was $.69 to $8.63 per share.
F - 20
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 6 - STOCK OPTION PLAN (continued)
The Company has adopted the disclosure-only provisions of SFAS 123. Had
compensation cost for the Company's stock option plan been determined based
on the fair value at the grant date consistent with the provisions of SFAS
123, the Company's net loss and loss per share for 2002, 2001, and 2000
would have been increased to the pro forma amounts indicated below:
2002 2001 2000
------------ ------------ -----------
Net (loss) applicable to common stockholders - as reported $(13,129,828) $(13,205,171) $(1,161,168)
============ ============ ===========
Net (loss) applicable to common stockholders - pro forma $(13,995,781) $(13,632,412) $(1,483,622)
============ ============ ===========
(Loss) per share - as reported $ (.55) $ (.59) $ (.07)
============ ============ ===========
(Loss) per share - pro forma $ (.59) $ (.61) $ (.09)
============ ============ ===========
NOTE 7 - COMMITMENTS AND CONTINGENCIES
The Company has entered into a non-cancelable lease, as amended, for office
facilities. Minimum payments due under this lease are as follows:
Year ending August 31,
2003 $97,723
2004 97,723
Rent expense was $98,415, $58,988, and $41,036 for the years ended August
31, 2002, 2001, and 2000, respectively.
In conjunction with the Company's working interests in undeveloped oil and
gas prospects, the Company must pay approximately $1,120,000 in delay
rentals and other costs during the fiscal year ending August 31, 2003 to
maintain the right to explore these prospects.
The Company may be subject to various possible contingencies which are
derived primarily from interpretations of federal and state laws and
regulations affecting the oil and gas industry. Although management
believes it has complied with the various laws and regulations, new rulings
and interpretations may require the Company to make adjustments.
NOTE 8 - SEGMENT REPORTING
In June 1997, SFAS 131, "Disclosure about Segments of an Enterprise and
Related Information", was issued, which amends the requirements for a
public enterprise to report financial and descriptive information about its
reportable operating segments. Operating segments, as defined in the
pronouncement, are components of an enterprise about which separate
financial information is available and that are evaluated regularly by the
Company in deciding how to allocate resources and in assessing performance.
The financial information is required to be reported on the basis that is
used internally for evaluating segment performance and deciding how to
allocate resources to segments.
The Company has one reportable segment, oil and gas exploration and
production. The Company has concentrated its oil and gas acquisition and
exploration activities in the western United States, primarily in
California and the Rocky Mountain region. All significant activities in
this segment have been with industry partners.
F - 21
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 8 - SEGMENT REPORTING (continued)
During 2001, initial production commenced on the Company's East Lost Hills
Prospect in California, and production continued through 2002. Results of
operations for oil and gas operations in 2002 and 2001 are as follows:
2002 2001
------------ ------------
Revenues
Oil and gas sales $ 132,569 $ 1,201,979
------------ ------------
Expense
Lease operating expense 91,384 40,055
Ad Valorem Taxes -- 61,963
Impairment 11,722,830 13,339,911
------------ ------------
11,814,214 13,441,929
------------ ------------
(Loss) from oil and gas operations $(11,681,645) $(12,239,950)
============ ============
All sales of oil and gas were made to one customer.
No depletion has been recorded on oil and gas properties. The Company
recorded impairments against its entire amortizable full cost pool as of
August 31, 2002, and 2001 and accordingly, had no costs to amortize. (See
Note 3).
NOTE 9 - COMPREHENSIVE INCOME
There are no adjustments necessary to net (loss) as presented in the
accompanying statements of operations to derive comprehensive income in
accordance with SFAS 130, "Reporting Comprehensive Income."
F-22
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 10 - QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each quarter
for the years ended August 31, 2002, 2001 and 2000:
Three Months Ended
2002 11/30/01 2/28/02 5/31/02 8/31/02
Revenues $ 108,914 $ 58,564 $ 62,087 $ 48,649
------------ ------------ ------------ ------------
Operating expenses
Lease operating expenses 25,167 6,794 28,808 30,615
Impairment, dry hole and abandonments 113,544 -- -- 11,609,286
Depreciation and amortization 3,496 3,730 3,691 3,688
General and administrative 324,143 328,142 323,474 520,570
Interest
-- -- 6,562 76,332
------------ ------------ ------------ ------------
466,350 338,666 362,535 12,240,491
------------ ------------ ------------ ------------
Net (Loss) $ (357,436) $ (280,102) $ (300,448) $(12,191,842)
============ ============ ============ ============
Net (Loss) per common share
Basic and diluted $ (.02) $ (.01) $ (.01) $ (.51)
============ ============ ============ ============
In the quarter ended August 31, 2002, the Company recorded an impairment of
$11,560,212 on its East Lost Hills project.
Three Months Ended
2001 11/30/00 2/28/01 5/31/01 8/31/01
Revenues $ 111,128 $ 309,566 $ 965,155 $ 238,247
------------ ------------ ------------ ------------
Operating expenses
Lease operating expenses -- 3,052 78,005 20,961
Impairment -- -- -- 13,339,911
Depreciation and amortization 4,098 4,843 5,507 3,375
General and administrative 254,248 320,781 370,021 361,585
------------ ------------ ------------ ------------
258,346 328,676 453,533 13,725,832
------------ ------------ ------------ ------------
Net (Loss) Income $ (147,218) $ (19,110) $ 511,622 $(13,487,585)
============ ============ ============ ============
Net (Loss ) income per common share
Basic and diluted $ (.007) $ (.001) $ .022 $ (.569)
============ ============ ============ ============
In the quarter ended August 31, 2001, the Company recorded an impairment of
$13,339,911 on its oil and gas properties due to a ceiling test limitation.
Included in the impairment is a reclassification of depletion originally
recorded on oil and gas properties of $16,035 and $52,421 for the quarters
ended February 28, 2001 and May 31, 2001, respectively.
F-23