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, 2001
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [No Fee Required]
For the transition period from to
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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
incorporation or organization) Identification No.)
1675 Broadway, Suite 2450, Denver, CO 80202
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (303) 825-3748
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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
riling 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 December 12, 2001, the registrant had 23,691,357 common shares
outstanding, and the aggregate market value of the common shares held by
non-affiliates was approximately $36,234,000*. This calculation is based upon
the closing sale price of $1.99 per share on December 12, 2001.
* Without asserting that any of the issuer's directors or executive officers, or
the entity that owns 3,113,923 shares of common stock is an affiliate, 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,
2001.
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.............................................22
Item 4. Submission Of Matters To A Vote Of Security Holders...........22
Part II......................................................................22
Item 5. Market For Common Equity And Related Stockholder Matters......22
Item 6. Selected Financial Data.......................................23
Item 7. Management's Discussion And Analysis Of Financial Condition
And Results Of Operations.....................................24
Item 7A. Quantitative And Qualitative Disclosures About Market Risk....28
Item 8. Financial Statements And Supplemental Data....................28
Item 9. Changes In And Disagreements With Accountants On
Accounting And Financial Disclosure...........................28
Part III.....................................................................28
Item 10. Directors And Executive Officers Of Registrant................28
Item 11. Executive Compensation........................................30
Item 12. Security Ownership Of Certain Beneficial
Owners And Management.........................................31
Item 13. Certain Relationships And Related Transactions................31
Part IV......................................................................31
Item 14. Exhibits, Financial Schedules And Reports On Form 8-K.........31
Signatures...................................................................33
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, 2001, 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 2001
Property Impairment
At August 31, 2001, the Company recorded a ceiling test write-down of
$13,340,000 in conjunction with its capitalized oil and gas properties. This
non-cash accounting charge is comprised of approximately $10,528,000 of costs at
the Company's East Lost Hills project, which includes drilling and completion
costs associated with its working interests in the ELH #1, ELH #2, ELH #3,
Bellevue 1-17 and 1-17R wells and allocated land, geological and geophysical
costs. Also included in the impairment are capital costs associated with the
Company's Southeast Maricopa project and costs associated with the Company's
interests in the Cal Canal and Lucky Dog prospects in the approximate amount of
$2,812,000. As a result of this write-down, the Company reported a net loss for
the year of $13,142,000. 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, 2001, we acquired, from a private
entity, an additional 1.544% working interest at East Lost Hills. As a result of
this acquisition, our total working interest in the approximately 37,000 gross
and approximately 33,000 net acres increased to 12.1193%. The ELH #1 well began
producing natural gas and liquid hydrocarbons on February 6, 2001, providing us
with our first revenues from oil and gas production. During March of 2001, the
previous operator of the East Lost Hills project, Berkley Petroleum Inc., was
acquired by Anadarko Petroleum Corporation and Anadarko became operator of the
East Lost Hills project.
1
We participated in the drilling and completion of two additional East Lost
Hills wells during fiscal 2001. The ELH #2 well was drilled and completed to a
depth of 18,011 feet. Although this well flowed natural gas and liquid
hydrocarbons upon production testing, we believe mechanical issues prevented a
thorough test of the reservoir. This well has been shut-in, awaiting a decision
by the participant group to connect this well to processing facilities. The ELH
#3 well was drilled to test a separate structure directly west of the East Lost
Hills structure. This well was drilled to 21,769 feet and, upon production
testing, was found to be non-productive. Because this wellbore could potentially
be used to sidetrack to a new location in the East Lost Hills structure, the ELH
#3 well has not been plugged and abandoned.
We are participating in three additional wells currently drilling at East
Lost Hills. Two of these wells, the ELH #4 and the ELH #9, are operated by
Anadarko. 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 and the ELH #9
well is approximately six miles southeast of the ELH #1 well. A third well, the
Aera Energy LLC NWLH 1-22, operated by Aera Energy LLC, is currently drilling
approximately 3.5 miles northwest of the ELH #1 well. We are participating in
this well through a pooling arrangement at a 4.04% working interest.
During the first half of 2001, the East Lost Hills working interest owners
participated in the acquisition of approximately 165 square miles of 3D seismic
data, a portion of which encompasses the East Lost Hills acreage. Ongoing
interpretation of the data is expected to assist in selection of potential
delineation and development well locations.
Funding and Financing
On March 12, 2001, we received an aggregate $11.6 million 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 $11.44 million. Investors consisted of
a total of ten separate funds managed by four California based institutions. For
information on the use of the proceeds from this financing, see below, "Item 5.
Markets For Common Equity And Related Stockholder Matters--Use of Proceeds."
During the fiscal year ended August 31, 2001, various outstanding warrants
were exercised to purchase a total of 802,390 shares of our common stock,
resulting in our receipt of $1,845,684 in aggregate proceeds.
Markets and Major Customers
We generated our first revenues from sales of oil and gas during our fiscal
year ended August 31, 2001. Sales to ChevronTexaco accounted for all of our
revenues. 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. In order to
alleviate this constraint, the participants at East Lost Hills are planning to
drill a water disposal well and install 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 our attempt to drill and connect a water
disposal well, we may not be able to find an alternative economical method to
dispose of water. We believe this event could cause an interruption in
production that may have a material adverse effect on our business.
2
Employees and Office Space
At August 31, 2001, PYR had seven full time employees. The Company believes
that its relationship with its employees is satisfactory. None of the Company's
employees are covered by a collective bargaining agreement. PYR leases
approximately 3,800 square feet of office space in Denver, Colorado for its
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:
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 Expand Production and Cash Flow From East Lost Hills. On February 6,
2001, we commenced our first production from the ELH #1 well. The
production from this well has been constrained by limitations in
disposing production water. The participant group is in the
preliminary stages of drilling a disposal well and building pipeline
and disposal facilities in order to alleviate this constraint. Because
of the water disposal constraint, no additional production can be
brought on line at this time. Should the water disposal constraint be
eliminated, the ELH #2 well could be connected to a processing
facility. There are currently three additional wells drilling at East
Lost Hills.
o Initiate Exploration Drilling on Our Other Projects. In addition to
our East Lost Hills project, 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 prospect and Bulldog prospect, which are large
target reserve prospects located immediately to the northwest of our
East Lost Hills acreage. In the Rocky Mountains, our most notable
large target reserve potential project is our Montana Foothills
project.
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.
3
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.
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 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 Bellevue #1-17
well bore. On May 29, 1999, the Bellevue #1-17 well was controlled by pumping
4
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.
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.
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 was installed
and, on February 6, 2001, we commenced commercial production of natural gas and
liquid hydrocarbons from this well.
Since shortly after commencing production on February 6, 2001, the
production from the ELH #1 well has been constrained by a variety of factors.
Most recently, the major constraint inhibiting production has been 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 365 mmcfe, averaging approximately four
mmcfe per day. Water production during this period averaged approximately 6,350
barrels per day.
During the first months of production, the ELH #1 well was shut-in for
varying time periods ranging from a few hours to multiple days due to
operational difficulties at the ChevronTexaco processing plant, shut-in pressure
testing at the well, rolling brown-outs that were affecting California at the
time and for general maintenance/testing reasons. During this period of random
shut-ins, produced water would typically load in the well and when the ELH #1
well was put back on line, the water to gas ratio would generally increase. Over
a period of months, the water to gas ratio reached the point where ChevronTexaco
is requiring a decrease in the overall flow accepted at the processing and
disposal facilities. The water to gas ratio increase became most apparent late
in the Company's fourth fiscal quarter and has continued. It is unknown whether
this ratio increase is an independent function of the reservoir or if the
decline in the performance of the well is attributable solely to water loading
from curtailment in overall flow rates. The participants are currently in the
process of preparing to drill a water disposal well and to build associated
pipeline and disposal facilities in order to remove the water disposal
constraint that has affected the ELH #1 well. It is unknown whether removing the
water disposal constraint will result in a decrease in the water to gas ratio.
On July 11, 2000, the participants commenced drilling the ELH #2 well. This
well is located approximately 1.5 miles northwest of the ELH #1 well. The ELH #2
well reached total depth of 18,011 feet in December 2000. While the final liner
was run to total depth during the completion process, a portion of the drill
pipe was inadvertently cemented in place across all potential pay zones. The
Company believes that this mechanical issue may have prevented a thorough
production test. Although the well production tested at approximately three mmcf
per day, water disposal facilities are not yet available. This well has been
suspended pending the ability and the decision to connect to processing and
water disposal facilities.
On June 19, 2000, the participants at East Lost Hills commenced drilling
the ELH #3 well. This well was designed to test a geologically separate feature
than the structure encountered by the Bellevue #1-17, Bellevue #1-17R, ELH #1
and ELH #2 wells. This well was drilled to a total depth of 21,769 feet and upon
production testing was determined to be non-productive. Because this wellbore
may be used to sidetrack to a new location in the East Lost Hills structure, the
ELH #3 well has not been plugged and abandoned.
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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 20,800 feet on August 7, 2001. Log and coring analysis was performed
and it was determined that in order to maximize potential production, the
wellbore should be sidetracked and directed to a more crestal position within
the lower Temblor. On October 16, 2001, sidetrack drilling operations commenced
to drill to a projected depth of 20,500 feet. As of December 12, 2001, this well
was drilling at approximately 19,450 feet.
The ELH #9 well is currently drilling at a location approximately six miles
southeast of the ELH #1 well. This well commenced drilling operations on July
17, 2001 with a projected total depth in the lower Temblor of 21,000 feet. This
well continued to drill at an approximate depth of 17,600 feet as of December
12, 2001.
We are participating in a third well currently drilling 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 and is designed to test the Temblor formation to a
projected depth of 20,000 feet. We are participating in this well operated by
Aera Energy LLC, through a pooling arrangement at a 4.04% working interest. At
December 12, 2001, this well was beginning to enter zones of interest.
The participants may commence drilling operations on up to three additional
wells in this prospect during the fiscal year ending August 31, 2002, although
there is no assurance this will occur.
Wedge Prospect. This is a seismic generated 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 that has
proven productive 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 14,000 gross
and approximately 13,000 net acres here. Our approach is to sell down our
working interest and to retain a 25% to 40% working interest in this prospect.
Bulldog Prospect. This project is a 2D seismic generated light oil and
natural gas 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 16,000 gross and approximately
15,000 net acres here. We are in the process of securing industry participation
to drill a 14,000 foot test well and expect to retain a 25% to 40% working
interest in this prospect.
Greater San Joaquin Basin Projects. In April 1999, we purchased a working
interest in three additional deep exploration projects in the San Joaquin Basin.
These three projects are outside the East Lost Hills joint venture area. Our
working interests range from 3.00% to 3.75% in each of the three exploration
projects, with a carried interest in the initial test well in each. These
projects target the Temblor formation at depths ranging from 15,000 to 19,000
feet.
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The Pyramid Power project is a 2D seismic generated natural gas prospect.
An initial exploration well, operated by Anadarko and located in Section 9,
T25S-R18E, commenced drilling on November 22, 2001. This exploration well is
designed to test the Temblor and the Point of Rocks formation to a total depth
of 18,500 feet. PYR owns a 3.75% working interest in this prospect acreage with
its interest in this initial well being carried through the tanks. The
participants at Pyramid Power jointly control approximately 20,000 gross and
15,000 net acres over the prospect. At December 12, 2001, this well was drilling
at a depth of approximately 8,500 feet.
An exploration well began drilling in the Cal Canal area on June 15, 1999
and was drilled to a total depth of 18,100 feet. After the participants
concluded that a completion in the upper portion of the Temblor formation was
not warranted, the well was completed in the shallower McDonald formation, and a
production test resulted in non-commercial hydrocarbon flow rates. Although this
well has not been plugged and abandoned, no further drilling is planned.
The third project, named Lucky Dog, has been terminated and no drilling is
expected to occur on this prospect.
Rectange Force Project. We own a 30% working interest in approximately
6,000 gross acres in this San Joaquin Basin project that targets the deep
Temblor formation. We may elect to participate in the drilling of an initial
exploration well here at the current 30% ownership, or may elect to sell down
our interest for cash and/or a carried working interest in the initial well.
This project is still in the development stage and no drilling plans currently
are in place.
Rocky Mountain Exploration
Montana Foothills Project. This extensive natural gas 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
extremely 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 recognizing that
this test well was drilled based upon a misleading seismic image and was located
significantly off-structure.
We currently control approximately 262,000 gross and 224,000 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% to 40%.
Wyoming Projects. We have three separate exploration projects in Wyoming,
and have acquired an initial land position of approximately 8,000 gross and net
acres. We intend to acquire additional land holdings as opportunities arise. We
currently are interpreting seismic data and conducting other geophysical
activities.
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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.
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.
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.
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Undeveloped Acreage. Lease acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether or not such acreage contains proved
reserves.
Working Interest. An interest in an oil and gas lease that gives the owner
of the interest the right to drill and produce oil and gas on the leased acreage
and requires the owner to pay a share of the costs of drilling and production
operations. The share of production to which a working interest owner is
entitled will always be smaller than the share of costs that the working
interest owner is required to bear, with the balance of the production accruing
to the owners of royalties.
Production and Productive Wells
On February 6, 2001, we commenced our first production from the ELH #1 well
at East Lost Hills. At August 31, 2001, the Company had production from only the
ELH #1 well. From February 6, 2001 through August 31, 2001, the Company's net
share of production from this well was 99,535 mcf of natural gas and 5,804
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, 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
and after a sidetrack operation, the well, on December 12, 2001, was
drilling at approximately 19,450 feet. The ELH #9 well commenced
drilling on July 18, 2001 and, on December 12, 2001, was drilling at a
depth of approximately 17,600 feet. On August 23, 2001, the Aera
Energy LLC NWLH 1-22 well commenced drilling and, on December 12,
2001, continued to drill toward its target depth of 20,000 feet.
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.
o During the fiscal year ended August 31, 1999, we participated in the
drilling of three gross (0.147 net) exploratory wells that began
drilling during that fiscal year. These wells consist of the Bellevue
#1-17R relief well, a Cal Canal exploratory well and the ELH #1 well.
The Bellevue #1-17R relief well began drilling on December 18, 1998
and was used to control the Bellevue #1-17 well blowout. The Bellevue
#1-17R well then was sidetracked as a replacement well. Operations on
this well have been suspended. After an unsuccessful production test,
operations on the Cal Canal well have been suspended. The ELH #1 well
was completed and began producing on February 6, 2001.
Although there is no assurance that any additional wells will be drilled,
we anticipate we may commence drilling up to three additional wells during
fiscal 2002 in our East Lost Hills project. We also may participate in the
drilling of up to four exploration wells during fiscal 2002 on our other
9
exploration projects. 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, and during our fiscal year ended August 31, 2001, we
generated approximately $1,202,000 as our first revenues from oil and gas
production from the ELH #1 well. Concurrent with the end of our fiscal year, we
engaged Netherland, Sewell & Associates, Inc., independent petroleum engineers,
to prepare a reserve report for our ownership interest in the East Lost Hills
project. Previous to August 31, 2001, all of our oil and gas properties were
classified as undeveloped, and no reserve reports were warranted.
The estimates of proved reserves are based on the information available at
this time, most importantly the production history of ELH #1, which has been
constrained by inadequate water disposal facilities for most of its nine-month
history. In addition, the estimates of capital costs to drill potential offset
wells are based upon the actual costs of drilling the initial East Lost Hills
wells, which were negatively affected by mechanical difficulties associated with
drilling in a very difficult and challenging environment. Based on this
historical data of 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. As experience is gained in drilling additional wells,
and as more production, tests, and pressure data become available, future
reserve estimates could change, but there is no assurance this will be the case.
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, 2001. 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, 2001, our amortizable cost pool was comprised of East Lost
Hills 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 the aggregate amount of $10,528,000, and
10
capital costs associated with our Southeast Maricopa project, Cal Canal prospect
and Lucky Dog prospect in the amount of $2,812,000. The unevaluated costs that
remain in our full cost pool include drilling costs associated with our working
interest in the ELH #4 and ELH #9 wells, and allocated land and geological and
geophysical costs associated with our East Lost Hills project and other
exploration projects. 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 104,000 40,000
Colorado 11,000 7,000
Montana 260,000 224,000
Wyoming 8,000 8,000
------- -------
TOTAL 383,000 279,000
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 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.
11
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
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,
12
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
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
13
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
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
14
and local government levels. These various initiatives could have a similar
adverse impact on operating costs. The regulatory burden of environmental laws
and regulations increases our cost and risk of doing business and consequently
affects our profitability.
The federal Comprehensive Environmental Response, Compensation and
Liability Act, or CERCLA, also known as the "Superfund" law, imposes liability,
without regard to fault, on certain classes of persons with respect to the
release of a "hazardous substance" into the environment. These persons include
the current or prior owner or operator of the disposal site or sites where the
release occurred and companies that transported, disposed or arranged for the
transport or disposal of the hazardous substances found at the site. Persons who
are or were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for the federal or state
government to pursue such claims. It is also not uncommon for neighboring
landowners and other third parties to file claims for personal injury or
property or natural resource damages allegedly caused by the hazardous
substances released into the environment. Under CERCLA, certain oil and gas
materials and products are, by definition, excluded from the term "hazardous
substances." At least two federal courts have held that certain wastes
associated with the production of crude oil may be classified as hazardous
substances under CERCLA. Similarly, under the federal Resource, Conservation and
Recovery Act, or RCRA, which governs the generation, treatment, storage and
disposal of "solid wastes" and "hazardous wastes," certain oil and gas materials
and wastes are exempt from the definition of "hazardous wastes." This exemption
continues to be subject to judicial interpretation and increasingly stringent
state interpretation. During the normal course of operations on properties in
which we have an interest, exempt and non-exempt wastes, including hazardous
wastes, that are subject to RCRA and comparable state statutes and implementing
regulations are generated or have been generated in the past. The federal
Environmental Protection Agency and various state agencies continue to
promulgate regulations that limit the disposal and permitting options for
certain hazardous and non-hazardous wastes.
Our operations will involve the use of gas fired compressors to transport
collected gas. These compressors are subject to federal and state regulations
for the control of air emissions. Title V status for a facility results in
significant increased testing, monitoring and administrative and compliance
costs. To date, other compressor facilities have not triggered Title V
requirements due to the design of the facility and the use of state-of-the-art
engines and pollution control equipment that serve to reduce air emissions.
However, in the future, additional facilities could become subject to Title V
requirements as compressor facilities are expanded or if regulatory
interpretations of Title V applicability change. Stack testing and emissions
monitoring costs will grow as these facilities are expanded and if they trigger
Title V. We believe that the operator of the properties in which we have an
interest is in substantial compliance with applicable laws, rules and
regulations relating to the control of air emissions at all facilities on those
properties.
Although we maintain insurance against some, but not all, of the risks
described above, including insuring the costs of clean-up operations, public
liability and physical damage, there is no assurance that our insurance will be
adequate to cover all such costs, that the insurance will continue to be
available in the future or that the insurance will be available at premium
levels that justify our purchase. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on our
financial condition and operations.
Compliance with environmental requirements, including financial assurance
requirements and the costs associated with the cleanup of any spill, could have
a material adverse effect on our capital expenditures, earnings or competitive
position. We do believe, however, that our operators are in substantial
15
compliance with current applicable environmental laws and regulations.
Nevertheless, changes in environmental laws have the potential to adversely
affect operations. At this time, we have no plans to make any material capital
expenditures for environmental control facilities.
Title to Properties
As is customary in the oil and gas industry, only a preliminary title
examination is conducted at the time we acquire leases or enter into other
agreements to obtain control over interests in acreage believed to be suitable
for drilling operations. In many instances, our partners have acquired rights to
the prospective acreage and we have a contractual right to have our interests in
that acreage assigned to us. In some cases, we are in the process of having
those interests so assigned. Prior to the commencement of drilling operations, a
thorough title examination of the drill site tract is conducted by independent
attorneys. Once production from a given well is established, the operator will
prepare a division order title report indicating the proper parties and
percentages for payment of production proceeds, including royalties. We believe
that titles to our leasehold properties are good and defensible in accordance
with standards generally acceptable in the oil and gas industry.
Risk Factors
In evaluating the Company, careful consideration should be given to the
following risk factors, in addition to the other information included or
incorporated by reference in this annual report. In addition, the
"Forward-Looking Statements" located herein, describe additional uncertainties
associated with our business and the forward-looking statements included or
incorporated by reference. Each of these risk factors could adversely affect our
business, operating results and financial condition, as well as adversely affect
the value of an investment in our common stock.
We have a limited operating history in the oil and gas business. Our
operations to date have consisted solely of evaluating geological and
geophysical information, acquiring acreage positions, generating exploration
prospects, and drilling a limited number of wells on deep oil and gas prospects.
We currently have 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.
16
Exploratory drilling is an uncertain process with many risks. Exploratory
drilling involves numerous risks, including the risk that we will not find any
commercially productive oil or gas reservoirs. The cost of drilling, completing
and operating wells is often uncertain, and a number of factors can delay or
prevent drilling operations, including:
o unexpected drilling conditions,
o pressure or irregularities in formations,
o equipment failures or accidents,
o adverse weather conditions,
o compliance with governmental requirements,
o shortages or delays in the availability of drilling rigs and the
delivery of equipment, and
o shortages of trained oilfield service personnel.
Our future drilling activities may not be successful, nor can we be sure
that our overall drilling success rate or our drilling success rate for
activities within a particular area will not decline. Unsuccessful drilling
activities could have a material adverse effect on our results of operations and
financial condition. Also, we may not be able to obtain any options or lease
rights in potential drilling locations that we identify. Although we have
identified a number of potential exploration projects, we cannot be sure that we
will ever drill them or that we will produce oil or gas from them or any other
potential exploration projects.
Our exploration and development activities are subject to reservoir and
operational risks. Even when oil and gas is found in what is believed to be
commercial quantities, reservoir risks, which may be heightened in new
discoveries, may lead to increased costs and decreased production. These risks
include the inability to sustain deliverability at commercially productive
levels as a result of decreased reservoir pressures, large amounts of water, or
other factors that might be encountered. As a result of these types of risks,
most lenders will not loan funds secured by reserves from newly discovered
reservoirs, which would have a negative impact on our future liquidity.
Operational risks include hazards such as fires, explosions, craterings,
blowouts (such as the blowout experienced at our initial exploratory well),
uncontrollable flows of oil, gas or well fluids, pollution, releases of toxic
gas and encountering formations with abnormal pressures. In addition, we may be
liable for environmental damage caused by previous owners of property we own or
lease. As a result, we may face substantial liabilities to third parties or
governmental entities, which could reduce or eliminate funds available for
exploration, development or acquisitions or cause us to incur substantial
losses.
We expect to maintain insurance against some, but not all, of the risks
associated with drilling and production in amounts that we believe to be
reasonable in accordance with customary industry practices. The occurrence of a
significant event, however, that is not fully insured could have a material
adverse effect on our financial condition and results of operations.
Our operations require large amounts of capital. Our current development
plans will require us to make large capital expenditures for the exploration and
development of our oil and gas projects. Under our current capital expenditure
budget, we expect to spend a minimum of approximately $7 million on exploration
and development activities during our fiscal year ending August 31, 2002. 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
17
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.
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 expansion and development in the San Joaquin Basin.
All of our current drilling activity is in the San Joaquin Basin, and our future
growth plans rely heavily on initiating and increasing production and reserves
in the San Joaquin Basin. This lack of diverse business operations subjects us
to a high degree of risk.
Our development plan includes establishing and then increasing reserves
through continued drilling and development of our existing properties in the San
Joaquin Basin. We cannot be sure, though, that our planned projects in the San
Joaquin Basin will lead to significant additional 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:
18
o the availability of leases with favorable terms and the availability
of required permitting for projects,
o the availability of future capital resources to us and the other
participants to be used for purchasing leases and drilling wells,
o the approval of other participants for the purchasing of leases and
the drilling of wells on the projects, and
o the economic conditions at the time of drilling, including the
prevailing and anticipated prices for oil and gas.
Our reliance on other project participants and our limited ability to
directly control project costs could have a material adverse effect on our
expected rates of return.
Oil and gas prices are volatile and an extended decline in prices could
hurt our business prospects. Our future profitability and rate of growth and the
anticipated carrying value of our oil and gas properties will depend heavily on
then prevailing market prices for oil and gas. We expect the markets for oil and
gas to continue to be volatile. If we are successful in continuing to establish
production, any substantial or extended decline in the price of oil or gas
could:
o have a material adverse effect on our results of operations,
o limit our ability to attract capital,
o make the formations we are targeting significantly less economically
attractive,
o reduce our cash flow and borrowing capacity, and
o reduce the value and the amount of any future reserves.
Various factors beyond our control will affect prices of oil and gas, including:
o worldwide and domestic supplies of oil and gas,
o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls,
o political instability or armed conflict in oil or gas producing
regions,
o the price and level of foreign imports,
o worldwide economic conditions,
o marketability of production,
o the level of consumer demand,
o the price, availability and acceptance of alternative fuels,
o the availability of processing and pipeline capacity,
o weather conditions, and
o actions of federal, state, local and foreign authorities.
These external factors and the volatile nature of the energy markets make
it difficult to estimate future prices of oil and gas. In addition, sales of oil
and gas are seasonal in nature, leading to substantial differences in cash flow
at various times throughout the year.
Accounting rules may require write-downs. Under full cost accounting rules,
capitalized costs of proved oil and gas properties may not exceed the present
value of estimated future net revenues from proved reserves, discounted at 10%.
Application of the ceiling test generally requires pricing future revenue at the
unescalated prices in effect as of the end of each fiscal quarter and requires a
write-down for accounting purposes if the ceiling is exceeded. If a write-down
is required, it would result in a charge to earnings, but would not impact cash
flow from operating activities. Once incurred, a write-down of oil and gas
properties is not reversible at a later date. We commenced our first oil and gas
production on February 6, 2001, resulting in a change of classification of a
19
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 have recorded a write-down of approximately $13,340,000 to
reduce the carrying value of 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,
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
20
regulate various aspects of oil and gas drilling and production activities,
including the drilling of wells (through permit and bonding requirements), the
spacing of wells, the unitization or pooling of oil and gas properties,
environmental matters, safety standards, the sharing of markets, production
limitations, plugging and abandonment, and restoration. The overall regulatory
burden on the industry increases the cost of doing business, which, in turn,
decreases profitability.
Our operations must comply with complex environmental regulations. Our
operations are subject to complex and constantly changing environmental laws and
regulations adopted by federal, state and local governmental authorities. New
laws or regulations, or changes to current requirements, could have a material
adverse effect on our business. We will continue to be subject to uncertainty
associated with new regulatory interpretations and inconsistent interpretations
between state and federal agencies. We could face significant liabilities to the
government and third parties for discharges of oil, natural gas, produced water
or other pollutants into the air, soil or water, and we could have to spend
substantial amounts on investigations, litigation and remediation. We cannot be
sure that existing environmental laws or regulations, as currently interpreted
or enforced, or as they may be interpreted, enforced or altered in the future,
will not have a material adverse effect on our results of operations and
financial condition.
Our business depends on transportation facilities owned by others. The
marketability of our anticipated gas production depends in part on the
availability, proximity and capacity of pipeline systems owned or operated by
third parties. Federal and state regulation of oil and gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions could adversely affect our ability to produce,
gather and transport oil and natural gas.
Attempts to grow our business could have an adverse effect. Because of our
small size, we desire to grow rapidly in order to achieve certain economies of
scale. Although there is no assurance that this rapid growth will occur, to the
extent that it does occur, it will place a significant strain on our financial,
technical, operational and administrative resources. As we increase our services
and enlarge the number of projects we are evaluating or in which we are
participating, there will be additional demands on our financial, technical and
administrative resources. The failure to continue to upgrade our technical,
administrative, operating and financial control systems or the occurrence of
unexpected expansion difficulties, including the recruitment and retention of
geoscientists and engineers, could have a material adverse effect on our
business, financial condition and results of operations.
We 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
21
uncertainties, many of which are beyond our control. Actual results could differ
materially from these forward-looking statements as a result of, among other
things:
o failure to obtain, or a decline in, oil or gas production, or a
decline in oil or gas prices,
o incorrect estimates of required capital expenditures,
o increases in the cost of drilling, completion and gas collection or
other costs of production and operations,
o an inability to meet growth projections, and
o other risk factors set forth under "Risk Factors" in this annual
report. In addition, the words "believe," "may," "could," "will,"
"when," "estimate," "continue," "anticipate," "intend," "expect" and
similar expressions, as they relate to PYR, our business or our
management, are intended to identify forward-looking statements.
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any 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, 2001.
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, 2000
First Quarter.......................... $5.312 $3.625
Second Quarter......................... 4.625 2.875
Third Quarter.......................... 5.938 2.750
Fourth Quarter......................... 7.125 3.500
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
On December 12, 2001, the last reported sales price of our common stock on
the AMEX was $1.99.
22
Stockholders Of Record
As of December 12, 2001, the number of record holders of our common stock
was approximately 800 and the number of beneficial owners of our common stock
was approximately 3,600.
Dividends
We have not declared or paid, and do not anticipate declaring or paying in
the near future, any dividends on our common stock.
Use Of Proceeds
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, 2001, $2,963,058 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, 2001, the balance of the net proceeds
continue to be held for those purposes and for possible acquisition and general
corporate purposes as described in the prospectus supplement.
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,
--------------------------------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Operating Revenues ............................ $ 1,624,096 $ 165,411 $ 116,713 $ 46,145 $ 85,596
Net (loss) from operations .................... (13,142,291) (982,547) (1,140,407) (110,807) (40,920)
Net income (loss( per share) .................. (.59) (.07) (.11) (.012) (.009)
Total assets at the end of each period ........ 22,067,184 19,942,090 10,762,521 2,939,602 1,789,666
Long-term debt at the end of each period ...... -0- -0- 1,062 2,661 -0-
23
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, 2001, we had approximately $8,786,000 in working capital.
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.
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 fiscal year ended August 31, 1999, our capitalized costs for
undeveloped oil and gas properties increased by a net amount of approximately
$2,572,000. This net increase is comprised of expenditures on undeveloped oil
24
and gas prospects of approximately $2,878,000, offset by property abandonments
and impairments of approximately $306,000.
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 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 were
exercised to purchase a total of 164,063 shares of our common stock for total
proceeds issued in the May 1999 private placement had been 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.
We had no outstanding long-term debt at August 31, 2001 or at August 31,
2000. 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.
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, 2002 will depend on our
25
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 continuing results at our East Lost Hills project. We
anticipate spending a minimum of approximately $7 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 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.
During fiscal 1999, we incurred approximately $876,000 for costs related to
continued leasing and optioning of acreage, $1,094,000 for positions in
additional exploration projects in California, $313,000 for costs relating to
seismic and $480,000 in drilling costs associated with deep exploratory drilling
at our East Lost Hills project.
We currently anticipate that we will participate in the drilling of from
three to seven wells during our fiscal year ending August 31, 2002, 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, 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 to 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
26
$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.
The twelve months ended August 31, 2000 ("2000") compared with the twelve
months ended August 31, 1999 ("1999")
Operations during the fiscal year ended August 31, 2000 resulted in a net
loss of $982,547 compared to a net loss $1,140,407 for the fiscal year ended
August 31, 1999.
Oil and Gas Revenues and Expenses. At August 31, 2000 and August 31, 1999,
the Company did not own any producing or proved oil and gas properties, and no
oil and gas production revenues or expenses had been recorded by the Company.
General and Administrative Expense. The Company incurred $929,000 and
$743,000 in general and administrative expenses during 2000 and 1999,
respectively. The increase results from increases in shareholder and investor
relations costs resulting from our listing on the American Stock Exchange and
from our expanding investor and shareholder base, and from additional increases
in personnel and salaries.
27
Dry Hole, Impairment and Abandonments. In 2000, the Company recorded an
impairment of $200,000 against its Cal Canal project. In 1999, the Company
re-evaluated its School Road project and recorded an impairment of approximately
$285,000 against its basis in this project. Also in 1999, the Company had
abandoned projects and recorded an abandonment cost of approximately $21,000
associated with these projects.
Interest Expense. The Company recorded nominal interest expense in 2000.
The Company recorded $183,000 in interest expense during 1999, predominately
associated with the 10% Convertible Debentures that were outstanding from
October 26, 1998 through April 16, 1999. Per the Convertible Debenture
agreement, the Company elected to pay this interest by issuing 53,326 shares of
the Company's common stock. These Debentures were converted into Series A
Convertible Preferred Stock on April 16, 1999. The Company is obligated to pay a
10 percent dividend on the outstanding preferred stock. During 2000, the Company
paid dividends to the holders of preferred stock of approximately $178,600 by
issuing a total of 38,531 shares of common stock.
Depreciation, Depletion and Amortization. The Company recorded no depletion
expense from oil and gas properties in 2000 or 1999. At August 31, 2000 and
1999, the Company did not own any proved reserves and had no oil or gas
production. The Company recorded $18,327 and $24,111 in depreciation expense
associated with capitalized office furniture and equipment during 2000 and 1999,
respectively.
ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required under Item 7A is not applicable.
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.
28
Name Age Position with the Company Director Since
- ---- --- ------------------------- --------------
D. Scott Singdahlsen 43 Chief Executive Officer, 1997
President, and Chairman Of the
Board
Andrew P. Calerich 37 Chief Financial Officer, Vice ---
President and Secretary
Keith F. Carney 45 Director 1997
S. L. Hutchison 68 Director 1999
Bryce W. Rhodes 48 Director 1999
Kenneth R. Berry, Jr. 49 Vice President-Land ---
D. Scott Singdahlsen has served as President, Chief Executive Officer, and
Chairman of the Board of the Company since August 1997. Mr. Singdahlsen
co-founded PYR Energy, LLC in 1996, and served as General Manager and
Exploration Coordinator. In 1992, Mr. Singdahlsen co-founded Interactive Earth
Sciences Corporation, a 3-D seismic management and interpretation consulting
firm in Denver, where he served as vice president and president and lead seismic
interpretation specialist from 1992 to 1996. Prior to forming Interactive Earth
Sciences Corporation, Mr. Singdahlsen was employed as a Development Geologist
for Chevron USA in the Rocky Mountain region. At Chevron, Mr. Singdahlsen was
involved in 3-D seismic reservoir characterization projects and geostatistical
analysis. Mr. Singdahlsen started his career at UNOCAL as an Exploration
Geologist in Midland, Texas. Mr. Singdahlsen earned a B.A. in Geology from
Hamilton College and a M.S. in Structural Geology from Montana State University.
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.
Keith F. Carney has served as a Director of the Company since 1997. Since
October 2001, Mr. Carney has been President of Dolomite Advisors, LLC, a manager
of energy investment funds. From October 1997 until August, 2001, Mr. Carney
served as Executive Vice-President of Cheniere Energy, Inc., a Houston-based
natural gas company. From July 1996 until September 1997 Mr. Carney served as
Chief Financial Officer of Cheniere. Mr. Carney is currently a Director of
Cheniere. After earning his M.B.A. degree from the University of Denver in 1992,
Mr. Carney was employed as a Securities Analyst in the oil and gas
exploration/production sector with Smith Barney, Inc. Mr. Carney began his
career as an exploration Geologist at Shell Oil after earning B.S. and M.S.
degrees in Geology from Lehigh University.
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
29
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.
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.
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. Mr. Berry has 23 years of experience as an independent landman.
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, 2001, 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, 2001 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
2002 annual meeting of shareholders, which is to be filed within 120 days after
our fiscal year end on August 31, 2001.
30
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
2002 annual meeting of shareholders, which is to be filed within 120 days after
our fiscal year end on August 31, 2001.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
During the fiscal year ended August 31, 2001, there were no 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.
PART IV
ITEM 14. EXHIBITS, FINANCIAL SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements And Financial Statement Schedules
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
INDEX
Independent Auditor's Report F-2
Balance Sheets
August 31, 2001 and 2000 F-3
Statements of Operations
Years Ended August 31, 2001, 2000, and 1999 and
Cumulative Amounts from Inception to August 31, 2001 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, and 2001 F-5 - F-8
Statements of Cash Flows
Years Ended August 31, 2001, 2000, and 1999 and F-9 - F-10
Cumulative Amounts from Inception to August 31, 2001
Notes to Financial Statements F-11 - F-23
31
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.
3.2 Articles of Merger filed with the Maryland Secretary Of State on
July 3, 2001 in connection with Maryland reincorporation.
3.3 Bylaws
(b) Reports On Form 8-K.
-------------------
During the fourth quarter of the fiscal year ended August 31, 2001, the
Company filed three Current Reports on Form 8-K dated July 5, 2001, July 16,
2001 and August 24, 2001. These events consisted of the dissemination of press
releases by the Company and were reported under "ITEM 5. OTHER EVENTS".
32
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant
has caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
PYR ENERGY CORPORATION
Date: December 14, 2001 By: /s/ D. Scott Singdahlsen
---------------------------------------------
D. Scott Singdahlsen, Chief Executive Officer
In accordance with the requirements of the Exchange Act, this report has
been signed below by the following persons on behalf of the registrant and in
the capacities and on the dates indicated.
Signatures Title Date
- ---------- ----- ----
/s/ D. Scott Singdahlsen Chief Executive Officer, President and December 14, 2001
- ------------------------ Chairman Of The Board
D. Scott Singdahlsen
/s/ Keith F. Carney Director December 14, 2001
- ------------------------
Keith F. Carney
/s/ S. L. Hutchison Director December 14, 2001
- ------------------------
S. L. Hutchison
/s/ Bryce W. Rhodes Director December 14, 2001
- ------------------------
Bryce W. Rhodes
/s/ Andrew P. Calerich Vice-President, Chief Financial December 14, 2001
- ------------------------ Officer and Secretary
Andrew P. Calerich
33
PYR ENERGY CORPORATION
(A Development Stage Company)
INDEX
Independent Auditor's Report F-2
Balance Sheets
August 31, 2001 and 2000 F-3
Statements of Operations
Years Ended August 31, 2001, 2000, and 1999 and
Cumulative Amounts from Inception to August 31, 2001 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, and 2001 F-5 - F-8
Statements of Cash Flows
Years Ended August 31, 2001, 2000, and 1999 and F-9 - F-10
Cumulative Amounts from Inception to August 31, 2001
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, 2001 and 2000 and, the related
statements of operations, stockholders' equity and cash flows for each of the
three years in the period ended August 31, 2001 and cumulative amounts from
inception to August 31, 2001. 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, 2001 and 2000, and the results of its operations and its cash flows
for each of the three years in the period ended August 31, 2001 and cumulative
amounts from inception to August 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.
/s/ Wheeler Wasoff, P.C.
-------------------------
Wheeler Wasoff, P.C.
Denver, Colorado
November 13, 2001
F-2
PYR ENERGY CORPORATION
(A Development Stage Company)
BALANCE SHEETS
AUGUST 31, 2001 and 2000
ASSETS
2001 2000
CURRENT ASSETS
Cash $ 9,800,842 $ 8,598,016
Accounts receivable 1,173,751 --
Prepaid expenses 74,636 20,835
------------ ------------
Total Current Assets 11,049,229 8,618,851
PROPERTY AND EQUIPMENT 11,017,955 11,323,239
------------ ------------
$ 22,067,184 $ 19,942,090
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 2,263,368 $ 165,289
Current portion of capital lease obligation -- 920
------------ ------------
Total Current Liabilities 2,263,368 166,209
------------ ------------
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 14,263 shares (2000) -- 14
Common stock, $.001 par value; authorized 75,000,000 shares
Issued and outstanding 23,691,357 shares (2001) and 19,069,019 shares (2000) 23,691 19,069
Capital in excess of par value 35,214,002 22,048,384
Deficit accumulated during the development stage (15,433,877) (2,291,586)
------------ ------------
19,803,816 19,775,881
------------ ------------
$ 22,067,184 $ 19,942,090
============ ============
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
Years ended August 31, Inception to
August 31,
2001 2000 1999 2001
REVENUES
Oil and gas production $ 1,201,979 $ -- $ -- $ 1,201,979
Interest income 422,117 165,411 116,713 745,982
Other -- -- -- 127,528
------------ ------------ ------------ ------------
1,624,096 165,411 116,713 2,075,489
------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 102,018 -- -- 102,018
Impairment, dry hole, and abandonments 13,339,911 200,000 306,369 13,861,280
Depreciation and amortization 17,823 18,327 24,380 83,996
General and administrative 1,306,635 929,420 743,115 3,798,095
Interest -- 211 183,256 184,306
------------ ------------ ------------ ------------
14,766,387 1,147,958 1,257,120 18,029,695
------------ ------------ ------------ ------------
OTHER INCOME
Gain on sale of oil and gas prospects -- -- -- 556,197
------------ ------------ ------------ ------------
(13,142,291) (982,547) (1,140,407) (15,398,009)
INCOME APPLICABLE TO
PREDECESSOR LLC (Note 1) -- -- -- (35,868)
------------ ------------ ------------ ------------
NET (LOSS) (13,142,291) (982,547) (1,140,407) (15,433,877)
Less dividends on preferred stock (62,880) (178,621) (50,910) (292,411)
------------ ------------ ------------ ------------
NET (LOSS) TO COMMON STOCKHOLDERS $(13,205,171) $ (1,161,168) $ (1,191,317) $(15,726,288)
============ ============ ============ ============
NET (LOSS) PER COMMON SHARE
BASIC AND DILUTED (Note 1) $ (.59) $ (.07) $ (.11) $ (1.30)
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING
BASIC AND DILUTED (Note 1) 22,226,906 16,069,869 10,823,645 12,076,601
============ ============ ============ ============
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 YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
Preferred Stock
---------------
Members'
Equity Shares Amount
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) -- --
Recapitalization of shares issued by Mar prior to merger -- -- --
Sales of common stock pursuant to private placement at
$.25 per share -- -- --
Sale of common stock pursuant to private placement at
$.75 per share -- -- --
Costs of private placements offerings -- -- --
Net (loss) August 6, 1997 to August 31, 1997 -- -- --
----------- ----------- -----------
Balance, August 31, 1997 -- -- --
Net (loss) -- -- --
----------- ----------- -----------
Balance, August 31, 1998 $ -- -- $ --
----------- ----------- -----------
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
PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31,
1996, EIGHT MONTHS ENDED AUGUST 31, 1997 AND YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
(Con't)
Deficit
Common Stock Accumulated
---------------- Capital in During the
Excess of Development
Shares Amount Par Value Stage
Inception, May 31, 1996 -- $ -- $ -- $ --
Initial member contributions - cash -- -- -- --
Member contribution- services -- -- -- --
Distributions to members -- -- -- --
Net income
----------- ----------- ----------- -----------
Balance, December 31, 1996 -- -- -- --
Member contributions - cash -- -- -- --
Member contribution - services -- -- -- --
Distributions to members -- -- -- --
Net income - January 1, 1997 to August 5, 1997 -- -- -- --
Issuance of common stock to members of PYR Energy,
LLC upon merger ($.008 per share) 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(Con't)
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 YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
Preferred Stock
----------------
Shares Amount
Balance Forward -- $ --
Issuance of preferred stock for convertible notes 25,000 25
Unamortized convertible note financing costs -- --
Issuance of common stock for interest on convertible
debt, at $2.19 per share -- --
Issuance of common stock warrants for financing costs -- --
Conversion of preferred stock to common stock
at $.60 per share (2,021) (2)
Sale of common stock pursuant to private placement for
cash of $1.60 per share -- --
Costs of private placement -- --
Exercise of private placement warrants for cash of $2.50
per share -- --
Issuance of common stock for property, valued at $.75
per share -- --
Issuance of common stock for property, valued at $2.00
per share -- --
Preferred dividends paid -- --
Net (loss) -- --
------------ ------------
Balance August 31, 1999 22,979 $ 23
------------ ------------
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 YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
(Con't)
Deficit
Accumulated
Common Sock Capital in During the
--------------- Excess of Par Development
Shares Amount Value Stage
Balance Forward 9,154,804 $ 9,155 $ 1,768,088 $ (168,632)
Issuance of preferred stock for convertible notes -- -- 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 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 14,408,620 $ 14,409 $ 11,874,627 $ (1,309,039)
------------ ------------ ------------ ------------
The accompanying notes are an integral part of the financial statements
F - 6(Con't)
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 YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
Preferred Stock
---------------
Shares Amount
Balance Forward 22,979 $ 23
Issuance of common stock for services
(valued at $4.00 per share) -- --
Conversion of preferred stock to common stock
at $.60 per share (8,716) (9)
Exercise of warrants for cash of $.75 per share -- --
Exercise of private placement warrants for
cash of $2.50 per share -- --
Issuance of common stock for payment of
preferred dividends (valued at $4.30 per share) -- --
Issuance of common stock for payment of
preferred dividends (valued at $5.24 per share) -- --
Sale of common stock pursuant to private placement
for cash of $3.25 per share -- --
Cost of private placement -- --
Exercise of common stock options -- --
Retirement of common stock received for option exercise -- --
Sale of common stock pursuant to private placement
for cash of $3.50 per share -- --
Issuance of common stock warrants for offering costs -- --
Costs of private placement -- --
Net (loss) -- --
------------ ------------
Balance August 31, 2000 14,263 $ 14
------------ ------------
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 YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
(Con't)
Deficit
Accumulated
Common Stock Capital in During the
------------ Excess of Par Development
Shares Amounts Value Stage
Balance Forward 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 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 19,069,019 $ 19,069 $ 22,048,384 $ (2,291,568)
------------ ------------ ------------ ------------
The accompanying notes are an integral part of the financial statements
F - 7(Con't)
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 YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
Preferred Stock
---------------
Shares Amounts
Balance Forward 14,263 $ 14
Conversion of preferred stock to common stock (14,263) (14)
Exercise of warrants for cash of $.75 per share -- --
Exercise of private placement warrants for
cash of $2.50 to $4.80 per share -- --
Issuance of common stock for payment of
preferred dividends (valued at $6.40 per share) -- --
Exercise of common stock options for cash at $.69 to
$3.66 per share -- --
Retirement of common stock received for option exercise -- --
Sale of common stock for cash of $8.00 per share -- --
Costs of common stock sale -- --
Net (loss) -- --
------------ ------------
Balance August 31, 2001 -- $ --
============ ============
The accompanying notes are an integral part of the financial statements
F - 8
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 YEARS ENDED AUGUST
31, 1998, 1999, 2000, and 2001
(Con't)
Deficit
Accumulated
Common Stock Capital in During the
------------ Excess of Par Development
Shares Amounts Value Stage
Balance Forward 19,069,019 $ 19,069 $ 22,048,384 $ (2,291,586)
Conversion of preferred stock to common stock 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)
============ ============ ============ ============
The accompanying notes are an integral part of the financial statements
F - 8(Con't)
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS
Cumulative
Years Ended August 31, Amounts from
2001 2000 1999 Inception
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) $(13,142,291) $ (982,547) $ (1,140,407) $(15,398,009)
Adjustments to reconcile net (loss) to
net cash (used) by operating activities
Depreciation and amortization 17,823 18,327 24,380 83,997
Contributed services -- -- -- 36,000
Gain on sale of oil and gas prospects -- -- -- (556,197)
Impairment, dry hole and abandonments 13,339,911 200,000 306,369 13,861,280
Common stock issued for interest on debt -- -- 116,822 116,822
Common stock issued for services -- 20,000 -- 20,000
Amortization of financing costs -- -- 26,939 26,939
Amortization of marketable securities -- -- (20,263) (20,263)
Changes in assets and liabilities
(Increase) decrease in accounts receivable (1,173,751) 2,516 (3,082) (1,174,317)
(Increase) in prepaids (53,801) (6,644) (3,451) (79,187)
Increase (decrease) in accounts payable 22,303 (105,802) 135,450 81,906
Other 1,946 -- 10,000 8,195
------------ ------------ ------------ ------------
Net cash (used) by operating activities (987,860) (854,150) (547,243) (2,992,834)
------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (30,757) (4,200) (13,067) (120,912)
Cash paid for oil and gas properties 1,329,468) (5,929,267) (3,522,969) (22,486,495)
Proceeds from sale of oil and gas properties -- -- -- 1,050,078
Cash paid for marketable securities -- -- (5,090,799) (5,090,799)
Proceeds from sale of marketable securities -- 5,111,062 -- 5,111,062
Cash received (paid) for reimbursable property costs 381,605 -- (410,000) (28,395)
------------ ------------ ------------ ------------
Net cash (used) in investing activities (10,978,620) (822,405) (9,036,835) (21,565,461)
------------ ------------ ------------ ------------
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 7,000,000 30,788,750
Proceeds from sale of convertible debt -- -- 2,500,001 2,500,001
Proceeds from exercise of warrants 1,557,166 446,095 7,812 2,011,073
Proceeds from exercise of options 173,530 16,000 -- 189,530
Cash paid for offering costs (160,470) (468,687) (126,580) (1,036,448)
Payments on capital lease (920) (1,742) (1,440) (5,195)
Preferred dividends paid -- -- (50,910) (50,910)
------------ ------------ ------------ ------------
Net cash provided by financing activities 13,169,306 10,156,666 9,328,883 34,359,137
------------ ------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH 1,202,826 8,480,111 (255,195) 9,800,842
CASH, BEGINNING OF PERIODS 8,598,016 117,905 373,100 --
------------ ------------ ------------ ------------
CASH, END OF PERIODS $ 9,800,842 $ 8,598,016 $ 117,905 $ 9,800,842
============ ============ ============ ============
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, 2001, 2000 and 1999 and
PERIOD FROM INCEPTION TO AUGUST 31, 2001
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
During the years ended August 31, 2001, 2000 and 1999, the Company paid
cash for interest of $0, $211 and $371 respectively, on a capital lease.
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
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, 2001, 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 are 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.
As of the nine months period ended May 31, 2001, the Company disclosed in
it's Form 10QSB filed with the Securities and Exchange Commission that it
was no longer a development stage company. This was based on the Company's
assessment that it had commenced principal operations from its oil and gas
activities due to initial production from its East Lost Hills prospect.
Based on the results of the reserve report prepared as of August 31, 2001,
the Company has determined that it is still a development stage Company as
defined by SFAS 7.
F - 11
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
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.
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.
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.
F - 12
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
INCOME TAXES
The Company has adopted the provisions of SFAS No. 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, 2001, the Company had a net operating loss carryforward of
approximately $14,100,000 that may be offset against future taxable income
through 2021. These carryforwards are subject to review by the Internal
Revenue Service.
The Company has fully reserved the $3,085,000 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, $1,700,000 is attributable to 2001.
Temporary differences between the time of reporting certain items for
financial and tax reporting purposes consist primarily of exploration and
development costs on oil and gas properties, and impairment pursuant to the
ceiling test limitation.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
The 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 stock
options and warrants, are not considered in the calculation of net loss per
share as their inclusion would be antidilutive.
F - 13
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 -ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
SHARE BASED COMPENSATION
In October 1995, SFAS No. 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 No. 25 for
measurement; and will, pursuant to SFAS No. 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".
NEW TECHNICAL PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
141 "Business Combinations" and SFAS 142 "Goodwill and Other Intangible
Assets". SFAS 141 requires all business combinations initiated after June
30, 2001 to be accounted for under the purchase method. For all business
combinations for which the date of acquisition is after June 30, 2001, SFAS
141 also establishes specific criteria for the recognition of intangible
assets separately from goodwill and requires unallocated negative goodwill
to be written off immediately as an extraordinary gain rather than deferred
and amortized. SFAS 142 changes the accounting for goodwill and other
intangible assets after an acquisition. The most significant changes made
by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives
will no longer be amortized; 2) goodwill and intangible assets with
indefinite lives must be tested for impairment at least annually; and 3)
the amortization period for intangible assets with finite lives will no
longer be limited to forty years. The Company does not believe that the
adoption of these statements will have a material effect on its financial
position, results of operations, or cash flows.
In June 2001, the FASB also approved for issuance SFAS 143, "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets,
including (1) the timing of the liability recognition, (2) initial
measurement of the liability, (3) allocation of assets retirement cost to
expense, (4) subsequent measurement of the liability, and (5) financial
statement disclosure. SFAS 143 requires that an asset retirement cost
should be capitalized as part of the cost of the related long-lived asset
and subsequently allocated to expense using a systematic and rational
method. The adoption of SFAS 143 is not expected to have a material effect
on the Company's financial position, results of operations, or cash flows.
F - 14
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 1 -ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
In August 2001, the FASB also approved SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets ." SFAS 144 replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." The new accounting model for long-lived assets
to be disposed of by sale applies to all long-lived assets, including
discounted operations, and replaces the provisions of APB Opinion No. 30,
"Reporting Results of Operations-Reporting the Effects of Disposal of a
Segment of a Business," for the disposal of segments of a business. SFAS
144 requires that those long-lived assets be measured at the lower of
carrying amount or fair value less cost to sell, whether reported in
continuing operations or in discounted operations. Therefore, discounted
operations will no longer be measured at net realizable value or include
amounts for operating losses that have not yet occurred. SFAS 144 also
broadens the reporting of discontinued operations to include all components
of an entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction. The provisions of SFAS 144 are effective
for financial statements issued for fiscal years beginning after December
15, 2001 and, generally, are to be applied prospectively. The adoption of
SFAS 144 is not expected to have a material effect on the Company's
financial position, results of operations, or cash flows.
FAIR VALUE
The carrying amount reported in the balance sheet for cash, accounts
receivable, 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.
The Company's receivables are from oil and gas sales due from one
purchaser, a major U.S. oil and gas company. Based on the credit worthiness
of this Fortune 500 Company, the Company believes that credit risk
associated with receivables is nominal.
RECLASSIFICATION
Certain reclassifications have been made to 2000 and 1999 amounts to
conform to the 2001 presentation.
NOTE 2 - ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE
Accounts receivable at August 31, 2001 includes $1,173,155 of net revenue
due from operator for oil and gas sales for the initial period from
February to August 2001. The Company has not received any payments for
production from the operator, and the joint operating agreement underlying
the East Lost Hills prospect does not provide for the Company to offset the
receivable for oil and gas revenue against amounts due to the operator. The
Company believes that the operator is legally responsible to remit payment.
Until the Company receives payment, management intends to offset payments
due to the operator for cash calls and other liabilities in an amount equal
to the revenue due. Although the joint operating agreement provides that
the operator can charge interest on past due cash calls and billings, no
interest has been charged to the Company.
F - 15
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 2 - ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE (continued)
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 at August 31, 2001 and 2000 are as follows:
2001 2000
Due to operator $ 1,947,192 $ --
Trade payables 254,213 165,289
Ad Valorem Tax 61,963 --
----------- -----------
$2,263,368 $ 165,289
=========== ===========
NOTE 3 - PROPERTY AND EQUIPMENT
Property and equipment at August 31, 2001 and 2000 consisted of the
following:
2001 2000
Oil and gas properties, full cost method
Unevaluated costs, not subject to amortization or ceiling test $10,977,317 $11,293,589
Evaluated costs 13,825,140 485,229
Furniture and equipment 118,208 90,155
Asset under capital lease
-- 5,195
----------- -----------
24,920,665 11,874,168
Less accumulated depreciation, amortization, and impairment (13,902,710) (550,929)
----------- -----------
$11,017,955 $11,323,239
=========== ===========
Information relating to the Company's costs incurred in its oil and gas
operations during the years ended August 31, 2001, 2000, and 1999 is
summarized as follows:
2001 2000 1999
Property acquisition costs, unproved properties $ 4,114,449 $ 1,318,813 $ 2,085,584
Exploration costs 2,448,990 4,610,454 792,616
Development costs 6,460,201 -- --
----------- ----------- -----------
$13,023,640 $ 5,929,267 $ 2,878,200
=========== =========== ===========
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.
F - 16
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 3 - PROPERTY AND EQUIPMENT (continued)
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. Depreciation, depletion
and amortization of $68,456 previously recorded through May 31, 2001 has
been reclassified as a component of the impairment charge at August 31,
2001. The Company recorded impairment losses on undeveloped oil and gas
properties of $200,000 and $285,229 for the years ended August 31, 2000 and
1999, respectively. During the year ended August 31, 1999, the Company
abandoned properties with a carrying cost of $21,140
At August 31, 2001, 2000, and 1999, accumulated charges to impairment were
$13,825,140, $485,229 and $285,229, respectively.
Depreciation expense for the years ended August 31, 2001, 2000 and 1999 was
$17,823, $18,327, and $24,111, 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, 2001, the Company had a 12.119% interest in East Lost Hills.
NOTE 4 - CONVERTIBLE NOTES PAYABLE
In November 1998, the Company completed the sale of $2,500,000, 10%
convertible notes, due October 1999. The notes were convertible into an
aggregate 25,000 shares of a newly designated Series A Preferred Stock of
the Company. The Company obtained stockholder approval for authorization of
the Series A Preferred Stock and, in April 1999, all notes were converted
to Series A Preferred Stock. Accrued interest due as of the date of
conversion of $116,822 was paid by the issuance of 53,326 shares of common
stock, valued at $2.19 per share, the non-discounted trading price of the
Company's common stock at the transaction date. In conjunction with the
sale of $1,500,000 of the notes, the Company paid a finder's fee consisting
of $45,000 and warrants to purchase 175,000 shares of the Company's common
stock at an exercise price of $.75 per share for a period of five years.
The warrants were valued at $56,833.
NOTE 5 - STOCKHOLDERS' EQUITY
PREFERRED STOCK
In April 1999, the stockholders of the Company approved an amendment to the
Certificate of Incorporation wherein 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, 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.
F - 17
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 5 - STOCKHOLDERS' EQUITY (continued)
In April 1999, the holders of convertible notes (Note 5) 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.
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 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:
F - 18
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 5 - STOCKHOLDERS' EQUITY (continued)
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 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.
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.
WARRANTS
In 1999, the Company issued warrants to purchase 175,000 shares of common
stock at an exercise price of $.75 per share through October 26, 2003 as
partial consideration for a finder's fee in conjunction with the private
placement of convertible notes. The warrants are valued at $56,833, using
the Black-Scholes option pricing model. In May 1999, in conjunction with
the sale of 437,500 units of common stock and warrants as described above,
the Company issued warrants to purchase 437,500 shares of common stock at
an exercise price of $2.50 through May 14, 2004.
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.
F - 19
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 5 - STOCKHOLDERS' EQUITY (continued)
At August 31, 2001, 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
At August 31, 2001, the per share weighted average exercise price of
outstanding warrants was $4.91 per share and the weighted average remaining
contractual life was 1.9 years.
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, 2001 and 2000, options to purchase
1,000,000 and 300,000 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, 1998 246,000 $1.46 $ .26
(37,000 exercisable)
Expired (10,000) $1.28
Granted 585,000 $1.10 $ .92
---------
Options Outstanding- August 31, 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
(537,333 exercisable) 1,226,500 $3.31 $1.94
=========
F - 20
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 6 - STOCK OPTION PLAN (continued)
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:
2001 2000 1999
Expected option life-years 5 2-5 3-5
Risk-free interest rate 5.75% 5.50% 5.50%
Dividend yield 0 0 0
Volatility 68-75% 71-81% 25-161%
At August 31, 2001, the number of options exercisable was 537,333, the
weighted average exercise price of these options was $2.27, the weighted
average contractual life of the options was 4.59 years and the exercise
price was $.69 to $4.40 per share.
The Company has adopted the disclosure-only provisions of SFAS No. 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
No. 123, the Company's net loss and loss per share for 2001, 2000, and 1999
would have been increased to the pro forma amounts indicated below:
2001 2000 1999
Net (loss) applicable to common stockholders - as reported $ (13,205,171) $ (1,161,168) $ (1,191,317)
============= ============ ============
Net (loss) applicable to common stockholders - pro forma $ (13,632,412) $ (1,483,622) $ (1,238,232)
============= ============ ============
(Loss) per share - as reported $ (.59) $ (.07) $ (.11)
============= ============ ============
(Loss) per share - pro forma $ (.61) $ (.09) $ (.11)
============= ============ ============
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,
2002 $95,975
2003 95,975
2004 95,975
Rent expense was $58,988, $41,036 and $40,816 for the years ended August
31, 2001, 2000, and 1999, respectively.
In conjunction with the Company's working interests in undeveloped oil and
gas prospects, the Company must pay approximately $1,498,000 in delay
rentals and other costs during the fiscal year ending August 31, 2002 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.
F - 21
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
NOTE 8 - SEGMENT REPORTING
In June 1997, SFAS No. 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.
During 2001, initial production commenced on the Company's East Lost Hills
Prospect in California. Results of operations for oil and gas operations in
2001 are as follows:
Revenues
Oil and gas sales $ 1,201,979
-------------
Expense
Lease operating expense 40,055
Ad Valorem Taxes 61,963
Impairment 13,339,911
-------------
13,441,929
(Loss) from oil and gas operations $ (12,239,950)
=============
All sales of oil and gas were made to one customer.
No depletion has been recorded on oil and gas properties. Based on the
ceiling test limitation as of August 31, 2001, the Company recorded an
impairment against its entire amortizable cost pool. (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 No. 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, 2001 and 2000:
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 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.
Three Months Ended
2000 11/30/99 2/28/00 5/31/00 8/31/00
Revenues $ 56,842 $ 27,447 $ 21,226 $ 59,896
------------ ------------ ------------ ------------
Operating expenses
Impairment -- -- -- 200,000
Depreciation and amortization 4,558 4,699 4,581 4,489
Interest 66 55 59 31
General and administrative 217,845 263,993 202,917 244,665
------------ ------------ ------------ ------------
222,469 268,747 207,557 449,185
------------ ------------ ------------ ------------
Net (Loss) $ (165,627) $ (241,300) $ (186,331) $ (389,289)
============ ============ ============ ============
F -23