e10ksb
U.S. SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-KSB
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
August 31, 2006
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period from
to
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Commission file
no. 0-20879
PYR ENERGY
CORPORATION
(Name of small business issuer
in its charter)
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Maryland
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95-4580642
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(State or jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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1675 Broadway, Suite 2450,
Denver, CO
(Address of principal
executive offices)
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80202
(Zip Code)
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Registrants telephone number, including area
code: (303)
825-3748
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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$.001 Par Value Common Stock
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American Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
(Title of Class)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such report), and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-B
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-KSB
or any amendment to this
Form 10-KSB. Yes þ No o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12-b-2
of the Exchange
Act). Yes o No þ
The registrants revenues for the fiscal year ended
August 31, 2006 were $10.3 million. As of
November 15, 2006, the registrant had 37,993,259 common
shares outstanding, and the aggregate market value of the common
shares held by non-affiliates was approximately $32,682,570*.
This calculation is based upon the closing sale price of
$1.01 per share on November 15, 2006.
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Without asserting that any of the issuers directors or
executive officers, or the entities that own 10% or greater of
the registrants shares of common stock, are affiliates,
the shares of which they are beneficial owners have been deemed
to be owned by affiliates solely for this calculation. |
PART I
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ITEM 1
and ITEM 2.
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DESCRIPTION
OF BUSINESS AND PROPERTIES
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General
PYR Energy Corporation (referred to as PYR, the
Company, we, us and
our) is an independent oil and gas exploration and
production company, engaged in the exploration, development and
acquisition of crude oil and natural gas reserves. The Company
was incorporated in March 1996 in the state of Delaware under
the name Mar Ventures Inc. Effective as of August 6, 1997,
the Company purchased all the ownership interests of PYR Energy,
LLC, an oil and gas exploration company. On November 12,
1997, the name of the Company was changed to PYR Energy
Corporation. Effective July 2, 2001, the Company was
re-incorporated in Maryland through the merger of the Company
into a wholly owned subsidiary, PYR Energy Corporation, a
Maryland corporation. On February 18, 2004, PYR Cumberland
LLC, PYR Mallard LLC, and PYR Pintail LLC were formed as wholly
owned subsidiaries of PYR Energy Corporation. PYR Mallard LLC
owns and is developing the Companys Mallard project in
Uinta County, Wyoming. PYR Cumberland LLC and PYR Pintail LLC
are currently inactive.
Our current focus is on the Rocky Mountain, Texas and Gulf Coast
regions as described below. During the fiscal years ended
August 31, 2006 and 2005, we focused our development and
exploration efforts on the drilling phase of our high potential
development and exploration projects in the Rocky Mountain and
Gulf Coast regions.
The Companys 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 Companys web site is www.pyrenergy.com. The
Companys periodic and current reports filed with the
Securities and Exchange Commission (the SEC) can be
found on the Companys website at www.pyrenergy.com and on
the SECs website at www.sec.gov.
PROPERTIES
AND BUSINESS ACTIVITIES
Oil and
Gas Exploration and Development Activities
Our development, exploration, and acquisition activities are
focused primarily in select areas of the Rocky Mountains, Texas
and the Gulf Coast. A number of these projects offer multiple
drilling opportunities with individual wells having the
potential of encountering multiple reservoirs.
The following is an update of our production and exploration
areas and significant projects. While actively pursuing specific
production and exploration activities in each of the following
areas, we continually review additional acquisition
opportunities in these core areas and in other areas that meet
our production and exploration criteria. We are currently
producing over 5.1 million cubic feet of gas equivalent per
day and are 100% unhedged.
Rocky
Mountain Exploration
Mallard Project. At our Mallard project
in Uinta County, Wyoming, three and one-half inch tubing has
been successfully installed inside of the seven-inch casing of
the well-bore for the #1-30 Duck Federal well. From
mid-September through mid-November 2006, the operator
encountered difficulties in removing a retrievable mechanical
plug in the tubing that was installed for safety reasons during
installation of the tubing and the well was shut-in pending the
removal of either this plug or the tubing. As a result of this
difficulty, along with the shut-down for the actual tubing
operation, the well was off-line from August through
mid-November, 2006, and production was down sharply. Thirty days
prior to the tubing installation, production averaged
4.0 MMcf per day of gas, 61 barrels of associated
condensate, and 325 barrels of water. Since mid-November
2006, when the well was recently brought back on-line, it has
produced on average approximately 5.0 MMcf per day of gas,
75 barrels of condensate and 371 barrels of water
using a
16/64th
choke. Production is expected to improve as the well continues
to clean-up and stabilize. The 23 square miles of
3-D seismic
that the Company is participating in to define future drilling
locations has been completed. The Company is participating with
a 28.75% working interest in the #1-30 Duck Federal well
and 3-D
seismic. The Company believes there are additional proved
undeveloped (PUD) locations to drill within its acreage
position. The #1-30 Duck Federal represents a development
well within the Whitney Canyon-Carter Creek Field complex. Of
the more than 2.1 Tcf that has been produced to date from this
Field, over 80% of the production is from the Mission Canyon
formation, which is the primary producing formation for the
#1-30 Duck Federal.
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In addition, PYR and the other working interest owners have
begun the process to re-enter and sidetrack the now-abandoned
UPRC 25-1 well, located approximately 2400 north of
the Duck Federal. This well encountered the Mission Canyon
approximately 400 high to the Duck Federal, but failed to
penetrate the main porosity zone due to steep dips. As a result,
it produced only around 587 MMcf and 5000 barrels
condensate prior to being plugged and abandoned by another
operator in May 2001. PYR believes economic reserves can be
found within the porosity zones, accessible via a sidetrack. The
Company expects to be drilling this well before the end of
December 2006.
The Company has also participated in road and location
construction for the Teal #36-1 pending the outcome of the
3D survey.
Pioneer Prospect. The Company has
recently leased approximately 1,800 net acres in this
project in Wyoming.
Ryckman Creek Project. We have leased
approximately 1,820 net acres, covering the majority of the
abandoned Ryckman Creek field, in the Overthrust region of
southwestern Wyoming. Ryckman Creek, located 6 miles east
of our Mallard prospect, was discovered in 1975 and produced
approximately 250 Bcfe prior to abandonment. We believe that
recoverable gas reserves were stranded in Ryckman Creek upon
abandonment. Potential reserves exist in multiple zones,
including the Twin Creek, Nugget, and Thaynes Formations, in the
field. The Company owns 100% of this project and we are studying
our alternatives, which include selling our interest down or
possibly farming out the project.
Montana Foothills Project. Following
the plugging and abandonment of the Flesher Pass exploratory
well in August 2005, the Company re-evaluated the exploration
prospects associated with its undeveloped acreage in the project
and elected to release all of its undeveloped acreage position.
As a result, all remaining acreage positions expired by
August 1, 2006. As previously stated, the Company wrote
down all of its costs in the amortizable base of the full cost
pool in the first quarter ended November 30, 2005.
Texas
and Gulf Coast Exploration:
Nome Field. This field was discovered
in 1994, and our interpretation of subsequently acquired 3D
seismic over the field indicates the presence of numerous
undeveloped fault blocks. Multiple structural closures and
associated bright spot locations have been identified at Nome
based on the 3D seismic. One such location resulted in the Sun
Fee GU #1-ST well (the Sun Fee Well), which
produces from the upper Yegua, and was initiated in late May
2004, and beginning in early June 2004, averaged approximately
19 MMcfe per day. The well continues to produce at an
average rate of 11 MMcfe/day (8.1 MMcf/day and 500
BO/day). At the end of October 2006 the well had cumulative
production of approximately 11.7 Bcfe. When the well
reached payout on October 13, 2004, PYR was placed in pay
status as a working interest participant in the well. Based on
pooling of lands into the Sun Fee Sidetrack Unit (the
Sidetrack Unit) by the operator, our current net
revenue interest in the well and associated lands is 5.7%,
consisting of a 5.19% working interest with a 1.5% overriding
royalty interest. We and the other working interest partners
control approximately 4,200 of gross leasehold acres in the
project. Wells drilled in this prospect are subject to a 50% net
profits interest agreement, reducing to 25% after the payout of
the net profit interest to Venus Exploration Trust.
We are currently in litigation with the operator of the Sun Fee
Well, Samson Lone Star L.P. (Samson), concerning,
among other matters, Samsons pooling of certain lands into
the production unit and the corresponding reduction in our
working interest. The outcome of the litigation will determine
our working interest and revenue interest.
In September, the U.S. District Court for the Eastern
District of Texas issued its ruling on the outstanding motions
for summary judgment that had been filed by both parties, PYR
Energy Corporation, as Plaintiff, and Samson Resources Company
and Samson Lone Star Partnership LLP (Samson), as
Defendant. In its ruling, the Court held (1) that Samson
did not have authority to pool PYRs original overriding
royalty interest in the Sun Fee Well, located in Jefferson
County, Texas into the Sidetrack Unit and, therefore, PYR is
entitled to the interest in the production from the Sun Fee Well
that is attributable to this 3.5% overriding royalty from the
day of first production, rather than the 1.5% overriding royalty
interest amount upon which Samson has been paying, and
(2) that, although Samson did have authority to pool
PYRs working interest into the unit, PYR would be able to
maintain its claim for breach of contract against Samson for
joining non-productive acreage into the unit.
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In its complaint in this suit, PYR has alleged that Samson
breached its underlying contracts with PYR when Samson included
in the Sidetrack Unit properties in which Samson held the
exclusive interests and which PYR contends are non-productive.
PYR believes that this action by Samson improperly diluted
PYRs unit-based interest. The Court also left for trial
PYRs claims that Samson had also breached the underlying
agreements by failing to assign to PYR its working interest in
all properties as called for in the underlying contracts and by
failing to give PYR geologic and other technical information
applicable to the Sun Fee Well and Unit. The Court held that
PYRs alternate claim that Samson owed PYR a fiduciary duty
in forming the Sidetrack Unit was fully resolved by its other
rulings.
Our revenues and costs associated with the production from the
Sun Fee Well, as well as our costs incurred on the Nome Project,
are subject to a net profits agreement with Venus Exploration
Trust (Trust). The net profits agreement arose out
of our acquisition of properties from Venus Exploration Inc.
(Venus) in May 2004. The initial net profit interest
under the agreement varies from 25% to 50% with respect to
different Venus exploration and exploitation project areas, and
decreases by one-half of its original amount after a total of
$3.3 million in net profits proceeds has been paid to the
Trust. The amount of net profits liability recognized over time
is subject to fluctuation, because both revenues and costs
associated with production from any wells and other costs
incurred on the designated exploration and exploitation project
areas will increase or decrease over a given period of time.
The Tindall #1, offsetting by approximately 1600 feet
the Sun Fee Well, is a location that the Company owns 100% of
the working interest. Samson filed a lawsuit seeking a judicial
declaration of Samsons exclusive right to operate the
Tindall well and injunctive relief enjoining the Company from
continuing its drilling operations or serving as operator. As of
September 6, 2006, the State District Court for Jefferson
County, Texas, 58th Judicial District, issued a final
summary judgment in PYRs favor against Samson and ending
this suit. The Company is evaluating the economic viability of
drilling the Tindall #1 well given the current volumes of
gas, oil and water produced from the offsetting Sun Fee Well.
At the Nome Field, in Jefferson County, Texas, the
Nome-Long #1 well has reached total depth of
15,800 feet. Based on log analysis, the Company believes
that the well has found significant pay in the upper Yegua
(EY-3) sandstone at a measured depth of 14,200 feet.
Multiple wireline tests indicate formation pressure averaging
approximately 12,700 psi in this zone. Additional pay was logged
in shallower Yegua zones. The operator has commenced completion
operations and we anticipate that subsequent testing of the
indicated pay zone will take place by the end of December 2006.
PYR is participating with an 8.33% working interest. Wells
drilled in this prospect are subject to the Trusts initial
net profits interest of 50%.
Cotton Creek Prospect. Cotton Creek
Prospect, located in Jefferson County, Texas, is adjacent to the
Nome project. The prospect is located approximately one mile
west of the productive Sun Fee Well in the same structural fault
block. PYR owns a 50% working interest in the acreage position
and controls with its partner approximately 500 acres of
term minerals in addition to a modest amount of term leasehold.
PYRs ownership in this prospect is not in dispute;
however, the other working interest owner has connected
PYRs ownership in this project to the Bankruptcy case and
has indicated that they will not participate in any activity in
this prospect until the issues in the Bankruptcy case have been
resolved. PYRs ownership in this project consists of
predominately a term fee mineral interest. As long as there is
production elsewhere on these minerals the Companys
interest is not in danger of reverting or expiring. The Company
will evaluate its options once the legal matters and partner
issues have been resolved. Wells drilled in this prospect are
subject to the Trusts initial net profits interest of 25%.
Madison Prospect. At the Madison
project in the northern part of the Constitution Field, located
in Jefferson County, Texas, the Maness Gas Unit #1 well,
which had recently undergone an extensive and complicated
workover during the 2006 summer to replace production tubing
damaged by corrosion and scaling, is flowing at approximately
1.95 MMcfe per day to sales at this time. The well
continues to build pressure and volume, and we expect the well
to continue to improve. At the time of shut-in for the workover,
the Maness GU#1 had cumulative production of 2.6 Bcfe and
was averaging gross production of approximately 400 BO/day and
1.5 MMcf/day (3.9 MMcfe/day). The Company is
participating with a 12.5% working interest. This well is
subject to the Trusts initial net profits interest of 50%.
Also in the Madison Prospect, the Wall #1 well, a PUD
location offsetting the Maness GU#1 well, has reached total
depth and completion operations are in progress. The Company
believes the well will be flowing to sales in the
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next several weeks. Based on log analysis, this well found
approximately 20 feet of net pay in the middle Yegua zone,
Doyle sandstone, at a depth of 14,050 feet. Wireline tests
indicate gas production and formation pressure averaging
approximately 11,645 psi. An additional 10 feet of net
pay were logged and tested in shallower zones. Pending results
from this test, the Company anticipates that additional PUD
locations should be drilled in the summer of 2007. PYR is
participating for a 17.5% working interest in this development
well. Wells drilled in this prospect are subject to the
Trusts initial net profits of 50%.
Tortuga Grande Prospect. At the Tortuga
project in Smith County, Texas, the Chisum #1 well was
completed in the lower Rodessa section and is currently
producing at approximately 820 Mcfe per day. Rodessa
production, within 3 miles to the north and northeast of
the Chisum location, has yielded cumulative production ranging
up to 6.4 Bcfe per well. Additional drilling locations to
fully exploit the Rodessa potential in the project area have
been identified and it is expected that approximately
25 square miles of 3D seismic data will be acquired to
better delineate the additional drilling opportunities. The
Company owns a 28.57% working interest in the Chisum well and
surrounding acreage. The Company and the operator also control
approximately 9,800 acres of leasehold in the project.
Wells drilled in this prospect are subject to the Trusts
net profits interest.
Merganser Prospect. This prospect,
located in Leon County, Texas, targets Cotton Valley and Bossier
sandstone reservoirs. In February 2006, PYR sold its interest in
approximately 250 acres, in the prospect, for $280,239 to
Encana Oil & Gas.
Bayou Duralde Prospect. In 2006, the
Company participated in the completion of the
Fontenot #1 well located in Evangeline Parish,
Louisiana on the Bayou Duralde prospect. The well has been
drilled and cased to a total depth of 10,650 to evaluate
the Cockfield and Frio formations. Given the expense of
connecting to a pipeline, the operator is considering the most
cost effective method to evaluate this well. They evaluated
their initial approach of testing through a sales line and are
now considering an alternative that would replicate a flow test
to a sales line, placing back pressure on the well, and flowing
it to atmosphere for a period of time to ultimately determine
its commerciality. PYR is participating with a 15% working
interest before payout and 17.5% after payout in the project.
PYR, along with its partners, controls approximately
3,000 acres of leasehold. Wells drilled in this prospect
are subject to the Trusts initial net profits interest of
25%.
West Westbury Prospect. This prospect,
which consists of 388 acres in which PYR has a 100% working
interest, is located in Jefferson County, Texas, and targets
Yegua sand reservoirs. The prospect, based on 3D seismic
amplitude, is located approximately 1.5 miles to the
southwest of an analog well that was completed in October of
2004 and in which PYR does not have an interest. This analog
well, located in the same fault block but subject to different
seismic attributes, had cumulative production of 21.9 Bcfe
through April 2006 and is currently producing 35 MMcf of
gas and 1700 barrels of condensate per day. Recently, a
second well in which PYR does not have an interest, the Paggi
Broussard #2, was drilled and is producing 28MMcfd and
1500 barrels of condensate per day. The Paggi Broussard #2
also is in the same fault block with different seismic
attributes than PYRs acreage. PYR is currently marketing
its interest in this exploration prospect to industry partners.
Wilburton Field. In the Wilburton field
located in Latimer County, Oklahoma, the Scharff #7-1 was
recently completed and is producing approximately 16 MMcf
per day from a total of 181 net feet of commingled pay in
the Cecil, Shay, and Wister B sandstone at measured depths
ranging from 11,830 to 14,222 feet. Four shallower zones
behind pipe contain a total of approximately 48 net feet of
pay, based on log analysis. The Scharff #8-1 was recently
completed after the Scharff #7-1 and is producing
approximately 13 MMcf per day from a total of 112 net
feet of pay in the Cecil sandstone at a measured depth of
11,300 feet, based on log analysis. Additionally, an
approximate 44 net feet of pay was logged in shallower
zones. The Scharff #6-1 and #5-1 continue to produce
at 6 MMcf and 25 MMcf per day respectively. PYR owns a
2.42% working interest in each of the Scharff #5-1, 6-1,
7-1, and 8-1 wells.
Hansford Project. Located in Hansford
County of the Texas Panhandle, the Hansford project is a
development project at the southern end of the Houghton
Embayment. Main producing horizons within the Hansford area
include the upper and lower Morrow as well as the Chester. On
December 20, 2005, the Company closed a strategic
acquisition of additional interest in the Hansford project, from
multiple private entities, for $1.78 million in cash. The
acquisition of the Hansford County property consisted of
approximately 1.64 Bcf of proved reserves and
2,265 acres of undeveloped leasehold. This acquisition
allowed the Company to consolidate working interest and
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operations in a field which offers significant development
drilling opportunities. As of August 31, 2006, in a report
prepared by Ryder Scott Company, L.P., the Companys
estimated proved reserves in the Hansford project are
approximately 2.5BCF, of which 65% are classified as PUD. PYR
owns a 100% working interest on the majority of the acreage,
which includes three producing wells, two PUD locations. The
Lackey GU #2, completed earlier this year is currently
producing between 200 and 300 Mcf per day. The Lackey
GU #1, which underwent a work over is currently producing
between 200 and 300 Mcf per day. The Company owns a 100%
working interest in both the Lackey GU #1 and Lackey GU #2.
Future drilling opportunities are currently being evaluated.
OTHER
Utah
PYR owns working interests ranging from 19% to 57% in four wells
(one of which reached payout in August) located in Duchesne and
Uintah Counties, State of Utah. PYR acquired its interests in
these wells through the acquisition from Venus in 2004.
San Joaquin
Basin, California
The Company continues to maintain some leasehold in two
prospects, Bulldog and Wedge, in this region.
Blizzard. The Blizzard project is
located in the southern portion of the San Joaquin Basin of
Kern County, California. Blizzard is a combination exploration
and exploitation project offsetting the Rio Viejo Field.
Management has sold the Companys leasehold position while
retaining an overriding royalty.
Bulldog Prospect. This project is a 2D
seismically identified natural gas and condensate prospect
located adjacent to the giant Kettleman North Dome field in the
San Joaquin Basin. This prospect can be best characterized
as a classic footwall fault trap, similar to the many known
footwall fault trap accumulations that have produced significant
quantities of hydrocarbons throughout the San Joaquin
basin. The Company may drill, farm out, or sell its position in
this prospect in the future.
Wedge Prospect. This is a seismically
identified Temblor prospect located northwest of and adjacent to
the East Lost Hills deep gas discovery. During the first fiscal
quarter of 2001, we acquired approximately 17 miles of
proprietary, high effort 2D seismic data and combined this data
with existing 2D seismic data in order to refine what we
interpret as the up-dip extension of the East Lost Hills
structure. Our seismic interpretation shows that the same trend
at East Lost Hills extends approximately ten miles farther
northwest of the East Lost Hills Area of Mutual Interest and can
be encountered as much as 3,000 feet higher. The Company
may drill, farm out, or sell its position in this prospect in
the future.
Markets
and Major Customers
Sales from our ownership interests in producing properties to
major unaffiliated customers (customers accounting for 10% or
more of gross revenue), all representing purchasers of oil and
gas, for the years ended August 31, 2006 and 2005 are as
follows:
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2006
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2005
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Customer A
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26
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%
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Customer B
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20
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%
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38
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%
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Customer C
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11
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%
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Customer D
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22
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%
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Customer E
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10
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%
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We are not confined to, nor dependent upon, any one purchaser or
small group of purchasers. Accordingly, the loss of a single
purchaser would not materially affect our business because we
believe we would be able to find another purchaser.
5
Employees
and Office Space
At November 15, 2006, we had seven full-time employees. Our
Denver office has six full-time employees including two
geologists. Our San Antonio office has one full-time
employee and two consulting geologists and one consulting
engineer. We believe that our relationship with our employees is
satisfactory. None of our employees are represented by labor
unions or covered by any collective bargaining agreement. We
lease approximately 3,800 square feet of office space in
Denver, Colorado for our executive and administrative offices.
We have an additional office in San Antonio, Texas, in
which we lease approximately 4,300 square feet.
Business
Strategy
Our objective is to increase stockholder value per share by
adding reserves, production, cash flow, earnings and net asset
value. To accomplish this objective, we intend to develop our
proved undeveloped locations and to capitalize on our technical
expertise in identifying, evaluating and participating in the
exploratory drilling and development of deep, structurally
complex formations. We also intend to build on our experience
and our competitive strengths, which include:
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our inventory of Texas and Rocky Mountain development and
exploration projects,
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our control of pre-drill exploration phases, and
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our ability to identify suitable development and exploitation
drilling opportunities.
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To implement our strategy, we seek to:
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Execute Exploration and Development Drilling on Our
Undrilled Projects. We have interests in
several exploration projects in the Texas Gulf Coast and select
areas of the Rocky Mountains. In the Rocky Mountains, our most
notable project is the Mallard prospect located in southwestern
Wyoming. We are currently expanding our drilling activities on
the Mallard prospect with the drilling of the UPRC
25-1 well and completion of
3-D seismic.
In the Texas Gulf Coast, we have interests in several
exploration projects and PUD locations to be drilled in the
future. We are currently attempting completion of recently
drilled wells in the Nome and Madison prospects.
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Continue to Internally Generate Exploration
Prospects. We believe that by continuing to
generate exploitation and 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 drilling.
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Evaluate Low Risk, Shallow Exploitation and Development
Drilling Opportunities. As part of our
ongoing strategy, we are evaluating lower risk drilling
opportunities relative to our higher risk, internally generated,
exploration projects. If found to be appropriate, these
opportunities can provide the Company with suitable internal
rates of return on investment, geographic and risk
diversification, and exposure to reserves and potential cash
flow. We continue to review and evaluate additional development
and exploitation opportunities as they arise.
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Continue a Disciplined Acquisition
Process. As part of our ongoing strategy, we
diligently look for properties or opportunities with significant
upside in our core areas. Through our personal contacts,
industry knowledge and expertise, we look to find under-worked
properties or missed structures, that with strong operatorship,
may be productive.
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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.
AMI. Area of Mutual Interest.
6
Bbl. One stock tank barrel, or 42
U.S. gallons liquid volume, used in reference to oil or
other liquid hydrocarbons.
Bbl/d. One Bbl per day.
Bc/d. Barrels of condensate daily.
Bcf. One billion cubic feet of natural gas at
standard atmospheric conditions.
Bcfe. One billion cubic feet equivalent of
natural gas, calculated by converting oil to equivalent Mcf at a
ratio of 6 Mcf to 1 Bbl of oil.
Boe. Barrels of oil equivalent, with six
thousand cubic feet of natural gas being equivalent to one
barrel of oil.
Btu or British thermal unit. The quantity of
heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
Capital Expenditures. Costs associated with
exploratory and development drilling (including exploratory dry
holes); leasehold acquisitions; seismic data acquisitions;
geological, geophysical and land related overhead expenditures;
delay rentals; producing property acquisitions; other
miscellaneous capital expenditures; compression equipment and
pipeline costs.
Carried through the tanks. The owner of this
type of interest in the drilling of a well incurs no liability
for costs associated with the well until the well is drilled,
completed and connected to commercial production/processing
facilities.
Completion. The installation of permanent
equipment for the production of oil or natural gas.
Condensate. Liquid hydrocarbons associated
with the production of a primarily natural gas reserve.
Developed Acreage. The number of acres that
are allocated or assignable to producing wells or wells capable
of production.
Development Well. A well drilled within the
proved area of an oil or natural gas reservoir to the depth of a
stratigraphic horizon known to be productive.
Exploitation. The continuing development of a
known producing formation in a previously discovered field. To
make complete or maximize the ultimate recovery of oil or
natural gas from the field by work including development wells,
secondary recovery equipment or other suitable processes and
technology.
Exploration. The search for natural
accumulations of oil and natural gas by any geological,
geophysical or other suitable means.
Exploratory Well. A well drilled to find and
produce oil or natural gas in an unproved area, to find a new
reservoir in a field previously found to be productive of oil or
natural gas in another reservoir, or to extend a known reservoir.
Field. An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Finding and Development Costs. The total
capital expenditures, including acquisition costs, and
exploration and abandonment costs, for oil and gas activities
divided by the amount of proved reserves added in the specified
period.
Gross Acres or Gross Wells. The total acres or
wells, as the case may be, in which we have a working interest.
Lease. An instrument which grants to another
(the lessee) the exclusive right to enter to explore for, drill
for, produce, store and remove oil and natural gas on the
mineral interest, in consideration for which the lessor is
entitled to certain rents and royalties payable under the terms
of the lease. Typically, the duration of the lessees
authorization is for a stated term of years and for so
long thereafter as minerals are producing.
Mcf. One thousand cubic feet of natural gas at
standard atmospheric conditions.
7
Mcf/d. One Mcf per day.
Mcfe. One thousand cubic feet equivalent of
natural gas, calculated by converting oil to equivalent Mcf at a
ratio of 6 Mcf to 1 Bbl of oil.
MMcf. One million cubic feet of natural gas.
Net Acres or Net Wells. A net acre or well is
deemed to exist when the sum of our fractional ownership working
interests in gross acres or wells, as the case may be, equals
one. The number of net acres or wells is the sum of the
fractional working interests owned in gross acres or wells, as
the case may be, expressed as whole numbers and fractions
thereof.
Operator. The individual or company
responsible to the working interest owners for the exploration,
development and production of an oil or natural gas well or
lease.
Participant Group. The individuals
and/or
companies that, together, comprise the ownership of 100% of the
working interest in a specific well or project.
PV-10
value. The present value of estimated future
revenues to be generated from the production of proved reserves
calculated in accordance with SEC guidelines, net of estimated
lease operating expense, production taxes and future development
costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to non-property
related expenses such as general and administrative expenses,
debt service and depreciation, depletion and amortization or
federal income taxes and discounted using an annual discount
rate of 10%.
Productive well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of the production exceed production
expenses and taxes.
Prospect. A specific geographic area which,
based on supporting geological, geophysical or other data and
also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery
of commercial hydrocarbons.
Proved developed reserves. Reserves that can
be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved reserves. The estimated quantities of
oil, natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
commercially recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped reserves (PUD). Proved
reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.
Re-entry. Entering an existing well bore to
redrill or repair.
Reserves. Natural gas and crude oil,
condensate and natural gas liquids on a net revenue interest
basis, found to be commercially recoverable.
Reservoir. A porous and permeable underground
formation containing a natural accumulation of producible
natural gas and/or oil that is confined by impermeable rock or
water barriers and is separate from other reservoirs.
Royalty. An interest in an oil and natural gas
lease that gives the owner of the interest the right to receive
a portion of the production from the leased acreage, or of the
proceeds of the sale thereof, but generally does not require the
owner to pay any portion of the costs of drilling or operating
the wells on the leased acreage. Royalties may be either
landowners royalties, which are reserved by the owner of
the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of
the leasehold in connection with a transfer to a subsequent
owner.
Sidetrack. An operation involving the use of a
portion of an existing well to drill a second hole at some
desired angle into previously undrilled areas. From this
directional start, a new hole is drilled to the desired
formation depth and casing is set in the new hole and tied back
to the casing from the existing well.
8
Tcf. One trillion cubic feet.
3-D
Seismic. The method by which a three-dimensional
image of the earths subsurface is created through the
interpretation of reflection seismic data collected over a
surface grid.
3-D seismic
surveys allow for a more detailed understanding of the
subsurface than do conventional surveys and contribute
significantly to field appraisal, exploitation and production.
Undeveloped Acreage. Lease acres on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas
regardless of whether or not such acreage contains proved
reserves.
Working Interest. An interest in an oil and
gas lease that gives the owner of the interest the right to
drill and produce oil and gas on the leased acreage and requires
the owner to pay a share of the costs of drilling and production
operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs
that the working interest owner is required to bear, with the
balance of the production accruing to the owners of royalties.
Proved
Reserves
For fiscal years 2006 and 2005, our proved reserve estimates for
our United States oil and gas properties were prepared by Ryder
Scott Company, L.P., an independent petroleum engineering firm,
and, in accordance with SEC guidelines, are the estimated
quantities of oil, natural gas and plant products which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions,
i.e. prices and costs as of the date the estimate is made. The
Standardized Measure shown in the table is not intended to
represent the current market value of our estimated natural gas
and oil reserves.
|
|
|
|
|
|
|
|
|
|
|
As of August 31,
|
|
|
|
2005
|
|
|
2006
|
|
|
Estimated Net Proved Reserves:
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
3,668
|
|
|
|
5,738
|
|
Oil & NGLs (MBbls)
|
|
|
566
|
|
|
|
628
|
|
Total (MMcfe)
|
|
|
7,064
|
|
|
|
9,508
|
|
Percent proved developed
|
|
|
61.8
|
%
|
|
|
61.7
|
%
|
Standardized Measure (in
thousands)(1)
|
|
$
|
28,752
|
|
|
$
|
28,685
|
|
|
|
|
(1) |
|
The Standardized Measure represents the present value of
estimated future cash inflows from proved natural gas and oil
reserves, less future development, production, and income tax
expenses, discounted at 10% per annum to reflect timing of
future cash flows and using market prices for natural gas and
oil at each of August 31, 2005 and 2006, which were
$11.74 per Mcf of gas and $66.95 per bbl of oil at
August 31, 2005 and $5.49 per Mcf of gas and
$67.12 per Bbl of oil at August 31, 2006. |
At August 31, 2006, our estimated total proved reserves
increased 34% increase over August 31, 2005 estimated total
proved reserves. This increase resulted principally from the
addition of estimated proved reserves from new proved developed
producing and proved undeveloped additions related to
development in the expanded Yegua trend of south Texas and
completion of the #1-30 Duck Federal well in Uinta County
Wyoming. As of August 31, 2006, proved developed producing
reserves are estimated at 4.431 Bcfe, while proved
developed non-producing reserves are estimated at
1.437 Bcfe. Proved undeveloped reserves are estimated at
3.640 Bcfe. The Companys Canadian oil and gas
properties do not have proved reserves.
Using current market product prices in effect at the end of the
fiscal year and a discount rate of 10% as prescribed by SEC
regulation, our total discounted future after-tax net cash flows
were estimated to be approximately $28.7 million for total
proved reserves for the years ended August 31, 2006 and
2005. Reserve additions in fiscal 2006 offset a decrease of 53%
in gas prices from August 31, 2005. The present value of
future net cash flows does not purport to be an estimate of the
fair market value of our proved reserves. An estimate of the
future value would also take into consideration, among other
things, anticipated changes in future prices and costs, the
expected
9
recovery of reserves in excess of proved reserves and a discount
factor more representative of the time value of money and the
risks inherent in producing oil, natural gas and plant products.
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.
Production
and Prices
The following table sets forth information regarding net
production of oil, natural gas and natural gas liquids, and
certain price and cost information for fiscal years ended
August 31, 2005 and 2006:
|
|
|
|
|
|
|
|
|
|
|
As of August 31,
|
|
|
|
2005
|
|
|
2006
|
|
|
Production Data:
|
|
|
|
|
|
|
|
|
Natural gas (Mcf)
|
|
|
392,067
|
|
|
|
915,973
|
|
Oil (Bbls)
|
|
|
61,948
|
|
|
|
53,049
|
|
NGLs (Bbls)
|
|
|
336
|
|
|
|
5,267
|
|
Combined volumes (MMcfe)
|
|
|
766
|
|
|
|
1,266
|
|
Daily combined volumes (MMcfe/d)
|
|
|
2.1
|
|
|
|
3.5
|
|
Average Prices:
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.54
|
|
|
$
|
7.32
|
|
Oil (per Bbl)
|
|
$
|
50.04
|
|
|
$
|
63.55
|
|
NGLs (per Bbl)
|
|
$
|
29.53
|
|
|
$
|
34.83
|
|
Combined (per Mcfe)
|
|
$
|
7.96
|
|
|
$
|
8.15
|
|
Average Costs (Per
Mcfe):
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.94
|
|
|
$
|
1.22
|
|
Production taxes, gathering and
transportation
|
|
$
|
0.50
|
|
|
$
|
0.54
|
|
Depreciation, depletion and
amortization
|
|
$
|
1.13
|
|
|
$
|
2.05
|
|
General and administrative
|
|
$
|
2.49
|
|
|
$
|
1.78
|
|
Productive
Wells
The following table summarizes information at August 31,
2006, relating to the productive wells in which we owned a
working interest as of that date. Productive wells consist of
producing wells and wells capable of
10
production. Gross wells are the total number of producing wells
in which we have an interest, and net wells are the sum of our
fractional working interests owned in gross wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Location
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
0.05
|
|
|
|
0.05
|
|
California
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
|
|
0.24
|
|
|
|
|
|
|
|
0.24
|
|
Oklahoma
|
|
|
17
|
|
|
|
27
|
|
|
|
44
|
|
|
|
2.86
|
|
|
|
0.85
|
|
|
|
3.71
|
|
Texas
|
|
|
20
|
|
|
|
15
|
|
|
|
35
|
|
|
|
4.42
|
|
|
|
4.41
|
|
|
|
8.83
|
|
Utah
|
|
|
5
|
|
|
|
|
|
|
|
5
|
|
|
|
1.68
|
|
|
|
|
|
|
|
1.68
|
|
Wyoming
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
0.29
|
|
|
|
0.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
|
45
|
|
|
|
44
|
|
|
|
89
|
|
|
|
9.20
|
|
|
|
5.60
|
|
|
|
14.80
|
|
Drilling
Activities
During the past two fiscal years, we participated in the
drilling of the following exploration and development wells:
|
|
|
|
|
During the fiscal year ended August 31, 2006, PYR
participated in the drilling of three exploration wells, with
one exploration well in the Wyoming Overthrust, one in the
southeast Gulf Coast, and one in Louisiana. PYR also
participated in drilling a workover in Hansford County, Texas
and another one in the Constitution Field in the Gulf Coast.
During this time period, the Company participated in drilling
seven PUDs total, with one drilled in Hansford, Texas (100% WI),
five drilled in the Willburton Field in Oklahoma (2.42% WI), and
one in the Gulf Coast area (17.5% WI). As of mid-November 2006,
both workovers were producing to sales, all of the exploratory
wells were either producing or in the process of being
completed, and all of the PUD wells were also either producing
to sales or in the process of being completed.
|
|
|
|
During the fiscal year ended August 31, 2005, we
participated in the drilling of two exploration wells in the
Wyoming Overthrust, one exploration well in East Texas, and two
development wells in Oklahoma. Four of these wells were
successful, and one of the Wyoming Overthrust exploration wells
was plugged and abandoned in November 2005. Additionally in
fiscal year 2005, the Company participated in several well
workovers in Texas and Oklahoma.
|
Although there is no assurance that any additional wells will be
drilled, we anticipate we may drill additional exploration and
development wells during fiscal 2007 on our projects in the
Texas Gulf Coast and Rocky Mountains. The actual number of wells
drilled will be dependent on several factors, including the
results of our ongoing exploration efforts and the availability
of capital.
Full Cost
Method of Accounting for Oil and Gas Properties
The Company utilizes the full cost method of accounting for oil
and gas activities and in accordance with the full cost method
of accounting, the Company maintained separate cost centers for
its oil and gas activities in the United States and Canada for
fiscal years 2006 and 2005. Under this method, all costs
associated with acquisition, exploration and development
activities are capitalized by cost center. Capitalized costs,
excluding costs of investments in unproved properties and major
development projects, are subject to a ceiling test
limitation computed separately for each cost center. Under
this method, we are required to record a permanent impairment
provision if the net book value of our oil and gas properties
(net of related deferred taxes) exceeds a ceiling value equal to
the sum of (i) the present value of the future cash inflows
from proved reserves, tax effected and discounted at
10% per annum, and (ii) the cost of unevaluated
properties. The ceiling test is computed by country and at the
end of each quarter. The oil and gas prices used in calculating
future cash inflows in the United States are based upon the
market price on the last day of the accounting period. Oil and
gas prices are generally volatile; and if the market prices at a
period end date have decreased, we may have to record an
impairment. A loss may also be generated by the transfer of
significant early stage exploratory costs to the oil and gas
property cost pool that is subject to the ceiling test. These
losses typically occur when significant costs are transferred to
the oil and gas property full cost
11
pool as a result of an unsuccessful project without commercial
oil and gas production. For the years ended August 31, 2006
and 2005, no property impairment charges were recorded for the
Companys United States properties.
In accordance with the full cost method of accounting, the
Companys Canadian oil and gas investment, comprised
principally of non-producing acreage (used for exploration and
development activities), is recorded in a separate full cost
pool. During 2005, the Company recorded a non-cash impairment of
$580,000 of its initial oil and gas investment in Canada as the
book value of the properties exceeded the fair market value of
such properties. The Company decided to limit future
expenditures in Canada.
Developed
and Undeveloped Acreage
The following table sets forth information as of August 31,
2006 relating to our leasehold acreage.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Acres
|
|
|
Net Acres
|
|
State
|
|
Developed
|
|
|
Undeveloped
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
California
|
|
|
400
|
|
|
|
5,000
|
|
|
|
33
|
|
|
|
5,000
|
|
Louisiana
|
|
|
|
|
|
|
2,665
|
|
|
|
|
|
|
|
2,615
|
|
Oklahoma
|
|
|
5,659
|
|
|
|
|
|
|
|
197
|
|
|
|
|
|
Texas
|
|
|
25,633
|
|
|
|
8,306
|
|
|
|
9,610
|
|
|
|
7,048
|
|
Utah
|
|
|
4,943
|
|
|
|
|
|
|
|
1,504
|
|
|
|
|
|
Wyoming
|
|
|
640
|
|
|
|
7,872
|
|
|
|
184
|
|
|
|
5,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
|
37,275
|
|
|
|
23,843
|
|
|
|
11,528
|
|
|
|
19,763
|
|
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 currently operate one property. We believe that operations
where we own interests comply in all material respects with
applicable laws and regulations and that the existence and
enforcement of these laws and regulations have no more
restrictive an effect on our operations than on other similar
companies in the energy industry.
The following discussion contains summaries of certain laws and
regulations and is qualified in its entirety by the foregoing
and by reference to the full text of the laws and regulations
described.
Federal Regulation of the Sale and Transportation of Oil and
Gas. Various aspects of our oil and gas
operations are or will be regulated by agencies of the federal
government. The Federal Energy Regulatory Commission, or FERC,
regulates the transportation and sale for resale of natural gas
in interstate commerce pursuant to the Natural Gas Act of 1938,
or NGA, and the Natural Gas Policy Act of 1978, or NGPA. In the
past, the
12
federal government has regulated the prices at which oil and gas
could be sold. While first sales by producers of
natural gas, and all sales of crude oil, condensate and natural
gas liquids can currently be made at uncontrolled market prices,
Congress could reenact price controls in the future.
Deregulation of wellhead sales in the natural gas industry began
with the enactment of the NGPA in 1978. In 1989, Congress
enacted the Natural Gas Wellhead Decontrol Act.
The Decontrol Act removed all NGA and NGPA price and non-price
controls affecting wellhead sales of natural gas effective
January 1, 1993, and resulted in a series of Orders being
issued by FERC requiring interstate pipelines to provide
transportation services separately, or unbundled,
from the pipelines sales of gas and to provide open access
transportation on a nondiscriminatory basis that is equal for
all natural gas shippers.
We do not believe that we will be affected by these or any other
FERC rules or orders materially differently than other natural
gas producers and marketers with which we compete.
The FERC also has issued numerous orders confirming the sale and
abandonment of natural gas gathering facilities previously owned
by interstate pipelines and acknowledging that if the FERC does
not have jurisdiction over services provided on those
facilities, then those facilities and services may be subject to
regulation by state authorities in accordance with state law. A
number of states have either enacted new laws or are considering
the adequacy of existing laws affecting gathering rates
and/or
services. Other state regulation of gathering facilities
generally includes various safety, environmental, and in some
circumstances, nondiscriminatory take requirements, but does not
generally entail rate regulation. Thus, natural gas gathering
may receive greater regulatory scrutiny of state agencies in the
future. Our anticipated gathering operations could be adversely
affected should they be subject in the future to increased state
regulation of rates or services, although we do not believe that
we would be affected by such regulation any differently than
other natural gas producers or gatherers. In addition, the
FERCs approval of transfers of previously-regulated
gathering systems to independent or pipeline affiliated
gathering companies that are not subject to FERC regulation may
affect competition for gathering or natural gas marketing
services in areas served by those systems and thus may affect
both the costs and the nature of gathering services that will be
available to interested producers or shippers in the future.
We conduct certain operations on federal oil and gas leases,
which are administered by the Minerals Management Service, or
MMS. Federal leases contain relatively standard terms and
require compliance with detailed MMS regulations and orders,
which are subject to change. Among other restrictions, the MMS
has regulations restricting the flaring or venting of natural
gas, and has proposed to amend those regulations to prohibit the
flaring of liquid hydrocarbons and oil without prior
authorization. Under certain circumstances, the MMS may require
any of our operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially
and adversely affect our financial condition, cash flows and
operations. The MMS issued a final rule that amended its
regulations governing the valuation of crude oil produced from
federal leases. This rule, which became effective June 1,
2000, provides that the MMS will collect royalties based on the
market value of oil produced from federal leases, and was
further modified by amendments to the June 2000 MMS rules,
effective July 1, 2004. Also, the MMS promulgated new
Federal Gas Valuation rules, effective June 1, 2005 (70FR
11869, March 10, 2005) concerning calculation of
transportation costs, including the allowed rate of return in
the calculation of actual transportation costs in non-arms
length arrangements and addresses various other related matters.
We cannot predict whether this new gas rule will become
effective, nor can we predict whether the MMS will take further
action on oil and gas valuation matters. However, we do not
believe that any such rules will affect us any differently than
other producers and marketers of crude oil with which we will
compete.
Additional proposals and proceedings that might affect the oil
and gas industry are pending before Congress, the FERC, the MMS,
state commissions and the courts. We cannot predict when or
whether any such proposals may become effective. In the past,
the natural gas industry has been heavily regulated. There is no
assurance that the regulatory approach currently pursued by
various agencies will continue indefinitely. Notwithstanding the
foregoing, we do not anticipate that compliance with existing
federal, state and local laws, rules and regulations will have a
material or significantly adverse effect upon our capital
expenditures, earnings or competitive position. No material
portion of our business is subject to re-negotiation of profits
or termination of contracts or subcontracts at the election of
the federal government.
13
State Regulation. Our operations also are
subject to regulation at the state and, in some cases, county,
municipal and local governmental levels. This regulation
includes requiring permits for the drilling of wells,
maintaining bonding requirements in order to drill or operate
wells and regulating the location of wells, the method of
drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled, the plugging and
abandonment of wells and the disposal of fluids used and
produced in connection with operations. Our operations also are
or will be subject to various conservation laws and regulations.
These include (1) the size of drilling and spacing units or
proration units, (2) the density of wells that may be
drilled, and (3) the unitization or pooling of oil and gas
properties. In addition, state conservation laws, which
frequently establish maximum rates of production from oil and
gas wells, generally prohibit the venting or flaring of gas and
impose certain requirements regarding the ratability of
production. State regulation of gathering facilities generally
includes various safety, environmental and, in some
circumstances, nondiscriminatory take requirements, but (except
as noted above) does not generally entail rate regulation. These
regulatory burdens may affect profitability, but we are unable
to predict the future cost or impact of complying with such
regulations.
Environmental Matters. Operations on
properties in which we have an interest are subject to extensive
federal, state and local environmental laws that regulate the
discharge or disposal of materials or substances into the
environment and otherwise are intended to protect the
environment. Numerous governmental agencies issue rules and
regulations to implement and enforce such laws, which are often
difficult and costly to comply with and which carry substantial
administrative, civil and criminal penalties and in some cases
injunctive relief for failure to comply. Some laws, rules and
regulations relating to the protection of the environment may,
in certain circumstances, impose strict liability
for environmental contamination. These laws render a person or
company liable for environmental and natural resource damages,
cleanup costs and, in the case of oil spills in certain states,
consequential damages without regard to negligence or fault.
Other laws, rules and regulations may require the rate of oil
and gas production to be below the economically optimal rate or
may even prohibit exploration or production activities in
environmentally sensitive areas. In addition, state laws often
require some form of remedial action, such as closure of
inactive pits and plugging of abandoned wells, to prevent
pollution from former or suspended operations. Legislation has
been proposed in the past and continues to be evaluated in
Congress from time to time that would reclassify certain oil and
gas exploration and production wastes as hazardous
wastes. This reclassification would make these wastes
subject to much more stringent storage, treatment, disposal and
clean-up
requirements, which could have a significant adverse impact on
operating costs. Initiatives to further regulate the disposal of
oil and gas wastes are also proposed in certain states from time
to time and may include initiatives at the county, municipal and
local government levels. These various initiatives could have a
similar adverse impact on operating costs. The regulatory burden
of environmental laws and regulations increases our cost and
risk of doing business and consequently affects our
profitability.
The federal Comprehensive Environmental Response, Compensation
and Liability Act, or CERCLA, also known as the
Superfund law, imposes liability, without regard to
fault, on certain classes of persons with respect to the release
of a hazardous substance into the environment. These
persons include the current or prior owner or operator of the
disposal site or sites where the release occurred and companies
that transported, disposed or arranged for the transport or
disposal of the hazardous substances found at the site. Persons
who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for
the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural
resources, and it is not uncommon for the federal or state
government to pursue such claims. It is also not uncommon for
neighboring landowners and other third parties to file claims
for personal injury or property or natural resource damages
allegedly caused by the hazardous substances released into the
environment. Under CERCLA, certain oil and gas materials and
products are, by definition, excluded from the term
hazardous substances. At least two federal courts
have held that certain wastes associated with the production of
crude oil may be classified as hazardous substances under
CERCLA. Similarly, under the federal Resource, Conservation and
Recovery Act, or RCRA, which governs the generation, treatment,
storage and disposal of solid wastes and
hazardous wastes, certain oil and gas materials and
wastes are exempt from the definition of hazardous
wastes. This exemption continues to be subject to judicial
interpretation and increasingly stringent state interpretation.
During the normal course of operations on properties in which we
have an interest, exempt and non-exempt wastes, including
hazardous wastes, that are subject to RCRA and comparable state
statutes and implementing regulations are generated or have been
generated in the past. The federal Environmental Protection
Agency and various state
14
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. The U.S. Environmental Protection
Agency and some other state environmental agencies have
increased their focus on control of minor gas emission leaks
from pipelines, compressors, tanks, and related oil and gas
production and storage equipment in response to ozone
non-attainment requirements increasing the costs and complexity
of our operations. We believe that the operator of the
properties in which we have an interest is in substantial
compliance with applicable laws, rules and regulations relating
to the control of air emissions at all facilities on those
properties.
Although we maintain insurance against some, but not all, of the
risks described above, including insuring the costs of
clean-up
operations, public liability and physical damage, there is no
assurance that our insurance will be adequate to cover all such
costs, that the insurance will continue to be available in the
future or that the insurance will be available at premium levels
that justify our purchase. The occurrence of a significant event
not fully insured or indemnified against could have a material
adverse effect on our financial condition and operations.
Compliance with environmental requirements, including financial
assurance requirements and the costs associated with the cleanup
of any spill, could have a material adverse effect on our
capital expenditures, earnings or competitive position. We do
believe, however, that our operators are in substantial
compliance with current applicable environmental laws and
regulations. Nevertheless, changes in environmental laws have
the potential to adversely affect operations. At this time, we
have no plans to make any material capital expenditures for
environmental control facilities.
Title to
Properties
As is customary in the oil and gas industry, only a preliminary
title examination is conducted at the time we acquire leases or
enter into other agreements to obtain control over interests in
acreage believed to be suitable for drilling operations. In many
instances, our partners have acquired rights to the prospective
acreage and we have a contractual right to have our interests in
that acreage assigned to us. In some cases, we are in the
process of having those interests so assigned. Prior to the
commencement of drilling operations, a thorough title
examination of the drill site tract is conducted by independent
attorneys. Once production from a given well is established, the
operator will prepare a division order title report indicating
the proper parties and percentages for payment of production
proceeds, including royalties. We believe that titles to our
leasehold properties are good and defensible in accordance with
standards generally acceptable in the oil and gas industry.
Risk
Factors
In evaluating the Company, careful consideration should be given
to the following risk factors, in addition to the other
information included or incorporated by reference in this annual
report. In addition, the Forward-Looking Statements
located herein, describe additional uncertainties associated
with our business and the forward-looking statements included or
incorporated by reference. Each of these risk factors could
adversely affect our business, operating results and financial
condition, as well as adversely affect the value of an
investment in our common stock.
We have a limited history of drilling and monitoring oil and
gas properties. 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
15
exploration prospects; and (4) our ability to fully
implement our exploration and development program. We cannot
predict that our future operations will be profitable. In
addition, our operating results may vary significantly during
any financial period. These variations may be caused by
significant periods of time between discovery and development of
oil or gas reserves, if any, in commercial quantities.
We may not discover commercially productive
reserves. Our future success depends on our
ability to economically locate oil and gas reserves in
commercial quantities. Except to the extent that we acquire
properties containing proved reserves or that we conduct
successful exploration and development activities, or both, our
proved reserves, if any, will decline as reserves are produced.
Our ability to locate reserves is dependent upon a number of
factors, including our participation in multiple exploration
projects and our technological capability to locate oil and gas
in commercial quantities. We cannot predict that we will have
the opportunity to participate in projects that economically
produce commercial quantities of oil and gas in amounts
necessary to meet our business plan or that the projects in
which we elect to participate will be successful. There can be
no assurance that our planned projects will result in
significant reserves or that we will have future success in
drilling productive wells at economical reserve replacement
costs.
Exploratory drilling is an uncertain process with many
risks. Exploratory drilling involves numerous
risks, including the risk that we will not find any commercially
productive oil or gas reservoirs. The cost of drilling,
completing and operating wells is often uncertain, and a number
of factors can delay or prevent drilling operations, including:
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unexpected drilling conditions,
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pressure or irregularities in formations,
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equipment failures or accidents,
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adverse weather conditions,
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compliance with governmental requirements,
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shortages or delays in the availability of drilling rigs and the
delivery of equipment, and
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shortages of trained oilfield service personnel.
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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.
16
Our operations require large amounts of capital and our cash
resources are limited. Our current development
plans will require us to have large amounts of cash in order 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 between $8 and
$12 million on exploration and development activities
during our fiscal year ending August 31, 2007. Also, we
must secure substantial capital to explore and develop our other
potential projects. Historically, we have funded our capital
expenditures through the issuance of equity. Volatility in the
price of our common stock, which may be significantly influenced
by our drilling and production activity, may impede our ability
to raise money quickly, if at all, through the issuance of
equity at acceptable prices. Future cash flows and the
availability of financing will be subject to a number of
variables, such as:
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our success in locating and producing reserves in other projects,
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the level of production from existing wells, and
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prices of oil and gas.
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Issuing equity securities to satisfy our financing requirements
could cause substantial dilution to our existing stockholders.
Debt financing, if obtained, could lead to:
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a substantial portion of our operating cash flow being dedicated
to the payment of principal and interest,
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our being more vulnerable to competitive pressures and economic
downturns, and
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restrictions on our operations.
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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 may consider selling down a portion of our interests
in some of our exploration and development projects to industry
partners to generate additional funds to finance our capital
budget.
We depend heavily on exploration success and subsequent
success in developing our exploration
projects. Our future growth plans rely heavily on
discovering reserves and initiating production in Texas, the
Gulf Coast, and the Rocky Mountains. Our development plan
includes the need to discover reserves and establish commercial
production through exploratory drilling and development of our
existing properties. We cannot be sure, though, that our planned
projects will lead to significant reserves that can be
economically extracted or that we will be able to drill
productive wells at anticipated finding and development costs.
If we are able to record reserves, our reserves will decline as
they are depleted, except to the extent that we conduct
successful exploration or development activities or acquire
other properties containing proved reserves.
We depend on industry alliances. We attempt to
limit financial exposure on a
project-by-project
basis by forming industry alliances where our technical
expertise can be complemented with the financial resources and
operating expertise of more established companies. While
entering into these alliances limits our financial exposure, it
also limits our potential revenue from successful projects.
Industry alliances also have the potential to expose us to
uncertainty if our industry partners are acquired or have
priorities in areas other than our projects. Despite these
risks, we believe that if we are not able to form industry
alliances, our ability to fully implement our business plan
could be limited, which could have a material adverse effect on
our business.
We have limited control over our oil and gas
projects. We focus primarily on creating
exploration opportunities and forming industry alliances to
develop those opportunities. We serve as the operator of only
one of our projects. As a result, we have only a limited ability
to exercise control over a significant portion of a
projects 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:
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the abilities of the operator of the project,
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the availability of leases with favorable terms and the
availability of required permitting for projects,
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the availability of future capital resources to us and the other
participants to be used for purchasing leases and drilling wells,
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the approval of other participants for the purchasing of leases
and the drilling of wells on the projects, and
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the economic conditions at the time of drilling, including the
prevailing and anticipated prices for oil and gas.
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Our reliance on the operator and 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:
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have a material adverse effect on our results of operations,
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limit our ability to attract capital,
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make the formations we are targeting significantly less
economically attractive,
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reduce our cash flow and borrowing capacity, and
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reduce the value and the amount of any future reserves.
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Various factors beyond our control will affect prices of oil and
gas, including:
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worldwide and domestic supplies of oil and gas,
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the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls,
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political instability or armed conflict in oil or gas producing
regions,
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the price and level of foreign imports,
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worldwide economic conditions,
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marketability of production,
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the level of consumer demand,
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the price, availability and acceptance of alternative fuels,
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the availability of processing and pipeline capacity,
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weather conditions, and
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actions of federal, state, local and foreign authorities.
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These external factors and the volatile nature of the energy
markets make it difficult to estimate future prices of oil and
gas. In addition, sales of oil and gas are seasonal in nature,
leading to substantial differences in cash flow at various times
throughout the year.
Accounting rules may require
write-downs. Under full cost accounting rules,
capitalized costs of proved oil and gas properties may not
exceed the present value of estimated future net revenues from
proved reserves, discounted at 10%. Application of the ceiling
test generally requires pricing future revenue at the
unescalated prices in effect as of the end of each fiscal
quarter and requires a write-down for accounting purposes if the
ceiling is exceeded. If a write-down is required, it would
result in a charge to earnings, but would not impact cash flow
from operating activities. Once incurred, a write-down of oil
and gas properties is not reversible at a later date.
We face risks related to title to the leases we enter into
that may result in additional costs and affect our operating
results. It is customary in the oil and gas
industry to acquire a leasehold interest in a property based
upon a preliminary title investigation. In many instances, our
partners have acquired rights to the prospective acreage and we
have a contractual right to have our interests in that acreage
assigned to us. In some cases, we are in the process of having
those interests so assigned. If the title to the leases acquired
is defective, or title to the leases
18
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
states interpretation of lease language concerning the
costs of production. We cannot guarantee that there will be no
litigation concerning the proper interpretation of the terms of
our leases. Adverse decisions in any litigation of this kind
could result in material costs or the loss of one or more leases.
Limitations on the effectiveness of
controls. Our management, including our Chief
Executive Officer and Chief Financial Officer, does not expect
that our disclosure controls or our internal controls can
prevent all possible error or fraud. A control system, no matter
how well conceived and operated, can provide only reasonable,
not absolute, assurance that the objectives of the control
system are met. Further, the design of a control system must
reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs.
Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all
control issues and instances of fraud, if any, within our
company have been detected. These inherent limitations include
the realities that judgments in decision making can be faulty,
and that breakdowns can occur because of simple error or
mistake. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more
people, or by management override of the control. The design of
any system of controls also is based in part upon certain
assumptions about the likelihood of future events, and there can
be no assurance that any design will succeed in achieving its
stated goals under all potential future conditions; over time,
controls may become inadequate because of changes in conditions,
or the degree of compliance with the policies or procedures may
deteriorate. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or
fraud may occur and not be detected.
Our industry is highly competitive and many of our
competitors have more resources than we do. We
compete in oil and gas exploration with a number of other
companies. Many of these competitors have financial and
technological resources vastly exceeding those available to us.
We cannot be sure that we will be successful in acquiring and
developing profitable properties in the face of this
competition. In addition, from time to time, there may be
competition for, and shortage of, exploration, drilling and
production equipment. These shortages could lead to an increase
in costs and delays in operations that could have a material
adverse effect on our business and our ability to develop our
properties. Problems of this nature also could prevent us from
producing any oil and gas we discover at the rate we desire to
do so.
Technological changes could put us at a competitive
disadvantage. The oil and gas industry is
characterized by rapid and significant technological
advancements and introductions of new products and services
using new technologies. As new technologies develop, we may be
placed at a competitive disadvantage, and competitive pressures
may force us to implement those new technologies at a
substantial cost. If other oil and gas exploration and
development companies implement new technologies before we do,
those companies may be able to provide enhanced capabilities and
superior quality compared with what we are able to provide. We
may not be able to respond to these competitive pressures and
implement new technologies on a timely basis or at an acceptable
cost. If we are unable to utilize the most advanced commercially
available technologies, our business could be materially and
adversely affected.
Our industry is heavily regulated. Federal,
state and local authorities extensively regulate the oil and gas
industry. Legislation and regulations affecting the industry are
under constant review for amendment or expansion, raising the
possibility of changes that may affect, among other things, the
pricing or marketing of oil and gas production. State and local
authorities regulate various aspects of oil and gas drilling and
production activities, including the drilling of wells (through
permit and bonding requirements), the spacing of wells, the
unitization or pooling of oil and gas properties, environmental
matters, safety standards, the sharing of markets, production
limitations, plugging and abandonment, and restoration. The
overall regulatory burden on the industry increases the cost of
doing business, which, in turn, decreases profitability.
19
Our operations must comply with complex environmental
regulations. Our operations are subject to
complex and constantly changing environmental laws and
regulations adopted by federal, state and local governmental
authorities. New laws or regulations, or changes to current
requirements, could have a material adverse effect on our
business. We will continue to be subject to uncertainty
associated with new regulatory interpretations and inconsistent
interpretations between state and federal agencies. We could
face significant liabilities to the government and third parties
for discharges of oil, natural gas, produced water or other
pollutants into the air, soil or water, and we could have to
spend substantial amounts on investigations, litigation and
remediation. We cannot be sure that existing environmental laws
or regulations, as currently interpreted or enforced, or as they
may be interpreted, enforced or altered in the future, will not
have a material adverse effect on our results of operations and
financial condition.
Our business depends on transportation facilities owned by
others. The marketability of our anticipated gas
production depends in part on the availability, proximity and
capacity of pipeline systems owned or operated by third parties.
Federal and state regulation of oil and gas production and
transportation, tax and energy policies, changes in supply and
demand and general economic conditions could adversely affect
our ability to produce, gather and transport oil and natural gas.
Attempts to grow our business could have an adverse
effect. Because of our small size, we desire to
grow rapidly in order to achieve certain economies of scale.
Although there is no assurance that this rapid growth will
occur, to the extent that it does occur, it will place a
significant strain on our financial, technical, operational and
administrative resources. As we increase our services and
enlarge the number of projects we are evaluating or in which we
are participating, there will be additional demands on our
financial, technical and administrative resources. The failure
to continue to upgrade our technical, administrative, operating
and financial control systems or the occurrence of unexpected
expansion difficulties, including the recruitment and retention
of geoscientists and engineers, could have a material adverse
effect on our business, financial condition and results of
operations.
We may not be able to retain our listing on the American
Stock Exchange. The American Stock Exchange has
certain listing requirements in order for a company to continue
to have their securities traded on this exchange. A company may
risk delisting if its common stock trades at a low price per
share for a substantial period of time. Should our stock trade
at a low share price for a substantial period of time, or our
net tangible equity be below certain levels, we may not be able
to retain our listing.
We depend on key personnel. We have a small
group of employees and are highly dependent on the services of
our executive management, and our other geological, geophysical
and land technical employees. The loss of the services of any of
these persons could hurt our business.
Disclosure
Regarding Forward-Looking Statements and Cautionary
Statements
This annual report contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934,
including statements regarding, among other items, our business
and growth strategies, anticipated trends in our business and
our future results of operations, market conditions in the oil
and gas industry, our ability to make and integrate
acquisitions, the outcome of litigation, if any, and the impact
of governmental regulation. These forward-looking statements are
based largely on our expectations and are subject to a number of
risks and uncertainties, many of which are beyond our control.
Actual results could differ materially from these
forward-looking statements as a result of, among other things:
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failure to obtain, or a decline in, oil or gas production, or a
decline in oil or gas prices,
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incorrect estimates of required capital expenditures,
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increases in the cost of drilling, completion and gas collection
or other costs of production and operations,
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an inability to meet growth projections, and
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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.
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ITEM 3.
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LEGAL
PROCEEDINGS
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On July 29, 2005, the Company filed a lawsuit in the
U.S. District Court for the Eastern District of Texas,
Beaumont Division against Samson Lone Star Limited Partnership
(Samson) and Samsons parent company, Samson
Resources Corp. The Company alleged in its complaint that
Samson, the operator of a producing gas well in Jefferson
County, Texas named the Sun Fee GU #1-ST (the Sun Fee
Well), has breached its obligations to the Company, which
owns interests in the property on which the Sun Fee Well is
located, by joining, without authorization, the Sun Fee Well
into a unit (the Sidetrack Unit) with other
properties in which the Company has no interest, many of which
are non-productive. Samson has a large interest in the
properties that Samson has joined into the unit. Pursuant to
Samsons proposed pooling configuration, the Companys
working and overriding royalty interests in the Sun Fee Well
would be reduced substantially. The Company believes that Samson
has no legal or contractual right to reduce the Companys
interests in this manner. The Company is seeking monetary
damages for all payments due and owing to the Company based on
the proper, undiluted interests in the property.
Until approximately August 1, 2005, Samson had been paying
the Company its share of oil and gas revenues based on
Samsons calculation of the Companys net revenue
interest (5.7%) in the Sun Fee Well after dilution for the
disputed pooling of the non-productive properties, when it
ceased paying the Company any portion of the production proceeds
from the Sun Fee Well. On September 13, 2005, the Court
entered a Preliminary Injunction ordering Samson to return the
Company to pay status for the amounts upon which Samson had been
paying the Company prior to the filing of the suit. On
December 23, 2005, Samson filed a motion for summary
judgment on the Companys claims, to which the Company
filed its response on January 3, 2006, rigorously denying
that Samson has grounds in law or fact for the requested relief.
Further, on January 17, 2006, Samson filed a counterclaim
for an unspecified overpayment to the Company, which was
clarified by a subsequent filing on February 14, 2006, that
it was disputing the unit interest originally attributed to the
Company and now asserting that the Companys net revenue
unit interest is approximately 4.7%. On March 28, 2006, the
Court denied a motion by Samson to modify the present injunction
to allow payment upon the lower amount. The Company has also
filed additional claims against Samson for breach of
contract or reformation of the certain assignment issued by
Samson to the Company in April 2005 upon which Samson bases its
present counterclaim. The outcome of the litigation will
determine whether PYRs ownership in the Sun Fee Well
consists of (a) the 5.7% net revenue interest (consisting
of a 5.19% working and a 1.5% overriding royalty interest) that
was formerly the portion that was not contested by Samson and
represents the amount of the payments that Samson, as operator,
has been paying PYR and that PYR has been recording in its
financial statements; or (b) the 4.7% net revenue interest
that Samson asserted in its February 14, 2006 filing; or
(c) a net revenue interest higher than 5.7% as a result of
the Companys prevailing on part or all of its claims that
it owns an 8.33% working interest as well as an overriding
royalty interest greater than 1.5%. On September 15, 2006,
the U.S. District Court for the Eastern District of Texas
issued its ruling on the outstanding motions for summary
judgment that had been filed by both PYR and Samson. In its
ruling, the Court held (1) that Samson did not have
authority to pool PYRs 3.5% overriding royalty interest in
the Sun Fee Well into the Sidetrack Unit and, therefore, that
PYR is entitled to the full, undiluted interest in all
production from the Sun Fee Well based on this overriding
royalty; and (2) that, although Samson had authority to
pool PYRs working interest into the unit, PYR would be
able to maintain its claim for breach of contract against Samson
for joining non-productive acreage into the unit. The Court also
left for trial PYRs claims that Samson had also breached
the underlying agreements by failing to assign to PYR its
working interest in all properties as called for in the
underlying contracts and by failing to give PYR geologic and
other technical information applicable to the Sun Fee Well and
the Sidetrack Unit. The Court held that PYRs alternate
claim that Samson owed PYR a fiduciary duty in forming the
Sidetrack Unit was fully resolved by its other rulings.
Following a brief scheduling conference, the Court has requested
that the parties discuss next steps, including (i) resuming the
trial schedule for the issues and claims that remain unresolved
by the Courts order, (ii) the immediate appeal on the rulings
made to date in the order and/or (iii) mediation of the issues
in dispute.
On August 11, 2006, the State District Court for Jefferson
County, Texas,
58th Judicial
District, issued a final summary judgment in the Companys
favor against Samson in Samsons suit to enjoin the
Companys drilling of the Tindall Well, located in
Jefferson County, Texas on property directly adjacent to and
east of the Sun Fee Well. As previously reported, on the grounds
that it had the exclusive right to serve as operator to drill
the proposed Tindall Well, Samson had filed suit to enjoin or
prevent the Company from drilling the planned well on the
approximately
21
400-acre
property in which the Company holds 100% of the oil and gas
interest. Upon mutual agreement of the parties, no appeal will
be taken from the final judgment.
On February 15, 2006, the Company filed a motion in the
on-going bankruptcy proceeding involving Venus Exploration
Company (Venus) in the U.S. Bankruptcy Court
for the Eastern District of Texas requesting that the Bankruptcy
Court uphold its Order of April 9, 2004 approving the
Companys purchase of Venus remaining assets free and
clear of any obligations under a pre-bankruptcy Operating
Agreement between Venus and Trail Mountain Inc. (Trail
Mountain) that required Venus and Trail Mountain to offer
each other participation in subsequently acquired oil and gas
properties. The Company believes and has asserted in its motion
that the pre-bankruptcy Operating Agreement was not listed among
the contracts that were assigned to it under the sale in and
under the approval of the Bankruptcy Court. Trail Mountain has
filed an adversary proceeding against the Company requesting
that the Bankruptcy Court find that the pre-bankruptcy Operating
Agreement was still effective and that the Company is obligated
to offer an opportunity to Trail Mountain to share in the lease
upon which the proposed Tindall well is to be drilled. If Trail
Mountain is successful, it will lead to a potential 50%
reduction in the Companys interest in the lease, but could
also lead to a corresponding assignment of interests in
properties acquired by Trail Mountain, including certain
properties assigned to the Sidetrack Unit. A ruling by the Court
should also clarify whether the parties rights to operate
their interests in the Cotton Creek Prospect are subject to an
existing operating agreement or are free to enter into a new
operating agreement. The parties have submitted the matter to
the Bankruptcy Court on motions for summary and partial summary
judgment.
The Company will continue to vigorously pursue and defend its
rights with respect to the foregoing matters.
PART II
|
|
ITEM 5.
|
MARKET
FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
|
Market
for Common Equity
Our common stock has been listed on the American Stock Exchange
under the market symbol PYR since December 8,
1999. The following table sets forth the range of high and low
sales prices per share of our common stock for the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
Fiscal Year Ended
August 31, 2005
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
1.31
|
|
|
$
|
0.90
|
|
Second Quarter
|
|
|
1.79
|
|
|
|
0.95
|
|
Third Quarter
|
|
|
1.99
|
|
|
|
1.20
|
|
Fourth Quarter
|
|
|
1.64
|
|
|
|
1.30
|
|
Fiscal Year Ended
August 31, 2006
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
2.07
|
|
|
$
|
1.00
|
|
Second Quarter
|
|
|
1.78
|
|
|
|
1.23
|
|
Third Quarter
|
|
|
1.57
|
|
|
|
1.18
|
|
Fourth Quarter
|
|
|
1.30
|
|
|
|
1.01
|
|
On November 15, 2006, the last reported sales price of our
common stock on the American Stock Exchange was $1.01 per
share.
Stockholders
of Record
As of November 15, 2006, the number of record holders of
our common stock was approximately 489.
Dividends
We have not declared or paid, and do not anticipate declaring or
paying in the near future, any dividends on our common stock.
22
Equity
Compensation Plan Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Compensation Plan Information
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available
|
|
|
|
Number of
|
|
|
|
|
|
for Future Issuance
|
|
|
|
Securities to be
|
|
|
|
|
|
under Equity
|
|
|
|
Issued Upon
|
|
|
Weighted-Average
|
|
|
Compensation Plans
|
|
|
|
Exercise of
|
|
|
Exercise Price of
|
|
|
(Excluding
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Securities
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
Reflected in
|
|
Plan Category
|
|
and Rights
|
|
|
and Rights
|
|
|
Column (a))*
|
|
|
|
(a)
|
|
|
(b)
|
|
|
(c)
|
|
|
Equity compensation plans approved
by security holders
|
|
|
2,331,750
|
|
|
$
|
1.08
|
|
|
|
4,429,250
|
|
Equity compensation plans not
approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,331,750
|
|
|
$
|
1.08
|
|
|
|
4,429,250
|
|
* At August 31, 2006
|
|
ITEM 6.
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS
|
The following discussion should be read in conjunction with the
Consolidated Financial Statements and Notes thereto referred to
in Item 8. Financial Statements and Supplemental
Data, and Items 1. and 2. Business and
Properties Disclosures Regarding Forward-Looking
Statements of this
Form 10-KSB.
Overview
We are an independent oil and gas exploration and production
company engaged in the exploration, development and acquisition
of crude oil and natural gas reserves. We intend to increase
stockholder value by profitably growing reserves and production,
primarily through drilling operations and strategic
acquisitions. 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.
In general, we are not able to commence additional exploratory
drilling operations without outside industry participation. We
have pursued, and will continue to pursue, exploration
opportunities in regions where we believe significant
opportunity for discovery of oil and gas exist. 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.
In mid-October 2005, we completed a private equity placement
consisting of the sale of 6.275 million shares of common
stock, priced at $1.30 per share, to a group of
institutional and accredited individual investors and issued
warrants to purchase 52,500 shares of common stock at a price of
$1.30 per share to a financial advisory company as partial
payment for services rendered. Proceeds from this placement of
approximately $8.0 million net of offering costs were for
general corporate purposes and costs associated with the
Companys development drilling portfolio located
principally in the Rocky Mountains and Texas.
Liquidity
and Capital Resources
Our primary sources of liquidity historically have been from
placements of common stock and convertible notes, and to a much
lesser extent, cash provided by operating activities. Our
primary use of capital has been for the acquisition,
development, and exploration of oil and natural gas properties.
As we pursue growth, we continually monitor the capital
resources available to us to meet our future financial
obligations, planned capital expenditure
23
activities and liquidity. Our future success in growing proved
reserves and production is highly dependent on capital resources
available to us and our success in finding or acquiring
additional reserves. The Company is always looking at strategic
alternatives to increase its shareholder value and is actively
looking for acquisitions
and/or
merger possibilities. At August 31, 2006, we had
approximately $5.6 million in working capital and cash of
$6.2 million.
Cash
Flows from Operating Activities
Net cash provided by operating activities was $4.4 million
in 2006 compared with $1.9 million in 2005. The increase in
net cash provided by operating activities was substantially due
to a 69% increase in production revenues offset in part by an
increase in operating expenses. See Results of
Operations for discussion of changes in revenues and
expenses. Non-cash charges increased due to higher depreciation,
depletion and amortization associated with increased production
and higher depletion rates. Changes in current assets and
liabilities decreased cash flow from operations by $815,000 in
2006 compared with an increase of $91,000 in 2005. During the
year ended August 31, 2006, we used cash to pay all net
profits due to the Venus Exploration Trust as of August 31,
2005 and for most of the net profits due for fiscal 2006. These
payments account for the primary reduction in current
liabilities and related use of cash associated with the changes
in current assets and liabilities for fiscal 2006.
Operating cash flows are impacted by many variables, the most
significant of which is the volatility of prices for natural gas
and oil produced. Prices for these commodities are determined
primarily by prevailing market conditions. Regional and
worldwide economic activity, weather and other substantially
variable factors influence market conditions for these products.
These factors are beyond our control and are difficult to
predict.
Cash
Flows used in Investing Activities
Our cash flows used in investing activities increased to
approximately $9.2 million in fiscal 2006 from
approximately $5.1 million in fiscal 2005. Investing
activities included capital expenditures for oil and gas
properties and furniture and equipment, net of proceeds from the
sale of oil and gas properties. Our capital expenditures were
approximately $9.6 million and $5.9 million in 2006
and 2005, respectively. The total for 2006 includes
$5.9 million for drilling, development, exploration and
exploitation, $1.7 million for the purchase of additional
working interest in properties located in Hansford County, Texas
and $2.0 million for leasehold costs including lease
acquisitions, delay rentals and capitalized litigation costs
incurred related to our Nome project and $29,000 for office
furniture, fixtures and equipment. In 2005, we incurred
approximately $4.3 million for drilling, development,
exploration and exploitation, $1.6 million for leasehold
expenditures and $10,000 for office furniture, fixtures and
equipment.
In 2006 and 2005, we received proceeds of approximately $398,000
from sales of our interests in acreage located in our School
Road prospect in California and acreage located in our Merganser
prospect located in Leon County, Texas and $49,000 from the sale
of a portion of our interests in prospects in Louisiana and
Texas, respectively. During 2005, we received $750,000 for
non-refundable option fees received from Suncor Energy Natural
Gas America, Inc. (SENGAI) pursuant to an
Exploration Option Agreement between the Company and SENGAI
covering our Rogers Pass exploration project in the foothills of
west-central Montana.
We currently anticipate our capital budget will be approximately
between $9.0 and $12.0 million for fiscal year 2007, which
we plan to use for a diverse portfolio of development and
exploration wells in our core areas of operation. 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 may consider selling down a portion of our interests
in some of our exploration and development projects to industry
partners to generate additional funds to finance our 2007
capital budget. We are projecting that cash on hand, cash
available from operating activities and funds from the partial
sale of our interest in some prospects will be sufficient to
fund our 2007 capital budget.
24
Cash
Flows provided by Financing Activities
Our fiscal 2006 financing activities provided cash of
approximately $8.0 million. In mid-October 2005, the
Company completed a private equity placement consisting of the
sale of 6.275 million shares of common stock, priced at
$1.30 per share, to a group of institutional and accredited
individual investors and issued warrants to purchase
52,500 shares of common stock at a price of $1.30 per
share to a financial advisory company as partial payment for
services rendered. Proceeds from this placement of approximately
$8.0 million net of offering costs were used for general
corporate purposes and costs associated with the Companys
development drilling portfolio located principally in the Rocky
Mountains and Texas.
It is anticipated that the continuation and future development
of our business will require additional, and possibly
substantial, capital expenditures. We have no reliable source
for additional funds for administration and operations to the
extent our existing funds have been utilized. In addition, our
capital expenditure budget for the fiscal year ending
August 31, 2007 will depend on our success in selling
additional prospects for cash, the level of industry
participation in our exploration projects, the availability of
debt or equity financing, and the results of our activities. We
anticipate spending approximately between $9.0 and
$12.0 million on exploration and development activities
during our fiscal year ending August 31, 2007. To limit
capital expenditures, we intend to form industry alliances and
exchange an appropriate portion of our interest for cash
and/or a
carried interest in our exploration projects. We may need to
raise additional funds to cover capital expenditures. These
funds may come from cash flow, equity or debt financings, a
credit facility, or sales of interests in our properties,
although there is no assurance additional funding will be
available or that it will be available on satisfactory terms.
Contractual
Obligations
The following table summarizes the Companys obligations
and commitments, as of August 31, 2006, to make future
payments under its convertible notes payable and office lease
for the periods specified (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by Period
|
|
Contractual Obligations
|
|
Total
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Convertible Notes
|
|
$
|
8,474
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8,474
|
|
Office Leases
|
|
|
93
|
|
|
|
70
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Cash Obligations
|
|
$
|
8,567
|
|
|
$
|
70
|
|
|
$
|
23
|
|
|
$
|
8,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above schedule assumes convertible note interest payments
will be added to the principal amount (which is at the
discretion of the Company), and the entire balance will be paid
in full on maturity of May 24, 2009, and there will be no
conversion of debt to common stock. In addition to the above
obligations, if we elect to continue holding all our existing
leases on a delayed rental basis, we would have to pay
approximately $96,000 during the year ending August 31,
2007. The Company considers on a quarterly basis whether to
continue holding all or part of each acreage block by making
delay rental payments on existing leases.
25
Results
of Operations
The
twelve months ended August 31, 2006 (2006)
compared with the twelve months ended August 31, 2005
(2005)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
2006
|
|
|
2005
|
|
|
Amount
|
|
|
Percent
|
|
|
|
($ in thousands, except for per unit prices and costs)
|
|
|
Operating Results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas production revenues
|
|
$
|
6,706
|
|
|
$
|
2,957
|
|
|
$
|
3,749
|
|
|
|
127
|
%
|
Oil production revenues
|
|
|
3,371
|
|
|
|
3,135
|
|
|
|
236
|
|
|
|
8
|
%
|
Natural gas liquids revenues
|
|
|
184
|
|
|
|
10
|
|
|
|
174
|
|
|
|
1740
|
%
|
Other products
|
|
|
58
|
|
|
|
0
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
10,319
|
|
|
$
|
6,102
|
|
|
$
|
4,217
|
|
|
|
69
|
%
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
1,547
|
|
|
$
|
721
|
|
|
$
|
826
|
|
|
|
115
|
%
|
Production taxes, gathering and
transportation expense
|
|
|
689
|
|
|
|
383
|
|
|
|
306
|
|
|
|
80
|
%
|
Net profits expense
|
|
|
829
|
|
|
|
1,343
|
|
|
|
(514
|
)
|
|
|
(38
|
)%
|
Depletion, depreciation,
amortization and accretion
|
|
|
2,616
|
|
|
|
893
|
|
|
|
1,723
|
|
|
|
193
|
%
|
Impairment of oil and gas
properties
|
|
|
0
|
|
|
|
580
|
|
|
|
(580
|
)
|
|
|
(100
|
)%
|
General and administrative
|
|
|
2,256
|
|
|
|
1,909
|
|
|
|
347
|
|
|
|
18
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
$
|
7,937
|
|
|
$
|
5,829
|
|
|
$
|
2,108
|
|
|
|
36
|
%
|
Interest Expense
|
|
$
|
371
|
|
|
$
|
343
|
|
|
$
|
28
|
|
|
|
8
|
%
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf)
|
|
|
915,973
|
|
|
|
392,067
|
|
|
|
523,906
|
|
|
|
134
|
%
|
Oil (Bbls)
|
|
|
53,049
|
|
|
|
61,948
|
|
|
|
(8,899
|
)
|
|
|
(14
|
)%
|
Natural gas liquids (Bbls)
|
|
|
5,267
|
|
|
|
336
|
|
|
|
4,931
|
|
|
|
1468
|
%
|
Combined volumes (Mcfe)
|
|
|
1,265,869
|
|
|
|
765,771
|
|
|
|
500,098
|
|
|
|
65
|
%
|
Daily combined volumes (Mcfe/d)
|
|
|
3,468
|
|
|
|
2,098
|
|
|
|
1,370
|
|
|
|
65
|
%
|
Average Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.32
|
|
|
$
|
7.54
|
|
|
$
|
(0.22
|
)
|
|
|
(3
|
)%
|
Oil (per Bbl)
|
|
|
63.55
|
|
|
|
50.04
|
|
|
|
13.51
|
|
|
|
27
|
%
|
Natural gas liquids (per Bbl)
|
|
|
34.83
|
|
|
|
29.53
|
|
|
|
5.30
|
|
|
|
18
|
%
|
Combined (per Mcfe)
|
|
|
8.15
|
|
|
|
7.96
|
|
|
|
0.19
|
|
|
|
2
|
%
|
Average Costs (per
Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
1.22
|
|
|
$
|
0.94
|
|
|
$
|
0.28
|
|
|
|
30
|
%
|
Production taxes, gathering and
transportation expense
|
|
|
0.54
|
|
|
|
0.50
|
|
|
|
0.04
|
|
|
|
8
|
%
|
Net profit expense
|
|
|
0.65
|
|
|
|
1.75
|
|
|
|
(1.10
|
)
|
|
|
(63
|
)%
|
Depletion, depreciation,
amortization and accretion
|
|
|
2.05
|
|
|
|
1.13
|
|
|
|
0.92
|
|
|
|
81
|
%
|
General and administrative
|
|
|
1.78
|
|
|
|
2.49
|
|
|
|
(0.71
|
)
|
|
|
(28
|
)%
|
Interest expense
|
|
|
0.29
|
|
|
|
0.45
|
|
|
|
(0.16
|
)
|
|
|
(36
|
)%
|
Operations during the fiscal year ended August 31, 2006
resulted in net income of approximately $2.3 million
compared to net income of approximately $12,000 for the fiscal
year ended August 31, 2005. The increase is attributed
primarily to the increase in revenue relative to expense
described below.
Oil and Gas Revenues. Oil and gas revenues
increased by approximately $4.2 million, or 69%, to
approximately $10.3 million in 2006 from approximately
$6.1 million in 2005, of which 83% of the increase is
attributed to a 65% increase in production volumes and 17% is
attributed to a 3% increase in average price per Mcfe. The
natural gas production increase of 523,906 Mcf is
attributed to production from the new wells drilled and
completed during 2006 , particularly the Scharff wells in
Oklahoma, the Lackey Gas Unit #2 well in Texas and
the #1-30 Duck Federal
26
well in Wyoming and additional production received from the
purchased interest in the Hansford producing wells in Texas.
During 2006, average natural gas prices declined by
approximately 3%. Average oil prices increased by approximately
27%, and were offset, in part, by a 14% decline in production.
An increase in natural gas liquids (NGLs) production of
4,931 Bbls is attributed to new production from
the #1-30 Duck Federal well located in Wyoming. Average NGL
prices increased by 18% to $34.83 per Bbl.
During 2005, the Company commenced receiving its net revenue
interest proceeds from the Sun Fee GU #1-ST well and the
Maness #1 well, located in Texas, after the wells had
reached payout during the fiscal year 2005. The oil and gas
revenues from these wells approximate 28% and 55% of total oil
and gas revenues for 2006 and 2005, respectively. Revenues from
these wells are subject to a 50% net profits expense.
Lease Operating Expenses. Lease operating
expenses increased from $721,000 in 2005 to $1.547 million
in 2006. The increase is attributed to the workover on the
Maness GU #1 well, new wells added, and additional
operating costs associated with purchased interests in existing
wells. Excluding the workover costs incurred in 2006, lease
operating costs on a per unit of production basis was
$0.96 per Mcfe in 2006 as compared to $0.94 per Mcfe
in 2005. The 2006 workover costs on the Maness
GU #1 well cost approximately $323,000, or
$0.26 per Mcfe.
Production Taxes, Gathering and Transportation
Expenses. Production taxes as a percentage of
natural gas and oil revenues averaged 5.9% for both 2006 and
2005. Production taxes are primarily based on revenues from
production sold and rates vary across the different areas that
our wells are located. Accordingly, fluctuations in production
taxes are directly associated with fluctuations in revenues.
Production taxes for 2006 increased approximately 68% over 2005.
Gathering, transportation and other sales expenses increased by
$62,000 from 2005.
Net Profits Expense. The net profits interest
agreement with Venus Exploration Trust (Trust) arose
out of an acquisition of properties from Venus Exploration Inc.
(Venus) in May 2004. The amount of the Trusts net
profits interest is either 25% or 50% with respect to different
Venus exploration and exploitation project areas, and decreases
by one-half of its original amount after an aggregate total of
$3.3 million in net profits. The 38% decrease in net
profits expense from 2005 to 2006 resulted from additional costs
incurred, a workover on the Maness well which also caused the
well to be shut-in for several months and capital expenditures
for drilling the Wall #1 well and the
Nome-Long #1 well which have not been fully offset
from current operating profits on the wells subject to the net
profits obligation and will reduce any future net profits
obligation until fully offset.
Depreciation, Depletion, Amortization and Accretion
Expense. Depreciation, depletion, amortization
and accretion expense increased by $1.723 million to
$2.616 million in 2006 from $893,000 in 2005. The increase
was primarily attributable to depletion expense which increased
by $1.719 million from $861,000 in 2005 to
$2.580 million in 2006. The depletion expense increase is
the result of a 64% increase in production volumes and an
increase in the average depletion rate from $1.12 per Mcfe
to $2.038 per Mcfe. The rate increase is attributed
primarily to the inclusion of costs of certain impaired
unevaluated properties in the amortizable base of the full cost
pool and additional costs, principally capitalized legal costs
associated with the Nome prospect, for which no additional
reserves have been added. Under the full cost pool method of
accounting, impairment costs of unevaluated properties,
previously excluded from the amortizable base of the depletable
full cost pool, are added to the full cost pool depletable base
resulting in an increase in the depletion rate. We recorded
$14,000 and $8,000 in depreciation expense associated with
capitalized office furniture and equipment during 2006 and 2005,
respectively. We recorded $22,000 and $25,000, respectively, for
2006 and 2005, of accretion of the unamortized discount of the
Asset Retirement Obligation liability. For further discussion of
the Asset Retirement Obligation, see Note 4 to the
Financial Statements included in this
Form 10-KSB.
Impairment and Abandonments. No impairment
expense was recorded for 2006. In 2005, we recognized a non-cash
impairment expense of $580,000 associated with the
Companys investment in its Canadian properties.
General and Administrative Expenses. General
and administrative expenses in 2006 increased by $347,000, or
18%, from 2005. The increase is due principally to increased
Board of Director fees and bonuses resulting from increased
meetings, and increased franchise taxes, specifically in Texas,
resulting from higher revenues. In September 2006, the
Compensation Committee awarded a non-employee director bonus of
$25,000 to each of the three non-employee directors for the
extraordinary amount of time and effort expended by the
non-employee directors during fiscal 2006. In addition, the
Compensation Committee revised non-employee director meeting
27
compensation and annual retainer policies. The additional 2006
costs associated with the recognition of the bonuses and the
revised compensation and annual retainer policies were recorded
in the fourth quarter 2006, which resulted in higher costs for
the fourth quarter as compared to previous quarters for 2006.
Based on a per unit of production basis, general and
administrative costs decreased from $9.19 per Mcfe in 2005
to $2.49 per Mcfe in 2006 due to higher production volumes.
Interest Expense. During 2006 and 2005, we
recorded interest expense of $371,000 and $343,000,
respectively. The interest expense, principally associated with
the Companys convertible notes due May 24, 2009,
increased due to an increase in convertible note principal
balances (resulting from adding previously accrued interest to
the principal). The Company elected to pay accrued interest on
the convertible notes of approximately $352,000 and $335,000 for
2006 and 2005, respectively, by increasing the outstanding
balance of the Convertible Notes.
Interest Income. We recorded $245,000 and
$93,000 in interest income for 2006 and 2005, respectively.
Interest income increased in 2006 due to higher average cash
balances resulting principally from proceeds received from a
private placement of our common stock in October 2005.
The
twelve months ended August 31, 2005 (2005)
compared with the twelve months ended August 31, 2004
(2004)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
2005
|
|
|
2004
|
|
|
Amount
|
|
|
Percent
|
|
|
|
($ in thousands, except for per unit prices and costs)
|
|
|
Operating Results:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas production revenues
|
|
$
|
2,957
|
|
|
$
|
334
|
|
|
$
|
2,623
|
|
|
|
785
|
%
|
Oil production & PP
revenues
|
|
|
3,145
|
|
|
|
529
|
|
|
|
2,616
|
|
|
|
495
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
6,102
|
|
|
$
|
863
|
|
|
$
|
5,239
|
|
|
|
607
|
%
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense (including
production taxes, gathering, transportation)
|
|
$
|
1,104
|
|
|
$
|
335
|
|
|
$
|
769
|
|
|
|
229
|
%
|
Net profits expense
|
|
|
1,343
|
|
|
|
0
|
|
|
|
1,343
|
|
|
|
|
|
Depletion, depreciation,
amortization and accretion
|
|
|
893
|
|
|
|
273
|
|
|
|
620
|
|
|
|
227
|
%
|
Impairment of oil and gas
properties
|
|
|
580
|
|
|
|
0
|
|
|
|
580
|
|
|
|
|
|
General and administrative
|
|
|
1,909
|
|
|
|
1,324
|
|
|
|
585
|
|
|
|
44
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
$
|
5,829
|
|
|
$
|
1,933
|
|
|
$
|
3,896
|
|
|
|
202
|
%
|
Interest expense
|
|
$
|
343
|
|
|
$
|
327
|
|
|
$
|
16
|
|
|
|
5
|
%
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf)
|
|
|
392,067
|
|
|
|
60,285
|
|
|
|
331,782
|
|
|
|
551
|
%
|
Oil and NGLs (Bbls)
|
|
|
62,284
|
|
|
|
13,973
|
|
|
|
48,311
|
|
|
|
346
|
%
|
Combined volumes (Mcfe)
|
|
|
765,771
|
|
|
|
144,123
|
|
|
|
621,648
|
|
|
|
432
|
%
|
Daily combined volumes (Mcfe/d)
|
|
|
2,098
|
|
|
|
395
|
|
|
|
1703
|
|
|
|
431
|
%
|
Average Prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.54
|
|
|
$
|
5.54
|
|
|
$
|
2.00
|
|
|
|
36
|
%
|
Oil and NGLs (per Bbl)
|
|
|
50.49
|
|
|
|
37.88
|
|
|
|
12.61
|
|
|
|
33
|
%
|
Combined (per Mcfe)
|
|
|
7.97
|
|
|
|
5.99
|
|
|
|
1.98
|
|
|
|
33
|
%
|
Average Costs (per
Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
1.44
|
|
|
$
|
2.33
|
|
|
$
|
(0.89
|
)
|
|
|
(38
|
%)
|
Net profit expense
|
|
|
1.75
|
|
|
|
0.00
|
|
|
|
1.75
|
|
|
|
|
|
Depletion, depreciation,
amortization and accretion
|
|
|
1.13
|
|
|
|
1.20
|
|
|
|
(0.07
|
)
|
|
|
(6
|
%)
|
General and administrative
|
|
|
2.49
|
|
|
|
9.19
|
|
|
|
(6.70
|
)
|
|
|
(73
|
%)
|
Interest expense
|
|
|
0.45
|
|
|
|
2.27
|
|
|
|
(1.82
|
)
|
|
|
(80
|
%)
|
28
Operations during the fiscal year ended August 31, 2005
resulted in net income of approximately $12,000 compared to a
net loss of approximately $1.4 million for the fiscal year
ended August 31, 2004. The increase in net income is
primarily attributed to income from the producing properties
purchased from Venus in May 2004.
Oil and Gas Revenues. During the year ended
August 31, 2005, we recorded approximately
$6.1 million in total oil and gas revenues compared with
approximately $863,000 for the same period in 2004. Natural gas
revenues increased to $3.0 million from the sale of
392,067 Mcf of natural gas at an average price of
$7.54 per Mcf in 2005 compared with revenues of $334,000
from the sale of 60,285 Mcf of natural gas at an average
price of $5.54 per Mcf in 2004. Average natural gas prices
for 2005 increased 36% over 2004 average prices. Oil and
hydrocarbon liquids revenues for 2005 and 2004 were
$3.1 million and $529,000, respectively, from the sale of
62,284 and 13,973 Bbls of oil and hydrocarbon liquids,
respectively. Average oil prices increased 33% from $37.88 in
2004 to $50.49 in 2005. The increase in oil and gas revenues and
production is principally attributed to new revenues and
production from two wells that reached payout during 2005,
increased prices and a full year of revenue and production from
properties acquired from Venus in May 2004 compared with only
four months of revenue and production from the same properties
in 2004. During 2005, the Company commenced receiving its net
revenue interest proceeds from the Sun Fee GU #1-ST well
and the Maness #1 well, located in Texas, after the
wells reached payout during the fiscal year 2005. The oil and
gas revenues from these wells approximate 55% of total oil and
gas revenues for 2005. Revenues from these wells are subject to
a net profits expense.
Lease Operating Expenses. Lease operating
expenses increased from $335,000 in 2004 to approximately
$1.1 million in 2005. The increase is attributed to new
wells added and a full year of lease operating expenses on
properties acquired from Venus compared with only four months in
2004.
Net Profits Expense. During 2005, two wells,
the Sun Fee GU #1-ST and the Maness #1, reached payout
and we commenced receiving revenues and incurring operating
expenses on these wells. These wells are subject to a net
profits expense of 50% of revenues net of capital and operating
expenses incurred.
Depreciation, Depletion, Amortization and
Accretion. Depreciation, depletion and
amortization expense increased to $894,000 in 2005 from $273,000
in 2004. The increase was primarily attributable to depletion
expense of $860,000 associated with increased production volumes
from properties acquired from Venus in May 2004. We recorded
$8,000 and $13,000 in depreciation expense associated with
capitalized office furniture and equipment during 2005 and 2004,
respectively. Depreciation of Asset Retirement Obligation assets
for the years ended August 31, 2005 and 2004 was $0 and
$114,000, respectively. We recorded $25,000 and $100,000,
respectively, for the years ended August 31, 2005 and
August 31, 2004, of accretion of the unamortized discount
of the Asset Retirement Obligation liability. The accretion
expense for 2004 was attributable to the properties acquired
from Venus in May 2004. For further discussion of the Asset
Retirement Obligation, see Note 4 to the Financial
Statements included in this
Form 10-KSB.
Impairment and Abandonments. We recognized a
non-cash impairment expense of $580,000 associated with the
Companys investment in its Canadian properties. We
recorded no impairment expense for the year ended
August 31, 2004
General and Administrative Expenses. General
and administrative expenses in 2005 were approximately
$1.9 million compared to approximately $1.3 million in
2004. The 44% increase is due principally to higher personnel
costs, legal and auditing expenses and contract services. The
addition of staff and related general and administrative
expenses to manage the Venus properties acquired in May 2004 was
the primary factor contributing to the increases.
Interest Expense. During 2005, we recorded
interest expense of $343,000 compared to $327,000 in 2004. The
interest expense for each year is associated with the
May 24, 2002 sale of outstanding convertible notes due on
May 24, 2009. The Company elected to add $335,000 and
$319,000 of accrued interest to the balance of the debt for the
years ended August 31, 2005 and August 31, 2004,
respectively. We have reflected the outstanding balance of these
notes as Convertible Notes under Long Term Debt on our
August 31, 2005 and 2004 balance sheets.
Interest Income. We recorded $93,000 and
$28,000 in interest income for the years ended August 31,
2005 and 2004, respectively. Interest income increased in 2005
due to higher average cash balances for the majority of 2005 due
principally to funds received from a private placement of our
common stock in May 2004.
29
Critical
Accounting Policies And Estimates
We believe the following critical accounting policies affect our
more significant judgments and estimates used in the preparation
of our Financial Statements.
Reserve
Estimates:
Our estimates of oil and natural gas reserves, by necessity, are
projections based on geological and engineering data, and there
are uncertainties inherent in the interpretation of such data as
well as the projection of future rates of production and the
timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of
oil and natural gas that are difficult to measure. The accuracy
of any reserve estimate is a function of the quality of
available data, engineering and geological interpretation and
judgment. Estimates of economically recoverable oil and natural
gas reserves and future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical
production from the area compared with production from other
producing areas, the assumed effects of regulations by
governmental agencies and assumptions governing future oil and
natural gas prices, future operating costs, severance and excise
taxes, development costs and workover and remedial costs, all of
which may in fact vary considerably from actual results. For
these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular
group of properties, classifications of such reserves based on
risk of recovery, and estimates of the future net cash flows
expected from there may vary substantially. Any significant
variance in the assumptions could materially affect the
estimated quantity and value of the reserves, which could affect
the carrying value of our oil and gas properties
and/or the
rate of depletion of the oil and gas properties. Actual
production, revenues and expenditures with respect to our
reserves will likely vary from estimates, and such variances may
be material.
Many factors will affect actual net cash flows, including the
following: the amount and timing of actual production; supply
and demand for natural gas; curtailments or increases in
consumption by natural gas purchasers; and changes in
governmental regulations or taxation.
Property,
Equipment and Depreciation:
We follow the full cost method to account for our oil and gas
exploration and development activities. Under the full cost
method, all costs incurred which are directly related to oil and
gas exploration and development are capitalized and subjected to
depreciation and depletion. Depletable costs also include
estimates of future development costs of proved reserves. Costs
related to undeveloped oil and gas properties may be excluded
from depletable costs until those properties are evaluated as
either proved or unproved. The net capitalized costs are subject
to a ceiling limitation based on the estimated present value of
discounted future net cash flows from proved reserves. As a
result, we are required to estimate our proved reserves at the
end of each quarter, which is subject to the uncertainties
described in the previous section. Gains or losses upon
disposition of oil and gas properties are treated as adjustments
to capitalized costs, unless the disposition represents a
significant portion of the Companys proved reserves.
Revenue
Recognition:
The Company recognizes oil and gas revenues from its interests
in producing wells as oil and gas is produced and sold from
these wells. The Company uses the sales method to account for
gas imbalances. Oil and gas sold is not significantly different
from the Companys product entitlement. Gas imbalances at
August 31, 2006 and 2005 were not significant.
Recent
Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board
(FSAB) issued its final standard on accounting for
employee stock options, SFAS No. 123 (Revised 2004),
Share-Based Payment (SFAS 123 (R)).
SFAS 123 (R) replaces SFAS No. 123, Accounting
for Stock-Based Compensation (SFAS 123), and supersedes
APB 25, Accounting for Stock Issued to Employees.
SFAS 123 (R) requires companies to measure compensation
costs for all share-based payments, including grants of employee
stock options, based on the fair value of the awards on the
grant date and to recognize such expense over the period during
which an employee is required to provide services in exchange
for the
30
award. The pro forma disclosures previously permitted under
SFAS 123 will no longer be an alternative to financial
statement recognition. For entities that file as a small
business issuer, such as PYR Energy Corporation, SFAS 123
(R) is effective for all awards granted, modified, repurchased
or cancelled after, and to unvested portions of previously
issued and outstanding awards vesting for annual periods
beginning after December 15, 2005, which for us will be the
first quarter of fiscal 2007. We are currently evaluating the
effect of adopting SFAS 123 (R) on our financial position
and results of operations. We currently estimate the adoption of
SFAS 123 (R) will result in expenses in amounts that are
similar to the current pro forma disclosures under SFAS 123.
In March 2005, the FASB issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations
(FIN 47). FIN 47 clarifies that the
term conditional asset retirement obligation, as
used in SFAS 143, Accounting for Asset Retirement
Obligations, refers to a legal obligation to perform an
asset retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity. However, the
obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing or
method of settlement. FIN 47 requires that the uncertainty
about the timing or method of settlement of a conditional asset
retirement obligation be factored into the measurement of the
liability when sufficient information exists. FIN 47 also
clarifies when an entity would have sufficient information to
reasonably estimate the fair value of an asset retirement
obligation. The adoption of FIN 47 had no effect on our
financial position or results of operations for the fiscal year
ended August 31, 2006.
On July 13, 2006, the FASB released Interpretation
No. 48, Accounting for Uncertainty in Income
Taxes an Interpretation of FASB Statement 109
(FIN 48). FIN 48 requires companies to
evaluate and disclose material uncertain tax positions it has
taken with various taxing jurisdictions. We are currently
reviewing and evaluating the effect, if any, of adopting
FIN 48 on our financial position and results of operations.
We will be required to adopt FIN 48 for our fiscal year
ended August 31, 2008.
|
|
ITEM 7.
|
FINANCIAL
STATEMENTS
|
The Consolidated Financial Statements and schedules that
constitute Item 7 are attached at the end of this Annual
Report on
Form 10-KSB.
An index to these Financial Statements and schedules is also
included in Item 14(a) of this Annual Report on
Form 10-KSB.
|
|
ITEM 8.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
|
None.
|
|
ITEM 8A.
|
CONTROLS
AND PROCEDURES
|
As of the end of the period covered by this report, the Company
conducted an evaluation of the Companys disclosure
controls and procedures (as defined in
Rules 13a-15(e)
under the Securities Exchange Act of 1934 (the Exchange
Act)). Based on this evaluation, the Company concluded
that, subject to the limitations described below, the
Companys disclosure controls and procedures are effective
to ensure that information required to be disclosed by the
Company in annual reports that it files under the Exchange Act
is recorded, processed, summarized, and reported within the time
periods specified in Securities and Exchange Commission rules
and forms. There was no change in the Companys internal
controls over financial reporting during the Companys most
recently completed fiscal quarter that has materially affected,
or is reasonably likely to materially affect, the Companys
internal control over financial reporting period.
|
|
ITEM 8B.
|
OTHER
INFORMATION
|
Not applicable.
31
PART III
|
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ITEM 9.
|
DIRECTORS,
EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE
ACT
|
The directors and executive officers of the Company, their
respective positions and ages, and the year in which each
director was first elected, are set forth in the following
table. Each director has been elected to hold office until the
next annual meeting of stockholders and thereafter until his
successor is elected and has qualified. Additional information
concerning each of these individuals follows the table.
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Director
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Name
|
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Age
|
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Position with the Company
|
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Since
|
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Kenneth R Berry, Jr.
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54
|
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Chief Executive Officer and
President
|
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David Kilpatrick
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56
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Chairman of the Board
|
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2002
|
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Bryce W. Rhodes
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53
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Director
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1999
|
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Dennis M. Swenson
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71
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Director
|
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2004
|
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Jane M. Richards
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58
|
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Chief Financial Officer
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Tucker L. Franciscus
|
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38
|
|
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Vice President of Strategic
Development and Corporate Secretary
|
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|
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|
Kenneth R. Berry, Jr. has served as our Chief
Executive Officer since July 25, 2006. Previously he served
as Vice President of land since August 1999, and Corporate
Secretary since November 2005. From October 1997 to August 1999,
Mr. Berry served as our land manager. In addition to his
duties as Chief Executive Officer, Mr. Berry is responsible
for the management of all land issues including leasing and
permitting. Prior to joining the Company, Mr. Berry served
as the managing land consultant for Swift Energy Company in the
Rocky Mountain region. Mr. Berry began his career in the
land department with Tenneco Oil Company after earning a B.A.
degree in Petroleum Land Management at the University of
Texas Austin.
David B. Kilpatrick has been a Director of the Company
since June, 2002 and was appointed as Chairman of the Board in
November 2005. He also serves on the Compensation Committee and
Audit Committee of the Company. Mr. Kilpatrick is currently
President of Kilpatrick Energy Group, which provides strategic
management consulting services to the oil and gas industry. He
currently serves as a Director of the publicly traded Cheniere
Energy and Whittier Energy companies as well as privately held
Ensyn Petroleum International, Ltd. Prior to the 1998 merger
with Texaco, he was President and Chief Operating Officer of
Monterey Resources, Inc., the largest independent oil and gas
producer in California. Mr. Kilpatrick has served as
President of the California Independent Petroleum Association
and is a member of its Board of Directors and also serves as a
Director of the Independent Oil Producers Agency. He earned a
Bachelor of Science degree in Petroleum Engineering from the
University of Southern California and a Bachelors Degree
in Geology and Physics from Whittier College.
Bryce W. Rhodes has been a Director of the Company since
April 1999, when he was nominated and elected to the Board in
connection with the sale by the Company of convertible
promissory notes issued in a private placement transaction in
October and November 1998 and serves as the Compensation
Committee Chairman and is a member of the Audit Committee. From
1996 until September 2003, Mr. Rhodes served as President
and CEO of Whittier Energy Company (WEC), an oil and
gas investment company. In September 2003, WEC merged with
Olympic Resources, Inc. and Mr. Rhodes was appointed as
President and Chief Executive Officer. Mr. Rhodes served as
Investment Manager of WEC from 1990 until 1996. Mr. Rhodes
received B.A. degrees in Geology and Biology from the University
of California, Santa Cruz, in 1976 and an MBA degree from
Stanford University in 1979.
Dennis M. Swenson joined as a Director in October 2004,
and serves as the Audit Committee Chairman and a member of the
Compensation Committee. From 1992 through 1995, Mr. Swenson
was an independent consultant. Mr. Swenson was Executive
Vice President, Chief Financial Officer, Secretary and
Treasurer, of StarTek, Inc., a NYSE traded company with
headquarters in Denver, Colorado, from 1996 through retirement
in 2001. Mr. Swenson was employed at Ernst & Young
in Denver from 1960 to 1973, and was a partner at
Ernst & Young from 1973 to
32
1991. He has a Bachelors Degree in Accounting from Brigham
Young University and an MBA Degree from the University of Denver.
Jane M. Richards has served as Chief Financial Officer
since July 2006 and as Controller and Chief Accounting Officer
since April 2005. Ms. Richards responsibilities
include managing the financial reporting for the Company,
internal controls and cash management. Ms. Richards has
managed financial and accounting reporting in the oil and gas
exploration industry for over 20 years. Prior to joining
PYR, Ms. Richards served in various financial management
positions for Tipperary Corporation, Williams Companies and
Barrett Resources Corporation. Mrs. Richards received a
B.A. degree in Accounting from the Daniels College of Business
at the University of Denver.
Tucker L. Franciscus, Vice President of Strategic
Development, joined PYR in September 2004. Prior to joining the
Company, Mr. Franciscus was with Stifel Nicolaus &
Company, where he oversaw their Investment Banking Energy Group
practice between 2001 and 2004. Mr. Franciscus was
responsible for mergers and acquisitions, equity and debt
offerings, and private placements for all of Stifels
energy clients. Prior to working at Stifel, Mr. Franciscus
was the senior associate and manager for the Global Energy Group
at J.P. Morgan in New York and an associate in the Deutsche
Banc BT Wolfensohn Mergers & Acquisitions Group.
Mr. Franciscus has executed equity, debt, mergers and
acquisitions and other financing transactions in various
industries including defense, energy, media and telecom. For
five years preceding his banking experience, Mr. Franciscus
worked in various marketing and finance positions in the oil and
gas sector, including Synder Oil and KN Energy
(Interenergy). Additionally, he was a commissioned Infantry
Officer in the U.S. Army and continues to serve in the
reserves. During the 2006 fiscal year, he was recalled to active
duty for three months. Mr. Franciscus has an MBA from the
Daniels College of Business at the University of Denver and a
Bachelor of Arts from Ohio Wesleyan University.
Section 16(a)
Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as
amended (the Exchange Act), requires the
Companys directors, executive officers and holders of more
than 10% of the Companys 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. Except as set forth below, the
Company believes that during the year ended August 31,
2006, its officers, directors and holders of more than 10% of
the Companys common stock complied with all
Section 16(a) filing requirements. In making these
statements, the Company has relied solely upon its review of
copies of the Section 16(a) reports filed for the fiscal
year ended August 31, 2006 on behalf of the Companys
directors, officers and holders of more than 10% of the
Companys common stock. Based upon this review, Mr.
Franciscus and Messrs. Berry and Singdahlsen inadvertently filed
his Form 4 delinquently on March 15, 2006 relating to
his receipt of 25,000 options to purchase shares of common stock
granted on November 2, 2005 and November 23, 2005,
respectively. In addition, each of Messrs. Kilpatrick, Rhodes
and Swenson inadvertently filed his Form 4 delinquently on
March 30, 2006 relating to his receipt of 15,000 options to
purchase shares of our common stock granted on November 23,
2005.
Employee
Code of Conduct and Code of Ethics and Reporting of Accounting
Concerns
The Company has adopted an Employee Code of Conduct (the
Code of Conduct). We require all employees to adhere
to the Code of Conduct in addressing legal and ethical issues
encountered in conducting their work. The Code of Conduct
requires that our employees avoid conflicts of interest, comply
with all laws and other legal requirements, conduct business in
an honest and ethical manner and otherwise act with integrity
and in the Companys best interest.
The Company also has adopted a Code of Ethics for our Chief
Executive Officer, our Chief Financial Officer, our Controller
and all other financial officers and executives. This Code of
Ethics supplements our Code of Conduct and is intended to
promote honest and ethical conduct, full and accurate reporting,
and compliance with laws as well as other matters. The Code of
Conduct and Code of Ethics are filed with the SEC.
Further, the Audit Committee of the Board of Directors has
established whistle-blower procedures, which provide
a process for the confidential and anonymous submission,
receipt, retention and treatment of complaints
33
regarding accounting, internal accounting controls or auditing
matters. These procedures provide substantial protections to
employees who report company misconduct.
Audit
Committee Financial Expert
The Companys Board of Directors has determined that
Mr. Dennis M. Swenson is the Companys audit committee
financial expert.
Identification
of Audit Committee
The Board of Directors currently has an Audit Committee
consisting of Messrs. Swenson (Chairman), Kilpatrick and
Rhodes. The Audit Committee is responsible for the selection and
retention of our independent auditors, reviews the scope of the
audit functions of the independent auditor, and reviews audit
reports rendered by our independent auditors. The Audit
Committee oversees the Companys financial reporting
process on behalf of the Board of Directors. Management has the
primary responsibility for the financial statements, accounting
policies and procedures, and the reporting process, including
the systems of internal controls. In fulfilling its oversight
responsibilities, the Committee reviewed and discussed with
management the audited financial statements in this Annual
Report on
Form 10-KSB
for the year ended August 31, 2006 and the unaudited
financial statements included in the Quarterly Reports on
Form 10-Q
for the first three quarters of the fiscal year ended
August 31, 2006.
|
|
ITEM 10.
|
EXECUTIVE
COMPENSATION
|
Summary
Compensation Table
The following table sets forth the compensation for the fiscal
years ended August 31, 2006, 2005 and 2004 of our Chief
Executive Officer, Chief Financial Officer and Vice President,
our most highly compensated officers serving as of
August 31, 2006.
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Summary Compensation Table
|
|
|
|
Annual Compensation
|
|
|
Long-Term Compensation
|
|
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|
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|
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|
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Awards
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|
|
Payouts
|
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|
|
|
|
|
|
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|
|
|
|
|
|
|
Other Annual
|
|
|
Restricted
|
|
|
Securities
|
|
|
LTIP
|
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|
All Other
|
|
|
|
Fiscal
|
|
|
Salary
|
|
|
Bonus
|
|
|
Compensation
|
|
|
Stock
|
|
|
Underlying
|
|
|
Payouts
|
|
|
Compensation
|
|
Name and Principal Position
|
|
Year
|
|
|
($)(1)
|
|
|
($)
|
|
|
($)(3)
|
|
|
Awards ($)
|
|
|
Options (#)
|
|
|
($)(3)
|
|
|
($)
|
|
|
Kenneth R. Berry Jr.
|
|
|
2006
|
|
|
$
|
121,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
175,000
|
|
|
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|
|
|
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|
Chief Executive Officer
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|
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2005
|
|
|
$
|
108,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
$
|
93,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
135,000
|
|
|
|
|
|
|
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Jane M. Richards
|
|
|
2006
|
|
|
$
|
104,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85,000
|
|
|
|
|
|
|
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Chief Financial Officer
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|
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2005
|
|
|
$
|
38,000
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
90,000
|
|
|
|
|
|
|
|
|
|
|
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tucker L. Franciscus
|
|
|
2006
|
|
|
$
|
89,000
|
|
|
|
|
|
|
|
|
|
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25,000
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|
|
|
|
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|
Vice President
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2005
|
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$
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120,000
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150,000
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|
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|
2004
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|
|
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D. Scott Singdahlsen(4)
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|
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2006
|
|
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$
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175,000
|
|
|
|
|
|
|
|
|
|
|
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25,000
|
|
|
|
|
|
|
|
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|
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2005
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|
$
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175,000
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|
|
|
|
|
|
|
|
|
|
|
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200,000
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|
|
|
|
|
|
|
|
|
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|
|
2004
|
|
|
$
|
175,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The dollar value of base salary (cash and non-cash) received
during the year indicated. |
|
(2) |
|
During the period covered by the Summary Compensation Table, we
did not pay any other annual compensation not properly
categorized as salary or bonus, including perquisites and other
personal benefits, securities or property. |
|
(3) |
|
We do not have in effect any plan that is intended to serve as
incentive for performance to occur over a period longer than one
fiscal year except for our 1997 and 2000 Stock Option Plans and
our 2006 Stock Incentive Plan. |
|
(4) |
|
Mr. Singdahlsen was the Companys Chief Executive
Officer, Chief Financial Officer and President through
July 25, 2006, which was the effective date of his
resignation from these positions. Mr. Singdahlsen remains
an |
34
|
|
|
|
|
employee of the Company, and as a result his compensation
disclosed above includes both compensation as Chief Executive
Officer, Chief Financial Officer and President through
July 25, 2006 and compensation as an employee from
July 25, 2006 through August 31, 2006. |
Aggregated
Option Exercises And Fiscal Year-End Option Value
Table
The following table provides certain summary information
concerning stock option exercises during the fiscal year ended
August 31, 2006 by the named executive officers and the
value of unexercised stock options held by the named executive
officers as of August 31, 2006.
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|
|
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|
|
|
|
|
|
|
|
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|
|
Aggregated Option Exercises in last Fiscal Year and Year-End
Option Values(1)
|
|
|
|
|
|
|
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|
|
Number of Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
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Underlying Unexercised
|
|
|
Value of Unexercised
|
|
|
|
Shares
|
|
|
|
|
|
Options at
|
|
|
In-the-Money
Options at
|
|
|
|
Acquired on
|
|
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Value
|
|
|
Fiscal Year-End (#)(4)
|
|
|
Fiscal Year-End ($)(5)
|
|
Name
|
|
Exercise(2)
|
|
|
Realized ($)(3)
|
|
|
Exercisable
|
|
|
Unexercisable
|
|
|
Exercisable
|
|
|
Unexercisable
|
|
|
Kenneth R. Berry , Jr.
|
|
|
|
|
|
|
|
|
|
|
397,500
|
|
|
|
115,000
|
|
|
|
158,300
|
|
|
|
1,950
|
|
Jane M. Richards
|
|
|
|
|
|
|
|
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|
75,000
|
|
|
|
100,000
|
|
|
|
|
|
|
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|
Tucker L. Franciscus
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|
|
|
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|
75,000
|
|
|
|
100,000
|
|
|
|
5,500
|
|
|
|
11,000
|
|
|
|
|
(1) |
|
No stock appreciation rights are held by any of the named
executive officers. |
|
(2) |
|
The number of shares received upon exercise of options during
the year ended August 31, 2006. |
|
(3) |
|
With respect to options exercised during the year ended
August 31, 2006, the dollar value of the difference between
the option exercise price and the market value of the option
shares purchased on the date of the exercise of the options. |
|
(4) |
|
The total number of unexercised options held as of
August 31, 2006, separated between those options that were
exercisable and those options that were not exercisable on that
date. |
|
(5) |
|
For all unexercised options held as of August 31, 2006, the
aggregate dollar value of the excess of the market value of the
stock underlying those options over the exercise price of those
unexercised options. These values are shown separately for those
options that were exercisable and those options that were not
yet exercisable on August 31, 2006 based on the closing
sale price of our common stock on that date, which was $1.05 per
share. |
Employee
Retirement Plans, Long-Term Incentive Plans and Pension
Plans
Excluding the Companys stock option plans, we do not have
any long-term incentive plan to serve as incentive for
performance to occur over a period longer than one fiscal year.
1997
Stock Option Plan
In August 1997, our 1997 Stock Option Plan (the 1997
Plan) was adopted by the Board of Directors and
subsequently approved by the stockholders. Pursuant to the 1997
Plan, we may grant options to purchase an aggregate of
1,000,000 shares of common stock to key employees,
directors, and other persons who have contributed or are
contributing to our success. The options granted pursuant to the
1997 Plan may be either incentive options qualifying for
beneficial tax treatment for the recipient or they may be
nonqualified options. The 1997 Plan may be administered by the
Board of Directors or by an option committee. Administration of
the 1997 Plan includes determination of the terms of options
granted under the 1997 Plan. At August 31, 2006, options to
purchase 490,000 shares were outstanding under the Plan and
226,500 options were available to be granted under the 1997 Plan.
2000
Stock Option Plan
In March 1999, our 2000 Stock Option Plan (the 2000
Plan) was adopted by the Board of Directors and
subsequently approved by the stockholders. Pursuant to the 2000
Plan, we may grant options to purchase shares of our common
stock to key employees, directors, and other persons who have
contributed or are contributing to our success. We initially
could grant options to purchase up to 500,000 shares
pursuant to the 2000 Plan. In June 2001,
35
our stockholders approved an amendment which allows us to grant
options to purchase up to 1,500,000 shares pursuant to the
2000 Plan. In June 2004, our stockholders approved an amendment
to increase from 1,500,000 to 2,250,000 the number of shares of
common stock issuable pursuant to options granted under the 2000
Plan. The options granted pursuant to the 2000 Plan may be
either incentive options qualifying for beneficial tax treatment
for the recipient or non-qualified options. The 2000 Plan may be
administered by the Board of Directors or by an option
committee. Administration of the 2000 Plan includes
determination of the terms of options granted under the 2000
Plan. As of August 31, 2006, options to purchase
1,631,750 shares were outstanding under the 2000 Plan and
412,750 options were available to be granted pursuant to the
2000 Plan.
2006
Stock Incentive Plan
In April 2006, our 2006 Stock Incentive Plan (the 2006
Plan) was adopted by the Board of Directors and
subsequently approved by the stockholders in June 2006. Pursuant
to the 2006 Plan, we may grant 4,000,000 options to purchase
shares of our common stock, restricted stock and restricted
stock units to key employees, directors, and other persons who
have contributed or are contributing to our success. The options
granted pursuant to the 2006 Plan may be either incentive
options qualifying for beneficial tax treatment for the
recipient or non-qualified options. The 2006 Plan may be
administered by the Companys Compensation Committee.
Administration of the 2006 Plan includes determination of the
terms of options, restricted stock and restricted stock units
granted under the 2006 Plan. As of August 31, 2006, options
to purchase 210,000 shares were outstanding under the 2006
Plan and 3,790,000 options were available to be granted pursuant
to the 2006 Plan.
Compensation
Committee Interlocks and Insider Participation
The Compensation Committee is made up of three directors:
Messrs. Swenson, Kilpatrick and Rhodes. None of the members
of the Committee have been executive officers of the Company. In
addition, no member of the Committee is, or was during the
fiscal year ended August 31, 2006, an executive officer of
another company whose board of directors has a comparable
committee on which one of the Companys executive officers
serves.
Employment
Contracts and Termination of Employment and
Change-In-Control
Arrangements
We have only one employment agreement, which is with D. Scott
Singdahlsen, our former chief executive officer. The agreement,
effective August 1, 2006, provides for a base salary of
$14,583.33 per month beginning August 1, 2006 through
January 31, 2007 and $12,000 per month beginning
February 1, 2007 plus the opportunity to participate in
project overrides and certain benefits made available to the
Companys employees. The agreement expires on July 31,
2007, but may be extended for up to three additional periods of
one-year each if mutually agreed.
We currently have no compensatory plan or arrangement that
results or will result from the resignation, retirement, or any
other termination of an executive officers employment or
from a
change-in-control
or a change in an executive officers responsibilities
following a
change-in-control,
except that each of the 1997, 2000 and 2006 Plans provide for
vesting of all outstanding options in the event of the
occurrence of a
change-in-control.
|
|
ITEM 11.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
|
Stock
Ownership of Directors and Principal Stockholders
As of November 15, 2006, there were 37,993,259 shares
of common stock outstanding. The following table sets forth
certain information as of that date with respect to the
beneficial ownership of common stock by each
36
director and nominee for director, by all executive officers and
directors as a group, and by each other person known by us to be
the beneficial owner of more than five percent of our
outstanding shares of common stock:
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Percentage of
|
Name and Address of Beneficial Owner
|
|
Beneficially Owned(1)
|
|
Shares Outstanding
|
|
Kenneth R. Berry, Jr.
|
|
|
570,365(2
|
)
|
|
|
1.5
|
%
|
1675 Broadway, Suite 2450
Denver, Colorado 80202
|
|
|
|
|
|
|
|
|
Bryce W. Rhodes
|
|
|
175,583(3
|
)
|
|
|
*
|
|
c/o Whittier Energy
Company
7770 El Camino Real
Carlsbad, CA 92009
|
|
|
|
|
|
|
|
|
David B. Kilpatrick
|
|
|
98,169(4
|
)
|
|
|
*
|
|
9105 St. Cloud Lane
Bakersfield, CA 93311
|
|
|
|
|
|
|
|
|
Dennis M. Swenson
|
|
|
78,169(5
|
)
|
|
|
*
|
|
5360 Lakeshore Drive
Littleton, CO 80123
|
|
|
|
|
|
|
|
|
Tucker L. Franciscus
|
|
|
125,000(6
|
)
|
|
|
*
|
|
1675 Broadway, Suite 2450
Denver, Colorado 80202
|
|
|
|
|
|
|
|
|
Jane M. Richards
|
|
|
75,000(7
|
)
|
|
|
*
|
|
1675 Broadway, Suite 2450
Denver, Colorado 80202
|
|
|
|
|
|
|
|
|
All Executive Officers and
Directors as a group (six persons)
|
|
|
1,142,286(2
|
)(3)(4)(5)(6)(7)
|
|
|
3.0
|
%
|
D. Scott Singdahlsen
|
|
|
2,151,750(8
|
)
|
|
|
5.6
|
%
|
1675 Broadway, Suite 2450
Denver, Colorado 80202
|
|
|
|
|
|
|
|
|
Victory Oil Company
|
|
|
2,773,204(9
|
)
|
|
|
7.3
|
%
|
222 West Sixth Street,
Suite 1010
San Pedro, California 90731
|
|
|
|
|
|
|
|
|
Eastbourne Capital Management,
L.L.C.
|
|
|
3,634,000(10
|
)
|
|
|
9.6
|
%
|
1101 Fifth Avenue,
Suite 160
San Rafael, CA 94901
|
|
|
|
|
|
|
|
|
|
|
|
(*) |
|
Less than one percent. |
|
(1) |
|
Beneficial ownership is defined in the regulations
promulgated by the U.S. Securities and Exchange Commission
as having or sharing, directly or indirectly (1) voting
power, which includes the power to vote or to direct the voting,
or (2) investment power, which includes the power to
dispose or to direct the disposition of shares of the common
stock of an issuer. The definition of beneficial ownership
includes shares underlying options or warrants to purchase
common stock, or other securities convertible into common stock,
that currently are exercisable or convertible or that will
become exercisable or convertible within 60 days. Unless
otherwise indicated, the beneficial owner has sole voting and
investment power. |
|
(2) |
|
Includes the following securities held directly or indirectly by
Kenneth R. Berry, Jr.: an aggregate of 172,865 shares
owned by various entities, IRAs, and trusts with which
Mr. Berry, or his spouse or minor daughter, is associated;
and options to purchase 397,500 shares of common stock at
exercise prices ranging from $.29 to $1.65 per share that
currently are exercisable or that will become exercisable within
the next 60 days. Does not include options to purchase an
additional 15,000 shares at $0.92 until August 25,
2009 that become exercisable in fiscal 2007 and options to
purchase 100,000 shares at $1.12 until July 25, 2011
of which 50,000 share increments become exercisable in July
2007 and 2008, respectively. |
|
(3) |
|
Includes 13,000 shares of common stock owned by
Mr. Rhodes and 64,414 shares of common stock owned by
Adventure Seekers Travel, Inc. Adventure Seekers is owned by
Mr. Rhodes wife and Mr. Rhodes is the |
37
|
|
|
|
|
President of Adventure Seekers. Also includes options to
purchase 20,000 shares at $1.65 per share until
April 11, 2007, options to purchase 50,000 shares at
$1.15 per share until October 14, 2009, options to
purchase 15,000 shares at $1.34 per share until
November 22, 2010 and options to purchase
13,169 shares at $0.97 per share until
October 10, 2011 that are exercisable or will become
exercisable within the next 60 days. Does not include
options to purchase an additional 13,169 shares at
$0.97 per share until October 10, 2011 of which 6,585
and 6,584 become exercisable on February 28, 2007 and
May 31, 2007, respectively. Excludes 171,625 shares
that are held by Whittier Energy Company. Mr. Rhodes is a
President and CEO of Whittier Energy Company. Mr. Rhodes
disclaims beneficial ownership of the shares beneficially owned
by Whittier Energy Company. |
|
(4) |
|
Includes options to purchase 20,000 shares at
$1.72 per share until June 4, 2007, options to
purchase 50,000 shares at $1.15 per share until
October 14, 2009, options to purchase 15,000 shares at
$1.34 per share until November 22, 2010 and options to
purchase 13,169 shares at $0.97 per share until
October 10, 2011 that are exercisable or will become
exercisable within the next 60 days. Does not include
options to purchase an additional 13,169 shares at
$0.97 per share until October 10, 2011 of which 6,585
and 6,584 become exercisable on February 28, 2007 and
May 31, 2007, respectively. |
|
(5) |
|
Includes options to purchase 50,000 shares at
$1.24 per share until October 1, 2009, options to
purchase 15,000 shares at $1.34 per share until
November 22, 2010 and options to purchase
13,169 shares at $0.97 per share until
October 10, 2011 that are exercisable or will become
exercisable within the next 60 days. Does not include
options to purchase an additional 13,169 shares at
$0.97 per share until October 10, 2011 of which 6,585
and 6,584 become exercisable on February 28, 2007 and
May 31, 2007, respectively. |
|
(6) |
|
includes options to purchase 100,000 shares at
$.94 share until September 1, 2009 and options to
purchase 25,000 shares at $1.34 per share until
November 1, 2010. Does not include options to purchase an
additional 50,000 shares at $0.94 share until
September 1, 2009 which become exercisable on
September 1, 2007. |
|
(7) |
|
Includes options to purchase 30,000 shares at $1.46 until
April 15, 2010, options to purchase 25,000 shares at
$1.34 until November 22, 2010 and options to purchase
20,000 at $1.12 until July 25, 2011. Does not include
options to purchase an additional 40,000 shares at $1.12 of
which 20,000 share increments will become exercisable on
July 26, 2007 and 2008, respectively. |
|
(8) |
|
The shares shown for Mr. Singdahlsen include
200,000 shares owned by Mr. Singdahlsens two
minor children. Also includes options to purchase
15,000 shares at $1.82 per share until April 12,
2007, options to purchase 200,000 shares at $0.29 per
share until February 4, 2010, options to purchase
81,750 shares at $1.30 per share until
February 4, 2010, options to purchase 80,000 shares at
$0.96 per share until November 17, 2014 and options to
purchase 25,000 shares at $1.34 per share until
November 22, 2010. |
|
(9) |
|
Based on the information provided by shareholder. |
|
(10) |
|
The shares reflected include shares beneficially owned by
Eastbourne Capital Management, L.L.C., a registered investment
adviser, Richard Jon Barry, Manager of Eastbourne and the
following companies to which Eastbourne is investment adviser:
Black Bear Offshore Master Fund Limited, a Cayman Island
exempted company, Black Bear Fund I, L.P. and Black Bear
Fund II, LLC. Not included are equivalent shares of common
stock underlying $7,309,500 of convertible notes held by Black
Bear Offshore Master Fund Limited, Black Bear Fund I,
L.P. and Black Bear Fund II, LLC. |
|
|
ITEM 12.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS
|
On May 24, 2002, certain investment entities managed by
Eastbourne Capital Management, LLC purchased $6 million of
convertible notes from the Company. The notes provide for
semi-annual interest payments at an annual rate of 4.99% and are
convertible into common stock at the rate of $1.30 per
share. At the time of the transaction, these entities had
aggregate ownership in PYR Energy Corporation of approximately
15%. Concurrent with the sale, we agreed to add
Messrs. Eric Sippel and Borden Putnam, of Eastbourne, to
our Board of Directors. Messrs. Sippel and Putnam resigned
from the board in August 2003, although Eastbourne still has the
right to designate two individuals to serve on the Board.
As more fully described in the
Form 8-K
filed with the SEC on October 26, 2005, in mid-October
2005, the Company completed a private equity placement
consisting of the sale of 6.275 million shares of common
stock,
38
priced at $1.30 per share, to a group of institutional and
accredited individual investors and issued warrants to purchase
52,500 shares of common stock at a price of $1.30 per share to a
financial advisory company as partial payment for services
rendered. Pursuant to the terms of the private placement, the
Company filed a registration statement covering the resale of
these shares. Kenneth R. Berry, Jr., who is now our Chief
Executive Officer (and at the time of purchase was our Vice
President of Land), purchased beneficial ownership of shares of
our common stock in connection with this private placement,
which occurred on October 3, 2005, as follows. The Kenneth
R. Berry, Jr. and Leslie A. Berry Trust (the
Trust) purchased 20,000 shares of common stock
in the private placement. Mr. Berry is a trustee and
beneficiary of the trust. Estancia Petroleum Corporation
(Estancia) purchased 50,000 shares of common
stock in the private placement. Mr. Berry owns all the
outstanding equity interests in Estancia Corporation. The
foregoing purchases were made at the same purchase price as all
the other purchasers in the private placement and account for
1.1% ($91,000) of the total $8,157,000 private placement
offering. The shares were subscribed for pursuant to two
separate Subscription Agreements, each executed on
October 3, 2005 by the Trust and Estancia, respectively.
Based on the closing price of our stock on October 3, 2005,
the aggregate dollar discount from that market price that was
received by the Trust and Estancia in connection with the
purchase of their shares was $53,900, or $0.77 per share.
Mr. Berry was not involved in the structure or negotiation
of the terms of the private placement, nor did he commit to
purchase any shares pursuant to the private placement until
after: (1) the price per share had been negotiated between
the Company and an unrelated third party, and (ii) the
private placement had commenced. Our Audit Committee had
approved Mr. Berrys participation in the private
placement in a meeting held on November 2, 2005. On
June 22, 2006, our shareholders ratified the issuance of
the shares purchased as part of the private placement by the
Trust and Estancia as described above.
During the fiscal year ended August 31, 2006, there were no
other transactions between the Company and its directors,
executive officers or known holders of greater than five percent
of the Companys 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.
Exhibit Index
|
|
|
|
|
Number
|
|
Description
|
|
|
3
|
.1*
|
|
Articles of Incorporation, filed
with the Maryland Secretary of State on June 18, 2001(1)
|
|
3
|
.2*
|
|
Articles of Merger, filed with the
Maryland Secretary of State on July 3, 2001(1)
|
|
3
|
.3*
|
|
Bylaws(1)
|
|
4
|
.1*
|
|
Specimen Common Stock
Certificate(2)
|
|
4
|
.2*
|
|
Subscription and Registration
Rights Agreement between Wellington parties and the Company,
September 2005(3)
|
|
21
|
|
|
List of the Companys
Subsidiaries
|
|
23
|
.1
|
|
Consent of HEIN &
Associates LLP.
|
|
23
|
.2
|
|
Consent of Ryder Scott Company
|
|
31
|
.1
|
|
Certification of Chief Executive
Officer
|
|
31
|
.2
|
|
Certification of Chief Financial
Officer
|
|
32
|
.1
|
|
Certification pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 by Chief
Executive Officer
|
|
32
|
.2
|
|
Certification pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 by Chief
Financial Officer
|
|
|
|
* |
|
Previously filed. |
|
(1) |
|
Incorporated by reference from the Companys
Form 10-KSB
for the year ended August 31, 2001. |
|
(2) |
|
Incorporated by reference from the Companys
Form 10-KSB/A1
for the year ended August 31, 1997. |
|
(3) |
|
Incorporated by reference from the Companys Report on
Form 8-K
filed on October 8, 2005. |
39
|
|
ITEM 14.
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
Audit
Fees
Hein & Associates LLP, the Companys principal
accountants, billed the Company approximately $76,000 and
$79,000 for the years ended August 31, 2006 and 2005,
respectively. Heins professional services, as of
August 31, 2006, included review of financial statements
included in the Companys
Forms 10-Q,
and services provided in connection with regulatory filings.
Audit-Related
Fees
For the years ended August 31, 2006 and 2005,
Hein & Associates LLP billed the Company approximately
$2,000 in each fiscal year for work performed in the preparation
of a
Form S-3
filed during fiscal 2006 and an
8-K filed
during fiscal 2005, respectively.
Tax
Fees
There was approximately $3,000 billed by Hein &
Associates, LLP for professional services for tax compliance,
tax advice, and tax planning for fiscal 2006. No amounts were
billed for such services in fiscal 2005.
All Other
Fees
For the years ended August 31, 2006 and August 31,
2005, Hein & Associates, LLP did not bill the Company
for products and services other than those described above.
Audit
Committee Pre-Approval Policies
The audit committee currently does not have any pre-approval
policies or procedures concerning services performed by
Hein & Associates, LLP. All services performed by
Hein & Associates, LLP that are described above were
pre-approved by the audit committee.
40
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
|
|
|
|
By:
|
/s/ Kenneth
R. Berry, Jr.
|
Kenneth R. Berry, Jr.
Chief Executive Officer
Date: November 22, 2006
Jane M. Richards
Chief Financial Officer and Principal Accounting Officer
Date: November 22, 2006
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/ Kenneth
R. Berry, Jr.
Kenneth
R. Berry, Jr.
|
|
Chief Executive Officer
|
|
November 22, 2006
|
|
|
|
|
|
/s/ Jane
M. Richards
Jane
M. Richards
|
|
Chief Financial Officer
|
|
November 22, 2006
|
|
|
|
|
|
/s/ David
Kilpatrick
David
Kilpatrick
|
|
Chairman of the Board
|
|
November 22, 2006
|
|
|
|
|
|
/s/ Dennis
M. Swenson
Dennis
M. Swenson
|
|
Director
|
|
November 22, 2006
|
|
|
|
|
|
/s/ Bryce
W. Rhodes
Bryce
W. Rhodes
|
|
Director
|
|
November 22, 2006
|
41
PYR
ENERGY CORPORATION
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
PYR Energy Corporation
Denver, Colorado
We have audited the consolidated balance sheets of PYR Energy
Corporation and subsidiaries as of August 31, 2006 and
2005, and the related consolidated statements of operations,
stockholders equity and cash flows for the years then
ended. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of PYR Energy Corporation and subsidiaries as of
August 31, 2006 and 2005, and the results of their
operations and their cash flows for the years then ended, in
conformity with U.S. generally accepted accounting
principles.
HEIN & ASSOCIATES LLP
Denver, Colorado
November 6, 2006
F-2
PYR
ENERGY CORPORATION
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
August 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except share and per share data)
|
|
|
ASSETS
|
Current
Assets:
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
6,254
|
|
|
$
|
2,934
|
|
Oil and gas receivables
|
|
|
1,784
|
|
|
|
1,618
|
|
Other receivable
|
|
|
62
|
|
|
|
124
|
|
Prepaid expenses and other assets
|
|
|
64
|
|
|
|
59
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
8,164
|
|
|
|
4,735
|
|
|
|
|
|
|
|
|
|
|
Property
and Equipment, at cost
|
|
|
|
|
|
|
|
|
Oil and gas properties under full
cost, net
|
|
|
20,421
|
|
|
|
13,242
|
|
Furniture and equipment, net
|
|
|
45
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,466
|
|
|
|
13,271
|
|
|
|
|
|
|
|
|
|
|
Other
Assets:
|
|
|
|
|
|
|
|
|
Deferred financing costs and other
assets
|
|
|
29
|
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
28,659
|
|
|
$
|
18,086
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS EQUITY
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
321
|
|
|
$
|
89
|
|
Amounts payable to oil and gas
property owners
|
|
|
38
|
|
|
|
2
|
|
Accrued expenses:
|
|
|
|
|
|
|
|
|
Accrued interest payable
|
|
|
99
|
|
|
|
94
|
|
Accrued net profits payable
|
|
|
231
|
|
|
|
1,287
|
|
Other accrued liabilities
|
|
|
936
|
|
|
|
282
|
|
Asset retirement obligation
|
|
|
907
|
|
|
|
904
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
2,532
|
|
|
|
2,658
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Liabilities:
|
|
|
|
|
|
|
|
|
Convertible notes
|
|
|
7,310
|
|
|
|
6,958
|
|
Asset retirement obligation
|
|
|
366
|
|
|
|
293
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
7,676
|
|
|
|
7,251
|
|
Commitments
And Contingencies
(Note 9)
|
|
|
|
|
|
|
|
|
Stockholders
Equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $.001 par
value; authorized 1,000,000 shares; issued and
outstanding none
|
|
|
|
|
|
|
|
|
Common stock, $.001 par
value; authorized 75,000,000 shares; issued and
outstanding 37,993,259 at 8/31/06 and
31,640,259 shares at 8/31/05
|
|
|
38
|
|
|
|
32
|
|
Capital in excess of par value
|
|
|
51,292
|
|
|
|
43,294
|
|
Accumulated deficit
|
|
|
(32,879
|
)
|
|
|
(35,149
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
18,451
|
|
|
|
8,177
|
|
|
|
|
|
|
|
|
|
|
Total
Liabilities and Stockholders Equity
|
|
$
|
28,659
|
|
|
$
|
18,086
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial
statements.
F-3
PYR
ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
Years Ended August 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil and gas revenues
|
|
$
|
10,319
|
|
|
$
|
6,102
|
|
|
|
|
|
|
|
|
|
|
Operating
Expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
1,547
|
|
|
|
721
|
|
Production taxes, gathering and
transportation
|
|
|
689
|
|
|
|
383
|
|
Net profits expense
|
|
|
829
|
|
|
|
1,343
|
|
Impairment
|
|
|
|
|
|
|
580
|
|
Depreciation, depletion,
amortization and accretion
|
|
|
2,616
|
|
|
|
893
|
|
General and administrative
|
|
|
2,256
|
|
|
|
1,909
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
7,937
|
|
|
|
5,829
|
|
|
|
|
|
|
|
|
|
|
Income
From Operations
|
|
|
2,382
|
|
|
|
273
|
|
Other
Income (Expense):
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
245
|
|
|
|
93
|
|
Interest (expense)
|
|
|
(371
|
)
|
|
|
(343
|
)
|
Other (expense) income
|
|
|
14
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
(112
|
)
|
|
|
(261
|
)
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
2,270
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
Net
Income Per Common Share -Basic And Diluted
|
|
$
|
0.06
|
|
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Shares Outstanding
|
|
|
|
|
|
|
|
|
Basic
|
|
|
37,319
|
|
|
|
31,597
|
|
Diluted
|
|
|
37,864
|
|
|
|
32,290
|
|
The accompanying notes are an integral part of the financial
statements.
F-4
PYR
ENERGY CORPORATION
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in
|
|
|
|
|
|
|
Common Stock
|
|
|
Excess of
|
|
|
Accumulated
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Par Value
|
|
|
Deficit
|
|
|
|
(In thousands)
|
|
|
Balance,
September 1, 2004
|
|
|
31,564
|
|
|
$
|
32
|
|
|
$
|
43,221
|
|
|
$
|
(35,161
|
)
|
Exercise of common stock options
for cash
|
|
|
76
|
|
|
|
|
|
|
|
58
|
|
|
|
|
|
Issuance of common stock options
for director services
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
August 31, 2005
|
|
|
31,640
|
|
|
|
32
|
|
|
|
43,294
|
|
|
|
(35,149
|
)
|
Exercise of common stock options
for cash
|
|
|
78
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
Private Placement sale of common
stock, net of offering costs of $196,000
|
|
|
6,275
|
|
|
|
6
|
|
|
|
7,955
|
|
|
|
|
|
Issuance of non-qualifying options
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,270
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
August 31, 2006
|
|
|
37,993
|
|
|
$
|
38
|
|
|
$
|
51,292
|
|
|
$
|
(32,879
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial
statements.
F-5
PYR
ENERGY CORPORATION
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Years Ended August 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Operating
Activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,270
|
|
|
$
|
12
|
|
Adjustments to reconcile net
income to net cash used by operating activities
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
2,593
|
|
|
|
868
|
|
Impairment
|
|
|
|
|
|
|
580
|
|
Amortization of financing costs
|
|
|
3
|
|
|
|
3
|
|
Interest expense converted into
debt
|
|
|
352
|
|
|
|
335
|
|
Accretion of asset retirement
obligation
|
|
|
22
|
|
|
|
25
|
|
Stock option expense for
non-qualifying options issued
|
|
|
10
|
|
|
|
|
|
Stock options issued for director
services
|
|
|
|
|
|
|
15
|
|
Changes in current assets and
liabilities (Increase) in accounts receivable
|
|
|
(104
|
)
|
|
|
(1,266
|
)
|
Decrease (increase) in prepaids
and other receivables
|
|
|
(5
|
)
|
|
|
44
|
|
Increase in accounts payable
|
|
|
30
|
|
|
|
4
|
|
Increase in amounts payable to oil
and gas property owners
|
|
|
36
|
|
|
|
|
|
Increase in accrued liabilities
|
|
|
284
|
|
|
|
22
|
|
(Decrease) increase in net profits
payable
|
|
|
(1,056
|
)
|
|
|
1,287
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating
activities
|
|
|
4,435
|
|
|
|
1,929
|
|
|
|
|
|
|
|
|
|
|
Investing
Activities:
|
|
|
|
|
|
|
|
|
Cash paid for furniture and
equipment
|
|
|
(29
|
)
|
|
|
(10
|
)
|
Cash paid for oil and gas
properties
|
|
|
(9,526
|
)
|
|
|
(5,862
|
)
|
Proceeds from sale of exploration
options
|
|
|
|
|
|
|
750
|
|
Proceeds from sale of oil and gas
properties
|
|
|
398
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing
activities
|
|
|
(9,157
|
)
|
|
|
(5,073
|
)
|
|
|
|
|
|
|
|
|
|
Financing
Activities:
|
|
|
|
|
|
|
|
|
Proceeds from sale of common stock
|
|
|
8,157
|
|
|
|
|
|
Proceeds from exercise of options
|
|
|
33
|
|
|
|
58
|
|
Cash paid for offering costs
|
|
|
(178
|
)
|
|
|
(18
|
)
|
Other
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing
activities
|
|
|
8,042
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
Net
(Decrease) Increase In Cash
|
|
|
3,320
|
|
|
|
(3,104
|
)
|
Cash,
Beginning Of Year
|
|
|
2,934
|
|
|
|
6,038
|
|
|
|
|
|
|
|
|
|
|
Cash,
End Of Year
|
|
$
|
6,254
|
|
|
$
|
2,934
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest and income
taxes
|
|
$
|
10
|
|
|
$
|
|
|
Non-cash financing activities:
|
|
|
|
|
|
|
|
|
Asset retirement obligation
increase
|
|
$
|
54
|
|
|
$
|
15
|
|
Net increase in payables and
accrued liabilities for capital expenditures
|
|
|
578
|
|
|
|
3
|
|
Debt issued for interest
|
|
|
351
|
|
|
|
335
|
|
The accompanying notes are an integral part of the financial
statements.
F-6
PYR
ENERGY CORPORATION AND SUBSIDIARIES
For the fiscal years ended August 31, 2005 and
2006
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 Companys current activities are principally
conducted in the Rocky Mountains, Texas, and Gulf Coast regions
of the United States.
On February 18, 2004, PYR Cumberland LLC, PYR Mallard LLC,
and PYR Pintail LLC were formed as wholly owned subsidiaries of
PYR Energy Corporation. The purpose of these entities is to own
and develop certain assets related to designated individual
exploration projects.
Basis Of Presentation The accompanying
consolidated financial statements for the years ended
August 31, 2006 and 2005 include the Company and its three
wholly owned subsidiaries (collectively, the
Company, we, us or
our). All significant inter-company transactions
have been eliminated upon consolidation.
Cash Equivalents For purposes of
reporting cash flows, the Company considers as cash equivalents
all highly liquid investments with a maturity of three months or
less at the time of purchase. On occasion, the Company has cash
in banks in excess of federally insured amounts. See
Concentration of Risk below.
Receivables And Credit Policies The
Company has certain trade receivables consisting of oil and gas
sales obligations due under normal trade terms. Management
regularly reviews trade receivables and reduces the carrying
amount by a valuation allowance that reflects managements
best estimate of the amount that may not be collectible.
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
Companys oil and gas properties are located within the
United States and Canada. Properties within these respective
countries constitute separate cost centers. No gain or loss is
recognized upon the sale or abandonment of undeveloped or
producing oil and gas properties unless the sale represents a
significant portion of oil and gas properties and the gain
significantly alters the relationship between capitalized costs
and proved oil and gas reserves of the cost center.
Depreciation, depletion and amortization of oil and gas
properties is computed on the units of production method based
on proved reserves. Amortizable costs include estimates of
future development costs of proved undeveloped reserves.
Capitalized costs of oil and gas properties may not exceed an
amount equal to the present value, discounted at 10%, of the
estimated future net cash flows from proved oil and gas reserves
plus the cost, or estimated fair market value, if lower, of
unproved properties. Should capitalized costs exceed this
ceiling, an impairment is recognized. The present value of
estimated future net cash flows is computed by applying year end
prices of oil and natural gas to estimated future production of
proved oil and gas reserves as of year end, less estimated
future expenditures to be incurred in developing and producing
the proved reserves and assuming continuation of existing
economic conditions. A reserve is provided for estimated future
costs of site restoration, dismantlement and abandonment
activities.
The Company utilizes the full cost accounting method of
accounting for oil and gas activities and in 2006 and 2005 had
separate cost centers for the United States and Canada. During
2005, the Company recorded a non-cash impairment of $580,000 of
its initial oil and gas investment in Canada as the book value
of the properties exceeded the estimated fair market value of
such properties. The Company decided to limit future
expenditures in Canada.
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.
Furniture And Equipment Furniture and
equipment is recorded at cost. Depreciation of assets is
provided by use of the straight-line method over the estimated
useful lives of the related assets of three to five years.
F-7
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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 Companys
product entitlement.
Deferred Financing Costs Costs
incurred in connection with the execution of the Companys
Convertible Notes have been capitalized and are amortized over
the life of the notes.
Income Taxes The Company has adopted
the provisions of Statement of Financial Accounting Standards
No. 109 (SFAS 109), Accounting for Income Taxes
issued by the Financial Accounting Standards Board (FASB).
SFAS 109 requires recognition of deferred tax liabilities
and assets for the expected future tax consequences of events
that have been included in the financial statements or tax
returns. Under this method, deferred tax liabilities and assets
are determined based on the difference between the financial
statement and tax basis of assets and liabilities using enacted
tax rates in effect for the year in which the differences are
expected to reverse.
Temporary differences between the time of reporting certain
items for financial and tax reporting purposes consist primarily
of exploration and development costs on oil and gas properties,
and impairment pursuant to the ceiling test limitation.
Use Of Estimates The preparation of
financial statements in conformity with generally accepted
accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and reported amounts of
revenues and expenses during the reporting period. Actual
results could differ from those estimates.
The Companys financial statements are based on a number of
significant estimates, including ability to realize its
receivables and deferred tax assets, selection of the useful
lives for property and equipment, timing and costs associated
with its retirement obligations and oil and gas reserve
quantities which are the basis for the calculation of
depreciation, depletion and impairment of oil and gas properties.
The oil and gas industry is subject, by its nature, to
environmental hazards and
clean-up
costs. At this time, management knows of no substantial costs
from environmental accidents or events for which it may be
currently liable. In addition, the Companys oil and gas
business makes it vulnerable to changes in wellhead prices of
crude oil and natural gas. Such prices have been volatile in the
past and can be expected to be volatile in the future. By
definition, proved reserves are based on current oil and gas
prices and estimated reserves, which is considered a significant
estimate by the Company, which is subject to changes. Price
declines reduce the estimated quantity of proved reserves and
increase annual amortization expense (which is based on proved
reserves) and may impact the impairment analysis of the
Companys full cost pool.
Net Income Per Share Basic net income
per common share is computed based on the weighted average
number of common shares outstanding during each period. Diluted
net income per common share is computed based on the weighted
average number of common shares outstanding plus other dilutive
securities such as stock options and warrants.
Share Based Compensation In October
1995, the FASB issued SFAS No. 123, Accounting for
Stock-Based Compensation (SFAS 123), effective for
fiscal years beginning after December 15, 1995. This
statement defines a fair value method of accounting for employee
stock options and encourages entities to adopt that method of
accounting for its stock compensation plans. SFAS 123
allows an entity to continue to measure compensation costs for
these plans using the intrinsic value based method of accounting
as prescribed in Accounting Pronouncement Bulletin Opinion
No. 25, Accounting for Stock Issued to Employees
(APB 25) for annual periods beginning before
December 15, 2005.
F-8
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Accordingly, for the years ended August 31, 2006 and 2005,
the Company has elected to continue to account for its employee
stock compensation plans as prescribed under APB 25. Had
compensation cost for the Companys stock-based
compensation plans been determined based on the fair value at
the grant dates for awards under those plans consistent with the
method prescribed in SFAS 123, the Companys net
(loss) and (loss) per share for the years ended August 31,
2006 and 2005 would have been increased to the pro forma amounts
indicated below:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands, except per share data)
|
|
|
Net income:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
2,270
|
|
|
$
|
12
|
|
Total compensation cost determined
under the fair value base method for all awards
|
|
|
(559
|
)
|
|
|
(331
|
)
|
|
|
|
|
|
|
|
|
|
Pro forma net income (loss)
|
|
$
|
1,711
|
|
|
$
|
(319
|
)
|
|
|
|
|
|
|
|
|
|
Net pro forma income (loss) per
share:
|
|
|
|
|
|
|
|
|
As reported Basic and
Dilutive
|
|
$
|
0.06
|
|
|
$
|
(0.00
|
)
|
|
|
|
|
|
|
|
|
|
Pro forma Basic and
Dilutive
|
|
$
|
0.05
|
|
|
$
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
See Note 8 with respect to assumptions used. See Recent
Accounting Pronouncements regarding the adoption of
SFAS No. 123(R).
Gas Balancing The Company uses the
sales method of accounting for gas balancing of gas production,
and would recognize a liability if the existing proven reserves
were not adequate to cover the current imbalance situation. As
of August 31, 2006, the Company was over-produced by
17 MMcf (unaudited), which represents approximately $98,000
in gas revenues based on an average sales price of
$5.78 per equivalent Mcfe
Fair Value The carrying amount
reported in the balance sheet for cash, prepaid expenses,
accounts payable and accrued liabilities approximates fair value
because of the immediate or short-term maturity of these
financial instruments.
In May 2002, the Company completed the sale of $6 million,
4.99% convertible promissory notes, due May 2009. The notes are
convertible, together with accrued interest, into shares of the
Companys common stock at the rate of $1.30 per share,
at the option of the holder. The company considers the notes to
be stated at fair value due to arms length negotiation of the
transaction and the conversion feature.
Concentration Of Risk Financial
instruments which potentially subject the Company to
concentrations of credit risk consist of cash and receivables.
The Company maintains cash accounts at one financial
institution. The Company periodically evaluates the credit
worthiness of financial institutions, and maintains cash
accounts only in large high quality financial institutions,
thereby minimizing exposure for deposits in excess of federally
insured amounts. The Company believes that credit risk
associated cash is remote.
The Company has concentrated its United States exploration and
production activities primarily in the Rocky Mountain, Texas and
Gulf Coast regions. All significant activities in these segments
have been with industry partners.
As of August 31, 2005 and August 31, 2006, there were
no reserves associated with the Canadian cost center. The
Companys oil and gas prospects in Canada consist of
undeveloped properties. During 2005, the Company recorded a
non-cash impairment of $580,000 of its initial oil and gas
investment in Canada as the book value of these properties
exceeded the estimated fair market value of such properties. The
Company decided to limit future expenditures in Canada.
F-9
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Customers accounting for 10% or more of gross revenue, all
representing purchasers of oil and gas, for the years ended
August 31, 2006 and 2005 are as follows:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Customer A
|
|
|
26
|
%
|
|
|
|
|
Customer B
|
|
|
20
|
%
|
|
|
38
|
%
|
Customer C
|
|
|
11
|
%
|
|
|
|
|
Customer D
|
|
|
|
|
|
|
22
|
%
|
Customer E
|
|
|
|
|
|
|
10
|
%
|
Reclassification Certain
reclassifications have been made to the 2005 financial
statements to conform to 2006 presentation. Such
reclassifications had no effect on the net income (loss).
Recent Accounting Pronouncements In
December 2004, the FSAB issued its final standard on accounting
for employee stock options, SFAS No. 123 (Revised
2004), Share-Based Payment
(SFAS 123 (R)). SFAS 123 (R)
replaces SFAS No. 123, Accounting for Stock-Based
Compensation (SFAS 123), and supersedes
APB 25, Accounting for Stock Issued to
Employees. SFAS 123 (R) requires
companies to measure compensation costs for all share-based
payments, including grants of employee stock options, based on
the fair value of the awards on the grant date and to recognize
such expense over the period during which an employee is
required to provide services in exchange for the award. The pro
forma disclosures previously permitted under SFAS 123 will
no longer be an alternative to financial statement recognition.
For entities that file as a small business issuer, such as PYR
Energy Corporation, SFAS 123 (R) is effective for all
awards granted, modified, repurchased or cancelled after, and to
unvested portions of previously issued and outstanding awards
vesting for annual periods beginning after December 15,
2005, which for us will be the first quarter of fiscal 2007. We
are currently evaluating the effect of adopting
SFAS 123 (R) on our financial position and results of
operations. We currently estimate the adoption of
SFAS 123 (R) will result in expenses in amounts that
are similar to the current pro forma disclosures under
SFAS 123.
In March 2005, the FASB issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations
(FIN 47). FIN 47 clarifies that the
term conditional asset retirement obligation, as
used in SFAS 143, Accounting for Asset Retirement
Obligations, refers to a legal obligation to perform an
asset retirement activity in which the timing
and/or
method of settlement are conditional on a future event that may
or may not be within the control of the entity. However, the
obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing or
method of settlement. FIN 47 requires that the uncertainty
about the timing or method of settlement of a conditional asset
retirement obligation be factored into the measurement of the
liability when sufficient information exists. FIN 47 also
clarifies when an entity would have sufficient information to
reasonably estimate the fair value of an asset retirement
obligation. The adoption of FIN 47 had no effect on our
financial position or results of operations for the fiscal year
ended August 31, 2006.
On July 13, 2006, the FASB released Interpretation
No. 48, Accounting for Uncertainty in Income
Taxes an Interpretation of FASB
Statement 109 (FIN 48). FIN 48
requires companies to evaluate and disclose material uncertain
tax positions it has taken with various taxing jurisdictions. We
are currently reviewing and evaluating the effect, if any, of
adopting FIN 48 on our financial position and results of
operations. We will be required to adopt FIN 48 for our
fiscal year ended August 31, 2008.
|
|
2.
|
Acquisition
and Divestitures of Properties
|
In February 2005, the Company acquired additional working and
revenue interest in two producing properties and additional
interest in undeveloped properties located in Hansford County of
the Texas panhandle for a purchase price of approximately
$440,000.
F-10
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In December 2005, the Company again acquired additional working
and revenue interests in the Hansford project, from multiple
private entities for $1.7 million. This acquisition
included 1.64 Bcf of proved reserves and 2,265 acres
of leasehold. As a result of these acquisitions, the Company
owns 100% working interest on a majority of the acreage which
includes three producing wells, one of which was drilled and
completed in 2006.
The Company sold its interest in certain leasehold acreage
located in the School Road prospect in California for
approximately $96,000 and sold its interest in approximately
250 acres in the Merganser prospect located in Leon County,
Texas for approximately $280,000 in December 2005 and February
2006, respectively.
3. Property
and Equipment
Oil and Gas Properties Oil and gas
properties at August 31, 2006 and 2005 consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Oil and gas properties, full cost
method
|
|
|
|
|
|
|
|
|
Unevaluated costs, not subject to
amortization
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
1,852
|
|
|
$
|
5,164
|
|
Evaluated costs
|
|
|
47,079
|
|
|
|
37,767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,931
|
|
|
|
42,931
|
|
Less accumulated depreciation,
depletion, amortization and impairment
|
|
|
(28,510
|
)
|
|
|
(29,689
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
20,421
|
|
|
$
|
13,242
|
|
|
|
|
|
|
|
|
|
|
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.
Unevaluated property costs consisting of unproved oil and gas
leases (totaling approximately $1.437 million) and
exploration costs and exploratory wells in progress (totaling
approximately $415,000) as of the end of the year have been
excluded from depletable costs pending further evaluation as of
August 31, 2006 are as follows (in thousands):
|
|
|
|
|
Period Incurred
|
|
|
|
|
2006
|
|
$
|
1,118
|
|
2005
|
|
|
345
|
|
2004
|
|
|
348
|
|
2003
|
|
|
41
|
|
|
|
|
|
|
|
|
$
|
1,852
|
|
|
|
|
|
|
For the years ended August 31, 2006 and 2005, the Company
did not recognize any impairment expense against the capitalized
oil and gas properties in the United States, as determined by
the ceiling test performed pursuant to
Regulation S-X
Rule 4-10(c)(2).
For the year ended August 31, 2005, the Company recognized
an impairment expense of $580,000 against the capitalized oil
and gas properties in Canada.
Depreciation, depletion, and amortization of oil and gas
properties for the years ended August 31, 2006 and 2005 was
approximately $2.6 million and $860,000, or $2.04 and
$1.12 per Mcfe of gas produced, respectively. Depreciation
of assets recognized in accordance with the Asset Retirement
Obligation calculation is included in these amounts (see below).
F-11
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Information relating to the Companys costs incurred in its
oil and gas operations during the years ended August 31,
2006 and 2005 is summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Property acquisition costs
|
|
$
|
1,714
|
|
|
$
|
440
|
|
Exploration costs
|
|
|
5,597
|
|
|
|
5,101
|
|
Development costs
|
|
|
2,793
|
|
|
|
276
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10,104
|
|
|
$
|
5,817
|
|
|
|
|
|
|
|
|
|
|
Furniture and Equipment Furniture and
equipment at August 31, 2006 and 2005 consisted of the
following:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Furniture and equipment
|
|
$
|
178
|
|
|
$
|
149
|
|
Less accumulated depreciation
|
|
|
(133
|
)
|
|
|
(120
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
45
|
|
|
$
|
29
|
|
|
|
|
|
|
|
|
|
|
Depreciation expense associated with capitalized office
furniture and equipment during fiscal 2006 and 2005 was $14,000
and $8,000, respectively.
4. Asset
Retirement Obligations
In 2001, the FASB issued SFAS 143, Accounting for Asset
Retirement Obligations. SFAS 143 addresses
financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement requires
companies to record the present value of obligations associated
with the retirement of tangible long-lived assets in the period
in which it is incurred. The liability is capitalized as part of
the related long-lived assets carrying amount. Over time,
accretion of the liability is recognized as an operating expense
and the capitalized cost is depreciated over the expected useful
life of the related asset. The Companys asset retirement
obligations relate primarily to the plugging, dismantlement,
removal, site reclamation and similar activities of its oil and
gas properties.
The following table summarizes activity related to the
accounting for asset retirement obligations for the fiscal years
ended August 31, 2006 and August 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Asset retirement obligations,
beginning of fiscal year
|
|
$
|
1,197
|
|
|
$
|
1,158
|
|
Liabilities incurred
|
|
|
54
|
|
|
|
19
|
|
Liabilities settled
|
|
|
|
|
|
|
|
|
Accretion of asset retirement
obligation including revision of estimates
|
|
|
22
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end
of fiscal year
|
|
|
1,273
|
|
|
|
1,197
|
|
Less current portion
|
|
|
(907
|
)
|
|
|
(904
|
)
|
|
|
|
|
|
|
|
|
|
Long-term portion
|
|
$
|
366
|
|
|
$
|
293
|
|
|
|
|
|
|
|
|
|
|
F-12
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
5. Net
Income per Share
The following table sets forth the computation of basic and
diluted earning per share (in thousands except per share data):
|
|
|
|
|
|
|
|
|
|
|
Years Ended August 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,270
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
Weighted-average shares outstanding
|
|
|
37,319
|
|
|
|
31,597
|
|
Effect of Dilutive Securities:
|
|
|
|
|
|
|
|
|
Assumed exercise of dilutive
options
|
|
|
545
|
|
|
|
693
|
|
|
|
|
|
|
|
|
|
|
Weighted-average shares and
dilutive potential common shares
|
|
|
37,864
|
|
|
|
32,290
|
|
|
|
|
|
|
|
|
|
|
Basic and dilutive income per share
|
|
$
|
0.06
|
|
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
Convertible
Notes Payable
|
In May 2002, the Company completed the sale of $6 million,
4.99% convertible promissory notes, due May 2009. The notes are
convertible, together with accrued interest, into shares of the
Companys common stock at the rate of $1.30 per share,
at the option of the holder. No beneficial interest has been
accrued to the notes, as the conversion price approximates the
fair market value of the common shares as of the transaction
date. Interest is payable semiannually in May and November.
At the option of the Company, accrued interest can be paid in
cash or added to the principal amount of the notes. The Company
elected to add accrued interest of approximately $351,000 and
$335,000 during fiscal years 2006 and 2005, respectively, to the
balance of the notes. As of August 31, 2006 the balance of
the notes is approximately $7.3 million.
The Company follows the asset and liability method of accounting
for deferred income taxes. Deferred tax assets and liabilities
are determined based on the temporary differences between the
financial statement and tax basis of assets and liabilities. At
August 31, 2006, the Company had approximately
$42.3 million of net operating losses and $45,000 of
statutory depletion carry forward for tax return purposes. These
losses expire in varying amounts between 2012 and 2026 and
utilization could be limited if the Company experienced a change
in control as defined in the Internal Revenue Code.
Due to the net operating loss, no income tax expense was
recorded in the consolidated statements of operations.
The effective income tax rate differs from the U.S. Federal
statutory income tax rate due to the following:
|
|
|
|
|
|
|
|
|
|
|
Years Ended August 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Federal statutory income tax rate
|
|
|
(34
|
)%
|
|
|
(34
|
)%
|
Increase in valuation allowance
|
|
|
34
|
%
|
|
|
34
|
%
|
|
|
|
|
|
|
|
|
|
Effective rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-13
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The principal sources of temporary differences resulting in
deferred tax assets and tax liabilities at August 31, 2006
and 2005 are as follows:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Asset retirement obligation
|
|
$
|
472
|
|
|
$
|
444
|
|
Tax loss carryforward
|
|
|
15,988
|
|
|
|
15,296
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
16,460
|
|
|
|
15,740
|
|
Less valuation allowance
|
|
|
(13,658
|
)
|
|
|
(14,471
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
$
|
2,802
|
|
|
$
|
1,269
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property impaired for financial
reporting, but capitalized for tax; offset by intangible
drilling and other exploration costs capitalized for financial
reporting purposes but deducted for tax purposes
|
|
|
(2,802
|
)
|
|
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
$
|
(2,802
|
)
|
|
$
|
(1,269
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred taxes
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
The valuation allowance decreased by approximately $813,000 in
2006 and increased by $171,000 in 2005.
Preferred Stock In April 1999, the
stockholders of the Company approved an amendment to the
Certificate of Incorporation pursuant to which the Company was
authorized to issue 1,000,000 shares of preferred stock,
with a par value of $.001 per share. Such shares of
preferred stock may be issued with such preferences and rights
as determined by the Board of Directors.
Common Stock In October 2005, the
Company completed a private placement in which the Company sold
6.275 million shares of common stock at a price of
$1.30 per share to a group of accredited institutional and
individual investors and issued warrants to purchase
52,500 shares of common stock at a price of $1.30 per
share to a financial advisory company as partial payment for
services rendered. We received approximately $8.0 million
in net proceeds after deducting related offering expenses. The
proceeds received from the private placement were used for
general corporate purposes and costs associated with our
drilling portfolio. In December 2005, a registration statement
that became effective January 2006 was filed to register the
re-sale of the securities issued pursuant to this private
placement by the investors.
Warrants In October 2005, we issued
warrants to purchase 52,500 shares of common stock in
partial payment of a commission for financial advisory services
performed in connection with a private placement. The warrants
have an exercise price of $1.30 per share, expire in five
years and were valued at approximately $50,000 based on the
Black-Scholes option pricing model.
At August 31, 2006, the status of outstanding warrants is
as follows:
|
|
|
|
|
|
|
|
|
|
|
Issue Date
|
|
Shares Exercisable
|
|
Exercise Price
|
|
Expiration Date
|
|
May 9, 2002
|
|
|
200,000
|
|
|
$
|
1.49
|
|
|
May 8, 2007
|
December 1, 2003
|
|
|
100,000
|
|
|
$
|
0.65
|
|
|
December 1, 2006
|
May 5, 2004
|
|
|
225,000
|
|
|
$
|
1.30
|
|
|
May 5, 2009
|
June 11, 2004
|
|
|
150,000
|
|
|
$
|
1.24
|
|
|
June 11, 2009
|
October 17, 2005
|
|
|
52,500
|
|
|
$
|
1.30
|
|
|
October 17, 2010
|
F-14
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At August 31, 2006, the weighted average remaining
contractual life of outstanding warrants was 1.4 years.
Stock Options Under two stock option
plans and one stock incentive plan, options to purchase common
stock may be granted until 2016. Stock options are granted to
employees at exercise prices equal to the fair market value of
the Companys 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 7,250,000 shares of common stock for these plans.
At August 31, 2006 and 2005, options to purchase 4,429,250
and 604,250 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. Fair
|
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
Value
|
|
|
Options Outstanding
August 31, 2004
|
|
|
2,183,834
|
|
|
$
|
1.76
|
|
|
|
|
|
Granted
|
|
|
675,000
|
|
|
$
|
1.08
|
|
|
$
|
.68
|
|
Exercised
|
|
|
(75,834
|
)
|
|
$
|
.76
|
|
|
|
|
|
Expired/forfeited
|
|
|
(548,250
|
)
|
|
$
|
2.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
August 31, 2005
|
|
|
2,234,750
|
|
|
$
|
1.41
|
|
|
|
|
|
Granted
|
|
|
435,000
|
|
|
$
|
1.23
|
|
|
$
|
.89
|
|
Exercised
|
|
|
(78,000
|
)
|
|
$
|
.42
|
|
|
|
|
|
Expired/forfeited
|
|
|
(260,000
|
)
|
|
$
|
2.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
August 31, 2006
|
|
|
2,331,750
|
|
|
$
|
1.08
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable as of August 31,
2006
|
|
|
1,744,752
|
|
|
$
|
1.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
weighted-average assumptions used:
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Expected option life-years
|
|
|
5
|
|
|
|
7
|
|
Risk-free interest rate
|
|
|
4.7
|
%
|
|
|
3.5
|
%
|
Dividend yield
|
|
|
0
|
|
|
|
0
|
|
Weighted average volatility
|
|
|
90.6
|
%
|
|
|
70.0
|
%
|
At August 31, 2006 and 2005, the number of options
exercisable was 1,744,752 and 1,213,500 respectively, and the
weighted average exercise price of these options was $1.07 and
$1.76, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding
|
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
|
|
|
|
Contractual Life
|
|
|
Options Exercisable
|
|
Exercise Price
|
|
August 31, 2006
|
|
|
(Years)
|
|
|
at August 31, 2006
|
|
|
$0.29 $0.46
|
|
|
325,000
|
|
|
|
3
|
|
|
|
325,000
|
|
$0.47 $0.96
|
|
|
402,000
|
|
|
|
3
|
|
|
|
247,002
|
|
$0.97 $1.30
|
|
|
1,089,750
|
|
|
|
4
|
|
|
|
717,750
|
|
$1.31 $1.82
|
|
|
515,000
|
|
|
|
3
|
|
|
|
455,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,331,750
|
|
|
|
|
|
|
|
1,744,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-15
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
9.
|
Commitments
and Contingencies
|
Litigation
On July 29, 2005, the Company filed a lawsuit in the
U.S. District Court for the Eastern District of Texas,
Beaumont Division against Samson Lone Star Limited Partnership
(Samson) and Samsons parent company, Samson
Resources Corp. The Company alleged in its complaint that
Samson, the operator of a producing gas well in Jefferson
County, Texas named the Sun Fee GU #1-ST well (the
Sun Fee Well), has breached its obligations to the
Company, which owns interests in the property on which the Sun
Fee Well is located, by joining, without authorization, the Sun
Fee Well into a unit (the Sidetrack Unit) with other
properties in which the Company has no interest, many of which
are non-productive. Samson has a large interest in the
properties that Samson has joined into the unit. Pursuant to
Samsons proposed pooling configuration, the Companys
working and overriding royalty interests in the Sun Fee Well
would be reduced substantially. The Company believes that Samson
has no legal or contractual right to reduce the Companys
interests in this manner. The Company is seeking monetary
damages for all payments due and owing to the Company based on
the proper, undiluted interests in the property.
Until approximately August 1, 2005, Samson had been paying
the Company its share of oil and gas revenues based on
Samsons calculation of the Companys net revenue
interest (5.7%) in the Sun Fee Well after dilution for the
disputed pooling of the non-productive properties, when it
ceased paying the Company any portion of the production proceeds
from the Sun Fee Well. On September 13, 2005, the Court
entered a Preliminary Injunction ordering Samson to return the
Company to pay status for the amounts upon which Samson had been
paying the Company prior to the filing of the suit. On
December 23, 2005, Samson filed a motion for summary
judgment on the Companys claims, to which the Company
filed its response on January 3, 2006, rigorously denying
that Samson has grounds in law or fact for the requested relief.
Further, on January 17, 2006, Samson filed a counterclaim
for an unspecified overpayment to the Company, which was
clarified by a subsequent filing on February 14, 2006, that
it was disputing the unit interest originally attributed to the
Company and now asserting that the Companys net revenue
unit interest is approximately 4.7%. On March 28, 2006, the
Court denied a motion by Samson to modify the present injunction
to allow payment upon the lower amount. The Company has also
filed additional claims against Samson for breach of contract or
reformation of the certain assignment issued by Samson to the
Company in April 2005 upon which Samson bases its present
counterclaim. The outcome of the litigation will determine
whether PYRs ownership in the Sun Fee Well consists of
(a) the 5.7% net revenue interest (consisting of a 5.19%
working and a 1.5% overriding royalty interest) that was
formerly the portion that was not contested by Samson and
represents the amount of the payments that Samson, as operator,
has been paying PYR and that PYR has been recording in its
financial statements; or (b) the 4.7% net revenue interest
that Samson asserted in its February 14, 2006 filing; or
(c) a net revenue interest higher than 5.7% as a result of
the Companys prevailing on part or all of its claims that
it owns an 8.33% working interest as well as an overriding
royalty interest greater than 1.5%. On September 15, 2006,
the U.S. District Court for the Eastern District of Texas
issued its ruling on the outstanding motions for summary
judgment that had been filed by both PYR and Samson. In its
ruling, the Court held (1) that Samson did not have
authority to pool PYRs 3.5% overriding royalty interest in
the Sun Fee Well into the Sidetrack Unit and, therefore, that
PYR is entitled to the full, undiluted interest in all
production from the Sun Fee Well based on this overriding
royalty; and (2) that, although Samson had authority to
pool PYRs working interest into the unit, PYR would be
able to maintain its claim for breach of contract against Samson
for joining non-productive acreage into the unit. The Court also
left for trial PYRs claims that Samson had also breached
the underlying agreements by failing to assign to PYR its
working interest in all properties as called for in the
underlying contracts and by failing to give PYR geologic and
other technical information applicable to the Sun Fee Well and
the Sidetrack Unit. The Court held that PYRs alternate
claim that Samson owed PYR a fiduciary duty in forming the
Sidetrack Unit was fully resolved by its other rulings.
Following a brief scheduling conference, the Court has requested
that the parties discuss next steps, including (i) resuming
the trial schedule for the issues and claims that remain
unresolved by the Courts order, (ii) the immediate appeal
on the rulings made to date in the order and/or
(iii) mediation of the issues in dispute.
F-16
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On August 11, 2006, the State District Court for Jefferson
County, Texas,
58th Judicial
District, issued a final summary judgment in the Companys
favor against Samson in Samsons suit to enjoin the
Companys drilling of the Tindall Well, located in
Jefferson County, Texas on property directly adjacent to and
east of the Sun Fee Well. As previously reported, on the grounds
that it had the exclusive right to serve as operator to drill
the proposed Tindall Well, Samson had filed suit to enjoin or
prevent the Company from drilling the planned well on the
approximately
400-acre
property in which the Company holds 100% of the oil and gas
interest. Upon mutual agreement of the parties, no appeal will
be taken from the final judgment.
On February 15, 2006, the Company filed a motion in the
on-going bankruptcy proceeding involving Venus Exploration
Company (Venus) in the U.S. Bankruptcy Court
for the Eastern District of Texas requesting that the Bankruptcy
Court uphold its Order of April 9, 2004 approving the
Companys purchase of Venus remaining assets free and
clear of any obligations under a pre-bankruptcy Operating
Agreement between Venus and Trail Mountain Inc. (Trail
Mountain) that required Venus and Trail Mountain to offer
each other participation in subsequently acquired oil and gas
properties. The Company believes and has asserted in its motion
that the pre-bankruptcy Operating Agreement was not listed among
the contracts that were assigned to it under the sale in and
under the approval of the Bankruptcy Court. Trail Mountain has
filed an adversary proceeding against the Company requesting
that the Bankruptcy Court find that the pre-bankruptcy Operating
Agreement was still effective and that the Company is obligated
to offer an opportunity to Trail Mountain to share in the lease
upon which the proposed Tindall well is to be drilled. If Trail
Mountain is successful, it will lead to a potential 50%
reduction in the Companys interest in the lease, but could
also lead to a corresponding assignment of interests in
properties acquired by Trail Mountain, including certain
properties assigned to the Sidetrack Unit. A ruling by the Court
should also clarify whether the parties rights to operate
their interests in the Cotton Creek Prospect are subject to an
existing operating agreement or are free to enter into a new
operating agreement. The parties have submitted the matter to
the Bankruptcy Court on motions for summary and partial summary
judgment.
The Company will continue to vigorously pursue and defend its
rights with respect to the foregoing matters.
Other
contractual obligations
The following table summarizes the Companys contractual
obligations, as of August 31, 2006 to make future payments
under its convertible notes payable and office lease for the
periods specified (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
Contractual Obligations
|
|
Total
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Convertible Notes
|
|
$
|
8,474
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
8,474
|
|
Office Leases
|
|
|
93
|
|
|
|
70
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Cash Obligations
|
|
$
|
8,567
|
|
|
$
|
70
|
|
|
$
|
23
|
|
|
$
|
8,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above schedule assumes convertible note interest payments
will be added to the principal amount (which is at the
discretion of the Company), and the entire balance will be paid
in full on maturity of May 24, 2009, and there will be no
conversion of debt to common stock.
Rent expense was approximately $101,000 and $57,000 for the
years ended August 31, 2006 and 2005, respectively.
Delay Rentals In conjunction with the
Companys working interests in undeveloped oil and gas
prospects, the Company must pay approximately $96,000 in delay
rentals and other costs during the fiscal year ending
August 31, 2007 to maintain the right to explore these
prospects. The Company continually evaluates its leasehold
interests, therefore certain leases may be abandoned by the
Company in the normal course of business.
Environmental Oil and gas producing
activities are subject to extensive Federal, state and local
environmental laws and regulations. These laws, which are
constantly changing, regulate the discharge of materials into
the
F-17
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
environment and may require the Company to remove or mitigate
the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their
future economic benefit. Expenditures that relate to an existing
condition caused by past operations and that have no future
economic benefits are expensed. Liabilities for expenditures of
a noncapital nature are recorded when environmental assessment
and/or
remediation is probable, and the costs can be reasonably
estimated.
Contingencies The Company may from
time to time be involved in various claims, lawsuits, disputes
with third parties, actions involving allegations of
discrimination, or breach of contract incidental to the
operations of its business. The Company is not currently
involved in any such incidental litigation which it believes
could have a materially adverse effect on its financial
condition or results of operations.
|
|
10.
|
Operations
by Geographic Area
|
Segment Information has been prepared in accordance with
SFAS No. 131, Disclosures About Segments of an
Enterprise and Related Information. The Company had two
geographic reporting segments within the oil and gas
exploration, development and production segment. Corporate
expenses are not allocated to the geographic segments. The
segment data present below was prepared on the same basis as the
Consolidated Financial Statements.
Year
ended August 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
United
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
States
|
|
|
Total
|
|
|
Corporate
|
|
|
Total
|
|
|
Revenue
|
|
$
|
10
|
|
|
$
|
10,309
|
|
|
$
|
10,319
|
|
|
$
|
|
|
|
$
|
10,319
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs
|
|
|
(15
|
)
|
|
|
(2,221
|
)
|
|
|
(2,236
|
)
|
|
|
|
|
|
|
(2,236
|
)
|
Net profits interest expense
|
|
|
|
|
|
|
(829
|
)
|
|
|
(829
|
)
|
|
|
|
|
|
|
(829
|
)
|
Depreciation, depletion and
amortization expense
|
|
|
|
|
|
|
(2,580
|
)
|
|
|
(2,580
|
)
|
|
|
|
|
|
|
(2,580
|
)
|
Asset retirement obligation
accretion
|
|
|
|
|
|
|
(22
|
)
|
|
|
(22
|
)
|
|
|
|
|
|
|
(22
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from operations
|
|
|
(5
|
)
|
|
|
4,657
|
|
|
|
4,652
|
|
|
|
|
|
|
|
4,652
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,256
|
)
|
|
|
(2,256
|
)
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14
|
)
|
|
|
(14
|
)
|
Interest income and other expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
259
|
|
|
|
259
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(371
|
)
|
|
|
(371
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) before income taxes
|
|
$
|
(5
|
)
|
|
$
|
4,657
|
|
|
$
|
4,652
|
|
|
$
|
(2,382
|
)
|
|
$
|
2,270
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, net
|
|
$
|
1
|
|
|
$
|
9,705
|
|
|
$
|
9,706
|
|
|
$
|
29
|
|
|
$
|
9,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$
|
16
|
|
|
$
|
20,405
|
|
|
$
|
20,421
|
|
|
$
|
45
|
|
|
$
|
20,466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-18
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Year
ended August 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
United
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
States
|
|
|
Total
|
|
|
Corporate
|
|
|
Total
|
|
|
Revenue
|
|
$
|
1
|
|
|
$
|
6,101
|
|
|
$
|
6,102
|
|
|
$
|
|
|
|
$
|
6,102
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs
|
|
|
(5
|
)
|
|
|
(1,099
|
)
|
|
|
(1,104
|
)
|
|
|
|
|
|
|
(1,104
|
)
|
Net profits interest expense
|
|
|
|
|
|
|
(1,343
|
)
|
|
|
(1,343
|
)
|
|
|
|
|
|
|
(1,343
|
)
|
Depreciation, depletion and
amortization expense
|
|
|
|
|
|
|
(860
|
)
|
|
|
(860
|
)
|
|
|
|
|
|
|
(860
|
)
|
Impairment of oil and gas
properties
|
|
|
(580
|
)
|
|
|
|
|
|
|
(580
|
)
|
|
|
|
|
|
|
(580
|
)
|
Asset retirement obligation
accretion
|
|
|
|
|
|
|
(25
|
)
|
|
|
(25
|
)
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from operations
|
|
|
(584
|
)
|
|
|
2,774
|
|
|
|
2,190
|
|
|
|
|
|
|
|
2,190
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,909
|
)
|
|
|
(1,909
|
)
|
Depreciation and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
|
|
(8
|
)
|
Interest income and other expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
|
|
|
|
82
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(343
|
)
|
|
|
(343
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) before income taxes
|
|
$
|
(584
|
)
|
|
$
|
2,774
|
|
|
$
|
2,190
|
|
|
$
|
(2,178
|
)
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
37
|
|
|
$
|
5,825
|
|
|
$
|
5,862
|
|
|
$
|
10
|
|
|
$
|
5,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
$
|
15
|
|
|
$
|
13,227
|
|
|
$
|
13,242
|
|
|
$
|
29
|
|
|
$
|
13,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11.
|
Estimate
of Proved Oil and Gas Reserves (Unaudited)
|
At August 31, 2006, the estimated oil and gas reserves
presented herein were derived from a report prepared by Ryder
Scott Company, an independent petroleum engineering firm. All
reserves are located within the continental United States. The
Company cautions that there are many inherent uncertainties in
estimating proved reserve quantities and in projecting future
production rates and the timing of development expenditures.
Accordingly, these estimates are likely to change as future
information becomes available, and these changes could be
material.
The oil and gas reserve estimates presented below include all
activity from the Companys oil and gas properties for 2006
and 2005. Proved oil and gas reserves are the estimated
quantities of crude oil, condensate, natural gas and natural gas
liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions.
Proved developed reserves are reserves expected to be recovered
through existing wells with existing equipment and operating
methods.
F-19
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Analysis Of Changes In Proved Reserves
Estimated quantities of proved developed and undeveloped
reserves, as well as the changes during the years ended
August 31, 2005 and 2006, are as follows:
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural
|
|
|
Natural
|
|
|
|
Gas Liquids
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
Proved reserves at
September 1, 2004
|
|
|
684,865
|
|
|
|
1,393,000
|
|
Purchase of reserves
|
|
|
|
|
|
|
1,610,852
|
|
Revisions of previous estimates
|
|
|
(80,027
|
)
|
|
|
171,634
|
|
Extensions and discoveries
|
|
|
23,475
|
|
|
|
884,579
|
|
Production
|
|
|
(62,289
|
)
|
|
|
(392,065
|
)
|
|
|
|
|
|
|
|
|
|
Proved reserves at August 31,
2005
|
|
|
566,024
|
|
|
|
3,668,000
|
|
Purchase of reserves
|
|
|
|
|
|
|
1,636,235
|
|
Revisions of previous estimates
|
|
|
(1,990
|
)
|
|
|
(914,767
|
)
|
Extensions and discoveries
|
|
|
122,627
|
|
|
|
2,264,505
|
|
Production
|
|
|
(58,317
|
)
|
|
|
(915,973
|
)
|
|
|
|
|
|
|
|
|
|
Proved reserves at August 31,
2006
|
|
|
628,344
|
|
|
|
5,738,000
|
|
|
|
|
|
|
|
|
|
|
Proved developed
reserves end of year
|
|
|
|
|
|
|
|
|
August 31, 2005
|
|
|
503,767
|
|
|
|
1,345,000
|
|
August 31, 2006
|
|
|
518,788
|
|
|
|
2,755,000
|
|
The table below sets forth a standardized measure of the
estimated discounted future net cash flows attributable to the
Companys proved oil and gas reserves. Estimated future
cash inflows were computed by applying year end
(August 31) prices of oil and gas (with consideration
of price changes only to the extent provided by contractual
arrangements) averaging $67.12 and $66.95 per Bbl of oil
and natural gas liquids and $5.49 and $11.74 per Mcf of gas
for 2006 and 2005, respectively, to the estimated future
production of proved oil and gas reserves. The future production
and development costs represent the estimated future
expenditures to be incurred in developing and producing the
proved reserves, assuming continuation of existing economic
conditions. Future corporate overhead expenses and interest
expense have not been included. Discounting the annual net cash
flows at 10% illustrates the impact of timing on these future
cash flows.
Standardized
Measure of Estimated Discounted Future Net Cash
Flows
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Future cash inflows
|
|
$
|
73,657
|
|
|
$
|
80,966
|
|
Future cash outflows:
|
|
|
|
|
|
|
|
|
Production cost(1)
|
|
|
(23,168
|
)
|
|
|
(24,168
|
)
|
Development cost
|
|
|
(4,237
|
)
|
|
|
(5,255
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash, before income
taxes
|
|
|
46,252
|
|
|
|
51,543
|
|
Future income taxes
|
|
|
(661
|
)
|
|
|
(813
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
45,591
|
|
|
|
50,730
|
|
Adjustment to discount future
annual net cash flows at 10%
|
|
|
(16,906
|
)
|
|
|
(21,978
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted
future net cash flows
|
|
$
|
28,685
|
|
|
$
|
28,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Production costs include lease operating expenses, production
and ad valorem taxes and net profits expense. |
F-20
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the principal factors comprising
the changes in the standardized measure of estimated discounted
net cash flows for the years ending August 31, 2006 and
2005, respectively.
Changes
in Standardized Measure of Estimated Discounted Net Cash
Flows
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands)
|
|
|
Standardized measure, beginning of
period
|
|
$
|
28,752
|
|
|
$
|
11,044
|
|
Sales of oil and gas, net of
production costs and taxes
|
|
|
(7,254
|
)
|
|
|
(3,655
|
)
|
Purchase of reserves in place
|
|
|
3,994
|
|
|
|
7,232
|
|
Net change in sales prices, net of
production cost
|
|
|
(13,628
|
)
|
|
|
10,062
|
|
Discoveries, extensions and
improved recoveries, net of future development cost
|
|
|
14,888
|
|
|
|
7,100
|
|
Development costs incurred
|
|
|
815
|
|
|
|
682
|
|
Change in future development costs
|
|
|
1,800
|
|
|
|
143
|
|
Revisions of quantity estimates
|
|
|
(3,266
|
)
|
|
|
(4,398
|
)
|
Changes in future income tax
|
|
|
70
|
|
|
|
(504
|
)
|
Accretion of discount
|
|
|
2,514
|
|
|
|
1,046
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure, end of period
|
|
$
|
28,685
|
|
|
$
|
28,752
|
|
|
|
|
|
|
|
|
|
|
F-21
EXHIBIT INDEX
|
|
|
|
|
Number
|
|
Description
|
|
|
3
|
.1*
|
|
Articles of Incorporation, filed
with the Maryland Secretary of State on June 18, 2001(1)
|
|
3
|
.2*
|
|
Articles of Merger, filed with the
Maryland Secretary of State on July 3, 2001 (1)
|
|
3
|
.3*
|
|
Bylaws(1)
|
|
4
|
.1*
|
|
Specimen Common Stock
Certificate(2)
|
|
4
|
.2*
|
|
Subscription and Registration
Rights Agreement between Wellington parties and the Company,
September 2005(3)
|
|
21
|
|
|
List of the Companys
Subsidiaries
|
|
23
|
.1
|
|
Consent of HEIN &
Associates LLP
|
|
23
|
.2
|
|
Consent of Ryder Scott Company
|
|
31
|
.1
|
|
Certification of Chief Executive
Officer
|
|
31
|
.2
|
|
Certification of Chief Financial
Officer
|
|
32
|
.1
|
|
Certification pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 by Chief
Executive Officer
|
|
32
|
.2
|
|
Certification pursuant to
18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 by Chief
Financial Officer
|
|
|
|
* |
|
Previously filed. |
|
(1) |
|
Incorporated by reference from the Companys
Form 10-KSB
for the year ended August 31, 2001. |
|
(2) |
|
Incorporated by reference from the Companys
Form 10-KSB/A1
for the year ended August 31, 1997. |
|
(3) |
|
Incorporated by reference from the Companys Report on
Form 8-K
filed on October 8, 2005. |