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 |
For the fiscal year ended August 31, 2005
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TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File No. 0-20879
PYR ENERGY CORPORATION
(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
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80202 |
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| (Address of principal executive offices)
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(Zip Code) |
Registrant’s 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 |
$.001 Par Value Common Stock
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American Stock Exchange |
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
registrant’s knowledge, in definitive proxy or information statements incorporated by reference in
Part III of this Form 10-KSB or any amendment to this Form 10-KSB.
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 registrant’s revenues for the fiscal year ended August 31, 2005 were $6.1 million. As of
November 15, 2005, the registrant had 37,968,259 common shares outstanding, and the aggregate
market value of the common shares held by non-affiliates was approximately $32,972,306*. This
calculation is based upon the closing sale price of $1.22 per share on November 15, 2005.
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Without asserting that any of the issuer’s directors or executive officers, or the entities that
own 10% or greater of the registrant’s 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
ITEM 1 and ITEM 2. DESCRIPTION OF BUSINESS AND PROPERTIES
General
PYR Energy Corporation (referred to as “PYR,” the “Company,” “we,” “us” and “our”) is an
independent oil and gas exploration and production company, engaged in the exploration, development
and acquisition of crude oil and natural gas reserves. The Company was incorporated in March 1996
in the state of Delaware under the name Mar Ventures Inc. Effective as of August 6, 1997, the
Company purchased all the ownership interests of PYR Energy, LLC, an oil and gas exploration
company. On November 12, 1997, the name of the Company was changed to PYR Energy Corporation.
Effective July 2, 2001, the Company was re-incorporated in Maryland through the merger of the
Company into a wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation. On
February 18, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC were formed as wholly
owned subsidiaries of PYR Energy Corporation. The purpose of these entities is to own and develop
certain assets related to designated individual exploration projects.
Our current focus is on the Rocky Mountain, Texas and Gulf Coast regions as described below.
During the fiscal years ended August 31, 2005 and 2004, we focused our exploration efforts on the
drilling phase of our high potential exploration projects in the Rocky Mountain and Gulf Coast
regions.
The Company’s offices are located at 1675 Broadway, Suite 2450, Denver, Colorado 80202. The
telephone number is (303) 825-3748, the facsimile number is (303) 825-3768 and the Company’s web
site is www.pyrenergy.com. The Company’s periodic and current reports filed with the Securities and
Exchange Commission (the “SEC”) can be found on the Company’s website at www.pyrenergy.com and on
the SEC’s website at www.sec.gov.
PROPERTIES AND BUSINESS ACTIVITIES
Oil and Gas Exploration and Development Activities
Our exploration and development activities are focused primarily in select areas of the
Rocky Mountains, Texas and the Gulf Coast. Advanced seismic imaging of the structural and
stratigraphic complexities common to these regions provides us with the enhanced ability to
identify significant oil and gas reserve potential. A number of these projects offer multiple
drilling opportunities with individual wells having the potential of encountering multiple
reservoirs. We are currently producing over 3 million cubic feet of gas equivalent per day and are
100% unhedged.
The following is a summary of our exploration and development areas and significant projects.
While actively pursuing specific exploration activities in each of the following areas, we
continually review additional opportunities in these core areas and in other areas that meet our
exploration criteria.
Texas and Gulf Coast Exploration:
In May 2004, we acquired interests from Venus Exploration, Inc. (“Venus”) in certain
producing properties with estimated proved reserves of 4.78 Bcfe for approximately $3.3 million
(excluding acquisition expenses and subject to retention, by the Venus Exploration Trust (“Trust”),
of a net profits interest covering specific exploration projects). This equated to $0.67 per Mcf,
with a PV-10 value of $6.94 million. The net profits interest that we are required to pay to the
Trust, which applies only to the exploration and exploitation projects on the Venus acreage
acquired, varies from 25% to 50% with respect to different Venus exploration and exploitation
project areas, and decreases by one-half of its original amount after a total of $3.3 million in
net profits proceeds has been paid to the Trust. Venus was in Chapter 11 Bankruptcy, and we
acquired the properties through public auction as approved by the United States Bankruptcy Court.
To finance the purchase, we primarily used existing cash reserves and a portion of the proceeds
from a private placement of common stock.
Oil and gas interests acquired from Venus include producing oil and gas properties,
exploitation drilling projects, and exploration acreage. The assets acquired include interests in
80 non-operated wells in Utah, Oklahoma and Texas.
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In Texas, we have interests in three wells that were drilled and completed during the summer
of 2004. Two of the three wells, located in the Nome and Madison Prospects, were completed as
producers and are currently flowing to sales lines. Both wells reached payout resulting in our
working interest being put into pay status. These two successful wells are subject to a net
profits interest agreement with the Venus Exploration Trust. The third well was not commercially
productive. This well is currently being re-evaluated.
Nome Field was discovered in 1994, and our interpretation of subsequently acquired 3D
seismic over the field indicates the presence of numerous undeveloped fault blocks. Multiple
structural closures and associated bright spot locations have been identified at Nome based on the
3D seismic. Production in the Sun Fee GU #1-ST well (the “Sun Fee Well”), from the upper Yegua,
was initiated in late May 2004, and beginning in early June 2005, averaged approximately 19MMcfe
per day. Cumulative production since inception is in excess of 6.4 Bcfe through end of August,
2005. 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 Gas Unit by the
operator, our current working interest in the well and associated lands is 5.19% with a 1.5%
overriding royalty interest. We and our partners control approximately 4,200 acres of gross
leasehold acres in the project. A drilling AFE has been circulated and approved for the drilling
of a well (Tindall #1) offsetting by approximately 1600 feet, the Sun Fee GU #1-ST. It is
anticipated that this development well will be drilled in early 2006. Our working interest in the
Tindall #1 is currently 77.08%.
We are currently in litigation with the operator of the Sun Fee Well, Samson Lone Star L.P.
(“Samson”), concerning, among other matters, Samson’s pooling of certain lands into the production
unit and corresponding reduction in PYR’s working interest. The outcome of the litigation will
determine whether PYR owns a 5.19% working interest and 1.5% overriding royalty interest, as arises
from Samson’s unit pooling, or an 8.33% working interest and an overriding royalty interest in
excess of 1.5%, in the Sun Fee well, as PYR believes it is entitled to. Even if we are not
successful in the litigation, the outcome will not result in a negative adjustment to our revenues
or production volumes because we have reported production and revenue only on the lower working
interest and the lower royalty interest in our financial and operating statements to date.
Additionally, this lower working interest and lower overriding royalty interest are undisputed, and
it is only the difference between the 5.19% and 8.33% working interests and associated overriding
royalty interests that are the subject of the ongoing litigation.
Both 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 the net profits interest agreement we hold
with Venus Exploration Trust (“Trust”). The net profits interest agreement arose out of our
acquisition of properties from Venus Exploration Inc. (“Venus”) in May 2004. The 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 interest
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.
Madison prospect, located in the northern part of the Constitution Field,
Jefferson County, Texas, is an exploitation project to test multiple sand intervals within the
expanded Yegua section, downthrown to a major growth fault. The Maness GU #1 well started
production in mid-August 2004, and since inception, the well has cumulative production in excess of
1.7 Bcfe, through end of August, 2005. Payout has been reached in the Maness GU #1 well, and PYR
has been placed in pay status with a 12.5% working interest. The well is currently producing at a
rate of approximately 5.60 MMcfe per day The operator has converted an existing well bore within
the project area into a water disposal well, and is planning to drill an offset development well
(Wall#1) in late 2005 or early 2006 depending on rig availability. We will participate for 12.5%
working interest in the drilling of this development well. Wells drilled in this prospect are
subject to a net profits interest agreement with the Venus Exploration Trust.
Tortuga Grande prospect, located in Smith County, Texas, is a project to test the
productivity of the Cotton Valley Sand section. The Chisum #1 well, operated by Carrizo Oil and
Gas Inc, is projected to a target depth of approximately 15,500 feet, and is designed to test a
potentially thicker section of Cotton Valley Sand in a more favorable structural position to the
Brady #1 well. As a result of certain parties in the well electing not to participate in the
drilling of the well, PYR exercised its rights to increase its working interest in the well to
28.57% working interest. The Chisum #1 well reached total drilling depth of approximately 15,850
feet. Log and core analysis of the Cotton Valley section revealed abundant sand
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thickness in the expanded ‘turtle’ section, but did not indicate commercial reservoir
properties. As a result, the operator recommended abandonment of the Cotton Valley section and
completion of multiple horizons in the Travis Peak and Rodessa formations. The Company is
participating in the completion of the Travis Peak and Rodessa with its 28.57% working interest.
PYR and its partners control approximately 9,800 acres of leasehold in the project. Pending
favorable results from the Chisum #1 completion, the Company anticipates drilling additional wells
to fully exploit the Travis Peak and Rodessa potential in the project area. Wells drilled in this
prospect are subject to a net profits interest agreement with the Venus Exploration Trust.
Cotton Creek prospect, located in Jefferson County, Texas, is adjacent to the Nome
project. The prospect is located approximately one mile west of the productive Sun Fee #1 well in
the same structural fault block. PYR owns a 50% working interest in the project and controls with
its partner approximately 500 acres of leasehold. It is anticipated that an initial test well will
be drilled in 2006. PYR will retain approximately 25% working interest in the well and intends to
farmout the remainder of its interest to an industry partner.
Merganser prospect, located in Leon County, Texas, targets Cotton Valley and Bossier
sandstone reservoirs in an undrilled structural feature defined by 3D seismic data. The prospect
occupies a fault-bounded salt-withdrawal trough resulting in potential significant thickening of
the Bossier and Cotton Valley sand sections. The prospect location is structurally and
stratigraphically downdip from Cotton Valley production as well as updip from recent Bossier
productive discoveries. PYR owns 100% of approximately 300 acres in the prospect.
Bayou Duralde Project, located in Evangeline Parish, LA, is an exploration program to
identify and drill potential gas reservoirs in Yegua/Cockfield channel complexes. PYR owns a 25%
working interest in the project and controls, along with its partner, in excess of 3,000 net acres
of leasehold. PYR intends to participate with a 15% cost bearing interest and farmout the
remainder of its working interest. It is anticipated that the initial test well at Bayou Duralde
will begin drilling operations in late 2005 or early 2006 depending on rig availability.
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the Wilburton Field in Latimer County, Oklahoma, the
Scharff #4-1 well was recently drilled
and completed in the Lower Atoka (Cecil) formation, which resulted in initial
production rates of up to 38 MMcf per day and is currently producing at an average rate of
approximately 19 MMcfe per day. The Scharff #5-1 well, an offset of the Scharff #4-1, commenced
drilling activity on September 13, 2005, and reached total drilling depth in early November 2005.
The Scharff #5-1 is currently undergoing completion activities, and is expected to be on-line by
the end of the calendar year. The operator has proposed drilling of an additional PUD location
(Scharff #6-1) which the Company has approved and will participate in the drilling of. PYR has a
2.42% working interest in these wells.
Hansford Project, located in Hansford County of the Texas panhandle, 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. Purchased originally as part of
the Venus Exploration acquisition, the Company has recently purchased additional working interest
in two wells and associated undeveloped acreage at Hansford. Approximately 47% working interest in
the Lackey #152-1 well and acreage, as well as 15% working interest in the Archer Trust well and
acreage, were purchased for approximately $440,000. The Company believes that several proved
undeveloped drilling opportunities targeting gas are available on the acreage that was purchased at
Hansford. Drilling was commenced on the Lackey Gas Unit #2, a proved
undeveloped location, on October 23, 2005.
The well has been drilled to total depth and is currently undergoing completion operations. The
Company has a 47.16% working interest in this well. The Company continues to attempt to acquire
additional working interest, acreage and operational control in the project area.
Rocky Mountain Exploration
Mallard Project. The 1-30 Duck Federal Sidetrack well commenced drilling in
mid-July 2004 and was temporarily suspended, due to winter drilling restrictions, in December 2004.
The wellbore was re-entered in early August 2005, and reached a total measured depth of 15,110’
on October 18, 2005 within the Lodgepole Formation. Based on analysis of drilling shows, open-hole
logs, and reservoir pressure measurements, the working interest partners decided to attempt a
completion of the well within the objective Mission Canyon Formation.
Casing has been run to total depth,
and the well has been perforate over the prospective zones, covering a gross interval of
approximately 900 feet. Following perforation, it is anticipated that we will employ an acid
stimulation treatment to clean up the formation and enhance productivity. The acid stimulation
will be similar to
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that commonly employed in other field wells within the Whitney Canyon-Carter Creek Field. We
expect to commence testing in late November, pending scheduling of necessary equipment and
personnel. The Mission Canyon is the primary producing zone within the nearby Whitney
Canyon-Carter Creek Field, which has produced over 2.1 Tcfe to date. It is believed that the 1-30
Duck Federal well has encountered the Whitney Canyon-Carter Creek accumulation, and likely
represents a development step out well. It is anticipated that PYR and the working interest
partners will acquire approximately 20 square miles of 3-D seismic data during the summer of 2006
in order to better delineate additional drilling opportunities in the area. PYR is participating
in the project with a 28.75% working interest.
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 5 miles southwest of our Cumberland prospect, was discovered in 1975 and
produced approximately 250 Bcfe prior to abandonment. We believe that significant remaining
recoverable gas reserves were stranded in Ryckman Creek upon abandonment. We are currently
analyzing production and geologic data to determine potential reserves in multiple zones, including
the Twin Creek, Nugget, and Thaynes Formations, in the field. Due to rig availability timing, it
is anticipated that re-development activity of the Ryckman Creek project will not occur until
sometime in 2006.
Montana Foothills Project. Following the plugging and abandonment of the 14063-12
Flesher Pass exploratory well in August 2005, Suncor Energy Natural Gas America, Inc. (SENGAI), the
project operator, has informed the Company that they do not intend to exercise their option to
drill an additional earning well on the acreage block. The Company is re-evaluating exploration
prospects associated with its undeveloped acreage in the project.
OTHER
San Joaquin Basin, California
Blizzard Prospect. This project is a 3D seismic derived exploration and
exploitation program offsetting the Rio Viejo field at the south end of the San Joaquin Basin. A
linear sand body, stratigraphically higher than any of the productive Rio Viejo sands, has been
identified, north of the field, on the seismic data and represents an exploration opportunity for
new reserves. Additionally, analysis of the seismic data over the field suggests that up to two
additional undrilled field exploitation locations may exist. PYR owns 100% of the prospect.
Bulldog Prospect. This project is a 2D seismically identified natural gas and
condensate prospect located adjacent to the giant Kettleman North Dome field in the San Joaquin
Basin. This prospect can be best characterized as a classic footwall fault trap, similar to the
many known footwall fault trap accumulations that have produced significant quantities of
hydrocarbons throughout the San Joaquin basin. We intend to sell down our working interest in this
project and retain a 25% to 50% working interest in the prospect acreage.
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. Our approach is to sell down
our working interest to industry partners, and retain a 25% to 50% working interest in this
prospect.
Canada
The Company’s Canadian oil and gas property investment is comprised principally of
non-producing acreage. During 2005, the Company decided to limit future expenditures in Canada.
The net book value of the Company’s investment in its Canadian properties was greater than the
estimated fair market value. In accordance with the full cost method of accounting, the Company
recorded a non-cash impairment of $580,000, an amount equal to the Company’s initial investment in
its Canadian oil and gas properties.
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Markets and Major Customers
Sales from our ownership interests in producing properties to major unaffiliated customers
(customers accounting for 10 percent or more of gross revenue), all representing purchasers of oil
and gas, for the years ended August 31, 2005 and 2004 are as follows:
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2005 |
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2004 |
Customer A |
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38 |
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Customer B |
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22 |
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Customer C |
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10 |
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Customer D |
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22 |
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Customer E |
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20 |
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Customer F |
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Customer G |
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The May 2004 acquisition of interests in certain producing properties from Venus Exploration,
Inc. resulted in the increase of oil and gas purchasers. We are not confined to, nor
dependent upon, any one purchaser or small group of purchasers. Accordingly, the loss of a single
purchaser would not materially affect the Company’s business because we believe we would be able to
find another purchaser.
Employees and Office Space
At August 31, 2005, we had nine full time employees. We believe that our relationship with
our employees is satisfactory. None of our employees is covered by a collective bargaining
agreement. We lease approximately 3,800 square feet of office space in Denver, Colorado for our
executive and administrative offices. We have an additional office in San Antonio, Texas, in which
we lease approximately 4,300 square feet.
Business Strategy
Our objective is to increase stockholder value per share by adding reserves, production, cash
flow, earnings and net asset value. To accomplish this objective, we intend to 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, |
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our expertise in advanced seismic imaging, and |
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our ability to identify suitable development and exploitation drilling opportunities. |
To implement our strategy, we seek to:
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Execute Exploration and Development Drilling on Our Undrilled
Projects. We control interests in several exploration projects in the Texas Gulf
Coast, select areas of the Rocky Mountains, and the San Joaquin Basin of California.
In the Rocky Mountains, our most notable projects are Mallard and Ryckman Creek located
in southwestern Wyoming. We are currently attempting completion of our Mallard
project. In the Texas Gulf Coast, we have interests in several exploration projects
and PUD (“Proved Undeveloped”) locations related to recent discoveries to be drilled in
the future. We are currently attempting completion of recently drilled wells at Tortuga
Grande and Hansford. |
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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
little cost, but strong operatorship, may be productive. |
Certain Definitions
Unless otherwise indicated in this document, oil equivalents are determined using the ratio of
six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids so that six
Mcf of natural gas are referred to as one barrel of oil equivalent.
AMI. Area of Mutual Interest
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil
or other liquid hydrocarbons.
Bbl/d. One Bbl per day
Bc/d. Barrels of condensate daily
Bcf. One Billion cubic feet of natural gas at standard atmospheric conditions.
Bcfe. One billion cubic feet equivalent of natural gas, calculated by converting oil to
equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.
Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being
equivalent to one barrel of oil.
Btu or British thermal unit. The quantity of heat required to raise the temperature of
one pound of water by one degree Fahrenheit.
Capital Expenditures. Costs associated with exploratory and development drilling (including
exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological,
geophysical and land related overhead expenditures; delay rentals; producing property
acquisitions; other miscellaneous capital expenditures; compression equipment and pipeline
costs.
Carried through the tanks. The owner of this type of interest in the drilling of a well
incurs no liability for costs associated with the well until the well is drilled, completed
and connected to commercial production/processing facilities.
Completion. The installation of permanent equipment for the production of oil or natural
gas.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural
gas reserve.
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Developed Acreage. The number of acres that are allocated or assignable to producing wells
or wells capable of production.
Development Well. A well drilled within the proved area of an oil or natural gas reservoir
to the depth of a stratigraphic horizon known to be productive.
Exploitation. The continuing development of a known producing formation in a previously
discovered field. To make complete or maximize the ultimate recovery of oil or natural gas
from the field by work including development wells, secondary recovery equipment or other
suitable processes and technology.
Exploration. The search for natural accumulations of oil and natural gas by any
geological, geophysical or other suitable means.
Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved
area, to find a new reservoir in a field previously found to be productive of oil or natural
gas in another reservoir, or to extend a known reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all
grouped on or related to the same individual geological structural feature and/or
stratigraphic condition.
Finding and Development Costs. The total capital expenditures, including acquisition costs,
and exploration and abandonment costs, for oil and gas activities divided by the amount of
proved reserves added in the specified period.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we
have a working interest.
Lease. An instrument which grants to another (the lessee) the exclusive right to enter to
explore for, drill for, produce, store and remove oil and natural gas on the mineral
interest, in consideration for which the lessor is entitled to certain rents and royalties
payable under the terms of the lease. Typically, the duration of the lessee’s authorization
is for a stated term of years and “for so long thereafter” as minerals are producing.
Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.
Mcf/d. One Mcf per day.
Mcfe. One thousand cubic feet equivalent of natural gas, calculated by converting oil to
equivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.
MMcf. One million cubic feet of natural gas.
Net Acres or Net Wells. A net acre or well is deemed to exist when the sum of our
fractional ownership working interests in gross acres or wells, as the case may be, equals
one. The number of net acres or wells is the sum of the fractional working interests owned
in gross acres or wells, as the case may be, expressed as whole numbers and fractions
thereof.
Operator. The individual or company responsible to the working interest owners for the
exploration, development and production of an oil or natural gas well or lease.
Participant Group. The individuals and/or companies that, together, comprise the ownership
of 100% of the working interest in a specific well or project.
PV-10 value. The present value of estimated future revenues to be generated from the
production of proved reserves calculated in accordance with SEC guidelines, net of
estimated lease operating expense, production taxes and future development costs, using
prices and costs as of the date of estimation without future escalation, without giving
effect to non-property related expenses such as general and administrative expenses, debt
service and depreciation, depletion and amortization or federal income taxes and discounted
using an annual discount rate of 10%.
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Productive well. A well that is found to be capable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of the production exceed production
expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical
or other data and also preliminary economic analysis using reasonably anticipated prices and
costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty to be
commercially recoverable in future years from known reservoirs under existing economic and
operating conditions.
Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion.
Re-entry. Entering an existing well bore to redrill or repair.
Reserves. Natural gas and crude oil, condensate and natural gas liquids on a net revenue
interest basis, found to be commercially recoverable.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible natural gas and/ or oil that is confined by impermeable rock or
water barriers and is separate from other reservoirs.
Royalty. An interest in an oil and natural gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased acreage, or of the
proceeds of the sale thereof, but generally does not require the owner to pay any portion of
the costs of drilling or operating the wells on the leased acreage. Royalties may be either
landowner’s royalties, which are reserved by the owner of the leased acreage at the time the
lease is granted, or overriding royalties, which are usually reserved by an owner of the
leasehold in connection with a transfer to a subsequent owner.
Sidetrack. An operation involving the use of a portion of an existing well to drill
a second hole at some desired angle into previously undrilled areas. From this directional
start, a new hole is drilled to the desired formation depth and casing is set in the new
hole and tied back to the casing from the existing well.
3-D Seismic. The method by which a three dimensional image of the earth’s subsurface is
created through the interpretation of reflection seismic data collected over a surface grid.
3-D seismic surveys allow for a more detailed understanding of the subsurface than do
conventional surveys and contribute significantly to field appraisal, exploitation and
production.
Undeveloped Acreage. Lease acres on which wells have not been drilled or completed to a
point that would permit the production of commercial quantities of oil and gas regardless of
whether or not such acreage contains proved reserves.
Working Interest. An interest in an oil and gas lease that gives the owner of the
interest the right to drill and produce oil and gas on the leased acreage and requires the
owner to pay a share of the costs of drilling and production operations. The share of
production to which a working interest owner is entitled will always be smaller than the
share of costs that the working interest owner is required to bear, with the balance of the
production accruing to the owners of royalties.
8
Production and Productive Wells
The following table summarizes the Company’s productive wells as of August 31, 2005.
Productive wells are producing wells and wells capable of production. Gross wells are the total
number of wells in which the Company has an interest. Net wells are the sum of the Company’s
respective fractional interests owned in the gross wells.
Productive Gas wells as of August 31, 2005
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Gross |
|
|
|
|
|
|
|
|
|
Net |
|
|
|
|
| Location |
|
Oil |
|
Gas |
|
Total |
|
Oil |
|
Gas |
|
Total |
Canada |
|
|
— |
|
|
|
1 |
|
|
|
1 |
|
|
|
— |
|
|
|
0.05 |
|
|
|
0.05 |
|
| |
California |
|
|
3 |
|
|
|
— |
|
|
|
3 |
|
|
|
0.24 |
|
|
|
— |
|
|
|
0.24 |
|
| |
Oklahoma |
|
|
17 |
|
|
|
23 |
|
|
|
40 |
|
|
|
2.86 |
|
|
|
0.75 |
|
|
|
3.61 |
|
| |
Texas |
|
|
20 |
|
|
|
13 |
|
|
|
33 |
|
|
|
4.42 |
|
|
|
3.65 |
|
|
|
8.07 |
|
| |
Utah |
|
|
5 |
|
|
|
— |
|
|
|
5 |
|
|
|
1.68 |
|
|
|
— |
|
|
|
1.68 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
|
|
45 |
|
|
|
37 |
|
|
|
82 |
|
|
|
9.20 |
|
|
|
4.45 |
|
|
|
13.65 |
|
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, 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. As of November 2005, one of the exploration
wells in Wyoming was plugged and abandoned (10% WI), while the other well (28.75%
WI), located in the Mallard Prospect, is currently being completed. The exploration
well in East Texas (28.75% WI) is currently undergoing completion activities, and
the two development wells in Oklahoma (28.98% WI and 2.42% WI) were drilled and
completed as producers. Additionally in fiscal year 2005, the Company participated
in several well workovers in Texas and Oklahoma. |
| |
| |
• |
|
During the fiscal year ended August 31 2004, we participated in the drilling of
two exploration wells in the expanded Yegua trend of South Texas (carried), one
exploration well in the Cotton Valley section of East Texas, one exploration well in
the Wyoming Overthrust (5% WI with carry), and one exploration well in SE Alberta.
As of November 2004, the two exploration wells in South Texas have been classified
as discoveries and are producing into sales lines. The BLM suspended drilling
operations of the well in Wyoming (Mallard Prospect) in December, 2004 for a period
of five and half months, and the well in Southeast Alberta was tested and determined
to be non-productive. Additionally in fiscal year 2004, the Company participated in
several well workovers in Texas, Oklahoma, and Utah. |
Although there is no assurance that any additional wells will be drilled, we anticipate we may
drill additional exploration and development wells during fiscal 2006 on our projects in the Texas
Gulf Coast and Rocky Mountains. The actual number of wells drilled will be dependent on several
factors, including the results of our ongoing exploration efforts and the availability of capital.
Reserves
For fiscal years 2005 and 2004, our proved reserve estimates for our United States oil and gas
properties were prepared by Ryder Scott Company, 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.
9
At August 31, 2005, our total proved reserves were 7.064 Bcfe, which represents a 28% increase
over August 31, 2004 estimated total proved reserves of 5.502 Bcfe. Increased estimates for total
proved reserves result from revisions on multiple properties
including new proved developed producing and proved undeveloped additions
related to exploration drilling in the expanded Yegua trend of south Texas. As of August 31, 2005,
proved developed producing reserves are estimated at 3.908 Bcfe, while proved developed
non-producing reserves are estimated at .459 Bcfe. Proved undeveloped reserves are estimated at
2.697 Bcfe. At August 31, 2003, the Company had no proved reserves. The Company’s 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, as of August 31, 2005
as compared to approximately $11.0 million for total proved reserves as of August 31, 2004. This
increase in present value is a reflection of higher prices at fiscal year end plus reserve
additions and revisions. 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 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.
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 2005 and 2004.
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 pool
as a result of an unsuccessful project without commercial oil and gas production. For
the years ended August 31, 2005 and 2004, no property impairment charges were recorded for the
Company’s United States properties.
In accordance with the full cost method of accounting, the Company’s 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 estimated fair market value of such properties. The Company decided to
limit future expenditures in Canada. For the year ended August 31, 2004, no property impairment
charges were recorded for the Company’s Canadian properties.
10
Acreage
We currently control through lease, farmout, and option, the following approximate acreage position
as detailed below:
Developed And Undeveloped Acreage
As of August 31, 2005
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Gross Acres |
|
|
Net Acres |
|
| State |
|
Developed |
|
|
Undeveloped |
|
|
Developed |
|
|
Undeveloped |
|
| |
California |
|
|
400 |
|
|
|
13,000 |
|
|
|
33 |
|
|
|
13,000 |
|
| |
Canada |
|
|
640 |
|
|
|
5,000 |
|
|
|
32 |
|
|
|
250 |
|
| |
Louisiana |
|
|
— |
|
|
|
2,665 |
|
|
|
— |
|
|
|
2,615 |
|
| |
Montana(1) |
|
|
— |
|
|
|
241,800 |
|
|
|
— |
|
|
|
226,300 |
|
| |
Oklahoma |
|
|
5,659 |
|
|
|
— |
|
|
|
197 |
|
|
|
— |
|
| |
Texas |
|
|
25,633 |
|
|
|
6,391 |
|
|
|
9,610 |
|
|
|
5,305 |
|
| |
Utah |
|
|
4,943 |
|
|
|
— |
|
|
|
1,504 |
|
|
|
— |
|
| |
Wyoming |
|
|
— |
|
|
|
8,353 |
|
|
|
— |
|
|
|
8,353 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL |
|
|
37,275 |
|
|
|
277,209 |
|
|
|
11,376 |
|
|
|
255,823 |
|
|
|
|
| (1) |
|
The Company is re-evaluating exploration prospects associated with its
undeveloped acreage in the Montana Foothills Project and subsequent to August 31,
2005, has elected to release some of the undeveloped acreage reflected in the table
above. |
Competition
We compete with numerous companies in virtually all facets of our business, including many
companies that have significantly greater resources. These competitors may be able to pay more for
desirable leases and to evaluate, bid for and purchase a greater number of properties than our
financial or personnel resources permit. Our ability to establish and increase reserves in the
future will be dependent on our ability to select and acquire suitable producing properties and
prospects for future exploration and development. The availability of a market for oil and gas
production depends upon numerous factors beyond the control of producers, including but not limited
to the availability of other domestic or imported production, the locations and capacity of
pipelines, and the effect of federal and state regulation on that production.
Government Regulation of the Oil and Gas Industry
General. Our business is affected by numerous laws and regulations, including energy,
environmental, conservation, tax and other laws and regulations relating to the energy industry.
Failure to comply with these laws and regulations may result in the assessment of administrative,
civil and criminal penalties, the imposition of injunctive relief or both. Moreover, changes in
any of these laws and regulations could have a material adverse effect on our business. In view of
the many uncertainties with respect to current and future laws and regulations, including their
applicability to us, we cannot predict the overall effect of such laws and regulations on our
future operations.
We do not currently operate any properties. We believe that operations where we own interests
comply in all material respects with applicable laws and regulations and that the existence and
enforcement of these laws and regulations have no more restrictive an effect on our operations than
on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and regulations and is qualified
in its entirety by the foregoing and by reference to the full text of the laws and regulations
described.
Federal Regulation of the Sale and Transportation of Oil and Gas. Various aspects of our oil
and gas operations are or will be regulated by agencies of the federal government. The Federal
Energy Regulatory Commission, or FERC, regulates the transportation and sale for resale of natural
gas in interstate commerce pursuant to the Natural Gas Act of 1938, or NGA, and the
11
Natural Gas Policy Act of 1978, or NGPA. In the past, the federal government has regulated
the prices at which oil and gas could be sold. While ''first sales’’ by producers of natural gas,
and all sales of crude oil, condensate and natural gas liquids can currently be made at
uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989,
Congress enacted the Natural Gas Wellhead Decontrol Act.
The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead
sales of natural gas effective January 1, 1993, and resulted in a series of Orders being issued by
FERC requiring interstate pipelines to provide transportation services separately, or
''unbundled,’’ from the pipelines’ sales of gas and to provide open access transportation on a
nondiscriminatory basis that is equal for all natural gas shippers.
We do not believe that we will be affected by these or any other FERC rules or orders
materially differently than other natural gas producers and marketers with which we compete.
The FERC also has issued numerous orders confirming the sale and abandonment of natural gas
gathering facilities previously owned by interstate pipelines and acknowledging that if the FERC
does not have jurisdiction over services provided on those facilities, then those facilities and
services may be subject to regulation by state authorities in accordance with state law. A number
of states have either enacted new laws or are considering the adequacy of existing laws affecting
gathering rates and/or services. Other state regulation of gathering facilities generally includes
various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but
does not generally entail rate regulation. Thus, natural gas gathering may receive greater
regulatory scrutiny of state agencies in the future. Our anticipated gathering operations could be
adversely affected should they be subject in the future to increased state regulation of rates or
services, although we do not believe that we would be affected by such regulation any differently
than other natural gas producers or gatherers. In addition, the FERC’s approval of transfers of
previously-regulated gathering systems to independent or pipeline affiliated gathering companies
that are not subject to FERC regulation may affect competition for gathering or natural gas
marketing services in areas served by those systems and thus may affect both the costs and the
nature of gathering services that will be available to interested producers or shippers in the
future.
We conduct certain operations on federal oil and gas leases, which are administered by the
Minerals Management Service, or MMS. Federal leases contain relatively standard terms and require
compliance with detailed MMS regulations and orders, which are subject to change. Among other
restrictions, the MMS has regulations restricting the flaring or venting of natural gas, and has
proposed to amend those regulations to prohibit the flaring of liquid hydrocarbons and oil without
prior authorization. Under certain circumstances, the MMS may require any of our operations on
federal leases to be suspended or terminated. Any such suspension or termination could materially
and adversely affect our financial condition, cash flows and operations. The MMS issued a final
rule that amended its regulations governing the valuation of crude oil produced from federal
leases. This rule, which became effective June 1, 2000, provides that the MMS will collect
royalties based on the market value of oil produced from federal leases, and was further modified
by amendments to the June 2000 MMS rules, effective July 1, 2004. Also, there is currently pending
new proposed MMS Federal Gas Valuation rules concerning calculation of transportation costs,
including the allowed rate of return in the calculation of actual transportation costs in non-arm’s
length arrangements. We cannot predict whether this new gas rule will become effective, nor can
we predict whether the MMS will take further action on oil and gas valuation matters. However, we
do not believe that any such rules will affect us any differently than other producers and
marketers of crude oil with which we will compete.
Additional proposals and proceedings that might affect the oil and gas industry are pending
before Congress, the FERC, the MMS, state commissions and the courts. We cannot predict when or
whether any such proposals may become effective. In the past, the natural gas industry has been
heavily regulated. There is no assurance that the regulatory approach currently pursued by various
agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that
compliance with existing federal, state and local laws, rules and regulations will have a material
or significantly adverse effect upon our capital expenditures, earnings or competitive position.
No material portion of our business is subject to re-negotiation of profits or termination of
contracts or subcontracts at the election of the federal government.
State Regulation. Our operations also are subject to regulation at the state and, in some
cases, county, municipal and local governmental levels. This regulation includes requiring permits
for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled, the plugging and abandonment of wells and
the disposal of fluids used and produced in connection with operations. Our operations also are or
will be subject to various conservation laws and regulations.
12
These include (1) the size of drilling and spacing units or proration units, (2) the density
of wells that may be drilled, and (3) the unitization or pooling of oil and gas properties. In
addition, state conservation laws, which frequently establish maximum rates of production from oil
and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. State regulation of gathering facilities generally
includes various safety, environmental and, in some circumstances, nondiscriminatory take
requirements, but (except as noted above) does not generally entail rate regulation. These
regulatory burdens may affect profitability, but we are unable to predict the future cost or impact
of complying with such regulations.
Environmental Matters. Operations on properties in which we have an interest are subject to
extensive federal, state and local environmental laws that regulate the discharge or disposal of
materials or substances into the environment and otherwise are intended to protect the environment.
Numerous governmental agencies issue rules and regulations to implement and enforce such laws,
which are often difficult and costly to comply with and which carry substantial administrative,
civil and criminal penalties and in some cases injunctive relief for failure to comply. Some laws,
rules and regulations relating to the protection of the environment may, in certain circumstances,
impose ''strict liability’’ for environmental contamination. These laws render a person or company
liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills
in certain states, consequential damages without regard to negligence or fault. Other laws, rules
and regulations may require the rate of oil and gas production to be below the economically optimal
rate or may even prohibit exploration or production activities in environmentally sensitive areas.
In addition, state laws often require some form of remedial action, such as closure of inactive
pits and plugging of abandoned wells, to prevent pollution from former or suspended operations.
Legislation has been proposed in the past and continues to be evaluated in Congress from time to
time that would reclassify certain oil and gas exploration and production wastes as ''hazardous
wastes.’’ This reclassification would make these wastes subject to much more stringent storage,
treatment, disposal and clean-up requirements, which could have a significant adverse impact on
operating costs. Initiatives to further regulate the disposal of oil and gas wastes are also
proposed in certain states from time to time and may include initiatives at the county, municipal
and local government levels. These various initiatives could have a similar adverse impact on
operating costs. The regulatory burden of environmental laws and regulations increases our cost
and risk of doing business and consequently affects our profitability.
The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,
also known as the ''Superfund’’ law, imposes liability, without regard to fault, on certain classes
of persons with respect to the release of a ''hazardous substance’’ into the environment. These
persons include the current or prior owner or operator of the disposal site or sites where the
release occurred and companies that transported, disposed or arranged for the transport or disposal
of the hazardous substances found at the site. Persons who are or were responsible for releases of
hazardous substances under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the environment and for damages
to natural resources, and it is not uncommon for the federal or state government to pursue such
claims. It is also not uncommon for neighboring landowners and other third parties to file claims
for personal injury or property or natural resource damages allegedly caused by the hazardous
substances released into the environment. Under CERCLA, certain oil and gas materials and products
are, by definition, excluded from the term ''hazardous substances.’’ At least two federal courts
have held that certain wastes associated with the production of crude oil may be classified as
hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and
Recovery Act, or RCRA, which governs the generation, treatment, storage and disposal of ''solid
wastes’’ and ''hazardous wastes,’’ certain oil and gas materials and wastes are exempt from the
definition of ''hazardous wastes.’’ This exemption continues to be subject to judicial
interpretation and increasingly stringent state interpretation. During the normal course of
operations on properties in which we have an interest, exempt and non-exempt wastes, including
hazardous wastes, that are subject to RCRA and comparable state statutes and implementing
regulations are generated or have been generated in the past. The federal Environmental Protection
Agency and various state agencies continue to promulgate regulations that limit the disposal and
permitting options for certain hazardous and non-hazardous wastes.
Our operations will involve the use of gas fired compressors to transport collected gas.
These compressors are subject to federal and state regulations for the control of air emissions.
Title V status for a facility results in significant increased testing, monitoring and
administrative and compliance costs. To date, other compressor facilities have not triggered Title
V requirements due to the design of the facility and the use of state-of-the-art engines and
pollution control equipment that serve to reduce air emissions. However, in the future, additional
facilities could become subject to Title V requirements as compressor facilities are expanded or if
regulatory interpretations of Title V applicability change. Stack testing and emissions monitoring
costs will grow as these facilities are expanded and if they trigger Title V. We believe that the
operator of the properties in which we have an interest is in substantial compliance with
applicable laws, rules and regulations relating to the control of air emissions at all facilities
on those properties.
13
Although we maintain insurance against some, but not all, of the risks described above,
including insuring the costs of clean-up operations, public liability and physical damage, there is
no assurance that our insurance will be adequate to cover all such costs, that the insurance will
continue to be available in the future or that the insurance will be available at premium levels
that justify our purchase. The occurrence of a significant event not fully insured or indemnified
against could have a material adverse effect on our financial condition and operations.
Compliance with environmental requirements, including financial assurance requirements and the
costs associated with the cleanup of any spill, could have a material adverse effect on our capital
expenditures, earnings or competitive position. We do believe, however, that our operators are in
substantial compliance with current applicable environmental laws and regulations. Nevertheless,
changes in environmental laws have the potential to adversely affect operations. At this time, we
have no plans to make any material capital expenditures for environmental control facilities.
Title to Properties
As is customary in the oil and gas industry, only a preliminary title examination is conducted
at the time we acquire leases or enter into other agreements to obtain control over interests in
acreage believed to be suitable for drilling operations. In many instances, our partners have
acquired rights to the prospective acreage and we have a contractual right to have our interests in
that acreage assigned to us. In some cases, we are in the process of having those interests so
assigned. Prior to the commencement of drilling operations, a thorough title examination of the
drill site tract is conducted by independent attorneys. Once production from a given well is
established, the operator will prepare a division order title report indicating the proper parties
and percentages for payment of production proceeds, including royalties. We believe that titles to
our leasehold properties are good and defensible in accordance with standards generally acceptable
in the oil and gas industry.
Risk Factors
In evaluating the Company, careful consideration should be given to the following risk
factors, in addition to the other information included or incorporated by reference in this annual
report. In addition, the ''Forward-Looking Statements’’ located herein, describe additional
uncertainties associated with our business and the forward-looking statements included or
incorporated by reference. Each of these risk factors could adversely affect our business,
operating results and financial condition, as well as adversely affect the value of an investment
in our common stock.
We have a limited operating history in the oil and gas business. Our operations to date have
consisted solely of evaluating geological and geophysical information, acquiring acreage positions,
generating exploration prospects, and drilling a limited number of wells on deep oil and gas
prospects. We currently have nine full-time employees. Our future financial results depend
primarily on (1) our ability to discover commercial quantities of oil and gas; (2) the market price
for oil and gas; (3) our ability to continue to generate potential exploration prospects; and (4)
our ability to fully implement our exploration and development program. We cannot predict that our
future operations will be profitable. In addition, our operating results may vary significantly
during any financial period. These variations may be caused by significant periods of time between
discovery and development of oil or gas reserves, if any, in commercial quantities.
Our cash resources are not unlimited. We need to increase our sources of revenue and/or
funding in order to sustain operations for the long run. There is no assurance that this will
occur.
We may not discover commercially productive reserves. Our future success depends on our
ability to economically locate oil and gas reserves in commercial quantities. Except to the extent
that we acquire properties containing proved reserves or that we conduct successful exploration and
development activities, or both, our proved reserves, if any, will decline as reserves are
produced. Our ability to locate reserves is dependent upon a number of factors, including our
participation in multiple exploration projects and our technological capability to locate oil and
gas in commercial quantities. We cannot predict that we will have the opportunity to participate
in projects that economically produce commercial quantities of oil and gas in amounts necessary to
meet our business plan or that the projects in which we elect to participate will be successful.
There can be no assurance that our planned projects will result in significant reserves or that we
will have future success in drilling productive wells at economical reserve replacement costs.
14
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:
| |
• |
|
unexpected drilling conditions, |
| |
| |
• |
|
pressure or irregularities in formations, |
| |
| |
• |
|
equipment failures or accidents, |
| |
| |
• |
|
adverse weather conditions, |
| |
| |
• |
|
compliance with governmental requirements, |
| |
| |
• |
|
shortages or delays in the availability of drilling rigs and the delivery of equipment, and |
| |
| |
• |
|
shortages of trained oilfield service personnel. |
Our future drilling activities may not be successful, nor can we be sure that our overall
drilling success rate or our drilling success rate for activities within a particular area will not
decline. Unsuccessful drilling activities could have a material adverse effect on our results of
operations and financial condition. Also, we may not be able to obtain any options or lease rights
in potential drilling locations that we identify. Although we have identified a number of
potential exploration projects, we cannot be sure that we will ever drill them or that we will
produce oil or gas from them or any other potential exploration projects.
Our exploration and development activities are subject to reservoir and operational risks.
Even when oil and gas is found in what is believed to be commercial quantities, reservoir risks,
which may be heightened in new discoveries, may lead to increased costs and decreased production.
These risks include the inability to sustain deliverability at commercially productive levels as a
result of decreased reservoir pressures, large amounts of water, or other factors that might be
encountered. As a result of these types of risks, most lenders will not loan funds secured by
reserves from newly discovered reservoirs, which would have a negative impact on our future
liquidity. Operational risks include hazards such as fires, explosions, craterings, blowouts (such
as the blowout experienced at our initial exploratory well), uncontrollable flows of oil, gas or
well fluids, pollution, releases of toxic gas and encountering formations with abnormal pressures.
In addition, we may be liable for environmental damage caused by previous owners of property we own
or lease. As a result, we may face substantial liabilities to third parties or governmental
entities, which could reduce or eliminate funds available for exploration, development or
acquisitions or cause us to incur substantial losses.
We expect to maintain insurance against some, but not all, of the risks associated with
drilling and production in amounts that we believe to be reasonable in accordance with customary
industry practices. The occurrence of a significant event, however, that is not fully insured
could have a material adverse effect on our financial condition and results of operations.
Our operations require large amounts of capital. Our current development plans will require
us to make large capital expenditures for the exploration and development of our oil and gas
projects. Under our current capital expenditure budget, we expect to spend between $7.5 and $10.0
million on exploration and development activities during our fiscal year ending August 31, 2006.
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:
| |
• |
|
our success in locating and producing reserves in other projects, |
| |
| |
• |
|
the level of production from existing wells, and |
| |
| |
• |
|
prices of oil and gas. |
Issuing equity securities to satisfy our financing requirements could cause substantial
dilution to our existing stockholders. Debt financing, if obtained, could lead to:
| |
• |
|
a substantial portion of our operating cash flow being dedicated to the payment of principal and interest, |
| |
| |
• |
|
our being more vulnerable to competitive pressures and economic downturns, and |
| |
| |
• |
|
restrictions on our operations. |
15
If our revenues were to decrease due to lower oil and gas prices, decreased production or
other reasons, and if we could not obtain capital through a credit facility or otherwise, our
ability to execute our development plans, obtain and replace reserves, or maintain production
levels could be greatly limited.
We depend heavily on exploration success and subsequent success in developing our exploration
projects. Our future growth plans rely heavily on discovering reserves and initiating production
in the San Joaquin Basin, Texas, Gulf Coast and in the Rocky Mountains. Our development plan
includes the need to discover reserves and establish commercial production through exploratory
drilling and development of our existing properties. We cannot be sure, though, that our planned
projects will lead to significant reserves that can be economically extracted or that we will be
able to drill productive wells at anticipated finding and development costs. If we are able to
record reserves, our reserves will decline as they are depleted, except to the extent that we
conduct successful exploration or development activities or acquire other properties containing
proved reserves.
We depend on industry alliances. We attempt to limit financial exposure on a
project-by-project basis by forming industry alliances where our technical expertise can be
complemented with the financial resources and operating expertise of more established companies.
While entering into these alliances limits our financial exposure, it also limits our potential
revenue from successful projects. Industry alliances also have the potential to expose us to
uncertainty if our industry partners are acquired or have priorities in areas other than our
projects. Despite these risks, we believe that if we are not able to form industry alliances, our
ability to fully implement our business plan could be limited, which could have a material adverse
effect on our business.
Our non-operator status limits our control over our oil and gas projects. We focus primarily
on creating exploration opportunities and forming industry alliances to develop those
opportunities. As a result, we have only a limited ability to exercise control over a significant
portion of a project’s operations or the associated costs of those operations. The success of a
project is dependent upon a number of factors that are outside our areas of expertise and control.
These factors include:
| |
• |
|
the availability of leases with favorable terms and the availability of
required permitting for projects, |
| |
| |
• |
|
the availability of future capital resources to us and the other
participants to be used for purchasing leases and drilling wells, |
| |
| |
• |
|
the approval of other participants for the purchasing of leases and the
drilling of wells on the projects, and |
| |
| |
• |
|
the economic conditions at the time of drilling, including the prevailing
and anticipated prices for oil and gas. |
Our reliance on other project participants and our limited ability to directly control project
costs could have a material adverse effect on our expected rates of return.
Oil and gas prices are volatile and an extended decline in prices could hurt our business
prospects. Our future profitability and rate of growth and the anticipated carrying value of our
oil and gas properties will depend heavily on then prevailing market prices for oil and gas. We
expect the markets for oil and gas to continue to be volatile. If we are successful in continuing
to establish production, any substantial or extended decline in the price of oil or gas could:
| |
• |
|
have a material adverse effect on our results of operations, |
| |
| |
• |
|
limit our ability to attract capital, |
| |
| |
• |
|
make the formations we are targeting significantly less economically attractive, |
| |
| |
• |
|
reduce our cash flow and borrowing capacity, and |
| |
| |
• |
|
reduce the value and the amount of any future reserves. |
Various factors beyond our control will affect prices of oil and gas, including:
| |
• |
|
worldwide and domestic supplies of oil and gas, |
| |
| |
• |
|
the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls, |
| |
| |
• |
|
political instability or armed conflict in oil or gas producing regions, |
| |
| |
• |
|
the price and level of foreign imports, |
| |
| |
• |
|
worldwide economic conditions, |
| |
| |
• |
|
marketability of production, |
16
| |
• |
|
the level of consumer demand, |
| |
| |
• |
|
the price, availability and acceptance of alternative fuels, |
| |
| |
• |
|
the availability of processing and pipeline capacity, |
| |
| |
• |
|
weather conditions, and |
| |
| |
• |
|
actions of federal, state, local and foreign authorities. |
These external factors and the volatile nature of the energy markets make it difficult to
estimate future prices of oil and gas. In addition, sales of oil and gas are seasonal in nature,
leading to substantial differences in cash flow at various times throughout the year.
Accounting rules may require write-downs. Under full cost accounting rules, capitalized costs
of proved oil and gas properties may not exceed the present value of estimated future net revenues
from proved reserves, discounted at 10%. Application of the ceiling test generally requires
pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and
requires a write-down for accounting purposes if the ceiling is exceeded. If a write-down is
required, it would result in a charge to earnings, but would not impact cash flow from operating
activities. Once incurred, a write-down of oil and gas properties is not reversible at a later
date.
We face risks related to title to the leases we enter into that may result in additional costs
and affect our operating results. It is customary in the oil and gas industry to acquire a
leasehold interest in a property based upon a preliminary title investigation. In many instances,
our partners have acquired rights to the prospective acreage and we have a contractual right to
have our interests in that acreage assigned to us. In some cases, we are in the process of having
those interests so assigned. If the title to the leases acquired is defective, or title to the
leases one of our partners acquires for our benefit is defective, we could lose the money already
spent on acquisition and development, or incur substantial costs to cure the title defect,
including any necessary litigation. If a title defect cannot be cured or if one of our partners
does not assign to us our interest in a lease acquired for our benefit, we will not have the right
to participate in the development of or production from the leased properties. In addition, it is
possible that the terms of our oil and gas leases may be interpreted differently depending on the
state in which the property is located. For instance, royalty calculations can be substantially
different from state to state, depending on each state’s interpretation of lease language
concerning the costs of production. We cannot guarantee that there will be no litigation
concerning the proper interpretation of the terms of our leases. Adverse decisions in any
litigation of this kind could result in material costs or the loss of one or more leases.
Limitations on the Effectiveness of Controls. Our management, including our Chief Executive
Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal
controls will prevent all possible error or fraud. A control system, no matter how well conceived
and operated, can provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Further the design of a control system must reflect the fact that there
are resource constraints, and the benefits of controls must be considered relative to their costs.
Because of the inherent limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any, within our company have
been detected. These inherent limitations include the realities that judgments in decision making
can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally,
controls can be circumvented by the individual acts of some persons, by collusion of two or more
people, or by management override of the control. The design of any system of controls also is
based in part upon certain assumptions about the likelihood of future events, and there can be no
assurance that any design will succeed in achieving its stated goals under all potential future
conditions; over time, controls may become inadequate because of changes in conditions, or the
degree of compliance with the policies or procedures may deteriorate. Because of the inherent
limitations in a cost-effective control system, misstatements due to error or fraud may occur and
not be detected.
Our industry is highly competitive and many of our competitors have more resources than we do.
We compete in oil and gas exploration with a number of other companies. Many of these competitors
have financial and technological resources vastly exceeding those available to us. We cannot be
sure that we will be successful in acquiring and developing profitable properties in the face of
this competition. In addition, from time to time, there may be competition for, and shortage of,
exploration, drilling and production equipment. These shortages could lead to an increase in costs
and delays in operations that could have a material adverse effect on our business and our ability
to develop our properties. Problems of this nature also could prevent us from producing any oil
and gas we discover at the rate we desire to do so.
Technological changes could put us at a competitive disadvantage. The oil and gas industry is
characterized by rapid and significant technological advancements and introductions of new products
and services using new technologies. As new
17
technologies develop, we may be placed at a competitive disadvantage, and competitive
pressures may force us to implement those new technologies at a substantial cost. If other oil and
gas exploration and development companies implement new technologies before we do, those companies
may be able to provide enhanced capabilities and superior quality compared with what we are able to
provide. We may not be able to respond to these competitive pressures and implement new
technologies on a timely basis or at an acceptable cost. If we are unable to utilize the most
advanced commercially available technologies, our business could be materially and adversely
affected.
Our industry is heavily regulated. Federal, state and local authorities extensively regulate
the oil and gas industry. Legislation and regulations affecting the industry are under constant
review for amendment or expansion, raising the possibility of changes that may affect, among other
things, the pricing or marketing of oil and gas production. State and local authorities regulate
various aspects of oil and gas drilling and production activities, including the drilling of wells
(through permit and bonding requirements), the spacing of wells, the unitization or pooling of oil
and gas properties, environmental matters, safety standards, the sharing of markets, production
limitations, plugging and abandonment, and restoration. The overall regulatory burden on the
industry increases the cost of doing business, which, in turn, decreases profitability.
Our operations must comply with complex environmental regulations. Our operations are subject
to complex and constantly changing environmental laws and regulations adopted by federal, state and
local governmental authorities. New laws or regulations, or changes to current requirements, could
have a material adverse effect on our business. We will continue to be subject to uncertainty
associated with new regulatory interpretations and inconsistent interpretations between state and
federal agencies. We could face significant liabilities to the government and third parties for
discharges of oil, natural gas, produced water or other pollutants into the air, soil or water, and
we could have to spend substantial amounts on investigations, litigation and remediation. We
cannot be sure that existing environmental laws or regulations, as currently interpreted or
enforced, or as they may be interpreted, enforced or altered in the future, will not have a
material adverse effect on our results of operations and financial condition.
Our business depends on transportation facilities owned by others. The marketability of our
anticipated gas production depends in part on the availability, proximity and capacity of pipeline
systems owned or operated by third parties. Federal and state regulation of oil and gas production
and transportation, tax and energy policies, changes in supply and demand and general economic
conditions could adversely affect our ability to produce, gather and transport oil and natural gas.
Attempts to grow our business could have an adverse effect. Because of our small size, we
desire to grow rapidly in order to achieve certain economies of scale. Although there is no
assurance that this rapid growth will occur, to the extent that it does occur, it will place a
significant strain on our financial, technical, operational and administrative resources. As we
increase our services and enlarge the number of projects we are evaluating or in which we are
participating, there will be additional demands on our financial, technical and administrative
resources. The failure to continue to upgrade our technical, administrative, operating and
financial control systems or the occurrence of unexpected expansion difficulties, including the
recruitment and retention of geoscientists and engineers, could have a material adverse effect on
our business, financial condition and results of operations.
We may not be able to retain our listing on the American Stock Exchange. The American Stock
Exchange has certain listing requirements in order for a company to continue to have their
securities traded on this exchange. A company may risk delisting if their common stock trades at a
low price per share for a substantial period of time. Should our stock trade at a low share price
for a substantial period of time, or our net tangible equity be below certain levels, we may not be
able to retain our listing.
We depend on key personnel. We are highly dependent on the services of D. Scott Singdahlsen,
our President and Chief Executive Officer, and our other geological and geophysical staff members.
The loss of the services of any of these persons could hurt our business. We do not have an
employment contract with Mr. Singdahlsen or any other employee.
Disclosure Regarding Forward-Looking Statements And Cautionary Statements
This annual report contains forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including
statements regarding, among other items, our business and growth strategies, anticipated trends in
our business and our future results of operations, market conditions in the oil and gas industry,
our ability to make and integrate acquisitions, the outcome of litigation, if any, and the impact
of governmental regulation. These forward-looking statements are based largely on our expectations
and are subject to a number of risks and
18
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:
| |
• |
|
failure to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices, |
| |
| |
• |
|
incorrect estimates of required capital expenditures, |
| |
| |
• |
|
increases in the cost of drilling, completion and gas collection or other
costs of production and operations, |
| |
| |
• |
|
an inability to meet growth projections, and |
| |
| |
• |
|
other risk factors set forth under ''Risk Factors’’ in this annual report.
In addition, the words ''believe,’’ ''may,’’ ''could,’’ ''will,’’ ''when,’’
''estimate,’’ ''continue,’’ ''anticipate,’’ ''intend,’’ ''expect’’ and similar
expressions, as they relate to PYR, our business or our management, are intended to
identify forward-looking statements. |
ITEM 3. LEGAL PROCEEDINGS
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
Samson’s 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 No. 1 Sidetrack
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 with other properties in which the Company has no interest, many of which are
non-productive. Samson has a large interest in these properties that Samson has joined into the
unit. Pursuant to Samson’s proposed pooling configuration, the Company’s 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 Company’s 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. On September 13, 2005, the Court entered a
Preliminary Injunction ordering Samson to return the Company to pay status for the undisputed
amounts upon which Samson had been paying the Company prior to the filing of the suit.
On August 22, 2005, Samson filed a lawsuit in District Court for Jefferson County, Texas,
58th Judicial District against the Company, claiming that Samson has the right to serve
as operator to drill and operate on the property to the east of the Sun Fee Well, which is located
on property in which the Company owns a majority interest. The Company holds a 100% interest in
oil and gas leases that comprise 75% of the approximately 400-acre parcel on which it is planning
to drill a gas well to the same reservoir from which the Sun Fee Well produces. In June 2005, the
Company notified Samson of its intention to drill a well on this property and offered Samson the
opportunity to participate in the well. Samson elected to participate in the well and demanded to
be allowed to operate the well. Upon the Company’s initial preparation of the drill site, which
began in August 2005, Samson filed a lawsuit seeking a judicial declaration of Samson’s exclusive
right to operate the well and injunctive relief enjoining the Company from continuing its drilling
operations or serving as operator.
The Company will continue to vigorously pursue and defend its rights with respect to the
foregoing litigations. The Company intends to continue to move forward with construction of the
potential drill site and to drill the well in order to protect its interests in the underlying
leases until such time as the issue is fully adjudicated.
On November 2, 2005, an adversary proceeding was filed against the Company in the on-going
bankruptcy proceeding of Venus Exploration Company (“Venus”) in the U.S. Bankruptcy Court for the
Eastern District of Texas. In the adversary proceeding, the Venus Exploration Trust, representing
the interests of the secured creditors (the “Trust”), seeks a full accounting, with interest and
attorneys’ fees, of the net profits interest accounts established under the Net Profit Conveyance
by which the Company purchased Venus’ assets and is to account for proceeds generated from certain
identified, potential income-generating projects less costs. Presently, proceeds are generated by
the Nome and Madison projects in Jefferson County, Texas. The Trust also seeks reformation of the
conveyance whereby future proceeds shall be paid by third-part
purchasers directly to the Trust,
from which the Company may subsequently request reimbursement of costs. Upon reconsideration of an
initial good-faith deduction of costs for anticipated drilling operations on the two projects and
prior to the filing of the adversary proceeding, the Company forwarded to the Trust a payment in
excess of $820,970, including interest, with over 35 pages of detailed accounting. The Company has
entered discussions with the Trust to withdraw and dismiss the proceeding in light of the payment,
which discussions are pending the return of the Trust’s counsel from foreign travel. As a result,
the lawsuit has not been served on the Company. Should the Trust refuse to dismiss and proceed
with service, the Company will vigorously defend its interests against the claims in this
proceeding.
19
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The following matters were submitted to a vote of security holders at the annual meeting of
stockholders which was held on August 8, 2005:
The stockholders voted to re-elect D. Scott Singdahlsen, David Kilpatrick, Bryce W. Rhodes and
Dennis Swenson to continue as directors of the Company. A total of 25,939,535 votes were
represented with respect to this matter, with voting on each specific nominee as follows:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
BROKER |
| |
|
FOR |
|
AGAINST |
|
WITHHELD |
|
NON-VOTES |
D. Scott Singdahlsen
|
|
|
25,073,407 |
|
|
|
0 |
|
|
|
866,128 |
|
|
— |
David Kilpatrick
|
|
|
25,088,178 |
|
|
|
0 |
|
|
|
851,357 |
|
|
— |
Bryce W. Rhodes
|
|
|
25,103,428 |
|
|
|
0 |
|
|
|
836,107 |
|
|
— |
Dennis Swenson
|
|
|
25,103,728 |
|
|
|
0 |
|
|
|
835,807 |
|
|
— |
A proposal to approve the issuance of up to an additional 1,780,702 shares of common stock to
be available for the conversion of accrued interest on previously issued convertible notes was
approved by the stockholders. A total of 14,495,324 votes were represented with a total of
13,492,288 (93%) shares voting for the proposal, 965,683 shares voting against the proposal, and
37,353 shares abstaining from voting.
A proposal to ratify the selection of Hein & Associates LLP as our Certified Public
Accountants was approved by the stockholders. A total of 25,939,535 votes were represented with a
total of 25,073,454 (97%) shares voting for the proposal, 843,683 shares voting against the
proposal, and 22,398 shares abstaining from voting.
PART II
ITEM
5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Market For Common Equity
Our common stock has been listed on the American Stock Exchange under the market symbol “PYR”
since December 8, 1999. The following table sets forth the range of high and low sales prices per
share of our common stock for the periods indicated.
| |
|
|
|
|
|
|
|
|
| |
|
High |
|
Low |
Fiscal Year Ended August 31, 2004 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
0.83 |
|
|
$ |
0.45 |
|
Second Quarter |
|
|
1.81 |
|
|
|
0.53 |
|
Third Quarter |
|
|
1.70 |
|
|
|
1.04 |
|
Fourth Quarter |
|
|
1.32 |
|
|
|
0.75 |
|
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 |
|
On November 15, 2005, the last reported sales price of our common stock on the American Stock
Exchange was $1.22 per share.
Stockholders Of Record
As of November 15, 2005, the number of record holders of our common stock was approximately
520.
20
Dividends
We have not declared or paid, and do not anticipate declaring or paying in the near future,
any dividends on our common stock.
Recent Sales Of Unregistered Securities; Use Of Proceeds From Registered Securities
In mid-October 2005, the Company completed a Private Equity Placement consisting of the sale
of 6.328 million shares of common stock, priced at $1.30 per share, to a group of institutional and
accredited individual investors. Proceeds from the Placement of approximately $8.2 million will be
used for general corporate purposes and costs associated with the Company’s development drilling
portfolio. Shares purchased in the Private Placement were issued in reliance on exemptions from
registration contained in Section 4(2) of the Securities Act of 1933, and as amended, and Rule 506
of Regulation D promulgated thereunder. Pursuant to the terms of the Private Placement, the
Company has agreed to file a registration statement covering the resale of these shares.
Equity Compensation Plan Information
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Equity Compensation Plan Information |
| |
|
|
|
|
|
|
|
|
|
Number of Securities |
| |
|
|
|
|
|
|
|
|
|
Remaining Available for |
| |
|
|
|
|
|
|
|
|
|
Future Issuance under |
| |
|
Number of Securities to be |
|
|
|
|
|
Equity Compensation |
| |
|
Issued Upon Exercise of |
|
Weighted-Average Exercise |
|
Plans (Excluding |
| |
|
Outstanding Options, |
|
Price of Outstanding Options, |
|
Securities Reflected in |
| Plan Category |
|
Warrants and Rights |
|
Warrants and Rights |
|
Column (a))* |
| |
|
(a) |
|
(b) |
|
(c) |
Equity compensation
plans approved by
security holders |
|
|
2,234,750 |
|
|
$ |
1.41 |
|
|
|
604,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation
plans not approved
by security holders |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2,234,750 |
|
|
$ |
1.41 |
|
|
|
604,250 |
|
ITEM 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS
The following discussion should be read in conjunction with the Consolidated Financial
Statements and Notes thereto referred to in “Item 8. Financial Statements and Supplemental Data,”
and “Items 1. and 2. Business and Properties — Disclosures Regarding Forward-Looking Statements”
of this Form 10-KSB.
Overview
We are an independent oil and gas exploration and production company engaged in the
exploration, development and acquisition of crude oil and natural gas reserves. We intend to
increase stockholder value by profitably growing reserves and production, primarily through
drilling operations and strategic acquisitions. Our strategic focus is the application of advanced
seismic imaging and computer aided exploration technologies in the systematic search for commercial
hydrocarbon reserves, primarily in the onshore western United States. We attempt to leverage our
technical experience and expertise with seismic data to identify exploration and exploitation
projects with significant potential economic return. We intend to participate in selected
exploration projects as a working interest owner, currently as a non-operator, sharing both risk
and rewards with our partners. Our financial results depend on our ability to sell prospect
interests to outside industry participants. We will not be able to commence additional exploratory
drilling operations without outside industry participation. We have pursued, and will continue
21
to pursue, exploration opportunities in regions where we believe significant opportunity for
discovery of oil and gas exists. By attempting to reduce drilling risk through seismic technology,
we seek to improve the expected return on investment in our oil and gas exploration projects.
Our future financial results continue to depend primarily on (1) our ability to discover
commercial quantities of hydrocarbons; (2) the market price for oil and gas; (3) our ability to
continue to source and screen potential projects; and (4) our ability to fully implement our
exploration and development program with respect to these and other matters. There can be no
assurance that we will be successful in any of these respects or that the prices of oil and gas
prevailing at the time of production will be at a level allowing for profitable production.
In fiscal year 2004, we acquired various oil and gas interests from Venus Exploration, Inc.
(“Venus”) in certain producing properties with estimated proved reserves of 4.784 Bcfe for
approximately $3.2 million (excluding acquisition expenses and subject to retention, by the Venus
Exploration Trust, of a net profits interest covering the non-productive exploration projects), and
made a private placement of our common stock, which raised approximately $8.2 million in gross
proceeds. The revenue generated from production from these acquired properties comprises the
principal source of the Company’ oil and gas revenues for fiscal year 2005.
In mid-October 2005, we completed a Private Equity Placement consisting of the sale of 6.328
million shares of common stock, priced at $1.30 per share, to a group of institutional and
accredited individual investors. Proceeds from this Placement of approximately $8.2 million will
be used for general corporate purposes and costs associated with the Company’s 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 activities and liquidity. Our
future success in growing proved reserves and production is highly dependent on capital resources
available to us and our success in finding or acquiring additional reserves. At August 31, 2005,
we had approximately $2.1 million in working capital and cash of $2.9 million.
Cash Flow from Operating Activities
Net cash provided by operating activities was $1.9 million in 2005 compared with net cash used
by operating activities of $1.1 million in 2004. The increase in net cash provided by operating
activities was substantially due to the increase in production revenues, net of increases in
expenses, attributed to the producing properties acquired from Venus in May 2004. See “Results of
Operations” for discussion of changes in expenses. Non-cash charges increased due to higher
depreciation, depletion and amortization associated with increased production and a non-cash charge
for the impairment of the Company’s investment in its Canadian properties. Changes in current
assets and liabilities increased cash flow from operations by $91,000 in 2005 compared with a
decrease in cash flows from operations of $323,000 in 2004.
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.
Capital Expenditures
Our capital expenditures were approximately $5.9 million and $5.1 million in 2005 and 2004,
respectively. The total for 2005 includes $4.2 million for drilling, development, exploration and
exploitation, $1.6 million for leasehold acquisition costs and delay rentals, $98,000 for geologic
and geophysical costs and $10,000 for office furniture, fixtures and equipment. In 2004 we
incurred approximately $3.8 million of capital costs related to the properties we acquired from
Venus. This amount includes capitalized acquisition costs, costs associated with undeveloped
leasehold, drilling, workover, and geological and geophysical costs. We incurred approximately
$1.6 million for costs related to our other exploration projects including continued acreage lease
obligations and associated geological and geophysical costs, as well as drilling costs for the
Mallard
well.
22
In May 2004, we acquired interests in certain producing properties for approximately
$3.3 million (excluding acquisition expenses and subject to retention, by the Venus Exploration
Trust, of a net profits interest covering the non-productive exploration projects) from Venus.
Venus was in Chapter 11 Bankruptcy, and the properties were acquired through public auction as
approved by the United States Bankruptcy Court. To finance the purchase, we primarily used
existing cash reserves and also a portion of the proceeds from the Placement. The purchase also
provides for a net profits interest payable to the Venus Exploration Trust. The net profits
interest, which applies only to the exploration and exploitation projects on the Venus acreage
being acquired, varies from 25% to 50% with respect to different Venus exploration and exploitation
project areas, and decreases by one-half of its original amount after
a total of $3.3 million in net
profits proceeds has been paid to the Trust.
During 2005 and 2004, we received $750,000 and $500,000, respectively, 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. In 2005, we received proceeds of approximately
$49,000 from the sale of a portion of our interests in prospects in Louisiana and Texas. In 2004,
we received approximately $632,000 in prospect fees and pro-rata development costs from two private
oil and gas exploration companies pursuant to an agreement covering two of our exploration projects
in the Overthrust of southwestern Wyoming.
We currently anticipate our capital budget will be approximately between $7.5 and $10.0
million for fiscal year 2006 which will be used for a diverse portfolio of development and
exploration wells in our core areas of operation. 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 2006 capital budget. We are projecting that cash on hand, cash
available from operating activities, capital of $8.2 million received in an October 2005 private
placement, and funds from the partial sale of our interest in some prospects will be sufficient to
fund our 2006 capital budget.
Financing Activities
In
early May 2004, we received subscriptions for an aggregate of
approximately $8.2 million in gross proceeds
from a private placement of our common stock. The private placement (the “Placement”) consisted of
the sale of 7.5 million shares of common stock, priced at $1.09 per share, to a group of twelve
institutional and accredited individual investors pursuant to exemptions from registration under
Sections 3(b) and 4(2) of the Securities Act of 1933, as amended. The first tranche of the
Placement, consisting of 4.5 million shares and approximately
$4.9 million in gross proceeds, was received and
accepted in early May 2004. The second tranche of the Placement, consisting of 3.0 million shares
and approximately $3.3 million in gross proceeds, was approved by our stockholders at our Annual
Meeting of Stockholders on June 11, 2004. We received the funds from the second tranche in late
June 2004. Proceeds from the Placement will be used for general corporate purposes, partial
funding of the acquisition of assets from Venus Exploration, Inc., and project development and
drilling costs associated with our exploration and exploitation portfolio. The resale of these
shares acquired in the Placement has subsequently been registered through a Registration Statement
that has become effective with the SEC.
In mid-October 2005, the Company completed a Private Equity Placement consisting of the sale
of 6.328 million shares of common stock, priced at $1.30 per share, to a group of institutional and
accredited individual investors. Proceeds from this Placement of approximately $8.2 million will
be used for general corporate purposes and costs associated with the Company’s 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, 2006
will depend on our success in selling additional prospects for cash, the level of industry
participation in our exploration projects, the availability of debt or equity financing, and the
results of our activities. We anticipate spending a minimum of approximately between $7.5 and
$10.0 million on exploration and development activities during our fiscal year ending August 31,
2006. 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.
23
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.
Contractual Obligations
The following table summarizes the Company’s obligations and commitments, as of August 31,
2005 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 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
Thereafter |
|
Convertible Notes |
|
$ |
8,474 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
8,474 |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Office Leases |
|
|
163 |
|
|
|
70 |
|
|
|
70 |
|
|
|
23 |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual
Cash Obligations |
|
$ |
8,637 |
|
|
$ |
70 |
|
|
$ |
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 $129,000 during the year ending August 31, 2006. The
Company considers on a quarterly basis whether to continue holding all or part of each acreage
block by making delay rental payments on existing leases.
Results of Operations
The twelve months ended August 31, 2005 (“2005”) compared with the twelve months ended August 31,
2004 (“2004”)
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 the purchase of
producing properties from Venus Exploration Inc. (“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 392,065 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 62,289 and 13,971 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 #1 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.
24
Net Profits Expense. During 2005, two wells, the Sun Fee #1 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 and Amortization. Depreciation, depletion and amortization expense
increased to $868,000 in 2005 from $173,000 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. For further discussion of the Asset Retirement Obligation, see Note 4 to
the Financial Statements included in this Form 10-KSB.
Accretion Expense. We recorded $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.
Dry Hole, Impairment and Abandonments. We recognized a non-cash impairment expense of
$580,000 associated with the Company’s 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 45% 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.
The twelve months ended August 31, 2004 (“2004”) compared with the twelve months ended August 31,
2003 (“2003”)
Operations during the fiscal year ended August 31, 2004 resulted in a net loss of
approximately $1.4 million compared to a net loss of approximately $5.3 million for the fiscal year
ended August 31, 2003.
Oil and Gas Revenues and Expenses. During the year ended August 31, 2004, we recorded
approximately $863,000 in total oil and gas revenues. Of this amount, we recorded approximately
$334,000 from the sale of 60,285 mcf of natural gas for an average price of $5.54 per mcf, and
approximately $529,000 from the sale of 13,971 bbls of oil and hydrocarbon liquids for an average
price of $37.88 per bbl. The portion of fiscal year 2004 oil and gas revenues related to the May
2004 property acquisition from Venus Exploration, Inc. (“Venus”), was approximately $694,000. As
the acquisition from Venus was recorded as a purchase transaction, only four months of operations
related to these properties were recorded in 2004. During the year ended August 31, 2003, we
recorded approximately $154,000 from the sale of 34,773 mcf of natural gas for an average price of
$4.41 per mcf, and $42,000 for the sale of 1,583 bbls of hydrocarbon liquids for an average price
of $26.33 per bbl. 2003 revenues relate totally to the Company’s interest in East Lost Hills in
California. Comparable revenues for this prospect in 2004 were $169,000. Lease operating expenses
in 2004 were $336,000 compared to $95,000 in 2003.
25
Interest Income. We recorded $27,000 and $54,000 in interest income for the years ended
August 31, 2004 and 2003, respectively. Lower interest income in 2004 resulted from lower average
cash balances for the majority of 2004, offset partially by interest on the funds received from the
private placement of our common stock in May 2004.
General and Administrative Expenses. General and administrative expenses in 2004 were
approximately $1.3 million compared to approximately $1.3 million in 2003. The increase
principally reflects additional audit and legal fees incurred in conjunction with the property
acquisition from Venus Exploration Inc.
Depreciation Depletion and Amortization. We recorded $46,000 in depreciation, depletion and
amortization expense from oil and gas properties for the year ended August 31, 2004. We recorded
no depreciation, depletion and amortization expense from oil and gas properties for the year ended
August 31, 2003, due to an impairment taken against our entire amortizable full cost pool at August
31, 2003, and accordingly, there were no costs to amortize. The increase in depreciation,
depletion and amortization expense was attributable to the properties acquired from Venus
Exploration, Inc. We recorded $13,000 and $11,000 in depreciation expense associated with
capitalized office furniture and equipment during 2004 and 2003, respectively. Depreciation of
Asset Retirement Obligation assets for the years ended August 31, 2004 and August 31, 2003, was
$114,000 and $151,000, respectively. For further discussion of the Asset Retirement Obligation,
see Note 4 to the Financial Statements included in this Form 10-KSB.
Accretion Expense. We recorded $100,000 and $77,000, respectively, for the years ended August
31, 2004 and August 31, 2003, of accretion of the unamortized discount of the Asset Retirement
Obligation liability. The increase in accretion expense was attributable to the properties
acquired from Venus Exploration, Inc. For further discussion of the Asset Retirement Obligation,
see Note 4 to the Financial Statements included in this Form 10-KSB.
Dry Hole, Impairment and Abandonments. We recorded no impairment expense for the year ended
August 31, 2004. For the year ended August 31, 2004, we recorded an impairment expense of $3.2
million, of which $451,000 related to costs incurred in the East Lost Hills prospect, and the
remainder, $2.8 million, related to other undeveloped prospects in California and the Rocky
Mountain region, which were determined by management to be impaired as of August 31, 2003.
Interest Expense. During 2004, we recorded interest expense of $327,000 compared to $315,000
in 2003. The interest expense for each year is associated with the May 24, 2002 sale of
outstanding convertible notes due on May 24, 2009. The Company elected to add $319,000 and
$304,000 of accrued interest to the balance of the debt for the years ended August 31, 2004 and
August 31, 2003, respectively. We have reflected the outstanding balance of these notes as
Convertible Notes under Long Term Debt on our August 31, 2004 and 2003 balance sheets. The twelve
months ended August 31, 2004 (“2004”) compared with the twelve months ended August 31, 2003.
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
26
rate of depletion of the oil and gas properties. Actual production, revenues and expenditures
with respect to our reserves will likely vary from estimates, and such variances may be material.
Many factors will affect actual net cash flows, including the following: the amount and timing
of actual production; supply and demand for natural gas; curtailments or increases in consumption
by natural gas purchasers; and changes in governmental regulations or taxation.
Property, Equipment and Depreciation:
We follow the full cost method to account for our oil and gas exploration and development
activities. Under the full cost method, all costs incurred which are directly related to oil and
gas exploration and development are capitalized and subjected to depreciation and depletion.
Depletable costs also include estimates of future development costs of proved reserves. Costs
related to undeveloped oil and gas properties may be excluded from depletable costs until those
properties are evaluated as either proved or unproved. The net capitalized costs are subject to a
ceiling limitation based on the estimated present value of discounted future net cash flows from
proved reserves. As a result, we are required to estimate our proved reserves at the end of each
quarter, which is subject to the uncertainties described in the previous section. Gains or losses
upon disposition of oil and gas properties are treated as adjustments to capitalized costs, unless
the disposition represents a significant portion of the Company’s proved reserves.
Revenue Recognition:
The Company recognizes oil and gas revenues from its interests in producing wells as oil and
gas is produced and sold from these wells. The Company uses the sales method to account for gas
imbalances. Oil and gas sold is not significantly different from the Company’s product
entitlement. Gas imbalances at August 31, 2005 and 2004 were not significant.
Recent Accounting Pronouncements
In
May 2005, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 154, Accounting Changes and Error Corrections — a
replacement of APB Opinion No. 20 and FASB Statement
No. 3 (SFAS 154). SFAS 154 requires
retrospective application to prior periods’ financial statements for changes in accounting
principle, unless it is impracticable application to prior periods’ financial statements for
changes in accounting principle, unless it is impracticable to determine either the period-specific
effects or the cumulative effect of the change. SFAS 154 also requires that a change in
depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted
for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is
effective for accounting changes and corrections of errors made in fiscal years beginning after
December 15, 2005. The implementation of SFAS 154 is not expected to have a material impact on our
condensed consolidated results of operations, financial position or cash flows.
In December 2004, the FASB 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 Accounting Principles
Board Opinion No.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. 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 after, interim or annual periods, beginning after June 15, 2005, which for us will
be the first quarter of fiscal 2006. 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.
ITEM 7. FINANCIAL STATEMENTS
The Consolidated Financial Statements and schedules that constitute Item 7 are attached at the
end of Annual Report on Form 10-KSB. An index to these Financial Statements and schedules is also
included in Item 14(a) of this Annual Report on Form 10-KSB.
27
|
|
|
| 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
Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) under the Securities
Exchange Act of 1934 (the “Exchange Act”)). Based on this evaluation, the Company concluded that,
subject to the limitations described below, the Company’s disclosure controls and procedures are
effective to ensure that information required to be disclosed by the Company in annual reports that
it files under the Exchange Act is recorded, processed, summarized, and reported within the time
periods specified in Securities and Exchange Commission rules and forms. There was no change
in the Company’s internal controls over financial reporting during the Company’s most recently
completed fiscal quarter that has materially affected, or is reasonably likely to materially
affect, the Company’s internal control over financial reporting period.
ITEM 8B. OTHER INFORMATION
Not applicable
28
PART III
|
|
|
| ITEM 9. |
|
DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION
16(a) OF THE EXCHANGE ACT |
The directors and executive officers of the Company, their respective positions and ages, and
the year in which each director was first elected, are set forth in the following table. Each
director has been elected to hold office until the next annual meeting of stockholders and
thereafter until his successor is elected and has qualified. Additional information concerning
each of these individuals follows the table.
| |
|
|
|
|
|
|
|
|
|
|
| Name |
|
Age |
|
Position with the Company |
|
Director Since |
D. Scott Singdahlsen
|
|
|
47 |
|
|
Chief Executive Officer, Chief Financial
Officer and President
|
|
|
1997 |
|
|
|
|
|
|
|
|
|
|
|
|
David Kilpatrick
|
|
|
55 |
|
|
Chairman of the Board
|
|
|
2002 |
|
|
|
|
|
|
|
|
|
|
|
|
Bryce W. Rhodes
|
|
|
52 |
|
|
Director
|
|
|
1999 |
|
|
|
|
|
|
|
|
|
|
|
|
Dennis M. Swenson
|
|
|
70 |
|
|
Director
|
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
Kenneth R. Berry, Jr.
|
|
|
53 |
|
|
Vice President-Land and Corporate Secretary
|
|
—
|
D. Scott Singdahlsen has served as President, Chief Executive Officer, and Chief Financial
Officer of the Company since August 1997. From August 1997 to November 2005, Mr. Singdahlsen
served as our Chairman of the Board. Mr. Singdahlsen co-founded PYR Energy, LLC in 1996, and
served as General Manager and Exploration Coordinator. In 1992, Mr. Singdahlsen co-founded
Interactive Earth Sciences Corporation, a 3-D seismic management and interpretation consulting firm
in Denver, where he served as vice president and president and lead seismic interpretation
specialist from 1992 to 1996. Prior to forming Interactive Earth Sciences Corporation, Mr.
Singdahlsen was employed as a Development Geologist for Chevron USA in the Rocky Mountain region.
At Chevron, Mr. Singdahlsen was involved in 3-D seismic reservoir characterization projects and
geostatistical analysis. Mr. Singdahlsen started his career at UNOCAL as an Exploration Geologist
in Midland, Texas. Mr. Singdahlsen earned a B.A. in Geology from Hamilton College and a M.S. in
Structural Geology from Montana State University.
David B. Kilpatrick has been a Director of the Company since June, 2002 and was appointed to
Chairman of the Board in November 2005. He is currently President of Kilpatrick Energy Group,
which provides strategic management consulting services to the oil and gas industry. He currently
serves as a Director of the publicly traded Cheniere Energy and 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 Bachelor’s Degree in Geology and
Physics from Whittier College.
Bryce W. Rhodes has been a Director of the Company since April 1999, when he was nominated and
elected to the Board in connection with the sale by the Company of convertible promissory notes
issued in a private placement transaction in October and November 1998. From 1996 until September
2003, Mr. Rhodes has served as President and CEO of Whittier
29
Energy Company (“WEC”), an oil and gas investment company. In September 2003, WEC merged with
Olympic Resources, Inc. and Mr. Rhodes was appointed as President and Chief Executive Officer. Mr.
Rhodes served as Investment Manager of WEC from 1990 until 1996. Mr. Rhodes received B.A. degrees
in Geology and Biology from the University of California, Santa Cruz, in 1976 and an MBA degree
from Stanford University in 1979.
Dennis M. Swenson joined as a Director in October 2004, and serves as the Audit Committee
Chairman and a member of the Compensation Committee. From 1992 through 1995, Mr. Swenson was an
independent consultant. Mr. Swenson was Executive Vice President, Chief Financial Officer,
Secretary and Treasurer, of StarTek, Inc., a NYSE traded company with headquarters in Denver,
Colorado from 1996 through retirement in 2001. Mr. Swenson was employed at Ernst & Young in Denver
from 1960 to 1973, and was a partner at Ernst & Young from 1973 to 1991. He has a Bachelor’s
Degree in Accounting from Brigham Young University and an MBA Degree from the University of Denver.
Kenneth R. Berry, Jr. has 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. Mr. Berry is responsible for the management of all land issues including leasing and
permitting. Prior to joining the Company, Mr. Berry served as the managing land consultant for
Swift Energy Company in the Rocky Mountain region. Mr. Berry began his career in the land
department with Tenneco Oil Company after earning a B.A. degree in Petroleum Land Management at the
University of Texas — Austin.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”),
requires the Company’s directors, executive officers and holders of more than 10% of the Company’s
common stock to file with the Securities and Exchange Commission initial reports of ownership and
reports of changes in ownership of common stock and other equity securities of the Company. The
Company believes that during the year ended August 31, 2005, its officers, directors and holders of
more than 10% of the Company’s common stock complied with all Section 16(a) filing requirements.
In making these statements, the Company has relied upon representations and its review of copies of
the Section 16(a) reports filed for the fiscal year ended August 31, 2005 on behalf of the
Company’s directors, officers and holders of more than 10% of the Company’s common stock.
Employee Code of Conduct and Code of Ethics and Reporting of Accounting Concerns
The Company adopted an Employee Code of Conduct (the “Code of Conduct”). We require all
employees to adhere to the Code of Conduct in addressing legal and ethical issues encountered in
conducting their work. The Code of Conduct requires that our employees avoid conflicts of
interest, comply with all laws and other legal requirements, conduct business in an honest and
ethical manner and otherwise act with integrity and in the Company’s best interest.
The Company also adopted a Code of Ethics for our Chief Executive Officer, our Chief Financial
Officer, our Controller and all other financial officers and executives. This Code of Ethics
supplements our Code of Conduct and is intended to promote honest and ethical conduct, full and
accurate reporting, and compliance with laws as well as other matters. The Code of Conduct and
Code of Ethics are filed with the SEC.
Further, the Audit Committee of the Board of Directors has established “whistle-blower
procedures” which provides a process for the confidential and anonymous submission, receipt,
retention and treatment of complaints regarding accounting, internal accounting controls or
auditing matters. These procedures provide substantial protections to employees who report company
misconduct.
Audit Committee Financial Expert
The Company’s Board of Directors has determined that Mr. Dennis M. Swenson is the Company’s
audit committee financial expert.
Identification of Audit Committee
The Board of Directors currently has an Audit Committee consisting of Messrs. Swenson
(Chairman), Kilpatrick and Rhodes. The Audit Committee is responsible for the selection and
retention of our independent auditors, reviews the scope of
30
the audit functions of the independent auditor, and reviews audit reports rendered by our
independent auditors. The Audit Committee oversees the Company’s financial reporting process on
behalf of the Board of Directors. Management has the primary responsibility for the financial
statements, accounting policies and procedures, and the reporting process, including the systems of
internal controls. In fulfilling its oversight responsibilities, the Committee reviewed and
discussed with management the audited financial statements in this Annual Report on Form 10-KSB for
the year ended August 31, 2005 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, 2005.
ITEM 10. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth in summary form the compensation received during each of the
last three completed fiscal years ended August 31, 2005 by our Chief Executive Officer, President,
Chief Financial Officer and Chairman of The Board and two of our most highly compensated officers
serving as of August 31, 2005.
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| Summary Compensation Table |
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Annual Compensation |
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Long-Term Compensation |
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Awards |
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Payouts |
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Other Annual |
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Restricted |
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Securities |
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LTIP |
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All Other |
| Name and Principal |
|
Fiscal |
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Salary |
|
Bonus |
|
Compensation |
|
Stock |
|
Underlying |
|
Payouts |
|
Compensation |
| Position |
|
Year |
|
($)(1) |
|
($)(2) |
|
($)(3) |
|
Awards ($) |
|
Options(#) |
|
($)(4) |
|
($)(5) |
D. Scott Singdahlsen |
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Chief Executive
Officer, |
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2005 |
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$ |
175,000 |
|
|
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— |
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— |
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— |
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200,000 |
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— |
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— |
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Chief Financial Officer,
President and Chairman |
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2004 |
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$ |
175,000 |
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— |
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— |
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|
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— |
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|
|
— |
|
|
|
— |
|
|
|
— |
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Of the Board |
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2003 |
|
|
$ |
175,000 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
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281,750 |
|
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|
— |
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— |
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Tucker L. Franciscus |
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2005 |
|
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$ |
120,000 |
|
|
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— |
|
|
|
— |
|
|
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— |
|
|
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150,000 |
|
|
|
— |
|
|
|
— |
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Vice President |
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2004 |
|
|
|
— |
|
|
|
— |
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|
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— |
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|
|
— |
|
|
|
— |
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|
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— |
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— |
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2003 |
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— |
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— |
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|
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— |
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|
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— |
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— |
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— |
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— |
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Kenneth R. Berry Jr. |
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2005 |
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$ |
108,000 |
|
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— |
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— |
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— |
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— |
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— |
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— |
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Vice President |
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2004 |
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$ |
93,150 |
|
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— |
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— |
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— |
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135,000 |
|
|
|
— |
|
|
|
— |
|
|
|
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2003 |
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$ |
93,150 |
|
|
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— |
|
|
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— |
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— |
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157,500 |
|
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— |
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— |
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| (1) |
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The dollar value of base salary (cash and non-cash) received during the year indicated. |
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| (2) |
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The dollar value of bonus (cash and non-cash) received during the year indicated. |
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| (3) |
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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. |
31
|
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| (4) |
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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. |
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| (5) |
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All other compensation received that we could not properly report in any other column of the
Summary Compensation Table including annual Company contributions or other allocations to
vested and unvested defined contribution plans, and the dollar value of any insurance premiums
paid by, or on behalf of, the Company with respect to term life insurance for the benefit of
the named executive officer, and, the full dollar value of the remainder of the premiums paid
by, or on behalf of, the Company. |
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, 2005 by the named executive officer and the value of
unexercised stock options held by the named executive officer as of August 31, 2005.
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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 |
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Value of Unexercised In-the- |
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Options at Fiscal |
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Money Options at Fiscal |
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Year-End (#)(4) |
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Year-End ($)(5) |
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Shares |
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Acquired on |
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Value |
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| Name |
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Exercise(2) |
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Realized ($)(3) |
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Exercisable |
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Unexercisable |
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Exercisable |
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Unexercisable |
D. Scott Singdahlsen |
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— |
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— |
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302,834 |
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293,916 |
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145,937 |
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152,968 |
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| (1) |
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No stock appreciation rights are held by any of the named executive officers. |
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| (2) |
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The number of shares received upon exercise of options during the year ended August 31, 2005. |
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| (3) |
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With respect to options exercised during the year ended August 31, 2005, 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. |
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| (4) |
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The total number of unexercised options held as of August 31, 2005, separated between those
options that were exercisable and those options that were not exercisable on that date. |
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| (5) |
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For all unexercised options held as of August 31, 2005, 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, 2005 based on the
closing sale price of our common stock on that date, which was $1.36 per share. |
Employee Retirement Plans, Long-Term Incentive Plans and Pension Plans
Excluding the Company’s stock option plans, we do not have any long-term incentive plan to
serve as incentive for performance to occur over a period longer than one fiscal year.
1997 Stock Option Plan
In August 1997, our 1997 Stock Option Plan (the “1997 Plan”) was adopted by the Board of
Directors and subsequently approved by the stockholders. Pursuant to the 1997 Plan, we may grant
options to purchase an aggregate of
32
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, 2005, options to purchase 525,000 shares were
outstanding under the Plan and 191,500 options were available to be granted under the 1997 Plan.
2000 Stock Option Plan
In March 1999, our 2000 Stock Option Plan (the “2000 Plan”) was adopted by the Board of
Directors and subsequently approved by the stockholders. Pursuant to the 2000 Plan, we may grant
options to purchase shares of our common stock to key employees, directors, and other persons who
have contributed or are contributing to our success. We initially could grant options to purchase
up to 500,000 shares pursuant to the 2000 Plan. In June 2001, our stockholders approved an
amendment which allows us to grant options to purchase up to 1,500,000 shares pursuant to the 2000
Plan. In June 2004, our stockholders approved an amendment to increase from 1,500,000 to 2,250,000
the number of shares of common stock issuable pursuant to options granted under the 2000 Plan. The
options granted pursuant to the 2000 Plan may be either incentive options qualifying for beneficial
tax treatment for the recipient or non-qualified options. The 2000 Plan may be administered by the
Board of Directors or by an option committee. Administration of the 2000 Plan includes
determination of the terms of options granted under the 2000 Plan. As of August 31, 2005, options
to purchase 1,709,750 shares were outstanding under the 2000 Plan and 412,750 options were
available to be granted pursuant to the 2000 Plan.
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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, 2005, an
executive officer of another company whose board of directors has a comparable committee on which
one of the Company’s executive officers serves.
Employment Contracts And Termination of Employment And Change-In-Control Arrangements
We do not have any written employment contracts with any of our officers or other employees.
We have no compensatory plan or arrangement that results or will result from the resignation,
retirement, or any other termination of an executive officer’s employment or from a
change-in-control or a change in an executive officer’s responsibilities following a
change-in-control, except that both the 1997 Plan and the 2000 Plan provide for vesting of all
outstanding options in the event of the occurrence of a change-in-control.
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| ITEM 11. |
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS |
Stock Ownership Of Directors And Principal Stockholders
As of November 15, 2005, there were 37,968,259 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 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:
33
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Number of Shares |
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Percentage of |
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| Name and Address of Beneficial Owner |
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Beneficially Owned(1) |
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Shares Outstanding |
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D. Scott Singdahlsen
1675 Broadway, Suite 2450
Denver, Colorado 80202 |
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2,092,834 |
(2) |
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5.5 |
% |
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Bryce W. Rhodes
c/o Whittier Energy Company
7770 El Camino Real
Carlsbad, CA 92009 |
|
|
147,414 |
(3) |
|
|
* |
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David B. Kilpatrick
9105 St. Cloud Lane
Bakersfield, CA 93311 |
|
|
70,000 |
(4) |
|
|
* |
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|
|
|
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Dennis M. Swenson
5360 Lakeshore Drive
Littleton, CO 80123 |
|
|
50,000 |
(5) |
|
|
* |
|
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|
|
|
|
|
|
|
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Tucker L. Franciscus
1675 Broadway, Suite 2450
Denver, Colorado 80202 |
|
|
50,000 |
(6) |
|
|
* |
|
|
|
|
|
|
|
|
|
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Kenneth R. Berry, Jr.
1675 Broadway, Suite 2450
Denver, Colorado 80202 |
|
|
472,865 |
(7) |
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1.2 |
% |
|
|
|
|
|
|
|
|
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All Executive Officers and Directors as a
group
(five persons) |
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2,883,113 |
(1)(2)(3)(4)(5)(6) |
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7.4 |
% |
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Victory Oil Company
222 West Sixth Street, Suite 1010
San Pedro, California 90731 |
|
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2,978,428 |
(7) |
|
|
7.9 |
% |
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|
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|
|
|
|
|
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Eastbourne Capital Management, L.L.C.
1101 Fifth Avenue, Suite 160
San Rafael, CA 94901 |
|
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7,141,329 |
(8) |
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18.8 |
% |
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|
|
|
|
|
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|
Wellington Management Company, LLP
75 State Street
Boston, MA 02109 |
|
|
5,307,500 |
(9) |
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14.0 |
% |
|
|
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|
|
|
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|
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Crestview Capital Master LLC
95 Revere Drive Suite A
Northbrook, IL 60052 |
|
|
1,987,875 |
(9) |
|
|
5.2 |
% |
|
|
|
| (*) |
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Less than one percent. |
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| (1) |
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“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, |
34
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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. |
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| (2) |
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The shares shown for Mr. Singdahlsen include 200,000 shares owned by Mr. Singdahlsen’s two
minor children. Also includes options to purchase 100,000 shares at $5.98 per share until
November 27, 2005, options to purchase 15,000 shares at $1.82 per share until April 12, 2007,
options to purchase 133,334 shares at $0.29 per share until February 4, 2010, options to
purchase 54,500 shares at $1.30 per share until February 4, 2010, and options to purchase
40,000 shares at $0.96 per share until November 17, 2014. |
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| (3) |
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Includes 13,000 shares of common stock owned by Mr. Rhodes and 64,414 shares of common stock
owned by Adventure Seekers Travel, Inc. Adventure Seekers is owned by Mr. Rhodes’ wife and
Mr. Rhodes is the President of Adventure Seekers. Also includes options to purchase 20,000
shares at $1.65 per share until April 11, 2007 and options to purchase 50,000 shares at $1.15
per share until October 14, 2009 that currently are exercisable. Excludes 171,625 shares that
are held by Whittier Energy Company. Mr. Rhodes is a President and CEO of Whittier Energy
Company. Mr. Rhodes disclaims beneficial ownership of the shares beneficially owned by
Whittier Energy Company |
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| (4) |
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Includes options to purchase 20,000 shares at $1.72 per share until June 4, 2007, and options
to purchase 50,000 shares at $1.15 per share until October 14, 2009 that currently are
exercisable that are owned by Mr. Kilpatrick. |
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| (5) |
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Includes options to purchase 50,000 shares at $1.24 per share until October 1, 2009 that are
exercisable. The options expire five years from the date that they become exercisable by Mr.
Swenson. |
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| (6) |
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Includes options to purchase 50,000 shares at $.94 share until September 1, 2009. Does not
include options to purchase an additional 100,000 shares at $0.94 share until September 1,
2009, 50,000 of which become exercisable on September 1, 2006, and 50,000 of which become
exercisable on September 1, 2007. |
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| (7) |
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Includes the following securities held directly or indirectly by Kenneth R. Berry, Jr., who
is Vice President of Land: 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 300,000 shares of common stock at exercise prices ranging from $.29 to $5.44 per
share that currently are exercisable or that will become exercisable within the next 60 days. |
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| (8) |
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Based on the information contained in an amendment to Schedule 13D filed with the SEC on July
16, 2001. |
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| (9) |
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Based solely on information contained in Schedules 13D and 13G filed with the SEC. The shares
reflected include the shares beneficially owned by Eastbourne Capital Management, L.L.C., a
registered investment adviser, Richard Jon Barry, Manager of Eastbourne and the following
companies to which Eastbourne is investment adviser: Black Bear Offshore Master Fund Limited,
a Cayman Island exempted company, Black Bear Fund I, L.P. and Black Bear Fund II, LLC. These
shares include the equivalent shares of common stock underlying $6,958,000 of convertible
notes held by Black Bear Offshore Master Fund Limited, Black Bear Fund I, L.P. and Black Bear
Fund II, LLC. |
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| (10) |
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Based on information contained in a Schedule 13G filed with the SEC on October 11, 2005.
Includes 1,344,600 shares owned by J. Caird Partners, L.P., and 1,472,600 shares owned by J.
Caird Investors (Bermuda) L.P., each of which is an entity controlled by Wellington, and each
of which is a 5% or greater beneficial owner of the Company’s common stock. |
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| (11) |
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Based solely on information provided to the Company by its transfer agent. |
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| 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
35
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 elsewhere in this Annual Report, in mid-October 2005, the Company
completed a Private Equity Placement consisting of the sale of 6.328 million shares of common
stock, priced at $1.30 per share, to a group of institutional and accredited individual investors.
Pursuant to the terms of the Private Placement, the Company has agreed to file a registration
statement covering the resale of these shares. On October 3, 2005, Estancia Corporation, an entity
solely owned by Kenneth Berry Jr., purchased 50,000 shares of common stock pursuant to the Private
Placement, and a trust of which Mr. Berry is Trustee and a beneficiary purchased an additional
20,000 shares of common stock pursuant to the Private Placement. This transaction was approved by
the Board of Directors of the Company.
During the fiscal year ended August 31, 2005, there were no other transactions between the
Company and its directors, executive officers or known holders of greater than five percent of the
Company’s common stock in which the amount involved exceeded $60,000 and in which any of the
foregoing persons had or will have a material interest.
ITEM 13. EXHIBITS
Exhibit Index
| |
|
|
| Number |
|
Description |
23.1
|
|
Consent of HEIN & Associates LLP. |
|
|
|
23.2
|
|
Consent of Ryder Scott Company |
|
|
|
31
|
|
Rule 13a – 14(a) Certifications of Chief Executive Officer and Chief Financial Officer |
|
|
|
32
|
|
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 |
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees
Hein & Associates, LLP, the Company’s principal accountants, billed the Company approximately
$79,000 and $47,000 for the years ended August 31, 2005 and 2004, respectively. Hein & Associates,
LLP was hired in November 2003 as the Corporation’s certified independent accountant. Hein’s
professional services, as of August 31, 2005, included review of financial statements included in
the Company’s Forms 10-Q, and services provided in connection with regulatory filings.
Audit-Related Fees
For the year ended August 31, 2005, Hein & Associates, LLP billed the Company approximately
$2,000 for work performed in the preparation of a Form 8-K filed during fiscal 2005.
For the year ended August 31, 2004, Hein & Associates, LLP also audited the historical summary
of oil and gas operations of Venus Exploration Inc., which was included in a Form 8-K as filed by
the Company, and issued currently dated consents in connection with the Company’s Form S-3 filings.
For these services Hein & Associates LLP, billed the Company $28,757.
36
Tax Fees
There were no amounts billed by Hein & Associates, LLP for professional services for tax
compliance, tax advice, and tax planning for those fiscal years.
All Other Fees
For the years ended August 31, 2005 and August 31, 2004, 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.
37
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
| |
|
|
|
|
| |
PYR ENERGY CORPORATION
|
|
| Date: November 28, 2005 |
By: |
/s/ D. Scott Singdahlsen
|
|
| |
|
D. Scott Singdahlsen |
|
| |
|
Chief Executive Officer |
|
| |
| |
|
|
|
|
| |
|
|
| Date: November 28, 2005 |
By: |
/s/ Jane M. Richards
|
|
| |
|
Jane M. Richards |
|
| |
|
Principal Accounting Officer |
|
| |
In accordance with the requirements of the Exchange Act, this report has been signed below by
the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| |
|
|
|
|
| Signatures |
|
Title |
|
Date |
| |
/s/ D. Scott Singdahlsen
D. Scott Singdahlsen
|
|
Chief Executive Officer,
President and Chief
Financial Officer
|
|
November 28, 2005 |
|
|
|
|
|
/s/ David Kilpatrick
David Kilpatrick
|
|
Chairman Of The Board
|
|
November 28, 2005 |
|
|
|
|
|
/s/ Dennis M. Swenson
Dennis M. Swenson
|
|
Director
|
|
November 28, 2005 |
|
|
|
|
|
/s/ Bryce W. Rhodes
Bryce W. Rhodes
|
|
Director
|
|
November 28, 2005 |
38
PYR ENERGY CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| |
|
|
|
|
F-2 |
|
|
F-3 |
|
|
F-4 |
|
|
F-5 |
|
|
F-6 – F-7 |
|
|
F-8 – F-21 |
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
PYR Energy Corporation
Denver, Colorado
We have audited the consolidated balance sheets of PYR Energy Corporation and subsidiaries as of
August 31, 2005 and 2004, 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 Company’s management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with 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, 2005 and 2004, 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 10, 2005
The accompanying notes are an integral part of the financial statements.
F-2
PYR ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
| |
|
|
|
|
|
|
|
|
| |
|
August 31, |
|
| |
|
2005 |
|
|
2004 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current Assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
2,934 |
|
|
$ |
6,038 |
|
Oil and Gas Receivables |
|
|
1,618 |
|
|
|
477 |
|
Other receivable |
|
|
124 |
|
|
|
750 |
|
Prepaid expenses and other assets |
|
|
59 |
|
|
|
103 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
4,735 |
|
|
|
7,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and Equipment, at cost |
|
|
|
|
|
|
|
|
Oil and gas properties under full cost, net |
|
|
13,242 |
|
|
|
8,851 |
|
Furniture and equipment, net |
|
|
29 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
13,271 |
|
|
|
8,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets: |
|
|
|
|
|
|
|
|
Deferred financing costs and other assets |
|
|
80 |
|
|
|
65 |
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
18,086 |
|
|
$ |
16,311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
89 |
|
|
$ |
83 |
|
Accrued expenses: |
|
|
|
|
|
|
|
|
Ad valorem tax payable |
|
|
65 |
|
|
|
65 |
|
Accrued interest payable |
|
|
94 |
|
|
|
90 |
|
Accrued net profits payable |
|
|
1,287 |
|
|
|
— |
|
Other accrued liabilities |
|
|
219 |
|
|
|
200 |
|
|
|
|
|
|
|
|
|
|
|
1,665 |
|
|
|
355 |
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation |
|
|
904 |
|
|
|
868 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
2,658 |
|
|
|
1,306 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Liabilities: |
|
|
|
|
|
|
|
|
Convertible Notes |
|
|
6,958 |
|
|
|
6,623 |
|
Asset retirement obligation |
|
|
293 |
|
|
|
290 |
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
7,251 |
|
|
|
6,913 |
|
|
|
|
|
|
|
|
|
|
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 -
31,640,259 at 8/31/05 and 31,564,426 shares at
8/31/04 |
|
|
32 |
|
|
|
32 |
|
Capital in excess of par value |
|
|
43,294 |
|
|
|
43,221 |
|
Accumulated deficit |
|
|
(35,149 |
) |
|
|
(35,161 |
) |
|
|
|
|
|
|
|
Total stockholders’ equity |
|
|
8,177 |
|
|
|
8,092 |
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders’ Equity |
|
$ |
18,086 |
|
|
$ |
16,311 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
F-3
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
| |
|
|
|
|
|
|
|
|
| |
|
Years Ended August 31, |
|
| |
|
2005 |
|
|
2004 |
|
Revenues: |
|
|
|
|
|
|
|
|
Oil and gas revenues |
|
$ |
6,102 |
|
|
$ |
863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
1,104 |
|
|
|
335 |
|
Net profits expense |
|
|
1,343 |
|
|
|
– |
|
Accretion expense |
|
|
25 |
|
|
|
100 |
|
Impairment |
|
|
580 |
|
|
|
– |
|
Depreciation, depletion and amortization |
|
|
868 |
|
|
|
173 |
|
General and administrative |
|
|
1,909 |
|
|
|
1,324 |
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
5,829 |
|
|
|
1,932 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) From Operations |
|
|
273 |
|
|
|
(1,069 |
) |
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
Interest income |
|
|
93 |
|
|
|
28 |
|
Interest (expense) |
|
|
(343 |
) |
|
|
(327 |
) |
Other (expense) income |
|
|
(11 |
) |
|
|
9 |
|
|
|
|
|
|
|
|
Total other income (expense) |
|
|
(261 |
) |
|
|
(290 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
|
$ |
12 |
|
|
$ |
(1,359 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) Per Common Share -Basic And Diluted |
|
$ |
0.00 |
|
|
$ |
(.05 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding |
|
|
|
|
|
|
|
|
Basic |
|
|
31,597 |
|
|
|
25,790 |
|
Diluted |
|
|
32,290 |
|
|
|
25,790 |
|
The accompanying notes are an integral part of the financial statements.
F-4
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands)
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Capital in |
|
|
|
|
| |
|
Common Stock |
|
|
Excess of |
|
|
Accumulated |
|
| |
|
Shares |
|
|
Amount |
|
|
Par Value |
|
|
Deficit |
|
Balance, September 1, 2003 |
|
|
23,701 |
|
|
$ |
24 |
|
|
$ |
35,408 |
|
|
$ |
(33,802 |
) |
Issuance of common stock and
warrants for property and
rights to oil and gas
technology |
|
|
311 |
|
|
|
– |
|
|
|
371 |
|
|
|
– |
|
Exercise of common stock
options for cash |
|
|
52 |
|
|
|
– |
|
|
|
15 |
|
|
|
– |
|
Sale of common stock for cash
and underwriter warrants, net |
|
|
7,500 |
|
|
|
8 |
|
|
|
7,427 |
|
|
|
– |
|
Net (loss) |
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(1,359 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, August 31, 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 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
F-5
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| |
|
|
|
|
|
|
|
|
| |
|
Years Ended August 31, |
|
| |
|
2005 |
|
|
2004 |
|
Cash Flows From Operating Activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
12 |
|
|
$ |
(1,359 |
) |
Adjustments to reconcile net loss to net cash used by
operating activities |
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
868 |
|
|
|
173 |
|
Impairment |
|
|
580 |
|
|
|
— |
|
Amortization of financing costs |
|
|
3 |
|
|
|
3 |
|
Interest expense converted into debt |
|
|
335 |
|
|
|
319 |
|
Accretion of asset retirement obligation |
|
|
25 |
|
|
|
100 |
|
Stock options issued for director services |
|
|
15 |
|
|
|
— |
|
Changes in assets and liabilities |
|
|
|
|
|
|
|
|
(Increase) in accounts receivable |
|
|
(1,266 |
) |
|
|
(477 |
) |
Decrease (increase) in prepaids and other receivables |
|
|
44 |
|
|
|
(46 |
) |
Increase in accounts payable |
|
|
4 |
|
|
|
58 |
|
Increase in accrued expenses |
|
|
22 |
|
|
|
152 |
|
Increase in net profits liability |
|
|
1,287 |
|
|
|
— |
|
Other |
|
|
— |
|
|
|
(10 |
) |
|
|
|
|
|
|
|
Net cash provided (used) by operating activities |
|
|
1,929 |
|
|
|
(1,087 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
Cash paid for furniture and equipment |
|
|
(10 |
) |
|
|
(11 |
) |
Cash paid for oil and gas properties |
|
|
(5,862 |
) |
|
|
(5,103 |
) |
Proceeds from sale of exploration options |
|
|
750 |
|
|
|
500 |
|
Proceeds from sale of oil and gas properties |
|
|
49 |
|
|
|
632 |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(5,073 |
) |
|
|
(3,982 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities |
|
|
|
|
|
|
|
|
Proceeds from sale of common stock |
|
|
— |
|
|
|
8,175 |
|
Proceeds from exercise of options |
|
|
58 |
|
|
|
15 |
|
Cash paid for offering costs |
|
|
(18 |
) |
|
|
(739 |
) |
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
40 |
|
|
|
7,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (Decrease) Increase In Cash |
|
|
(3,104 |
) |
|
|
2,380 |
|
|
|
|
|
|
|
|
|
|
Cash, Beginning Of Year |
|
|
6,038 |
|
|
|
3,658 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash, End Of Year |
|
$ |
2,934 |
|
|
$ |
6,038 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the financial statements.
F-6
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(continued)
YEARS ENDED AUGUST 31, 2005 AND 2004
SUPPLEMENTAL CASH FLOW INFORMATION:
| |
|
|
|
|
|
|
|
|
| |
|
Years Ended August 31, |
|
| |
|
2005 |
|
|
2004 |
|
Cash paid for interest and income taxes |
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
Non-cash financing activities: |
|
|
|
|
|
|
|
|
Asset retirement obligation increase |
|
$ |
15 |
|
|
$ |
212 |
|
Net increase in payables for capital expenditures |
|
|
3 |
|
|
|
82 |
|
Debt issued for interest |
|
|
335 |
|
|
|
320 |
|
Common stock issued for the purchase of oil and gas properties |
|
|
— |
|
|
|
338 |
|
Warrants issued in connection with private placement of common stock |
|
|
— |
|
|
|
353 |
|
Warrants issued for rights to oil and gas technology |
|
|
— |
|
|
|
34 |
|
Third party exercise of right to drill option (collected in 2005) |
|
|
— |
|
|
|
750 |
|
The accompanying notes are an integral part of the financial statements.
F-7
PYR
ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the fiscal years ended August 31, 2004 and 2005
| 1. |
|
Organization And Summary Of Significant Accounting Policies |
| |
| |
|
Organization And Business – PYR Energy Corporation (the “Company”) is an independent
oil and gas company primarily engaged in the exploration for, acquisition, development and
production of, crude oil and natural gas. The Company’s current activities are principally
conducted in the Rocky Mountains, Texas, and Gulf Coast regions of the United States. |
| |
| |
|
On February 18, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC were formed as
wholly owned subsidiaries of PYR Energy Corporation. The purpose of these entities is to own
and develop certain assets related to designated individual exploration projects. |
| |
| |
|
On May 7, 2004, PYR acquired certain oil and gas assets of Venus Exploration, Inc. (“Venus”)
out of Bankruptcy. The Venus assets acquired include interests in 80 non-operated wells in
Utah, Oklahoma and Texas. New drilling and workovers have been conducted since the acquisition
date and include two recent discoveries. |
| |
| |
|
Basis Of Presentation – The accompanying consolidated financial statements for the
year ended August 31, 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
management’s best estimate of the amount that may not be collectible. |
| |
| |
|
Other Receivables – During fiscal 2004, an unaffiliated third party exercised an
option to drill. As a result of this exercise, the Company recorded a $750,000 receivable for
this option. This receivable was collected in fiscal 2005. |
| |
| |
|
Oil And Gas Properties – The Company utilizes the full cost method of accounting for
oil and gas activities. Under this method, subject to a limitation based on estimated value,
all costs associated with property acquisition, exploration and development, including costs
of unsuccessful exploration, are capitalized within a cost center. The Company’s oil and gas
properties are located within the United States and Canada. Properties within these
respective countries constitute separate cost centers. No gain or loss is recognized upon the
sale or abandonment of undeveloped or producing oil and gas properties unless the sale
represents a significant portion of oil and gas properties and the gain significantly alters
the relationship between capitalized costs and proved oil and gas reserves of the cost center.
Depreciation, depletion and amortization of oil and gas properties is computed on the units
of production method based on proved reserves. Amortizable costs include estimates of future
development costs of proved undeveloped reserves. |
| |
| |
|
Capitalized costs of oil and gas properties may not exceed an amount equal to the present
value, discounted at 10%, of the estimated future net cash flows from proved oil and gas
reserves plus the cost, or estimated fair market value, if lower, of unproved properties.
Should capitalized costs exceed this ceiling, an impairment is recognized. The present value
of 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. |
F-8
| |
|
The Company utilizes the full cost accounting method of accounting for oil and gas activities
and in 2005 and 2004 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. |
| |
| |
|
During 2004, the Company acquired the rights to certain proven oil and gas drilling technology
for unlimited use on specified areas of interest. The cost of these rights are being included
as part of the Company’s full cost pools. |
| |
| |
|
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. 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
Company’s product entitlement. |
| |
| |
|
Deferred Financing Costs – Costs incurred in connection with the execution of the
Company’s 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 Company’s 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 Company’s oil and gas business
makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices
have been volatile in the past and can be expected to be volatile in the future. By
definition, proved reserves are based on current oil and gas prices and estimated reserves,
which is considered a significant estimate by the Company, which is subject to changes. Price
declines reduce the estimated quantity of proved reserves and increase annual amortization
expense (which is based on proved reserves) and may impact the impairment analysis of the
Company’s full cost pool. |
F-9
| |
|
Net Income (Loss) Per Share – Basic net income (loss) 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. Other dilutive
securities are not considered in the calculation of diluted net income (loss) per share as
their inclusion would be anti-dilutive. |
| |
| |
|
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). The Company has elected to
continue to account for its employee stock compensation plans as prescribed under APB 25. Had
compensation cost for the Company’s stock-based compensation plans been determined based on
the fair value at the grant dates for awards under those plans consistent with the method
prescribed in SFAS 123, the Company’s net (loss) and (loss) per share for the years ended
August 31, 2005 and 2004 would have been increased to the pro forma amounts indicated below: |
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| |
|
(in thousands, except per share data) |
|
Net income (loss): |
|
|
|
|
|
|
|
|
As reported |
|
$ |
12 |
|
|
$ |
(1,359 |
) |
Total compensation cost
determined under the fair value
base method for all awards |
|
|
(331 |
) |
|
|
(1,050 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net loss |
|
$ |
(319 |
) |
|
$ |
(2,409 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net pro forma income (loss) per share: |
|
|
|
|
|
|
|
|
As reported – Basic and Dilutive |
|
$ |
(0.00 |
) |
|
$ |
(0.05 |
) |
|
|
|
|
|
|
|
Pro forma – Basic and Dilutive |
|
$ |
(0.01 |
) |
|
$ |
(0.09 |
) |
|
|
|
|
|
|
|
See Note 8 with respect to assumptions used.
Gas Balancing – The Company uses the sales method of accounting for gas balancing of
gas production, and would recognize a liability if the existing proven reserves were not
adequate to cover the current imbalance situation. As of August 31, 2005, the Company was
under-produced by 30 MMcfs (unaudited) which represents approximately $217,000 in gas revenues
based on an average sales price of $7.23 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
Company’s common stock at the rate of $1.30 per share, at the option of the holder. The
company considers the notes to be stated at fair value due to arms length negotiation of the
transaction and the conversion feature.
Concentration Of Risk – Financial instruments which potentially subject the Company to
concentrations of credit risk consist of cash and receivables. The Company maintains cash
accounts at one financial institution. The Company periodically evaluates the credit
worthiness of financial institutions, and maintains cash accounts only in large high quality
financial institutions, thereby minimizing exposure for deposits in excess of federally
insured amounts. The Company believes that credit risk associated cash is remote.
The Company has concentrated its United States exploration and production activities primarily
in the Rocky Mountain, Texas and Gulf Coast regions. All significant activities in these
segments have been with industry partners.
F-10
As of August 31, 2005, there were no reserves associated with the Canadian cost center. The
Company’s 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.
Customers accounting for 10 percent or more of gross revenue, all representing purchasers of
oil and gas, for the years ended August 31, 2005 and 2004 are as follows:
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
Customer A |
|
|
38 |
% |
|
|
|
|
Customer B |
|
|
22 |
% |
|
|
|
|
Customer C |
|
|
10 |
% |
|
|
|
|
Customer D |
|
|
|
|
|
|
22 |
% |
Customer E |
|
|
|
|
|
|
20 |
% |
Customer F |
|
|
|
|
|
|
16 |
% |
Customer G |
|
|
|
|
|
|
13 |
% |
Reclassification – Certain reclassifications have been made to the 2004 financial
statements to conform to 2005 presentation. Such reclassifications had no effect on the net
income (loss).
Recent Accounting Pronouncements – In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB
Statement No. 3 (SFAS 154). SFAS 154 requires retrospective application to prior
periods’ financial statements for changes in accounting principle, unless it is impracticable
application to prior periods’ financial statements for changes in accounting principle,
unless it is impracticable to determine either the period-specific effects or the cumulative
effect of the change. SFAS 154 also requires that a change in depreciation, amortization, or
depletion method for long-lived, non-financial assets be accounted for as a change in
accounting estimate affected by a change in accounting principle. SFAS 154 is effective for
accounting changes and corrections of errors made in fiscal years beginning after December
15, 2005. The implementation of SFAS 154 is not expected to have a material impact on our
condensed consolidated results of operations, financial position or cash flows.
In December 2004, the FASB 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. 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 after, interim or annual periods, beginning after June
15, 2005, which for us will be the first quarter of fiscal 2006. 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.
| 2. |
|
Acquisition of Properties |
| |
| |
|
In 2005, the Company acquired additional working and revenue interest in two producing
properties and additional interest in undeveloped properties located in the Hansford Prospect
in Texas for a purchase price of approximately $440,000. |
| |
| |
|
In 2004, the Company acquired certain oil and gas properties from Venus Exploration for cash
consideration of $3.3 million. The purchase also provides for the Company to pay a net profits
interest payable to the Venus Exploration |
F-11
| |
|
Trust (“Trust”). The net profits interest, which applies only to the exploration and
exploitation projects on the Venus acreage being acquired, varies from 25% to 50% with respect
to different Venus exploration and exploitation project areas, and decreases by one-half of
its original amount after a total of $3.3 million in net profits proceeds has been paid to the
Trust. Venus was in Chapter 11 Bankruptcy, and the properties were acquired through public
auction as approved by the United States Bankruptcy Court. This acquisition was considered a
purchase transaction and the properties acquired were recorded based on the consideration paid
as of the closing date of May 8, 2004. Therefore, the statement of operations includes the
revenues and operating expenses of the Venus properties for the period from May 2004 and
thereafter. |
| |
| |
|
Below is certain unaudited pro forma information based on historical financial information
assuming the acquisition had occurred as of the beginning of fiscal 2004 (in thousands, except
per share data): |
| |
|
|
|
|
| |
|
2004 |
|
Revenues |
|
$ |
1,847 |
|
Net loss before cumulative effect of accounting change |
|
$ |
(1,055 |
) |
Net loss |
|
$ |
(1,055 |
) |
Net loss per share |
|
$ |
(.04 |
) |
| |
|
The above, however, is not necessarily indicative of results which would have occurred if the
transaction had closed as of the earlier date or of future results of operations. |
| |
| |
|
To finance the purchase and to provide additional working capital, the Company issued shares
of its common stock as described in Note 8. |
| |
| 3. |
|
Property and Equipment |
| |
| |
|
Oil and Gas Properties – Oil and gas properties at August 31, 2005 and 2004 consisted
of the following: |
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| |
|
(in thousands) |
|
Oil and gas properties, full cost method |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unevaluated costs, not subject to amortization |
|
|
|
|
|
|
|
|
United States |
|
$ |
5,164 |
|
|
$ |
4,936 |
|
Canada |
|
|
— |
|
|
|
558 |
|
Evaluated costs |
|
|
37,767 |
|
|
|
32,740 |
|
|
|
|
|
|
|
|
|
|
|
42,931 |
|
|
|
38,234 |
|
Less accumulated depreciation, depletion,
amortization and impairment |
|
|
(29,689 |
) |
|
|
(29,383 |
) |
|
|
|
|
|
|
|
|
|
$ |
13,242 |
|
|
$ |
8,851 |
|
|
|
|
|
|
|
|
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
$2.0 million) and exploration costs and exploratory wells in progress (totaling approximately
$3.2 million) as of the end of the year have been excluded from depletable costs pending
further evaluation as of August 31, 2005 are as follows (in thousands):
| |
|
|
|
|
Period Incurred |
|
|
|
|
2005 |
|
$ |
3,780 |
|
2004 |
|
|
1,222 |
|
2003 |
|
|
162 |
|
|
|
|
|
|
|
$ |
5,164 |
|
|
|
|
|
F-12
For the years ended August 31, 2005 and 2004, the Company did not recognize any impairment
expense against the capitalized oil and gas properties in the United States, as determined by
the ceiling test performed pursuant to Regulation S-X Rule 4-10(c)(2). 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, 2005 and 2004 was $860,000 and $160,000, or $6.74 and $6.65 per barrel of oil equivalent
production, respectively. Depreciation of assets recognized in accordance with the Asset
Retirement Obligation calculation is included in these amounts (see below).
Information relating to the Company’s costs incurred in its oil and gas operations during the
years ended August 31, 2005 and 2004 is summarized as follows:
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| |
|
(in thousands) |
|
Property acquisition costs |
|
$ |
440 |
|
|
$ |
4,647 |
|
Exploration costs |
|
|
5,101 |
|
|
|
466 |
|
Development costs |
|
|
276 |
|
|
|
127 |
|
|
|
|
|
|
|
|
| |
|
|
$ |
5,817 |
|
|
$ |
5,240 |
|
|
|
|
|
|
|
|
Furniture and Equipment – Furniture and equipment at August 31, 2005 and 2004
consisted of the following:
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| |
|
(in thousands) |
|
Furniture and equipment |
|
$ |
149 |
|
|
$ |
139 |
|
Less accumulated depreciation |
|
|
(120 |
) |
|
|
(112 |
) |
|
|
|
|
|
|
|
| |
|
|
$ |
29 |
|
|
$ |
27 |
|
|
|
|
|
|
|
|
| |
|
Depreciation expense associated with capitalized office furniture and equipment during fiscal
2005 and 2004 was $8,000 and $13,000 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 asset’s carrying amount. Over time, accretion of the
liability is recognized as an operating expense and the capitalized cost is depreciated over
the expected useful life of the related asset. The Company’s asset retirement obligations
relate primarily to the plugging, dismantlement, removal, site reclamation and similar
activities of its oil and gas properties. |
F-13
| |
|
The following table summarizes activity related to the accounting for asset retirement
obligations for the fiscal years ended August 31, 2005 and August 31, 2004: |
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| |
|
(in thousands) |
|
Asset retirement obligations, beginning of fiscal year |
|
$ |
1,158 |
|
|
$ |
846 |
|
Liabilities incurred |
|
|
19 |
|
|
|
212 |
|
Liabilities settled |
|
|
— |
|
|
|
— |
|
Accretion of asset retirement obligation including
revision of estimates |
|
|
20 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, end of fiscal year |
|
|
1,197 |
|
|
|
1,158 |
|
Less current portion |
|
|
(904 |
) |
|
|
(868 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion |
|
$ |
293 |
|
|
$ |
290 |
|
|
|
|
|
|
|
|
| 5. |
|
Net Income (loss) per Share |
| |
| |
|
The following table sets forth the computation of basic and diluted earning (loss) per share
(in thousands except per share data): |
| |
|
|
|
|
|
|
|
|
| |
|
Years Ended August 31, |
|
| |
|
2005 |
|
|
2004 |
|
| |
|
|
Numerator: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
12 |
|
|
$ |
(1,359 |
) |
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
Weighted-average shares outstanding |
|
|
31,597 |
|
|
|
25,790 |
|
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
Assumed exercise of dilutive options |
|
|
693 |
|
|
|
— |
|
|
|
|
|
|
|
|
Weighted-average shares and dilutive
potential common shares |
|
|
32,290 |
|
|
|
25,790 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and dilutive income (loss) per share |
|
$ |
0.00 |
|
|
$ |
(0.05 |
) |
|
|
|
|
|
|
|
| 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
Company’s common stock at the rate of $1.30 per share, at the option of the holder. No
beneficial interest has been accrued to the notes, as the conversion price approximates the
fair market value of the common shares as of the transaction date. Interest is payable
semiannually in May and November. |
| |
| |
|
At the option of the Company, accrued interest can be paid in cash or added to the principal
amount of the notes. The Company elected to add accrued interest of approximately $335,000 and
$319,000 during fiscal years 2005 and 2004, respectively, to the balance of the notes. As of
August 31, 2005 the balance of the notes is approximately $7.0 million. |
| |
| 7. |
|
Income Taxes |
| |
| |
|
The Company follows the asset and liability method of accounting for deferred income taxes.
Deferred tax assets and liabilities are determined based on the temporary differences between
the financial statement and tax basis of assets and liabilities. At August 31, 2005, the
Company had approximately $40.3 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 |
F-14
|
|
2025 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, |
|
| |
|
2005 |
|
|
2004 |
|
Federal statutory income tax rate |
|
|
(34 |
%) |
|
|
(34 |
%) |
Increase in valuation allowance |
|
|
34 |
% |
|
|
34 |
% |
|
|
|
|
|
|
|
Effective rate |
|
|
– |
|
|
|
– |
|
|
|
|
|
|
|
|
The principal sources of temporary differences resulting in deferred tax assets and tax
liabilities at August 31, 2005 and 2004 are as follows:
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| (In thousands) |
|
|
|
|
|
|
|
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Property impaired for
financial reporting, but
capitalized for tax; offset
by intangible drilling and
other exploration costs
capitalized for financial
reporting purposes but
deducted for tax purposes |
|
$ |
– |
|
|
$ |
2,500 |
|
Asset retirement obligation |
|
|
444 |
|
|
|
400 |
|
Tax loss carryforward |
|
|
15,296 |
|
|
|
11,400 |
|
|
|
|
|
|
|
|
Total deferred tax assets |
|
|
15,740 |
|
|
|
14,300 |
|
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 |
|
|
(1,269 |
) |
|
|
– |
|
|
|
|
|
|
|
|
Net deferred tax asset |
|
|
14,471 |
|
|
|
14,300 |
|
Valuation allowance |
|
|
(14,471 |
) |
|
|
(14,300 |
) |
|
|
|
|
|
|
|
Net deferred taxes |
|
$ |
– |
|
|
$ |
– |
|
|
|
|
|
|
|
|
| |
|
The valuation allowance increased by approximately $171,000 and $500,000 in 2005 and 2004,
respectively. |
| |
| 8. |
|
Stockholders’ Equity: |
| |
| |
|
Preferred Stock –In April 1999, the stockholders of the Company approved an amendment
to the Certificate of Incorporation pursuant to which the Company was authorized to issue
1,000,000 shares of preferred stock, with a par value of $.001 per share. Such shares of
preferred stock may be issued with such preferences and rights as determined by the Board of
Directors. |
| |
| |
|
Common Stock – During the year ended August 31, 2004, the Company completed the sale
of 7.5 million shares of common stock pursuant to a private placement at a price of $1.09 per
share. The first tranche of the Placement, consisting of
4.5 million shares and approximately $4.9 million in
gross proceeds, was received and accepted in early May 2004. The second tranche of the
Placement, consisting of 3.0 million shares and approximately
$3.3 million in gross proceeds, was received and
accepted in late June 2004. Costs of the offering were
approximately $1.1 million which
included warrants valued at approximately $353,000. |
F-15
| |
|
During the year ended August 31, 2004, the Company issued 125,000 shares of common stock for
an interest in oil and gas properties, valued as of the date of the transaction at $90,000
($.72 per share). The Company also issued 186,403 shares of common stock for an interest in
rights to oil and gas technology, valued as of the date of the transaction at approximately
$248,000 ($1.33 per share). |
| |
| |
|
Warrants – During the year ended August 31, 2004, the Company issued a warrant to
purchase 100,000 shares of common stock at an exercise price of $.65 per share through
December 1, 2006, for rights to oil and gas technology. The warrants are valued at $34,000,
based on the Black-Scholes option pricing model, and this amount was included in oil and gas
properties for the year ended August 31, 2004. During fiscal 2004, the Company also issued
warrants in partial payment of a commission for financial advisory services performed in
connection with the private placement of common stock in May and June, 2004. Included in this
issuance was (i) a warrant to purchase 225,000 shares of common stock at an exercise price of
$1.30 per share and (ii) a warrant to purchase 150,000 shares of common stock at an exercise
price of $1.24 per share. These warrants expire on May 5, 2009 and June 11, 2009,
respectively. The warrants are valued at $229,500 and $123,000, respectively, based on the
Black-Scholes option pricing model, and these amounts were included as costs associated with
the private placement in additional paid-in capital for the year ended August 31, 2004. |
| |
| |
|
At August 31, 2005, the status of outstanding warrants is as follows: |
| |
|
|
|
|
|
|
| Issue |
|
Shares |
|
Exercise |
|
Expiration |
| Date |
|
Exercisable |
|
Price |
|
Date |
May 9, 2002 |
|
200,000 |
|
$1.49 |
|
May 8, 2007 |
December 1, 2003 |
|
100,000 |
|
$0.65 |
|
December 1, 2006 |
May 5, 2004 |
|
225,000 |
|
$1.30 |
|
May 5, 2009 |
June 11, 2004 |
|
150,000 |
|
$1.24 |
|
June 11, 2009 |
At August 31, 2005, the weighted average remaining contractual life of outstanding warrants
was 2.6 years.
Stock Options – Under two stock option plans, options to purchase common stock may be
granted until 2010. Stock options are granted to employees at exercise prices equal to the
fair market value of the Company’s stock at the dates of grants. Generally, options vest 1/3
each year for a period of three years from grant date and can have a maximum term of up to 10
years. Options are issued to key employees and other persons who contribute to the success of
the Company. The Company has reserved 3,250,000 shares of common stock for these plans. At
August 31, 2005 and 2004, options to purchase 604,250 and 731,000 shares, respectively, were
available to be granted pursuant to the stock option plans.
The status of outstanding options granted pursuant to the plans are as follows:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
Weighted Avg. |
|
|
Weighted Avg. Fair |
|
| |
|
Number of Shares |
|
|
Exercise Price |
|
|
Value |
|
Options Outstanding – August 31, 2003 |
|
|
2,216,500 |
|
|
$ |
2.07 |
|
|
|
|
|
Granted |
|
|
843,000 |
|
|
$ |
.95 |
|
|
$ |
.61 |
|
Exercised |
|
|
(51,666 |
) |
|
$ |
.29 |
|
|
|
|
|
Expired |
|
|
(824,000 |
) |
|
$ |
1.87 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding – August 31, 2004 |
|
|
2,183,834 |
|
|
$ |
1.76 |
|
|
|
|
|
Granted |
|
|
675,000 |
|
|
$ |
1.08 |
|
|
$ |
.68 |
|
Exercised |
|
|
(75,834 |
) |
|
$ |
.76 |
|
|
|
|
|
Expired |
|
|
(548,250 |
) |
|
$ |
2.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding – August 31, 2005 |
|
|
2,234,750 |
|
|
$ |
1.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable as of August 31, 2005 |
|
|
1,213,500 |
|
|
$ |
1.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-16
The calculated value of stock options granted under these plans, following calculation methods
prescribed by SFAS 123, uses the Black-Scholes stock option pricing model with the following
assumptions used:
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
Expected option life-years |
|
|
5-10 |
|
|
|
3-5 |
|
Risk-free interest rate |
|
|
3.3 – 4.0 |
% |
|
|
3.1 – 3.9 |
% |
Dividend yield |
|
|
0 |
|
|
|
0 |
|
Volatility |
|
|
57 – 83 |
% |
|
|
62 – 125 |
% |
At August 31, 2005 and 2004, the number of options exercisable was 1,213,500 and 1,076,168,
respectively, and the weighted average exercise price of these options was $1.76 and $1.64,
respectively.
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Options Outstanding |
|
|
|
|
| |
|
|
|
|
|
Remaining |
|
|
|
|
| |
|
August 31, |
|
|
Contractual Life |
|
|
Options Exercisable |
|
| Exercise Price |
|
2005 |
|
|
(years) |
|
|
at August 31, 2005 |
|
$0.29 – $0.46 |
|
|
400,000 |
|
|
|
4 |
|
|
|
283,334 |
|
$0.92 – $0.96 |
|
|
605,000 |
|
|
|
6 |
|
|
|
145,000 |
|
$1.02 – $1.30 |
|
|
739,750 |
|
|
|
4 |
|
|
|
385,166 |
|
$1.46 – $1.82 |
|
|
300,000 |
|
|
|
3 |
|
|
|
210,000 |
|
$5.44 – $5.98 |
|
|
190,000 |
|
|
|
1 |
|
|
|
190,000 |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total |
|
|
2,234,750 |
|
|
|
|
|
|
|
1,213,500 |
|
|
|
|
|
|
|
|
|
|
|
|
| 9. |
|
Commitments and Contingencies |
| |
| |
|
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 Samson’s 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 No.
1 Sidetrack 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 with other properties in which the Company has no
interest, many of which are non-productive. Samson has a large interest in these properties
that Samson has joined into the unit. Pursuant to Samson’s proposed pooling configuration,
the Company’s 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 Company’s 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. On September 13, 2005, the Court entered a Preliminary Injunction ordering Samson
to return the Company to pay status for the undisputed amounts upon which Samson had been
paying the Company prior to the filing of the suit. |
| |
| |
|
On August 22, 2005, Samson filed a lawsuit in District Court for Jefferson County, Texas,
58th Judicial District against the Company, claiming that Samson has the right to
serve as operator to drill and operate on the property to the east of the Sun Fee Well, which
is located on property in which the Company owns a majority interest. The Company holds a
100% interest in oil and gas leases that comprise 75% of the approximately 400-acre parcel on
which it is planning to drill a gas well to the same reservoir from which the Sun Fee Well
produces. In June 2005, the Company notified Samson of its intention to drill a well on this
property and offered Samson the opportunity to participate in the well. Samson elected to
participate in the well and demanded to be allowed to operate the well. Upon the Company’s
initial preparation of the drill site, which began in August 2005, Samson filed a lawsuit
seeking a judicial declaration of Samson’s exclusive right to operate the well and injunctive
relief enjoining the Company from continuing its drilling operations or serving as operator. |
F-17
The Company will continue to vigorously pursue and defend its rights with respect to the
foregoing litigations. The Company intends to continue to move forward with construction of
the potential drill site and to drill the well in order to protect its interests in the
underlying leases until such time as the issue is fully adjudicated.
On November 2, 2005, an adversary proceeding was filed against the Company in the on-going
bankruptcy proceeding of Venus Exploration Company (“Venus”) in the U.S. Bankruptcy Court for the
Eastern District of Texas. In the adversary proceeding, the Venus Exploration Trust, representing
the interests of the secured creditors (the “Trust”), seeks a full accounting, with interest and
attorneys’ fees, of the net profits interest accounts established under the Net Profit Conveyance
by which the Company purchased Venus’ assets and is to account for proceeds generated from certain
identified, potential income-generating projects less costs. Presently, proceeds are generated by
the Nome and Madison projects in Jefferson County, Texas. The Trust also seeks reformation of the
conveyance whereby future proceeds shall be paid by third-part
purchasers directly to the Trust,
from which the Company may subsequently request reimbursement of costs. Upon reconsideration of an
initial good-faith deduction of costs for anticipated drilling operations on the two projects and
prior to the filing of the adversary proceeding, the Company forwarded to the Trust a payment in
excess of $820,970, including interest, with over 35 pages of detailed accounting. The Company has
entered discussions with the Trust to withdraw and dismiss the proceeding in light of the payment,
which discussions are pending the return of the Trust’s counsel from foreign travel. As a result,
the lawsuit has not been served on the Company. Should the Trust refuse to dismiss and proceed
with service, the Company will vigorously defend its interests against the claims in this
proceeding.
Other Commitments and Contingencies
The following table summarizes the Company’s obligations and commitments, as of August
31, 2005 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 |
|
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
Thereafter |
|
Convertible Notes |
|
$ |
8,474 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
8,474 |
|
|
$ |
— |
|
Office Leases |
|
|
163 |
|
|
|
70 |
|
|
|
70 |
|
|
|
23 |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Cash
Obligations |
|
$ |
8,637 |
|
|
$ |
70 |
|
|
$ |
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 $57,000 and $114,000 for the years ended August 31, 2005 and
2004, respectively.
Delay Rentals – In conjunction with the Company’s working interests in undeveloped oil
and gas prospects, the Company must pay approximately $129,000 in delay rentals and other
costs during the fiscal year ending August 31, 2006 to maintain the right to explore these
prospects. The Company continually evaluates its leasehold interests, therefore certain
leases may be abandoned by the Company in the normal course of business.
Environmental – Oil and gas producing activities are subject to extensive Federal,
state and local environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and may require the Company
to remove or mitigate the environmental effects of the disposal or release of petroleum or
chemical substances at various sites. Environmental expenditures are expensed or capitalized
depending on their future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are expensed. Liabilities
for expenditures of a noncapital nature are recorded when environmental assessment and/or
remediation is probable, and the costs can be reasonably estimated.
Contingencies – The Company may from time to time be involved in various claims,
lawsuits, disputes with third parties, actions involving allegations of discrimination, or
breach of contract incidental to the operations of its
F-18
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, 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 |
|
| |
|
|
Year
ended August 31, 2004
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil and Gas Operations |
|
|
|
|
| |
|
|
|
|
|
United |
|
|
|
|
|
|
|
|
|
|
| |
|
Canada |
|
|
States |
|
|
Total |
|
|
Corporate |
|
|
Total |
|
| |
|
|
Revenue |
|
$ |
— |
|
|
$ |
863 |
|
|
$ |
863 |
|
|
$ |
— |
|
|
$ |
863 |
|
Expenses
Operating Costs |
|
|
(3 |
) |
|
|
(332 |
) |
|
|
(335 |
) |
|
|
— |
|
|
|
(335 |
) |
Depreciation, depletion and
amortization expense |
|
|
— |
|
|
|
(160 |
) |
|
|
(160 |
) |
|
|
— |
|
|
|
(160 |
) |
Asset retirement obligation accretion |
|
|
— |
|
|
|
(100 |
) |
|
|
(100 |
) |
|
|
— |
|
|
|
(100 |
) |
| |
|
|
Earnings (loss) from operations |
|
|
(3 |
) |
|
|
271 |
|
|
|
268 |
|
|
|
— |
|
|
|
268 |
|
Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,324 |
) |
|
|
(1,324 |
) |
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13 |
) |
|
|
(13 |
) |
Interest income and other expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37 |
|
|
|
37 |
|
F-19
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Oil and Gas Operations |
|
|
|
|
| |
|
|
|
|
|
United |
|
|
|
|
|
|
|
|
|
|
| |
|
Canada |
|
|
States |
|
|
Total |
|
|
Corporate |
|
|
Total |
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(327 |
) |
|
|
(327 |
) |
| |
|
|
Earnings (loss) before income taxes |
|
$ |
(3 |
) |
|
$ |
271 |
|
|
$ |
268 |
|
|
$ |
(1,627 |
) |
|
$ |
(1,359 |
) |
| |
|
|
| |
Capital Expenditures |
|
$ |
558 |
|
|
$ |
4,545 |
|
|
$ |
5,103 |
|
|
$ |
11 |
|
|
$ |
5,114 |
|
| |
|
|
Property and equipment, net |
|
$ |
558 |
|
|
$ |
8,293 |
|
|
$ |
8,851 |
|
|
$ |
27 |
|
|
$ |
8,878 |
|
| |
|
|
| 11. |
|
Subsequent Events |
| |
| |
|
In mid-October 2005, the Company completed a Private Equity Placement consisting of the sale
of 6.328 million shares of common stock at a price of $1.30 per share to a group of
institutional and accredited individual investors. Proceeds from the Placement will be used
for general corporate purposes and costs associated with the Company’s development drilling
portfolio. |
| |
| 12. |
|
Estimate of Proved Oil and Gas Reserves (Unaudited) |
| |
| |
|
At August 31, 2005, the estimated oil and gas reserves presented herein were derived from a
report prepared by Ryder Scott Company, an independent petroleum engineering firm. All
reserves are located within the continental United States. The Company had no oil and gas
reserves at August 31, 2003. The Company cautions that there are many inherent uncertainties
in estimating proved reserve quantities and in projecting future production rates and the
timing of development expenditures. Accordingly, these estimates are likely to change as
future information becomes available, and these changes could be material. |
| |
| |
|
The oil and gas reserve estimates presented below include all activity from the Company’s oil
and gas properties for 2005 and 2004. The Company had no proved reserves as of August 31,
2003. The Company realized production from its East Lost Hills prospect in 2004, but has not
recorded any proved reserves as it had been previously determined that reserves from this
prospect were not economic to produce. Revisions of previous estimates for 2004 are solely the
result of the current year production from the East Lost Hills prospect, and these amounts are
also included in production for 2004. |
| |
| |
|
Proved oil and gas reserves are the estimated quantities of crude oil, condensate, natural gas
and natural gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing economic and
operating conditions. |
| |
| |
|
Proved developed reserves are reserves expected to be recovered through existing wells with
existing equipment and operating methods. |
| |
| |
|
Analysis Of Changes In Proved Reserves – Estimated quantities of proved developed and
undeveloped reserves, as well as the changes during the years ended August 31, 2004 and 2005,
are as follows: |
| |
|
|
|
|
|
|
|
|
| |
|
Oil and Natural Gas |
|
|
Natural |
|
| |
|
Liquids |
|
|
Gas |
|
| |
|
(Bbls) |
|
|
(Mcf) |
|
Proved reserves at September 1, 2003 |
|
|
– |
|
|
|
– |
|
Purchase of reserves |
|
|
629,573 |
|
|
|
1,064,205 |
|
Revisions of previous estimates |
|
|
12,044 |
|
|
|
20,362 |
|
Extensions and discoveries |
|
|
57,219 |
|
|
|
370,927 |
|
Production |
|
|
(13,971 |
) |
|
|
(62,494 |
) |
|
|
|
|
|
|
|
Proved reserves at August 31, 2004 |
|
|
684,865 |
|
|
|
1,393,000 |
|
| |
Purchase of reserves |
|
|
— |
|
|
|
1,610,852 |
|
Revisions of previous estimates |
|
|
(80,027 |
) |
|
|
171,634 |
|
F-20
| |
|
|
|
|
|
|
|
|
| |
|
Oil and Natural Gas |
|
|
Natural |
|
| |
|
Liquids |
|
|
Gas |
|
| |
|
(Bbls) |
|
|
(Mcf) |
|
Extensions and discoveries |
|
|
23,475 |
|
|
|
884,579 |
|
Production |
|
|
(62,289 |
) |
|
|
(392,065 |
) |
|
|
|
|
|
|
|
Proved reserves at August 31, 2005 |
|
|
566,024 |
|
|
|
3,668,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves – end of year
|
|
|
|
|
|
|
|
|
August 31, 2004 |
|
|
559,629 |
|
|
|
842,000 |
|
August 31, 2005 |
|
|
503,767 |
|
|
|
1,345,000 |
|
The table below sets forth a standardized measure of the estimated discounted future net cash
flows attributable to the Company’s proved oil and gas reserves. Estimated future cash
inflows were computed by applying year end (August 31) prices of oil and gas (with
consideration of price changes only to the extent provided by contractual arrangements)
averaging $66.95 and $40.97 per Bbl of oil and $11.74 and $4.49 per mcf of gas for 2005 and
2004, 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
(in thousands)
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| |
|
|
Future cash inflows |
|
$ |
80,966 |
|
|
$ |
34,192 |
|
Future cash outflows: |
|
|
|
|
|
|
|
|
Production
cost(1) |
|
|
(24,168 |
) |
|
|
(13,519 |
) |
Development cost |
|
|
(5,255 |
) |
|
|
(2,426 |
) |
|
|
|
|
|
|
|
Future net cash , before income taxes |
|
|
51,543 |
|
|
|
18,247 |
|
Future income taxes |
|
|
(813 |
) |
|
|
– |
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
50,730 |
|
|
|
18,247 |
|
Adjustment to discount future annual net cash flows at 10% |
|
|
(21,978 |
) |
|
|
(7,203 |
) |
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
28,752 |
|
|
$ |
11,044 |
|
|
|
|
|
|
|
|
(1)
Production costs include lease operating expenses, production and ad
valorem taxes and net profits expense.
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,
2005 and 2004, respectively.
Changes in Standardized Measure of Estimated Discounted Net Cash Flows
(in thousands)
| |
|
|
|
|
|
|
|
|
| |
|
2005 |
|
|
2004 |
|
| |
|
|
Standardized measure, beginning of period |
|
$ |
11,044 |
|
|
$ |
– |
|
Sales of oil and gas, net of production costs and taxes |
|
|
(3,655 |
) |
|
|
(528 |
) |
Purchase of reserves in place |
|
|
7,232 |
|
|
|
6,942 |
|
Net change in sales prices, net of production cost |
|
|
10,062 |
|
|
|
2,725 |
|
Discoveries, extensions and improved recoveries, net
of future development cost |
|
|
7,100 |
|
|
|
1,464 |
|
Development costs incurred |
|
|
682 |
|
|
|
– |
|
Change in future development costs |
|
|
143 |
|
|
|
(692 |
) |
Revisions of quantity estimates |
|
|
(4,398 |
) |
|
|
314 |
|
Changes in future income tax |
|
|
(504 |
) |
|
|
– |
|
Accretion of discount |
|
|
1,046 |
|
|
|
– |
|
Other |
|
|
– |
|
|
|
819 |
|
|
|
|
|
|
|
|
Standardized measure, end of period |
|
$ |
28,752 |
|
|
$ |
11,044 |
|
|
|
|
|
|
|
|
F-21
SUBSIDIARIES OF THE REGISTRANT
| |
|
|
| Name |
|
State of Incorporation or Organization |
PYR Cumberland LLC
|
|
Colorado |
PYR Mallard LLC
|
|
Colorado |
PYR Pintail LLC
|
|
Colorado |
F-22
Exhibit Index
| |
|
|
| Number |
|
Description |
23.1
|
|
Consent of HEIN & Associates LLP. |
|
|
|
23.2
|
|
Consent of Ryder Scott Company |
|
|
|
31
|
|
Rule 13a – 14(a) Certifications of Chief Executive Officer and Chief Financial Officer |
|
|
|
32
|
|
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 |