U.S. Securities And Exchange Commission
Washington, D.C. 20549
FORM 10-QSB
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended November 30, 2004
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from _____________ to ______________
Commission File No. 001-15511
PYR ENERGY CORPORATION
----------------------
(Exact name of small business issuer as specified in its charter)
Maryland 95-4580642
-------- ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1675 Broadway, Suite 2450, Denver, CO 80202
------------------------------------- -----
(Address of principal executive offices) (Zip Code)
Issuer's telephone number, including area code (303) 825-3748
Check whether the issuer (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 reports), and (2) has been subject to such filing requirements for the past
90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
The number of shares outstanding of each of the issuer's classes of common
equity as of November 30, 2004 is as follows:
$.001 Par Value Common Stock 31,564,426
----------
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements 3
Balance Sheets - November 30, 2004 (Unaudited) and August 31, 2004 3
Statements of Operations - Three Months Ended November 30, 2004
and November 30, 2003 (Unaudited) 4
Statements of Cash Flows - Three Months Ended November 30, 2004
and November 30, 2003 (Unaudited) 5
Notes to Financial Statements 7
Item 2. Management's Discussion and Analysis or Plan of Operation 9
Item 3. Controls and Procedures 19
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 20
Item 2. Unregistered Sales o f Equity Securities and Use of Proceeds 20
Item 3. Defaults Upon Senior Securities 20
Item 4. Submission of Matters to a Vote of Security Holders 20
Item 5. Other Information 20
Item 6. Exhibits 20
Signatures 21
2
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
November 30, August 31,
2004 2004
(Unaudited)
CURRENT ASSETS ------------ ------------
Cash $ 5,978,834 $ 6,038,156
Oil and gas receivables 1,067,912 477,176
Other receivable -- 750,000
Prepaid expenses and other assets 27,986 102,239
------------ ------------
Total current assets 7,074,732 7,367,571
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 32,143 26,736
Oil and gas properties under full cost, net 9,893,754 8,851,351
------------ ------------
9,925,897 8,878,087
------------ ------------
OTHER ASSETS
Deferred financing costs and other assets 64,273 65,070
------------ ------------
64,273 65,070
------------ ------------
TOTAL ASSETS $ 17,064,902 $ 16,310,728
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 181,587 $ 83,042
Accrued expenses:
Ad valorem tax payable 67,135 65,068
Accrued interest payable 5,570 89,644
Accrued net profits interest payable 122,366 --
Other accrued liabilities 568,045 199,688
------------ ------------
763,116 354,400
Asset retirement obligation 868,163 868,163
------------ ------------
Total current liabilities 1,812,866 1,305,605
------------ ------------
LONG TERM LIABILITIES
Convertible notes 6,789,962 6,623,351
Asset retirement obligation 308,758 289,489
------------ ------------
Total long term liabilities 7,098,720 6,912,840
------------ ------------
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value; authorized 1,000,000 shares;
issued and outstanding - none -- --
Common stock, $.001 par value; authorized 75,000,000 shares;
issued and outstanding - 31,564,426 at 11/30/04 and
31,564,426 shares at 8/31/04 31,564 31,564
Capital in excess of par value 43,221,391 43,221,391
Accumulated deficit (35,099,639) (35,160,672)
------------ ------------
Total stockholders' equity 8,153,316 8,092,283
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 17,064,902 $ 16,310,728
============ ============
3
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended November 30,
------------------------------
2004 2003
------------ ------------
REVENUES
Oil and gas revenues $ 1,082,510 $ 40,018
------------ ------------
1,082,510 40,018
------------ ------------
OPERATING EXPENSES
Lease operating expenses 280,576 15,271
Accretion expense 6,300 21,152
Net profits interest expense 122,366 --
Depreciation and amortization 38,037 40,120
General and administrative 511,387 251,490
------------ ------------
Total operating expenses 958,666 328,033
INCOME (LOSS) FROM OPERATIONS 123,844 (288,015)
OTHER INCOME (EXPENSE)
Interest income 20,299 5,567
Other income 4,140 --
Interest (expense) (83,333) (79,354)
Other (expense) (3,918)
------------ ------------
Total other income (expense) (62,812) (73,787)
------------ ------------
NET INCOME (LOSS) $ 61,032 $ (361,802)
============ ============
NET INCOME (LOSS) PER COMMON
SHARE -BASIC AND DILUTED $ 0.00 $ (0.02)
============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 31,564,426 23,701,357
============ ============
4
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended November 30,
------------------------------
2004 2003
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 61,032 $ (361,802)
Adjustments to reconcile net income (loss) to
net cash provided (used) by operating activities
Depreciation and amortization 38,037 40,120
Amortization of financing costs 797 797
Interest expense converted into debt 166,611 158,577
Accretion of asset retirement obligation 6,300 21,152
Changes in assets and liabilities
(Increase) in accounts receivable (590,736) --
Decrease (increase) in prepaids and other receivables 74,253 (78,684)
Increase (decrease) in accounts payable 101,015 (7,381)
Increase in net profits interest liability 122,366 --
Increase (decrease) in accrued expenses 415,031 (40,045)
----------- -----------
Net cash provided (used) by operating activities 394,706 (267,266)
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (8,622) --
Cash paid for oil and gas properties (1,220,406) (276,389)
Proceeds from exercise of exploration options 750,000 --
Proceeds from sale of oil and gas properties 25,000 --
----------- -----------
Net cash used in investing activities (454,028) (276,389)
----------- -----------
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES -- --
----------- -----------
NET DECREASE IN CASH (59,322) (543,655)
CASH, BEGINNING OF PERIODS 6,038,156 3,657,938
----------- -----------
CASH, END OF PERIODS $ 5,978,834 $ 3,114,283
=========== ===========
5
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(continued)
THREE MONTHS ENDED NOVEMBER 30, 2004 AND 2003
(Unaudited)
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
During the three months ended November 30, 2004, the asset retirement obligation
increased by $12,969.
6
PYR ENERGY CORPORATION
Notes to Consolidated Financial Statements
November 30, 2004
(Unaudited)
The accompanying interim financial statements of PYR Energy Corporation are
unaudited. In the opinion of management, the interim data includes all
adjustments, consisting only of normal recurring adjustments, necessary for a
fair presentation of the results for the interim period. The results of
operations for the three months ended November 30, 2004 are not necessarily
indicative of the operating results for the entire year.
We have prepared the financial statements included herein pursuant to the
rules and regulations of the Securities and Exchange Commission. Certain
information and footnote disclosure normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to such rules and regulations. We believe the
disclosures made are adequate to make the information not misleading and
recommend that these condensed financial statements be read in conjunction with
the financial statements and notes included in our Form 10-KSB for the year
ended August 31, 2004.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
-------------------------------------------
Use of Estimates - The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date
of the financial statements and reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
The Company's financial statements are based on a number of significant
estimates, including reliability of receivables, selection of the useful
lives for property and equipment, timing and costs associated with its
retirement obligations and oil and gas reserve quantities which are the
basis for the calculation of depreciation, depletion and impairment of oil
and gas properties.
The oil and gas industry is subject, by its nature, to environmental
hazards and clean-up costs. At this time, management knows of no
substantial costs from environmental accidents or events for which it may
be currently liable. In addition, the Company's oil and gas business makes
it vulnerable to changes in wellhead prices of crude oil and natural gas.
Such prices have been volatile in the past and can be expected to be
volatile in the future. By definition, proved reserves are based on current
oil and gas prices and estimated reserves, which is considered a
significant estimate by the Company, which is subject to changes. Price
declines reduce the estimated quantity of proved reserves and increase
annual amortization expense (which is based on proved reserves) and may
impact the impairment analysis of the Company's full cost pool.
Earnings (Loss) Per Share - Basic earnings (loss) per common share is
computed by dividing net earnings (loss) attributed to common stock by the
weighted average number of common shares outstanding during each period.
Diluted earnings (loss) per share is computed by adjusting the average
number of common shares outstanding for the dilutive effect, if any, of
convertible equity instruments, such as convertible notes payable, stock
options and warrants. The dilutive effect of such securities was
insignificant for the three months ended November 30, 2004 and was not
considered for the three months ended November 30, 2003 because it would
have been anti-dilutive.
Share Based Compensation - In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation (SFAS 123), effective for fiscal
years beginning after December 15, 1995. This statement defines a fair
value method of accounting for employee stock options and encourages
entities to adopt that method of accounting for its stock compensation
plans. SFAS 123 allows an entity to continue to measure compensation costs
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
7
under those plans consistent with the method prescribed in SFAS 123, the
Company's net income (loss) and income (loss) per share for the quarters
ended November 30, 2004 and 2003 would have been increased (decreased) to
the pro forma amounts indicated below:
November 30, November 30,
2004 2003
--------- ---------
Net income (loss):
As reported $ 61,032 $(361,802)
Pro forma equity compensation expense (82,839) (132,620)
--------- ---------
Pro forma net loss $ (21,807) $(494,422)
========= =========
Net pro forma loss per share:
As reported $ 0.00 $ (0.02)
========= =========
Pro forma $ 0.00 $ (0.02)
========= =========
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:
November 30, November 30,
2004 2003
----------- -----------
Expected option life-years 5 5-7
Risk-free interest rate 3.3 - 3.5% 3.0 %
Dividend yield 0.00% 0.00%
Volatility 67-83% 107%
Reclassification - Certain reclassifications have been made to the November
30, 2003 financial statements to conform to November 30, 2004 presentation.
Such reclassifications had no effect on net loss.
Recent Accounting Pronouncements - In December 2004, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards (SFAS) No. 123(R), "Share-Based Payment". This statement requires
all entities to recognize compensation expense in an amount equal to the
fair value of share-based payments granted to employees. SFAS No. 123(R) is
effective the first reporting period beginning after December 15, 2005. Due
to the recent adoption of SFAS No. 123(R), the Company has not determined
the future impact on its financial statements; however, it will result in
additional future financial reporting expense to the Company when
implemented.
2. ACQUISITION OF PROPERTIES:
--------------------------
In May 2004, the Company acquired certain oil and gas properties from Venus
Exploration Inc. ("Venus") for cash consideration of $3,230,000. The
financial statements therefore reflect the revenue and other operating
expenses associated with these properties since the date of acquisition.
The purchase also provides for the Company to pay a net profits interest
payable to the Venus Exploration Trust ("Trust"). During the quarter ended
November 30, 2004, the Company accrued $122,366, which is payable to the
Trust based on the net profits interest agreement; however, the company
does not anticipate that it will be required to pay this amount as the
Company intends to drill additional wells in the future on the property
subject to payout. Costs incurred in connection with additional drilling
would reduce this liability; however, in the unlikely event the Company
does not incur additional drilling costs, such amount would then be payable
to the Trust. The net profits interest, 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 $3,300,000 in net profits proceeds has been paid to
the Trust.
3. CONTINGENCY
-----------
We are currently in dispute with the operator of the Sun Fee #1, Sampson
Lone Star L.P. ("Sampson"), concerning the pooling of certain lands into
the production unit at Nome Field. The pooling of these lands in which the
8
Company does not own an interest, comprises approximately 32% of the unit
area, and may result in a reduction of working interest and net revenue
interest, relative to production from the Sun Fee #1, attributable to the
Company. If the current pooling were to stand, our working interest in the
well would be reduced from 8.33% to 5.66%. The Company strongly believes
that the lands in question are `Non-Productive', and therefore not eligible
for pooling, based on all available geological, seismic, and existing well
data. As a result of this dispute, we will vigorously pursue and defend our
rights to our proportionate share of production and revenue from the Sun
Fee #1 with all legal avenues and remedies available. For this reason, the
Company has not signed any of the proposed production and revenue division
orders, and has not received any revenue, attributable to the well, to
date. If we undertake legal action against the operator relative to this
issue, which we currently intend, it may result in all revenues
attributable to the Sun Fee #1 well being held in suspense until the legal
action is completed. If the outcome of the dispute results in the operator
recognizing our working interest of 8.33%, the increased working interest
could potentially result in increased revenue to the Company and increased
net profits liability to Venus Exploration Trust, subject to the net
profits interest agreement.
For the quarter ended November 30, 2004, we accrued approximately $325,000
in royalty and working interest revenues from the Sun Fee #1. As a result
of the dispute with Sampson, revenues were accrued at the lower working
interest percentage (5.66%) as stated by the operator.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read in conjunction with the Financial
Statements and Notes thereto referred to in "Item 1. Financial Statements" of
this Form 10-QSB.
Overview
PYR Energy Corporation (referred to as "PYR," the "Company," "we," "us" and
"our") is an independent oil and gas exploration and production company, engaged
in the exploration, development and acquisition of crude oil and natural gas
reserves. Our current focus is on the Rocky Mountain, Texas and Gulf Coast
regions. We continue to focus our exploration efforts and advanced technical
expertise on the pre-drill phases of our high potential exploration projects in
the Rocky Mountain region. In May 2004, we acquired interests from Venus
Exploration, Inc. ("Venus") in certain producing properties and undeveloped
acreage for approximately $3,230,000 (excluding acquisition expenses and subject
to retention, by the Venus Exploration Trust, of a net profits interest covering
the non-productive exploration projects) with estimated proved reserves of 4.78
Bcfe. This equates to $0.67 per Mcf, with a PV-10 value of $6.94 million. The
Venus assets acquired include interests in 80 non-operated wells in Utah,
Oklahoma and Texas. New drilling and workovers have been conducted since the
acquisition date and include two recent discoveries. As a result of the
acquisition of the Venus assets, PYR has undertaken a transformation from a
development stage company to a producing oil and gas company. Previously our
primary drilling activity had been in the San Joaquin Basin of California and on
our East Lost Hills project.
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 November 30, 2004, we had approximately
$5,261,866 in working capital.
During the quarter ended November 30, 2004, our capitalized costs for oil
and gas properties increased by approximately $1,042,000. The increase reflects
net costs incurred for undeveloped leasehold, drilling and completion, workover,
geological and geophysical costs, delay rentals and other related direct costs
with respect to our exploration and development prospects, which is further
discussed in Capital Expenditures and Summary of Exploration Projects.
9
During the quarter ended November 30, 2003, capitalized costs for oil and
gas properties increased by approximately $198,000. This increase reflects net
costs incurred for drilling and completion, geological and geophysical costs,
delay rentals and other related direct costs with respect to our exploration and
development prospects, of approximately $236,000, less depreciation of asset
retirement obligation assets of approximately $38,000.
It is anticipated that the continuation and future development of our
business will require additional, and possibly substantial, capital
expenditures. We have no reliable source for additional funds for administration
and operations to the extent our existing funds have been utilized. In addition,
our capital expenditure budget for the fiscal year ending August 31, 2005 will
depend on our success in selling additional prospects for cash, the level of
industry participation in our exploration projects, the availability of debt or
equity financing, and the results of our activities. We anticipate spending a
minimum of approximately $2,000,000 on exploration and development activities
during our fiscal year ending August 31, 2005. To limit capital expenditures, we
intend to form industry alliances and exchange an appropriate portion of our
interest for cash and/or a carried interest in our exploration projects. We may
need to raise additional funds to cover capital expenditures. These funds may
come from cash flow, equity or debt financings, a credit facility, or sales of
interests in our properties, although there is no assurance additional funding
will be available or that it will be available on satisfactory terms.
CAPITAL EXPENDITURES
During the quarter ended November 30, 2004, we incurred approximately
$1,089,000 of capital costs for our oil and gas properties. This amount includes
costs associated with undeveloped leasehold, drilling and completion, workover,
geological and geophysical costs, delay rentals, and other related direct costs
with respect to our exploration and development prospects. Revenues from oil and
gas production during the quarter were approximately $1,082,510.
We currently anticipate that we will participate in the drilling of up to
six exploration wells during our fiscal year ending August 31, 2005, although
the number of wells may increase as additional projects are added to our
portfolio. However, there can be no assurance that any such wells will be
drilled and if drilled that any of these wells will be successful.
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.
SUMMARY OF EXPLORATION PROJECTS
Our exploration activities are focused primarily in select areas of the
Rocky Mountains, Texas and Gulf Coast, Southeast Alberta, and in the San Joaquin
Basin of California. Advanced seismic imaging of the structural and
stratigraphic complexities common to these regions provides us with the enhanced
ability to identify significant oil and gas reserve potential. A number of these
projects offer multiple drilling opportunities with individual wells having the
potential of encountering multiple reservoirs.
The following is a summary of our exploration areas and significant
projects. While actively pursuing specific exploration activities in each of the
following areas, we continually review additional opportunities in these core
areas and in other areas that meet our exploration criteria.
ROCKY MOUNTAIN EXPLORATION
Montana Foothills Project. This extensive natural gas exploration project,
located in west-central Montana, is part of the southern Alberta basin, and has
been classified as the southern extension of the Alberta Foothills producing
province. The USGS and numerous Canadian industry sources have estimated
10
significant recoverable reserves for the Montana portion of the Foothills trend.
Based on extensive geologic and seismic analysis, we have identified numerous
structural culminations of similar size, geometry, and kinematic history as
prolific Canadian foothills fields, such as Waterton and Turner Valley.
The geologic setting and hydrocarbon potential of this area was not
recognized by the industry until the early 1980s. At that time, a number of
companies initiated exploration efforts, including Exxon, Arco, Chevron, Amoco,
Conoco, and Unocal. This initial exploration phase culminated in a deep test by
Unocal, the Unocal #1-B30, drilled in 1989 to a depth of 17,817 feet, which was
plugged and abandoned after testing. Although this well was unsuccessful, recent
improvements in seismic imaging and pre-stack processing have resulted in our
belief that this test well was drilled based upon a misleading seismic image and
was located significantly off-structure. Within the Rogers Pass acreage block,
we have undertaken extensive seismic analysis and geological study, resulting in
the identification of multiple untested, prospective structures.
In March 2004, we signed an Exploration Option Agreement with a subsidiary
of Suncor Energy, Incorporated, covering our Rogers Pass exploration project We
currently control approximately 241,800 gross and 226,300 net leasehold acres in
the Rogers Pass project. Pursuant to our agreement with the subsidiary of Suncor
Energy, Suncor Energy Natural Gas America, Inc. ("SENGAI"), SENGAI has paid us a
$500,000 option fee for a technical evaluation period of up to three months. On
August 31, 2004 SENGAI exercised its option to drill an initial test well at
Rogers Pass, and paid us $750,000 in the form of a prospect fee (received in
September 2004). It is anticipated that the initial test well will begin
drilling operations in late February or March 2005, depending on rig
availability. SENGAI will bear 100% of the costs of the well, to a depth
sufficient to evaluate the Mississippian, to earn a 100% working interest in
100,000 acres of the project area. SENGAI will have the option to pay a second
prospect fee of $1,250,000 and drill a second test well, to be spud by December
31, 2005. By paying this second prospect fee and bearing 100% of the costs of
the second well, SENGAI will earn a 100% working interest in the remaining
acreage within the project area. We will retain a 12.5% overriding royalty
interest, subject to amortized recovery of gas plant and certain transportation
costs, covering all earned acreage within the Rogers Pass project area.
Mallard Project. The Mallard project, located within the Overthrust Belt of
southwest Wyoming, is a sour gas and condensate exploration prospect in Uinta
County, Wyoming. We believe that Mallard is within the Paleozoic trend of
productive fields on the Absaroka thrust. Mallard directly offsets and is
adjacent to the giant sour gas field of Whitney Canyon-Carter Creek.
We interpret the Mallard prospect to occupy a separate fault block,
adjacent to the Whitney Canyon field, generated by a complex imbricated system
of faults splaying off of the Absaroka thrust. Paleozoic targets at the Mallard
prospect include the Mississippian Mission Canyon, as well as numerous secondary
objectives in the Ordovician, Pennsylvanian, and Permian sections.
The agreement we entered into with two private companies ("the
Participants") in December 2003 requires the Participants to drill the initial
test well at the Mallard Prospect to earn part of our acreage position within a
designated area of mutual interest. We currently control 4,160 net leasehold
acres within the AMI. During the fiscal year ended 2004, the partners paid us
approximately $450,000 in prospect fees and pro-rata development costs. The
Mallard well started drilling in mid-July and Intermediate casing was set to
9,735 feet in the Thaynes Formation. The Bureau of Land Management has suspended
drilling activities at Mallard, effective December 1, 2004, due to wildlife
critical winter range restrictions. As a result, the well has been temporarily
suspended and secured in compliance with applicable federal and state
regulations, until the wildlife restrictions are lifted in mid - 2005. We are
participating with a 5% working interest in the drilling of Mallard, and will be
carried to casing point, at an estimated total depth of 15,500 feet, for an
additional 23.75% working interest. After casing point, we will have a 28.75%
working interest in the initial test well and all subsequent wells in the
prospect.
Cumberland Project. The Cumberland project, located within the Overthrust
Belt of southwest Wyoming, is a gas-condensate exploration prospect in Uinta
County, Wyoming. Cumberland is at the northern end of the historically
productive Nugget trend on the hangingwall of the Absaroka thrust fault. We
believe that the prospect is along geologic trend of and just north of Ryckman
Creek field, which was discovered in 1975.
Drilling at the Cumberland prospect started in early November 2004. The
Cumberland #1-16 State well reached total drilling depth of 10,860 feet in the
Nugget Sandstone. Based on preliminary log analysis, the Nugget zone of interest
appears to be nonproductive, and the well will be plugged and abandoned. Further
evaluation of the log data will be analyzed and studied to determine any
remaining prospective targets within our 6,233 net leasehold area of mutual
interest ("AMI"). PYR participated in the drilling of the well at a 10% working
interest and was carried for an additional 22.5% working interest to casing
point.
11
Ryckman Creek Project. We have recently leased approximately 1,820 net
acres, covering the majority of the abandoned Ryckman Creek field, in the
Overthrust of southwestern Wyoming. Ryckman Creek, located 5 miles southwest of
our Cumberland prospect, was discovered in 1975 and produced approximately 250
Bcfe prior to abandonment. We believe that significant remaining recoverable gas
reserves were stranded in Ryckman Creek upon abandonment. We are currently
analyzing production and geologic data to determine potential reserves in
multiple zones, including the Twin Creek, Nugget, and Thaynes Formations, in the
field. Due to winter activity restrictions, it is anticipated that a well may be
drilled at Ryckman Creek in mid-2005, and based on our analysis, we may decide
to sell part of our 100% working interest in the project.
INTERESTS ACQUIRED FROM VENUS EXPLORATION, INC.:
In May 2004, we acquired interests from Venus Exploration, Inc. ("Venus")
in certain producing properties with estimated proved reserves of 4.784 Bcfe for
approximately $3,230,000 (excluding acquisition expenses and subject to
retention, by the Venus Exploration Trust, of a net profits interest covering
the non-productive exploration projects). This equates to $0.67 per Mcf, with a
PV-10 value of $6.94 million. The purchase also provides for us to pay a net
profits interest payable to the Venus Exploration Trust. The net profits
interest, which applies only to the exploration and exploitation projects on the
Venus acreage being acquired, varies from 25% to 50% with respect to different
Venus exploration and exploitation project areas, and decreases by one-half of
its original amount after a total of $3,300,000 in net profits proceeds has been
paid to the Trust. Venus was in Chapter 11 Bankruptcy, and the properties were
acquired through public auction as approved by the United States Bankruptcy
Court. To finance the purchase, we primarily used existing cash reserves and
also a portion of the proceeds from a private placement of common stock.
Oil and gas interests acquired from Venus include producing oil and gas
properties, exploitation drilling projects, and exploration acreage. The assets
acquired include interests in 80 non-operated wells in Utah, Oklahoma and Texas.
In Texas, we have interests in three projects that were drilled and
completed over this past summer. Two of the three wells, the Nome and Madison
Prospects, were completed as producers and are currently flowing to sales lines.
These two successful projects are, upon reaching payout, subject to a 50% net
profits interest payable to the Venus Exploration Trust.
Tortuga Grande prospect, located in east Texas, is a project to test the
productivity of the Cotton Valley Sand section at depths ranging from 13,000 to
14,500 feet. Drilled originally in 1984 for deeper targets, the Brady #1 is the
only deep well on the structure, and had shows in the Cotton Valley Sand, but
was never fracture stimulated. Log analysis indicates that the well contains
approximately 322 feet of potential pay greater than 8% porosity. The Brady #1
was re-entered and the middle Cotton Valley Sand section was fracture stimulated
and tested. Results of the test were inconclusive and the partners continue to
evaluate the test data. The partners may decide at a future date to drill
another well to test the Cotton Valley within the project area. Should this
occur, PYR would be responsible for 20% of the costs of any additional well. In
all additional locations within the Tortuga Grande area of mutual interest, we
will participate with a cost bearing 20% working interest. We currently control
approximately 5,600 net leasehold acres within the project. It is anticipated
that the partners will drill another test well at Tortuga Grande during the
second quarter of 2005.
Nome Field was discovered in 1994, and our interpretation of subsequently
acquired 3D seismic over the field indicates the presence of numerous
undeveloped fault blocks. Multiple structural closures and associated bright
spot locations have been identified at Nome based on the 3D seismic. PYR owns a
1.5% overriding royalty interest with an additional 8.33% working interest,
after project payout, in the project. Production in the Sun Fee #1 well, from
the upper Yegua, was initiated in late May 2004, and over the past three months
(October through December), the well has averaged production of 15.34 Mmcfe per
day. Cumulative production since inception is in excess of 2.5 Bcfe. After
project payout, it is estimated that the well will add approximately 1MMcfe of
net daily production to PYR, given current production rates. During the quarter
ended November 30, 2004, we received confirmation from the operator that the Sun
Fee #1 well and project reached payout, and that PYR is currently a working
interest participant in the well. We and our partners control approximately
4,200 acres of gross leasehold acres in the project.
12
We are currently in dispute with the operator of the Sun Fee #1, Sampson
Lone Star L.P. ("Sampson"), concerning the pooling of certain lands into the
production unit. The pooling of these lands in which the Company does not own an
interest, comprises approximately 32% of the unit area, and may result in a
reduction of working interest and net revenue interest, relative to production
from the Sun Fee #1, attributable to the Company. If the current pooling were to
stand, our working interest in the well would be reduced from 8.33% to 5.66%.
The Company strongly believes that the lands in question are `Non-Productive',
and therefore not eligible for pooling, based on all available geological,
seismic, and existing well data. As a result of this dispute, we will vigorously
pursue and defend our rights to our proportionate share of production and
revenue from the Sun Fee #1 with all legal avenues and remedies available. For
this reason, the Company has not signed any of the proposed production and
revenue division orders, and has not received any revenue, attributable to the
well, to date. If we undertake legal action against the operator relative to
this issue, which we currently intend, it may result in all revenues
attributable to the Sun Fee #1 well being held in suspense until the legal
action is completed.
For the quarter ended November 30, 2004, we accrued approximately $325,000
in royalty and working interest revenues from the Sun Fee #1. As a result of the
dispute with Sampson, revenues were accrued at the lower working interest
percentage (5.66%) as stated by the operator. Both revenues and costs associated
with the production from the Sun Fee #1, as well as the 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 the acquisition of properties from Venus Exploration Inc. ("Venus") in May
2004. 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 $3,300,000 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. As of November 30, 2004, we accrued a net profits interest liability of
$122,366 payable to the Trust.
Madison prospect, located in the northern part of the Constitution Field,
is an exploitation project to test multiple sand intervals within the expanded
Yegua section, downthrown to a major growth fault. The prospect involves
sidetracking an existing cased hole updip to test multiple sand targets at a
location offsetting, but significantly high to Doyle sand production from the
Texaco #1 Doyle well within the field. The location is also offset to the Texaco
#1 Sanders Gas Unit well, which tested the Doyle sand interval at a rate of
1,176 Bc/d and 2.7 MMcf/d with no water. This well was subsequently plugged and
abandoned in the Doyle interval and never produced from the zone. The Maness Gas
Unit location represents a proved undeveloped location for Doyle sand, 183 feet
structurally high to the equivalent produced zone in the Texaco Doyle #1 well.
The current well has been drilled to total depth, production casing has been
run, and the well is currently producing at a rate of approximately 5.00 MMcfe
per day. We own a 0.5% overriding royalty interest that converts to a 12.5%
working interest in the project after payout (which has not been reached) of the
initial test well. The operator has converted an existing wellbore within the
project area into a water disposal well, and is planning to drill an offset
development well ( Maness GU#2). The cost of the water disposal well will be
covered under the payout account, and we will participate for 12.5% working
interest in the drilling of this low risk development well. It is anticipated
that the offset well will begin drilling operations in late January 2005.
The Cotton Creek prospect, located in Jefferson County, Texas, is adjacent
to the Nome project. The prospect is located approximately one mile west of the
productive Sun Fee #1 well in the same structural fault block. PYR owns a 50%
working interest in the project and controls with its partner approximately 500
acres of leasehold.
The South Wharton prospect, located in Wharton County, Texas, is an
exploration project designed to test several stratigraphic intervals within the
expanded Yegua section in multiple structural features as defined by 3D seismic
data. Drilling targets are estimated to be at depths between 11,000 and 13,500
feet. PYR owns a 58% working interest in the project and in excess of 1,065
gross acres are currently under lease.
The Merganser prospect, located in Leon County, Texas, targets Cotton
Valley and Bossier sandstone reservoirs in an undrilled structural feature
defined by 3D seismic data. The prospect occupies a fault-bounded
salt-withdrawal trough resulting in potential significant thickening of the
Bossier and Cotton Valley sand sections. The prospect location is structurally
and stratigraphically downdip from Cotton Valley production as well as updip
from recent Bossier productive discoveries. PYR owns 100% of the prospect and
controls in excess of 1,500 gross acres of leasehold.
13
The Orbison #3-11 development well is a low risk prospect located in
eastern Oklahoma. PYR hopes to spud this by the end of January and has a working
interest of 29% in the well.
The 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. It is anticipated that the initial test well in the project will be
drilled in the next few months, and PYR will participate with a 15% cost bearing
interest and farm-out the remainder of its working interest.
The Canadian River Project, located in Oklahoma, we are preparing to drill
a Cromwell development well. PYR has a 28.98% WI in the well, and drilling
activities are expected to begin by late January 2005.
SOUTHEAST ALBERTA SHALLOW GAS REDEVELOPMENT PROJECT:
We have entered into two joint ventures, the Atlas Joint Venture and the
Blue River Joint Venture, to redevelop shallow gas reserves in southeastern
Alberta, Canada. Southeastern Alberta has been the site of significant shallow
gas development drilling and production over the last two decades. We have
undertaken geologic and engineering studies of the region, and believe that many
wellbores in the region were prematurely suspended and/or abandoned due to water
coning and production. These premature well abandonments suggest the possibility
that significant additional reserves may remain in a number of shallow gas
reservoirs in local areas within the Southeastern Alberta.
We own a 5% working interest in the Atlas Joint Venture, which has
identified multiple potential re-entry and redevelopment opportunities for which
the Joint Venture intends to acquire the right to participate. The first well
has been re-entered, re-perforated, and completed in the upper Bow Island sand.
The well is currently producing into a sales line during long term testing. An
offset wellbore is currently being permitted for re-entry based on results from
the initial well. A number of other prospects are being leased and permitted at
this time.
We also own a 25% working interest in the Blue River Joint Venture, which
intends to operate in different areas of southeastern Alberta. Initial
investigation indicates multiple wells that exhibit an appropriate production
type decline curve, potential disposal interval, and gas reservoir. We are
currently undertaking detailed geologic and production analysis to refine
certain areas, for which the Joint Venture will undertake to acquire and develop
prospects for recompletion or drilling.
SAN JOAQUIN BASIN, CALIFORNIA
Wedge Prospect. This is a seismically identified Temblor prospect located
northwest of and adjacent to the East Lost Hills deep gas discovery. During the
first fiscal quarter of 2001, we acquired approximately 17 miles of proprietary,
high effort 2D seismic data and combined this data with existing 2D seismic data
in order to refine what we interpret as the up-dip extension of the East Lost
Hills structure. Our seismic interpretation shows that the same trend at East
Lost Hills extends approximately ten miles further northwest of the East Lost
Hills Area of Mutual Interest and can be encountered as much as 3,000 feet
higher. Despite repeated attempts to facilitate drilling interest at Wedge
during 2003, no industry interest was generated sufficient to put together a
drilling partnership during the year. As a result, PYR re-evaluated its acreage
position at Wedge and made the decision to consolidate the leasehold by
abandoning non-core prospect acreage in the project area. We currently control
approximately 3,500 gross and net acres here. Our approach is to sell down our
working interest to industry partners, and retain a 25% to 50% working interest
in this prospect.
Bulldog Prospect. This project is a 2D seismically identified natural gas
and condensate prospect located adjacent to the giant Kettleman North Dome field
in the San Joaquin Basin. This prospect can be best characterized as a classic
footwall fault trap, similar to the many known footwall fault trap accumulations
that have produced significant quantities of hydrocarbons throughout the San
Joaquin basin. During 2003, we re-evaluated our acreage position at Bulldog and
consolidated the leasehold by releasing approximately 3,200 non-core acres in
the project area. We currently control approximately 11,900 gross and net acres
here. We expect to sell down our working interest in this project and retain a
25% to 50% working interest in the prospect acreage.
14
Blizzard Prospect. This project is a 3D seismic derived exploration and
exploitation program offsetting the Rio Viejo field at the south end of the San
Joaquin Basin. A linear sand body, stratigraphically higher than any of the
productive Rio Viejo sands, has been identified, north of the field, on the
seismic data and represents an exploration opportunity for new reserves.
Additionally, analysis of the seismic data over the field suggests that up to
two additional undrilled field exploitation locations may exist. PYR owns 100%
of the prospect and controls approximately 2,500 net and gross acres.
CASH FLOW
The three months ended November 30, 2004 ("2004") compared with the three months
ended November 30, 2003 ("2003").
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided (used) by operating activities was $394,706 and
($267,266) for the quarters years ended November 30, 2004 and 2003,
respectively. A discussion of these and other items are presented below.
Net loss. See discussion of net income (loss) in "Results of Operations"
section below.
Depreciation and amortization. Depreciation and amortization expense was
$38,037 for the quarter ended November 30, 2004, compared to $40,120 for the
quarter ended November 20, 2003. The 2004 expense includes $34,822 of depletion
of oil and gas properties. The 2003 expense includes depreciation of Asset
Retirement Obligation assets of $37,821.
Accounts receivable. For the quarters ended November 30, 2004 and 2003,
accounts receivable increased $590,736 and $0, respectively. The increase in
2004 related principally to receivables generated from the properties acquired
from Venus Exploration, Inc. in May 2004.
Accrued interest converted into debt. For the quarter ended November 30,
2004, accrued interest converted into debt was $166,611 compared to $158,577 for
the quarter ended November 30, 2003. Both amounts reflect interest accrued on
the $6,000,000 convertible notes issued May 24, 2002.
Accretion of asset retirement obligation. During the quarters ended
November 30, 2004 and 2003, accretion of unamortized discount of the Asset
Retirement Obligation liability was $6,300 and $21,152, respectively. The prior
quarter is higher because the estimated lives of the East Lost Hills properties
escalated the accretion rate, while the current quarter includes properties
(acquired from Venus Exploration Inc. in May 2004) with longer estimated lives,
and hence a lower accretion rate.
Prepaid expenses and other. During the quarter ended November 30, 2004,
prepaid expenses decreased $74,253, compared to a increase of $78,684 during the
quarter ended November 30, 2003. The decrease in 2004 primarily reflects timing
of payments. The increase in 2003 reflected the payment of Directors and
Officers liability insurance premiums during the quarter.
Accounts payable. During the quarter ended November 30, 2004, accounts
payable and accruals increased $101,015 compared to a decrease of $7,381 during
the quarter ended November 30, 2003. The change in the current quarter primarily
reflects increased payables activity as a result of the properties acquired from
Venus in May 2004. The decrease in 2003 primarily reflected timing of payments.
Net profits interest liability. During the quarter ended November 30, 2004,
the net profits interest liability increased $122,366, compared to $0 in the
quarter ended November 30, 2003. The net profits interest agreement with Venus
Exploration Trust ("Trust") agreement arose out of the acquisition of properties
from Venus Exploration Inc. ("Venus") in May 2004. The current quarter increase
resulted from an accrued liability to the Trust for net profits realized on the
Sun Fee #1 well in the Nome Project.
Accrued expenses. During the quarter ended November 30, 2004, accrued
expenses increased $415,031, compared to a decrease of $40,045 in the quarter
ended November 30, 2003. The change in the current quarter primarily reflects
increased lease operating and capital costs incurred as a result of the
properties acquired from Venus in May 2004, as well as accrued costs for the
Cumberland and Mallard prospects. The increase was partially offset by the
conversion of accrued interest payable into convertible debt. The $6,000,000
convertible notes were issued on May 24, 2002. The decrease in 2004 also relates
to the same conversion of accrued interest payable into convertible debt.
15
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties. During the quarter ended November 30,
2004, we paid $1,220,406 for oil and gas properties, compared to $276,389,
during the year ended August 31, 2003. The increase in 2004 principally reflects
activity resulting from the acquisition of properties from Venus in May 2004.
The increase in 2003 relates to costs incurred on exploration projects in the
California and the Rocky Mountain regions.
Proceeds from sale of exploration options. During the year ended August 31,
2004, we signed an Exploration Option Agreement with Suncor Energy Natural Gas
America, Inc. ("SENGAI"), covering our Rogers Pass exploration project in the
Foothills of west-central Montana. On August 31, 2004, SENGAI exercised its
option to drill an initial test well and paid us $750,000 in the form of a
prospect fee, which was received in September 2004. We received $0 in proceeds
from the sale of exploration options during the quarter ended November 30, 2003.
Proceeds from sale of oil and gas properties. We received $25,000 in
prospect fees from a private company in connection with our Madison project
during the quarter ended November 30, 2004. We received $0 in proceeds from the
sale of oil and gas properties during the quarter ended November 30, 2003.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash provided by financing activities was $0 for the quarters ended
November 30, 2004 and 2003, respectively.
Results of Operations
The three months ended November 30, 2004 ("2004") compared with the three
months ended August 31, 2003 ("2003"). Operations during the quarter ended
November 30, 2004 resulted in net income of $61,032 compared to a net loss of
($361,802) for the quarter ended November 30, 2003.
Oil and Gas Revenues and Expenses. During the quarter ended November 30,
2004, we recorded $1,082,510 in total oil and gas revenues. Of this amount, we
recorded $445,986 from the sale of 63,057 mcf of natural gas for an average
price of $7.07 per mcf, and $636,523 from the sale of 13,978 bbls of hydrocarbon
liquids for an average price of $45.54 per bbl. During the quarter ended
November 30, 2003, we recorded $40,018 in total oil and gas revenues. Of this
amount, we recorded $30,717 from the sale of 7,487 mcf of natural gas for an
average price of $4.10 per mcf and $9,301 from the sale of 402 bbls of
hydrocarbon liquids for an average price of $23.13 per barrel. 2004 revenues
increased largely due to the acquisition of properties from Venus Exploration
Inc. in May 2004, while 2003 revenues related wholly to the Company's interest
in East Lost Hills in California. Comparable revenues for the East Lost Hills
property during the quarter ended November 30, 2004 were $42,898. Lease
operating expenses during the quarters ended November 30, 2004 and 2003,
respectively, were $280,576 and $15,271.
Interest Income. We recorded $20,299 and $5,567 in interest income for the
quarters ended November 30, 2004 and 2003, respectively. The increase was due to
interest on the funds received from the private placement of our common stock in
May 2004.
General and Administrative Expenses. General and administrative expenses
during the quarters ended November 30, 2004 and 2003 were $511,387 and $251,490,
respectively. The increase principally reflects an increase in salaries as a
result of hiring additional personnel and an increase in audit and legal fees,
both of which resulted from the acquisition of properties from Venus Exploration
Inc. in May 2004.
Depreciation Depletion and Amortization. We recorded $34,822 and $0,
respectively, in depreciation, depletion and amortization expense from oil and
gas properties for the quarters ended November 30, 2004 and 2003. We recorded no
depreciation, depletion and amortization expense from oil and gas properties for
the quarter ended November 20, 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; however, included in depreciation expense reported
for 2003, is $37,821 of depreciation of Asset Retirement Obligation assets. The
current fiscal quarter increase in depreciation, depletion and amortization
expense was attributable to the properties acquired from Venus Exploration, Inc.
We recorded $3,215 and $2,299 in depreciation expense associated with
capitalized office furniture and equipment during the quarters ended November
30, 2004 and 2003, respectively.
16
Accretion Expense. We recorded $6,300 and $21,152, respectively, for the
quarters ended November 30, 2004 and 2003, of accretion of the unamortized
discount of the Asset Retirement Obligation liability. The prior quarter is
higher because the estimated lives of the East Lost Hills properties escalated
the accretion rate, while the current quarter includes properties (acquired from
Venus Exploration Inc. in May 2004) with longer estimated lives, and hence a
lower accretion rate.
Net Profits Interest Expense. The net profits interest agreement with Venus
Exploration Trust ("Trust") agreement arose out of the acquisition of properties
from Venus Exploration Inc. ("Venus") in May 2004. 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
$3,300,000 in net profits proceeds has been paid to the Trust. As of November
30, 2004, we accrued net profits interest expense of $122,366, in connection
with net profits realized for the Sun Fee #1 well at November 30, 2004. For the
quarter ended November 30, 2003, there was no net profits interest expense
recognized.
Interest Expense. During the quarters ended November 30, 2004 and 2003, we
recorded interest expense of $83,333 and $79,354, respectively. 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 $166,611 and
$158,577 of accrued interest to the balance of the debt for the quarters ended
November 30, 2004 and 2003, respectively. We have reflected the outstanding
balance of these notes as Convertible Notes under Long Term Debt on our November
30, 2004 and 2003 consolidated balance sheets.
17
Critical Accounting Policies And Estimates
We believe the following critical accounting policies affect our more
significant judgments and estimates used in the preparation of our Financial
Statements.
Reserve Estimates:
Our estimates of oil and natural gas reserves, by necessity, are
projections based on geological and engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that are difficult to measure.
The accuracy of any reserve estimate is a function of the quality of available
data, engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and natural gas reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies and
assumptions governing future oil and natural gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and natural
gas attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected from there may vary substantially. Any significant variance in the
assumptions could materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of our oil and gas properties
and/or the rate of depletion of the oil and gas properties. Actual production,
revenues and expenditures with respect to our reserves will likely vary from
estimates, and such variances may be material.
Many factors will affect actual net cash flows, including the following:
the amount and timing of actual production; supply and demand for natural gas;
curtailments or increases in consumption by natural gas purchasers; and changes
in governmental regulations or taxation.
Property, Equipment and Depreciation:
We follow the full cost method to account for our oil and gas exploration
and development activities. Under the full cost method, all costs incurred which
are directly related to oil and gas exploration and development are capitalized
and subjected to depreciation and depletion. Depletable costs also include
estimates of future development costs of proved reserves. Costs related to
undeveloped oil and gas properties may be excluded from depletable costs until
those properties are evaluated as either proved or unproved. The net capitalized
costs are subject to a ceiling limitation based on the estimated present value
of discounted future net cash flows from proved reserves. As a result, we are
required to estimate our proved reserves at the end of each quarter, which is
subject to the uncertainties described in the previous section. Gains or losses
upon disposition of oil and gas properties are treated as adjustments to
capitalized costs, unless the disposition represents a significant portion of
the Company's proved reserves.
Revenue Recognition:
The Company recognizes oil and gas revenues from its interests in producing
wells as oil and gas is produced and sold from these wells. The Company has no
gas balancing arrangements in place. Oil and gas sold is not significantly
different from the Company's product entitlement.
Asset Retirement Obligations:
In 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement requires companies to record
the present value of obligations associated with the retirement of tangible
long-lived assets in the period in which it is incurred. The liability is
capitalized as part of the related long-lived asset's carrying amount. Over
time, accretion of the liability is recognized as an operating expense and the
capitalized cost is depreciated over the expected useful life of the related
asset. The Company's asset retirement obligations relate primarily to the
plugging, dismantlement, removal, site reclamation and similar activities of its
oil and gas properties. Prior to adoption of this statement, such obligations
were accrued ratably over the productive lives of the assets through
depreciation, depletion and amortization of oil and gas properties without
recording a separate liability for such amounts.
18
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 123(R), "Share-Based
Payment". This statement requires all entities to recognize compensation expense
in an amount equal to the fair value of share-based payments granted to
employees. SFAS No. 123(R) is effective the first reporting period beginning
after December 15, 2005. Due to the recent adoption of SFAS No. 123(R), the
Company has not determined the future impact on its financial statements;
however, it will result in additional future financial reporting expense to the
Company when implemented.
ITEM 3. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, we conducted an
evaluation under the supervision and with the participation of the principal
executive officer and principal financial officer, of our disclosure controls
and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934 (the "Exchange Act")). Based on this evaluation, the
principal executive officer and principal financial officer concluded that our
disclosure controls and procedures are effective to ensure that the information
we are required to disclose in reports that we file or submit 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 our internal controls over financial reporting during our most
recently completed fiscal quarter that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
19
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings
Not Applicable
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits
Exhibit Index
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Number Description
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31 Rule 13a-14(a) Certifications of Chief Executive Officer and
Principal 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
20
SIGNATURES
In accordance with the requirements of the Exchange Act, the Registrant has
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Signatures Title Date
---------- ----- ----
/s/ D. Scott Singdahlsen President, Chief Executive Officer January 14, 2005
------------------------ and Principal Financial Officer
D. Scott Singdahlsen
21