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 May 31, 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 May 31, 2004 is as follows:
$.001 Par Value Common Stock 28,243,023
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements........................................... 3
Balance Sheets - May 31, 2004 (Unaudited) and August 31,
2003........................................................... 3
Statements of Operations - Three Months and Nine Months
Ended May 31, 2004 and May 31, 2003 (Unaudited)................ 4
Statements of Cash Flows - Nine Months Ended May 31, 2004
and May 31, 2003 (Unaudited)................................... 5
Notes to Financial Statements.................................. 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................ 10
Item 3. Controls and Procedures......................................... 20
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.............................................. 21
Item 2. Changes in Securities and Use of Proceeds; Recent Sales of
Unregistered Securities........................................ 21
Item 3. Defaults Upon Senior Securities................................ 21
Item 4. Submission of Matters to a Vote of Security Holders............ 21
Item 5. Other Information.............................................. 21
Item 6. Exhibits and Reports on Form 8-K............................... 21
Signatures.............................................................. 22
2
PART I
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
BALANCE SHEETS
ASSETS
May 31, August 31,
2004 2003
(Unaudited)
CURRENT ASSETS
Cash $ 3,956,819 $ 3,657,938
Oil and gas receivables 316,265 --
Deposits, prepaid expenses and other receivables 110,463 46,559
------------ ------------
Total Current Assets 4,383,547 3,704,497
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 22,890 29,313
Oil and gas properties under full cost, net 8,572,006 5,287,837
------------ ------------
8,594,896 5,317,150
------------ ------------
OTHER ASSETS
Deferred financing costs and other assets 75,867 68,257
------------ ------------
75,867 68,257
------------ ------------
$ 13,054,310 $ 9,089,904
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 427,987 $ 309,796
Asset retirement obligation 793,749 727,231
------------ ------------
Total Current Liabilities 1,221,736 1,037,027
------------ ------------
LONG TERM LIABILITIES
Convertible Notes 6,623,351 6,303,975
Asset retirement obligation 292,380 118,862
------------ ------------
Total Long Term Liabilities 6,915,731 6,422,837
STOCKHOLDERS' EQUITY
Common stock, $.001 par value; authorized 75,000,000 shares
Issued and outstanding - 28,243,023 at 5/31/04 and
23,701,357 shares at 8/31/03 28,243 23,701
Capital in excess of par value 39,845,468 35,407,657
Accumulated deficit (34,956,868) (33,801,318)
------------ ------------
4,916,843 1,630,040
------------ ------------
$ 13,054,310 $ 9,089,904
============ ============
3
PYR ENERGY CORPORATION
STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Three Nine Nine
Months Months Months Months
Ended Ended Ended Ended
5/31/2004 5/31/2003 5/31/2004 5/31/2003
REVENUES
Oil and gas revenues $ 184,551 $ 43,041 268,945 $ 137,079
------------ ------------ ------------ ------------
184,551 43,041 268,945 137,079
------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 77,958 18,349 114,910 64,694
Impairment, dry hole, and abandonments -- -- -- 1,178,267
Depreciation and amortization 71,813 3,020 196,041 8,892
General and administrative 350,377 339,576 887,309 1,010,119
------------ ------------ ------------ ------------
500,148 360,945 1,198,260 2,261,972
LOSS FROM OPERATIONS (315,597) (317,904) (929,315) (2,124,893)
OTHER INCOME (EXPENSE)
Interest income 4,921 11,044 15,529 45,879
Other income 1,020 -- 1,020 --
Interest (expense) (82,234) (78,316) (242,784) (230,371)
------------ ------------ ------------ ------------
(76,293) (67,272) (226,235) (184,492)
------------ ------------ ------------ ------------
NET LOSS $ (391,890) $ (385,176) $ (1,155,550) $ (2,309,385)
============ ============ ============ ============
NET LOSS PER COMMON
SHARE -BASIC AND DILUTED (0.02) (0.02) (0.05) (0.10)
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 24,930,795 23,701,357 24,114,161 23,701,357
============ ============ ============ ============
4
PYR ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Nine Months
Ended Ended
5/31/2004 5/31/2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $(1,155,550) $(2,309,385)
Adjustments to reconcile net loss to
net cash used by operating activities
Depreciation and amortization 196,041 8,892
Impairment, dry hole and abandonments -- 1,178,267
Amortization of financing costs 2,390 2,390
Interest expense converted into debt 319,376 221,948
Changes in assets and liabilities
(Increase) in accounts receivable (328,787) --
(Increase) decrease in prepaids (51,382) (23,976)
Increase in accounts payable, accruals 88,891 311,024
Other (10,000) (40,000)
----------- -----------
Net cash used by operating activities (939,021) (650,840)
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (3,161) (4,688)
Cash paid for oil and gas properties (3,887,304) (1,067,737)
Proceeds from sale of exploration options 500,000 --
Proceeds from sale of oil and gas properties 186,014 --
----------- -----------
Net cash used in investing activities (3,204,451) (1,072,425)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of common stock 4,430,269 --
Proceeds from exercise of options 12,084 --
----------- -----------
Net cash provided by financing activities 4,442,353 --
----------- -----------
NET (DECREASE) INCREASE IN CASH 298,881 (1,723,265)
CASH, BEGINNING OF PERIODS 3,657,938 6,516,086
----------- -----------
CASH, END OF PERIODS $ 3,956,819 $ 4,792,821
=========== ===========
NON-CASH TRANSACTIONS
Increase in asset retirement obligation $ 169,874 $ --
=========== ===========
5
PYR ENERGY CORPORATION
Notes to Financial Statements
May 31, 2004
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 periods ended May 31, 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, 2003.
PYR Energy Corporation, formerly known as Mar Ventures Inc. ("Mar"), was
incorporated under the laws of the State of Delaware on March 27, 1996. Mar was
a public company with no significant operations as of July 31, 1997. On August
6, 1997, Mar acquired all the interests in PYR Energy LLC ("PYR LLC"), a
Colorado limited liability company organized on May 31, 1996, a development
stage company as defined by Statement of Financial Accounting Standards (SFAS)
No. 7. PYR LLC, an independent oil and gas exploration company, was engaged in
the acquisition of undeveloped oil and gas interests for exploration and
exploitation in the Rocky Mountain region and California. As of August 6, 1997,
PYR LLC had acquired only non-producing leases and acreage, and no exploration
had commenced on the properties. Upon completion of the acquisition of PYR LLC
by Mar, PYR LLC ceased to exist as a separate entity. Mar remained as the
surviving legal entity and, effective November 12, 1997, Mar changed its name to
PYR Energy Corporation. Effective July 2, 2001, we re-incorporated in Maryland
through our merger into our 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. As of May 31, 2004, PYR
Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC had no business activity.
Prior to the third quarter ended May 31, 2004, we were a development stage
company. As discussed in Note 3, we acquired interests in certain producing
properties from Venus Exploration, Inc. As a result of this acquisition, during
the third quarter ended May 31, 2004, we began receiving revenues from our
planned operations, and therefore we are no longer considered to be a
development stage company.
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
USE OF ESTIMATES - The preparation of financial statements in conformity
with generally accepted accounting principles requires us 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.
CASH EQUIVALENTS - For purposes of reporting cash flows, we consider as
cash equivalents all highly liquid investments with a maturity of three months
or less at the time of purchase. At May 31, 2004, there were no cash
equivalents.
6
PROPERTY AND EQUIPMENT - Furniture and equipment is recorded at cost.
Depreciation 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.
OIL AND GAS PROPERTIES - We follow 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 on a
country-by-country basis. 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.
We lease non-producing acreage for our 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.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 141, "Business
Combinations," which requires the purchase method of accounting for business
combinations initiated after June 30, 2001, and eliminates the
pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142,
"Goodwill and Other Intangible Assets," which discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and initiates an
annual review for impairment. Intangible assets with a determinable useful life
will continue to be amortized over that period. The oil and gas industry is
currently discussing the appropriate balance sheet classification of oil and gas
mineral rights held by lease or contract. We classify these assets as a
component of oil and gas properties in accordance with the full cost method of
accounting for oil and gas activities and common industry practice. There is
also a view that these mineral rights are intangible assets as defined in SFAS
No. 141, "Business Combinations," and, therefore, should be classified
separately on the balance sheet as intangible assets.
We did not change or reclassify contractual mineral rights included in oil
and gas properties on the balance sheet upon adoption of SFAS No. 141. We
believe our current accounting of such mineral rights, as part of oil and gas
properties, is appropriate under the full cost method of accounting. However, if
the accounting for mineral rights held by lease or contract is ultimately
changed so that costs associated with mineral rights not held under fee title
and pursuant to the guidelines of SFAS No. 141 are required to be classified as
long-term intangible assets, then the reclassified amount as of May 31, 2004,
would be approximately $7,140,000, and the reclassified amount as of August 31,
2003 (the end of our last completed fiscal year), would be approximately
$4,366,000. Management does not believe that the ultimate outcome of this issue
will have a significant impact on our cash flows, results of operations or
financial condition.
DEPLETION, DEPRECIATION AND AMORTIZATION - Depletion of exploration and
development costs and depreciation of production equipment is provided using the
unit-of-production method based upon estimated proven oil and gas reserves. The
costs of significant unevaluated or otherwise impaired properties are excluded
from costs subject to depletion. For depletion and depreciation purposes,
relative volumes of oil and gas production and reserves are converted at the
energy equivalent conversion rate of six thousand cubic feet of natural gas to
one barrel of crude oil. In conjunction with the May 2004 acquisition of oil and
gas properties from Venus Exploration, Inc. ("Venus"), a reserve report was
prepared by an independent petroleum engineering firm as of August 31, 2003.
This report was used to calculate depreciation, depletion and amortization
charges of the recently acquired properties at May 31, 2004. Prior to the
property acquisition from Venus, we had no proved reserves.
7
CEILING TEST - 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, net of residual salvage value, as a
component of impairment, dry holes and abandonment expense.
REVENUE RECOGNITION - We recognize oil and gas revenues from our interests
in producing wells as oil and gas is produced and sold from these wells. We have
no gas balancing arrangements in place. Oil and gas sold is not significantly
different from our product entitlement.
INCOME TAXES - We have adopted the provisions of SFAS No. 109, "Accounting
for Income Taxes." SFAS No. 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.
ASSET RETIREMENT OBLIGATIONS - In 2001, the FASB issued SFAS No. 143,
"Accounting for Asset Retirement Obligations." SFAS No. 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. Our asset retirement obligations
relate primarily to the plugging, dismantlement, removal, site reclamation and
similar activities of our oil and gas properties. Prior to adoption of this
statement, such obligations were accrued ratably over the productive lives of
the assets through our depreciation, depletion and amortization for oil and gas
properties without recording a separate liability for such amounts.
The transition adjustment related to adopting SFAS No. 143 on September 1,
2002, was recognized as a cumulative effect of a change in accounting principle.
The cumulative effect on net income of adopting SFAS No. 143 was a net
unfavorable effect of $341,175. At the time of adoption, total assets increased
$629,816, and total liabilities increased $769,175. The amounts recognized upon
adoption are based upon numerous estimates and assumptions, including future
retirement costs, future recoverable quantities of oil and gas, future inflation
rates and the credit-adjusted risk-free interest rate. During the quarter ended
May 31, 2004, an additional asset retirement obligation of $169,874 was
recognized in conjunction with the acquisition of properties from Venus. As of
May 31, 2004, the asset retirement obligation net asset balance, after
depreciation and impairment, was $244,125, and the total asset retirement
obligation liability, after accretion of unamortized discount, was $1,086,129.
STOCK OPTION COMPENSATION - We have elected to follow Accounting Principles
Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," and
related interpretations in accounting for its stock options and grants to
employees and directors since the alternative fair market value accounting
provided for under SFAS No. 123 requires use of grant valuation models that were
not developed for use in valuing employee stock options and grants. Under APB
Opinion No. 25, if the exercise price of our stock grants and options equal the
fair value of the underlying stock on the date of grant, no compensation expense
is recognized.
8
If compensation cost for our stock-based compensation plans had been
determined based on the fair value at the grant dates for awards under those
plans consistent with the method of SFAS No. 123, then our net loss per share
would have been adjusted to the pro forma amounts indicated below:
Three Months Three Months Nine Months Nine Months
Ended Ended Ended Ended
5/31/2004 5/31/2003 5/31/2004 5/31/2003
Net loss as reported $ (391,890) $ (385,176) $ (1,155,550) $ (2,309,385)
Deduct: stock-based compensation
Costs under SFAS No. 123 (184,070) -- (479,134) --
------------ ------------ ------------ ------------
Pro forma net loss (575,960) (385,176) (1,634,684) (2,309,385)
============ ============ ============ ============
Pro forma basic and diluted net
income per share:
Pro forma shares used in the 24,930,795 23,701,357 24,114,161 23,701,357
calculation of pro forma net
income per common share
basic and diluted
Reported net income per common
share - basic and diluted $ (0.02) $ (0.02) $ (0.05) $ (0.10)
Pro forma net income per common
share - basic and diluted $ (0.02) $ (0.02) $ (0.06) $ (0.10)
Pro forma information regarding net income is required by SFAS No. 123. Options
granted were estimated using the Black-Scholes valuation model. The following
weighted average assumptions were used for the three and nine months ended May
31, 2004.
Volatility 87-125%
Expected life of options (in years) 5-7
Dividend Yield 0.00%
Risk free interest rate 3.1-3.85%
NOTE 2 - COMMON STOCK
In early May 2004, we received subscriptions for an aggregate of $8,175,000
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 Exchange Act of 1934, as amended. The
first tranche of the Placement, consisting of 4.5 million shares and $4,905,000
in gross proceeds, was received and accepted in early May 2004. The second
tranche of the Placement, consisting of 3.0 million shares and $3,270,000 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. (as discussed in Note 3 below), and project development and drilling costs
associated with our exploration and exploitation portfolio. In early July 2004,
we filed a registration statement with the Securities and Exchange Commission to
register any resales of the shares purchased in the Placement under the
Securities Act of 1933, as amended.
9
NOTE 3 - ACQUISITION OF ASSETS FROM VENUS EXPLORATION, INC.
In May 2004, we acquired interests in certain producing properties for
approximately $3,230,000 (excluding costs associated with the acquisition) from
Venus Exploration, Inc. ("Venus"). Venus is 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. 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 $3,300,000 in net profits proceeds has been paid to the Trust.
NOTE 4 - CONVERTIBLE NOTES
On May 24, 2002, we received $6 million in gross proceeds from the sale of
convertible notes due May 24, 2009. These notes call for semi-annual interest
payments at an annual rate of 4.99% and are convertible into shares of common
stock at the rate of $1.30 per share. The interest can be paid in cash or added
to the principal amount at our discretion. The notes were issued to three
investment funds pursuant to exemptions from registration under Sections 3(b)
and/or 4(2) of the Securities Act of 1933, as amended. Between May 24, 2002 and
May 31, 2004, we elected to add all semi-annual interest payments, totaling
$623,351, to the principal balance (rather than pay the interest in cash on a
current basis) so that at May 31, 2004, the aggregate balance of these notes,
reflected as Convertible Notes under Long-Term Debt, was $6,623,351.
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
We are an independent oil and gas exploration and production company whose
strategic focus is the application of advanced seismic imaging and computer
aided exploration technologies in the systematic search for commercial
hydrocarbon reserves, primarily in the onshore western United States. We attempt
to leverage our technical experience and expertise with seismic data to identify
exploration and exploitation projects with significant potential economic
return. We intend to participate in selected exploration projects as a working
interest owner, sharing both risk and rewards with other participants. We do not
currently operate any projects in which we own a working interest, although we
may operate some projects in the future. We do not have the financial ability to
commence exploratory drilling operations without third party participation. We
have pursued, and will continue to pursue, exploration opportunities in regions
in which 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.
10
Liquidity and Capital Resources
At May 31, 2004, we had approximately $3,161,811 in working capital.
In early May 2004, we received subscriptions for an aggregate of $8,175,000
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 Exchange Act of 1934, as amended. The
first tranche of the Placement, consisting of 4.5 million shares and $4,905,000
in gross proceeds, was received and accepted in early May 2004. The second
tranche of the Placement, consisting of 3.0 million shares and $3,270,000 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. In early July 2004, we filed a registration
statement with the Securities and Exchange Commission to register any resales of
the shares purchased in the Placement under the Securities Act of 1933, as
amended.
In May 2004, we acquired interests in certain producing properties for
approximately $3,230,000 (excluding costs associated with the acquisition) from
Venus. Venus is 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 $3,300,000 in net profits proceeds has been
paid to the Trust.
During the quarter ended May 31, 2004, capitalized costs for oil and gas
properties increased by approximately $3,400,000. The increase is due largely to
the acquisition of assets from Venus, and also includes net costs incurred for
drilling and completion, geological and geophysical costs, delay rentals, other
related direct costs with respect to our exploration and development prospects,
as well as an increase of approximately $170,000 in asset retirement obligations
related to the acquisition from Venus, less depreciation of asset retirement
obligation assets of approximately $115,000. There was no charge to impairment
during the quarter, based upon management's determination that no further
impairment of undeveloped properties had occurred since the end of the prior
fiscal year.
It is anticipated that the continuation and future development of our
business will require additional, and possibly substantial, capital
expenditures. Our capital expenditure budget depends 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. For the fiscal year ending August 31, 2004, we
anticipate spending a minimum of approximately $900,000 for capital expenditures
relating to our existing drilling commitments and related development expenses,
and other exploration costs. To limit capital expenditures, we intend to form
industry alliances and exchange an appropriate portion of our interest for cash
and/or a carried interest in our exploration projects. We may need to raise
additional funds to cover capital expenditures. These funds may come from cash
flow, equity or debt financings, a credit facility, or sales of interests in our
properties, although there is no assurance additional funding will be available.
11
Capital Expenditures
During the quarter ended May 31, 2004, we incurred approximately $3,400,000
of capital costs, largely due to the acquisition of assets from Venus, as well
as our continuing exploration projects, acreage lease obligations and associated
geological and geophysical costs. Approximately $24,000 in capital costs were
incurred on our East Lost Hills Project during the quarter, resulting from
inventory audit adjustments. Revenues from oil and gas production during the
three months ended May 31, 2004 were $184,551.
We currently anticipate that we will participate in the drilling of up to
four exploration wells during our fiscal year ending August 31, 2004, 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.
The following table summarizes our obligations and commitments to make
future payments under our convertible notes payable and office and equipment
leases for the periods specified as of May 31, 2004:
Payments Due By Period
Contractual Year Ending Fiscal Years Fiscal Years Fiscal Years
Obligations Total August 31, 2004 2005-2007 2008-2009 2010 and After
----------------- ---------- --------------- ---------- ---------- --------------
Convertible Notes $8,474,313 $ -- $ -- $8,474,313 $ --
Office Lease,
Denver, CO 236,045 25,827 186,861 23,357 --
Office Lease, San
Antonio, TX 108,000 12,000 96,000 -- --
Copier Lease 3,108 777 2,331 -- --
Subscriber
Agreement to
Computer Service 14,700 1,225 13,475 -- --
---------- ---------- ---------- ---------- -------
Total Contractual
Cash Obligations $8,836,166 $ 39,820 $ 298,667 $8,497,670 $ --
The above schedule assumes convertible note interest payments will be added
to the principal amount (which is at our discretion), 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 $560,000 during the year ending August 31, 2004.
We consider on a quarterly basis whether to continue holding all or part of each
acreage block by making delay rental payments on existing leases.
12
Summary of Exploration Projects
The following is a summary of the current status of our exploration
projects:
Wyoming Overthrust Prospects:
In December 2003, we entered into an agreement with two private oil and gas
exploration companies covering two of our exploration projects in the Overthrust
of southwestern Wyoming.
The first agreement relates to the Mallard Prospect, which is located
adjacent to the south end of the Whitney Canyon - Carter Creek field. The
agreement requires the participants to drill the initial test well at the
Mallard Prospect to earn part of our acreage position within our Greater Duck
area of mutual interest. We currently control 4,160 net leasehold acres within
the Greater Duck AMI. The partners will pay us approximately $500,000 in
prospect fees and pro-rata development costs. The construction and preparation
of the drilling location is completed, and it is anticipated that the Mallard
test well will begin drilling in mid to late July. We will participate with a 5%
working interest in the drilling of Mallard, and will be carried to casing point
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.
The second agreement relates to the Cumberland Prospect. The Cumberland
prospect is on trend with these productive features, and also is located in the
Overthrust of Southwestern Wyoming, approximately 5 miles northeast of the
Ryckman Creek field.
It is currently anticipated that the test well for the Cumberland Prospect
will be drilled in mid to late-calendar 2004, contingent on rig availability.
The partners paid us $186,016 in prospect fees and pro-rata development costs.
An additional $86,004 will be paid upon the well reaching casing point. We will
participate with a 10% working interest in the drilling, and will be carried for
an additional 22.5% working interest to casing point in the initial test well.
After casing point, we will have a 32.5% working interest in the initial well
and all subsequent wells in the Prospect. The anticipated total depth of the
well is estimated to be 10,600 feet. We control 6,233 net leasehold acres within
the Cumberland area of mutual interest.
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. It is anticipated that
a well may be drilled at Ryckman Creek late in 2004, and based on our analysis,
we may decide to sell down part of our 100% working interest in the project.
Montana Foothills Project:
In March 2004, we signed an Exploration Option Agreement with a subsidiary
of Suncor Energy, Incorporated, covering our Rogers Pass exploration project in
the Foothills of west-central Montana. We currently control approximately
241,800 gross and 226,300 net leasehold acres in the Rogers Pass project. Within
the Rogers Pass acreage block, we have undertaken extensive seismic analysis and
geological study, resulting in the identification of multiple untested,
prospective structures. Historically, only one well has been drilled within the
acreage block: the Unocal #1-B30, drilled in 1989 to a depth of 17,817 feet,
which was plugged and abandoned after testing.
13
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. Before the
end of the technical evaluation period, SENGAI will make an election, by
late-July 2004 either to proceed to drill the first test well or to drop the
project. Should SENGAI elect to drill the first test well within the project
area, a prospect fee of $750,000 will be paid to us, and the well will be spud
prior to December 31, 2004. 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.
Interests Acquired from Venus Exploration, Inc.:
As part of our acquisition of oil and gas interests from Venus Exploration,
Inc. ("Venus"), Venus retained 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 acquired Venus acreage, 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.
Oil and gas interests acquired from Venus include producing oil and gas
properties, exploitation drilling projects, and exploration acreage. Producing
assets include both operated and non-operated properties. Current net production
from the acquired properties is approximately 980 Mcfe per day, with estimated
`total proved' reserves of 4.784 Bcfe. Proved developed producing reserves are
estimated to be 2.025 Bcfe, while the proved developed non-producing reserves
are estimated at 1.761 Bcfe. Proved undeveloped reserves are estimated to be
0.998 Bcfe. Present value, discounted at 10%, is $6,941,000 for total proved
reserves and $3,089,000 for proved developed producing reserves.
In Texas, we have interests in three projects recently acquired from Venus.
The test wells in these three projects are currently at total depth, and are
being production tested, and evaluated. The three wells currently engaged in
operations are subject to a 50% net profits interest payable to the Venus
Exploration Trust.
The Tortuga Grande prospect, located in east Texas, is a re-entry of an
existing well, drilled on a large turtle structure, 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 of the re-entry in which we are currently
involved indicates that the well contains approximately 322 feet of potential
pay greater than 8% porosity. The middle Cotton Valley Sand section has been
fracture stimulated, and the well is currently flowing back load fluid. Should
the fracture treatment prove successful, we believe that multiple additional
development locations would be available to us. We have a 10% carry through the
tanks with an additional 10% working interest, after well payout, on the initial
test 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.
The 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, and
we own a 1.5% overriding royalty interest with an additional 8.33% working
interest, after project payout, in the project. The well is currently being
evaluated and tested in the Yegua section. We and our partners control
approximately 4,200 acres of gross leasehold acres in the project. We also own
additional acreage in the Cotton Creek prospect, located adjacent to the Nome
project.
14
The 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 Bcp/d and 2.7 MMcf/d with no water. This well was subsequently junked
and abandoned in the Doyle interval and never produced from the zone. The
Sanders 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 being production tested and
evaluated in the Yegua section. We own a 0.5% overriding royalty interest that
converts to a 12.5% working interest in the project after payout of the initial
test well.
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. Numerous
sandstone reservoirs (including Milk River, Belly River, Medicine Hat, Bow
Island, Glauconite, and Viking), generally shallower than 4,000 feet, have
produced in excess of 10 tcf of natural gas. 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 that significant additional reserves
may remain in a number of shallow gas reservoirs in local areas within the
Southeastern Alberta.
Reworking of existing prematurely abandoned wellbores can potentially
result in increased production rates and capture of incremental reserves if
water coning can be reversed and surface water disposal can be mitigated. To
this end, the partners in the Atlas Joint Venture have entered into Exclusive
Supply Agreements with a down hole water disposal tool design and manufacturing
company to supply separation and disposal tools for use in Canada. These tools
are intended to gravity separate gas and water in the wellbore, reverse the flow
of water, and inject the water into a disposal zone below the existing
production interval. In this manner, existing wells with water production issues
can potentially have increased gas productivity due to the lack of water coning
and lifting. These down hole disposal tools also remove the issues related to
surface handling and disposal of produced fluids.
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.
15
Property Impairment
During the quarter ended May 31, 2004, we recognized no impairment of our
capitalized oil and gas properties, based upon management's determination that
no further impairment of undeveloped properties had occurred since the end of
the prior fiscal year. As of the end of the prior fiscal year, August 31, 2003,
management completed a comprehensive evaluation of our capitalized oil and gas
properties for purposes of determining impaired properties and recognized an
impairment charge against the East Lost Hills properties of approximately
$3,234,000 for the year then ended.
East Lost Hills, San Joaquin Basin, California
During the quarter ended May 31, 2004, no drilling or development
activities occurred at our East Lost Hills project. Although the 1998 blow-out
of the original test well, the Bellevue #1-17, evidenced high volumes and
deliverability of hydrocarbons, the project has still not established meaningful
commercial production, and it is unlikely that additional activity will occur on
the project. As of the end of the prior fiscal year, August 31, 2003, we
recognized an impairment charge against the entire amortizable balance of these
properties.
Results of Operations
The quarter ended May 31, 2004 compared with the quarter ended May 31,
2003.
Operations during the quarter ended May 31, 2004 resulted in a net loss of
$391,890 compared with a net loss of $385,176 for the quarter ended May 31,
2003. While we had increased revenues associated with properties acquired from
Venus Exploration Inc. ("Venus"), the overall increase in net loss was primarily
due to an increase in non-cash expense from implementing SFAS No. 143,
"Accounting for Asset Retirement Obligations." A broader discussion of these and
other items are presented below.
Oil and Gas Revenues and Expenses. During the quarter ended May 31, 2004,
we recorded $60,787 from the sale of 11,435 Mcf of natural gas, for an average
price of $5.32 per Mcf, and $123,762 from the sale of 3,362 bbls of hydrocarbon
liquids, for an average price of $36.81 per barrel. Lease operating expenses
during this period were $77,958. Revenues and lease operating expenses related
to the properties acquired from Venus represent activity from the acquisition
close date (in May 2004) through the quarter ended May 31, 2004. During the
quarter ended May 31, 2003, we recorded $33,884 from the sale of 6,347 Mcf of
natural gas for an average price of $5.34 per Mcf and $9,157 from the sale of
332 bbls of hydrocarbon liquids for an average price of $27.58 per barrel. Lease
operating expenses during this period were $18,349.
Depreciation, Depletion and Amortization. We recorded $1,700 and $0,
respectively, in depreciation, depletion and amortization expense from oil and
gas properties for the quarters ended May 31, 2004 and May 31, 2003. The
increase in depreciation, depletion and amortization expense was attributable to
the properties acquired from Venus. We recorded $3,302 and $3,020 in
depreciation expense associated with capitalized office furniture and equipment
during the quarters ended May 31, 2004 and May 31, 2003, respectively.
Additionally, we recorded $38,953 of depreciation of Asset Retirement Obligation
assets, and $27,858 of accretion of the unamortized discount of the Asset
Retirement Obligation liability.
Dry Hole, Impairment and Abandonments. During the quarters ended May 31,
2004 and May 31, 2003, we recorded no impairment expense. Although properties
may be considered evaluated for purposes of the ceiling test and included in the
impairment calculation, until these properties are completely abandoned, we may
continue to incur costs associated with these properties. Until we can establish
economic reserves of the impaired properties, of which there is no assurance,
any additional costs associated with these properties are capitalized, and then
charged to impairment expense as incurred.
16
General and Administrative Expense. We incurred $350,377 and $339,576 in
general and administrative expenses during the quarters ended May 31, 2004 and
May 31, 2003, respectively. The increase principally reflects additional
accounting and auditing fees incurred in conjunction with properties acquired
from Venus.
Interest Expense. We incurred $82,234 and $78,316 in interest expense for
the quarters ended May 31, 2004 and May 31, 2003, 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 nine months ended May 31, 2004 compared with the nine months ended May
31, 2003.
Oil and Gas Revenues and Expenses. During the nine months ended May 31,
2004, we recorded $124,287 from the sale of 26,035 Mcf of natural gas, for an
average price of $4.77 per Mcf, and $144,657 from the sale of 4,162 bbls of
hydrocarbon liquids, for an average price of $35.76 per barrel. Lease operating
expenses during this period were $114,910. Revenues and lease operating expenses
related to the properties acquired from Venus represent activity from the
acquisition close date (in May 2004) through the quarter ended May 31, 2004.
During the nine months ended May 31, 2003, we recorded $106,507 from the sale of
25,268 Mcf of natural gas for an average price of $4.22 per Mcf and $30,572 from
the sale of 1,192 bbls of hydrocarbon liquids for an average price of $25.65 per
barrel. Lease operating expenses during this period were $64,694.
Depreciation, Depletion and Amortization. We recorded $1,700 and $0,
respectively, in depreciation, depletion and amortization expense from oil and
gas properties for the nine months ended May 31, 2004 and May 31, 2003. Although
the East Lost Hills #1 has produced continuously since 2001, we previously
recorded an impairment charge against our entire amortizable full cost pool, and
therefore had no costs to amortize. We recorded $9,584 and $8,892 in
depreciation expense associated with capitalized office furniture and equipment
during the nine months ended May 31, 2004 and May 31, 2003, respectively.
Additionally, we recorded $114,595 of depreciation of Asset Retirement
Obligation assets, and $70,162 of accretion of the unamortized discount of the
Asset Retirement Obligation liability.
Dry Hole, Impairment and Abandonments. During the nine months ended May 31,
2004, we recorded no impairment expense, compared to $1,178,267 of impairment
expense for the nine months ended May 31, 2003. Although properties may be
considered evaluated for purposes of the ceiling test and included in the
impairment calculation, until these properties are completely abandoned, we may
continue to incur costs associated with these properties. Until we can establish
economic reserves of the impaired properties, of which there is no assurance,
any additional costs associated with these properties are capitalized, and then
charged to impairment expense as incurred.
General and Administrative Expense. We incurred $887,309 and $1,010,119 in
general and administrative expenses during the nine months ended May 31, 2004
and May 31, 2003, respectively. The decrease principally reflects fewer
employees in 2004, as well as a decrease in funding and acquisition costs.
Interest Expense. We incurred $242,784 and $230,371 in interest expense for
the nine months ended May 31, 2004 and May 31, 2003, respectively. The interest
expense for each year is associated with the May 24, 2002 sale of outstanding
convertible notes due on May 24, 2009.
Cash Flow
The nine months ended May 31, 2004 compared to the nine months ended May
31, 2003
17
Cash Flows From Operating Activities
Net cash used by operating activities was $939,021 and $650,840 for the
nine months ended May 31, 2004 and May 31, 2003, respectively. A discussion of
these and other items are presented below.
Net loss. See discussion of net loss in "Results of Operations" section
above.
Depreciation and amortization. Depreciation expense increased to $196,042
for the nine months ended May 31, 2004, compared to $8,892 for the nine months
ended May 31, 2003. The 2004 expense includes depreciation of Asset Retirement
Obligation assets of $114,595 together with $70,162 of accretion of unamortized
discount of the Asset Retirement Obligation liability, neither of which was
recognized in 2003.
Impairment, dry hole and abandonments. During the nine months ended May 31,
2004, we recorded no impairment expense as compared to $1,178,267 during the
nine months ended May 31, 2003. The 2003 impairment related principally to costs
incurred to drill and complete wells in the East Lost Hills project.
Accrued interest converted into debt. For the nine months ended May 31,
2004, accrued interest converted into debt was $319,376 compared to $221,948 for
the nine months ended May 31, 2003. Both amounts reflect interest accrued on the
$6,000,000 convertible notes issued May 24, 2002.
Prepaid expenses. During the nine months ended May 31, 2004 and May 31,
2003, prepaid expenses increased $51,382 and $23,976, respectively. The increase
reflects higher director and officer liability insurance premiums.
Accounts payable and accruals. During the nine months ended May 31, 2004
and May 31, 2003, accounts payable and accruals increased $88,890, and $311,024,
respectively, reflecting lower amounts due to the operator of the East Lost
Hills project for costs to drill and complete wells.
Cash Flows From Investing Activities
Cash paid for oil and gas properties. During the nine months ended May 31,
2004, we paid $3,887,304 for oil and gas properties, compared to $1,067,737,
during the nine months ended May 31, 2003. The increased payment reflects the
acquisition of properties from Venus in May 2004.
Proceeds from sale of exploration options. During the nine months ended May
31, 2004, we signed an Exploration Option Agreement with a subsidiary of Suncor
Energy, Suncor Energy Natural Gas America, Inc. ("SENGAI"), covering our Rogers
Pass exploration project in the Foothills of west-central Montana. Pursuant to
our agreement, SENGAI has paid us a (non-refundable) $500,000 option fee for a
technical evaluation period of up to three months. Before the end of the
technical evaluation period, SENGAI will make an election, by late-July 2004
either to proceed to drill the first test well or to drop the project.
Proceeds from sale of oil and gas properties. During the nine months ended
May 31, 2004, we entered into an agreement with two private oil and gas
exploration companies covering two of our exploration projects in the Overthrust
of southwestern Wyoming. In conjunction with this agreement, the partners paid
us $186,016 in prospect fees and pro-rata development costs.
18
Cash Flows From Investing Activities
Cash provided by financing activities was $4,442,353 and $0 for the nine
months ended May 31, 2004 and May 31, 2003, respectively. The increase primarily
reflects the first tranche of a private placement of our common stock,
consisting of 4.5 million shares and $4,905,000 in gross proceeds, which was
received and accepted in early May 2004. The second tranche of the private
placement, consisting of 3.0 million shares and $3,270,000 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,
subsequent to the period ended May 31, 2004.
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.
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, or where there are no
proved reserves, it would be the estimated market value of our unproved
properties. We perform a detailed estimate of the market value of each property
on a quarterly basis based on information known to management as to drilling
activity in the area of our holdings and our near term intent to develop such
properties. Gains or losses upon disposition of or impairment of our unproved
oil and gas properties are recorded in the statement of operations as we have no
proved reserves.
Revenue Recognition:
We recognize oil and gas revenues from our interests in producing wells as
oil and gas is produced and sold from these wells. We have no gas balancing
arrangements in place. Oil and gas sold is not significantly different from our
product entitlement.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," which requires the purchase method of
accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS
No. 142, "Goodwill and Other Intangible Assets," which discontinues the practice
of amortizing goodwill and indefinite lived intangible assets and initiates an
annual review for impairment. Intangible assets with a determinable useful life
will continue to be amortized over that period. The oil and gas industry is
currently discussing the appropriate balance sheet classification of oil and gas
mineral rights held by lease or contract. We classify these assets as a
component of oil and gas properties in accordance with our interpretation of
SFAS No. 19 and common industry practice. There is also a view that these
mineral rights are intangible assets as defined in SFAS No. 141, "Business
Combinations", and, therefore, should be classified separately on the balance
sheet as intangible assets.
19
We did not change or reclassify contractual mineral rights included in oil
and gas properties on the balance sheet upon adoption of SFAS No. 141. We
believe our current accounting of such mineral rights as part of oil and gas
properties is appropriate under the full cost method of accounting. However, if
the accounting for mineral rights held by lease or contract is ultimately
changed so that costs associated with mineral rights not held under fee title
and pursuant to the guidelines of SFAS No. 141 are required to be classified as
long term intangible assets, then the reclassified amount as of May 31, 2004
would be approximately $4,059,000 and the reclassified amount as of August 31,
2003 (the end of our last completed fiscal year) would be approximately
$4,366,000. Management does not believe that the ultimate outcome of this issue
will have a significant impact on our cash flows, results of operations or
financial condition.
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.
20
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings
Not Applicable
Item 2. Changes in Securities and Use of Proceeds; Recent Sales Of Unregistered
Securities
In early May 2004, we received subscriptions for an aggregate of $8,175,000
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 Exchange Act of 1934, as amended. The
first tranche of the Placement, consisting of 4.5 million shares and $4,905,000
in gross proceeds, was received and accepted in early May 2004. The second
tranche of the Placement, consisting of 3.0 million shares and $3,270,000 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. In early July 2004, we filed a registration
statement with the Securities and Exchange Commission to register any resales of
the shares purchased in the Placement under the Securities Act of 1933, as
amended.
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 and Reports on Form 8-K
(a) Exhibits
Exhibit Index
--------------------------------------------------------------------------------
Number Description
--------------------------------------------------------------------------------
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
21
(b) During the quarter ended May 31, 2004, we filed the following reports
on Form 8-K:
On March 18, 2004 disclosing a news release dated March 17, 2004,
which announced that we had signed an exploration option agreement for
the Montana Foothills Project.
On April 6, 2004 disclosing a news release dated April 5, 2004, which
announced the acquisition of assets from Venus Exploration, Inc. and
three exploration/exploitation projects scheduled to commence drilling
operations.
On April 15, 2004 disclosing a news release dated April 13, 2004,
which announced our unaudited financial results for the three months
ended February 29, 2004.
On May 11, 2004 disclosing a news release dated May 6, 2004, which
announced an $8.175 million private placement of our common stock.
On May 13, 2004 disclosing a news release dated May 12, 2004, which
announced the closing of the acquisition of assets from Venus
Exploration, Inc. and updated operational activities.
Following the quarter ended May 31, 2004, we filed reports on Form 8-K
for events occurring on the following dates:
June 14, 2004
June 16, 2004
July 2, 2004 (Form 8-K/A)
22
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 July 15, 2004
------------------------ and Principal Financial Officer
D. Scott Singdahlsen
23