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 February 29, 2004
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from to
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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
incorporation or organization) Identification No.)
1675 Broadway, Suite 2450, Denver, CO 80202
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(Address of principal executive offices) (Zip Code)
Issuer's telephone number, including area code (303) 825-3748
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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
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Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes No X
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(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
The number of shares outstanding of each of the issuer's classes of common
equity as of February 29, 2004 is as follows:
$.001 Par Value Common Stock 23,701,357
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.......................................... 3
Balance Sheets - February 29, 2004 (Unaudited) and
August 31, 2003............................................... 3
Statements of Operations - Three Months and Six Months
Ended February 29, 2004 and February 28, 2003 and
Cumulative Amounts From Inception Through February 29,
2004 (Unaudited).............................................. 4
Statements of Cash Flows - Six Months Ended February 29,
2004 and February 28, 2003 and Cumulative Amounts
From Inception Through February 29, 2004 (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........................................ 19
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................. 20
Item 2. Changes in Securities and Use of Proceeds; Recent
Sales of Unregistered Securities.............................. 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 and Reports on Form 8-K.............................. 20
Signatures................................................................. 21
2
PART I
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
(A Development Stage Company)
BALANCE SHEETS
ASSETS
February 29, August 31,
2004 2003
------------ ------------
(Unaudited)
CURRENT ASSETS
Cash $ 2,647,813 $ 3,657,938
Deposits, prepaid expenses and other receivables 109,070 46,559
------------ ------------
Total Current Assets 2,756,883 3,704,497
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 23,268 29,313
Oil and gas properties under full cost, net 5,334,242 5,287,837
------------ ------------
5,357,510 5,317,150
------------ ------------
OTHER ASSETS
Deferred financing costs and other assets 76,664 68,257
Deferred acquisition costs 300,000 --
------------ ------------
376,664 68,257
------------ ------------
$ 8,491,057 $ 9,089,904
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 273,728 $ 309,796
Asset retirement obligation 727,231 727,231
------------ ------------
Total Current Liabilities 1,000,959 1,037,027
------------ ------------
LONG TERM LIABILITIES
Convertible Notes 6,462,552 6,303,975
Asset retirement obligation 161,165 118,862
------------ ------------
Total Long Term Liabilties 6,623,717 6,422,837
------------ ------------
STOCKHOLDERS' EQUITY
Common stock, $.001 par value
Authorized 75,000,000 shares
Issued and outstanding - 23,701,357 shares 23,701 23,701
Capital in excess of par value 35,407,657 35,407,657
Deficit accumulated during the development stage (34,564,977) (33,801,318)
------------ ------------
866,381 1,630,040
------------ ------------
$ 8,491,057 $ 9,089,904
============ ============
3
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Three Six Six Cumulative from
Months Months Months Months Inception
Ended Ended Ended Ended Through
2/29/2004 2/28/2003 2/29/2004 2/28/2003 2/29/2004
--------- --------- --------- --------- ---------
REVENUES
Oil and gas revenues $ 44,376 $ 46,494 $ 84,394 $ 94,038 $ 1,614,109
------------ ------------ ------------ ------------ ------------
44,376 46,494 84,394 94,038 1,614,109
------------ ------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 21,681 25,308 36,952 46,345 325,688
Impairment, dry hole, and abandonments -- 698,599 -- 1,178,267 28,818,139
Depreciation and amortization 62,956 2,786 124,228 5,872 462,222
General and administrative 285,442 345,237 536,932 670,543 7,097,268
------------ ------------ ------------ ------------ ------------
370,079 1,071,930 698,112 1,901,027 36,703,317
LOSS FROM OPERATIONS (325,703) (1,025,436) (613,718) (1,806,989) (35,089,208)
OTHER INCOME (EXPENSE)
Interest income 5,041 14,089 10,608 34,835 955,755
Other income -- -- -- -- 127,528
Interest (expense) (81,196) (76,489) (160,550) (152,055) (738,207)
Gain on sale of oil and gas prospects -- -- -- -- 556,197
------------ ------------ ------------ ------------ ------------
(76,155) (62,400) (149,942) (117,220) 901,273
INCOME APPLICABLE TO PREDECESSOR LLC -- -- -- -- (35,868)
------------ ------------ ------------ ------------ ------------
LOSS BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE (401,858) (1,087,836) (763,660) (1,924,209) (34,223,803)
Cumulative effect of change in
accounting principle -- -- -- -- (341,175)
------------ ------------ ------------ ------------ ------------
NET LOSS (401,858) (1,087,836) (763,660) (1,924,209) (34,564,978)
Less dividends on preferred stock -- -- -- -- (292,411)
------------ ------------ ------------ ------------ ------------
NET LOSS TO COMMON STOCKHOLDERS $ (401,858) $ (1,087,836) $ (763,660) $ (1,924,209) $(34,857,389)
============ ============ ============ ============ ============
NET LOSS PER COMMON
SHARE - BASIC AND DILUTED (0.02) (0.05) (0.03) (0.08)
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 23,701,357 23,701,357 23,701,357 23,701,357
============ ============ ============ ============
4
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Cmulative from
Six Months Six Months Inception
Ended Ended Through
February 29, February 28, February 29,
2004 2003 2004
------------ ----------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss (763,660) $ (1,924,209) $(34,857,389)
Adjustments to reconcile net loss to
net cash used by operating activities
Cummulative effect of change in acounting principle -- -- 341,175
Depreciation and amortization 124,228 5,872 462,223
Contributed services -- -- 36,000
Gain on sale of oil and gas prospects -- -- (556,197)
Impairment, dry hole and abandonments -- 1,178,267 28,818,139
Common stock issued for interest on debt -- -- 136,822
Warrants issued for services -- -- 178,665
Amortization of financing costs 1,593 1,594 32,586
Amortization of marketable securities -- -- (20,263)
Interest expense converted into debt 158,577 71,487 462,552
Changes in assets and liabilities
(Increase) decrease in accounts receivable (6,553) -- (7,119)
(Increase) decrease in prepaids (55,957) (47,340) (107,069)
(Decrease) increase in accounts payable, accruals (105,932) 429,114 (1,222,113)
Other (50,000) -- 239,558
------------ ------------ ------------
Net cash used by operating activities (697,704) (285,215) (6,062,430)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (237) (4,688) (138,703)
Cash paid for oil and gas properties (238,200) (986,569) (32,720,842)
Proceeds from sale of oil and gas properties -- -- 1,300,078
Deferred acquisition costs (250,000) -- (250,000)
Cash paid for marketable securities -- -- (5,090,799)
Proceeds from sale of marketable securities -- -- 5,111,062
Cash paid for reimbursable property costs -- -- (28,395)
Other 176,016 -- 176,016
------------ ------------ ------------
Net cash used in investing activities (312,421) (991,257) (31,641,583)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Members capital contributions -- -- 28,000
Distributions to members -- -- (66,000)
Cash from short-term borrowings -- -- 285,000
Repayment of short-term borrowings -- -- (285,000)
Cash received upon recapitalization and merger -- -- 336
Proceeds from sale of common stock -- -- 30,788,750
Proceeds from sale of convertible debt -- -- 8,500,001
Proceeds from exercise of warrants -- -- 2,011,073
Proceeds from exercise of options -- -- 204,530
Cash paid for offering and financing costs -- -- (1,058,759)
Payments on capital lease -- -- (5,195)
Preferred dividends paid -- -- (50,910)
------------ ------------ ------------
Net cash provided by financing activities -- -- 40,351,826
------------ ------------ ------------
NET (DECREASE) INCREASE IN CASH (1,010,125) (1,276,472) 2,647,813
CASH, BEGINNING OF PERIODS 3,657,938 6,516,086 --
------------ ------------ ------------
CASH, END OF PERIODS $ 2,647,813 $ 5,239,614 $ 2,647,813
============ ============ ============
5
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
February 29, 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 February 29, 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, the Company was re-incorporated
in Maryland through the merger of the Company into a wholly owned subsidiary,
PYR Energy Corporation, a Maryland corporation. On February 18, 2004, PYR
Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC were formed as wholly owned
subsidiaries of PYR Energy Corporation. The purpose of these entities is to hold
certain assets related to designated individual exploration projects. As of
February 29, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC had
no business activity.
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 February 29, 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 - The Company utilizes the full cost method of
accounting for oil and gas activities. Under this method, subject to a
limitation based on estimated value, all costs associated with property
acquisition, exploration and development, including costs of unsuccessful
exploration, are capitalized within a cost center. The Company's oil and gas
properties are located within the United States, which constitutes one cost
center. No gain or loss is recognized upon the sale or abandonment of
undeveloped or producing oil and gas properties unless the sale represents a
significant portion of oil and gas properties and the gain significantly alters
the relationship between capitalized costs and proved oil and gas reserves of
the cost center. Depreciation, depletion and amortization of oil and gas
properties is computed on the units of production method based on proved
reserves. Amortizable costs include estimates of future development costs of
proved undeveloped reserves. A reserve report prepared as of August 31, 2001, by
an independent petroleum engineering firm concluded that reserves from the
Company's producing properties were not economic to produce and, therefore, at
August 31, 2001, the Company had no proved reserves. The Company has not
established additional production as of February 29, 2004, and, accordingly, did
not prepare a reserve report.
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.
The Company leases non-producing acreage for its exploration and
development activities. The cost of these leases is included in unevaluated oil
and gas property costs recorded at the lower of cost or fair market value.
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. The Company classifies 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.
The Company did not change or reclassify contractual mineral rights
included in oil and gas properties on the balance sheet upon adoption of SFAS
No. 141. The Company believes its 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
7
to be classified as long term intangible assets, then the reclassified amount as
of February 29, 2004, would be approximately $4,059,000 and the reclassified
amount as of August 31, 2003 (the end of the Company's 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 the Company's
cash flows, results of operations or financial condition.
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. 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 its 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. As of
February 29, 2004, the asset retirement obligation net asset balance, after
depreciation and impairment, was $113,204, and the total asset retirement
obligation liability, after accretion of unamortized discount, was $888,396.
STOCK OPTION COMPENSATION - The Company has 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 the Company's stock
grants and options equal the fair value of the underlying stock on the date of
grant, no compensation expense is recognized.
If compensation cost for the Company's 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 the Company's net
income per share would have been adjusted to the pro forma amounts indicated
below:
8
Three Months Three Months Six Months Six Months
Ended Ended Ended Ended
2/29/04 2/28/03 2/29/04 2/28/03
------- ------- ------- -------
Net loss as reported $ (401,858) $ (1,087,836) $ (763,660) $ (1,924,209)
Deduct: stock-based compensation
Costs under SFAS No. 123 (162,444) -- (295,064) --
------------ ------------ ------------ ------------
Pro forma net loss (564,302) (1,087,836) (1,058,724) (1,924,209)
============ ============ ============ ============
Pro forma basic and diluted net
income per share:
Pro forma shares used in the 23,701,357 23,701,357 23,701,357 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) $ (0.05) $ (0.03) $ (0.08)
Pro forma net income per common
share - basic and diluted $ (0.02) $ (0.05) $ (0.03) $ (0.08)
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 six months ended
February 29, 2004.
Volatility 100-125%
Expected life of options (in years) 5-7
Dividend Yield 0.00%
Risk free interest rate 3%
NOTE 2 - ACQUISITION OF ASSETS FROM VENUS EXPLORATION, INC.
The Company has agreed to acquire substantially all the assets of
Venus Exploration, Inc. ("Venus"), which is currently under the supervision of
the United States Bankruptcy Court ("Court"). The Court will soon issue the
final Order of Sale and the acquisition is expected to close on or before May 3,
2004. The Company and Venus have signed a definitive Purchase and Sale
Agreement, and the total purchase price is $3,205,000, subject to final
adjustments at closing. The purchase 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 proceeds has been paid to the Trust.
In connection with this purchase, the Company placed $250,000 in an
escrow account during the quarter ended February 29, 2004. The Company also
incurred approximately $50,000 in related legal fees during the quarter ended
February 29, 2004. These amounts are recorded as deferred acquisition costs. The
escrow amount will be applied to the purchase price. Other costs incurred in
conjunction with the acquisition, including the escrow amount, will be
capitalized as part of the acquisition costs. In the unlikely event the
acquisition does not close, the Company will be subject to a break-up fee of
$150,000, and all other previously deferred costs will be expensed in
operations.
9
NOTE 3 - 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 the discretion of the Company. 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. On November
24, 2002, May 24, 2003 and November 24, 2003, we elected to add $151,751,
$152,224 and $158,577, respectively, in interest due on these notes to the
principal balance (rather than pay the interest in cash on a current basis) so
that at February 29, 2004, the aggregate balance of these notes, reflected as
Convertible Notes under Long Term Debt, was $6,462,552.
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 2. Financial Statements" of
this Form 10-QSB.
Overview
We are a development stage independent oil and gas exploration company
whose strategic focus is the application of advanced seismic imaging and
computer aided exploration technologies in the systematic search for commercial
hydrocarbon reserves, primarily in the onshore western United States. We attempt
to leverage our technical experience and expertise with seismic data to identify
exploration and exploitation projects with significant potential economic
return. We intend to participate in selected exploration projects as a working
interest owner, 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.
Liquidity and Capital Resources
At February 29, 2004, we had approximately $1,755,924 in working capital.
During the quarter ended February 29, 2004, capitalized costs for oil and
gas properties decreased by approximately $122,000, due largely to adjustments
credited by the operator of the East Lost Hills wells for previously billed well
equipment costs. The resulting net credit incurred for drilling and completion,
geological and geophysical costs, delay rentals and other related direct costs
with respect to our exploration and development prospects was approximately
$84,000, less depreciation of asset retirement obligation assets of
approximately $38,000. There was no charge to impairment during the quarter,
10
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. At this time, our ongoing administrative and operating overhead
exceeds our incoming revenue, and 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, 2004, 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, including continuing results at our East Lost Hills project. 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.
Capital Expenditures
During the quarter ended February 29, 2004, we incurred approximately
$122,000 of capital costs relating to our exploration projects in California and
the Rocky Mountain region, including continued acreage lease obligations and
associated geological and geophysical costs. There were no capital costs
incurred on our East Lost Hills Project during the quarter. Revenues from oil
and gas production during the three months ended February 29, 2004, were
$44,376.
We currently anticipate that we will participate in the drilling of up
to three 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 the Company's obligations and commitments to
make future payments under its convertible notes payable and office lease for
the periods specified as of February 29, 2004:
Payments Due By Period
----------------------------------------------------------------------------------
Contractual Year Ended Fiscal Years Fiscal Years Fiscal Years
Obligations Total August 31, 2004 2005-2007 2008-2009 2010 and After
----------- ----- --------------- --------- --------- --------------
Convertible Notes $8,474,313 $-0- $-0- $8,474,313 $-0-
Office Lease 51,640 51,640 -0- -0- $-0-
Total Contractual
Cash Obligations $8,525,953 $ 51,640 -0- $8,474,313 $-0-
11
The above schedule assumes convertible note interest payments will be added to
the principal amount (which is at the discretion of the Company), and the entire
balance will be paid in full on maturity of May 24, 2009, and there will be no
conversion of debt to common stock. In addition to the above obligations, if we
elect to continue holding all our existing leases on a delayed rental basis, we
would have to pay approximately $560,000 during the year ending August 31, 2004.
The Company considers on a quarterly basis whether to continue holding all or
part of each acreage block by making delay rental payments on existing leases.
Summary of Exploration Projects
The following is a summary of the current status of our exploration
projects:
Wyoming Overthrust Prospects:
In December 2003, the Company entered into an agreement with two private
oil and gas exploration companies covering the Company's exploration projects in
the Overthrust of Southwestern Wyoming.
The Cumberland Prospect is a Jurassic Nugget test of an undrilled structure
at the leading edge of the Absaroka Thrust. The Nugget Formation has produced in
excess of 3.70 Tcfe of natural gas from structural closures on the Absaroka
Thrust. The Cumberland prospect is on trend with these productive features, and
is located approximately 5 miles northeast of the Ryckman Creek field. Ryckman
Creek field was discovered in 1975 by Amoco and Chevron, and produced in excess
of 250 Bcfe from the Nugget, prior to abandonment.
It is currently anticipated that the test well for the Cumberland Prospect
will be drilled in mid-calendar 2004. The partners paid the Company $186,016 in
prospect fees and pro-rata development costs. An additional $86,004 will be paid
upon the well reaching casing point. PYR Energy 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,
PYR 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. As part of the agreement, PYR has been reimbursed for certain
exploration and prospect development costs associated with the Cumberland
Prospect. PYR controls 6,233 net acres within the Cumberland area of mutual
interest ("AMI").
After drilling of the Cumberland test well, the participants also will have
an option to earn part of PYR's Greater Duck AMI surrounding the Mallard
Prospect at the south end of the giant Whitney Canyon - Carter Creek gas field.
The agreement requires the participants to drill the initial test well at the
Mallard Prospect to earn part of PYR's acreage position within the AMI. PYR
currently controls 4,160 net acres of leasehold within the Greater Duck AMI.
Upon election to drill the Mallard test well, the partners will pay the Company
$445,570 in prospect fees and pro-rata development costs. If the Mallard
Prospect is drilled, PYR will participate with a 5% working interest and will be
carried for an additional 23.75% working interest to casing point in the initial
test well. After casing point, PYR will have a 28.75% working interest in the
initial test well and all subsequent wells in the prospect.
The Mallard Prospect, seismically identified as a subsidiary structural
feature, is located adjacent to the south end of the Whitney Canyon - Carter
Creek field. Whitney Canyon - Carter Creek, discovered in 1978, has produced
approximately 1.98 Tcfe of natural gas from multiple Paleozoic reservoirs in a
large, complex structural closure on the Absaroka Thrust. The main target
horizon at Mallard Prospect is the Mississippian Mission Canyon Formation at an
estimated depth of approximately 14,500 feet. The Mission Canyon Formation has
accounted for 93% of the cumulative production from Whitney Canyon - Carter
Creek.
12
The agreement also provides that the participants can earn interests in
certain other portions of the Company's Overthrust acreage by undertaking other
specified exploration activities.
Montana Foothills Project:
In March of 2004, the Company signed an Exploration Option Agreement with a
subsidiary of Suncor Energy, Incorporated, covering the Company's Rogers Pass
exploration project in the Foothills of west-central Montana.
The Rogers Pass project has been classified as the southern extension of
the Alberta Foothills producing province. The USGS and numerous Canadian
industry sources have estimated significant recoverable reserves for the Montana
portion of the Foothills trend. The Company currently controls approximately
241,800 gross and 226,300 net acres in the Rogers Pass project. Company
management believes that the geology and seismic character of the Rogers Pass
project share many of the same characteristics as those observed within the
productive Canadian Foothills Trend of southern Alberta. Within the Rogers Pass
acreage block, PYR has undertaken extensive seismic analysis and geological
study resulting in the identification of multiple untested, prospective
structures. As of April 13, 2004, only one well has been drilled within the
acreage block: the Unocal #1-B30, drilled in 1989 to a depth of 17,817 feet, was
plugged and abandoned after testing.
The agreement with Suncor Energy Natural Gas America, Inc ("SENGAI") calls
for SENGAI to pay the Company a $500,000 option fee for a technical evaluation
period of up to three months. This amount has subsequently been received. Before
the end of the technical evaluation period, SENGAI will make an election 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 PYR 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. PYR 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 AMI.
Acquisition of Assets of Venus Exploration, Inc.:
The Company has agreed to acquire substantially all the assets of Venus
Exploration, Inc. ("Venus"), which is currently under the supervision of the
United States Bankruptcy Court in the Eastern District of Texas. The Court will
soon issue the final Order of Sale and the acquisition will close on or before
May 3, 2004, with an effective date of January 1, 2004. PYR and Venus have
signed a definitive Purchase and Sale Agreement, and the total purchase price is
$3,205,000, subject to final adjustments at closing. The Company could finance
this purchase with existing cash balances; however, the Company is also
exploring raising capital from other sources. The purchase 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 proceeds has been paid to the
Trust.
Assets in the acquisition 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 internally
estimated `total proved' reserves of 4.667 Bcfe. Proved developed producing
("PDP") reserves are estimated at 692.5 MMcf and 192.6 Mbo (1.848 Bcfe) while
the proved developed not producing ("PDNP") reserves are estimated at 34.8 MMcf
13
and 205.0 Mbo (1.265 Bcfe). Proved un-developed ("PUD") reserves are estimated
at 862.2 MMcf and 115.2 Mbo or 1.554 Bcfe. Using flat pricing of $28 per bbl and
$4.50 per Mcf, internal estimate of the present value, discounted at 10%, for
total proved reserves is $5,819,000 and $3,797,000 for total proved developed
reserves. Given the final estimated purchase price, total proved reserves will
be purchased at $0.68 per Mcfe while the total proved developed reserves will be
purchased at $1.02 per Mcfe.
A total of seven existing exploration and exploitation projects are
included in the asset acquisition. Of this total, three projects are pre-sold to
industry partners and are scheduled to begin drilling operations within the next
45 days. These projects include Tortuga Grande Prospect in Smith County, Texas,
and the Nome and Madison Prospects in Jefferson County, Texas. PYR will have no
capital costs associated with the initial testing of each of these three
projects.
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.
Shallow zones in the overlying Sand Flats field, including the Paluxy, Rodessa,
and Travis Peak, have produced in excess of 90 MMbo and 60 Bcf on the turtle
structure, although this is not indicative of whether the deeper zones will be
productive. 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 by Schlumberger indicates that the well
contains approximately 322 feet of potential pay greater than 8% porosity. A
multi-stage fracture stimulation treatment is planed to evaluate the productive
potential of the feature. Should the fracture treatment prove successful,
multiple additional development locations would be available to the Company. PYR
will 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 AMI, PYR will participate with a cost bearing 20% working interest. PYR
currently controls approximately 5,600 net lease acres within the project AMI.
The Nome Field was discovered in 1994, and 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 PYR
will be carried for an 8.33% working interest, after project payout, in the
project. PYR and partners control approximately 4,200 acres of leasehold in the
project.
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
(Texaco #1 Doyle) within the field. The location will also offset 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 Doyle #1 well. PYR
owns 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:
PYR has entered into two joint ventures, covering approximately 20 million
acres, 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 4000 feet, have produced in excess of 10 tcf of
natural gas. The Company has undertaken geologic and engineering studies of the
14
region, and believes 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 the
shallow gas reservoirs in local areas within the Joint Venture ("JV") AMI.
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 JV partners have entered into Exclusive Supply Agreements with a
Houston-based down hole water disposal tool design and manufacturing company to
supply separation and disposal tools for use in Canada. These tools have the
proven ability 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.
The Company owns a 5% working interest in the Atlas Joint Venture, which
covers approximately 4 million acres within southeastern Alberta. The Company
and its partners have identified multiple potential re-entry and redevelopment
opportunities within the JV AMI. The first well (Princess #10-9 well) in the
Apollo prospect has been re-entered, re-perforated, and completed in the upper
Bow Island sand. After cumulative production of 0.3 Bcf, the well was abandoned
as non-productive, but after re-completion, the well tested at production rates
in excess of 700 Mcf/d. Extensive injectivity analysis and testing of the lower
`Detrital' disposal zone indicates that up to 2200 Bw/d can be injected into the
interval. The well is currently waiting on power supply and pipeline hookup
prior to product sales. An offset wellbore (Princess #6-10) is currently being
permitted for re-entry based on initial results from the #10-9 well. Numerous
other prospects are being leased and permitted at this time.
The Company owns a 25% working interest in the Blue River Joint Venture
covering approximately 16 million acres. Initial investigation within the Joint
Venture AMI indicates approximately 500+ wells that exhibit an appropriate
production type decline curve, potential disposal interval, and gas reservoir.
The company is currently undertaking detailed geologic and production analysis
to refine certain areas and develop prospects for recompletion.
Property Impairment
During the quarter ended February 29, 2004, the Company recognized no
impairment of its 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, Company management had completed a comprehensive evaluation of
its capitalized oil and gas properties for purposes of determining impaired
properties and recognized an impairment charge of approximately $3,234,000 for
the year then ended.
East Lost Hills, San Joaquin Basin, California
During our quarter ended February 29, 2004 and fiscal year ended August 31,
2003, 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. The Company has written off
its entire investment in this project.
Berkley Petroleum Inc., a wholly owned subsidiary of Anadarko Petroleum
Corporation, the operator at East Lost Hills, has informed the participant group
that it does not intend to participate in additional operations at East Lost
Hills. Significant portions of the leaseholds in the project have expired or
will expire in the near future.
15
We have continued to evaluate our ongoing participation in the East Lost
Hills project. Although we do not believe that there has been adequate
evaluation of the Temblor potential at East Lost Hills, the historical cost
structure of operations and the ongoing uncertainties make it very difficult to
continue to participate in this project. We will seek to limit capital
expenditures at East Lost Hills until there occurs a point in time as many of
the ongoing problems associated with the play are mitigated. There is no
assurance that any such mitigation of problems or any additional operations will
occur at East Lost Hills. If additional operations are proposed, we will
carefully evaluate to what extent, if any, we will participate in those
operations.
The ELH #4 well was drilled and completed to a depth of approximately
20,500 feet. Although the well flowed natural gas and liquid hydrocarbons upon
initial production testing, we believe that mechanical difficulties related to
the influx of wellbore debris have prevented an adequate and full evaluation of
the reservoir potential. During initial production testing of the ELH #4, coil
tubing was used to attempt to clean out debris in the wellbore. During these
clean-out operations, a portion of the coil tubing separated and became stuck in
the wellbore. Retrieval operations have not been initiated, and it is uncertain
whether the coil tubing can be removed from the wellbore. The well is currently
shut-in. Although the participant group has not approved or consented, the
operator has formally proposed to plug and abandon the well.
The ELH #9 well was drilled and completed to a depth of approximately
20,100 feet. Initially, the well was production tested in the Kreyenhagen shale
underlying the Temblor formation. Non-commercial hydrocarbons were encountered
and tested from this zone, and the participants agreed to move up-hole and test
the lower Temblor section. These zones were perforated by wireline and limited
production of hydrocarbons was encountered. We believe that the perforation and
testing methodology may have been inadequate to fully evaluate the reservoir
potential and that the production results are inconclusive. This well is
currently shut-in. Although the participant group has not approved or consented,
the operator has formally proposed to plug and abandon the well.
The third well, the AERA Energy LLC #1-22 NWLH, located approximately 3.5
miles northwest of the ELH #1 well, was drilled to a total depth of 20,457 feet.
The well encountered hydrocarbon shows and gas flow from several zones in the
Temblor, and casing has been installed in preparation for production testing. We
have determined to prioritize our financial resources on other prospects, and
have elected to non-consent to the completion and production testing operations.
We participated in the drilling of this well through a pooling arrangement at a
4.04% working interest.
Results of Operations
The quarter ended February 29, 2004 compared with the quarter ended
February 28, 2003.
Operations during the quarter ended February 29, 2004 resulted in a net
loss of $401,858 compared with a net loss of $1,087,836 for the quarter ended
February 28, 2003. The decrease in net loss is due primarily to impairment
charges in the prior year totaling approximately $699,000, as opposed to the
current year, during which no impairment was charged. A broader discussion of
these and other items are presented below.
Oil and Gas Revenues and Expenses. During the quarter ended February 29,
2004, we recorded $32,782 from the sale of 7,113 Mcf of natural gas for an
average price of $4.61 per Mcf and $11,594 from the sale of 398 bbls of
hydrocarbon liquids for an average price of $29.13 per barrel. Lease operating
expenses during this period were $21,681. During the quarter ended February 28,
2003, we recorded $35,733 from the sale of 8,163 Mcf of natural gas for an
average price of $4.38 per Mcf and $10,761 from the sale of 381 bbls of
hydrocarbon liquids for an average price of $28.24 per barrel. Lease operating
expenses during this period were $25,308.
16
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the quarters
ended February 29, 2004 and February 28, 2003. Although the East Lost Hills #1
has produced continuously since 2001, we have previously recorded an impairment
against our entire amortizable full cost pool, and therefore had no costs to
amortize. We recorded $3,983 and $2,786 in depreciation expense associated with
capitalized office furniture and equipment during the quarters ended February
29, 2004 and February 28, 2003, respectively. Additionally, we recorded $37,821
of depreciation of Asset Retirement Obligation assets, and $21,152 of accretion
of the unamortized discount of the Asset Retirement Obligation liability.
Dry Hole, Impairment and Abandonments. During the quarter ended February
29, 2004, we recorded no impairment expense, compared to $698,599 of impairment
expense for the quarter ended February 28, 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 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 $285,442 and $345,237 in
general and administrative expenses during the quarters ended February 29, 2004
and February 28, 2003, respectively. The decrease principally reflects fewer
employees in 2004, as well as a decrease in funding and acquisition costs.
Interest Expense. We incurred $81,196 and $76,489 in interest expense for
the quarters ended February 29, 2004 and February 28, 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 six months ended February 29, 2004 compared with the six months ended
February 28, 2003.
Oil and Gas Revenues and Expenses. During the six months ended February 29,
2004, we recorded $63,500 from the sale of 14,600 Mcf of natural gas for an
average price of $4.35 per Mcf and $20,894 from the sale of 799 bbls of
hydrocarbon liquids for an average price of $26.15 per barrel. Lease operating
expenses during this period were $36,952. During the six months ended February
28, 2003, we recorded $72,623 from the sale of 19,110 Mcf of natural gas for an
average price of $3.80 per Mcf and $21,415 from the sale of 833 bbls of
hydrocarbon liquids for an average price of $25.71 per barrel. Lease operating
expenses during this period were $46,345.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the six
months ended February 29, 2004, and February 28, 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 $6,282 and $5,872 in depreciation expense
associated with capitalized office furniture and equipment during the six months
ended February 29, 2004 and February 28, 2003, respectively. Additionally, we
recorded $75,642 of depreciation of Asset Retirement Obligation assets, and
$42,304 of accretion of the unamortized discount of the Asset Retirement
Obligation liability.
Dry Hole, Impairment and Abandonments. During the six months ended February
29, 2004, we recorded no impairment expense, compared to $1,178,267 of
impairment expense for the six months ended February 28, 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 which there is no assurance, any
additional costs associated with these properties are capitalized, and then
charged to impairment expense as incurred.
17
General and Administrative Expense. We incurred $536,932 and $670,543 in
general and administrative expenses during the six months ended February 29,
2004 and February 28, 2003, respectively. The decrease principally reflects
fewer employees in 2004, as well as a decrease in funding and acquisition costs.
Interest Expense. We incurred $160,550 and $152,055 in interest expense for
the six months ended February 29, 2004 and February 28, 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 six months ended February 29, 2004 compared to the six months ended
February 28, 2003
Cash Flows From Operating Activities
Net loss. See discussion of net loss in Results of Operations section
above.
Depreciation and amortization. Depreciation expense increased to $124,228
for the six months ended February 29, 2004, compared to $5,872 for the six
months ended February 28, 2003. The 2004 expense reflects depreciation of Asset
Retirement Obligation assets of $75,642 and $42,304 of accretion of unamortized
discount of the Asset Retirement Obligation liability, neither of which were
recognized in 2003.
Impairment, dry hole and abandonments. During the six months ended February
29, 2004, we recorded no impairment expense as compared to $1,178,267 during the
six months ended February 28, 2003. The 2003 impairment related principally to
costs incurred to drill and complete wells in the East Lost Hills project. There
were no such costs incurred in 2004.
Accrued interest converted into debt. For the six months ended February 29,
2004, accrued interest converted into debt was $158,577 compared to $71,487 for
the six months ended February 28, 2003. Both amounts reflect interest accrued on
the $6,000,000 convertible notes issued May 24, 2002.
Prepaid expenses. During the six months ended February 29, 2004 and
February 28, 2003, prepaid expenses increased $55,957 and $47,340, respectively.
The increase reflects higher director and officer liability insurance premiums.
Accounts payable and accruals. During the six months ended February 29,
2004, accounts payable and accruals decreased $105,932, principally reflecting
decreased amounts due to the operator of the East Lost Hills wells. During the
six months ended February 28, 2003, accounts payable and accruals increased
$429,114, reflecting increased 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 six months ended February
29, 2004, the Company paid $238,200 of costs incurred on exploration projects in
California and the Rocky Mountain region, compared to $986,569 paid during the
six months ended February 28, 2003. The decrease relates principally to higher
costs paid on the East Lost Hills project in fiscal year 2003.
Deferred acquisition costs. During the six months ended February 29, 2004,
the Company placed $250,000 in an escrow account in connection with our
agreement to acquire substantially all of the assets of Venus Exploration,
Incorporated. There were no deferred acquisition costs in the six months ended
February 28, 2003.
Critical Accounting Policies And Estimates
We believe the following critical accounting policies affect our more
significant judgments and estimates used in the preparation of our Financial
Statements.
18
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 in the Company's
case, where there are no proved reserves, it would be the estimated market value
of the Company's unproved properties. The Company performs 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 the Company's
holdings and the Company's near term intent to develop such properties. Gains or
losses upon disposition of or impairment of the Company's unproved oil and gas
properties are recorded in the statement of operations as the Company has no
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.
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. The Corporation classifies these
assets as a component of oil and gas properties in accordance with its
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.
The Company did not change or reclassify contractual mineral rights
included in oil and gas properties on the balance sheet upon adoption of SFAS
No. 141. The Company believes its 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 February 29, 2004 would be approximately $4,059,000 and the reclassified
amount as of August 31, 2003 (the end of the Company's 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 the Company's
cash flows, results of operations or financial condition.
ITEM 3. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, the Company conducted
an evaluation under the supervision and with the participation of the principal
executive officer and principal financial officer, of the Company's disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
19
Securities Exchange Act of 1934 (the "Exchange Act")). Based on this evaluation,
the principal executive officer and principal financial officer concluded that
the Company's disclosure controls and procedures are effective to ensure that
information required to be disclosed by the Company in reports that it files or
submits under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission rules
and forms. There was no change in the Company's internal controls over financial
reporting during the Company's most recently completed fiscal quarter that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting.
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings
Not Applicable
Item 2. Changes in Securities and Use of Proceeds; Recent Sales Of
Unregistered Securities
None
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
Previously reported.
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 Chief
Financial Officer
32 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
(b) During the quarter ended February 29, 2004, we filed five reports Form
8-K:
December 12, 2003
December 18, 2003 (Form 8-K/A-1)
December 15, 2003
January 21, 2004
January 14, 2004
Following the quarter ended February 29, 2004, we filed
reports on Form 8-K for events occurring on the following
dates:
March 18, 2004
April 5, 2004
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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 April 13, 2004
---------------------------- Officer and Principal
D. Scott Singdahlsen Financial Officer
21