U.S. Securities And Exchange Commission
Washington, D.C. 20549
FORM 10-QSB
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended November 30, 2003
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from _____________ to ______________
Commission File No. 001-15511
PYR ENERGY CORPORATION
----------------------
(Exact name of small business issuer as specified in its charter)
Maryland 95-4580642
-------- ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1675 Broadway, Suite 2450, Denver, CO 80202
------------------------------------- -----
(Address of principal executive offices) (Zip Code)
Issuer's telephone number, including area code (303) 825-3748
Check whether the issuer (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes X No ___
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes ___ No X
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
The number of shares outstanding of each of the issuer's classes of common
equity as of November 30, 2003 is as follows:
$.001 Par Value Common Stock 23,701,357
----------
PYR ENERGY CORPORATION
FORM 10-QSB
INDEX
PART I. FINANCIAL INFORMATION.......................................................3
Item 1. Financial Statements........................................................3
Balance Sheets - November 30, 2003 (Unaudited) and August 31, 2003..........3
Statements of Operations - Three Months Ended November 30, 2003 and
November 30, 2002 and Cumulative Amounts From Inception Through
November 30, 2003 (Unaudited)...............................................4
Statements of Cash Flows - Three Months Ended November 30, 2003 and
November 30, 2002 and Cumulative Amounts From Inception Through
November 30, 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....................................................17
PART II. OTHER INFORMATION..........................................................17
Item 1. Legal Proceedings..........................................................17
Item 2. Changes in Securities and Use of Proceeds; Recent Sales Of Unregistered
Securities.................................................................17
Item 3. Defaults Upon Senior Securities............................................17
Item 4. Submission of Matters to a Vote of Security Holders........................17
Item 5. Other Information..........................................................17
Item 6. Exhibits and Reports on Form 8-K...........................................17
Signatures...........................................................................18
2
PART I
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
(A Development Stage Company)
BALANCE SHEETS
ASSETS
November 30, August 31,
2003 2003
------------ ------------
(Unaudited)
CURRENT ASSETS
Cash $ 3,114,283 $ 3,657,938
Deposits and prepaid expenses 125,243 46,559
------------ ------------
Total Current Assets 3,239,526 3,704,497
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 27,014 29,313
Oil and gas properties, net 5,486,295 5,287,837
------------ ------------
5,513,309 5,317,150
------------ ------------
OTHER ASSETS
Deferred financing costs and other assets 67,460 68,257
------------ ------------
67,460 68,257
------------ ------------
$ 8,820,295 $ 9,089,904
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 222,261 $ 309,795
Asset Retirement Obligation 727,231 727,231
------------ ------------
Total Current Liabilities 949,492 1,037,026
------------ ------------
LONG TERM LIABILITIES
Convertible Notes 6,462,552 6,303,975
Asset retirement obligation 140,013 118,861
------------ ------------
Total Long Term Liabilities 6,602,565 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 (34,163,120) (33,801,318)
------------ ------------
1,268,238 1,630,041
------------ ------------
8,820,295 $ 9,089,904
============ ============
3
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF OPERATIONS
Cumulative from
Three Months Three Months Inception
Ended Ended Through
November 30, November 30, November 30,
2003 2002 2003
------------ ------------ ------------
REVENUES
Oil and gas revenues $ 40,018 $ 47,544 $ 1,569,732
------------ ------------ ------------
40,018 47,544 1,569,732
------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 15,271 21,037 304,007
Impairment, dry hole, and abandonments -- 479,668 28,818,139
Depreciation and amortization 61,272 3,086 399,266
General and administrative 251,490 325,306 6,811,826
------------ ------------
328,033 829,097 36,333,238
LOSS FROM OPERATIONS (288,015) (781,553) (34,763,506)
OTHER INCOME (EXPENSE)
Interest income 5,567 20,746 950,714
Other income -- 127,528
Interest (expense) (79,354) (75,566) (657,010)
Gain on sale of oil and gas prospects -- -- 556,197
------------ ------------ ------------
(73,787) (54,820) 977,429
LOSS BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE (361,802) (836,373) (33,786,077)
Cumulative effect of change in accounting
principle (341,175)
------------ ------------ ------------
(361,802) (836,373) (34,127,252)
INCOME APPLICABLE TO
PREDECESSOR LLC -- -- (35,868)
------------ ------------ ------------
NET LOSS (361,802) (836,373) (34,163,120)
Less dividends on preferred stock -- -- (292,411)
------------ ------------ ------------
NET LOSS TO COMMON STOCKHOLDERS $ (361,802) $ (836,373) $(34,455,531)
============ ============ ============
NET LOSS PER COMMON
SHARE -BASIC AND DILUTED (0.02) (0.04) (2.21)
============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 23,701,357 23,701,357 15,562,642
============ ============ ============
4
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Cumulative from
Three Months Three Months Inception
Ended Ended Through
November 30, November 30, November 30,
2003 2002 2003
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $ (361,802) $ (836,373) $(34,127,252)
Adjustments to reconcile net loss to
net cash used by operating activities
Cumulative effect of change in accounting principle -- 341,175
Depreciation and amortization 61,272 3,086 399,267
Contributed services -- 36,000
Gain on sale of oil and gas prospects -- (556,197)
Impairment, dry hole and abandonments -- 479,668 28,818,139
Common stock issued for interest on debt -- 136,822
Common stock issued for services --
Warrants issued for services 178,665
Amortization of financing costs 797 796 31,790
Amortization of marketable securities -- (20,263)
Accrued interest converted into debt 158,577 151,751 462,552
Changes in assets and liabilities --
Decrease (Increase) in accounts receivable -- (566)
(Increase) decrease in prepaids (78,684) (70,683) (129,796)
(Decrease) increase in accounts payable, accruals (47,426) 242,153 (1,163,607)
Other -- (38,721)
------------ ------------ ------------
Net cash used by operating activities (267,266) (29,602) (5,631,992)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment -- -- (138,466)
Cash paid for oil and gas properties (276,389) (747,293) (32,759,030)
Proceeds from sale of oil and gas properties 1,300,078
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 -- -- --
------------ ------------ ------------
Net cash used in investing activities (276,389) (747,293) (31,605,550)
------------ ------------ ------------
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 (543,655) (776,895) 3,114,283
CASH, BEGINNING OF PERIODS 3,657,938 6,516,086 --
------------ ------------ ------------
CASH, END OF PERIODS $ 3,114,283 $ 5,739,191 $ 3,114,283
============ ============ ============
5
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
November 30, 2003
The accompanying interim financial statements of PYR Energy Corporation are
unaudited. In the opinion of management, the interim data includes all
adjustments, consisting only of normal recurring adjustments, necessary for a
fair presentation of the results for the interim period. The results of
operations for the three months ended November 30, 2003 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-K 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.
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 November 30, 2003, there were no cash
equivalents.
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.
6
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 November 30, 2003 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 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 November 30, 2003 would be approximately $4,539,000 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.
7
INCOME TAXES - We have adopted the provisions of SFAS No. 109, "Accounting
for Income Taxes". SFAS 109 requires recognition of deferred tax liabilities and
assets for the expected future tax consequences of events that have been
included in the financial statements or tax returns. Under this method, deferred
tax liabilities and assets are determined based on the difference between the
financial statement and tax basis of assets and liabilities using enacted tax
rates in effect for the year in which the differences are expected to reverse.
ASSET RETIREMENT OBLIGATIONS - In 2001, the FASB issued SFAS 143,
"Accounting for Asset Retirement Obligations." SFAS 143 addresses financial
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs. This
statement requires companies to record the present value of obligations
associated with the retirement of tangible long-lived assets in the period in
which it is incurred. The liability is capitalized as part of the related
long-lived asset's carrying amount. Over time, accretion of the liability is
recognized as an operating expense and the capitalized cost is depreciated over
the expected useful life of the related asset. The Company's asset retirement
obligations relate primarily to the plugging, dismantlement, removal, site
reclamation and similar activities of its oil and gas properties. Prior to
adoption of this statement, such obligations were accrued ratably over the
productive lives of the assets through 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 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 November 30, 2003 the asset
retirement obligation net asset balance, after depreciation, was $151,025, and
the total asset retirement obligation liability, after accretion of unamortized
discount, was $867,244.
STOCK OPTION COMPENSATION - The Company has elected to follow APB Opinion
No. 25 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 Statement of Financial Accounting Standards (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 expenses are
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
November 30, November 30,
2003 2002
------------ ------------
Net loss as reported $ (361,802) $ (836,373)
Deduct: stock based compensation
Cost under SFAS 123 (132,620) --
------------ ------------
Pro forma net income (494,422) (836,373)
============ ============
Pro forma basic and diluted net income per
share: -- --
Pro forma shares used in the calculation of
pro forma net income per common share
basic and diluted 23,701,357 23,701,357
Reported net income per common share -
basic and diluted $ (0.02) $ (0.04)
Pro forma net income per common share
basic and diluted $ (0.02) $ (0.04)
Pro forma information regarding net income is required by SFAS 123. Options
granted were estimated using the Black-Scholes valuation model. The following
weighted average assumptions were used for the three months ended November 30,
2003.
Volatility 107%
Expected life of options (in years) 5-7
Dividend Yield 0.00%
Risk free interest rate 3%
NOTE 2 - 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 November 30, 2003, the aggregate balance of these notes, reflected as
Convertible Notes under Long Term Debt, was $6,462,552.
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.
9
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, currently as a non-operator, sharing both risk and rewards with
our partners. Our financial results depend on our ability to sell prospect
interests to outside industry participants. We will not be able to commence
exploratory drilling operations without outside industry participation. We have
pursued, and will continue to pursue, exploration opportunities in regions where
we believe significant opportunity for discovery of oil and gas 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 November 30, 2003, we had approximately $2,290,000 in working capital.
During the quarter ended November 30, 2003, capitalized costs for oil and
gas properties increased by approximately $198,000. This increase reflects net
costs incurred for drilling and completion, geological and geophysical costs,
delay rentals and other related direct costs with respect to our exploration and
development prospects, of approximately $236,000, less depreciation of asset
retirement obligation assets of approximately $38,000. 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.
During the quarter ended November 30, 2002, capitalized costs for oil and
gas properties increased by approximately $214,000. This increase reflects net
costs incurred for drilling and completion, geological and geophysical costs,
delay rentals and other related direct costs with respect to our exploration and
development prospects, of $694,000. This increase was offset by impairment taken
against such oil and gas properties in the approximate amount of $480,000.
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
10
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 November 30, 2003, we incurred approximately
$236,000 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 quarter ended November 30, 2003 were $40,018.
During the quarter ended November 30, 2002, we incurred approximately
$421,000 for costs relating to drilling and completing wells at our East Lost
Hills Project. We incurred approximately $273,000 for costs related to our other
exploration projects including continued acreage lease obligations and
associated geological and geophysical costs. Revenues from oil and gas
production during the quarter ended November 30, 2002 were $47,544.
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 November 30, 2003:
Payments Due By Period
-----------------------------------------------------------
Year Ended Fiscal Fiscal Fiscal
Contractual August 31, Years Years Years 2010
Obligations Total 2004 2005-2007 2008-2009 and After
----------- ----- ---- --------- --------- ---------
Convertible Notes $8,474,313 $-0- $-0- $8,474,313 $-0-
Office Lease 97,723 97,723 -0- -0- $-0-
---------- ---------- ---- ---------- ----
Total Contractual
Cash Obligations $8,572,036 $ 97,723 -0- $8,474,313 $-0-
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
11
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:
Exploration Of Overthrust Properties
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 agreement calls for an initial well
to be drilled to test the Cumberland Prospect in section 16, T18N, R118W.
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 early in calendar 2004. 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 6233 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 its 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 4160 net acres of leasehold within the Greater Duck AMI. 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.
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.
12
Property Impairment
During the quarter ended November 30, 2003, 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 November 30, 2003 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.
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.
13
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 November 30, 2003 compared with the quarter ended
November 30, 2002.
Operations during the quarter ended November 30, 2003 resulted in a net
loss of $361,802 compared with a net loss of $836,373 for the quarter ended
November 30, 2002. The decrease in net loss is reflects the lack of a charge for
impairment of oil and gas properties in 2003 compared to $480,000 of impairment
expense recognized in 2002. A broader discussion of these and other items are
presented below.
Oil and Gas Revenues and Expenses. During the quarter ended November 30,
2003, we recorded $30,717 from the sale of 7,487 mcf of natural gas for an
average price of $4.10 per mcf and $9,301 from the sale of 402 bbls of
hydrocarbon liquids for an average price of $23.13 per barrel. Lease operating
expenses during this period were $15,271. During the quarter ended November 30,
2002, we recorded $36,890 from the sale of 10,947 mcf of natural gas for an
average price of $3.37 per mcf and $10,654 from the sale of 452 bbls of
hydrocarbon liquids for an average price of $23.57 per barrel. Lease operating
expenses during this period were $21,037.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the quarters
ended November 30, 2003 and November 30, 2002. 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 $2,299 and $3,086 in depreciation expense associated with
capitalized office furniture and equipment during the quarters ended November
30, 2003 and November 30, 2002, respectively. Included in depreciation expense
reported for 2003, is $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 November
30, 2003 we recorded no impairment expense, compared to $479,668 of impairment
expense for the quarter ended November 30, 2002. 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 $251,490 and $325,306 in
general and administrative expenses during the quarters ended November 30, 2003
and November 30, 2002, respectively. The decrease principally reflects lower
salaries and wages in 2003 following staff resignations.
Interest Expense. We incurred $79,354 and $75,566 in interest expense for
the quarters ended November 30, 2003 and November 30, 2002, respectively. The
interest expense for each year is associated with the May 24, 2002 sale of
outstanding convertible notes due on May 24, 2009.
14
Cash Flow
The quarter ended November 30, 2003 compared to the quarter ended November
30, 2002
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 $61,272
for the quarter ended November 30, 2003, compared to $3,068 for the quarter
ended November 30, 2002. The 2003 expense reflects depreciation of Asset
Retirement Obligation assets of $37,821 and $21,152 of accretion of unamortized
discount of the Asset Retirement Obligation liability, neither of which were
recognized in 2002.
Impairment, dry hole and abandonments. During the quarter ended November
30, 2003, the company recorded no impairment expense as compared to $479,668
during the quarter ended November 30, 2002. The 2002 impairment related
principally to costs incurred to drill and complete wells in the East Lost Hills
project. There were no such costs incurred in 2003.
Accrued interest converted into debt. For the quarter ended November 30,
2003 accrued interest converted into debt was $158,577 compared to $151,751 for
the quarter ended November 30, 2002. Both amounts reflect interest accrued on
the $6,000,000 convertible notes issued May 24, 2002.
Prepaid expenses. Prepaid expenses increase $78,684 in the quarter ended
November 30, 2003 compared to an increase of $70,683 for the quarter ended
November 30, 2002. The increases in both periods reflect the payment of
Directors and Officers Liability Insurance premiums during the quarters.
Accounts payable and accruals. During the quarter ended November 30, 2003,
accounts payable and accruals decreased $47,426, principally reflecting the
conversion of accrued interest expense to debt. During the quarter ended
November 30, 2002, accounts payable and accruals increased $322,417 reflecting
increased amounts due to the operator of the East Lost Hills project for costs
to drill and complete wells in the project.
Cash Flows From Investing Activities
Cash paid for oil and gas properties. During the quarter ended November 30,
2003 the Company paid $276,389 of costs incurred on exploration projects in
California and the Rocky Mountain region, compared to $747,293 paid during the
quarter ended November 30, 2002. The decrease relates principally to costs paid
on the East Lost Hills project in 2002, not incurred or paid in 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.
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
15
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 November 30, 2003 would be approximately $4,539,000 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.
In June 2003, the FASB approved SFAS 150, "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity". SFAS 150
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity. This
Statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise is effective at the beginning of the first interim
period beginning after June 15, 2003. SFAS 150 is not expected to have an effect
on the Company's financial position.
16
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
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 November 30, 2003, we did not file any
Current Reports on Form 8-K. Following the quarter ended November
30, 2003, we filed reports on Form 8-K for events occurring on
the following dates:
December 15, 2003
December 11, 2003
17
SIGNATURES
----------
In accordance with the requirements of the Exchange Act, the Registrant has
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Signatures Title Date
---------- ----- ----
/s/ D. Scott Singdahlsen President, Chief Executive Officer January 20, 2004
------------------------ and Principal Financial Officer
D. Scott Singdahlsen
18