U.S. Securities And Exchange Commission
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended May 31, 2002
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. 0-20879
PYR ENERGY CORPORATION
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(Exact name of registrant as specified in its charter)
Maryland 95-4580642
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(State or 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)
Registrant's telephone number, including area code (303) 825-3748
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Check whether the issuer (1) 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 ___ No___
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
The number of shares outstanding of each of the issuer's classes of common
equity as of July 15, 2002 is as follows:
$.001 Par Value Common Stock 23,701,357
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PYR ENERGY CORPORATION
FORM 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements................................. 3
Balance Sheets - May 31, 2002 (Unaudited)
and August 31, 2001.................................. 3
Statements of Operations - Three Months and
Nine Months Ended May 31, 2002 and May 31, 2001
and Cumulative Amounts
From Inception Through May 31, 2002 (Unaudited)...... 4
Statements of Cash Flows - Nine Months Ended
May 31, 2002 and May 31, 2001 and
Cumulative Amounts
From Inception Through May 31, 2002 (Unaudited)...... 5
Notes to Financial Statements........................ 6
Item 2. Management's Discussion and Analysis
of Financial Condition and
Results of Operations....................... 7
Item 3. Quantitative and Qualitative Disclosures
about Market Risk..................................... 13
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.................................... 13
Item 2. Changes in Securities and Use of Proceeds;
Recent Sales of Unregistered Securities.............. 13
Item 3. Defaults Upon Senior Securities...................... 13
Item 4. Submission of Matters to a Vote of Security Holders.. 13
Item 5. Other Information.................................... 13
Item 6. Exhibits and Reports on Form 8-K..................... 14
Signatures.................................................... 14
2
PART I
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
(A Development Stage Company)
BALANCE SHEETS
ASSETS
5/31/02 8/31/01
(UNAUDITED)
CURRENT ASSETS
Cash $ 7,632,128 $ 9,800,842
Oil and gas receivables -- 1,173,751
Deposits and prepaid expenses 65,789 71,358
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Total Current Assets 7,697,917 11,045,951
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PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 37,931 40,638
Oil and gas properties, net 16,250,558 10,977,317
Prepaid oil and gas capital costs 1,437,403 --
------------ ------------
17,725,892 11,017,955
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OTHER ASSETS
Deposits 3,278 3,278
Deferred financing costs 21,081 --
------------ ------------
24,359 3,278
------------ ------------
------------ ------------
$ 25,448,168 $ 22,067,184
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 582,338 $ 2,263,368
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Total Current Liabilities 582,338 2,263,368
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CONVERTIBLE NOTES 6,000,000 --
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STOCKHOLDERS' EQUITY
Common stock, $.001 par value
Authorized 75,000,000 shares
Issued and outstanding - 23,691,357 shares 23,691 23,691
Capital in excess of par value 35,214,002 35,214,002
Deficit accumulated during the development stage (16,371,863) (15,433,877)
------------ ------------
18,865,830 19,803,816
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$ 25,448,168 $ 22,067,184
============ ============
3
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Three Nine Nine Cumulative from
Months Months Months Months Inception
Ended Ended Ended Ended Through
5/31/02 5/31/01 5/31/02 5/31/01 5/31/02
REVENUES
Oil and gas revenues $ 38,510 $ 822,993 $ 110,822 $ 1,075,353 $ 1,312,801
Interest 23,577 142,162 118,743 310,496 864,725
Other -- -- -- -- 127,528
------------ ------------ ------------ ------------ ------------
62,087 965,155 229,565 1,385,849 2,305,054
------------ ------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 28,808 78,005 60,769 81,057 162,787
Impairment, dry hole, and abandonments 0 -- 113,544 -- 13,974,824
General and administrative 323,474 370,021 975,759 955,068 4,773,854
Depreciation and amortization 3,691 57,928 10,917 82,904 94,913
Interest 6,562 -- 6,562 -- 190,868
------------ ------------ ------------ ------------ ------------
362,535 505,954 1,167,551 1,119,029 19,197,246
------------ ------------ ------------ ------------ ------------
OTHER INCOME
Gain on sale of oil and gas prospects -- -- -- -- 556,197
------------ ------------ ------------ ------------ ------------
(300,448) 459,201 (937,986) 266,820 (16,335,995)
INCOME APPLICABLE TO
PREDECESSOR LLC -- -- -- -- (35,868)
------------ ------------ ------------ ------------ ------------
NET (LOSS) INCOME (300,448) 459,201 (937,986) 266,820 (16,371,863)
Less dividends on preferred stock -- -- -- (62,899) (292,411)
------------ ------------ ------------ ------------ ------------
NET (LOSS) INCOME TO
COMMON STOCKHOLDERS $ (300,448) $ 459,201 $ (937,986) $ 203,921 $(16,664,274)
============ ============ ============ ============ ============
NET (LOSS) INCOME PER COMMON
SHARE - BASIC AND DILUTED $ (0.01) $ 0.02 $ (0.04) $ 0.01 $ (1.23)
============ ============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 23,691,357 23,512,581 23,691,357 21,704,133 13,528,445
============ ============ ============ ============ ============
4
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Nine Months Cumulative Amounts
Ended Ended from Inception
5/31/02 5/31/01 Through 5/31/02
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income $ (937,986) $ 266,820 $(16,335,995)
Adjustments to reconcile net (loss) income to
net cash (used) by operating activities
Depreciation and amortization 10,917 82,904 95,278
Contributed services -- -- 36,000
Gain on sale of oil and gas prospects -- -- (556,197)
Impairment, dry hole and abandonments 113,544 -- 13,974,824
Common stock issued for interest on debt -- -- 116,822
Common stock issued for services -- -- 20,000
Amortization of financing costs -- -- 26,939
Amortization of marketable securities -- -- (20,263)
Changes in assets and liabilities
(Increase) in accounts receivable -- (1,061,022) (1,174,317)
(Increase) decrease in prepaids 5,568 (63,307) (73,619)
Increase in accounts payable, accruals 412,281 1,341,922 494,187
Other 3,447 1,888 11,278
------------ ------------ ------------
Net cash (used) provided by operating activities (392,229) 569,205 (3,385,063)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (11,293) (30,972) (132,205)
Cash paid for oil and gas properties (6,327,789) (9,724,786) (28,814,284)
Prepaid oil and gas capital costs (1,437,403) -- (1,437,403)
Proceeds from sale of oil and gas properties -- -- 1,050,078
Cash paid for marketable securities -- -- (5,090,799)
Proceeds from sale of marketable securities -- -- 5,111,062
Cash received (paid) for reimbursable property costs -- -- (28,395)
------------ ------------ ------------
Net cash (used) in investing activities (7,776,485) (9,755,758) (29,341,946)
------------ ------------ ------------
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 -- 11,600,000 30,788,750
Proceeds from sale of convertible debt 6,000,000 -- 8,500,001
Proceeds from exercise of warrants -- 1,557,165 2,011,073
Proceeds from exercise of options -- 152,906 189,530
Cash paid for offering costs -- (160,470) (1,036,448)
Payments on capital lease -- (920) (5,195)
Preferred dividends paid -- -- (50,910)
------------ ------------ ------------
Net cash provided by financing activities 6,000,000 13,148,681 40,359,137
------------ ------------ ------------
NET (DECREASE) INCREASE IN CASH (2,168,714) 3,962,128 7,632,128
CASH, BEGINNING OF PERIODS 9,800,842 8,598,016 --
------------ ------------ ------------
CASH, END OF PERIODS $ 7,632,128 $ 12,560,144 $ 7,632,128
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5
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
May 31, 2002
The accompanying interim financial statements of PYR Energy Corporation are
unaudited. In the opinion of management, the interim data includes all
adjustments, consisting only of normal recurring adjustments, necessary for a
fair presentation of the results for the interim period. The results of
operations for the periods ended May 31, 2002 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, 2001.
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 May 31, 2002, 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.
OIL AND GAS PROPERTIES - 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
6
from depletable costs until such properties are evaluated as either proved or
unproved. The net capitalized costs are subject to a ceiling limitation. Gains
or losses upon disposition of oil and gas properties are treated as adjustments
to capitalized costs, unless the disposition represents a significant portion of
the Company's proved reserves.
Unevaluated oil and gas properties consists of ongoing exploratory drilling
costs, for which no results have been obtained, and of leases and acreage that
we acquire for our exploration and development activities. The cost of these
non-producing leases is recorded at the lower of cost or fair market value.
We have adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long Lived Assets to Be Disposed of", which requires that
long-lived assets to be held and used be reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount of an asset may
not be recoverable. During the fiscal year ended August 31, 2001, we earned our
initial revenues from our oil and gas producing activities. A reserve report
prepared as of August 31, 2001 by an independent petroleum engineering firm
concluded that based on information available at that time, reserves from our
producing properties were not economic to produce. Therefore, at August 31,
2001, we had no proved reserves and recorded an impairment charge against the
entire net value of our evaluated properties of $13,339,911 based on the ceiling
test limitation. Although properties may be considered as 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, additional costs associated with these properties are charged
directly to impairment expense as incurred.
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.
NOTE 2 - ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE
During the quarter ended May 31, 2002, we agreed to allow the operator at
our East Lost Hills project to offset our share of net revenues from the ELH #1
well against amounts we owed to the operator for costs associated with the East
Lost Hills project. At May 31, 2002, a total of $1,204,594 representing net
revenues from February 6, 2001 through May 31, 2002 had been offset against
amounts due. In addition, we received certain credits against amounts due and
paid a total of $2,840,571 in order to bring our outstanding balance current
with the operator. At May 31, 2002, we reflected a balance due to the operator
of $342,115, all of which is considered current.
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 Section
3(b) and/or 4(2) of the Securities Act of 1933, as amended. We have reflected
the outstanding balance of these notes as Convertible Notes under Long Term Debt
on our May 31, 2002 balance sheet.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
ESULTS OF OPERATIONS
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. We may
operate projects in the future. Whether we participate in our projects as
operator or non-operator, our financial results depend on our ability to sell
prospect interests to outside industry participants. We do not have the
financial ability to commence exploratory drilling operations without outside
industry 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.
7
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.
We paid approximately $7,765,000 and $9,725,000 during the nine months
ended May 31, 2002 and 2001, respectively, for drilling costs, delay rentals,
acquisition of acreage, direct geological and geophysical costs, and other
related direct costs, with respect to our identified exploration and
exploitation projects.
We currently anticipate that we could participate in the drilling of one to
four exploration/development wells during the next 12 months, with the number of
wells subject to increase to the extent that additional projects are added to
our portfolio. However, there can be no assurance that any wells will be
drilled, or if drilled, that any of these wells will be successful.
It is anticipated that the future development of our business will require
additional, and possibly substantial, capital expenditures. Depending upon the
extent of success of our ability to sell additional prospects for cash, the
level of industry participation in our exploration projects, and the continuing
results at East Lost Hills and the deep Temblor exploration program, we
anticipate spending a minimum of approximately $5 million for capital
expenditures relating to exploration and development of our projects during the
next 12 months. To limit additional capital expenditures, we intend to form
industry alliances to exchange a 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 financing, or from sales of interests in our properties although there
is no assurance continued funding will be available.
At May 31, 2002, we had a working capital amount of approximately
$7,116,000. 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. We have
reflected the outstanding balance of these notes as Convertible Notes under Long
Term Debt on our May 31, 2002 balance sheet.
At May 31, 2002, we had not entered into any commodity swap arrangements or
hedging transactions. Although we have no current plans to do so, we may enter
into commodity swap and/or hedging transactions in the future in conjunction
with oil and gas production.
The following is a summary of the current status of the East Lost Hills
project in the San Joaquin Basin of California operated by Anadarko Petroleum
Corporation:
During the third quarter ended May 31, 2002, our only producing well, the
ELH #1, produced a gross total of approximately 130 mmcfe, averaging
approximately 1.5 mmcfe per day. Water production during this period averaged
approximately 6,200 barrels per day. The oil and gas production from the ELH #1
well continues to be limited by the amount of production water that is accepted
at water disposal facilities owned by ChevronTexaco. The operator has reported
to the participants that it is evaluating alternatives to the current water
disposal facilities including drilling a water disposal well. However, there is
no assurance that the drilling of a disposal well will occur, or if drilled,
that it will completely remove the water disposal constraint.
8
The ELH #4 well commenced drilling on November 26, 2000 at a location
approximately four miles southeast of the ELH #1 well. After a successful
sidetrack operation, this well was drilled to its total depth of approximately
20,500 feet. Final casing was run and a production liner has been installed.
During early July 2002, the Kreyenhagen and lower Temblor zones were perforated
in preparation for a production test. The well is flowing on clean up before
actual production flow testing begins. Upon completion of the production testing
and analysis, if the participants determine that this well is a commercially
viable well, a pipeline will need to be installed to connect to processing
facilities. We expect that water will need to be disposed of as a component of
the production, if any, and unless an alternative to the current water disposal
facilities is implemented, the well will be subject to similar water disposal
issues experienced at the ELH #1 well.
The ELH #9 well commenced drilling on July 17, 2001, approximately six
miles southeast of the ELH #1 well. This well has reached its total depth of
approximately 21,100 feet, and production testing commenced during late June
2002 in the Kreyenhagen. After preliminary flow testing, the participants have
agreed to attempt to perform an acid stimulation procedure in order to fully
evaluate this zone. Pending results of this test, the participants will
determine whether to attempt to produce the well from this zone or move up-hole
in order to test other potentially productive zones.
The Aera Energy LLC NWLH 1-22 well, located in Section 22, T25S-R20E,
commenced drilling on August 23, 2001. This well is approximately three and a
half miles northwest of the ELH #1 well and is designed to test the Temblor
formation to a projected depth of 20,000 feet. We are participating in this well
operated by Aera Energy LLC through a pooling arrangement at a 4.04% working
interest. Operations to kick-off a sidetrack well bore from a depth of 14,100
feet were successful. An intermediate string of casing has been run to
approximately 17,500 feet and drilling operations continue at an approximate
depth below 20,200 feet.
Additional San Joaquin Basin California activities include the following
projects:
Pyramid Power Prospect. In April 1999, we purchased a working interest in
the Pyramid Power deep natural gas exploration project in the San Joaquin Basin.
This project is outside the East Lost Hills joint venture area. Our working
interest in this project is 3.75%, with our interest being carried through the
tanks in the initial test well. The initial test well, operated by Anadarko and
located in Section 9, T25S-R18E, commenced drilling on November 22, 2001. This
well is designed to test the Temblor and the Point of Rocks formations. This
well is currently drilling at an approximate depth below 20,300 feet. The
participants at Pyramid Power jointly control approximately 20,000 gross and
15,000 net acres over the prospect.
Wedge Prospect. This is a seismic-generated Temblor prospect located
northwest of and adjacent to the East Lost Hills deep gas discovery. During the
first fiscal quarter of 2001, we acquired approximately 17 miles of proprietary,
high effort 2D seismic data and combined this data with existing 2D seismic data
in order to refine what we interpret as the up-dip extension of the East Lost
Hills structure. Our seismic interpretation shows that the same trend at East
Lost Hills extends approximately ten miles further northwest of the East Lost
Hills Area of Mutual Interest and can be encountered as much as 3,000 feet
higher. We currently control approximately 14,000 gross and approximately 13,000
net acres here. Our approach is to sell down our working interest and retain a
25% to 40% working interest in this prospect.
Bulldog Prospect. This project is a 2D seismic generated light oil and
natural gas prospect located adjacent to the giant Kettleman North Dome field in
the San Joaquin Basin. This prospect can be best characterized as a classic
footwall fault trap, similar to the many known footwall fault trap accumulations
that have produced significant quantities of hydrocarbons throughout the San
Joaquin basin. We currently control approximately 16,000 gross and approximately
15,000 net acres here. We are attempting to obtain industry participation to
drill a 14,000 foot test well, with the intent of retaining a 25% to 40% working
interest in this prospect.
9
Additional activities located in the Rocky Mountains include the following
projects:
Montana Foothills Project. This extensive natural gas exploration project,
located in northwestern Montana, is part of the southern Alberta basin, and has
been classified as the southern extension of the Alberta Foothills producing
province. The USGS and numerous Canadian industry sources have estimated
significant recoverable reserves for the Montana portion of the Foothills trend.
Based on extensive geologic and seismic analysis, we have identified numerous
structural culminations of similar size, geometry, and kinematic history as
prolific Canadian foothills fields, such as Waterton and Turner Valley.
The geologic setting and hydrocarbon potential of this area was not
recognized by industry until the early 1980s. At that time, a number of
companies initiated exploration efforts, including Exxon, Arco, Chevron, Amoco,
Conoco, and Unocal. This initial exploration phase culminated in a deep test by
Unocal in 1989. Although this well was unsuccessful, recent improvements in
seismic imaging and pre-stack processing have resulted in our belief that this
test well was drilled based upon a misleading seismic image and was located
significantly off-structure.
We currently control approximately 262,000 gross and 224,000 net acres in
this project and are currently presenting this project to potential industry
participants in order to sell down our working interest and generate exploratory
drilling activity. We anticipate retaining a working interest in this project of
between 20% and 40%.
Cumberland Project. The Cumberland project, located within the Overthrust
Belt of southwest Wyoming, is a gas-condensate exploration prospect in Uinta
County, Wyoming. Cumberland is at the northern end of the historically
productive Nugget trend on the hangingwall of the Absaroka thrust fault. The
prospect lies along trend of and just north of Ryckman Creek field, which was
discovered in 1975.
The Cumberland prospect can be best characterized as a classic hangingwall
anticlinal trap, similar to the many known Nugget sandstone accumulations that
have produced significant quantities of hydrocarbons from Pineview to Ryckman
Creek. The Cumberland culmination is the result of structural deformation
related to back-thrusting off of the Absaroka thrust, a similar geometry to that
exhibited at East Painter Reservoir field.
We currently control approximately 5,400 gross and net acres in the project
and are attempting to secure industry participation in the drilling of the
initial exploration test well in the prospect. We anticipate retaining a working
interest in this prospect of 25% to 40 %.
Mallard Project. The Mallard project, located within the Overthrust Belt of
SW Wyoming, is a sour gas and condensate exploration prospect in Uinta County,
Wyoming. Mallard is within the Paleozoic trend of productive fields on the
Absaroka thrust. Mallard directly offsets and is adjacent to the giant sour gas
field of Whitney Canyon-Carter Creek.
We interpret the Mallard prospect to occupy a separate fault block,
adjacent to the Whitney Canyon field, generated by a complex imbricated system
of faults spaying off of the Absaroka thrust. Paleozoic targets at the Mallard
prospect include the Mississippian Mission Canyon, as well as numerous secondary
objectives in the Ordovician, Pennsylvanian, and Permian sections.
We currently control approximately 3,900 gross and net acres in the
project. We continue to refine our geological and geophysical model for the
10
prospect, and will be presenting the project to potential industry partners for
joint participation in the drilling of an initial exploration test well. We
anticipate retaining a working interest in this project of between 25% and 40%.
Results of Operations
The quarter ended May 31, 2002 compared with the quarter ended May 31,
2001.
Operations during the quarter ended May 31, 2002 resulted in a net loss of
$300,448 compared to a net income of $459,201 for the quarter ended May 31,
2001. The operating net loss is due largely to a reduction in oil and gas
revenues from production at the East Lost Hills #1 well.
Oil and Gas Revenues and Expenses. For the quarter ended May 31, 2002, we
recorded $29,460 from the sale of 10,696 mcf of natural gas for an average price
of $2.75 per mcf and $8,426 from the sale of 434 bbls of hydrocarbon liquids for
an average price of $19.41 per barrel. In addition, we recorded overriding
royalty revenues of $624. Operating expenses during this period were $28,808.
For the quarter ended May 31, 2001, we recorded $738,004 from the sale of 57,376
mcf of natural gas for an average price of $12.86 per mcf and $84,989 from the
sale of 3,166 bbls of hydrocarbon liquids for an average price of $26.84 per
barrel. Operating expenses were $78,005 for this period.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the quarter
ended May 31, 2002. Although the East Lost Hills #1 began producing in February
2001, we recorded an impairment against our entire amortizable full cost pool on
August 31, 2001, and therefore have no costs to amortize. No additional
impairment was recorded against our oil and gas properties for the quarter ended
May 31, 2002. We recorded $52,391 in depreciation, depletion and amortization
from oil and gas properties for the quarter ended May 31, 2001. This amount was
computed using reserve report estimates based on the best information available
at the time. We recorded $3,691 and $5,537 in depreciation expense associated
with office furniture and equipment during the quarters ended May 31, 2002 and
May 31, 2001, respectively.
General and Administrative Expense. We incurred $323,474 and $370,021 in
general and administrative expenses during the quarters ended May 31, 2002 and
May 31, 2001, respectively. The decrease is due primarily to a reduction in
funding and acquisition costs in the current year. The decrease is offset
partially by an increase in salary related expenses from additional personnel
and higher salaries, and an increase in shareholder communications.
The nine months ended May 31, 2002 compared with the nine months ended May
31, 2001.
Oil and Gas Revenues and Expenses. For the nine months ended May 31, 2002,
we recorded $70,305 from the sale of 28,996 mcf of natural gas for an average
price of $2.42 per mcf and $23,568 from the sale of 1,347 bbls of hydrocarbon
liquids for an average price of $17.50 per barrel. In addition, we recorded
overriding royalty revenues of $16,949 dating back to the commencement of
production of the ELH #1 well. Operating expenses during this period were
$60,769. For the nine months ended May 31, 2001, we recorded $962,838 from the
sale of 75,177 mcf of natural gas for an average price of $12.81 per mcf and
$112,515 from the sale of 4,236 bbls of hydrocarbon liquids for an average price
of $26.56 per barrel. Operating expenses were $81,057 for this period.
Production commenced at the East Lost Hills #1 well on February 6, 2001.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the nine
months ended May 31, 2002. Although the East Lost Hills #1 began producing in
2001, we recorded an impairment against our entire amortizable full cost pool on
August 31, 2001, and therefore have no costs to amortize. We recorded $68,456 in
depreciation, depletion and amortization from oil and gas properties for the
nine months ended May 31, 2001. This amount was computed using reserve report
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estimates based on the best information available at the time. We recorded
$10,917 and $14,448 in depreciation expense associated with office furniture and
equipment during the nine months ended May 31, 2002 and May 31, 2001,
respectively.
General and Administrative Expense. We incurred $975,759 and $955,068 in
general and administrative expenses during the nine months ended May 31, 2002
and May 31, 2001, respectively. The increase results primarily from increases in
salary related expenses from increasing personnel and salaries, costs associated
with our first independent reserve analysis and an increase in rent expense. The
increased costs were partially offset by decreases in legal expense, investor
relations, and funding and acquisition expenses.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
We believe the following critical accounting policies affect our more
significant judgments and estimates used in the preparation of our Financial
Statements.
Reserve Estimates:
Our estimates of oil and natural gas reserves, by necessity, are
projections based on geological and engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that are difficult to measure.
The accuracy of any reserve estimate is a function of the quality of available
data, engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and natural gas reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies and
assumptions governing future oil and natural gas prices, future operating costs,
severance and excise taxes, development costs and workover and remedial costs,
all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and natural
gas attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected there from may vary substantially. Any significant variance in the
assumptions could materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of our oil and gas properties
and/or the rate of depletion of the oil and gas properties. Actual production,
revenues and expenditures with respect to our reserves will likely vary from
estimates, and such variances may be material.
Many factors will affect actual net cash flows, including:
o the amount and timing of actual production;
o supply and demand for natural gas;
o curtailments or increases in consumption by natural gas purchasers;
and
o changes in governmental regulations or taxation.
Property, Equipment and Depreciation:
We follow the full cost method to account for our oil and gas exploration
and development activities. Under the full cost method, all costs incurred which
are directly related to oil and gas exploration and development are capitalized
and subjected to depreciation and depletion. Depletable costs also include
estimates of future development costs of proved reserves. Costs related to
undeveloped oil and gas properties may be excluded from depletable costs until
such properties are evaluated as either proved or unproved. The net capitalized
costs are subject to a ceiling limitation based on the estimated present value
of discounted future net cash flows from proved reserves. As a result, we are
required to estimate our proved reserves at the end of each quarter, which is
subject to the uncertainties described in the previous section. Gains or losses
upon disposition of oil and gas properties are treated as adjustments to
capitalized costs, unless the disposition represents a significant portion of
the Company's proved reserves.
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ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings
Not Applicable
Item 2. Changes in Securities and Use of Proceeds; Recent Sales Of Unregistered
Securities
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
Section 3(b) and/or 4(2) of the Securities Act of 1933, as amended.
The holders of the convertible notes have demand and "piggy back"
registration rights with respect to the transfer of the shares issued
upon conversion of the notes. We have reflected the outstanding
balance of these notes as Convertible Notes under Long Term Debt on
our May 31, 2002 balance sheet.
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
The results of the balloting at the Company's Annual Meeting of
Stockholders held on March 13, 2002 were reported in the Company's
Form 10-Q for the quarter ended February 28, 2002.
Item 5. Other Information
During the quarter ended May 31, 2002, the Board of Directors elected
David B. Kilpatrick to serve as a member of the Board of Directors
until the next annual meeting of stockholders and thereafter until his
successor is elected and qualified. Mr. Kilpatrick was President and
Chief Operating Officer of California based Monterey Resources, Inc.
until the 1997 merger with Texaco. Mr. Kilpatrick currently is
president of Kilpatrick Energy Group, which provides management
consulting services to the California oil and gas industry. Mr.
Kilpatrick also will serve as a member of the Company's audit
committee.
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Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit Number
--------------
4.1 Form of Convertible Note Series 2002-A dated May 24, 2002
4.2 Schedule of Differences in Convertible Notes Series 2002-A
10.1 Convertible Note Purchase Agreement dated May 24, 2002
(b) During the Quarter ended May 31, 2002, we filed two reports on Form 8-K:
A Form 8-K was filed on April 16, 2002 reporting a news
release dated April 15, 2002.
A Form 8-K was filed on May 28, 2002 reporting a news release
and events occurring on May 24, 2002, including the sale of
convertible notes and the election of two new members of the
Board of Directors.
SIGNATURES
----------
In accordance with the requirements of the Exchange Act, the Registrant has
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Signatures Title Date
---------- ----- ----
/s/ D. Scott Singdahlsen President, Chief Executive Officer July 15, 2002
------------------------- and Chairman Of The Board
D. Scott Singdahlsen
/s/ Andrew P. Calerich Vice-President and July 15, 2002
----------------------- Chief Financial Officer
Andrew P. Calerich
14