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 November 30, 2001
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 X No
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(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
The number of shares outstanding of each of the issuer's classes of common
equity as of January 11, 2002 is as follows:
$.001 Par Value Common Stock 23,691,357
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PYR ENERGY CORPORATION
FORM 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.................................. 3
Balance Sheets - November 30, 2001 (Unaudited)
and August 31, 2001................................... 3
Statements of Operations - Three Months Ended
November 30, 2001 and November 30, 2000 and
Cumulative Amounts From Inception Through
November 30, 2001 (Unaudited)......................... 4
Statements of Cash Flows - Three Months Ended
November 30, 2001 and November 30, 2000 and
Cumulative Amounts From Inception Through
November 30, 2001 (Unaudited)......................... 5
Notes to Financial Statements......................... 6
Summary of Significant Accounting Policies............ 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........................................... 11
PART II. OTHER INFORMATION
Item 1. Legal Proceedings..................................... 11
Item 2. Changes in Securities and Use of Proceeds............. 11
Item 3. Defaults Upon Senior Securities....................... 12
Item 4. Submission of Matters to a Vote of Security Holders... 12
Item 5. Other Information..................................... 12
Item 6. Exhibits and Reports on Form 8-K...................... 12
Signatures..................................................... 13
2
PART I
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
(A Development Stage Company)
BALANCE SHEETS
ASSETS
11/30/01 8/31/01
(UNAUDITED)
CURRENT ASSETS
Cash $ 7,660,808 $ 9,800,842
Oil and gas receivables 1,209,010 1,173,751
Deposits and prepaid expenses 95,659 74,636
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Total Current Assets 8,965,477 11,049,229
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PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 40,149 40,638
Oil and gas properties, net 13,283,941 10,977,317
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13,324,090 11,017,955
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$ 22,289,567 $ 22,067,184
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 2,843,186 $ 2,263,368
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Total Current Liabilities 2,843,186 2,263,368
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COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Common stock, $.001 par value
Authorized 75,000,000 shares
Issued and outstanding - 23,691,357 shares
at 11/30/01 and 23,691,357 shares at 8/31/01 23,691 23,691
Capital in excess of par value 35,214,002 35,214,002
Deficit accumulated during the development stage (15,791,312) (15,433,877)
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19,446,381 19,803,816
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$ 22,289,567 $ 22,067,184
============ ============
3
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF OPERATIONS
(UNAUDITED)
Cumulative
Three Three from
Months Months Inception
Ended Ended Through
11/30/01 11/30/00 11/30/01
REVENUES
Oil and gas revenues $ 46,256 $ -- 1,248,235
Interest 62,658 111,128 808,640
Other -- -- 127,528
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108,914 111,128 2,184,403
OPERATING EXPENSES
Lease operating expenses 25,167 -- 127,185
Impairment, dry hole, and abandonments 113,544 -- 13,974,824
General and administrative 324,143 254,248 4,122,238
Depreciation and amortization 3,496 4,098 87,492
Interest -- -- 184,306
------------ ------------ ------------
466,350 258,346 18,496,045
OTHER INCOME
Gain on sale of oil and gas prospects -- -- 556,197
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(357,436) (147,218) (15,755,445)
INCOME APPLICABLE TO
PREDECESSOR LLC (Note 1) -- -- (35,868)
------------ ------------ ------------
NET (LOSS) INCOME (357,436) (147,218) (15,791,313)
Less dividends on preferred stock -- -- (292,411)
------------ ------------ ------------
NET (LOSS) TO COMMON STOCKHOLDERS $ (357,436) $ (147,218) $(16,083,724)
============ ============ ============
NET (LOSS) PER COMMON
SHARE -BASIC AND DILUTED $ (0.02) $ (0.01) $ (1.28)
============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 23,691,357 19,532,027 12,604,544
============ ============ ============
4
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Cumulative Amounts
from Inception
11/30/01 11/30/00 Through 11/30/01
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) $ (357,436) $ (147,218) $(15,755,445)
Adjustments to reconcile net (loss) to
net cash (used) by operating activities
Depreciation and amortization 3,496 4,098 87,492
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) decrease in accounts receivable (35,258) (39,996) (1,209,575)
(Increase) decrease in prepaids (21,025) (18,537) (100,212)
(Decrease) increase in accounts payable (30,797) (99,542) 51,109
Other -- 980 8,195
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Net cash (used) by operating activities (327,476) (300,215) (3,320,311)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (3,007) -- (123,919)
Cash paid for oil and gas properties (1,809,550) (4,346,773) (24,296,045)
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 (1,812,557) (4,346,773) (23,378,018)
------------ ------------ ------------
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 -- -- 2,500,001
Proceeds from exercise of warrants -- 666,385 2,011,073
Proceeds from exercise of options -- 2,406 189,530
Cash paid for offering costs -- -- (1,036,448)
Payments on capital lease -- (920) (5,195)
Preferred dividends paid -- -- (50,910)
------------ ------------ ------------
Net cash provided by financing activities -- 667,871 34,359,137
------------ ------------ ------------
NET (DECREASE) INCREASE IN CASH (2,140,033) (3,979,117) 7,660,808
CASH, BEGINNING OF PERIODS 9,800,841 8,598,016 --
------------ ------------ ------------
CASH, END OF PERIODS $ 7,660,808 $ 4,618,899 $ 7,660,808
============ ============ ============
5
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
November 30, 2001
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 period ended November 30, 2001 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.
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, 2001, 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
6
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. 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.
During the quarter ended November 30, 2001, we recorded an additional
$113,544 for formation evaluation on the ELH #3 well, final drilling related
costs for the ELH #2 and ELH #3 wells and for delay rentals that were not
included in the impairment calculation at August 31, 2001 and charged this
entire amount to impairment expense. Management believes that in the future, any
additional costs associated with these properties will be nominal. We continue
to own oil and gas production and are recording revenues from the sale of oil
and gas. Because we have no costs to amortize, we recorded no depreciation,
depletion and amortization expense for the quarter ended November 30, 2001.
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.
ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE - Accounts receivable at November
30, 2001 includes $1,208,854 of net revenue due from operator for oil and gas
sales since commencement of production in February 6, 2001 through November 30,
2001. The Company has not received any payments for production from the
operator, and the joint operating agreement underlying the East Lost Hills
prospect does not provide for the Company to offset the receivable for oil and
gas revenue against amounts due to the operator. The Company believes that the
operator is legally responsible to remit payment. Until the Company receives
payment, management intends to offset payments due to the operator for cash
calls and other liabilities in an amount equal to the revenue due. Although the
joint operating agreement provides that the operator can charge interest on past
due cash calls and billings, no interest has been charged to the Company. As of
November 30, 2001, the Company's liability due to the operator exceeded accounts
receivable for oil and gas sales by $1,255,058, including $933,778 for drilling
costs not billed as of November 30, 2001.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS 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
7
currently operate any projects where 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 ability 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.
We paid approximately $1,810,000 and $4,346,000 during the three months
ended November 30, 2001 and November 30, 2000, 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 will participate in the drilling of between
three to seven exploration/development wells during the next 12 months, although
the number of wells may increase as additional projects are added to our
portfolio. However, there can be no assurance that any wells will be drilled and
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 $6 million for capital
expenditures relating to exploration and development of our projects during
calendar 2002. 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 November 30, 2001, we had a working capital amount of approximately
$6,122,000. We had no outstanding long-term debt at November 30, 2001 and 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 first quarter ended November 30, 2001, our only producing well,
the ELH #1, produced a gross total of approximately 125 mmcfe, averaging
approximately 1.5 mmcfe per day. Water production during this period averaged
approximately 4,850 barrels per day. The oil and gas production from the ELH #1
well is limited to the amount of production water that is accepted at water
disposal facilities owned by ChevronTexaco. The participants are currently in
the process of preparing to drill a water disposal well and to build associated
pipeline and disposal facilities in order to dispose of water without relying on
the ChevronTexaco facility, thereby removing the water disposal constraint that
8
continues to limit the oil and gas production from the ELH #1 well. Although we
expect to be able to increase oil and gas production if we can increase the
water disposal capability, it is unknown whether removing the water disposal
constraint will result in a decrease in the water to gas ratio.
The ELH #4 well commenced drilling on November 26, 2000 at a location
approximately four miles southeast of the ELH #1 well. This well reached a total
depth of 20,800 feet on August 7, 2001. Log and coring analysis was performed
and it was determined that in order to maximize potential production, the well
bore should be sidetracked and directed to a more crestal position within the
lower Temblor. On October 16, 2001, sidetrack drilling operations commenced to
drill to a projected depth of 20,500 feet. During late December 2001, an
intermediate string of casing was successfully run in the sidetracked well bore
to a depth of approximately 19,500 feet. This well is currently drilling at a
depth of approximately 20,000 feet.
The ELH #9 well commenced drilling on July 17, 2001 approximately six miles
southeast of the ELH #1 well. This well has a target total depth in the lower
Temblor of 21,000 feet. An intermediate string of casing was recently run to a
depth of approximately 17,600 feet. This well is currently drilling in the upper
Temblor at a depth of approximately 18,300 feet.
We are also participating in a third well currently drilling at East Lost
Hills. 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. After drilling to a depth of 18,400 feet, it was determined that the
well bore could be directed into the Temblor in a more crestal position. As a
result, operations have commenced to kick-off a sidetrack well bore from a depth
of 14,100 feet. The sidetrack operations are in the open hole portion of the
well bore as no casing has been run at this depth. The total target depth of
this sidetrack well remains at 20,000 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 exploration well, operated by
Anadarko and located in Section 9, T25S-R18E, commenced drilling on November 22,
2001. This exploration well is designed to test the Temblor and the Point of
Rocks formation to a total depth of 18,500 feet. The participants at Pyramid
Power jointly control approximately 20,000 gross and 15,000 net acres over the
prospect. This well continues drilling operations at an approximate depth of
14,150 feet.
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 that has
proven productive 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
9
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 in the process of securing industry participation
to drill a 14,000 foot test well and we expect to retain a 25% to 40% working
interest in this prospect.
Additional activities located in the Rocky Mountains include the following
projects:
Montana Foothills Project. This extensive natural gas 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
extremely 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% to 40%.
Wyoming Projects. We have three separate exploration projects in Wyoming,
and have acquired an initial land position of approximately 8,000 gross and net
acres. We intend to acquire additional land holdings as opportunities arise. We
currently are interpreting seismic data and conducting other geophysical
activities.
Results of Operations
The quarter ended November 30, 2001 compared with the quarter ended
November 30, 2000.
Operations during the quarter ended November 30, 2001 resulted in a net
loss of $357,436 compared to a net loss of $147,218 for the quarter ended
November 30, 2000. The components that account for the difference are presented
below.
Oil and Gas Revenues and Expenses. Production commenced at the East Lost
Hills #1 well on February 6, 2001. Our ownership share of this production
resulted in our recording $20,995 from the sale of 8,985 mcf of natural gas for
an average price of $2.34 per mcf and $8,700 from the sale of 485 bbls of
hydrocarbon liquids for an average price of $17.94 per barrel during the quarter
ended November 30, 2001. In addition, we recorded revenues dating back to
commencement of production of the ELH #1 well of $16,561 from overriding royalty
interests we own. Operating expenses during this period were $25,167. We
recorded no revenues or expenses from oil and gas operations for the quarter
ended November 30, 2000. None of our oil or gas properties were producing before
February 6, 2001.
10
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the quarters
ended November 30, 2001 and November 30, 2000. Although the East Lost Hills #1
began producing in 2001, we recorded an impairment against our entire
amortizable full cost pool through November 30, 2001, and therefore had no costs
to amortize. During the quarter ended November 30, 2000, none of our oil and gas
properties were producing, and therefore no DD&A expense was recognized. We
recorded $3,496 and $4,098 in depreciation expense associated with capitalized
office furniture and equipment during the quarters ended November 30, 2001 and
November 30, 2000, respectively.
Dry Hole, Impairment and Abandonments. During the quarter ended November
30, 2001, we recorded an additional $113,544 for formation evaluation on the ELH
#3 well, final drilling related costs for the ELH #2 and ELH #3 wells and for
delay rentals that were not included in the impairment calculation at August 31,
2001 and charged this entire amount to impairment expense. 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. We recorded no impairment against our oil and gas properties for the
quarter ended November 30, 2000.
General and Administrative Expense. We incurred $324,143 and $254,248 in
general and administrative expenses during the quarters ended November 30, 2001
and November 30, 2000, 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.
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 January 5, 2001, our "shelf" registration statement (SEC file number
333-51764), pertaining to the sale from time to time of up to $75 million of our
securities, was declared effective by the Securities and Exchange Commission.
The securities that may be offered by the Company pursuant to this registration
statement may include shares of common stock, shares of preferred stock, which
may be issued in the form of depositary shares evidenced by depositary receipts,
warrants to purchase common stock, preferred stock or any combination of those
securities, or any combination of any of these securities.
On March 9, 2001, we received a total of $11.6 million in gross proceeds
from the sale of 1,450,000 shares of our common stock. The common stock was sold
pursuant to a prospectus supplement with respect to the shelf registration
statement. We incurred offering expenses of $160,470 in this offering, so that
we received net proceeds of $11,439,530 from this sale of common stock. These
expenses do not include any direct or indirect payments to directors, officers,
persons owning 10% or more of any class of equity securities, or affiliates of
11
the Company. Because these securities were sold directly by the Company in an
offering that did not involve an underwriter, we did not pay any underwriting
discounts or commissions, finder's fees or other expenses to or for
underwriters.
Through November 30, 2001, $4,772,608 of the proceeds from this sale of
common stock have been used as described in the prospectus supplement to fund
our planned exploration and development activities, primarily in the San Joaquin
Basin of California. Included in the total amount is $1,809,550 which was used
during the quarter ended November 30, 2001.
Item 3. Defaults Upon Senior Securities
None
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
None
(b) During the Quarter ended November 30, 2001, we filed one report on
Form 8-K:
A Form 8-K was filed on November 29, 2001 reporting a news release
dated November 29, 2001.
12
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 January 11, 2002
----------------------------- Officer and Chairman
D. Scott Singdahlsen Of The Board
/s/ Andrew P. Calerich Vice-President and Chief January 11, 2002
----------------------------- Financial Officer
Andrew P. Calerich
13