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 February 28, 2003
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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Indicate by check mark whether the registrant (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 April 14, 2003 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 - February 28, 2003 (Unaudited) and
August 31, 2002............................................. 3
Statements of Operations - Three Months and Six Months
Ended February 28, 2003 and February 28, 2002 and
Cumulative Amounts From Inception Through February 28,
2003 (Unaudited)............................................ 4
Statements of Cash Flows - Six Months Ended February 28,
2003 and February 28, 2002 and Cumulative Amounts
From Inception Through February 28, 2003 (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................................... 8
Item 3. Quantitative and Qualitative Disclosures about Market Risk... 13
Item 4. Controls and Procedures...................................... 14
PART II. OTHER INFORMATION
Item 1. Legal Proceedings........................................... 14
Item 2. Changes in Securities and Use of Proceeds................... 14
Item 3. Defaults Upon Senior Securities............................. 14
Item 4. Submission of Matters to a Vote of Security Holders......... 14
Item 5. Other Information........................................... 15
Item 6. Exhibits and Reports on Form 8-K............................ 15
Signatures................................................................ 15
Certifications............................................................ 16
2
PART I
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
(A Development Stage Company)
BALANCE SHEETS
ASSETS
2/28/03 8/31/02
(UNAUDITED)
CURRENT ASSETS
Cash $ 5,239,614 $ 6,516,086
Deposits and prepaid expenses 94,705 47,365
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Total Current Assets 5,334,319 6,563,451
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PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 33,059 34,244
Oil and gas properties, net 7,068,306 6,771,111
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7,101,365 6,805,355
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OTHER ASSETS
Deferred financing costs and other assets 29,850 31,444
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29,850 31,444
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$ 12,465,534 $ 13,400,250
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LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities $ 1,370,339 $ 532,597
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Total Current Liabilities 1,370,339 532,597
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CONVERTIBLE NOTES 6,151,751 6,000,000
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STOCKHOLDERS' EQUITY
Common stock, $.001 par value
Authorized 75,000,000 shares
Issued and outstanding - 23,701,357 shares 23,701 23,701
Capital in excess of par value 35,407,657 35,407,657
Deficit accumulated during the development stage (30,487,914) (28,563,705)
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4,943,444 6,867,653
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$ 12,465,534 $ 13,400,250
============ ============
3
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Three Six Six Cumulative from
Months Months Months Months Inception
Ended Ended Ended Ended Through
2/28/03 2/28/02 2/28/03 2/28/02 2/28/03
REVENUES
Oil and gas revenues $ 46,494 $ 26,056 $ 94,038 $ 72,312 $ 1,428,586
Interest 14,089 32,508 34,835 95,166 926,462
Other -- -- -- -- 127,528
------------ ------------ ------------ ------------ ------------
60,583 58,564 128,873 167,478 2,482,576
OPERATING EXPENSES
Lease operating expenses 25,308 6,794 46,345 31,961 239,747
Impairment, dry hole, and abandonments 698,599 -- 1,178,267 113,544 26,762,377
Depreciation and amortization 2,786 3,730 5,872 7,226 104,473
General and administrative 345,237 328,142 670,543 652,285 5,964,967
Interest 76,489 -- 152,055 -- 419,255
------------ ------------ ------------ ------------ ------------
1,148,419 338,666 2,053,082 805,016 33,490,819
OTHER INCOME
Gain on sale of oil and gas prospects -- -- -- -- 556,197
------------ ------------ ------------ ------------ ------------
(1,087,836) (280,102) (1,924,209) (637,538) (30,452,046)
(INCOME) APPLICABLE TO
PREDECESSOR LLC -- -- -- -- (35,868)
------------ ------------ ------------ ------------ ------------
NET (LOSS) (1,087,836) (280,102) (1,924,209) (637,538) (30,487,914)
Less dividends on preferred stock -- -- -- -- (292,411)
------------ ------------ ------------ ------------ ------------
NET (LOSS) TO COMMON STOCKHOLDERS $ (1,087,836) $ (280,102) $ (1,924,209) $ (637,538) $(30,780,325)
============ ============ ============ ============ ============
NET (LOSS) PER COMMON
SHARE -BASIC AND DILUTED (0.05) (0.01) (0.08) (0.03) (2.08)
============ ============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 23,701,357 23,691,357 23,701,357 23,691,357 14,658,711
============ ============ ============ ============ ============
4
PYR ENERGY CORPORATION
(A Development Stage Company)
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Six Months Cumulative Amounts
Ended Ended from Inception
2/28/03 2/28/02 Through 2/28/03
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $ (1,924,209) $ (637,538) $(30,452,046)
Adjustments to reconcile net loss to
net cash used by operating activities
Depreciation and amortization 5,872 7,226 104,474
Contributed services -- -- 36,000
Gain on sale of oil and gas prospects -- -- (556,197)
Impairment, dry hole and abandonments 1,178,267 113,544 26,762,377
Common stock issued for interest on debt -- -- 136,822
Common stock issued for services -- -- 178,665
Amortization of financing costs 1,594 -- 29,400
Amortization of marketable securities -- -- (20,263)
Accrued interest converted into debt 71,487 -- 71,487
Changes in assets and liabilities
(Increase) in accounts receivable -- (36,896) (566)
(Increase) in prepaids (47,340) (8,178) (99,257)
Increase (decrease) in accounts payable, accruals 429,114 (44,455) (661,172)
Other -- 2,551 1,279
------------ ------------ ------------
Net cash used by operating activities (285,215) (603,746) (4,468,997)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (4,688) (11,293) (136,893)
Cash paid for oil and gas properties (986,569) (2,486,581) (31,798,268)
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)
------------ ------------ ------------
Net cash used in investing activities (991,257) (2,497,874) (30,643,215)
------------ ------------ ------------
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
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NET (DECREASE) INCREASE IN CASH (1,276,472) (3,101,620) 5,239,614
CASH, BEGINNING OF PERIODS 6,516,086 9,800,842 --
------------ ------------ ------------
CASH, END OF PERIODS $ 5,239,614 $ 6,699,222 $ 5,239,614
============ ============ ============
5
PYR ENERGY CORPORATION
(A Development Stage Company)
Notes to Financial Statements
February 28, 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 periods ended February 28, 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/A1 for the year
ended August 31, 2002.
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 February 28, 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.
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. At August 31, 2002, we had no proved reserves and recorded
an impairment charge against the net value of our evaluated properties of
approximately $11,723,000 based on the ceiling test limitation. This charge
relates primarily to costs incurred at our East Lost Hills project. We continue
to incur costs at East Lost Hills and recorded an impairment charge of $698,599
for our fiscal quarter ended February 28, 2003, primarily related to an accrual
of plugging liabilities associated with the ELH wells. 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 capitalized, then charged to impairment expense as
incurred.
SFAS 143, "Accounting for Asset Retirement Obligations," provides
accounting requirements for retirement obligations associated with tangible
long-lived assets, including the timing of liability recognition, initial
measurement of the liability, allocation of asset retirement costs to expense,
subsequent measurement of the liability, and financial statement disclosures.
SFAS 143 requires that asset retirement costs be capitalized along with the cost
of the related long-lived asset. The asset retirement costs should then be
allocated to expense using a systematic and rational method. SFAS 143 requires
us to recognize an estimated liability for the plugging, abandoning of oil and
gas wells and site restoration associated with oil and gas properties. We have
adopted SFAS 143 retroactively effective September 1, 2002, and have accrued a
total of $600,000 to reflect the liability for plugging, abandonment and site
restoration obligations associated with East Lost Hills wells. Our estimate is
based on the best information available to us at this time. Revisions to the
liability could occur due to changes in actual plugging, abandonment and or site
restoration cost. Because we expect to incur these costs within the next twelve
months, the liability we recorded is undiscounted and is reflected under current
liabilities on our balance sheet as of February 28, 2003. These costs have been
capitalized and charged to impairment expense.
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 - 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, we elected to add $151,751 in interest due on these notes to the
principal balance (rather than pay the interest in cash on a current basis) so
that at February 28, 2003, the aggregate balance of these notes, reflected as
Convertible Notes under Long Term Debt, was $6,151,751.
7
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
currently operate any projects in which we own a working interest, although we
may operate some projects in the future. We do not have the financial ability to
commence exploratory drilling operations without third party participation. We
have pursued, and will continue to pursue, exploration opportunities in regions
in which we believe significant opportunity for discovery of oil and gas exists.
By attempting to reduce drilling risk through seismic technology, we seek to
improve the expected return on investment in our oil and gas exploration
projects.
Our future financial results continue to depend primarily on (1) our
ability to discover commercial quantities of hydrocarbons; (2) the market price
for oil and gas; (3) our ability to continue to source and screen potential
projects; and (4) our ability to fully implement our exploration and development
program with respect to these and other matters. There can be no assurance that
we will be successful in any of these respects or that the prices of oil and gas
prevailing at the time of production will be at a level allowing for profitable
production.
We paid approximately $987,000 and $2,487,000 during the three months ended
February 28, 2003 and 2002, 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 control interests in several exploration projects in the San Joaquin
Basin and in select areas of the Rocky Mountains. In addition to East Lost
Hills, projects in the San Joaquin Basin include our Wedge and Bulldog
prospects, which are large target reserve, deep Temblor gas prospects located to
the northwest of our East Lost Hills acreage, and our Blizzard prospect which is
a light oil Stevens target. In the Rocky Mountains, we currently are focusing on
our Cumberland and Mallard projects, located in southwestern Wyoming, and on our
Montana Foothills project. We intend to raise project financing from outside
sources to assist in funding the drilling of initial test wells in the
California and Wyoming projects. We do not intend to sell additional equity in
PYR Energy Corporation in order to finance the drilling of exploration wells,
but intend to establish a joint venture with a drilling fund that we will
attempt to organize. If the drilling fund is successfully established, of which
there is no assurance, we would contribute our working interests in these
projects to the joint venture. If we are able to obtain sufficient funding for
the drilling fund, of which there is no assurance, we expect to commence
drilling exploration wells in up to five of these projects during the next 12
months. 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 raise capital through the drilling fund
and/or the level of industry participation in our exploration projects, we
anticipate spending a minimum of $2.1 million for capital expenditures relating
to exploration of our projects during the next 12 months. We may need to raise
additional funds in the future 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 of any nature will
be available.
At February 28, 2003, we had a working capital amount of approximately
$3,964,000 and had $6,151,751 of convertible notes outstanding. These notes are
due on May 24, 2009 and call for semi-annual interest payments at an annual rate
8
of 4.99%. The notes are convertible into shares of common stock at the rate of
$1.30 per share. At February 28, 2003, 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 our exploration
projects:
East Lost Hills, California. 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. Because of the very high historical cost structure of operations,
the expiration of certain leases, and uncertainties regarding the ability or
desire of other participants to continue to fund operations at East Lost Hills,
we are limiting our capital expenditures at East Lost Hills to those that we are
contractually liable for until such a point in time as many of the ongoing
problems associated with the play are mitigated, of which there is no assurance.
If additional operations are proposed, we will carefully evaluate to what
extent, if any, we will participate in those operations.
During our second quarter ended February 28, 2003, our only producing well,
the East Lost Hills ELH #1, produced a gross total of approximately 73 mmcfe,
averaging approximately 910 mcf per day. Water production during this period
averaged approximately 3,000 barrels per day. We own a 12.12% working interest
in this well.
The operator at East Lost Hills has formally proposed plugging the ELH #4
and ELH #9 wells. Although we have consented to these operations, we have not
been notified if or when these wells will be plugged. We own a 12.12% working
interest in each of these wells.
The Aera Energy LLC NWLH 1-22 well has reached total depth, however
completion operations have not commenced. It is uncertain as to whether or not
this well will be completed for production testing. Because we have determined
to prioritize our financial resources on other prospects, we have notified the
operator of our non-consent election in the completion of this well. We own a
4.04% working interest in this well, subject to a 300% percent non-consent
penalty.
Pyramid Power Prospect, California. 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.
The initial test well, located in Section 9, T25S-R18E, commenced drilling on
November 22, 2001. On July 17, 2002, the well reached total depth of 20,465
feet. Upon running final casing, the rig was released. Berkley Petroleum Inc., a
wholly owned subsidiary of Anadarko Petroleum Corporation, was operator of the
well during drilling. Upon release of the rig, Oxy Lost Hills Inc. ("Oxy") took
over as operator and conducted completion operations. Production testing in the
Point of Rocks formation resulted in non-commercial delivery of hydrocarbons.
Based on log analysis, Oxy determined that production testing in the Temblor
formation was not warranted and the well has been plugged and abandoned. PYR
owned a carried working interest of 2.81% in the well and as a result of the
carry, PYR did not incur any costs in the drilling or plugging of the well.
Wedge Prospect, California. This is a seismically identified 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 farther
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 12,100 gross
and approximately 11,600 net acres here. Our approach is to sell down our
working interest and retain a 25% to 50% working interest in this prospect.
9
Bulldog Prospect, California. This project is a 2D seismically identified
natural gas and condensate 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 15,600 gross and approximately 15,100 net acres here. We expect to
sell down our working interest in this project and retain a 25% to 50% working
interest in the prospect acreage and in a 14,000 foot test well we expect to
drill during calendar 2003.
Blizzard Prospect, California. The Blizzard prospect, located in the
Southern San Joaquin Basin, Kern county, is defined by 3D seismic data as an
untested uppermost Stevens turbidite sandstone similar to other Stevens
reservoir sandstones. While stratigraphically higher than productive sands at
the neighboring Rio Viejo field, the Blizzard reservoir is located basinward
along a direct migration pathway from the hydrocarbon generation basin center.
As evidenced at Yowlumne Field (located 5 miles to the west), higher
stratigraphic sands deposited basinward exhibit better productivity and higher
reserve potential. Estimated target depth for the Blizzard prospect is
approximately 14,500 feet. We control approximately 1,900 gross and net acres in
the prospect area. We anticipate drilling an initial test well during calendar
2003, and expect to retain a 40% to 50% working interest in this project.
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 241,800 gross and 226,300 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, Wyoming. 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
10
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 expect to sell down our working interest to between 25% and 50%. We have
recently received approval for our drilling permit from the State of Wyoming and
we intend to commence the drilling of an initial exploration well during 2003.
Mallard Project, Wyoming. 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 splaying 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
and expect to sell down our working interest to between 25% and 50%. We intend
to commence the drilling of an initial exploration well during 2003.
Results of Operations
The quarter ended February 28, 2003 compared with the quarter ended
February 28, 2002.
Operations during the quarter ended February 28, 2003 resulted in a net
loss of $1,087,836 compared to a net loss of $280,102 for the quarter ended
February 28, 2002. The increase in net loss is due primarily to an increase in
impairment charge of approximately $699,000 and an increase in interest expense
of approximately $76,000 from the prior year period. A broader discussion of
these and the other items are presented below.
Oil and Gas Revenues and Expenses. During the quarter ended February 28,
2003, we recorded $35,733 from the sale of 8,163 mcf of natural gas for an
average price of $4.38 per mcf and $10,761 from the sale of 381 bbls of
hydrocarbon liquids for an average price of $28.24 per barrel. Lease operating
expenses during this period were $25,308. During the quarter ended February 28,
2002, we recorded $19,892 from the sale of 9,336 mcf of natural gas for an
average price of $2.13 per mcf and $5,951 from the sale of 389 bbls of
hydrocarbon liquids for an average price of $15.29 per barrel. Overriding
royalty revenues totaled $213. Lease operating expenses during this period were
$6,794.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the quarters
ended February 28, 2003 and February 28, 2002. Although the East Lost Hills #1
began producing in 2001, we recorded an impairment against our entire
amortizable full cost pool at February 28, 2003, and therefore had no costs to
amortize. No impairment was recorded against our oil and gas properties for the
quarter ended February 28, 2002. We recorded $2,786 and $3,730 in depreciation
expense associated with capitalized office furniture and equipment during the
quarters ended February 28, 2003 and February 28, 2002, respectively.
Dry Hole, Impairment and Abandonments. During the quarter ended February
28, 2003, we recorded an impairment of $698,599. The charge was made up of
$600,000 in estimated plugging costs for the East Lost Hills wells and $98,599
in additional costs that continue to be incurred primarily on the East Lost
11
Hills property. 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. No impairment
expense was recognized for the quarter ended February 28, 2002.
General and Administrative Expense. We incurred $345,237 and $328,142 in
general and administrative expenses during the quarters ended February 28, 2003
and February 28, 2002, respectively. The difference is due largely to an
increase in initial costs associated with attempting to establish a drilling
fund.
Interest Expense. We incurred $76,489 in interest expense for the quarter
ended February 28, 2003 associated with outstanding convertible notes due May
24, 2009. We incurred no interest expense during the quarter ended February 28,
2002.
The six months ended February 28, 2003 compared with the six months ended
February 28, 2002.
Oil and Gas Revenues and Expenses. For the six months ended February 28,
2003, we recorded $72,623 from the sale of 19,110 mcf of natural gas for an
average price of $3.80 per mcf and $21,415 from the sale of 833 bbls of
hydrocarbon liquids for an average price of $25.71 per barrel. Operating
expenses during this period were $46,345. During the six months ended February
28, 2002, we recorded $40,887 from the sale of 18,321 mcf of natural gas for an
average price of $2.23 per mcf and $14,650 from the sale of 874 bbls of
hydrocarbon liquids for an average price of $16.76 per barrel. Additionally, we
recorded overriding royalty revenues of $16,775 dating back to the commencement
of production of the ELH#1 well. Operating expenses were $31,961 for this
period.
Depreciation, Depletion and Amortization. We recorded no depreciation,
depletion and amortization expense from oil and gas properties for the six
months ended February 28, 2003 and February 28, 2002. Although the East Lost
Hills #1 began producing in 2001, we recorded an impairment against our entire
amortizable full cost pool for both the six months ended February 28, 2003 and
February 28, 2002, and therefore had no costs to amortize. We recorded $5,872
and $7,226 in depreciation expense associated with capitalized office furniture
and equipment during the six months ended February 28, 2003 and February 28,
2002, respectively.
Dry Hole, Impairment and Abandonments. During the six months ended February
28, 2003, we recorded an impairment of $1,178,267. The charge was made up of
$600,000 in estimated plugging costs for the East Lost Hills wells and $578,267
in additional costs that continue to be incurred primarily on the East Lost
Hills property. 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, additional costs associated with these properties are
capitalized, then charged to impairment expense as incurred. During the six
months ended February 28, 2002, we recorded impairment expense of $113,544.
General and Administrative Expense. We incurred $670,543 and $652,285 in
general and administrative expenses during the six months ended February 28,
2003 and February 28, 2002, respectively. The difference is due largely to an
increase in initial costs associated with attempting to establish a drilling
fund.
12
Interest Expense. We incurred $152,055 in interest expense for the six
months ended February 28, 2003 associated with outstanding convertible notes due
May 24, 2009. We incurred no interest expense during the six months ended
February 28, 2002.
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 from there 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 the following:
the amount and timing of actual production; supply and demand for natural gas;
curtailments or increases in consumption by natural gas purchasers; and 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
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. 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.
ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable
13
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures
Based on an evaluation carried out under the supervision, and with the
participation of the management of the Company, including the Chief Executive
Officer and the Chief Financial Officer, during the 90 day period prior to the
filing of this report, the Company's Chief Executive Officer and Chief Financial
Officer believe the Company's disclosure controls and procedures, as defined in
Securities Exchange Act Rules 13a-14 and 15d-14, are, to the best of their
respective knowledge, effective.
(b) Changes in internal controls
Subsequent to the date of this evaluation, the Chief Executive Officer and
Chief Financial Officer are not aware of any significant changes in the
Company's internal controls, including any corrective actions with regard to
significant deficiencies and material weaknesses, or in other factors that could
significantly affect these controls to ensure that information required to be
disclosed by the Company, in reports that it files or submits under the
Securities Act of 1934, is recorded, processed, summarized and reported within
the time periods specified in Securities and Exchange Commission rules and
regulations.
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
The following matters were submitted to a vote of security holders at
the annual meeting of stockholders which was held on March 18, 2003:
The stockholders voted to re-elect D. Scott Singdahlsen, S.L.
Hutchison, Bryce W. Rhodes, Borden Putnam, Eric M. Sippel and David B.
Kilpatrick to continue as directors of the Company. A total of
19,809,110 votes were represented with respect to this matter.
Approximately 19,700,000 (99.4%) of the shares voted for each nominee,
no shares voted against any nominee, and the remaining shares abstained
from voting.
A proposal to ratify the selection of Wheeler Wasoff, P.C. as
Certified Public Accountants was approved by the stockholders. A total
of 19,809,110 votes were represented with a total of 19,786,421 (99.89%)
shares voting for the proposal, 15,253 shares voting against the
proposal, and 7,436 shares abstained from voting.
14
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
99.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) During the Quarter ended February 28, 2003, we filed two reports on
Form 8-K:
A Form 8-K was filed on January 14, 2003 reporting a news release
dated January 14, 2003, and a Form 8-K was filed on January 30, 2003
reporting a news release dated January 30, 2003.
SIGNATURES
----------
In accordance with the requirements of the Exchange Act, the Registrant has
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Signatures Title Date
---------- ----- ----
/s/ D. Scott Singdahlsen President, Chief Executive April 14, 2003
------------------------- Officer and Chairman
D. Scott Singdahlsen Of The Board of Directors
/s/ Andrew P. Calerich Vice-President and April 14, 2003
------------------------- Chief Financial Officer
Andrew P. Calerich
15
CERTIFICATIONS
I, D. Scott Singdahlsen, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PYR Energy
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: April 14, 2003 /s/ D. Scott Singdahlsen
-----------------------------------
D. Scott Singdahlsen
Chief Executive Officer
16
I, Andrew P. Calerich, certify that:
1. I have reviewed this quarterly report on Form 10-Q of PYR Energy
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: April 14, 2003 /s/ Andrew P. Calerich
-----------------------------------
Andrew P. Calerich
Chief Financial Officer
17