U.S. Securities And Exchange Commission
Washington, D.C. 20549
FORM 10-QSB
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended February 28, 2005
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from ______________ to ______________
Commission File No. 001-15511
PYR ENERGY CORPORATION
----------------------
(Exact name of small business issuer as specified in its charter)
Maryland 95-4580642
-------- ----------
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
1675 Broadway, Suite 2450, Denver, CO 80202
------------------------------------- -----
(Address of principal executive offices) (Zip Code)
Issuer's telephone number, including area code (303) 825-3748
Check whether the issuer (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
The number of shares outstanding of each of the issuer's classes of common
equity as of February 28, 2005 is as follows:
$.001 Par Value Common Stock 31,574,426
----------
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements 3
Balance Sheets - February 28, 2005 (Unaudited) and August 31, 2004 3
Statements of Operations - Three and Six Months Ended February 28, 2005
and February 29, 2004 (Unaudited) 4
Statements of Cash Flows - Six Months Ended February 28, 2005
and February 29, 2004 (Unaudited) 5
Notes to Financial Statements 7
Item 2. Management's Discussion and Analysis or Plan of Operation 10
Item 3. Controls and Procedures 22
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 23
Item 3. Defaults Upon Senior Securities 23
Item 4. Submission of Matters to a Vote of Security Holders 23
Item 5. Other Information 23
Item 6. Exhibits 23
Signatures 24
2
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
February 28, August 31,
CURRENT ASSETS 2005 2004
------------ ------------
Cash $ 5,171,981 $ 6,038,156
Receivables:
Oil and gas receivables 1,365,116 477,176
Joint billing receivables 109,373 --
Other receivables 7,692 --
Exploration option receivable -- 750,000
------------ ------------
1,482,181 1,227,176
Prepaid expenses and other assets 114,206 102,239
------------ ------------
Total current assets 6,768,368 7,367,571
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Furniture and equipment, net 31,945 26,736
Oil and gas properties under full cost, net 10,276,172 8,851,351
------------ ------------
10,308,117 8,878,087
------------ ------------
OTHER ASSETS
Deferred financing costs and other assets 63,476 65,070
------------ ------------
63,476 65,070
------------ ------------
TOTAL ASSETS $ 17,139,961 $ 16,310,728
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 203,536 $ 83,042
Accrued expenses:
Ad valorem tax payable 65,068 65,068
Accrued interest payable 89,114 89,644
Accrued net profits interest payable 354,954 --
Other accrued liabilities 251,738 199,688
------------ ------------
760,874 354,400
Asset retirement obligation 868,163 868,163
------------ ------------
Total current liabilities 1,832,573 1,305,605
------------ ------------
LONG TERM LIABILITIES
Convertible Notes 6,789,962 6,623,351
Asset retirement obligation 315,757 289,489
------------ ------------
Total long term liabilities
7,105,719 6,912,840
------------ ------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value; authorized 1,000,000 shares;
issued and outstanding - none -- --
Common stock, $.001 par value; authorized 75,000,000 shares
Issued and outstanding - 31,574,426 at 2/28/05 and
31,564,426 shares at 8/31/04 31,574 31,564
Capital in excess of par value 43,239,529 43,221,391
Accumulated deficit (35,069,434) (35,160,672)
------------ ------------
Total stockholders' equity 8,201,669 8,092,283
------------ ------------
$ 17,139,961 $ 16,310,728
============ ============
3
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
2/28/2005 2/29/2004 2/28/2005 2/29/2004
--------- --------- --------- ---------
REVENUES
Oil and gas revenues $ 1,195,671 $ 44,376 $ 2,278,181 $ 84,394
------------ ------------ ------------ ------------
1,195,671 44,376 2,278,181 84,394
------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 203,153 21,681 483,729 36,952
Accretion expense 6,307 21,152 12,607 42,304
Net profits interest expense 232,588 -- 354,954 --
Depreciation and amortization 167,046 41,804 205,083 81,924
General and administrative 497,669 285,442 1,009,056 536,932
------------ ------------ ------------ ------------
Total operating expenses 1,106,763 370,079 2,065,429 698,112
INCOME (LOSS) FROM OPERATIONS 88,908 (325,703) 212,752 (613,718)
OTHER INCOME (EXPENSE)
Interest income 24,833 5,041 45,132 10,608
Other income 4,141 -- 8,281 --
Interest (expense) (84,342) (81,196) (167,675) (160,550)
Other (expense) (3,335) -- (7,253)
------------ ------------ ------------ ------------
Total other (expense) (58,703) (76,155) (121,515) (149,942)
NET INCOME (LOSS) $ 30,205 $ (401,858) $ 91,237 $ (763,660)
============ ============ ============ ============
NET INCOME (LOSS) PER COMMON
SHARE -BASIC & DILUTED $ 0.00 $ (0.02) $ 0.00 $ (0.03)
============ ============ ============ ============
BASIC WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 31,564,870 23,701,357 31,564,647 23,701,357
============ ============ ============ ============
DILUTED WEIGHTED AVERAGE
COMMON SHARES OUTSTANDING 32,130,113 23,701,357 32,086,400 23,701,357
============ ============ ============ ============
4
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Six Months
Ended Ended
February 28, February 29,
2005 2004
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 91,237 $ (763,660)
Adjustments to reconcile net income (loss) to
net cash (used) by operating activities
Depreciation and amortization 205,083 81,924
Amortization of financing costs 1,594 1,593
Interest expense converted into debt 166,611 158,577
Accretion of asset retirement obligation 12,605 42,304
Stock options issued for director service 15,248 --
Changes in assets and liabilities
(Increase) in accounts receivable (888,567) (6,553)
(Increase) in joint billings receivable (109,373) --
(Increase) in prepaids and other receivables (19,032) (55,957)
Increase (decrease) in accounts payable 122,121 (72,184)
Increase in net profits interest liability 354,954 --
Increase (decrease) in accrued expenses 48,953 (33,748)
Other -- (50,000)
----------- -----------
Net cash provided (used) by operating activities 1,435 (697,704)
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for furniture and equipment (10,609) (237)
Cash paid for oil and gas properties (1,659,181) (238,200)
Deferred acquisition costs -- (250,000)
Proceeds from exercise of exploration options 750,000 --
Proceeds from exercise of stock options 2,900 --
Proceeds from sale of oil and gas properties 49,280 186,016
Other -- (10,000)
----------- -----------
Net cash (used) in investing activities (867,610) (312,421)
----------- -----------
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES -- --
----------- -----------
NET DECREASE IN CASH (866,175) (1,010,125)
CASH, BEGINNING OF PERIODS 6,038,156 3,657,938
----------- -----------
CASH, END OF PERIODS $ 5,171,981 $ 2,647,813
=========== ===========
5
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(continued)
SIX MONTHS ENDED FEBRUARY 28, 2005 AND FEBRUARY 29, 2004
(Unaudited)
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
During the six months ended February 28, 2005 and February 29, 2004, the asset
retirement obligation increased by $13,660 and $0, respectively.
6
PYR ENERGY CORPORATION
Notes to Consolidated Financial Statements
February 28, 2005
(Unaudited)
The accompanying interim financial statements of PYR Energy Corporation are
unaudited. In the opinion of management, the interim data includes all
adjustments, consisting only of normal recurring adjustments, necessary for a
fair presentation of the results for the interim period. The results of
operations for the three and six months ended February 28, 2005 are not
necessarily indicative of the operating results for the entire year.
We have prepared the financial statements included herein pursuant to the
rules and regulations of the Securities and Exchange Commission. Certain
information and footnote disclosure normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to such rules and regulations. We believe the
disclosures made are adequate to make the information not misleading and
recommend that these condensed financial statements be read in conjunction with
the financial statements and notes included in our Form 10-KSB for the year
ended August 31, 2004.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
-------------------------------------------
Use of Estimates - The preparation of financial statements in conformity
with generally accepted accounting principles requires management 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.
The Company's financial statements are based on a number of significant
estimates, including reliability of receivables, selection of the useful
lives for property and equipment, timing and costs associated with its
retirement obligations and oil and gas reserve quantities which are the
basis for the calculation of depreciation, depletion and impairment of oil
and gas properties.
The oil and gas industry is subject, by its nature, to environmental
hazards and clean-up costs. At this time, management knows of no
substantial costs from environmental accidents or events for which it may
be currently liable. In addition, the Company's oil and gas business makes
it vulnerable to changes in wellhead prices of crude oil and natural gas.
Such prices have been volatile in the past and can be expected to be
volatile in the future. By definition, proved reserves are based on current
oil and gas prices and estimated reserves, which is considered a
significant estimate by the Company, which is subject to changes. Price
declines reduce the estimated quantity of proved reserves and increase
annual amortization expense (which is based on proved reserves) and may
impact the impairment analysis of the Company's full cost pool.
Earnings (Loss) Per Share - Basic earnings (loss) per common share is
computed by dividing net earnings (loss) attributed to common stock by the
weighted average number of common shares outstanding during each period.
Diluted earnings (loss) per share is computed by adjusting the average
number of common shares outstanding for the dilutive effect, if any, of
convertible equity instruments, such as convertible notes payable, stock
options and warrants. The following table sets forth the computation of
basic and diluted earnings per share:
7
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
2/28/2005 2/29/2004 2/28/2005 2/29/2004
----------- ----------- ----------- -----------
Numerator:
Numerator for basic and diluted
earnings per share - income (loss)
available to common stockholders 30,205 (401,858) 91,237 (763,660)
Denominator:
Denominator for basic earnings
per share -weighted average
shares outstanding 31,564,870 23,701,357 31,564,647 23,701,357
Effect of dilutive securities -
stock options and warrants 565,243 -- 521,753 --
----------- ----------- ----------- -----------
Denominator for diluted
earnings per common share 32,130,113 23,701,357 32,086,400 23,701,357
=========== =========== =========== ===========
Basic earnings (loss)
per common share $ 0.00 $ (0.02) $ 0.00 $ (0.03)
=========== =========== =========== ===========
Diluted earnings (loss)
per common share $ 0.00 $ (0.02) $ 0.00 $ (0.03)
=========== =========== =========== ===========
Share Based Compensation - In October 1995, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation (SFAS 123), effective for fiscal
years beginning after December 15, 1995. This statement defines a fair
value method of accounting for employee stock options and encourages
entities to adopt that method of accounting for its stock compensation
plans. SFAS 123 allows an entity to continue to measure compensation costs
for these plans using the intrinsic value based method of accounting as
prescribed in Accounting Pronouncement Bulletin Opinion No. 25, Accounting
for Stock Issued to Employees (APB 25). The Company has elected to continue
to account for its employee stock compensation plans as prescribed under
APB 25. Had compensation cost for the Company's stock-based compensation
plans been determined based on the fair value at the grant dates for awards
under those plans consistent with the method prescribed in SFAS 123, the
Company's net income (loss) and income (loss) per share for the quarters
ended February 28, 2005 and February 29, 2004 would have been increased
(decreased) to the pro forma amounts indicated below:
8
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
2/28/2005 2/29/2004 2/28/2005 2/29/2004
----------- ----------- ----------- -----------
Net income (loss) as reported $ 30,205 $ (401,858) $ 91,237 $ (763,660)
Deduct: stock-based
compensation costs
under SFAS No. 123 (82,839) (162,444) (165,678) (295,064)
----------- ----------- ----------- -----------
Pro forma net income (loss) (52,634) (564,302) (74,441) (1,058,724)
=========== =========== =========== ===========
Pro forma basic and diluted
net income per share:
As reported $ 0.00 $ (0.02) $ 0.00 $ (0.03)
Pro forma $ 0.00 $ (0.02) $ 0.00 $ (0.04)
The calculated value of stock options granted under these plans, following
calculation methods prescribed by SFAS 123, uses the Black-Scholes stock
option pricing model with the following assumptions used:
February 28, February 29,
2005 2004
---- ----
Expected option life-years 5 5-7
Risk-free interest rate 3.3 - 3.7% 3.0 %
Dividend yield 0.00% 0.00%
Volatility 58-83% 100-125%
Reclassification - Certain reclassifications have been made to the February
29, 2004 financial statements to conform to February 28, 2005 presentation.
Such reclassifications had no effect on net loss.
Recent Accounting Pronouncements - In December 2004, the Financial
Accounting Standards Board (FASB) issued Statement of Financial Accounting
Standards (SFAS) No. 123(R), "Share-Based Payment". This statement requires
all entities to recognize compensation expense in an amount equal to the
fair value of share-based payments granted to employees. SFAS No. 123(R) is
effective the first reporting period beginning after December 15, 2005. Due
to the recent adoption of SFAS No. 123(R), the Company has not determined
the future impact on its financial statements; however, it will result in
additional future financial reporting expense to the Company when
implemented.
2. ACQUISITION OF PROPERTIES:
--------------------------
In May 2004, the Company acquired certain oil and gas properties from Venus
Exploration Inc. ("Venus") for cash consideration of $3,230,000. The
financial statements therefore reflect the revenue and other operating
expenses associated with these properties since the date of acquisition.
The purchase also provides for the Company to pay a net profits interest
payable to the Venus Exploration Trust ("Trust"). During the three and six
months ended February 28, 2005, the Company accrued $232,588 and $354,954,
respectively, which is payable to the Trust based on the net profits
interest agreement; however, the company does not anticipate that it will
be required to pay this amount as the Company intends to drill additional
wells in the future on the property subject to payout. Costs incurred in
connection with additional drilling would reduce this liability; however,
in the unlikely event the Company does not incur additional drilling costs,
such amount would then be payable to the Trust. The net profits interest,
which applies only to the exploration and exploitation projects on the
Venus acreage acquired, varies from 25% to 50% with respect to different
Venus exploration and exploitation project areas, and decreases by one-half
of its original amount after a total of $3,300,000 in net profits proceeds
has been paid to the Trust.
9
3. CONTINGENCY
-----------
We are currently in dispute with the operator of the Sun Fee #1, Sampson
Lone Star L.P. ("Sampson"), concerning the pooling of certain lands into
the production unit at Nome Field. The pooling of these lands in which the
Company does not own an interest, comprises approximately 32% of the unit
area, and may result in a reduction of working interest and net revenue
interest, relative to production from the Sun Fee #1, attributable to the
Company. If the current pooling were to stand, our working interest in the
well would be reduced from 8.33% to 5.19%. The Company strongly believes
that the lands in question are `Non-Productive', and therefore not eligible
for pooling, based on all available geological, seismic, and existing well
data. As a result of this dispute, we will vigorously pursue and defend our
rights to our proportionate share of production and revenue from the Sun
Fee #1 with all legal avenues and remedies available. For this reason, the
Company has not signed any of the proposed production and revenue division
orders, and has not received any revenue, attributable to the well, to
date. If we undertake legal action against the operator relative to this
issue, which we currently intend, it may result in all revenues
attributable to the Sun Fee #1 well being held in suspense until the legal
action is completed. If the outcome of the dispute results in the operator
recognizing our working interest of 8.33%, the increased working interest
could potentially result in increased revenue to the Company and increased
net profits liability to Venus Exploration Trust, subject to the net
profits interest agreement. The oil and gas receivable pertaining to the
Sun Fee #1 well is approximately $1,011,000 at February 28, 2005.
For the quarter ended February 28, 2005, we accrued approximately $512,000
in royalty and working interest revenues from the Sun Fee #1. As a result
of the dispute with Sampson, revenues were accrued at the lower working
interest percentage (5.19%) as stated by the operator.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF
OPERATION
The following discussion should be read in conjunction with the Financial
Statements and Notes thereto referred to in "Item 1. Financial Statements" of
this Form 10-QSB.
Overview
PYR Energy Corporation (referred to as "PYR," the "Company," "we," "us" and
"our") is an independent oil and gas exploration and production company, engaged
in the exploration, development and acquisition of crude oil and natural gas
reserves. Our exploration activities are focused in select areas of the Rocky
Mountains, Texas and Gulf Coast, Southeast Alberta, and in the San Joaquin Basin
of California. We continue to focus our exploration efforts and advanced
technical expertise on the pre-drill phases of our high potential exploration
projects in the Rocky Mountain region.
Liquidity and Capital Resources
Our primary sources of liquidity historically have been from placements of
common stock and convertible notes, and to a much lesser extent, cash provided
by operating activities. Our primary use of capital has been for the
acquisition, development, and exploration of oil and natural gas properties. As
we pursue growth, we continually monitor the capital resources available to us
to meet our future financial obligations, planned capital expenditure activities
and liquidity. Our future success in growing proved reserves and production is
highly dependent on capital resources available to us, and our success in
finding or acquiring additional reserves. At February 28, 2005, we had
approximately $4,935,795 in working capital.
During the quarter ended February 28, 2005, our capitalized costs for oil
and gas properties increased by approximately $512,457. The increase reflects
net costs incurred for undeveloped leasehold, drilling and completion, workover,
geological and geophysical costs, delay rentals and other related direct costs
with respect to our exploration and development prospects, which is further
discussed in Capital Expenditures and Summary of Exploration Projects.
10
It is anticipated that the continuation and future development of our
business will require additional, and possibly substantial, capital
expenditures. We have no reliable source for additional funds for administration
and operations to the extent our existing funds have been utilized. To limit
capital expenditures, we intend to form industry alliances and exchange an
appropriate portion of our interest for cash and/or a carried interest in our
exploration projects. We may need to raise additional funds to cover capital
expenditures. These funds may come from cash flow, equity or debt financings, a
credit facility, or sales of interests in our properties, although there is no
assurance additional funding will be available or that it will be available on
satisfactory terms.
CAPITAL EXPENDITURES
During the quarter ended February 28, 2005, we incurred approximately
$570,865 of capital costs for our oil and gas properties. This amount includes
costs associated with undeveloped leasehold, drilling and completion, workover,
geological and geophysical costs, delay rentals, and other related direct costs
with respect to our exploration and development prospects. Revenues from oil and
gas production during the quarter were $1,195,671.
We currently anticipate that we will participate in the drilling of up to
six exploration wells during the calendar year ending December 31, 2005.However,
there can be no assurance that any such wells will be drilled and if drilled
that any of these wells will be successful. We anticipate spending a minimum of
$3,000,000, possibly up to $7,000,000 million, on exploration and development
activities during the calendar year ending December 31, 2005. In total, we hope
to drill between 8 and 12 wells by the end of the calendar year, depending on
rig availability.
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.
PRODUCTION AND RESERVES
For the quarter ended February 28, 2005, production averaged 1,865 Mcfe per
day compared to 1,584 Mcfe per day for the quarter ended November 30, 2004. The
18% increase in average daily production was primarily due to a full quarter of
production from the Sun Fee #1-ST, a well in the Nome Field that reached payout
status in mid-October, 2004.
Total proved reserves, at calendar year end (December 31, 2004), were 6.73
Bcfe based on external estimation. Estimated 'total proved' reserves increased
by 22% when compared to estimates made at August 31, 2004, and by 41% when
compared to the estimated 'total proved' reserves on May 31, 2004. The increase
in 'total proved' reserves results from additions to the 'proved developed
producing' and 'proved un-developed' classification attributable to several new
discoveries resulting from drilling, primarily in South Texas. The external
estimated 'total proved' reserves includes the addition of 'proved developed
producing' reserves at the Sun Fee #1-ST well in Jefferson County, Texas, where
the Company's working interest is currently under dispute with the operator of
the well. Reserves for the well were estimated using the Company's claimed
higher working interest of 8.33%. Reserve estimations using the operator's
proposed working interest of 5.19%, currently being used to accrue revenue,
results in a reduction of 'proved developed producing' reserves of 101 MMcfe
giving 'total proved' reserves estimated at 6.63 Bcfe. Present value, discounted
at 10%, for the 'total proved' reserves is estimated to be $14.49 million at
December 31, 2004, compared to $6.94 million estimated at May 31, 2004. The 109%
increase in estimated present value is attributable to higher product prices and
increased reserves from drilling.
SUMMARY OF EXPLORATION PROJECTS
Our exploration activities are focused primarily in select areas of the
Rocky Mountains, Texas and Gulf Coast, Southeast Alberta, and in the San Joaquin
Basin of California. Advanced seismic imaging of the structural and
stratigraphic complexities common to these regions provides us with the enhanced
ability to identify significant oil and gas reserve potential. A number of these
projects offer multiple drilling opportunities with individual wells having the
potential of encountering multiple reservoirs.
11
The following is a summary of our exploration areas and significant
projects. While actively pursuing specific exploration activities in each of the
following areas, we continually review additional opportunities in these core
areas and in other areas that meet our exploration criteria.
ROCKY MOUNTAIN EXPLORATION
Montana Foothills Project. This extensive natural gas exploration project,
located in west-central 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 the 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, the Unocal #1-B30, drilled in 1989 to a depth of 17,817 feet, which was
plugged and abandoned after testing. 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. Within the Rogers Pass acreage block,
we have undertaken extensive seismic analysis and geological study, resulting in
the identification of multiple untested, prospective structures.
In March 2004, we signed an Exploration Option Agreement with a subsidiary
of Suncor Energy, Incorporated, covering our Rogers Pass exploration project. We
currently control approximately 241,800 gross and 226,300 net leasehold acres in
the Rogers Pass project. Pursuant to our agreement with the subsidiary of Suncor
Energy, Suncor Energy Natural Gas America, Inc. ("SENGAI"), SENGAI has paid us a
$500,000 option fee for a technical evaluation period of up to three months. On
August 31, 2004 SENGAI exercised its option to drill an initial test well at
Rogers Pass, and paid us $750,000 in the form of a prospect fee (received in
September 2004).
On March 11, 2005, drilling activities began at the Company's Rogers Pass
Project in the Montana Foothills. The Suncor Energy Natural Gas America, Inc.
#14063-12 Flesher Pass well, located approximately twenty-five miles northwest
of Helena, Montana, will test a potential structural closure within the Montana
Foothills trend. Anticipated target depth for the prospect is estimated to be
approximately 14,500 feet. SENGAI will bear 100% of the costs of the well, to a
depth sufficient to evaluate the Mississippian, to earn a 100% working interest
in 100,000 acres of the project area. SENGAI will have the option to pay a
second prospect fee of $1,250,000 and drill a second test well, to be spud by
December 31, 2005. By paying this second prospect fee and bearing 100% of the
costs of the second well, SENGAI will earn a 100% working interest in the
remaining acreage within the project area. We will retain a 12.5% overriding
royalty interest, subject to amortized recovery of gas plant and certain
transportation costs, covering all earned acreage within the Rogers Pass project
area.
Mallard Project. The Mallard project, located within the Overthrust Belt of
southwest Wyoming, is a sour gas and condensate exploration prospect in Uinta
County, Wyoming. We believe that 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.
The agreement we entered into with two private companies ("the
Participants") in December 2003 requires the Participants to drill the initial
test well at the Mallard Prospect to earn part of our acreage position within a
designated area of mutual interest. We currently control 4,160 net leasehold
acres within the AMI. During the fiscal year ended 2004, the partners paid us
approximately $450,000 in prospect fees and pro-rata development costs. The
12
Mallard well started drilling in mid-July and Intermediate casing was set to
9,735 feet in the Thaynes Formation. The Bureau of Land Management suspended
drilling activities at Mallard, effective December 1, 2004, due to wildlife
critical winter range restrictions. As a result, the well has been temporarily
suspended and secured in compliance with applicable federal and state
regulations, until the wildlife restrictions are lifted in mid - 2005. We are
participating with a 5% working interest in the drilling of Mallard, and will be
carried to casing point, at an estimated total depth of 15,500 feet, for an
additional 23.75% working interest. After casing point, we will have a 28.75%
working interest in the initial test well and all subsequent wells in the
prospect.
Cumberland Project. Drilling at the Cumberland prospect located within the
Overthrust Belt of southwest Wyoming, started in early November 2004. The
Cumberland #1-16 State well reached total drilling depth of 10,860 feet in the
Nugget Sandstone. Based on preliminary log analysis, the Nugget zone of interest
appears to be nonproductive, and the well will be plugged and abandoned. Further
evaluation of the log data will be analyzed and studied to determine any
remaining prospective targets within our 6,233 net leasehold area of mutual
interest ("AMI"). PYR participated in the drilling of the well at a 10% working
interest and was carried for an additional 22.5% working interest to casing
point.
Ryckman Creek Project. We have recently leased approximately 1,820 net
acres, covering the majority of the abandoned Ryckman Creek field, in the
Overthrust of southwestern Wyoming. Ryckman Creek, located 5 miles southwest of
our Cumberland prospect, was discovered in 1975 and produced approximately 250
Bcfe prior to abandonment. We believe that significant remaining recoverable gas
reserves were stranded in Ryckman Creek upon abandonment. We are currently
analyzing production and geologic data to determine potential reserves in
multiple zones, including the Twin Creek, Nugget, and Thaynes Formations, in the
field. Due to winter activity restrictions, it is anticipated that a well may be
drilled at Ryckman Creek in mid-2005, and, based on our analysis, we may decide
to sell part of our 100% working interest in the project.
TEXAS AND GULF COAST EXPLORATION:
In May 2004, we acquired interests from Venus Exploration, Inc. ("Venus")
in certain producing properties with estimated proved reserves of 4.784 Bcfe for
approximately $3,230,000 (excluding acquisition expenses and subject to
retention, by the Venus Exploration Trust, of a net profits interest covering
the non-productive exploration projects). This equates to $0.67 per Mcf, with a
PV-10 value of $6.94 million. The purchase also provides for us to pay a net
profits interest payable to the Venus Exploration Trust. The net profits
interest, which applies only to the exploration and exploitation projects on the
Venus acreage being acquired, varies from 25% to 50% with respect to different
Venus exploration and exploitation project areas, and decreases by one-half of
its original amount after a total of $3,300,000 in net profits proceeds has been
paid to the Trust. Venus was in Chapter 11 Bankruptcy, and the properties were
acquired through public auction as approved by the United States Bankruptcy
Court. To finance the purchase, we primarily used existing cash reserves and
also a portion of the proceeds from a private placement of common stock.
Oil and gas interests acquired from Venus include producing oil and gas
properties, exploitation drilling projects, and exploration acreage. The assets
acquired include interests in 80 non-operated wells in Utah, Oklahoma and Texas.
In Texas, we have interests in three projects that were drilled and
completed over this past summer. Two of the three wells, the Nome and Madison
Prospects, were completed as producers and are currently flowing to sales lines.
These two successful projects are, upon reaching payout, subject to a 50% net
profits interest payable to the Venus Exploration Trust.
Tortuga Grande prospect, located in east Texas, is a project to test the
productivity of the Cotton Valley Sand section at depths ranging from 13,000 to
14,500 feet. Drilled originally in 1984 for deeper targets, the Brady #1 is the
only deep well on the structure, and had shows in the Cotton Valley Sand, but
was never fracture stimulated. Log analysis indicates that the well contains
approximately 322 feet of potential pay greater than 8% porosity. The Brady #1,
in which we have a 20% carried working interest, was re-entered and the middle
Cotton Valley Sand section was fracture stimulated and tested. Results of the
test were inconclusive and the partners continue to evaluate the test data. The
partners may decide at a future date to drill another well to test the Cotton
Valley within the project area. Should this occur, PYR would be responsible for
20% of the costs of any additional well. In all additional locations within the
Tortuga Grande area of mutual interest, we will participate with a cost bearing
20% working interest. We currently control approximately 5,600 net leasehold
13
acres within the project. It is anticipated that the partners will drill another
test well at Tortuga Grande during the second calendar quarter of 2005. This
proposed well will be approximately 1000 feet structurally high to the Brady #1
and should test a complete section of Cotton Valley Sand. The operator has built
the location for the well, and is currently waiting on rig availability prior to
commencing drilling activities, which are anticipated to begin within the next
month or two.
Nome Field was discovered in 1994, and our interpretation of subsequently
acquired 3D seismic over the field indicates the presence of numerous
undeveloped fault blocks. Multiple structural closures and associated bright
spot locations have been identified at Nome based on the 3D seismic. PYR owns a
1.5% overriding royalty interest with an additional 8.33% working interest,
after project payout, in the project. Production in the Sun Fee #1 well, from
the upper Yegua, was initiated in late May 2004, and over the past months, the
well has averaged approximate production of 15MMcfe per day. Cumulative
production since inception is in excess of 3.0 Bcfe through February 7, 2005.
Payout on the Sun Fee #1 occurred on October 13th, 2004 and PYR is currently a
working interest participant in the well. We and our partners control
approximately 4,200 acres of gross leasehold acres in the project. PYR plans, in
the near future, to submit a drilling operations AFE (Authorizaton for
Expenditure) to the partners to drill, test and complete a well offsetting the
current Sun Fee #1 location.
We are currently in dispute with the operator of the Sun Fee #1, Sampson
Lone Star L.P. ("Sampson"), concerning the pooling of certain lands into the
production unit. The pooling of these lands in which the Company does not own an
interest, comprises approximately 32% of the unit area, and may result in a
reduction of working interest and net revenue interest, relative to production
from the Sun Fee #1, attributable to the Company. If the current pooling were to
stand, our working interest in the well would be reduced from 8.33% to 5.19%.
The Company strongly believes that the lands in question are `Non-Productive',
and therefore not eligible for pooling, based on all available geological,
seismic, and existing well data. As a result of this dispute, we will vigorously
pursue and defend our rights to our proportionate share of production and
revenue from the Sun Fee #1 with all legal avenues and remedies available. For
this reason, the Company has not signed any of the proposed production and
revenue division orders, and has not received any revenue, attributable to the
well, to date. If we undertake legal action against the operator relative to
this issue, which we currently intend, it may result in all revenues
attributable to the Sun Fee #1 well being held in suspense until the legal
action is completed.
For the quarter ended February 28, 2005, we accrued approximately $512,000
in royalty and working interest revenues from the Sun Fee #1. As a result of the
dispute with Sampson, revenues were accrued at the lower working interest
percentage (5.19%) as stated by the operator. The oil and gas receivable
pertaining to the Sun Fee #1 well is approximately $1,011,000 at February 28,
2005. Both revenues and costs associated with the production from the Sun Fee
#1, as well as the costs incurred on the Nome Project, are subject to the net
profits interest agreement we hold with Venus Exploration Trust ("Trust"). The
net profits interest agreement arose out of the acquisition of properties from
Venus Exploration Inc. ("Venus") in May 2004. The agreement varies from 25% to
50% with respect to different Venus exploration and exploitation project areas,
and decreases by one-half of its original amount after a total of $3,300,000 in
net profits proceeds has been paid to the Trust. The amount of net profits
interest liability recognized over time is subject to fluctuation, because both
revenues and costs associated with production from any wells and other costs
incurred on the designated exploration and exploitation project areas will
increase or decrease over a given period of time. As of February 28, 2005, we
accrued a net profits interest liability of $354,954 payable to the Trust.
Madison prospect, located in the northern part of the Constitution Field,
is an exploitation project to test multiple sand intervals within the expanded
Yegua section, downthrown to a major growth fault. The prospect involves
sidetracking an existing cased hole updip to test multiple sand targets at a
location offsetting, but significantly high to Doyle sand production from the
Texaco #1 Doyle well within the field. The location is also offset to the Texaco
#1 Sanders Gas Unit well, which tested the Doyle sand interval at a rate of
1,176 Bcf/d and 2.7 MMcf/d with no water. This well was subsequently plugged and
abandoned in the Doyle interval and never produced from the zone. The Maness Gas
Unit location represents a proved undeveloped location for Doyle sand, 183 feet
structurally high to the equivalent produced zone in the Texaco Doyle #1 well.
The current well has been drilled to total depth, production casing has been
run, and the well is currently producing at a rate of approximately 5.00 MMcfe
per day. We own a 0.5% overriding royalty interest that converts to a 12.5%
working interest in the project after payout (which has not been reached) of the
initial test well. The operator has converted an existing wellbore within the
project area into a water disposal well, and is planning to drill an offset
development well (Maness GU#2). The cost of the water disposal well will be
covered under the payout account, and we will participate for 12.5% working
interest in the drilling of this development well. It is anticipated that the
offset well will begin drilling operations in May 2005, based on rig
availability.
14
Cotton Creek prospect, located in Jefferson County, Texas, is adjacent to
the Nome project. The prospect is located approximately one mile west of the
productive Sun Fee #1 well in the same structural fault block. PYR owns a 50%
working interest in the project and controls with its partner approximately 500
acres of leasehold. It is anticipated that an initial test well will be drilled
in 2005. PYR will retain approximately 25% working interest in the well and will
farm-out the remainder of its interest to an industry partner.
Merganser prospect, located in Leon County, Texas, targets Cotton Valley
and Bossier sandstone reservoirs in an undrilled structural feature defined by
3D seismic data. The prospect occupies a fault-bounded salt-withdrawal trough
resulting in potential significant thickening of the Bossier and Cotton Valley
sand sections. The prospect location is structurally and stratigraphically
downdip from Cotton Valley production as well as updip from recent Bossier
productive discoveries. PYR owns 100% of the prospect and controls in excess of
1,500 gross acres of leasehold.
Bayou Duralde Project, located in Evangeline Parish, LA, is an exploration
program to identify and drill potential gas reservoirs in Yegua/Cockfield
channel complexes. PYR owns a 25% working interest in the project and controls,
along with its partner, in excess of 3,000 net acres of leasehold. PYR will
participate with a 15% cost bearing interest and farm-out the remainder of its
working interest. It is anticipated that the initial test well at Bayou Duralde
will begin drilling operations in early May 2005, contingent upon contracting an
available drilling rig.
In the Canadian River Project, located in Eastern Oklahoma, the Orbison
#3-11, a Cromwell development well operated by Questar, started drilling in
mid-March. PYR has a 28.98% WI in the well.
Hansford Project, located in the Texas panhandle, is a development project
at the southern end of the Houghton Embayment. Main producing horizons within
the Hansford area include the upper and lower Morrow as well as the Chester.
Purchased originally as part of the Venus Exploration acquisition, the Company
has recently purchased additional working interest in two wells and associated
undeveloped acreage at Hansford. Approximately 42% working interest in the
Lackey #152-1 well and acreage, as well as 15% working interest in the Archer
Trust well and acreage, were purchased for approximately $440,000. The Company
believes that additional development drilling opportunities targeting gas are
available on the un-developed acreage that was purchased at Hansford. The
Company has submitted a drilling AFE, to partners, to drill a development well
offsetting the Lackey #152-1. It is anticipated that this well will be drilled
during the summer of 2005 based on rig availability.
SOUTHEAST ALBERTA SHALLOW GAS REDEVELOPMENT PROJECT:
We have entered into two joint ventures, the Atlas Joint Venture and the
Blue River Joint Venture, to redevelop shallow gas reserves in southeastern
Alberta, Canada. Southeastern Alberta has been the site of significant shallow
gas development drilling and production over the last two decades. We have
undertaken geologic and engineering studies of the region, and believe that many
wellbores in the region were prematurely suspended and/or abandoned due to water
coning and production. These premature well abandonments suggest the possibility
that significant additional reserves may remain in a number of shallow gas
reservoirs in local areas within the Southeastern Alberta.
We own a 5% working interest in the Atlas Joint Venture, which has
identified multiple potential re-entry and redevelopment opportunities for which
the Joint Venture intends to acquire the right to participate. The first well
has been re-entered, re-perforated, and completed in the upper Bow Island sand.
The well is currently producing into a sales line during long term testing. An
offset wellbore is currently being permitted for re-entry based on results from
the initial well. A number of other prospects are being leased and permitted at
this time.
We also own a 25% working interest in the Blue River Joint Venture, which
intends to operate in different areas of southeastern Alberta. Initial
investigation indicates multiple wells that exhibit an appropriate production
type decline curve, potential disposal interval, and gas reservoir. We are
currently undertaking detailed geologic and production analysis to refine
certain areas, for which the Joint Venture will undertake to acquire and develop
prospects for recompletion or drilling.
15
SAN JOAQUIN BASIN, CALIFORNIA
Wedge Prospect. 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 further northwest of the East Lost
Hills Area of Mutual Interest and can be encountered as much as 3,000 feet
higher. Despite repeated attempts to facilitate drilling interest at Wedge
during 2003, no industry interest was generated sufficient to put together a
drilling partnership during the year. As a result, PYR re-evaluated its acreage
position at Wedge and made the decision to consolidate the leasehold by
abandoning non-core prospect acreage in the project area. We currently control
approximately 3,500 gross and net acres here. Our approach is to sell down our
working interest to industry partners, and retain a 25% to 50% working interest
in this prospect.
Bulldog Prospect. 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. During 2003, we re-evaluated our acreage position at Bulldog and
consolidated the leasehold by releasing approximately 3,200 non-core acres in
the project area. We currently control approximately 11,900 gross and 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.
Blizzard Prospect. This project is a 3D seismic derived exploration and
exploitation program offsetting the Rio Viejo field at the south end of the San
Joaquin Basin. A linear sand body, stratigraphically higher than any of the
productive Rio Viejo sands, has been identified, north of the field, on the
seismic data and represents an exploration opportunity for new reserves.
Additionally, analysis of the seismic data over the field suggests that up to
two additional undrilled field exploitation locations may exist. PYR owns 100%
of the prospect and controls approximately 2,500 net and gross acres.
CASH FLOW
The six months ended February 28, 2005 ("2005") compared with the six months
ended February 29, 2004 ("2004").
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided (used) by operating activities was $1,435 and ($697,704)
for the six months ended February 28, 2005 and February 29, 2004, respectively.
A discussion of these and other items are presented below.
Net income (loss). See discussion of net income (loss) in "Results of
Operations" section below.
Depreciation and amortization. Depreciation and amortization expense was
$205,083 in 2005, compared to $81,924 in 2004. The 2005 expense includes
$199,683 of depletion of oil and gas properties. There was no depletion expense
from oil and gas properties in 2004, due to an impairment taken against our
entire amortizable full cost pool at August 31, 2003, and accordingly, there
were no costs to amortize; however, included in depreciation expense reported
for 2004, is $75,642 of depreciation of Asset Retirement Obligation assets.
Accrued interest converted into debt. For the six months ended 2005,
accrued interest converted into debt was $166,611 compared to $158,577 for the
six months ended 2004. Both amounts reflect interest accrued on the $6,000,000
convertible notes issued May 24, 2002.
Accretion of asset retirement obligation. During the six months ended 2005
and 2004, accretion of unamortized discount of the Asset Retirement Obligation
liability was $12,605 and $42,304, respectively. The prior year is higher
because the estimated lives of the East Lost Hills properties escalated the
accretion rate, while the current year includes properties (acquired from Venus
Exploration Inc. in May 2004) with longer estimated lives, and hence a lower
accretion rate.
16
Stock options issued for director service. During the six months ended 2005
and 2004, stock options issued for director service were $15,248 and $0,
respectively. The current year activity represents stock options issued to a
former member of the Company's Board of Directors for services rendered.
Accounts receivable. For the six months ended 2005 and 2004, accounts
receivable increased $888,567 and $6,553, respectively. The increase in 2005
related principally to revenue receivables generated from the Sun Fee #1 well.
See Note 3 to the financial statements regarding contingency on the Sun Fee #1
and further discussion below regarding the net profits interest liability
associated with this well.
Joint billings receivable. For the six months ended 2005 and 2004, joint
billings receivable increased $109,373 and $0, respectively. The increase in
2005 relates principally to undeveloped leasehold costs the Company paid on
behalf of its partners for certain projects. Billings to partners were made
pursuant to participation agreements the Company has with its designated
partners.
Prepaid expenses and other. During the six months ended 2005, prepaid
expenses increased $19,032, compared to an increase of $55,957 during the six
months ended 2004. The increase in 2005 primarily reflects timing of payments.
The increase in 2004 reflected higher Directors and Officers liability insurance
premiums.
Accounts payable. During the six months ended 2005, accounts payable and
accruals increased $122,121, compared to a decrease of $72,184 during the six
months 2004. The increase in the current year primarily resulted from the timing
of payments. The decrease in 2004 reflected primarily decreased amounts due to
the operator of the East Lost Hills wells.
Net profits interest liability. During the six months ended 2005, the
cumulative net profits interest liability increased $354,954, compared to $0
during the six months ended 2004. The net profits interest agreement with Venus
Exploration Trust ("Trust") agreement arose out of the acquisition of properties
from Venus Exploration Inc. ("Venus") in May 2004. The current year increase
resulted from an accrued liability to the Trust for net profits accrued on the
Sun Fee #1 well in the Nome Project.
Accrued expenses. During the six months ended 2005 and 2004, accrued
expenses increased $48,953 and decreased $33,748, respectively. The change in
the current year primarily reflects an increase in accrued lease operating
costs. The increase was partially offset by the conversion of accrued interest
payable into convertible debt. The $6,000,000 4.99% convertible notes were
issued on May 24, 2002. The decrease in 2004 relates to the conversion of
accrued interest payable into convertible debt.
CASH FLOWS FROM INVESTING ACTIVITIES
Cash paid for oil and gas properties. During the six months ended 2005, we
paid $1,659,181 for oil and gas properties, compared to $238,200, during the six
months ended 2004. The increase in 2005 includes increased leasehold and lease
rental activity, primarily in the Rocky Mountain and Gulf Coast regions,
including the acquisition of additional working interest in the Hansford project
for approximately $440,000, and costs associated with a saltwater disposal well
conversion. The increase in 2004 relates to costs incurred on exploration
projects in the California and the Rocky Mountain regions.
Proceeds from sale of exploration options. During the year ended August 31,
2004, we signed an Exploration Option Agreement with Suncor Energy Natural Gas
America, Inc. ("SENGAI"), covering our Rogers Pass exploration project in the
Foothills of west-central Montana. On August 31, 2004, SENGAI exercised its
option to drill an initial test well and paid us $750,000 in the form of a
prospect fee, which was received in September 2004. We received $0 in proceeds
from the sale of exploration options during the six months ended February 29,
2004.
Proceeds from sale of oil and gas properties. We received $25,000 in
prospect fees from a private company in connection with our Madison project, as
well as approximately $23,000 for the sale of a partial interest in our Bayou
Duralde project during the six months ended February 28, 2005. We received $0 in
proceeds from the sale of oil and gas properties during the six months ended
February 29, 2004.
17
CASH FLOWS FROM FINANCING ACTIVITIES
Cash provided by financing activities was $0 for the six months ended 2005
and 2004, respectively.
Results of Operations
The quarter ended February 28, 2005 ("2005") compared with the quarter
ended February 29, 2004 ("2004").
Operations during the quarter ended February 28, 2005 resulted in net
income of $30,205 compared to a net loss of ($401,858) for the quarter ended
February 29, 2004.
Oil and Gas Revenues and Expenses. During the quarter ended February 28,
2005, we recorded $1,195,671 in total oil and gas revenues. Of this amount, we
recorded $553,457 from the sale of 81,655 mcf of natural gas for an average
price of $6.78 per mcf, and $642,214 from the sale of 14,369 bbls of hydrocarbon
liquids for an average price of $44.69 per bbl. During the quarter ended
February 29, 2004, we recorded $44,376 in total oil and gas revenues. Of this
amount, we recorded $32,782 from the sale of 7,113 mcf of natural gas for an
average price of $4.61 per mcf and $11,594 from the sale of 398 bbls of
hydrocarbon liquids for an average price of $29.13 per barrel. 2005 revenues
increased largely due to the acquisition of properties from Venus Exploration
Inc. in May 2004 and subsequent drilling results, while 2004 revenues related
wholly to the Company's interest in East Lost Hills in California. Lease
operating expenses during the quarters ended 2005 and 2004, respectively, were
$203,153 and $21,681.
Accretion Expense. We recorded $6,307 and $21,152, respectively, for the
quarters ended 2005 and 2004, of accretion of the unamortized discount of the
Asset Retirement Obligation liability. The prior quarter is higher because the
estimated lives of the East Lost Hills properties escalated the accretion rate,
while the current quarter includes properties (acquired from Venus Exploration
Inc. in May 2004) with longer estimated lives, and hence a lower accretion rate.
Net Profits Interest Expense. The net profits interest agreement with Venus
Exploration Trust ("Trust") agreement arose out of the acquisition of properties
from Venus Exploration Inc. ("Venus") in May 2004. The agreement varies from 25%
to 50% with respect to different Venus exploration and exploitation project
areas, and decreases by one-half of its original amount after a total of
$3,300,000 in net profits proceeds has been paid to the Trust. For the quarter
ended February 28, 2005, we accrued net profits interest expense of $232,588 in
connection with net profits realized for the Sun Fee #1 well for the quarter
ended February 28, 2005. For the quarter ended February 29, 2004, there was no
net profits interest expense recognized.
Depreciation, Depletion and Amortization. We recorded $167,046 and $41,804,
respectively, in depreciation, depletion and amortization expense for the
quarters ended 2005 and 2004. Of these amounts, we recorded $164,861 and $0,
respectively, in depreciation, depletion and amortization of oil and gas
properties for the quarters ended 2005 and 2004, respectively. The 2005 increase
was attributable to the properties acquired from Venus Exploration, Inc. in May
2004, which increased the amount of oil and gas production, and an increase in
the amortizable oil and gas asset base due to increased future development
costs. We recorded no depreciation, depletion and amortization expense from oil
and gas properties for the quarter ended February 29, 2004, due to an impairment
taken against our entire amortizable full cost pool at August 31, 2003, and
accordingly, there were no costs to amortize; however, included in depreciation
expense reported for 2004, is $37,821 of depreciation of Asset Retirement
Obligation assets. We recorded $2,185 and $3,983 in depreciation expense
associated with capitalized office furniture and equipment during the quarters
ended 2005 and 2004, respectively.
General and Administrative Expenses. General and administrative expenses
during the quarters ended 2005 and 2004 were $497,669 and $285,442,
respectively. The increase principally reflects an increase in salaries as a
result of hiring additional personnel and costs incurred related to the
implementation of a new computer system, both of which resulted from the
acquisition of properties from Venus Exploration Inc. in May 2004.
Interest Income. We recorded $24,833 and $5,041 in interest income for the
quarters ended 2005 and 2004, respectively. The increase was due to interest on
the funds received from the private placement of our common stock in May 2004.
18
Interest Expense. During the quarters ended 2005 and 2004, we recorded
interest expense of $84,342 and $81,196, respectively. The interest expense for
each year is associated with the May 24, 2002 sale of outstanding 4.99%
convertible notes due on May 24, 2009. We have reflected the outstanding balance
of these notes as Convertible Notes under Long Term Debt on our February 28,
2005 and August 31, 2004 consolidated balance sheets.
The six months ended February 28, 2005 ("2005") compared with the six
months ended February 29, 2004 ("2004").
Operations during the six months ended February 28, 2005 resulted in net
income of $91,237 compared to a net loss of ($763,660) for the six months ended
February 29, 2004.
Oil and Gas Revenues and Expenses. During the six months ended February 28,
2005, we recorded $2,278,181 in total oil and gas revenues. Of this amount, we
recorded $999,441 from the sale of 144,712 mcf of natural gas for an average
price of $6.91 per mcf, and $1,278,740 from the sale of 28,347 bbls of
hydrocarbon liquids for an average price of $45.11 per bbl. During the six
months ended February 29, 2004, we recorded $84,394 in total oil and gas
revenues. Of this amount, we recorded $63,500 from the sale of 14,600 mcf of
natural gas for an average price of $4.35 per mcf and $20,894 from the sale of
799 bbls of hydrocarbon liquids for an average price of $26.15 per barrel. 2005
revenues increased largely due to the acquisition of properties from Venus
Exploration Inc. in May 2004 and subsequent drilling results, while 2004
revenues related wholly to the Company's interest in East Lost Hills in
California. Lease operating expenses during the six months ended 2005 and 2004,
respectively, were $483,729 and $36,952.
Accretion Expense. We recorded $12,607 and $42,604, respectively, for the
six months ended 2005 and 2004, of accretion of the unamortized discount of the
Asset Retirement Obligation liability. The six months ended 2004 is higher
because the estimated lives of the East Lost Hills properties escalated the
accretion rate, while the six months ended 2005 includes properties (acquired
from Venus Exploration Inc. in May 2004) with longer estimated lives, and hence
a lower accretion rate.
Net Profits Interest Expense. The net profits interest agreement with Venus
Exploration Trust ("Trust") agreement arose out of the acquisition of properties
from Venus Exploration Inc. ("Venus") in May 2004. The net profits interest
agreement varies from 25% to 50% with respect to different Venus exploration and
exploitation project areas, and decreases by one-half of its original amount
after a total of $3,300,000 in net profits proceeds has been paid to the Trust.
For the six months ended February 28, 2005, we accrued net profits interest
expense of $354,954, in connection with net profits realized for the Sun Fee #1
well for the six months ended February 28, 2005. For the six months ended
February 29, 2004, there was no net profits interest expense recognized.
Depreciation Depletion and Amortization. We recorded $205,083 and $81,924,
respectively, in depreciation, depletion and amortization expense for the six
months ended 2005 and 2004. Of these amounts, we recorded $199,683 and $0,
respectively, in depreciation, depletion and amortization expense from oil and
gas properties for the six months ended 2005 and 2004. We recorded no
depreciation, depletion and amortization expense from oil and gas properties for
the six months ended 2004, due to an impairment taken against our entire
amortizable full cost pool at August 31, 2003, and accordingly, there were no
costs to amortize; however, included in depreciation expense reported for the
six months ended 2004, is $75,642 of depreciation of Asset Retirement Obligation
assets. The 2005 increase was attributable to the properties acquired from Venus
Exploration, Inc. in May 2004, which increased the amount of oil and gas
production, and an increase in the amortizable oil and gas asset base due to
increased future development costs. We recorded $5,400 and $6,282 in
depreciation expense associated with capitalized office furniture and equipment
during the six months ended 2005 and 2004, respectively.
General and Administrative Expenses. General and administrative expenses
during the quarters ended February 28, 2005 and 2004 were $1,009,056 and
$536,932, respectively. The increase principally reflects an increase in
salaries as a result of hiring additional personnel and an increase in audit and
legal fees, both of which resulted from the acquisition of properties from Venus
Exploration, Inc. in May 2004.
Interest Income. We recorded $45,132 and $10,608 in interest income for the
six months ended 2005 and 2004, respectively. The increase was due to interest
on the funds received from the private placement of our common stock in May
2004.
19
Interest Expense. During the six months ended 2005 and 2004, we recorded
interest expense of $167,675 and $160,550, respectively. The interest expense
for each year is associated with the sale of outstanding 4.99% convertible notes
due on May 24, 2009. The Company elected to add $166,611 and $158,577 of accrued
interest to the balance of the debt for the six months ended 2005 and 2004,
respectively. We have reflected the outstanding balance of these notes as
Convertible Notes under Long Term Debt on our February 28, 2005 and August 31,
2004 consolidated balance sheets.
20
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.
Revenue Recognition:
The Company recognizes oil and gas revenues from its interests in producing
wells as oil and gas is produced and sold from these wells. The Company has no
gas balancing arrangements in place. Oil and gas sold is not significantly
different from the Company's product entitlement.
Asset Retirement Obligations:
In 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement requires companies to record
the present value of obligations associated with the retirement of tangible
long-lived assets in the period in which it is incurred. The liability is
capitalized as part of the related long-lived asset's carrying amount. Over
time, accretion of the liability is recognized as an operating expense and the
capitalized cost is depreciated over the expected useful life of the related
asset. The Company's asset retirement obligations relate primarily to the
plugging, dismantlement, removal, site reclamation and similar activities of its
oil and gas properties. Prior to adoption of this statement, such obligations
were accrued ratably over the productive lives of the assets through
depreciation, depletion and amortization of oil and gas properties without
recording a separate liability for such amounts.
21
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 123(R), "Share-Based
Payment". This statement requires all entities to recognize compensation expense
in an amount equal to the fair value of share-based payments granted to
employees. SFAS No. 123(R) is effective the first reporting period beginning
after December 15, 2005. Due to the recent adoption of SFAS No. 123(R), the
Company has not determined the future impact on its financial statements;
however, it will result in additional future financial reporting expense to the
Company when implemented.
ITEM 3. CONTROLS AND PROCEDURES
As of the end of the period covered by this report, we conducted an
evaluation under the supervision and with the participation of the principal
executive officer and principal financial officer, of our disclosure controls
and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934 (the "Exchange Act")). Based on this evaluation, the
principal executive officer and principal financial officer concluded that our
disclosure controls and procedures are effective to ensure that the information
we are required to disclose in reports that we file or submit under the Exchange
Act is recorded, processed, summarized and reported within the time periods
specified in Securities and Exchange Commission rules and forms. There was no
change in our internal controls over financial reporting during our most
recently completed fiscal quarter that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
22
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings
Not Applicable
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None
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
Exhibit Index
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Number Description
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31 Rule 13a-14(a) Certifications of Chief Executive Officer and
Principal Financial Officer
32 Certification pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
23
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 April 14, 2005
------------------------ and Principal Financial Officer
D. Scott Singdahlsen
24