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, 2006
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from ___________ to ___________
Commission File No. 001-15511
PYR ENERGY CORPORATION
----------------------
(Exact name of small business issuer as specified in its charter)
Maryland 95-4580642
-------- ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1675 Broadway, Suite 2450, Denver, CO 80202
--------------------------------------- -----
(Address of principal executive offices) (Zip Code)
(303) 825-3748
--------------
(Registrant's telephone number, including area code)
Indicate by check mark 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]
There were 37,915,259 shares of $.001 par value common stock outstanding on
March 31, 2006.
Transitional Small Business Disclosure Format (Check one): Yes [ ] No [X]
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements 3
Balance Sheets - February 28, 2006 (Unaudited)
and August 31, 2005 3
Statements of Operations - Three and Six Months
Ended February 28, 2006 and February 28, 2005
(Unaudited) 4
Statements of Cash Flows - Six Months Ended
February 28, 2006 and February 28, 2005 (Unaudited) 5
Notes to Financial Statements 7
Item 2. Management's Discussion and Analysis or Plan of
Operation 11
Item 3. Controls and Procedures 21
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 22
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
(in thousands, except per share data)
February 28 August 31,
2006 2005
-------- --------
(Unaudited)
ASSETS
CURRENT ASSETS
Cash $ 6,713 $ 2,934
Oil and gas receivables 1,584 1,618
Other receivables 333 124
Prepaid expenses and other assets 117 59
-------- --------
Total current assets 8,747 4.735
-------- --------
PROPERTY AND EQUIPMENT
Oil and gas properties under full cost, net 18,280 13,242
Furniture and equipment, net 44 29
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18,324 13,271
-------- --------
OTHER ASSETS
Deferred financing costs and other assets 30 80
-------- --------
TOTAL ASSETS $ 27,101 $ 18,086
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 789 $ 89
Amounts due oil and gas property owners 148 --
Accrued net profits interest payable 455 1,287
Other accrued liabilities 585 378
Asset retirement obligation 904 904
-------- --------
Total current liabilities 2,881 2,658
-------- --------
LONG TERM LIABILITIES
Convertible notes 7,133 6,958
Asset retirement obligation 308 293
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 - 37,915,259 at 02/28/06 and
31,640,259 shares at 8/31/05 38 32
Capital in excess of par value 51,259 43,294
Accumulated deficit (34,518) (35,149)
-------- --------
Total stockholders' equity 16,779 8,177
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 27,101 $ 18,086
======== ========
See notes to consolidated financial statements.
3
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Six Months Ended
February 28, February 28,
---------------------------- ----------------------------
2006 2005 2006 2005
------------ ------------ ------------ ------------
(in thousands, except share and per share data)
REVENUES
Oil and gas revenues $ 2,069 $ 1,196 $ 4,072 $ 2,278
------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 331 120 575 329
Production taxes, gathering and transportation 141 84 265 155
Net profits interest expense 320 232 580 355
Depletion, depreciation, amortization and accretion 509 173 866 217
General and administrative 584 498 1,087 1,009
------------ ------------ ------------ ------------
Total operating expenses
1,885 1,107 3,373 2,065
------------ ------------ ------------ ------------
INCOME FROM OPERATIONS 184 89 699 213
OTHER INCOME (EXPENSE)
Interest income 68 25 115 45
Other income 5 4 5 8
Interest (expense) (89) (84) (188) (168)
Other (expense) 7 (4) -- (7)
------------ ------------ ------------ ------------
Total other income (expense) (9) (59) (68) (122)
------------ ------------ ------------ ------------
NET INCOME $ 175 $ 30 $ 631 $ 91
============ ============ ============ ============
NET INCOME PER COMMON
SHARE -BASIC AND DILUTED $ 0.00 $ 0.00 $ 0.02 $ 0.00
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING-
BASIC 37,915 31,565 36,658 31,565
DILUTED 38,623 32,130 37,353 32,087
See notes to consolidated financial statements.
4
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended February 28,
-----------------------------
2006 2005
------- -------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 631 $ 91
Adjustments to reconcile net income to
net cash provided by operating activities
Depletion, depreciation, amortization and accretion 866 217
Amortization of financing costs 2 2
Interest expense converted into debt 175 167
Stock option issued for director service -- 15
Stock option expense for non-qualifying options issued 9 --
Changes in current assets and liabilities
Decrease (increase) in accounts receivable 107 (997)
Increase in prepaids and other receivables (59) (19)
Increase in accounts payable 556 122
Increase in amounts due oil and gas property owners 148 --
(Decrease) increase in net profits interest liability (832) 355
Increase in accrued expenses 207 49
------- -------
Net cash provided by operating activities 1,810 2
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions of furniture and equipment (21) (11)
Additions to oil and gas properties (6,138) (1,659)
Proceeds from exercise of exploration options -- 750
Proceeds from sale of properties 118 49
------- -------
Net cash used in investing activities (6,041) (871)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of common stock 8,157 --
Proceeds from exercise of stock options -- 3
Offering costs (177) --
Other 30 --
------- -------
Net cash provided by financing activities 8,010 3
------- -------
NET INCREASE (DECREASE) IN CASH 3,779 (866)
CASH, BEGINNING OF PERIODS 2,934 6,038
------- -------
CASH, END OF PERIODS $ 6,713 $ 5,172
======= =======
See notes to consolidated financial statements.
5
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(continued)
SUPPLEMENTAL CASH FLOW INFORMATION:
Six Months Ended February 28,
-----------------------------
2006 2005
---------- ----------
(Unaudited)
Cash paid for interest and income taxes $ -- $ --
Non-cash financing activities:
Net increase in payables for capital expenditures 144 131
Debt issued for interest 175 167
Property sale - proceeds received in third quarter 280
Third party exercise of right to drill option (collected in 2005) -- 750
Asset retirement obligation increase 1 14
See notes to consolidated financial statements.
6
PYR ENERGY CORPORATION
Notes to Consolidated Financial Statements
February 28, 2006
(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, 2006 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 audited financial statements and notes included in our Form 10-KSB for the
year ended August 31, 2005.
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.
Our financial statements are based on a number of significant estimates,
including collectibility 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, our oil and gas business makes it
vulnerable to changes in wellhead prices of crude oil and natural gas.
These 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 are considered significant
estimates by us, and which are 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 our 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 dilutive effect of such securities was
insignificant for the three months ended November 30, 2005 and 2004,
respectively. The following table sets forth the computation of basic and
diluted earnings per share (in thousands except per share data):
7
Three Months Ended Six Months Ended
February 28, February 28,
----------------- -----------------
2006 2005 2006 2005
------- ------- ------- -------
Numerator:
Numerator for basic and diluted
earnings per share - income
available to common stockholders $ 175 $ 30 $ 631 $ 91
Denominator:
Denominator for basic earnings
per share -weighted average
shares outstanding 37,915 31,565 36,658 31,565
Effect of dilutive securities -
stock options and warrants 708 565 695 522
------- ------- ------- -------
Denominator for diluted
earnings per common share 38,623 32,130 37,353 32,087
======= ======= ======= =======
Basic and diluted earnings
per common share $ 0.00 $ 0.00 $ 0.02 $ 0.00
======= ======= ======= =======
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). We have elected to continue to
account for our employee stock compensation plans as prescribed under APB
25. Had compensation cost for our 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, our net
income and income per share for the quarters and six months ended February
28, 2006 and 2005 would have been decreased to the pro forma amounts
indicated below (in thousands, except per share data):
Three Months Ended Six Months Ended
February 28, February 28,
------------------ ----------------
2006 2005 2006 2005
------ ------ ------ ------
Net income as reported $ 175 $ 30 $ 631 $ 91
Deduct total compensation cost determined
under the fair value base method for all
awards (87) (83) (318) (166)
----- ----- ----- -----
Pro forma net income (loss) $ 88 $ (53) $ 313 $ (75)
===== ===== ===== =====
Net pro forma income (loss) per share:
As reported - Basic and Dilutive $0.00 $0.00 $0.02 $0.00
===== ===== ===== =====
Pro forma - Basic and Dilutive $0.00 $0.00 $0.01 $0.00
===== ===== ===== =====
Reclassification - Certain reclassifications have been made to the February
28, 2005 financial statements to conform to February 28, 2006 presentation.
Such reclassifications had no effect on net income.
Recent Accounting Pronouncements - In December 2004, the Financial
Accounting Standards Board ("FSAB") issued its final standard on accounting
for employee stock options, SFAS No. 123 (Revised 2004), Share-Based
Payment (SFAS 123 (R)). SFAS 123 (R) replaces SFAS No. 123, Accounting for
Stock-Based Compensation (SFAS 123), and supersedes APB 25, Accounting for
Stock Issued to Employees. SFAS 123 (R) requires companies to measure
compensation costs for all share-based payments, including grants of
employee stock options, based on the fair value of the awards on the grant
date and to recognize such expense over the period during which an employee
8
is required to provide services in exchange for the award. The pro forma
disclosures previously permitted under SFAS 123 will no longer be an
alternative to financial statement recognition. For entities that file as a
small business issuer, such as PYR Energy Corporation, SFAS 123 (R) is
effective for all awards granted, modified, repurchased or cancelled after,
and to unvested portions of previously issued and outstanding awards
vesting for annual periods beginning after December 15, 2005, which for us
will be the first quarter of fiscal 2007. We are currently evaluating the
effect of adopting SFAS 123 (R) on our financial position and results of
operations. We currently estimate the adoption of SFAS 123 (R) will result
in expenses in amounts that are similar to the current pro forma
disclosures under SFAS 123.
In March 2005, the FASB issued Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations ("FIN 47"). FIN 47 clarifies that
the term "conditional asset retirement obligation", as used in SFAS 143,
Accounting for Asset Retirement Obligations, refers to a legal obligation
to perform an asset retirement activity in which the timing and/or method
of settlement are conditional on a future event that may or may not be
within the control of the entity. However, the obligation to perform the
asset retirement activity is unconditional even though uncertainty exists
about the timing or method of settlement. FIN 47 requires that the
uncertainty about the timing or method of settlement of a conditional asset
retirement obligation be factored into the measurement of the liability
when sufficient information exists. FIN 47 also clarifies when an entity
would have sufficient information to reasonably estimate the fair value of
an asset retirement obligation. The adoption of FIN 47 had no effect on our
financial position or results of operations for the six months ended
February 28, 2006.
In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of
Financial Assets - an amendment of FASB Statement No. 140, regarding (1)
the circumstances under which a servicing asset or servicing liability must
be recognized, (2) the initial and subsequent measurement of recognized
servicing assets and liabilities, and (3) information required to be
disclosed relating to servicing assets and liabilities. We are required to
adopt this Statement as of the beginning of our first fiscal year that
begins after September 15, 2006, which for us will be the first quarter of
fiscal 2008. The adoption of this Statement will have no effect on our
financial position or results of operations.
2. STOCKHOLDERS' EQUITY
--------------------
In mid-October 2005, we completed a private placement in which we sold
6,327,250 shares of common stock at a price of $1.30 per share to a group
of accredited institutional and individual investors. We received
approximately $8.0 million in net proceeds after deducting related offering
expenses. In addition, we issued warrants to purchase 52,500 shares of
common stock in partial payment of a commission for financial advisory
services performed in connection with the private placement. The warrants
have an exercise price of $1.30 and expire in five years. The proceeds
received from the private placement will be used for general corporate
purposes and costs associated with our drilling portfolio.
In December 2005, we filed a registration statement to register the
re-sale of the securities issued pursuant to this private placement by the
investors. This registration statement became effective in January 2006.
3. CONTINGENCIES
-------------
On July 29, 2005, the Company filed a lawsuit in the U.S. District
Court for the Eastern District of Texas, Beaumont Division against Samson
Lone Star Limited Partnership ("Samson") and Samson's parent company,
Samson Resources Corp. The Company alleged in its complaint that Samson,
the operator of a producing gas well in Jefferson County, Texas named the
Sun Fee No. 1 Sidetrack Well (the "Sun Fee Well"), has breached its
obligations to the Company, which owns interests in the property on which
the Sun Fee Well is located, by joining, without authorization, the Sun Fee
Well into a unit with other properties in which the Company has no
interest, many of which are non-productive. Samson has a large interest in
the properties that Samson has joined into the unit. Pursuant to Samson's
proposed pooling configuration, the Company's working and overriding
royalty interests in the Sun Fee Well would be reduced substantially. The
Company believes that Samson has no legal or contractual right to reduce
the Company's interests in this manner. The Company is seeking monetary
damages for all payments due and owing to the Company based on the proper,
undiluted interests in the property. On September 13, 2005, the Court
entered a Preliminary Injunction ordering Samson to return the Company to
pay status for the undisputed amounts upon which Samson had been paying the
Company prior to the filing of the suit. On December 23, 2005, Samson filed
a motion for summary judgment on the Company's claims, to which the Company
filed its response on January 3, 2006, rigorously denying that Samson has
grounds in law or fact for the requested relief. Further, on January 17,
9
2006, Samson filed a counterclaim for an unspecified overpayment to the
Company, which was clarified by a subsequent filing on February 14, 2006,
that it was disputing the unit interest originally attributed to the
Company and now asserting that the Company's net revenue unit interest is
approximately 4.7%. On March 28, 2006, the Court denied a motion by Samson
to modify the present injunction to allow payment upon the lower amount.
The Company has also filed additional claims against Samson for breach of
contract or reformation of the certain assignment issued by Samson to the
Company in April 2005 upon which Samson bases its present counterclaim. The
outcome of the litigation will determine whether PYR's ownership in the Sun
Fee Well consists of (a) the 5.7% net revenue interest (consisting of a
5.19% working and a 1.5% overriding royalty interest) that was formerly the
portion that was not contested by Samson and represents the amount of the
payments that Samson, as operator, has been paying PYR and that PYR has
been recording in its financial statements; or (b) the 4.7% net revenue
interest that Samson asserted in its February 14, 2006 filing; or (c) a net
revenue interest higher than 5.7% as a result of the Company's prevailing
on part or all of its claims that it owns an 8.33% working interest as well
as an overriding royalty interest greater than 1.5%.
Samson has informed the Company that it will dismiss the suit that it
filed against the Company on August 22, 2005 in District Court for
Jefferson County, Texas, 58th Judicial District seeking to enjoin or
prevent the Company from drilling a planned well on the approximately
400-acre property directly east of the Sun Fee Well on the grounds that it,
Samson, has the exclusive right to serve as operator to drill the proposed
well. The Company holds a 100% interest in oil and gas leases that comprise
75% of the approximately 400-acre parcel on which it is planning to drill a
gas well to the same reservoir from which the Sun Fee Well produces.
On February 15, 2006, the Company filed a motion in the on-going
bankruptcy proceeding involving Venus Exploration Company ("Venus") in the
U.S. Bankruptcy Court for the Eastern District of Texas requesting that the
Bankruptcy Court uphold its Order of April 9, 2004 approving the Company's
purchase of Venus' remaining assets free and clear of any obligations under
a pre-bankruptcy Operating Agreement between Venus and Trail Mountain Inc.
("Trail Mountain") that required Venus and Trail Mountain to offer each
other participation in subsequently acquired oil and gas properties. The
Company believes and has asserted in its motion that the pre-bankruptcy
Operating Agreement was not listed among the contracts that were assigned
to it under the sale in and under the approval of the Bankruptcy Court.
Trail Mountain, along with two other parties, has filed an objection to the
Company's motion asserting that the Company is obligated to offer an
opportunity to Trail Mountain to share in the lease upon which the proposed
well is to be drilled. If Trail Mountain is successful, it will lead to a
potential 50% reduction in the Company's interest in the lease, but could
also lead to a corresponding assignment of interests in properties acquired
by Trail Mountain, including certain properties assigned to the Sidetrack
Unit.
The Company will continue to vigorously pursue and defend its rights
with respect to the foregoing litigations.
4. PROPERTY ACQUISITION AND DIVESTITURES
-------------------------------------
In December 2005, we acquired additional working interests in the
Hansford project, located in Hansford County of the Texas panhandle, from
multiple private entities for $1.7 million. The acquisition includes
approximately 1.95 Bcf of proved reserves of which 86% are undeveloped and
2,265 acres of leasehold. Following this acquisition, we own 100% working
interest on a majority of the acreage which includes two producing wells
and a well that has been drilled, cased and is awaiting completion.
In addition, in December 2005, we sold our interest in certain
leasehold acreage located in our School Road prospect in California for
approximately $96,000.
In February 2006, we sold our interest in approximately 250 acres in
the Merganser prospect located in Leon County, Texas for approximately
$280,000.
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion contains forward-looking statements that reflect
our future plans, estimates, beliefs and expected performance. The
forward-looking statements are dependent upon events, risks and uncertainties
that may be outside our control. Our actual results could differ materially from
those discussed in these forward-looking statements. Factors that could cause or
contribute to such differences include, but are not limited to, market prices
for natural gas and oil, economic and competitive conditions, regulatory
changes, estimates of proved reserves, potential failure to achieve production
from development projects, capital expenditures and other uncertainties, as well
as those factors discussed below and in our Annual Report on Form 10-KSB for the
year ended August 31, 2005. In light of these risks, uncertainties and
assumptions, the forward-looking events discussed may not occur.
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 current focus is on the Rocky Mountain, Texas and Gulf Coast
regions.
Liquidity and Capital Resources
Our primary sources of liquidity historically have been from sale of our
common stock, issuance of convertible notes, and to a much lesser extent, net
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, 2006, we
had approximately $5.9 million in working capital and cash of $6.7 million.
Cash Flow from Operating Activities
-----------------------------------
Net cash provided by operating activities was $1.8 million and $2,000 for
the six months ended February 28, 2006 and 2005, respectively. The increase in
net cash provided by operating activities was substantially due to the increase
in production revenues, net of increases in expenses. See "Results of
Operations" for discussion of changes in revenues and expenses. Non-cash charges
increased principally due to higher depreciation, depletion and amortization
associated with increased production and higher depletion rates. Changes in
current assets and liabilities increased cash flow from operations by $126,000
in the six months ended February 28, 2006 compared with a decrease in cash flows
from operations of $491,000 in the same period in 2005. The increase in current
assets and liabilities for the current period is principally attributed to
increases in accounts payable and accrued expenses related to our drilling
activity. This increase was offset, in part, by a decrease in the net profits
liability resulting from net profits payments.
Operating cash flows are impacted by many variables, the most significant
of which are production levels and the volatility of prices for natural gas and
oil produced. Prices for these commodities are determined primarily by
prevailing market conditions. Regional and worldwide economic activity, weather
and other substantially variable factors influence production levels and market
conditions for these products. These factors are beyond our control and are
difficult to predict.
Capital Expenditures
--------------------
Our capital expenditures approximated $6.2 million and $1.7 million for the
first six months ended February 28, 2006 and 2005, respectively. The total for
the current period includes principally $3.5 million for drilling, development,
exploration and exploitation, $1.7 million for the purchase of additional
working interest in properties located in Hansford County, Texas and $1.0 for
leasehold costs. Drilling costs for the current period were incurred principally
on two wells located in Texas, the Chisum #1 well and the Lackey Gas Unit #2
well, and on the #1-30 Duck Federal well located in Wyoming.
11
During the six months ended February 28, 2005, we received $750,000 for a
non-refundable option fee from Suncor Energy Natural Gas America, Inc.
("SENGAI") pursuant to an Exploration Option Agreement between the Company and
SENGAI covering our Rogers Pass exploration project in the foothills of
west-central Montana.
We currently anticipate our capital budget will be approximately between
$7.5 and $11.0 million for fiscal year 2006, which will be used for a diverse
portfolio of development and exploration wells in our core areas of operation.
We may consider selling down a portion of our interests in some of our
exploration and development projects to industry partners to generate additional
funds to finance our 2006 capital budget. We are projecting that cash on hand,
cash available from operating activities, and funds from the partial sale of our
interest in some prospects will be sufficient to fund our 2006 capital budget.
Financing Activities
--------------------
In mid-October 2005, we completed a private placement in which we sold
6,327,250 shares of common stock at a price of $1.30 per share, to a group of
accredited institutional and individual investors. Net proceeds from this
placement of approximately $8.0 million will be used for general corporate
purposes and costs associated with our development drilling portfolio located
principally in the Rocky Mountains and Texas.
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. In addition,
our capital expenditure budget for the fiscal year ending August 31, 2006 will
depend on our success in selling additional prospects for cash, the level of
industry participation in our exploration projects, the availability of debt or
equity financing, cash on hand' and the results of our activities. We anticipate
spending a minimum of approximately between $7.5 and $11.0 million on
exploration and development activities during our fiscal year ending August 31,
2006. 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.
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.
Summary of Development and Exploration Projects
Our development and exploration activities are focused primarily in select
areas of the Rocky Mountains, Texas and the Gulf Coast. 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.
The following is a summary of our production and 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 production and exploration
criteria.
Rocky Mountain Exploration
--------------------------
Mallard Project. The #1-30 Duck Federal well has been completed and is
flowing to gas sales. The well has been opened up slowly (currently at a 15%
choke) in an attempt to reach a stabilized flow rate. Since initial production,
the flow rate has been inhibited by surface facility and water disposal
limitations that have not allowed stabilized production flow to occur to date.
Currently, on a constrained 15% choke, the well is averaging 6 to 7 MMcf per day
of gas production with 175 barrels of associated condensate and approximately
1000 barrels of water at a flowing casing pressure (up 7" casing) of
approximately 1000 psi. As part of our processing agreement, the plant operator
is disposing of the water. Production to sales commenced in mid-March, and as
such revenues and volumes from this well are not included in the quarter's
12
financial statement. The Mission Canyon is the primary producing zone within the
nearby Whitney Canyon-Carter Creek Field, which has produced over 2.1 Tcfe to
date. The #1-30 Duck Federal well represents a development step out well. We
believe there are additional PUD locations to drill on structure. We own a
28.75% working interest in the well and surrounding acreage. It is anticipated
that PYR and the working interest partners will acquire approximately 20 square
miles of 3-D seismic data during the summer of 2006 in order to better delineate
additional drilling opportunities in the area.
Ryckman Creek Project. We have leased approximately 1,820 net acres,
covering the majority of the abandoned Ryckman Creek field, in the Overthrust
region of southwestern Wyoming. Ryckman Creek, located 6 miles east of our
Mallard 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 rig availability timing, it is anticipated that additional
development activity of the Ryckman Creek project will not occur until sometime
in the latter half of calendar 2006.
Montana Foothills Project. Following the plugging and abandonment of the
Flesher Pass exploratory well in August 2005, the Company has re-evaluated
exploration prospects associated with its undeveloped acreage in the project and
has elected to release most of its undeveloped acreage position.
Texas and Gulf Coast Exploration
--------------------------------
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. One such
location resulted in the Sun Fee GU #1-ST well (the "Sun Fee Well"), which
produces from the upper Yegua, and was initiated in late May 2004, and beginning
in early June 2005, averaged approximately 19MMcfe per day. Current production
is averaging 12MMcfe per day. Cumulative production since inception is in excess
of 9.1 Bcfe through end of February, 2006. When the well reached payout on
October 13, 2004, we were placed in pay status as a working interest participant
in the well. Based on pooling of lands into the Sun Fee Gas Unit by the
operator, our current working interest in the well and associated lands is 5.19%
with a 1.5% overriding royalty interest although Samson Lone Star L.P.
("Samson"), the operator of the wells, asserted in a filing on February 14, 2006
that our working interest should be only 4.7%, approximately. Together with our
partners, we control approximately 4,200 acres of gross leasehold acres in the
project. We intend to drill a well (Tindall #1), offsetting by approximately
1600 feet the Sun Fee GU #1-ST, in 2006 subject to drilling rig availability.
Based on a title opinion, we calculate our working interest in the Tindall #1
well to be 100%, although we anticipate that other parties may dispute this
amount. Samson filed a lawsuit seeking a judicial declaration of Samson's
exclusive right to operate the Tindall well as well as injunctive relief
enjoining the Company from continuing its drilling operations or serving as
operator. In early April 2006, Samson indicated its interest to withdraw this
lawsuit.
We are currently in litigation with the operator of the Sun Fee Well,
Samson Lone Star L.P. ("Samson"), concerning, among other matters, Samson's
pooling of certain lands into the production unit and corresponding reduction in
PYR's working interest. The outcome of the litigation will determine whether
PYR's ownership in the Sun Fee Well consists of (a) the 5.7% net revenue
interest (consisting of a 5.19% working and a 1.5% overriding royalty interest)
that was formerly the portion that was not contested by Samson and represents
the amount of the payments that Samson, as operator, has been paying PYR and
that PYR has been recording in its financial statements; or (b) the 4.7% net
revenue interest that Samson asserted in its February 14, 2006 filing; or (c) a
net revenue interest higher than 5.7% as a result of the Company's prevailing on
part or all of its claims that it owns as 8.33% working interest as well as an
overriding royalty interest greater than 1.5%.
Our revenues and costs associated with the production from the Sun Fee
Well, as well as our 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 our acquisition of properties from
Venus Exploration Inc. ("Venus") in May 2004. The net profit interest under 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 $3.3 million 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.
13
Madison prospect, located in the northern part of the Constitution Field,
Jefferson County, Texas, is an exploitation project to test multiple sand
intervals within the expanded Yegua section, downthrown to a major growth fault.
The Maness GU #1 well, in which we have a 12.5% working interest, started
production in mid-August 2004, and from inception through February 2006 the well
has cumulative production of approximately 2.5 Bcfe. The well is currently
producing at a rate of approximately 4 MMcfe per day. The operator has converted
an existing well bore within the project area into a water disposal well, and is
planning to drill an offset development well (Wall#1) in the summer of 2006,
depending on rig availability. We will participate for 19.16% working interest
in the drilling of this development well based on our additional purchase of 5%
working interest from the operator. The purchase calls for the Company to fund
6.66% of the drilling costs to casing point to earn the additional 5% working
interest in the Wall #1 well and surrounding acreage. Wells drilled in this
prospect are subject to a 50% net profits interest agreement with the Venus
Exploration Trust.
Tortuga Grande prospect, located in Smith County, Texas, was a project to
test the productivity of the Cotton Valley Sand section. Due to a lack of
commercial reservoir properties in the Cotton Valley section, the well was
recompleted in the lower Rodessa section. Initial flow testing of the Rodessa
indicated commercial production. The initial test rates were constrained by flow
into a low pressure system, but yielded rates in excess of 750 Mcf per day with
40 plus barrels of associated condensate production at a flowing tubing pressure
of 2200 psi. The well is currently being hooked up to a high pressure pipeline
system for production to sales. It is anticipated that this activity will take a
number of weeks and will result in improved production rates. Rodessa
production, within 3 miles to the north and northeast of the Chisum location,
has yielded cumulative production ranging up to 6.4 Bcfe per well. The Company
is participating in the completion of the Rodessa with its 28.57% working
interest, and PYR and its partners control approximately 9,800 acres of
leasehold in the project. The Company anticipates drilling additional wells to
fully exploit the Rodessa potential in the project area. We expect the next well
to commence drilling sometime this summer.
Merganser prospect, located in Leon County, Texas, targets Cotton Valley
and Bossier sandstone reservoirs. In February 2006, we sold our interest in
approximately 250 acres, in the prospect, for approximately $280,000.
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. We will
participate with a 15% cost bearing interest and have farmed out the remainder
of our working interest. It is anticipated that the initial test well at Bayou
Duralde will begin drilling operations in the spring of 2006.
At the Wilburton Field in Latimer County, Oklahoma, the operator of the
Scharff #3X well, a well in which we elected not to participate in the drilling
of the well by going non-consent, recently notified us that the well had reached
payout effective August 1, 2005. As a result, in the second quarter we
recognized revenues for August 2005 through February 2006. The Scharff #5-1 well
was recently drilled and completed in the Lower Atoka (Cecil) formation, which
resulted in initial production rates of up to 54 MMcfe per day and is currently
producing at an average rate in excess of 40 MMcfe per day. The Scharff #6-1 is
currently undergoing completion activities in the Upper Cecil and is expected to
be turned on to full sales shortly. The Scharff #7-1 has been permitted and is
expected to begin drilling operations in mid-May. We have a 2.42 % working
interest in these wells.
Hansford Project, located in Hansford County of 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. On December 20, 2005, the Company closed a strategic
acquisition of additional interest in the Hansford project, from multiple
private entities, for $1.78 million in cash. The acquisition of the Hansford
County property allows us to consolidate our working interest and operations in
a field which offers significant development drilling opportunities. The
transaction, which has an effective date of December 1, 2005, includes
externally estimated proved reserves of approximately 1.950 Bcfe, of which 86%
of the reserves are classified as proved undeveloped. We own 100% working
interest on the majority of the acreage, which includes two producing wells in
addition to the recently drilled Lackey GU #2. The Lackey GU #2 has been
completed and is currently flowing to sales as the well continues to clean up
from fracture stimulation. The Lackey GU #1 has been recently worked over and is
flowing back stimulation fluids and gas. Both wells are currently having
artificial lift installed to increase flow back of both stimulation fluids and
production rates. Currently the combined production from both wells, which we
anticipate will continue to improve, is 600 Mcf per day. The Company owns 100%
working interest in both the Lackey GU #1 and Lackey GU #2.
14
Other
-----
SAN JOAQUIN BASIN, CALIFORNIA
We continue to maintain our three prospects, Blizzard, Bulldog, and Wedge in
this region. We plan to decide whether to drill, farm out, or sell our position
in the near future.
15
Results of Operations
Three Months Ended February 28, 2006 Compared to Three Months Ended February 28, 2005
Three Months Ended
February 28, Increase (Decrease)
------------------- --------------------
2006 2005 Amount Percent
-------- -------- -------- --------
($ in thousands, except for per unit prices and costs)
Operating Results:
Revenues
Oil and gas production revenues $ 2,069 $ 1,196 $ 873 73%
Interest income 68 25 43 172%
Operating Expenses
Lease operating expense 331 120 211 175%
Production taxes, gathering and transportation expense 141 83 58 71%
Net profits expense 320 233 87 38%
Depletion, depreciation, amortization and accretion 509 173 336 194%
General and administrative 584 498 86 17%
-------- -------- -------- --------
Total operating expenses $ 1,885 $ 1,107 $ 778 70%
Interest Expense $ 89 $ 83 $ 6 6%
Production Data:
Natural gas (Mcf) 174,903 81,655 93,248 114%
Oil (Bbls) 13,550 14,369 (819) (6%)
Combined volumes (Mcfe) 256,203 167,869 88,334 53%
Daily combined volumes (Mcfe/d) 2,847 1,865 982 53%
Average Prices:
Natural gas (per Mcf) $ 7.15 $ 6.78 $ 0.37 5%
Oil (per Bbl) 60.41 44.69 15.72 35%
Combined (per Mcfe) 8.08 7.12 0.96 13%
Average Costs (per Mcfe):
Lease operating expense $ 1.29 $ 0.72 $ 0.57 79%
Production taxes, gathering and transportation expense 0.55 0.49 0.06 12%
Net profit expense 1.25 1.39 (0.14) (10%)
Depletion, depreciation, amortization and accretion 1.99 1.03 0.96 93%
General and administrative 2.28 2.96 (0.68) (23%)
Interest Expense 0.35 0.50 (0.15) (30%)
The second quarter ended February 28, 2006 resulted in net income of
$175,000 compared to a net income of $30,000 for the same quarter in 2005.
Oil and Gas Revenues. Oil and gas revenues increased 73% to approximately
$2.1 million for the three months ended February 28, 2006 from approximately
$1.2 million for the same period in 2005 due to i) a 53% increase in production
and ii) an increase in natural gas and oil prices of 5% and 35%, respectively.
Average price increases added approximately $160,000 of oil and gas revenues
while increases in average Mcfe production volumes added approximately $713,000
of oil and gas revenues. A six percent decrease in oil volumes was more than
offset by increases in average gas production resulting from the development of
existing properties. Two wells located in Texas and one in Oklahoma contributed
44% of the Company's oil and gas revenues, and 47% and 48% of the Company's
natural gas and oil production, respectively. During the second quarter of
fiscal 2006, the operator of the Scharff #3X-1 well located in Oklahoma notified
the Company that the well had reached payout effective the first of August 2005.
As a result of the payout, the Company's working interest in the well was placed
into pay status. Because the Company did not receive notice of the payout until
the first quarter had been reported, in addition to the actual second quarter
revenues and production for the Scharff #3X-1 well, the Company recognized in
the second quarter revenues of $247,000 from production of 25,600 Mcf for August
through November 2005.
16
Comparison of fiscal year 2006 first and second quarters production numbers
- Total net production for second quarter was 24% higher than the first quarter
of fiscal 2006 production primarily due to production from the Scharff #3X-1 and
the Scharff #5 wells located in Oklahoma and from the Lackey Gas Unit #2 located
in Texas.
Lease Operating Expenses. Our per unit of production lease operating
expenses increased 79% from $0.72 per Mcfe in the second quarter of fiscal year
2005 to $1.29 for the same period in fiscal year 2006. This per unit of
production increase is principally attributed to the addition of new wells with
higher operating costs and additional costs incurred on two Texas wells for
post-hurricane remedial maintenance. Total lease operating expenses increased
175% principally due to the addition of new producing wells and post-hurricane
remedial maintenance.
Production Taxes, Gathering and Transportation Expenses. Production taxes
as a percentage of natural gas and oil revenues averaged 6.0% for the second
quarter in fiscal year 2006 compared to 6.3% for the same quarter in fiscal year
2005. Production taxes are primarily based on wellhead values of production and
vary across the different areas that our wells are located. The decrease in the
average percent of natural gas and oil sales is attributed to increased
production from locations with lower production tax rates. Total production
taxes increased as a result of higher production revenues, due to increases in
both production volumes and average prices. Gathering, transportation and other
sales expenses increased by $13,000 in 2006 compared with the same period in
2005.
Net Profits 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 amount of the Venus Trust
net profits interest is either 25% or 50% with respect to different Venus
exploration and exploitation project areas, and decreases by one-half of its
original amount after an aggregate total of $3.3 million in net profits. The 38%
increase in net profits expense for the second quarter ended February 28, 2006
compared with the same period in 2005 is attributed to development of wells
subject to the net profits agreement and related increases in operating income
from these wells. As of February 28, 2006, the Company has paid net profits
expenses totaling approximately $1.5 million.
Depletion, Depreciation, Amortization and Accretion Expense. Depletion,
depreciation, amortization and accretion expense was $509,000 for the second
quarter ended February 28, 2006 compared with $173,000 for the same period in
the prior year. The increase is principally attributed to depletion expense
which increased $334,000. Depletion expense increase is the result of a 53%
increase in production volumes in the second quarter in fiscal year 2006 as
compared to the same period in the prior year. The weighted average depletion
rate for the Company's full cost pool increased from $0.98 per Mcfe in the
second quarter of the prior year to approximately $1.95 per Mcfe in the second
quarter of the current year. The rate increase is attributed to the inclusion of
costs of certain impaired unevaluated properties in the amortizable base of the
full cost pool. Under the full cost pool method of accounting, impairment costs
of unevaluated properties, previously excluded from the amortizable base of the
depletable full cost pool, are added to the full cost pool depletable base
resulting in an increase in the depletion rate.
General and Administrative Expenses. General and administrative expenses
during the quarter ended February 28, 2006 increased by approximately $86,000 or
17% from the same period in 2005. The principal costs contributing to the
increase were higher Texas franchise taxes associated with increased sales in
Texas, higher office rent and Sarbanes-Oxley compliance costs. As a result of
higher production volume levels, general and administrative costs per unit of
production decreased from $2.96 per Mcfe in the second quarter of the prior year
to $2.28 per Mcfe for the current period
Interest Income. Interest income increased by $42,000 to $67,000 for the
second quarter ended February 28, 2006 compared to the same period in 2005
principally due to higher cash and short-term investments balances. The increase
in cash and short-term investment balances resulted primarily from the receipt
of net proceeds from a private placement of our common stock in October 2005.
Interest Expense. During the quarters ended February 28, 2006 and 2005, we
recorded interest expense of $89,000 and $84,000, respectively. The interest
expense, primarily associated with the Company's convertible notes due May 24,
2009, increased due to an increase in convertible note principal balances
(resulting from adding previously accrued interest to the principal).
17
Six Months Ended February 28, 2006 Compared to Six Months Ended February 28, 2005
Six Months Ended
February 28, Increase (Decrease)
--------------------- ----------------------
2006 2005 Amount Percent
--------- --------- --------- ---------
($ in thousands, except for per unit prices and costs)
Operating Results:
Revenues
Oil and gas production revenues $ 4,072 $ 2,278 $ 1,794 79%
Interest income 115 45 70 156%
Operating Expenses
Lease operating expense 575 329 246 75%
Production taxes, gathering and transportation expense 265 155 110 71%
Net profits expense 580 355 225 63%
Depletion, depreciation, amortization and accretion 866 217 649 298%
General and administrative 1,087 1,009 78 8%
--------- --------- --------- ---------
Total operating expenses $ 3,373 $ 2,065 $ 1,308 $ 63%
Interest Expense 188 168 20 12%
Production Data:
Natural gas (Mcf) 305,147 144,712 160,435 111%
Oil (Bbls) 26,152 28,347 (2,195) (8%)
Combined volumes (Mcfe) 462,059 314,794 147,265 47%
Daily combined volumes (Mcfe/d) 2,553 1,739 814 47%
Average Prices:
Natural gas (per Mcf) $ 8.17 $ 6.91 $ 1.26 18%
Oil (per Bbl) 60.44 45.11 15.33 34%
Combined (per Mcfe) 8.81 7.24 1.58 22%
Average Costs (per Mcfe):
Lease operating expense $ 1.24 $ 1.04 $ 0.20 19%
Production taxes, gathering and transportation expense 0.57 0.49 0.08 16%
Net profit expense 1.25 1.13 0.12 11%
Depletion, depreciation, amortization and accretion 1.87 0.69 1.18 171%
General and administrative 2.35 3.21 (0.86) (27%)
Interest Expense 0.41 0.53 (0.12) (23%)
The first six months ended February 28, 2006 resulted in net income of
$631,000 compared to a net income of $91,000 for the same period in 2005.
Oil and Gas Revenues. Oil and gas revenues increased by approximately $1.8
million, or 79%, to approximately $4.1 million for the six months ended February
28, 2006 from approximately $2.3 million for the same period in 2005 due to i) a
47% increase in production and ii) to increases in natural gas and oil prices of
18% and 34%, respectively. Average price increases added approximately $496,000
of oil and gas revenues while increases in average Mcfe production volumes added
approximately $1.3 million of oil and gas revenues. An eight percent decrease in
oil volumes was more than offset by increases in average gas production
resulting from the development of existing properties. Two wells located in
Texas and one in Oklahoma contributed a majority (54%) of the Company's total
oil and gas revenues, and 59% and 46% of the Company's natural gas production
and oil production, respectively.
Lease Operating Expenses. Our per unit of production lease operating
expenses increased 19% from $1.04 per Mcfe in the first six months of fiscal
year 2005 to $1.24 for the same period in fiscal year 2006. This per unit of
production increase is principally attributed to increased operating expenses on
new and existing wells. Total lease operating expenses increased 75% principally
due to the higher per well operating expenses of the new wells added and
additional costs incurred on two Texas wells for post-hurricane remedial
maintenance.
18
Production Taxes, Gathering and Transportation Expenses. Production taxes
as a percentage of natural gas and oil revenues averaged 5.7% for the first six
months of fiscal year 2006 compared to 6.3% for the same period in fiscal year
2005. Production taxes are primarily based on wellhead values of production and
vary across the different areas that our wells are located. The decrease in the
average percent of natural gas and oil sales is attributed to increased
production from locations with lower production tax rates. Total production
taxes increased as a result of higher production revenues, due to increases in
both production volumes and average prices. Gathering, transportation and other
sales expenses increased by $25,000 in 2006 compared with the same period in
2005.
Net Profits 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 amount of the Venus Trust
net profits interest is either 25% or 50% with respect to different Venus
exploration and exploitation project areas, and decreases by one-half of its
original amount after an aggregate total of $3.3 million in net profits. The 63%
increase for the first six months of fiscal year 2006 compared with the same
period in 2005 is attributed to development of wells subject to the net profits
agreement and related increases in operating income from these wells.
Depletion, Depreciation, Amortization and Accretion Expense. Depletion,
depreciation, amortization and accretion expense was $866,000 for the first six
months of fiscal year 2006 compared with $217,000 for the same period in the
prior year. The increase is principally attributed to depletion expense which
increased $785,000. Depletion expense increase is the result of a 47% increase
in production volumes in the first six months fiscal year 2006 as compared to
the same period in the prior fiscal year. The weighted average depletion rate
for the Company's full cost pool increased from $0.63 per Mcfe in the first six
months of the prior year to $1.83 per Mcfe in the first six months of the
current year. The rate increase is attributed to the inclusion of costs of
certain impaired unevaluated properties in the amortizable base of the full cost
pool. Under the full cost pool method of accounting, impairment costs of
unevaluated properties, previously excluded from the amortizable base of the
depletable full cost pool, are added to the full cost pool depletable base
resulting in an increase in the depletion rate.
General and Administrative Expenses. General and administrative expenses
during the first six months for the fiscal year 2006 increased by $79,000, or
8%, from the same period in 2005. Increases are primarily due to higher office
rent, Texas franchise taxes, and Sarbanes-Oxley compliance costs. As a result of
higher production volume levels, general and administrative costs per unit of
production decreased from $3.21 per Mcfe in the first six months of the prior
year to $2.35 per Mcfe for the current period
Interest Income. Interest income increased by $70,000 to $115,000 for the
first six months of fiscal year 2006 compared to the same period in 2005
principally due to higher average cash and short-term investments balances. The
increase in cash and short-term investment balances resulted primarily from the
receipt of net proceeds from a private placement of our common stock in October
2005.
Interest Expense. During the six month period ended February 28, 2006 and
2005, we recorded interest expense of $188,000 and $168,000, respectively. The
interest expense, principally associated with the Company's convertible notes
due May 24, 2009, increased due to an increase in convertible note principal
balances (resulting from adding previously accrued interest to the principal)
and payment of $11,000 interest to the Venus Trust pertaining to net profits
expense. The Company elected to pay accrued interest on the convertible notes of
approximately $175,000 and $167,000 for the six months ended February 28, 2006
and 2005, respectively, by increasing the outstanding balance of the Convertible
Notes.
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
19
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 from production, including
the following: the amount and timing of actual production; curtailments due to
weather; 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 associated
with acquisition, exploration and development activities, including costs of
unsuccessful exploration, 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. As of February 28, 2006, the
Company has sold more than its entitlement by 11 MMcfs with a fair market value
of approximately $105,000.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board issued its final
standard on accounting for employee stock options, SFAS No. 123 (Revised 2004),
Share-Based Payment (SFAS 123 (R)). SFAS 123 (R) replaces SFAS No. 123,
Accounting for Stock-Based Compensation (SFAS 123), and supersedes APB 25,
Accounting for Stock Issued to Employees. SFAS 123 (R) requires companies to
measure compensation costs for all share-based payments, including grants of
employee stock options, based on the fair value of the awards on the grant date
and to recognize such expense over the period during which an employee is
required to provide services in exchange for the award. The pro forma
disclosures previously permitted under SFAS 123 will no longer be an alternative
to financial statement recognition. For entities that file as a small business
issuer, such as PYR Energy Corporation, SFAS 123 (R) is effective for all awards
granted, modified, repurchased or cancelled after, and to unvested portions of
previously issued and outstanding awards vesting for annual periods beginning
after December 15, 2005, which for us will be the first quarter of fiscal 2007.
We are currently evaluating the effect of adopting SFAS 123 (R) on our financial
position and results of operations. We currently estimate the adoption of SFAS
123 (R) will result in expenses in amounts that are similar to the current pro
forma disclosures under SFAS 123.
In March 2005, the FASB issued Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations ("FIN 47"). FIN 47 clarifies that the
term "conditional asset retirement obligation", as used in SFAS 143, Accounting
for Asset Retirement Obligations, refers to a legal obligation to perform an
20
asset retirement activity in which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of the
entity. However, the obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing or method of
settlement. FIN 47 requires that the uncertainty about the timing or method of
settlement of a conditional asset retirement obligation be factored into the
measurement of the liability when sufficient information exists. FIN 47 also
clarifies when an entity would have sufficient information to reasonably
estimate the fair value of an asset retirement obligation. The adoption of FIN
47 had no effect on our financial position or results of operations for the six
months ended February 28, 2006.
In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of
Financial Assets - an amendment of FASB Statement No. 140, regarding (1) the
circumstances under which a servicing asset or servicing liability must be
recognized, (2) the initial and subsequent measurement of recognized servicing
assets and liabilities, and (3) information required to be disclosed relating to
servicing assets and liabilities. We are required to adopt this Statement as of
the beginning of our first fiscal year that begins after September 15, 2006,
which for us will be the first quarter of fiscal 2008. The adoption of this
Statement will have no effect on our financial position or results of
operations.
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.
21
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings
On July 29, 2005, the Company filed a lawsuit in the U.S. District
Court for the Eastern District of Texas, Beaumont Division against Samson
Lone Star Limited Partnership ("Samson") and Samson's parent company,
Samson Resources Corp. The Company alleged in its complaint that Samson,
the operator of a producing gas well in Jefferson County, Texas named the
Sun Fee No. 1 Sidetrack Well (the "Sun Fee Well"), has breached its
obligations to the Company, which owns interests in the property on which
the Sun Fee Well is located, by joining, without authorization, the Sun Fee
Well into a unit with other properties in which the Company has no
interest, many of which are non-productive. Samson has a large interest in
the properties that Samson has joined into the unit. Pursuant to Samson's
proposed pooling configuration, the Company's working and overriding
royalty interests in the Sun Fee Well would be reduced substantially. The
Company believes that Samson has no legal or contractual right to reduce
the Company's interests in this manner. The Company is seeking monetary
damages for all payments due and owing to the Company based on the proper,
undiluted interests in the property. On September 13, 2005, the Court
entered a Preliminary Injunction ordering Samson to return the Company to
pay status for the undisputed amounts upon which Samson had been paying the
Company prior to the filing of the suit. On December 23, 2005, Samson filed
a motion for summary judgment on the Company's claims, to which the Company
filed its response on January 3, 2006, rigorously denying that Samson has
grounds in law or fact for the requested relief. Further, on January 17,
2006, Samson filed a counterclaim for an unspecified overpayment to the
Company, which was clarified by a subsequent filing on February 14, 2006,
that it was disputing the unit interest originally attributed to the
Company and now asserting that the Company's net revenue unit interest is
approximately 4.7%. On March 28, 2006, the Court denied a motion by Samson
to modify the present injunction to allow payment upon the lower amount.
The Company has also filed additional claims against Samson for breach of
contract or reformation of the certain assignment issued by Samson to the
Company in April 2005 upon which Samson bases its present counterclaim. The
outcome of the litigation will determine whether PYR's ownership in the Sun
Fee Well consists of (a) the 5.7% net revenue interest (consisting of a
5.19% working and a 1.5% overriding royalty interest) that was formerly the
portion that was not contested by Samson and represents the amount of the
payments that Samson, as operator, has been paying PYR and that PYR has
been recording in its financial statements; or (b) the 4.7% net revenue
interest that Samson asserted in its February 14, 2006 filing; or (c) a net
revenue interest higher than 5.7% as a result of the Company's prevailing
on part or all of its claims that it owns an 8.33% working interest as well
as an overriding royalty interest greater than 1.5%.
Samson has informed the Company that it will dismiss the suit that it
filed against the Company on August 22, 2005 in District Court for
Jefferson County, Texas, 58th Judicial District seeking to enjoin or
prevent the Company from drilling a planned well on the approximately
400-acre property directly east of the Sun Fee Well on the grounds that it,
Samson, has the exclusive right to serve as operator to drill the proposed
well. The Company holds a 100% interest in oil and gas leases that comprise
75% of the approximately 400-acre parcel on which it is planning to drill a
gas well to the same reservoir from which the Sun Fee Well produces.
On February 15, 2006, the Company filed a motion in the on-going
bankruptcy proceeding involving Venus Exploration Company ("Venus") in the
U.S. Bankruptcy Court for the Eastern District of Texas requesting that the
Bankruptcy Court uphold its Order of April 9, 2004 approving the Company's
purchase of Venus' remaining assets free and clear of any obligations under
a pre-bankruptcy Operating Agreement between Venus and Trail Mountain Inc.
("Trail Mountain") that required Venus and Trail Mountain to offer each
other participation in subsequently acquired oil and gas properties. The
Company believes and has asserted in its motion that the pre-bankruptcy
Operating Agreement was not listed among the contracts that were assigned
to it under the sale in and under the approval of the Bankruptcy Court.
Trail Mountain, along with two other parties, has filed an objection to the
Company's motion asserting that the Company is obligated to offer an
opportunity to Trail Mountain to share in the lease upon which the proposed
well is to be drilled. If Trail Mountain is successful, it will lead to a
potential 50% reduction in the Company's interest in the lease, but could
also lead to a corresponding assignment of interests in properties acquired
by Trail Mountain, including certain properties assigned to the Sidetrack
Unit.
The Company will continue to vigorously pursue and defend its rights
with respect to the foregoing litigations.
22
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The information required by this item was previously disclosed in our
Current Reports on Form 8-K, filed on October 4, October 13, and October
26, 2005, respectively.
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
--------------------------------------------------------------------------------
Number Description
--------------------------------------------------------------------------------
31 Rule 13a-14(a) Certifications of Chief Executive Officer and Chief
Financial Officer
32 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
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, 2006
-------------------------- and Chief Financial Officer
D. Scott Singdahlsen
/s/ Jane M. Richards Principal Accounting Officer April 14, 2006
--------------------------
Jane M. Richards
24