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 May 31, 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 a shell company (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
There were 37,993,259 shares of $.001 par value common stock
outstanding on July 5, 2006.
Transitional Small Business Disclosure Format (Check one): Yes [ ] No [X]
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements 3
Balance Sheets - May 31, 2006 (Unaudited) and August 31, 2005 3
Statements of Operations - Three and Nine months Ended
May 31, 2006 and May 31, 2005 (Unaudited) 4
Statements of Cash Flows - Nine months Ended May 31, 2006
and May 31, 2005 (Unaudited) 5
Notes to Financial Statements 7
Item 2. Management's Discussion and Analysis or Plan of Operation 12
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 24
Item 3. Defaults Upon Senior Securities 24
Item 4. Submission of Matters to a Vote of Security Holders 24
Item 5. Other Information 24
Item 6. Exhibits 24
Signatures 25
2
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
May 31, August 31,
2006 2005
-------- --------
(Unaudited)
ASSETS
CURRENT ASSETS
Cash $ 7,238 $ 2,934
Accounts receivable 2,090 1,742
Prepaid expenses and other current assets 78 59
-------- --------
Total current assets 9,406 4,735
-------- --------
PROPERTY AND EQUIPMENT
Oil and gas properties under full cost, net 18,682 13,242
Furniture and equipment, net 44 29
-------- --------
18,726 13,271
-------- --------
OTHER ASSETS
Deferred financing costs and other assets 30 80
-------- --------
TOTAL ASSETS $ 28,162 $ 18,086
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 232 $ 89
Amounts due oil and gas property owners 46 2
Accrued net profits interest payable 319 1,287
Other accrued liabilities 659 376
Asset retirement obligation 904 904
-------- --------
Total current liabilities 2,160 2,658
-------- --------
LONG TERM LIABILITIES
Convertible notes 7,310 6,958
Asset retirement obligation 344 293
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 - 37,993,259 at 05/31/06 and
31,640,259 shares at 8/31/05 38 32
Capital in excess of par value 51,293 43,294
Accumulated deficit (32,983) (35,149)
-------- --------
Total stockholders' equity 18,348 8,177
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 28,162 $ 18,086
======== ========
See notes to consolidated financial statements.
3
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended Nine Months Ended
May 31, May 31,
---------------------------- ----------------------------
2006 2005 2006 2005
------------ ------------ ------------ ------------
(in thousands, except share and per share data)
REVENUES
Gas and oil production revenues $ 3,703 $ 1,637 $ 7,775 $ 3,915
------------ ------------ ------------ ------------
OPERATING EXPENSES
Lease operating expenses 299 180 874 514
Production taxes, gathering and transportation 243 104 508 254
Net profits interest expense 125 283 705 638
Depletion, depreciation, amortization and accretion 942 251 1,808 469
Impairment of oil and gas properties -- 580 -- 580
General and administrative 530 488 1,618 1,497
------------ ------------ ------------ ------------
Total operating expenses
2,139 1,886 5,513 3,952
------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS 1,564 (249) 2,262 (36)
OTHER INCOME (EXPENSE)
Interest and other income 64 27 182 81
Interest (expense) (91) (86) (278) (254)
Other (expense) (2) (7) -- (14)
------------ ------------ ------------ ------------
Total other income (expense)
(29) (66) (96) (187)
------------ ------------ ------------ ------------
NET INCOME (LOSS) $ 1,535 $ (315) $ 2,166 $ (223)
============ ============ ============ ============
NET INCOME (LOSS) PER COMMON
SHARE -BASIC AND DILUTED $ 0.04 $ (0.01) $ .06 $ (0.01)
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING-
BASIC 37,945,585 31,616,772 37,092,127 31,582,213
DILUTED 38,486,234 31,616,772 37,697,023 31,582,213
See notes to consolidated financial statements.
4
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine months Ended May 31,
-------------------------
2006 2005
-------- --------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 2,166 $ (223)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Depletion, depreciation, amortization and accretion 1,808 469
Impairment of oil and gas properties -- 580
Amortization of financing costs 2 2
Interest expense converted into debt 352 335
Stock option issued for director service -- 15
Stock option expense for non-qualifying options issued 10 --
Changes in current assets and liabilities
Increase in accounts receivable (348) (1,885)
(Increase) decrease in prepaids and other current assets (18) 16
(Decrease) increase in accounts payable (144) 122
Increase in amounts due oil and gas property owners 44 --
(Decrease) increase in net profits interest liability (968) 638
Increase in accrued liabilities 283 49
------- -------
Net cash provided by operating activities 3,187 137
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions of furniture and equipment (24) (11)
Additions to oil and gas properties (7,300) (3,034)
Proceeds from exercise of exploration options -- 750
Proceeds from sale of properties 398 49
------- -------
Net cash used in investing activities (6,926) (2,246)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of common stock 8,157 --
Proceeds from exercise of stock options 33 42
Offering costs (177) --
Other 30 --
------- -------
Net cash provided by financing activities 8,043 42
------- -------
NET INCREASE (DECREASE) IN CASH 4,304 (2,067)
BEGINNING CASH 2,934 6,038
------- -------
ENDING CASH $ 7,238 $ 3,971
======= =======
See notes to consolidated financial statements.
5
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(continued)
SUPPLEMENTAL CASH FLOW INFORMATION:
Nine months Ended
May 31,
-----------------
2006 2005
------- -------
(Unaudited)
Cash paid for interest and income taxes $-- $--
Non-cash financing activities:
Net increase in payables for capital expenditures 287 475
Debt issued for interest 352 335
Asset retirement obligation increase 29 14
See notes to consolidated financial statements.
6
PYR ENERGY CORPORATION
Notes to Consolidated Financial Statements
May 31, 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 nine months ended May 31, 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 following table sets forth the computation of
basic and diluted earnings per share (in thousands except per share data):
7
Three Months Ended Nine Months Ended
May 31, May 31,
------------------- -------------------
2006 2005 2006 2005
-------- -------- -------- --------
Numerator:
Numerator for basic and diluted
earnings per share - income (loss)
available to common stockholders $ 1,535 $ (315) $ 2,166 $ (223)
Denominator:
Denominator for basic earnings
per share -weighted average
shares outstanding 37,946 31,617 37,092 31,582
Effect of dilutive securities -
stock options and warrants 540 -- 605 --
-------- -------- -------- --------
Denominator for diluted
earnings per common share 38,486 31,617 37,697 31,582
======== ======== ======== ========
Basic and diluted earnings (loss)
per common share $ 0.04 $ (0.01) $ 0.06 $ (0.01)
======== ======== ======== ========
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 nine months ended May 31,
2006 and 2005 would have been decreased to the pro forma amounts indicated
below (in thousands, except per share data):
Three Months Ended Nine Months Ended
May 31, May 31,
2006 2005 2006 2005
------- ------- ------- -------
Net income (loss) as reported $ 1,535 $ (315) $ 2,166 $ (223)
Deduct total compensation cost determined
under the fair value base method for all
awards (87) (83) (405) (249)
------- ------- ------- -------
Pro forma net income (loss) $ 1,448 $ (397) $ 1,761 $ (472)
======= ======= ======= =======
Net pro forma income (loss) per share:
As reported - Basic and Dilutive $ 0.04 $ (0.01) $ 0.06 $ (0.01)
======= ======= ======= =======
Pro forma - Basic and Dilutive $ 0.04 $ (0.01) $ 0.05 $ (0.01)
======= ======= ======= =======
8
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:
May 31, 2006 May 31, 2005
------------ ------------
Expected option life-years 5 5-10
Risk-free interest rate 4.38 - 4.5% 3.3 - 4.0%
Dividend yield 0.00% 0.00%
Volatility 48.9 - 51.83% 57 - 83%
Reclassification - Certain reclassifications have been made to the May 31,
2005 financial statements to conform to the May 31, 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
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 nine months ended May
31, 2006.
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,
9
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 withdrawn its prior statement that it would 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
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. The trial
court has taken under consideration PYR's motion for summary dismissal of
this suit.
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 has filed an adversary proceeding against the Company
requesting that the Bankruptcy Court find that the pre-bankruptcy Operating
Agreement was still effective and 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 1.95
Bcf of estimated 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 three producing wells
and a well that has been drilled, cased and is awaiting completion.
10
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.
11
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 Oklahoma
Panhandle, East 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 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 May 31, 2006, we had approximately $7.2
million in working capital and cash of $7.2 million.
Cash Flow from Operating Activities
-----------------------------------
Net cash provided by operating activities was $3.2 million and $137,000 for
the nine months ended May 31, 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 decreased cash flow from operations by approximately $1.2
million and $1.1 million in the nine months ended May 31, 2006 and 2005,
respectively. The decrease in current assets and liabilities for the current
period is principally attributed to increases in accounts receivable and a
decrease in net profits interest liability resulting from payments made.
Decreases in the nine month period in 2005 are attributed to increases in
accounts receivable.
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 $7.3 million and $3.0 million for the
nine months ended May 31, 2006 and 2005, respectively. The total for the current
nine month period includes principally $4.2 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 $1.4
million for leasehold costs including capitalized litigation costs incurred
related to our Nome project. Drilling costs for the current period were incurred
principally on three wells located in Texas, the Chisum #1 well and the Lackey
Gas Unit #1 and #2, and on the exploratory Duck Federal #1-30 well located in
Wyoming.
12
During the nine months ended May 31, 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 anticipate our capital budget for the year ended August 31, 2006 will be
approximately $11.0 million of which $7.3 million has been incurred through the
third quarter for fiscal year 2006 and will be used for a diverse portfolio of
development and exploration wells in our core areas of operation.
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 approximately $11.0 million, of which $7.3 million has been spent
through the third quarter of 2006, 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.
Off-Balance Sheet Financing
The Company has no off-balance sheet financing arrangements at May 31,
2006.
Summary of Development and Exploration Projects
Our development, exploration, and acquisition activities are focused
primarily in select areas of the Rocky Mountains, Texas and Oklahoma Panhandle,
East Texas and the Gulf Coast. A number of these projects offer multiple
drilling opportunities with individual wells having the potential of
encountering multiple reservoirs.
The following is an update of our production and exploration areas and
significant projects. While actively pursuing specific production and
exploration activities in each of the following areas, we continually review
additional acquisition opportunities in these core areas and in other areas that
meet our production and exploration criteria. For the month of May, 2006, the
latest time frame in which we have complete data, PYR's net production averaged
5.0 MMcfe per day.
Rocky Mountain Exploration
--------------------------
Mallard Project. At the Mallard project in Uinta County, Wyoming, the Duck
Federal #1-30 well is currently flowing on a 13/64" choke, with current July
production averaging 4.5 MMcf per day of gas, 85 barrels of associated
condensate, and 305 barrels of water. Within the past month the well has
undergone production logging and a bottom hole pressure survey. Results of the
tests indicate that water production has decreased significantly in the well
since initial production in mid-March (around 1200 to 1500 barrels per day at
that time). Analysis of the recent logging and pressure survey is being used to
13
design production tubing to be installed with the intent to stabilize and
enhance flow rates, as the well continues to experience an unstable slugging
flow performance through the 7" casing. We anticipate that tubing will be
installed within the next couple weeks. The Company owns a 28.75% working
interest in the well and surrounding acreage, and believes there are additional
PUD locations to drill within its acreage position. The Duck Federal #1-30
represents a development well within the giant Whitney Canyon-Carter Creek Field
complex, which has produced over 2.1 TCF to date.
It is anticipated that PYR and the working interest partners will acquire
approximately 23 square miles of 3D seismic data in order to better delineate
additional drilling opportunities in the area. The field surveying for the 3D
has been recently completed, and barring delays, we anticipate that acquisition
of the seismic should be complete by September 1.
In addition, PYR and the working interest partners are studying the
feasibility of re-entering and sidetracking the now-abandoned UPRC #25-1 well,
located approximately 2000' north of the Duck Federal. This well encountered the
Mission Canyon approximately 400' high to the Duck Federal #1-30, but failed to
penetrate the main porosity zone due to steep dips. As a result, it produced
only around 587 MMcf and 5000 barrels condensate prior to being plugged and
abandoned. PYR and its partners believe economic reserves can be found within
the porosity zones, accessible via a sidetrack.
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.
Montana Foothills Project. Following the plugging and abandonment of the
Flesher Pass exploratory well in August 2005, the Company re-evaluated the
exploration prospects associated with its undeveloped acreage in the project and
elected to release most of its undeveloped acreage position. As a result, all
remaining acreage positions will expire by August 1, 2006. As previously stated,
the Company wrote down all of its costs in the amortizable base of the full cost
pool in its first quarter, ended November 30th, 2005.
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 was
drilled in 2004 and commenced production in June 2005 from the upper Yegua and
averaged approximately 19 MMcfe per day. The well continues to produce at a
steady average rate of 12.8 MMcfe/day (8.9 MMcf/day and 625 BO/day). At the end
of May 2006 the well had cumulative production of approximately 9.9 Bcfe. When
the well reached payout on October 13, 2004, PYR was 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 net revenue interest in the well and
associated lands is 5.7%, consisting of a 5.19% working interest with a 1.5%
overriding royalty interest. We and our partners control approximately 4,200
acres of gross leasehold acres in the project.
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
owns a 5.7% net revenue interest, consisting of a 5.19% working interest and
1.5% overriding royalty interest, as arises from Samson's unit pooling and as
PYR has reported on its financial and operating statements to date, or a 4.7%
net revenue interest as has been asserted by Samson, or a higher working
interest and an overriding royalty interest, in the Sun Fee well, as PYR
believes it is entitled to. If the outcome of the litigation determines that
PYR's net revenue interest is 4.7%, the Company's oil and gas revenues for the
period of October 2004 through May 31, 2006 totaling approximately $4.2 million
would be reduced by approximately $680,000 and the Company would be required to
pay a similar amount to Samson.
Both 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 payout of 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.
14
We may drill a well (Tindall #1), offsetting by approximately 1600 feet the
Sun Fee GU #1-ST, in 2006 subject to drilling rig availability, industry
partners and the status of the Samson lawsuit. We calculate our working interest
in the Tindall #1 well to be 100%, although we anticipate that other parties may
dispute this amount. Samson Lone Star L.P. ("Samson") filed a lawsuit seeking a
judicial declaration of Samson's exclusive right to operate the Tindall well and
injunctive relief enjoining the Company from continuing its drilling operations
or serving as operator.
Samson has sent an AFE for the proposed drilling of the Nome-Long #1
exploratory well, which is located to the southeast of the Sun Fee #1 well. PYR
is currently evaluating this proposal and the Company's working interest would
be 8.33% should it elect to participate in the drilling of the well.
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 late 2006. PYR intends to retain approximately 25% working interest in the
well and intends to farmout the remainder of its interest to an industry
partner. Wells drilled in this prospect are subject to a 25% net profits
interest agreement, reducing to 12.5% after the NPI reaches payout, with the
Venus Exploration Trust.
Madison prospect, At the Madison project in the northern part of the
Constitution Field, located in Jefferson County, Texas, the Maness Gas Unit #1
well has undergone a work-over to replace production tubing damaged by corrosion
and scaling. The work-over began in mid-May, and as a result of difficulties in
removal of the existing production tubing, the well was shut-in for a protracted
time frame. The well is currently back on production recovering working fluids
and load, and it is expected that the well will return to sales in August 2006.
At the time of shut-in for the work-over, the Maness GU#1 had cumulative
production of 2.6 Bcfe (since mid-August 2004) and was averaging gross
production of approximately 400 BO/day and 1.5 MMcf/day (3.9 MMcfe/day). The
Company has a 12.5% working interest in the Maness Gas Unit #1 well.
The drilling of the Wall #1 well, a PUD location offsetting the Maness GU#1
well, should commence in the next few days. We will participate for 17.5%
working interest in the drilling of this development well, which includes 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, reducing to 25% after the NPI reaches payout with the Venus
Exploration Trust.
Tortuga Grande prospect, At the Tortuga project in Smith County, Texas, the
Chisum #1 well has been completed in the lower Rodessa section and is currently
flowing to sales. As reported earlier, the initial test rates were constrained
by flow into a low pressure system and as a result the well was tied into a high
pressure system on May 26th. Currently, the well is producing at 1 MMcf per day
with 53 barrels of associated condensate production. 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. Additional drilling
locations to fully exploit the Rodessa potential in the project area have been
identified and it is expected that approximately 25 square miles of 3D seismic
data will be acquired to better delineate the additional drilling opportunities.
The Company owns a 28.57% working interest in the Chisum well and surrounding
acreage. PYR and its partners control approximately 9,800 acres of leasehold in
the project.
Bayou Duralde Project is located in Evangeline Parish, Louisiana. The
Fontenot # 1 exploration well was spud on May 12th and reached a total depth of
10,650 feet on June 6th. Based on log and core analysis, casing has been set to
total depth and completion is underway. The first Yegua/Cockfield (CF-5) zone
has been perforated, and is currently being tested. PYR is participating with a
15% working interest before payout and 17.5% after payout in the project, and
along with its partners, controls approximately 3000 acres of leasehold. Wells
drilled in this prospect are subject to a 25% net profits interest agreement,
reducing to 12.5% after the NPI reaches payout, with the Venus Exploration
Trust.
West Westbury prospect, located in Jefferson County, Texas, targets Yegua
sand reservoirs. The prospect, based on 3D seismic amplitude, is located
approximately 1.5 miles to the southwest of a high productivity well completed
to Yegua sand reservoirs in October of 2004. This analog well, located in the
same fault block, has cumulative production, through April, 2006 of 21.9 Bcfe
and has produced on average 46 MMcfe per day. PYR owns 100% of the prospect and
is currently marketing a portion of this prospect to industry partners.
15
At the Wilburton Field in Latimer County, Oklahoma, the Scharff #7-1
commenced drilling operations in the first week of June and is currently
drilling ahead below 14,000 feet measured depth toward a target depth of
approximately 15,000 feet. It is expected that the Scharff #7-1 will reach total
depth in the next few days, and will be evaluated before commencement of
completion and stimulation activities. An AFE to drill the Scharff #8-1 has been
received from the operator and the Company has approved its participation in the
drilling of the new well. It is expected the Scharff #8-1 will begin drilling
operations once the #7-1 has completed drilling. The Scharff #6-1 was recently
placed on sales, and due to completion and fracture stimulation problems is
currently producing at a rate of approximately 6 MMcfe per day. The Scharff #5-1
well, drilled and completed in 2005, had initial production rates of up to 54
MMcfe per day, and is currently producing at an average rate in excess of 39
MMcfe per day. The Company owns 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 the Company to consolidate 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 `Total Proved' reserves of approximately 1.950
Bcf, of which 86% of the reserves are classified as `Proved Undeveloped'. PYR
owns 100% working interest on the majority of the acreage, which includes two
producing wells. The Company plans to drill two additional PUD locations in the
future.
Other
-----
SAN JOAQUIN BASIN, CALIFORNIA
The Company continues to maintain its three prospects, Blizzard, Bulldog,
and Wedge in this region. PYR will decide to drill, farm out, or sell its
position in the future.
16
Results of Operations
The results of operations for interim periods are not necessarily
indicative of the results of operations for the full fiscal year.
Three Months Ended May 31, 2006 Compared to Three Months Ended May 31, 2005
The third quarter ended May 31, 2006 resulted in net income of $1.5 million
compared to a net loss of $315,000 for the same quarter in 2005.
Three Months Ended
May 31, Increase (Decrease)
--------------------- -----------------------
2006 2005 Amount Percent
--------- --------- --------- ---------
($ in thousands, except for per unit prices and costs)
Operating Results:
Revenues
Gas production revenues $ 2,461 $ 748 $ 1,713 229%
Oil production revenues 987 888 99 11%
Natural gas liquids revenues 169 1 168 100%
Other products 86 -- 86 100%
--------- --------- ---------
Total revenues $ 3,703 $ 1,637 $ 2,066 126%
Operating Expenses
Lease operating expense 299 180 119 66%
Production taxes, gathering and transportation expense 243 104 139 134%
Net profits expense 125 283 (158) (56%)
Depletion, depreciation, amortization and accretion 942 251 691 275%
Impairment of oil and gas properties -- 580 (580) (100%)
General and administrative 530 488 42 9%
--------- --------- --------- ---------
Total operating expenses $ 2,139 $ 1,886 $ 253 13%
Interest Expense $ 91 $ 86 $ 5 6%
Production Data:
Natural gas (Mcf) 331,207 104,033 227,174 218%
Oil (Bbls) 16,138 17,455 (1,317) (8%)
Natural gas liquids (Bbls) 5,747 27 5,720 100%
Combined volumes (Mcfe) 462,517 208,925 253,592 121%
Daily combined volumes (Mcfe/d) 5,027 2,271 2,756 121%
Average Prices:
Natural gas (per Mcf) $ 7.43 $ 7.19 $ 0.24 3%
Oil (per Bbl) 61.15 50.86 10.29 20%
Natural gas liquids (per Bbl) 29.45 40.64 (11.19) (28%)
Combined (per Mcfe) 8.01 7.84 0.17 2%
Average Costs (per Mcfe):
Lease operating expense $ 0.65 $ 0.86 ($ 0.21) (24%)
Production taxes, gathering and transportation expense 0.52 0.50 0.02 4%
Net profit expense 0.27 1.36 (1.09) (80%)
Depletion, depreciation, amortization and accretion 2.04 1.20 0.84 70%
General and administrative 1.15 2.34 (1.19) (51%)
Interest Expense 0.20 0.41 (0.21) (51%)
Oil and Gas Revenues. Oil and gas revenues increased 126% to approximately
$3.7 million for the three months ended May 31, 2006 from approximately $1.6
million for the same period in 2005 due to i) a 121% increase in production and
17
ii) a 2% increase in average Mcfe prices. Average price increases added
approximately $35,000 of revenues while increases in average Mcfe production
volumes added approximately $2.1 million of revenues. An increase of natural gas
liquids (NGLs) production of 5,720 Bbls, principally from the Duck Federal #1-30
well, offset a 1,317 Bbl decline in oil production. Production increases were
attributed to the development of three Scharff wells located in Oklahoma, the
addition of production from an exploratory well located in Wyoming, the Duck
Federal #1-30 and increased production from existing wells. The Duck Federal
#1-30 well also generated revenues of approximately $86,000 from the sale of
sulfur.
Comparison of fiscal year 2006 second and third quarters production numbers
- Total net production for third quarter was 81% higher than the second quarter
of fiscal 2006 production primarily due to production from the Scharff #5 and
Scharff #6 wells located in Oklahoma and from the Duck Federal #1-30 well
located in Wyoming. Average prices increased in the third quarter by a nominal
2% over the second quarter.
Lease Operating Expenses. Our per unit of production lease operating
expenses decreased 25% from $0.86 per Mcfe in the third quarter of fiscal year
2005 to $0.65 for the same period in fiscal year 2006. This per unit of
production decrease is principally attributed to higher production volumes from
existing wells and lower per unit operating costs on new wells. Total lease
operating expenses increased 66% principally due to the addition of new
producing wells.
Production Taxes, Gathering and Transportation Expenses. Production taxes
as a percentage of natural gas and oil revenues were virtually unchanged at
approximately 5.7% for the third quarter in fiscal year 2006 compared to 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. Total production taxes increased $117,000, or 123%, over the same
period in 2005 as a result of higher production revenues, attributed to
increased production volumes. Gathering, transportation and other sales expenses
increased by $22,000 in 2006 compared with the same period in 2005.
Net Profits Expense. The net profits interest agreement with Venus
Exploration Trust ("Trust") 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 56%
decrease in net profits expense for the third quarter ended May 31, 2006
compared with the same period in 2005 is attributed principally to lower net
revenues and higher operating costs associated with the wells subject to the net
profits obligation and to increased litigation costs associated with the dispute
with Samson (see Note 2 to the financial statements). As of May 31, 2006, the
Company has paid net profits expenses totaling $1.7 million.
Depletion, Depreciation, Amortization and Accretion Expense. Depletion,
depreciation, amortization and accretion expense was $942,000 for the third
quarter ended May 31, 2006 compared with $251,000 for the same period in the
prior year. The increase is principally attributed to depletion expense which
increased $686,000. Depletion expense increase is the result of a 121% increase
in production volumes in the third 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 $1.17 per Mcfe in the third quarter of
the prior year to approximately $2.01 per Mcfe in the third 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 and additional costs, principally capitalized legal costs associated with
the Nome prospect, for which no additional reserves have been added. 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 May 31, 2006 increased by approximately $42,000 or 9%
from the same period in 2005. The principal costs contributing to the increase
were higher Texas franchise taxes associated with increased sales in Texas. As a
result of higher production volume levels, general and administrative costs per
unit of production decreased from $2.34 per Mcfe in the third quarter of the
prior year to $1.15 per Mcfe for the current period
Interest Income. Interest income increased by $38,000 to $64,000 for the
third quarter ended May 31, 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 May 31, 2006 and 2005, we
recorded interest expense of $91,000 and $86,000, respectively. The interest
expense, primarily associated with the Company's convertible notes due May 24,
18
2009, increased due to an increase in convertible note principal balances
(resulting from adding previously accrued interest to the principal). In May
2006, the Company elected to pay accrued interest due on the convertible notes
of approximately $176,500 by increasing the outstanding balance of the
Convertible Notes.
Nine Months Ended May 31, 2006 Compared to Nine Months Ended May 31, 2005
The first nine months ended May 31, 2006 resulted in net income of $2.2
million compared to a net loss of $223,000 for the same period in 2005.
Nine Months Ended
May 31, Increase (Decrease)
--------------------- -----------------------
2006 2005 Amount Percent
--------- --------- --------- ---------
($ in thousands, except for per unit prices and costs)
Operating Results:
Revenues
Gas production revenues $ 4,953 $ 1,748 $ 3,205 183%
Oil production revenues 2,563 2,159 404 19%
Natural gas liquids revenues 173 8 165 100%
Other products 86 -- 86 100%
--------- --------- --------- ---------
Total revenues $ 7,775 $ 3,915 $ 3,860 99%
Operating Expenses
Lease operating expense 874 514 360 70%
Production taxes, gathering and transportation expense 508 254 254 100%
Net profits expense 705 638 67 10%
Depletion, depreciation, amortization and accretion 1,808 469 1,339 286%
Impairment of oil and gas properties -- 580 (580) (100%)
General and administrative 1,618 1,497 121 8%
--------- --------- --------- ---------
Total operating expenses $ 5,513 $ 3,952 $ 1,561 39%
Interest Expense $ 278 $ 254 $ 24 9%
Production Data:
Natural gas (Mcf) 636,352 248,743 387,609 156%
Oil (Bbls) 42,157 44,846 (2,689) (6%)
Natural gas liquids (Bbls) 5,880 280 5,600 2000%
Combined volumes (Mcfe) 924,574 519,499 405,075 78%
Daily combined volumes (Mcfe/d) 3,387 1,903 1,484 78%
Average Prices:
Natural gas (per Mcf) $ 7.78 $ 7.03 $ 0.75 11%
Oil (per Bbl) 60.79 48.15 12.64 26%
Natural gas liquids (per Bbl) 29.55 29.00 .55 2%
Combined (per Mcfe) 8.41 7.54 0.87 12%
Average Costs (per Mcfe):
Lease operating expense $ 0.95 $ 0.99 ($ 0.04) (4%)
Production taxes, gathering and transportation expense 0.55 0.49 0.06 12%
Net profit expense 0.76 1.23 (0.47) (38%)
Depletion, depreciation, amortization and accretion 1.96 0.90 1.06 118%
General and administrative 1.75 2.88 (1.13) (39%)
Interest Expense 0.30 0.49 (0.19) (39%)
Oil and Gas Revenues. Oil and gas revenues increased by approximately $3.9
million, or 99%, to approximately $7.8 million for the nine months ended May 31,
2006 from approximately $3.9 million for the same period in 2005 due to i) a 78%
increase in production and ii) a 22% increase in average price per Mcfe. Average
19
price increases added approximately $453,000 of revenues while increases in
average Mcfe production volumes added approximately $3.4 million of revenues. An
increase of natural gas liquids (NGLs) production of 5,600 Bbls, principally
from the Duck Federal #1-30 well, offset a 2,689 Bbl decrease in oil production.
Other product revenues are comprised of revenues from the sale of sulfur
produced in Wyoming. Production increases resulted from the development and
addition of production from four Scharff wells located in Oklahoma and the
Lackey #2 well located in Texas, the addition of production from the Duck
Federal #1-30, an exploratory well located in Wyoming and increased production
from existing wells.
Lease Operating Expenses. Our per unit of production lease operating
expenses decreased 4% from $0.99 per Mcfe in the first nine months of fiscal
year 2005 to $0.95 for the same period in fiscal year 2006. This per unit of
production decrease is principally attributed to higher production volumes from
existing wells and lower per unit operating costs on new wells. Total lease
operating expenses increased 70% principally due to the addition of new
producing wells.
Production Taxes, Gathering and Transportation Expenses. Production taxes
as a percentage of natural gas and oil revenues averaged 5.7% and 6.1% for the
first nine months of fiscal years 2006 and 2005, respectively. 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
$206,000, or 86%, over the same period in 2005 as a result of higher production
revenues attributed to increased production volumes. Gathering, transportation
and other sales expenses increased by $47,000 in 2006 compared with the same
period in 2005.
Net Profits Expense. The net profits interest agreement with Venus
Exploration Trust ("Trust") 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 10%
increase for the first nine months of fiscal year 2006 compared with the same
period in 2005 is attributed to increased net operating profits from wells
subject to the net profits agreement, offset, in part, by capital development
costs and litigation expenses associated with the Nome prospect. As of May 31,
2006, the Company has paid net profits expenses totaling $1.7 million.
Depletion, Depreciation, Amortization and Accretion Expense. Depletion,
depreciation, amortization and accretion expense was $1.8 million for the first
nine months of fiscal year 2006 compared with $469,000 for the same period in
the prior year. The increase is principally attributed to depletion expense
which increased $1.3 million. Depletion expense increase is the result of a 78%
increase in production volumes in the first nine months of 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 $0.86 per Mcfe in
the first nine months of the prior year to $1.92 per Mcfe in the first nine
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 and additional costs, principally capitalized legal costs
associated with the Nome prospect, for which no additional reserves have been
added. 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 nine months for fiscal year 2006 increased by $121,000, or 8%,
from the same period in 2005. Increases are primarily due to higher office rent
and Texas franchise taxes. As a result of higher production volume levels,
general and administrative costs per unit of production decreased from $2.88 per
Mcfe in the first nine months of the prior year to $1.75 per Mcfe for the
current period
Interest Income. Interest income increased by $108,000 to $179,000 for the
first nine 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 nine month period ended May 31, 2006 and 2005,
we recorded interest expense of $278,000 and $254,000, 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 $352,000 and $335,000 for the nine months ended May 31, 2006 and
2005, respectively, by increasing the outstanding balance of the Convertible
Notes.
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 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 and legal costs incurred to defend the Company's
revenue interest in the Nome prospect, 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 May 31, 2006, the
Company has sold more than its entitlement by 12 MMcfs with a fair market value
of approximately $82,000.
Deferred Tax allowance:
As of May 31, 2006, the Company has a substantial deferred tax asset,
consisting principally of tax loss carryforwards valued at approximately $15.3
million. This deferred tax asset is fully offset by a deferred tax allowance as
the Company continues to believe it is more likely than not that such asset will
be realized due to the historical uncertainty in the volatility of oil and gas
prices, the industry in general and past historical losses. The Company
continues re-evaluate this estimate.
21
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
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 nine
months ended May 31, 2006.
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
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 withdrawn its prior statement that it would 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 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. The trial court has taken under
consideration PYR's motion for summary dismissal of this suit.
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 has filed an adversary
proceeding against the Company requesting that the Bankruptcy Court find that
the pre-bankruptcy Operating Agreement was still effective and 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.
23
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
The following matters were submitted to a vote of security holders at the
annual meeting of stockholders which was held on June 22, 2006:
The stockholders voted to re-elect David Kilpatrick, D. Scott Singdahlsen,
Bryce W. Rhodes and Dennis Swenson to continue as directors of the Company. A
total of 25,155,827 votes were represented with respect to this matter, with
voting on each specific nominee as follows:
BROKER
FOR AGAINST WITHHELD NON-VOTES
---- ------- -------- ---------
David Kilpatrick 23,885,744 0 1,270,083 -
D. Scott Singdahlsen 23,868,586 0 1,287,241 -
Bryce W. Rhodes 23,900,744 0 1,255,083 -
Dennis Swenson 23,886,044 0 1,269,783 -
A proposal to approve the adoption of a 2006 stock incentive plan under
which a maximum of 4,000,000 shares of the Company's common stock could be
issued to employees, directors and other persons selected to receive
equity-based compensation awards. A total of 15,314,131 votes were represented
with a total of 10,492,267 (69%) shares voting for the proposal, 4,787,338
shares voting against the proposal, and 34,526 shares abstaining from voting.
A proposal to ratify the sale as part of the October 2005 private placement
of 20,000 shares of common stock to a trust controlled by Kenneth R. Berry, Jr.
our Vice President of Land and currently Corporate Secretary and 50,000 shares
of common stock to an entity controlled by Mr. Berry. A total of 15,314,131
votes were represented with a total of 13,715,261 (90%) shares voting for the
proposal, 1,552,957 shares voting against the proposal, and 45,913 shares
abstaining from voting.
A proposal to ratify the selection of Hein & Associates LLP as our
Certified Public Accountants was approved by the stockholders. A total of
25,155,827 votes were represented with a total of 23,070,923 (92%) shares voting
for the proposal, 2,062,856 shares voting against the proposal, and 22,048
shares abstaining from voting.
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
24
SIGNATURES
----------
In accordance with the requirements of the Exchange Act, the Registrant has
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Signatures Title Date
------------------------ ------------------------------- -------------
/s/ D. Scott Singdahlsen President, Chief Executive Officer July 17, 2006
------------------------ and Chief Financial Officer
D. Scott Singdahlsen
/s/ Jane M. Richards Principal Accounting Officer July 17, 2006
------------------------
Jane M. Richards
25