U.S. Securities And Exchange Commission
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended November 30, 2006
OR
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from to
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Commission File No. 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 large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date.
Class Outstanding as of January 11, 2007
Common stock, $0.001 par value 37,993,259
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements 3
Balance Sheets - November 30, 2006 (Unaudited) and August 31, 2005 3
Statements of Operations - Three months Ended November 30, 2006
and November 30, 2005 (Unaudited) 4
Statements of Cash Flows - Three months Ended November 30, 2006
and November 30, 2005 (Unaudited) 5
Notes to Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 12
Item 3. Quantitative and Qualitative Disclosures About Market Risk 19
Item 4. Controls and Procedures 20
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 20
Item 1A. Risk Factors 22
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 22
Item 3. Defaults Upon Senior Securities 22
Item 4. Submission of Matters to a Vote of Security Holders 22
Item 5. Other Information 22
Item 6. Exhibits 22
SIGNATURES 23
EXHIBIT INDEX
2
ITEM 1. FINANCIAL STATEMENTS
PYR ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
November 30, August 31,
2006 2006
-------- --------
(Unaudited)
ASSETS
CURRENT ASSETS
Cash $ 4,872 $ 6,254
Accounts receivable 1,707 1,846
Prepaid expenses and other current assets 27 64
-------- --------
Total current assets 6,606 8,164
-------- --------
PROPERTY AND EQUIPMENT
Oil and gas properties under full cost, net 22,115 20,421
Furniture and equipment, net 61 45
-------- --------
22,176 20,466
-------- --------
OTHER ASSETS
Deferred financing costs and other assets 28 29
-------- --------
TOTAL ASSETS $ 28,810 $ 28,659
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 329 $ 321
Amounts due oil and gas property owners 48 38
Accrued net profits interest payable 203 231
Other accrued liabilities 565 1,035
Asset retirement obligation 907 907
-------- --------
Total current liabilities 2,052 2,532
-------- --------
LONG TERM LIABILITIES
Convertible notes 7,493 7,310
Asset retirement obligation 373 366
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 11/30/06 and 8/31/06,
respectively 38 38
Capital in excess of par value 51,350 51,292
Accumulated deficit (32,496) (32,879)
-------- --------
Total stockholders' equity 18,892 18,451
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 28,810 $ 28,659
======== ========
The accompanying notes are an integral part of the consolidated financial statements.
3
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
November 30,
--------------------
2006 2005
-------- --------
(in thousands, except per share data)
REVENUES
Gas and oil production revenues $ 2,619 $ 2,003
-------- --------
OPERATING EXPENSES
Lease operating expenses 424 244
Production taxes, gathering and transportation 193 124
Net profits interest expense 62 259
Depletion, depreciation, amortization and accretion 897 357
General and administrative 626 504
-------- --------
Total operating expenses 2,202 1,488
-------- --------
INCOME FROM OPERATIONS 417 515
OTHER INCOME (EXPENSE)
Interest and other income 58 47
Interest (expense) (92) (99)
Other (expense) -- (7)
-------- --------
Total other income (expense) (34) (59)
-------- --------
NET INCOME $ 383 $ 456
======== ========
NET INCOME PER COMMON
SHARE -BASIC AND DILUTED $ 0.01 $ 0.01
======== ========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING-
BASIC 37,993 35,417
DILUTED 38,264 36,010
The accompanying notes are an integral part of the consolidated financial statements.
4
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended November 30,
-------------------------------
2006 2005
-------- --------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 383 $ 456
Adjustments to reconcile net income to
net cash provided by operating activities
Depletion, depreciation, amortization and accretion 897 357
Amortization of financing costs 1 1
Interest expense converted into debt 184 175
Non-cash employee and director stock option expense 58 --
Stock option expense for non-qualifying options issued -- 5
Changes in current assets and liabilities
Decrease in accounts receivable 139 403
Decrease in prepaids and other current assets 37 103
Increase (decrease) in accounts payable 40 (73)
Increase in amounts due oil and gas property owners 10 --
Decrease in net profits interest liability (28) (616)
(Decrease) increase in accrued liabilities (306) 100
-------- --------
Net cash provided by operating activities 1,415 911
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions of furniture and equipment (20) (21)
Additions to oil and gas properties (2,811) (1,773)
Proceeds from sale of properties 34 --
-------- --------
Net cash used in investing activities (2,797) (1,794)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from sale of common stock -- 8,164
Offering costs -- (161)
Other -- 30
-------- --------
Net cash provided by financing activities -- 8,033
-------- --------
NET (DECREASE) INCREASE IN CASH (1,382) 7,150
BEGINNING CASH 6,254 2,934
-------- --------
ENDING CASH $ 4,872 $ 10,084
======== ========
The accompanying notes are an integral part of the consolidated financial statements.
5
PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(continued)
SUPPLEMENTAL CASH FLOW INFORMATION:
Three Months Ended
November 30,
------------------
2006 2005
------ ------
(Unaudited)
Cash paid for interest and income taxes $ -- $ 11
Non-cash financing activities:
Net increase in payables for capital expenditures -- 99
Debt issued for interest 184 175
Non-cash employee and director stock option expense 58 --
The accompanying notes are an integral part of the consolidated financial statements.
6
PYR ENERGY CORPORATION
Notes to Consolidated Financial Statements
November 30, 2006
(Unaudited)
1. ORGANIZATION
---------------
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 and conducts its activities principally in the Rocky Mountain, Texas
and Gulf Coast regions of the United States. The Company was incorporated in
March 1996 in the state of Delaware under the name Mar Ventures Inc. Effective
as of August 6, 1997, the Company purchased all the ownership interests of PYR
Energy, LLC, an oil and gas exploration company. On November 12, 1997, the name
of the Company was changed to PYR Energy Corporation. Effective July 2, 2001,
the Company was re-incorporated in Maryland through the merger of the Company
into a wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation.
On February 18, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC
were formed as wholly owned subsidiaries of PYR Energy Corporation. PYR Mallard
LLC owns and is developing the Company's Mallard project in Uinta County,
Wyoming. PYR Cumberland LLC and PYR Pintail LLC are currently inactive.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
---------------------------------------------
Basis of Presentation. 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 months ended November 30, 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, 2006.
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 the Company 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 our full cost pool.
Earnings Per Share. Basic earnings per common share is computed by dividing
net income by the weighted average number of common shares outstanding during
the applicable period. Diluted earnings per share incorporates the dilutive
impact, if any, of outstanding stock options by including the effect of
7
outstanding vested and unvested options in the average number of common shares
outstanding during the period. The following table sets forth the computation of
basic and diluted earnings per share (in thousands except per share data):
Three Months Ended
November 30,
-------------------
2006 2005
------- -------
Net income $ 383 $ 456
======= =======
Basic weighted-average common shares outstanding in period 37,993 35,417
Add dilutive effect of stock options and warrants 271 593
------- -------
Diluted weighted-average common shares outstanding in period 38,264 36,010
======= =======
Basic and diluted earnings per common share $ 0.01 $ 0.01
Share Based Compensation. The Company has three share-based compensation
plans, which are described in the Company's Form 10-KSB for the year ended
August 31, 2006. Stock options are granted to employees and directors at
exercise prices equal to the fair market value of the Company's stock at the
dates of grants. Generally, options vest annually over various periods up to
five years of continuous service and expire over various periods up to ten years
from the date of grant. On occasion, the Company has issued warrants not covered
under plans approved by the shareholders to individuals for services performed.
As of November 30, 2006, the Company had 727,500 warrants outstanding with
exercise prices ranging from $0.65 to $1.49 that expire over various periods up
to October 17, 2010.
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 encouraged entities to adopt that method of accounting for its
stock compensation plans. SFAS 123 allowed 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 elected to continue to
account for our employee stock compensation plans as prescribed under APB 25.
Under APB 25, no compensation expense was recorded for stock options issued
under qualified plans. 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 quarter ended November 30, 2005 would have
been decreased to the pro forma amounts indicated below (in thousands, except
per share data):
Three Months Ended
November 30, 2005
-----------------
Net income as reported $ 456
Deduct total compensation cost determined under the fair
value base method for all awards (231)
-----
Pro forma net income $ 225
=====
Net pro forma income (loss) per share:
As reported - Basic and Dilutive $0.01
=====
Pro forma - Basic and Dilutive $0.01
=====
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 123R). SFAS 123R replaces SFAS No. 123 and supersedes
APB 25. SFAS 123R 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. Effective September 1, 2006, the Company adopted SFAS 123R using
the modified prospective transition method. Under this transition method,
compensation costs are recognized in the financial statements beginning with the
8
effective date, based on the requirements of SFAS 123R for all share-based
payments granted after that date, and based on the requirements of SFAS 123 for
all unvested awards granted prior to the effective date of SFAS 123R. Prior
periods have not been restated. Total share-based compensation expense for
vested equity-based awards in the three months ended November 30, 2006, was
approximately $ 58,000 and is reflected in "General and Administrative" expense
in the Consolidated Statement of Operations. There was no impact on income tax
expense. Total unrecognized compensation expense from unvested stock options, as
of November 30, 2006, was approximately $350,000, which is expected to be
recognized over a period of a weighted average period of 2.0 years.
The Company uses the Black-Scholes valuation model to determine the fair
value of each option award. Expected volatilities are based on the historical
volatility of the Company's stock over a period consistent with that of the
expected terms of the options. The expected terms of the options are estimated
based on factors such as vesting periods, contractual expiration dates,
historical trends in stock price and historical exercise behavior. The risk-free
rates for periods within the contractual life of the options are based on the
yields of U.S. Treasury instruments with terms comparable to the estimated
option terms. The following assumptions were used in estimating fair value of
share-based awards for the periods indicated:
November 30, 2006 November 30, 2005
----------------- -----------------
Expected life 5 years 5 years
Risk-free interest rate 4.6% 4.4%
Dividend yield 0.0% 0.0%
Expected volatility 85.7% 91.7%
The following table summarizes option activity during the three months ended
November 30, 2006:
Weighted Average
Remaining Aggregate
Weighted-Average Contractual Term Intrinsic
Options Shares Exercise Price (Years) Value
----------------------------------------------------------------------------------------------
Outstanding at September 1, 2006 2,331,750 $1.07
Options granted 79,014 0.97
Options forfeited (300,000) 1.11
---------
Outstanding at November 30, 2006 2,110,764 $1.06 3.5 $267,790
==========================================================
Exercisable at November 30, 2006 1,649,259 $1.05 3.1 $14,680
==========================================================
The weighted-average grant-date fair value of options granted during the
three months ended November 30, 2006 was $0.68. The fair value of options vested
during the three months ended November 30, 2006 was $96,000.
Options Options Exercisable
Outstanding ----------------------------
Weighted Average
Number of Remaining Weighted Number of Weighted
Exercise Price Options Contractual Life Average Options Average
Range Outstanding (in years) Exercise Price Exercisable Exercise Price
------------------------------------------------------------------------------------------------
$0.29 - $0.29 275,000 3.2 $0.29 275,000 $0.29
$0.46 - $0.97 686,014 4.4 $0.91 436,508 $0.88
$1.12 - $1.15 383,000 3.8 $1.13 231,000 $1.14
$1.24 - $1.82 766,750 2.6 $1.43 706,751 $1.42
---------- ---------
2,110,764 3.5 $1.06 1,649,259 $1.05
===============================================================================
Recently Issued Accounting Pronouncements. In May 2005, the Financial
Accounting Standards Board ("FASB"), as part of an effort to conform to
international accounting standards, issued Statement of Financial Accounting
Standards ("SFAS") No. 154, Accounting Changes and Error Corrections ("SFAS No.
9
154"), which was effective for us beginning on September 1, 2006. SFAS No. 154
requires that all voluntary changes in accounting principles be retrospectively
applied to prior financial statements as if that principle had always been used,
unless it is impracticable to do so. When it is impracticable to calculate the
effects on all prior periods, SFAS No. 154 requires that the new principle be
applied to the earliest period practicable. The adoption of SFAS No. 154 has not
had a material effect on our financial position or results of operations.
On July 13, 2006, the FASB released Interpretation No. 48, Accounting for
Uncertainty in Income Taxes - an Interpretation of FASB Statement 109 ("FIN
48"). FIN 48 requires companies to evaluate and disclose material uncertain tax
positions it has taken with various taxing jurisdictions. We are currently
reviewing and evaluating the effect, if any, of adopting FIN 48 on our financial
position and results of operations. We will be required to adopt FIN 48 for our
fiscal year ended August 31, 2008.
In September 2006, the SEC issued Staff Accounting bulletin ("SAB") No.
108, Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements. SAB 108 provides guidance on
the consideration of effects of the prior year misstatements in quantifying
current year misstatements for the purpose of a materiality assessment. The SEC
Staff believes registrants must quantify errors using both a balance sheet and
income statement approach and evaluate whether either approach results in
quantifying a misstatement that, when all relevant quantitative and qualitative
factors are considered, is material. SAB 108 will be effective for the Company
as of September 1, 2006; however, it is not expected to have a material affect
on the Company's financial statements.
In September 2006, FASB issued SFAS No. 157, Fair Value Measurements. SFAS
No. 157 defines fair value, establishes a framework for measuring fair value,
and expands disclosure requirements regarding fair value measurement. Where
applicable, this Statement simplifies and codifies fair value related guidance
previously issued within GAAP. Although this Statement does not require any new
fair value measurements, its application may, for some entities, change current
practice. SFAS No. 157 will be effective for the Company beginning September 1,
2008. The adoption of SFAS No. 157 is not expected to have a material impact on
our financial statements.
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 GU #1-ST well
(the "Sun Fee Well"), had 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 (the "Sidetrack Unit") with
other properties in which the Company had no interest, many of which are
non-productive. Samson has a large interest in the properties that Samson had
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.
Until approximately August 1, 2005, Samson had been paying the Company its
share of oil and gas revenues based on Samson's calculation of the Company's net
revenue interest (5.7%) in the Sun Fee Well after dilution for the disputed
pooling of the non-productive properties, when it ceased paying the Company any
portion of the production proceeds from the Sun Fee Well. On September 13, 2005,
the Court entered a Preliminary Injunction ordering Samson to return the Company
to pay status for the 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
10
of its claims that it owns an 8.33% working interest as well as an overriding
royalty interest greater than 1.5%. On September 15, 2006, the U.S. District
Court for the Eastern District of Texas issued its ruling on the outstanding
motions for summary judgment that had been filed by both PYR and Samson. In its
ruling, the Court held (1) that Samson did not have authority to pool PYR's 3.5%
overriding royalty interest in the Sun Fee Well into the Sidetrack Unit and,
therefore, that PYR is entitled to the full, undiluted interest in all
production from the Sun Fee Well based on this overriding royalty; and (2) that
although Samson controlled PYR's working interest at the time the Sidetrack Unit
was formed, PYR would be able to maintain its claim for breach of contract
against Samson for joining non-productive acreage into the unit. The Court also
left for trial PYR's claims that Samson had also breached the underlying
agreements by failing to assign to PYR its working interest in all properties as
called for in the underlying contracts and by failing to give PYR geologic and
other technical information applicable to the Sun Fee Well and the Sidetrack
Unit. The Court held that PYR's alternate claim that Samson owed PYR a fiduciary
duty in forming the Sidetrack Unit was fully resolved by its other rulings.
Following a brief scheduling conference, the Court has requested that the
parties discuss next steps, including (i) resuming the trial schedule for the
issues and claims that remain unresolved by the Court's order, (ii) the
immediate appeal on the rulings made to date in the order and/or (iii) mediation
of the issues in dispute.
On August 11, 2006, the State District Court for Jefferson County, Texas,
58th Judicial District, issued a final summary judgment in the Company's favor
against Samson in Samson's suit to enjoin the Company's drilling of the Tindall
Well, located in Jefferson County, Texas on property directly adjacent to and
east of the Sun Fee Well. As previously reported, on the grounds that it had the
exclusive right to serve as operator to drill the proposed Tindall Well, Samson
had filed suit to enjoin or prevent the Company from drilling the planned well
on the approximately 400-acre property in which the Company holds 100% of the
oil and gas interest. Upon mutual agreement of the parties, no appeal will be
taken from the final judgment.
On February 15, 2006, the Company filed a motion in the ongoing 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 Tindall 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. A ruling by the Court should also clarify whether the
parties' rights to operate their interests in the Cotton Creek Prospect are
subject to an existing operating agreement or are free to enter into a new
operating agreement. The parties have submitted the matter to the Bankruptcy
Court on motions for summary and partial summary judgment.
The Company will continue to vigorously pursue and defend its rights with
respect to the foregoing matters.
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, 2006. 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-Q.
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 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 November 30, 2006, we had approximately
$4.6 million in working capital and cash of $4.9 million.
Cash Flow from Operating Activities
-----------------------------------
Net cash provided by operating activities was $1.4 million and $911,000 for
the three months ended November 30, 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 and the
recognition of compensation expense associated with unvested options resulting
from the adoption of FASB 123R effective September 1, 2006 as discussed in the
Notes to Consolidated Financial Statements. Changes in current assets and
liabilities decreased cash flow from operations by approximately $109,000 and
$83,000 in the three months ended November 30, 2006 and 2005, respectively. The
decrease in current assets and liabilities for the current period is principally
attributed to a decrease in accrued liabilities offset, in part, by a decrease
in accounts receivable. Decreases in the three month period in 2005 are
attributed principally to a reduction in the net profits liability resulting
from payments made offset by a decrease 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 $2.8 million and $1.8 million for the
three months ended November 30, 2006 and 2005, respectively. The total for the
current three month period includes principally $2.0 million for drilling,
development, exploration and exploitation, and $800,000 for leasehold costs
including capitalized litigation costs incurred related to our Nome project.
Drilling costs for the current period were incurred principally on two wells
located in Texas, the Wall #1 well and the Nome-Long #1, and on the exploratory
#1-30 Duck Federal well located in Wyoming. Included in drilling costs is a
drilling pre-payment of $493,000 for the UPRC #25-1 well located in Wyoming. The
operator of this well released the rig that it expected to use to drill the
re-entry of UPRC #25-1 resulting in delaying the drilling of this well.
12
We anticipate our capital budget for the year ended August 31, 2007 will be
approximately $10.0 million of which $2.8 million has been incurred through the
first quarter for fiscal year 2007 and will be used for a diverse portfolio of
development and exploration wells in our core areas of operation. In addition to
the capital budget in fiscal 2007, the Company expects to pay its share of
plugging costs of approximately $900,000 for six wells located in the East Lost
Hills area of California. In accordance with FASB 143, Accounting for Asset
Retirement Obligations, discussed in the Company's Form 10-KSB for the year
ended August 31, 2006, the Company has previously recognized this plugging
obligation as an asset retirement obligation, a current liability, on its
balance sheet.
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 has been and will continue to 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, 2007 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 $10.0 million, of which $2.8 million has been spent
through the first quarter of 2007, on exploration and development activities
during our fiscal year ending August 31, 2007. 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 had no off-balance sheet financing arrangements as of November
30, 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 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 our core areas that meet our production
and exploration criteria. Currently, PYR's net production is 5.2 MMcfe per day.
Rocky Mountain Region
---------------------
Mallard Project. The Company's Mallard Project is located within the
Whitney Canyon-Carter Creek field complex in the Overthrust Belt area of Uinta
County, Wyoming. Of the more than 2.1 Tcfe that has been produced to date by all
operators from this field, over 80% of the production is from the Mission Canyon
formation, which is the primary producing formation of the #1-30 Duck Federal
well. The #1-30 Duck Federal well is currently producing approximately 6.0 MMcf
of gas, 90 barrels of associated condensate and 350 barrels of water per day.
Production has improved since recently running a tubing string after an extended
shut-in. Following the successful completion of the Duck well, the Company and
its partners shot 23 square miles of 3-D seismic to define future drilling
locations, and the data is now being processed. The Company has a 28.75% working
interest in the #1-30 Duck Federal well and the 3-D seismic.
13
In addition, the Company has agreed to participate for a 28.75% working
interest in the re-drilling of an existing well, the UPRC #25-1, which directly
offsets the #1-30 Duck well. The Company was informed by the operator that the
drilling rig it expected to use to drill the re-entry of the UPRC #25-1 well has
been released temporarily to drill an intervening well for another operator.
North Stockyard Project. The Company has recently acquired a 20% working
interest in 3116 gross acres in the North Stockyard Creek field in Williams
County, North Dakota where the operator has used horizontal drilling techniques.
It is anticipated that extended reach horizontal drilling can significantly
improve the production rates of wells in this field. The Company's first
development well in the North Stockyard Creek field, the Harstad #1-15H, has
been drilled to a depth of 10,000' to evaluate the hydrocarbon potential of the
Bluell formation. The Company has determined that the Bluell zone is capable of
commercial production and intermediate casing has been set in the curved portion
of the hole. The zone will then be horizontally drilled in a southeasterly
direction to a maximum of 5,800'. With a successful completion of this well, the
Company expects that additional development wells may be drilled on the acreage
in which the Company has an interest.
Texas and Gulf Coast Region
---------------------------
Nome Field. The Company has producing interests in the Nome Field in
Jefferson County, Texas, which produces from the Yegua formation. This field was
discovered in 1994, and our interpretation of 3D seismic over the field has
identified undeveloped fault blocks, structural closures, and associated bright
spot locations. The Company's first well, the Sun Fee GU #1-ST ("Sun Fee Well"),
currently produces from the upper Yegua at an average rate of 7.2 MMcf/day and
365 BO/day (9.4 MMcfe/day). At the end of December 2006, the well had cumulative
production of over 12.3 Bcfe. When the well reached payout on October 13, 2004
(production at that time was over 19.0 MMcfe per day), PYR was placed in pay
status as a working interest participant in the well. Based on pooling of lands
into the Sun Fee Sidetrack Unit (the "Sidetrack 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 the other working interest partners control approximately 4,200 of gross
leasehold acres in the project. 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 a net profits agreement with Venus Exploration Trust
("Trust").
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 the corresponding
reduction in our working interest. The outcome of the litigation will determine
our working interest and revenue interest. See Part II, Item 1 of this document
for further details.
An additional well, in which the Company has an 8.33% working interest, the
Nome-Long #1, has been completed in the Nome Field. The well logged about 135
feet of potential Yegua gas sand. Sales from this well had been delayed pending
the construction of the Nome Central Facility by the operator. With this
facility now complete, the Nome-Long #1 well is currently producing at January
15, 2007, 7.0 MMcf and 230 BO per day on a 13/64th choke from limited
perforations (26feet) in the Yegua Formation. The operator has indicated that it
will flow test this lower interval for approximately 30 to 45 days before adding
an additional 97 feet of uphole perforations to the flow stream. Our interests
in wells drilled in this prospect are subject to the Trust's initial net profits
interest of 50%.
PYR has signed an AFE with the operator to drill the Nome-Harder #1, which
will offset the Nome-Long #1well by approximately 2685 feet to the northeast. We
expect drilling operations to begin on the Nome-Harder #1 within the next couple
months. PYR is participating with an approximate 4.167% working interest in this
planned 15,000 feet test of the Yegua Formation. Our interest in this well will
be subject to the aforementioned Trust net profits interest of 50%.
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 is currently producing approximately 350 BO/day and 1.2 MMcf/day (3.3
MMcfe/day). The production rate continues to improve steadily after the well was
shut in for an extended period over a year ago. The Company has a 12.5% working
interest in the Maness Gas Unit #1 well.
14
Also in the Madison prospect, the Company participated in drilling the Wall
#1 well, in which the Company has a 17.5% working interest. This well is a
development well that offsets the Maness GU#1 well. The Wall well was completed
during December 2006 and is producing small volumes of hydrocarbons. It is
currently undergoing further testing procedures. During completion, the well
suffered significant near well bore damage. Following planned mitigation
measures, the Company will determine whether the well is commercial. Our
interests in wells drilled in this prospect are subject to the Trust's initial
net profits interest of 50%.
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 6, 2006. Based on log and core analysis, casing has been set
to total depth, and the first Yegua/Cockfield zone has been perforated. The
operator has indicated that it is developing plans to test this well, but has
not indicated when it expects to perform the test. Should the Company elect to
participate in the evaluation of this well, and once it is tested, the economic
viability of the well will be determined. PYR has a 15% working interest before
payout (17.5% after payout) in the project. Our interests in wells drilled in
this prospect are subject to the Trust's initial net profits interest at 25%.
West Westbury Prospect, located in Jefferson County, Texas, targets Yegua
sand reservoirs. The prospect, based on 3D seismic interpretation and amplitude
analysis, is located approximately 1.5 miles to the southwest of an analog well,
in which PYR does not have an interest, completed in October of 2004. This
analog well had cumulative production of 28.6 Bcfe through September 2006,
averaging 36.8 MMcf of gas and 1655 barrels of condensate per day at that time.
Recently, a second well, in which PYR also does not have an interest, the Paggi
Broussard #2, was drilled and was producing 30.1 MMcfd and 1477 barrels of
condensate per day according to an October report. Both of these wells, along
with PYR's West Westbury prospect, are interpreted to be in the same general
structural block. Within this same area an additional well, the #1 Mixson Land,
is currently being drilled. While PYR does not own an interest in this test, the
well offsets our West Westbury prospect area by approximately 3600 feet, and
will be the third recent test by the operator on this structure. PYR is
evaluating the viability of drilling a well on its West Westbury prospect based
on these nearby wells and our technical interpretation of how they relate
geologically. PYR owns 100% working interest in the prospect and is currently
marketing a portion of this prospect to industry partners
California
----------
In California, the operator of the East Lost Hills prospect area located in
Kern County has commenced plugging operations of six wells drilled in 1998
through 2002, in which the Company has a 12.1193% working interest. The
Company's net plugging costs are expected to be approximately $900,000. The
Company has previously recognized this obligation as an asset retirement
obligation, a current liability, on its balance sheet and does not expect the
payment of these plugging costs to impact its Consolidated Statements of
Operations.
15
Results of Operations
The financial information with respect to the three months ended November
30, 2006 that is discussed below is unaudited. The results of operations for
interim periods are not necessarily indicative of the results of operations for
the full fiscal year.
Three Months Ended November 30, 2006 Compared to Three Months Ended November 30,
2005
The first quarter ended November 30, 2006 for the fiscal year ending August
31, 2007 ("fiscal 2007") resulted in net income of $383,000 compared to net
income of $456,000 for the first quarter ended November 30, 2005 for the fiscal
year ended August 31, 2006 ("fiscal 2006").
Three Months Ended
November 30, Increase (Decrease)
--------------------- ----------------------
2006 2005 Amount Percent
--------- --------- --------- ---------
($ in thousands, except for per unit prices and costs)
Operating Results:
Revenues
Gas production revenues $ 1,731 $ 1,241 $ 490 39%
Oil production revenues 840 760 80 10%
Natural gas liquids revenues 39 2 37 100%
Other products 9 -- 9 100%
--------- --------- ---------
Total revenues $ 2,619 $ 2,003 $ 616 31%
Operating Expenses
Lease operating expense $ 424 $ 244 $ 180 74%
Production taxes, gathering and transportation expense 193 124 69 56%
Net profits expense 62 259 (197) (76%)
Depletion, depreciation, amortization and accretion 897 357 540 151%
General and administrative 626 504 122 24%
--------- --------- --------- ---------
Total operating expenses $ 2,202 $ 1,488 $ 714 48%
Interest Expense $ 92 $ 99 ($ 7) (7%)
Production Data:
Natural gas (Mcf) 264,106 130,244 133,862 103%
Oil (Bbls) 14,736 12,542 2,194 17%
Natural gas liquids (Bbls) 770 60 710 1183%
Combined volumes (Mcfe) 357,142 205,856 151,286 73%
Daily combined volumes (Mcfe/d) 3,925 2,262 1,663 73%
Average Prices:
Natural gas (per Mcf) $ 6.56 $ 9.53 ($ 2.97) (31%)
Oil (per Bbl) 56.98 60.62 (3.64) (6%)
Natural gas liquids (per Bbl) 50.39 28.43 21.96 77%
Combined (per Mcfe) 7.33 9.73 (2.40) (25%)
Average Costs (per Mcfe):
Lease operating expense $ 1.19 $ 1.19 $ -- --
Production taxes, gathering and transportation expense 0.54 0.60 (0.06) (10%)
Net profit expense 0.17 1.26 (1.09) (87%)
Depletion, depreciation, amortization and accretion 2.49 1.70 0.79 46%
General and administrative 1.75 2.45 (0.70) (29%)
Interest Expense 0.26 0.48 (0.22) (46%)
16
Oil and Gas Revenues. Oil and gas revenues increased 31% to approximately
$2.6 million for the three months ended November 30, 2006 from approximately
$2.0 million for the same period in 2005. This increase is attributed to a 73%
increase in Mcf equivalent ("Mcfe") production, which was offset, in part, by a
25% decrease in average Mcfe prices.
Although natural gas prices declined by 31% from $9.53 per Mcf in the first
quarter of fiscal 2006 to $6.56 per Mcf in the first quarter of fiscal 2007, the
Company's gas production for the first quarter of fiscal 2007 increased 103%
over the same period in fiscal 2006, which offset the price declines and
resulted in a 39% increase in revenues over the same period in fiscal 2006.
Comparing first quarter of fiscal 2007 with the same period in fiscal 2006, the
gas production increases are attributed primarily to new production from three
wells located in Oklahoma, two wells located in Texas and one well located in
Wyoming that commenced production during fiscal 2006.
The Company's first quarter of fiscal 2007 oil revenues increased $80,000,
or 10%, over the same period in fiscal 2006 due to a 17% increase in production,
which was offset, in part, by a 6% decrease in average oil prices compared with
the first quarter of fiscal 2006. Increases in natural gas liquids ("NGLs")
revenues and production were generated from new production from the #1-30 Duck
Federal well located in Wyoming which commenced production in March 2006.
Oil and Gas Revenues - comparison of the first quarter in fiscal 2007 to
the fourth quarter in fiscal 2006. Total oil and gas revenues for the first
quarter of fiscal 2007 are 3% higher than the fourth quarter fiscal 2006. Gas
revenues for the first quarter fiscal 2007 are 1% lower than the previous
quarter due to a 6% decrease in production, which was offset, in part, by a 5%
increase in average gas prices. Compared to the previous quarter, the current
quarter gas production was lower principally due to natural production decline
in the Sun Fee well (Texas) and a decline in production from the Chisum well
(Texas). The Maness well (Texas), which, due to a workover, was shut-in for
nearly three months from mid-May 2006, commenced post- workover production in
late August. The post-workover production volumes are gradually improving to
approximately pre-workover volumes. The #1-30 Duck Federal well (Wyoming) gas
and oil production was curtailed from August through October 2006 due to running
a tubing string. Oil revenues for the current quarter are 4% higher than the
previous quarter due to a 35% increase in production, which was offset, in part,
by a 23% decrease in average oil prices.
Lease Operating Expenses. Our per unit of production lease operating
expenses remained unchanged at $1.19 per Mcfe for the first quarters of both
fiscal 2006 and 2007. Total lease operating expenses increased 74% principally
due to the addition of new producing wells and workover expenses incurred on the
Maness well.
Production Taxes, Gathering and Transportation Expenses. Production taxes
as a percentage of natural gas and oil revenues were approximately 6.5% for the
current quarter in fiscal 2007 compared to 5.3 % for the same quarter in fiscal
2006. 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 $61,000, or 57%, over the same period in fiscal 2006 as a result
of higher production revenues, attributed to increased production volumes, and
increased revenues in areas with higher production tax rates. Gathering,
transportation and other sales expenses increased by $8,000 in fiscal 2007
compared with the same period in fiscal 2006.
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 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 76%
decrease in net profits expense for the first quarter ended November 30, 2006
compared with the same period in 2005 resulted principally from capital
expenditures for drilling the Wall #1 well and the Nome-Long #1 well which have
not been fully offset from current operating profits on the wells that are
subject to the net profits obligation and will reduce any future net profits
obligation until fully offset. As of November 30, 2006, the Company has paid net
profits expenses totaling approximately $2.0 million.
Depletion, Depreciation, Amortization and Accretion Expense. Depletion,
depreciation, amortization and accretion expense was $897,000 for the first
quarter ended November 30, 2006 compared with $357,000 for the same period in
the prior year. The increase is principally attributed to depletion expense
which increased $539,000. Depletion expense increase is the result of a 73%
increase in production volumes in the first quarter in fiscal 2007 as compared
to the same period in the prior year. The weighted average depletion rate for
the Company's full cost pool increased from $1.69 per Mcfe in the first quarter
of fiscal 2006 to approximately $2.48 per Mcfe in the first quarter of the
fiscal 2007. The rate increase is attributed to the inclusion of costs of
certain impaired unevaluated properties in the amortizable base of the full cost
17
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 November 30, 2006 increased by approximately $122,000,
or 24% from the same period in 2005. The principal costs contributing to the
increase were higher Texas franchise taxes associated with increased sales in
Texas, AMEX registration fee associated with registering the Company's 2006
Stock Incentive Plan and non-cash stock-based compensation expense of $58,000
associated with the adoption of FASB 123R. See discussion of adoption of FASB
123R in Notes to Consolidated Financial Statements in Item 1 of this report. As
a result of higher production volume levels, general and administrative costs
per unit of production decreased from $2.45 per Mcfe in the first quarter of
fiscal 2006 to $1.75 per Mcfe in the first quarter of fiscal 2007.
Effective January 1, 2007, the Company and its former employees located in
San Antonio, Texas entered into a consulting arrangement whereby the former
employees, together with two consulting geologists and one consulting engineer,
will provide consulting services, upon request, to the Company on the Company's
strategic properties in Texas and other areas. This arrangement is expected to
reduce our general and administrative expenses while allowing us to access the
technical expertise of these consultants.
Interest Expense. During the quarters ended November 30, 2006 and 2005, we
recorded interest expense of $92,000 and $99,000, respectively. Interest expense
on the Company's convertible notes due May 24, 2009 increased by approximately
$4,000 in the first quarter of fiscal 2007 compared with the same period in
fiscal 2006 due to an increase in convertible note principal balances (resulting
from adding previously accrued interest to the principal). In November 2006, the
Company elected to pay accrued interest due on the convertible notes of
approximately $184,000 by increasing the outstanding balance of the Convertible
Notes. Other interest expense paid totaled nil and $11,000 for the first quarter
of fiscal 2007 and fiscal 2006, respectively.
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
18
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 November 30, 2006, the
Company has sold more than its entitlement by 17 MMcfs with a fair market value
of approximately $114,000.
Deferred Tax Allowance:
As of November 30, 2006, the Company had a substantial deferred tax asset,
consisting principally of tax loss carryforwards valued at approximately $16.0
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 to re-evaluate this estimate.
Recently Issued Accounting Pronouncements
In May 2005, the Financial Accounting Standards Board ("FASB"), as part of
an effort to conform to international accounting standards, issued Statement of
Financial Accounting Standards ("SFAS") No. 154, Accounting Changes and Error
Corrections ("SFAS No. 154"), which was effective for us beginning on September
1, 2006. SFAS No. 154 requires that all voluntary changes in accounting
principles be retrospectively applied to prior financial statements as if that
principle had always been used, unless it is impracticable to do so. When it is
impracticable to calculate the effects on all prior periods, SFAS No. 154
requires that the new principle be applied to the earliest period practicable.
The adoption of SFAS No. 154 has not had a material effect on our financial
position or results of operations.
On July 13, 2006, the FASB released Interpretation No. 48, Accounting for
Uncertainty in Income Taxes - an Interpretation of FASB Statement 109 ("FIN
48"). FIN 48 requires companies to evaluate and disclose material uncertain tax
positions it has taken with various taxing jurisdictions. We are currently
reviewing and evaluating the effect, if any, of adopting FIN 48 on our financial
position and results of operations. We will be required to adopt FIN 48 for our
fiscal year ended August 31, 2008.
In September 2006, the SEC issued Staff Accounting bulletin ("SAB") No.
108, Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements. SAB 108 provides guidance on
the consideration of effects of the prior year misstatements in quantifying
current year misstatements for the purpose of a materiality assessment. The SEC
Staff believes registrants must quantify errors using both a balance sheet and
income statement approach and evaluate whether either approach results in
quantifying a misstatement that, when all relevant quantitative and qualitative
factors are considered, is material. SAB 108 will be effective for the Company
as of September 1, 2006; however, it is not expected to have a material affect
on the Company's financial statements.
In September 2006, FASB issued SFAS No. 157, Fair Value Measurements. SFAS
No. 157 defines fair value, establishes a framework for measuring fair value,
and expands disclosure requirements regarding fair value measurement. Where
applicable, this Statement simplifies and codifies fair value related guidance
previously issued within GAAP. Although this Statement does not require any new
fair value measurements, its application may, for some entities, change current
practice. SFAS No. 157 will be effective for the Company beginning September 1,
2008. The adoption of SFAS No. 157 is not expected to have a material impact on
our financial statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the information set forth in this Item 3 is to
provide forward-looking quantitative and qualitative information about our
potential exposure to market risks. The term "market risk" refers to the risk of
19
loss arising from adverse changes in natural gas and oil prices and interest
rates. The disclosures are not meant to be precise indicators of expected future
losses, but rather indicators of reasonably possible losses. This
forward-looking information provides indicators of how we view and manage our
ongoing market risk exposures.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our natural
gas and oil production. Realized pricing is primarily driven by the prevailing
worldwide price for crude oil and spot market prices applicable to our U.S.
natural gas production. Pricing for natural gas and oil production has been
volatile and unpredictable for several years, and we expect this volatility to
continue in the future. The prices we receive for production depend on many
factors outside of our control. For the three months ended November 30, 2006,
our income would have changed by $26,000 for each $.10 per Mcf change in natural
gas prices and $16,000 for each $1.00 per Bbl change in crude oil prices.
We do not currently enter into hedging of our production prices.
Interest Rate Risks
At November 30, 2006, we had approximately $7.5 million in convertible
notes payable outstanding. These notes bear a fixed interest rate of 4.99% and
are convertible, together with accrued interest, into shares of the Company's
common stock at the rate of $1.30 per share, at the option of the holder. We do
not have any debt with fluctuating interest rates.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure 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 our Chief
Executive Officer and Chief 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, our Chief
Executive Officer and Chief Financial Officer believe that our disclosure
controls and procedures were, as of the end of the period covered by this
report, to the best of their knowledge effective.
Changes in Internal Control Over Financial Reporting
There has been 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.
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 GU #1-ST well
(the "Sun Fee Well"), had 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 (the "Sidetrack Unit") with
other properties in which the Company had no interest, many of which are
non-productive. Samson has a large interest in the properties that Samson had
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.
20
Until approximately August 1, 2005, Samson had been paying the Company its
share of oil and gas revenues based on Samson's calculation of the Company's net
revenue interest (5.7%) in the Sun Fee Well after dilution for the disputed
pooling of the non-productive properties, when it ceased paying the Company any
portion of the production proceeds from the Sun Fee Well. On September 13, 2005,
the Court entered a Preliminary Injunction ordering Samson to return the Company
to pay status for the 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%. On September 15, 2006, the U.S. District
Court for the Eastern District of Texas issued its ruling on the outstanding
motions for summary judgment that had been filed by both PYR and Samson. In its
ruling, the Court held (1) that Samson did not have authority to pool PYR's 3.5%
overriding royalty interest in the Sun Fee Well into the Sidetrack Unit and,
therefore, that PYR is entitled to the full, undiluted interest in all
production from the Sun Fee Well based on this overriding royalty; and (2) that
although Samson controlled PYR's working interest at the time the Sidetrack Unit
was formed, PYR would be able to maintain its claim for breach of contract
against Samson for joining non-productive acreage into the unit. The Court also
left for trial PYR's claims that Samson had also breached the underlying
agreements by failing to assign to PYR its working interest in all properties as
called for in the underlying contracts and by failing to give PYR geologic and
other technical information applicable to the Sun Fee Well and the Sidetrack
Unit. The Court held that PYR's alternate claim that Samson owed PYR a fiduciary
duty in forming the Sidetrack Unit was fully resolved by its other rulings.
Following a brief scheduling conference, the Court has requested that the
parties discuss next steps, including (i) resuming the trial schedule for the
issues and claims that remain unresolved by the Court's order, (ii) the
immediate appeal on the rulings made to date in the order and/or (iii) mediation
of the issues in dispute.
On August 11, 2006, the State District Court for Jefferson County, Texas,
58th Judicial District, issued a final summary judgment in the Company's favor
against Samson in Samson's suit to enjoin the Company's drilling of the Tindall
Well, located in Jefferson County, Texas on property directly adjacent to and
east of the Sun Fee Well. As previously reported, on the grounds that it had the
exclusive right to serve as operator to drill the proposed Tindall Well, Samson
had filed suit to enjoin or prevent the Company from drilling the planned well
on the approximately 400-acre property in which the Company holds 100% of the
oil and gas interest. Upon mutual agreement of the parties, no appeal will be
taken from the final judgment.
On February 15, 2006, the Company filed a motion in the ongoing 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 Tindall 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. A ruling by the Court should also clarify whether the
parties' rights to operate their interests in the Cotton Creek Prospect are
subject to an existing operating agreement or are free to enter into a new
operating agreement. The parties have submitted the matter to the Bankruptcy
Court on motions for summary and partial summary judgment.
21
The Company will continue to vigorously pursue and defend its rights with
respect to the foregoing matters.
Item 1A. RISK FACTORS
In addition to the other information set forth in this report, you should
carefully consider the factors discussed in "Risk Factors" in part I, Item 1 of
the Company's Annual Report on Form 10-KSB for the fiscal year ended August 31,
2006, which could materially affect the Company's business, financial condition
or future results. The risks described in the Company's Annual Report on Form
10-KSB are not the only risks facing the Company. Additional risks and
uncertainties not currently known to the Company or that the Company currently
deems to be immaterial also may materially adversely affect the Company's
business, financial condition and/or operating results.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS
Exhibit Index
--------------------------------------------------------------------------------
Number Description
------ ----------------------------------------------------------------------
3.1* Articles of Incorporation, filed with the Maryland Secretary of State
on June 18, 2001(1)
3.2* Articles of Merger, filed with the Maryland Secretary of State on July
3, 2001(1)
3.3* Bylaws(1)
4.1* Specimen Common Stock Certificate(2)
4.2* Subscription and Registration Rights Agreement between Wellington
parties and the Company, September 2005(3)
31.1 Rule 13a-14(a) Certifications of Chief Executive Officer
31.2 Rule 13a-14(a) Certifications of Chief Financial Officer
32 Certification of Chief Executive Officer and Chief Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
----------
* Previously filed.
(1) Incorporated by reference from the Company's Form 10-KSB for the year ended
August 31, 2001.
(2) Incorporated by reference from the Company's Form 10-KSB/A1 for the year
ended August 31, 1997.
(3) Incorporated by reference from the Company's Report on Form 8-K filed on
October 8, 2005.
22
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/ Kenneth R. Berry Jr. President and Chief Executive January 16, 2007
------------------------- Officer
Kenneth R. Berry Jr.
/s/ Jane M. Richards Chief Financial Officer January 16, 2007
-------------------------
Jane M. Richards
23
EXHIBIT INDEX
Exhibit Index
--------------------------------------------------------------------------------
Number Description
------ ----------------------------------------------------------------------
3.1* Articles of Incorporation, filed with the Maryland Secretary of State
on June 18, 2001(1)
3.2* Articles of Merger, filed with the Maryland Secretary of State on July
3, 2001(1)
3.3* Bylaws(1)
4.1* Specimen Common Stock Certificate(2)
4.2* Subscription and Registration Rights Agreement between Wellington
parties and the Company, September 2005(3)
31.1 Rule 13a-14(a) Certifications of Chief Executive Officer
31.2 Rule 13a-14(a) Certifications of Chief Financial Officer
32 Certification of Chief Executive Officer and Chief Financial Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002
----------
* Previously filed.
(1) Incorporated by reference from the Company's Form 10-KSB for the year ended
August 31, 2001.
(2) Incorporated by reference from the Company's Form 10-KSB/A1 for the year
ended August 31, 1997.
(3) Incorporated by reference from the Company's Report on Form 8-K filed on
October 8, 2005.