Edgar Filing: PYR ENERGY CORP

AutoCoded Document

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 November 30, 2005

[ ]

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 incorporation or organization)		(I.R.S. Employer Identification No.)
1675 Broadway, Suite 2450, Denver, CO		80202
(Address of principal executive offices)		(Zip Code)

(303) 825-3748
(Registrant's telephone number, including area code)

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [ X ] No [ ]

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [ X ]

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 37,915,259 shares of $.001 par value common stock outstanding on November 30, 2005.

PART I. FINANCIAL INFORMATION


Item 1. Financial Statements		3
Balance Sheets - November 30, 2005 (Unaudited) and August 31, 2005		3
Statements of Operations - Three Months Ended November 30, 2005
and November 30, 2004 (Unaudited)		4

Statements of Cash Flows - Three Months Ended November 30, 2005
and November 30, 2004 (Unaudited)		5
Notes to Financial Statements		7

Item 2. Management's Discussion and Analysis or Plan of Operation		10
Item 3. Controls and Procedures		18

PART II. OTHER INFORMATION


Item 1. Legal Proceedings		19

Item 2. Unregistered Sales o f Equity Securities and Use of Proceeds		19
Item 3. Defaults Upon Senior Securities		19
Item 4. Submission of Matters to a Vote of Security Holders		19
Item 5. Other Information		20
Item 6. Exhibits		20
Signatures		21

ITEM 1. FINANCIAL STATEMENTS

	November 30, 2005		August 31, 2005
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash	$ 10,084		$ 2,934
Oil and gas receivables	1,215		1,618

Other receivable	58		124
Prepaid expenses and other assets	22		59

Total current assets	11,379		4,735

PROPERTY AND EQUIPMENT, at cost
Oil and gas properties under full cost, net	14,765		13,242
Furniture and equipment, net	48		29

	14,813		13,271

OTHER ASSETS
Deferred financing costs and other assets	31		80

TOTAL ASSETS	$ 26,223		$ 18,086

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable	$ 114		$ 89

Accrued net profits interest payable	671		1,287
Other accrued liabilities	478		378
Asset retirement obligation	904		904

Total current liabilities	2,167		2,658

LONG TERM LIABILITIES
Convertible notes	7,133		6,958
Asset retirement obligation	300		293
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value; authorized 1,000,000 shares;

issued and outstanding - none	--		--
Common stock, $.001 par value; authorized 75,000,000 shares;
issued and outstanding - 37,915,259 at 11/30/05 and
31,640,259 shares at 8/31/05	38		32
Capital in excess of par value	51,278		43,294
Accumulated deficit	(34,693	)	(35,149	)

Total stockholders' equity	16,623		8,177

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 26,223		$ 18,086

See notes to consolidated financial statements.

PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

	Three Months Ended November 30,
	2005		2004
	(in thousands, except share and per share data)
REVENUES
Oil and gas revenues	$ 2,003		$ 1,083

OPERATING EXPENSES

Lease operating expenses	244		209

Production taxes, gathering and transportation	124		73

Net profits interest expense	259		122
Depletion, depreciation, amortization and accretion	357		44
General and administrative	504		511

Total operating expenses	1,488		959

INCOME FROM OPERATIONS	515		124
OTHER INCOME (EXPENSE)
Interest income	47		20
Other income	--		4
Interest (expense)	(99	)	(83	)
Other (expense)	(7	)	(4	)

Total other income (expense)	(59	)	(63	)

NET INCOME	$ 456		$ 61

NET INCOME PER COMMON
SHARE - BASIC AND DILUTED	$ 0.01		$ 0.00

WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING-
BASIC	35,417,567		31,564,426
DILUTED	36,010,317		32,045,587

See notes to consolidated financial statements.

PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended November 30,
	2005		2004
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 456		$ 61
Adjustments to reconcile net income to
net cash provided by operating activities
Depletion, depreciation and amortization	351		38
Amortization of financing costs	1		1
Interest expense converted into debt	175		167
Stock option expense for non-qualifying options issued	5		--
Accretion of asset retirement obligation	6		6
Changes in assets and liabilities

Decrease (increase) in accounts receivable	403		(591	)
Decrease in prepaids and other receivables	103		74
(Decrease) increase in accounts payable	(73	)	101

(Decrease) increase in net profits interest liability	(616	)	123
Increase in accrued expenses	100		415

Net cash provided by operating activities	911		395

CASH FLOWS FROM INVESTING ACTIVITIES

Additions of furniture and equipment	(21	)	(9	)
Additions to oil and gas properties	(1,773	)	(1,220	)

Proceeds from exercise of exploration options	--		750

Proceeds from sale of properties	--		25

Net cash used in investing activities	(1,794	)	(454	)

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 INCREASE (DECREASE) IN CASH	7,150		(59	)
CASH, BEGINNING OF PERIODS	2,934		6,038

CASH, END OF PERIODS	$ 10,084		$ 5,979

See notes to consolidated financial statements.

PYR ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(continued)

	Three Months Ended November 30,
	2005	2004
	(Unaudited)
SUPPLEMENTAL CASH FLOW INFORMATION:

Cash paid for interest and income taxes	$ -	$ --
Non-cash financing activities:

Net increase in payables for capital expenditures	99	131
Debt issued for interest	175	167

Third party exercise of right to drill option (collected in 2005)	--	750

Asset retirement obligation increase	--	13

See notes to consolidated financial statements.

PYR ENERGY CORPORATION
Notes to Consolidated Financial Statements
November 30, 2005
(Unaudited)

The accompanying interim financial statements of PYR Energy Corporation are unaudited. In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three months ended November 30, 2005 are not necessarily indicative of the operating results for the entire year.

We have prepared the financial statements included herein pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosure normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and recommend that these condensed financial statements be read in conjunction with the 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.

The Company’s financial statements are based on a number of significant estimates, including reliability of receivables, selection of the useful lives for property and equipment, timing and costs associated with its retirement obligations and oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties.

The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which it may be currently liable. In addition, the Company’s oil and gas business makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated reserves, which are considered significant estimates by the Company, 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 Company’s full cost pool.

Earnings (Loss) Per Share – Basic earnings (loss) per common share is computed by dividing net earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible equity instruments, such as convertible notes payable, stock options and warrants. The dilutive effect of such securities was insignificant for the three months ended November 30, 2005 and 2004, respectively.

Share Based Compensation – In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123), effective for fiscal years beginning after December 15, 1995. This statement defines a fair value method of accounting for employee stock options and encourages entities to adopt that method of accounting for its stock compensation plans. SFAS 123 allows an entity to continue to measure compensation costs for these plans using the intrinsic value based method of accounting as prescribed in Accounting Pronouncement Bulletin Opinion No. 25, Accounting for Stock Issued to Employees (APB 25). The Company has elected to continue to account for its employee stock compensation plans as prescribed under APB 25. Had compensation cost for the Company’s stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans consistent with the method prescribed in SFAS 123, the Company’s net income and income per share for the quarters ended November 30, 2005 and 2004 would have been decreased to the pro forma amounts indicated below:

	November 30, 2005		November 30, 2004
Net income:
As reported	$ 456		$ 61
Pro forma equity compensation expense	(231	)	(83	)

Pro forma net income (loss)	$ 225		$ (22	)

Pro forma net income (loss) per share:
As reported	$ 0.01		$ 0.00

Pro forma	$ 0.01		$ 0.00

Reclassification – Certain reclassifications have been made to the November 30, 2004 financial statements to conform to November 30, 2005 presentation. Such reclassifications had no effect on net income.

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.

2. STOCKHOLDERS’ EQUITY

In mid-October 2005, the Company completed a private placement consisting of 6,327,250 shares of common stock at a price of $1.30 per share to a group of accredited institutional and individual investors. The Company received approximately $8.0 million in net proceeds after deducting related offering expenses. In addition, the Company 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 the Company’s development drilling portfolio.

In December 2005, the Company filed a registration statement that would allow the re-sale by shareholders of the shares issued pursuant to this private placement. This statement became effective in January 2006.

3. CONTINGENCIES

On July 29, 2005, the Company filed a lawsuit in the U.S. District Court for the Eastern District of Texas, Beaumont Division against Samson Lone Star Limited Partnership (“Samson”) and Samson’s parent company, Samson Resources Corp. The Company alleged in its complaint that Samson, the operator of a producing gas well in Jefferson County, Texas named the Sun Fee No. 1 Sidetrack Well (the “Sun Fee Well”), has breached its obligations to the Company, which owns interests in the property on which the Sun Fee Well is located, by joining, without authorization, the Sun Fee Well into a unit with other properties in which the Company has no interest, many of which are non-productive. Samson has a large interest in the properties that Samson has joined into the unit. Pursuant to Samson’s proposed pooling configuration, the Company’s working and overriding royalty interests in the Sun Fee Well would be reduced substantially. The Company believes that Samson has no legal or contractual right to reduce the Company’s interests in this manner. The Company is seeking monetary damages for all payments due and owing to the Company based on the proper, undiluted interests in the property. On September 13, 2005, the Court entered a Preliminary Injunction ordering Samson to return the Company to pay status for the undisputed amounts upon which Samson had been paying the Company prior to the filing of the suit. On December 23, 2005, Samson filed a motion for summary judgment on the Company’s claims, to which the Company filed its response on January 3, 2006, rigorously denying that Samson has grounds in law or fact for the requested relief. The outcome of the litigation will determine whether PYR owns a 5.19% working interest and 1.5% overriding royalty interest, as arises from Samson’s unit pooling, or an 8.33% working interest and an overriding royalty interest in excess of 1.5%, in the Sun Fee well, as PYR believes it is entitled to. Even if we are not successful in the litigation, the outcome will not result in a negative adjustment to our revenues or production volumes because we have reported production and revenue only on the lower working interest and the lower royalty interest in our financial and operating statements to date. Additionally, this lower working interest and lower overriding royalty interest are undisputed, and it is only the difference between the 5.19% and 8.33% working interests and associated overriding royalty interests that are the subject of the ongoing litigation.

On August 22, 2005, Samson filed a lawsuit in District Court for Jefferson County, Texas, 58^th Judicial District against the Company, claiming that Samson has the right to serve as operator to drill and operate on the property to the east of the Sun Fee Well, which is located on property in which the Company owns a majority interest. The Company holds a 100% interest in oil and gas leases that comprise 75% of the approximately 400-acre parcel on which it is planning to drill a gas well to the same reservoir from which the Sun Fee Well produces. In June 2005, the Company notified Samson of its intention to drill a well on this property and offered Samson the opportunity to participate in the well. Samson elected to participate in the well and demanded to be allowed to operate the well. Upon the Company’s initial preparation of the drill site, which began in August 2005, Samson filed a lawsuit seeking a judicial declaration of Samson’s exclusive right to operate the well and injunctive relief enjoining the Company from continuing its drilling operations or serving as operator. The Company subsequently completed construction of the drillsite. The Company intends to drill the well in order to protect its interests in the underlying leases until such time as the issue is fully adjudicated.

The Company will continue to vigorously pursue and defend its rights with respect to the foregoing litigations.

On January 9, 2006, the Venus Exploration Trust (“Trust”) dismissed the adversary proceeding it had filed against the Company on November 2, 2005, in the on-going bankruptcy proceeding of Venus Exploration Company (“Venus”) in the U.S. Bankruptcy Court for the Eastern District of Texas. In this proceeding, the Trust, representing the interests of the secured creditors, also demanded a full accounting and, in the future, direct payment of the net profits interest accounts established under the Net Profits Conveyance by which the Company purchased Venus’ assets. Through these accounts, the Company accounts for net proceeds from income-generating projects, presently, the Nome and Madison projects in Jefferson County, Texas. The Company anticipates that final dismissal papers will be signed and filed in the near future.

4. SUBSEQUENT EVENTS

In December 2005, the Company acquired additional working interests in the Hansford project, located in Hansford County of the Texas panhandle, from multiple private entities for $1.7 million. The acquisition includes approximately 1.95 Bcf of proved reserves of which 86% are undeveloped and 2,265 acres of leasehold. With this acquisition, the Company will own 100% working interest on a majority of the acreage which includes two producing wells and a well that has been drilled, cased and is awaiting completion.

In addition, in December 2005, the Company sold its interest in certain leasehold acreage located in its School Road prospect in California for approximately $96,000.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development projects, capital expenditures and other uncertainties, as well as those factors discussed below and in our Annual Report on Form 10-KSB for the year ended August 31, 2005. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

The following discussion should be read in conjunction with the Financial Statements and Notes thereto referred to in “Item 1. Financial Statements” of this Form 10-QSB.

Overview

PYR Energy Corporation (referred to as “PYR,” the “Company,” “we,” “us” and “our”) is an independent oil and gas exploration and production company, engaged in the exploration, development and acquisition of crude oil and natural gas reserves. Our current focus is on the Rocky Mountain, Texas and Gulf Coast regions.

Liquidity and Capital Resources

Our primary sources of liquidity historically have been from sale of our common stock, issuance of convertible notes, and to a much lesser extent, net cash provided by operating activities. Our primary use of capital has been for the acquisition, development, and exploration of oil and natural gas properties. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production is highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. At November 30, 2005, we had $9.2 million in working capital and cash of approximately $10.1 million.

Cash Flow from Operating Activities

Net cash provided by operating activities was $959,000 and $395,000 for the three months ended November 30, 2005 and 2004, 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 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 $83,000 in the first quarter ended November 30, 2005 compared with an increase in cash flows from operations of $121,000 in the same period in 2004. The decrease in current assets and liabilities for the current period is principally attributed to a reduction of net profits liability resulting from net profits payments, offset, in part, by a decrease in oil and gas receivables attributed principally to collection of previously suspended revenues.

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 $1.8 million and $1.2 million for the first quarter ended November 30, 2005 and 2004, respectively. The total for the current period includes principally $1.4 million for drilling, development, exploration and exploitation and $422,000 for leasehold acquisition costs. Drilling costs for the current period were incurred principally on two development wells located in Texas, the Chisum #1 well and the Lackey Gas Unit #2 well, and on the exploratory #1-30 Duck Federal well located in Wyoming.

During the first quarter ended November 30, 2004, we received $750,000 for a non-refundable option fee received from Suncor Energy Natural Gas America, Inc. (“SENGAI”) pursuant to an Exploration Option Agreement between the Company and SENGAI covering our Rogers Pass exploration project in the foothills of west-central Montana.

We currently anticipate our capital budget will be approximately between $7.5 and $10.0 million for fiscal year 2006 which will be used for a diverse portfolio of development and exploration wells in our core areas of operation. We may consider selling down a portion of our interests in some of our exploration and development projects to industry partners to generate additional funds to finance our 2006 capital budget. We are projecting that cash on hand, cash available from operating activities, and funds from the partial sale of our interest in some prospects will be sufficient to fund our 2006 capital budget.

Financing Activities

In mid-October 2005, the Company completed a private placement of 6,327,250 shares of common stock at a priced 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 the Company’s development drilling portfolio located principally in the Rocky Mountains and Texas.

It is anticipated that the continuation and future development of our business will require additional, and possibly substantial, capital expenditures. We have no reliable source for additional funds for administration and operations to the extent our existing funds have been utilized. In addition, our capital expenditure budget for the fiscal year ending August 31, 2006 will depend on our success in selling additional prospects for cash, the level of industry participation in our exploration projects, the availability of debt or equity financing, cash on hand’ and the results of our activities. We anticipate spending a minimum of approximately between $7.5 and $10.0 million on exploration and development activities during our fiscal year ending August 31, 2006. To limit capital expenditures, we intend to form industry alliances and exchange an appropriate portion of our interest for cash and/or a carried interest in our exploration projects. We may need to raise additional funds to cover capital expenditures. These funds may come from cash flow, equity or debt financings, a credit facility, or sales of interests in our properties, although there is no assurance additional funding will be available or that it will be available on satisfactory terms.

Our future financial results continue to depend primarily on (1) our ability to discover commercial quantities of hydrocarbons; (2) the market price for oil and gas; (3) our ability to continue to source and screen potential projects; and (4) our ability to fully implement our exploration and development program with respect to these and other matters. There can be no assurance that we will be successful in any of these respects or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production.

Summary of Development and Exploration Projects

Our development and exploration activities are focused primarily in select areas of the Rocky Mountains, Texas and the Gulf Coast. Advanced seismic imaging of the structural and stratigraphic complexities common to these regions provides us with the enhanced ability to identify significant oil and gas reserve potential. A number of these projects offer multiple drilling opportunities with individual wells having the potential of encountering multiple reservoirs.

The following is a summary of our exploration areas and significant projects. While actively pursuing specific exploration activities in each of the following areas, we continually review additional opportunities in these core areas and in other areas that meet our exploration criteria.

Rocky Mountain Exploration

Mallard Project. The #1-30 Duck Federal Sidetrack well commenced drilling in mid-July 2004 and was temporarily suspended, due to winter drilling restrictions, in December 2004. The wellbore was re-entered in early August 2005, and reached a total measured depth of 15,110’ on October 18, 2005 within the Lodgepole Formation. Based on analysis of drilling shows, open-hole logs, and reservoir pressure measurements, the working interest partners decided to attempt a completion of the well within the objective Mission Canyon Formation. Casing has been run to total depth, and the well has been perforated over the prospective zones. The Mission Canyon is the primary producing zone within the nearby Whitney Canyon-Carter Creek Field, which has produced over 2.1 Tcfe to date. It is believed that the #1-30 Duck Federal well has encountered the Whitney Canyon-Carter Creek accumulation, and likely represents a development step out well. The #1-30 Duck Federal well has been completed and is currently awaiting final hook-up to processing and sales. Based on logging results and reservoir pressure tests indicating approximately 3800 psi, 177 net feet of reservoir were perforated and stimulated, within eleven separate zones covering a 333 foot gross interval, in the well. Due to the high H2S content (17 to 20%), a limited ‘clean-up’ flow back was accomplished and indicated flow rates of approximately 10 MMcf per day with associated liquid production. The Company believes that additional, un-perforated, pay exists in the wellbore. While previously anticipated that the well would be brought on-line to sales by mid-January, final start up of production has been delayed due to ongoing third party construction and modification at the gas processing plant. The operator has indicated that it is currently anticipated that production and sales will commence by late February contingent on no additional construction delays. The Company owns a 28.75% working interest in the well and surrounding acreage. It is anticipated that PYR and the working interest partners will acquire approximately 20 square miles of 3-D seismic data during the summer of 2006 in order to better delineate additional drilling opportunities in the area. PYR is participating in the project with a 28.75% working interest.

Ryckman Creek Project. We have leased approximately 1,820 net acres, covering the majority of the abandoned Ryckman Creek field, in the Overthrust region of southwestern Wyoming. Ryckman Creek, located 6 miles east of our Mallard prospect, was discovered in 1975 and produced approximately 250 Bcfe prior to abandonment. We believe that significant remaining recoverable gas reserves were stranded in Ryckman Creek upon abandonment. We are currently analyzing production and geologic data to determine potential reserves in multiple zones, including the Twin Creek, Nugget, and Thaynes Formations, in the field. Due to rig availability timing, it is anticipated that additional development activity of the Ryckman Creek project will not occur until sometime in 2006.

Montana Foothills Project. Following the plugging and abandonment of the Flesher Pass exploratory well in August 2005, the project operator has informed the Company that they do not intend to exercise their option to drill an additional earning well on the acreage block. The Company is re-evaluating exploration prospects associated with its undeveloped acreage in the project and subsequent to August 31, 2005, has elected to release some of its 241,800 acres of undeveloped acreage.

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. Production in the Sun Fee GU #1-ST well (the “Sun Fee Well”), from the upper Yegua, was initiated in late May 2004, and beginning in early June 2005, averaged approximately 19MMcfe per day. Cumulative production since inception is in excess of 8.089 Bcfe through end of December, 2005. 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 working interest in the well and associated lands is 5.19% with a 1.5% overriding royalty interest. We and our partners control approximately 4,200 acres of gross leasehold acres in the project. We intend to drill a well (Tindall #1), offsetting by approximately 1600 feet the Sun Fee GU #1-ST, in 2006 subject to drilling rig availability. We calculate our working interest in the Tindall #1 well to be 77.08%, 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.

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 5.19% working interest and 1.5% overriding royalty interest, as arises from Samson’s unit pooling, or an 8.33% working interest and an overriding royalty interest in excess of 1.5%, in the Sun Fee well, as PYR believes it is entitled to. Even if we are not successful in the litigation, the outcome will not result in a negative adjustment to our revenues or production volumes because we have reported production and revenue only on the lower working interest and the lower royalty interest in our financial and operating statements to date. Additionally, this lower working interest and lower overriding royalty interest are undisputed, and it is only the difference between the 5.19% and 8.33% working interests and associated overriding royalty interests that are the subject of the ongoing litigation.

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 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.

Madison prospect, located in the northern part of the Constitution Field, Jefferson County, Texas, is an exploitation project to test multiple sand intervals within the expanded Yegua section, downthrown to a major growth fault. The Maness GU #1 well started production in mid-August 2004, and from inception through December 2005 the well has cumulative production of approximately 2.085 Bcfe. The well is currently producing at a rate of approximately 4 MMcfe per day. The operator has converted an existing well bore within the project area into a water disposal well, and is planning to drill an offset development well (Wall#1) in the spring of 2006, depending on rig availability. We will participate for 17.5% working interest in the drilling of this development well based on our additional purchase of 5% working interest from the operator. The purchase calls for the Company to fund 6.66% of the drilling costs to casing point to earn the additional 5% working interest in the Wall #1 well and surrounding acreage. Wells drilled in this prospect are subject to a 50% net profits interest agreement with the Venus Exploration Trust.

Tortuga Grande prospect, located in Smith County, Texas, is a project to test the productivity of the Cotton Valley Sand section. The Chisum #1 well, operated by Carrizo Oil and Gas Inc, is projected to a target depth of approximately 15,500 feet, and is designed to test a potentially thicker section of Cotton Valley Sand in a more favorable structural position to the Brady #1 well. As a result of certain parties in the well electing not to participate in the drilling of the well, PYR exercised its rights to increase its working interest in the well to 28.57% working interest. The Chisum #1 well reached total drilling depth of approximately 15,850 feet. Log and core analysis of the Cotton Valley section revealed abundant sand thickness in the expanded ‘turtle’ section, but did not indicate commercial reservoir properties. As a result, the operator recommended abandonment of the Cotton Valley section and completion of multiple horizons in the Travis Peak and Rodessa formations. Multiple zones within the Travis Peak have been perforated and stimulated, yielding a modest amount of oil recovery. Flow testing of the Travis Peak has been initiated, and once completed, it is anticipated that the Rodessa will be completed and tested. Rodessa production, within 3 miles to the north and northeast of the Chisum location, has yielded cumulative production ranging up to 6.4 Bcfe per well. The Company is participating in the completion of the Travis Peak and Rodessa with its 28.57% working interest. PYR and its partners control approximately 9,800 acres of leasehold in the project. Pending favorable results from the Chisum #1 completion, the Company anticipates drilling additional wells to fully exploit the Travis Peak and Rodessa potential in the project area. Wells drilled in this prospect are subject to a net profits interest agreement with the Venus Exploration Trust.

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 2006. PYR will retain approximately 25% working interest in the well and intends to farmout the remainder of its interest to an industry partner.

Merganser prospect, located in Leon County, Texas, targets Cotton Valley and Bossier sandstone reservoirs in an undrilled structural feature defined by 3D seismic data. The prospect occupies a fault-bounded salt-withdrawal trough resulting in potential significant thickening of the Bossier and Cotton Valley sand sections. The prospect location is structurally and stratigraphically downdip from Cotton Valley production as well as updip from recent Bossier productive discoveries. Due to competition and skyrocketing lease costs in the project area, PYR has decided to discontinue active leasing in the project, and has signed an agreement to sell its interest in approximately 250 acres, in the prospect, for $1,000 per acre.

Bayou Duralde Project, located in Evangeline Parish, LA, is an exploration program to identify and drill potential gas reservoirs in Yegua/Cockfield channel complexes. PYR owns a 25% working interest in the project and controls, along with its partner, in excess of 3,000 net acres of leasehold. PYR will participate with a 15% cost bearing interest and has farmed out the remainder of its working interest. It is anticipated that the initial test well at Bayou Duralde will begin drilling operations in the first six months of 2006 depending on rig availability.

At the Wilburton Field in Latimer County, Oklahoma, the Scharff #4-1 well was recently drilled and completed in the Lower Atoka (Cecil) formation, which resulted in initial production rates of up to 38 MMcf per day and is currently producing at an average rate of approximately 19 MMcfe per day. The Scharff #5-1 well, an offset of the Scharff #4-1, commenced drilling activity on September 13, 2005, and reached total drilling depth in early November 2005. The Scharff #5-1 is currently undergoing final completion activities, and should be placed on sales in early 2006. It is anticipated that the well will initially produce at rates exceeding 20 MMcf per day based on flow testing to date. The Scharff #6-1 well was spud on November 30, 2005 and is currently drilling ahead below 14,000 feet. The Company has 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. Purchased originally as part of the Venus Exploration acquisition, the Company purchased additional working interest in two wells and associated undeveloped acreage in January and February 2005 for approximately $400,000. On December 20, 2005, the Company closed a strategic acquisition of additional interest in the Hansford project, from multiple private entities, for $1.7 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 will own 100% working interest on the majority of the acreage, which includes two producing wells in addition to the recently drilled Lackey GU #2 well which commenced drilling on October 23, 2005, has been cased, and is currently awaiting completion. The Company plans to complete the Lackey GU #2 and drill two additional PUD locations in the spring of 2006.

Other

SAN JOAQUIN BASIN, CALIFORNIA

Blizzard Prospect. This project is a 3D seismic derived exploration and exploitation program offsetting the Rio Viejo field at the south end of the San Joaquin Basin. A linear sand body, stratigraphically higher than any of the productive Rio Viejo sands, has been identified, north of the field, on the seismic data and represents an exploration opportunity for new reserves. Additionally, analysis of the seismic data over the field suggests that up to two additional undrilled field exploitation locations may exist. PYR owns 100% of the prospect.

Bulldog Prospect. This project is a 2D seismically identified natural gas and condensate prospect located adjacent to the giant Kettleman North Dome field in the San Joaquin Basin. This prospect can be best characterized as a classic footwall fault trap, similar to the many known footwall fault trap accumulations that have produced significant quantities of hydrocarbons throughout the San Joaquin basin. We intend to sell down our working interest in this project and retain a 25% to 50% working interest in the prospect acreage.

Wedge Prospect. This is a seismically identified Temblor prospect located northwest of and adjacent to the East Lost Hills deep gas discovery. During the first fiscal quarter of 2001, we acquired approximately 17 miles of proprietary, high effort 2D seismic data and combined this data with existing 2D seismic data in order to refine what we interpret as the up-dip extension of the East Lost Hills structure. Our seismic interpretation shows that the same trend at East Lost Hills extends approximately ten miles farther northwest of the East Lost Hills Area of Mutual Interest and can be encountered as much as 3,000 feet higher. Our approach is to sell down our working interest to industry partners, and retain a 25% to 50% working interest in this prospect.

CANADA

The Company’s Canadian oil and gas property investment is comprised principally of non-producing acreage. During fiscal year 2005, the Company impaired its initial investment of $580,000 in the Canadian properties and decided to limit future expenditures in Canada.

Results of Operations

Three Months Ended November 30, 2005 Compared to Three Months Ended November 30, 2004

	Three Months Ended
	November 30,		Increase (Decrease)
	2005	2004		Amount		Percent
	($ in thousands)
Operating Results:
Revenues
Oil and gas production revenues	$ 2,003	$ 1,083		$ 920		85	%
Interest income	47	20		27		135	%
Operating Expenses
Lease operating expense	244	209		35		17	%
Production taxes, gathering and transportation expense	124	73		51		70	%
Net profits expense	259	122		137		112	%
Depletion, depreciation, amortization and accretion	357	44		313		711	%
General and administrative	504	511		(7	)	(1	%)

Total operating expenses	$ 1,488	$ 959		$ 529		55	%
Interest Expense	$ 99	$ 83		$ 16		19	%
Production Data:
Natural gas (Mcf)	130,244	63,057		67,187		107	%
Oil (Bbls)	12,602	13,978		(1,376	)	(10	%)
Combined volumes (Mcfe)	205,856	146,925		58,931		40	%
Daily combined volumes (Mcfe/d)	2,262	1,615		647		40	%
Average Prices:
Natural gas (per Mcf)	$ 9.53	$ 7.07		$ 2.46		35	%
Oil (per Bbl)	60.46	45.54		14.92		33	%
Combined (per Mcfe)	9.73	7.37		2.36		32	%
Average Costs (per Mcfe):
Lease operating expense	$ 1.18	$ 1.42		$ (0.24	)	(17	%)
Production taxes, gathering and transportation expense	0.60	0.48		0.12		25	%
Net profit expense	1.26	0.83		0.43		52	%
Depletion, depreciation, amortization and accretion	1.73	.30		1.43		477	%
General and administrative	2.45	3.48		(1.03	)	(30	%)
Interest Expense	.48	.57		(0.09	)	(16	%)

The first quarter ended November 30, 2005 resulted in net income of $456,000 compared to a net income of $61,000 for the quarter ended November 30, 2004.

Oil and Gas Revenues. Oil and gas revenues increased 85% to $2.0 million for the three months ended November 30, 2005 from approximately $1.1 million for the same period in 2004 due to both an increase in production and increases in natural gas and oil prices. Average prices added approximately $364,000 of oil and gas revenues while increases in average Mcfe production volumes added approximately $556,000 of oil and gas revenues. A 10% decrease in oil volumes was more than offset by increases in average gas production resulting from the development of existing properties. Two wells located in Texas and one in Oklahoma contributed a majority of the Company's oil and gas revenues (65%), natural gas production (76%) and oil production (43%).

Comparison of first quarter 2006 to fourth quarter 2005 production numbers - Total net production for the first quarter 2006 was lower than fourth quarter 2005 production primarily due to production curtailment of two major gas wells, located north of Beaumont, Texas, caused by the effects of Hurricane Rita during the first quarter 2006. Both the Sun Fee #1-ST (Nome Field) and the Maness GU #1 (Constitution Field) were shut-in as a safety precaution during and immediately after the hurricane passed just to the east. While not incurring any direct damage from the hurricane, production from the wells was periodically and significantly curtailed for the next month due to damage and subsequent repair to third party transportation and processing facilities. Production levels normalized to pre-hurricane levels during the remainder of the first quarter 2006.

Lease Operating Expenses. Our per unit of production lease operating expenses decreased 17% from $1.42 per Mcfe in the first quarter of fiscal year 2005 to $1.18 for the same period in fiscal year 2006. This per unit of production decrease is principally attributed to increased production volumes. Total lease operating expenses increased 17% principally due to development of existing properties.

Production Taxes, Gathering and Transportation Expenses. Production taxes as a percentage of natural gas and oil revenues averaged 5.4% for the first quarter ended November 30, 2005 compared to 6.3% for the first quarter ended November 30, 2004. Production taxes are primarily based on wellhead values of production and vary across the different areas that our wells are located. The decrease in the average percent of natural gas and oil sales is attributed to increased production from locations with lower production tax rates. Total production taxes increased as a result of higher production revenues, due to increases in both production volumes and average prices. Gathering, transportation and other sales expenses increased by a nominal amount in 2005 compared with the same period in 2004.

Net Profits Expense. The net profits interest agreement with Venus Exploration Trust ("Trust") agreement arose out of the acquisition of properties from Venus Exploration Inc. ("Venus") in May 2004. The amount of the Venus Trust net profits interest is either 25% or 50% with respect to different Venus exploration and exploitation project areas, and decreases by one-half of its original amount after an aggregate total of $3.3 million in net profits. The increase for the first quarter ended November 30, 2005 compared with the same period in 2004 is attributed to development of wells subject to the net profits agreement and related increases in operating income from these wells. During the first quarter ended November 30, 2005, operating profits from these wells were lower than the fourth quarter ended August 31, 2005 due to production from these wells being curtailed during the month following the hurricanes. As a result, net profits expense for the current quarter was lower than the previous quarter. As of November 30, 2005, the Company has paid net profits expenses totaling $931,089.

Depletion, Depreciation, Amortization and Accretion Expense. Depletion, depreciation, amortization and accretion expense was $357,000 for the first quarter ended November 30, 2005 compared with $44,000 for the same period in the prior year. The increase is principally attributed to depletion expense which increased $313,000. Depletion expense increase is the result of a 40% increase in production volumes in the first three months ended November 30, 2005 as compared to the same period in the prior year. The weighted average depletion rate for the Company's full cost pool increased from $.24 per Mcfe in the first quarter of the prior year to $1.69 per Mcfe in the first quarter of the current year which was unchanged from the previous quarter ended August 31, 2005. The rate increase is attributed to the inclusion of costs of certain impaired unevaluated properties in the amortizable base of the full cost pool. Under the full cost pool method of accounting, impairment costs of unevaluated properties, previously excluded from the amortizable base of the depletable full cost pool, are added to the full cost pool depletable base resulting in an increase in the depletion rate.

General and Administrative Expenses. General and administrative expenses during the quarter ended November 30, 2005 decreased by 1% from the same period in 2004. Due to higher production volume levels, general and administrative costs per unit of production decreased from $3.48 per Mcfe in the first quarter of the prior year to $2.45 per Mcfe for the current period

Interest Income. Interest income increased by $27,000 to $47,000 for the first quarter ended November 30, 2005 compared to the same period in 2004 principally due to increased 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 November 30, 2005 and 2004, we recorded interest expense of $99,000 and $83,000, 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 finance accrued interest on the convertible notes of approximately $175,000 and $167,000 for the quarters ended November 30, 2005 and 2004, respectively, by increasing the outstanding balance of the Convertible Notes.

Critical Accounting Policies And Estimates

We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our Financial Statements.

Reserve Estimates:

Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development 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 incurred which are directly related to oil and gas exploration and development are capitalized and subjected to depreciation and depletion. Depletable costs also include estimates of future development costs of proved reserves. Costs related to undeveloped oil and gas properties may be excluded from depletable costs until those properties are evaluated as either proved or unproved. The net capitalized costs are subject to a ceiling limitation based on the estimated present value of discounted future net cash flows from proved reserves. As a result, we are required to estimate our proved reserves at the end of each quarter, which is subject to the uncertainties described in the previous section. Gains or losses upon disposition of oil and gas properties are treated as adjustments to capitalized costs, unless the disposition represents a significant portion of the Company's proved reserves.

Revenue Recognition:

The Company recognizes oil and gas revenues from its interests in producing wells as oil and gas is produced and sold from these wells. The Company has no gas balancing arrangements in place. Oil and gas sold is not significantly different from the Company's product entitlement. As of November 30, 2005, the Company has sold more than its entitlement by 10 MMcfs with a fair market value of approximately $95,000.

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board issued its final standard on accounting for employee stock options, SFAS No. 123 (Revised 2004), Share-Based Payment (SFAS 123 (R)). SFAS 123 (R) replaces SFAS No. 123, Accounting for Stock-Based Compensation (SFAS 123), and supersedes APB 25, Accounting for Stock Issued to Employees. SFAS 123 (R) requires companies to measure compensation costs for all share-based payments, including grants of employee stock options, based on the fair value of the awards on the grant date and to recognize such expense over the period during which an employee is required to provide services in exchange for the award. The pro forma disclosures previously permitted under SFAS 123 will no longer be an alternative to financial statement recognition. For entities that file as a small business issuer, such as PYR Energy Corporation, SFAS 123 (R) is effective for all awards granted, modified, repurchased or cancelled after, and to unvested portions of previously issued and outstanding awards vesting for annual periods beginning after December 15, 2005, which for us will be the first quarter of fiscal 2007. We are currently evaluating the effect of adopting SFAS 123 (R) on our financial position and results of operations. We currently estimate the adoption of SFAS 123 (R) will result in expenses in amounts that are similar to the current pro forma disclosures under SFAS 123.

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.

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.

On August 22, 2005, Samson filed a lawsuit in District Court for Jefferson County, Texas, 58th Judicial District against the Company, claiming that Samson has the right to serve as operator to drill and operate on the property to the east of the Sun Fee Well, which is located on property in which the Company owns a majority interest. The Company holds a 100% interest in oil and gas leases that comprise 75% of the approximately 400-acre parcel on which it is planning to drill a gas well to the same reservoir from which the Sun Fee Well produces. In June 2005, the Company notified Samson of its intention to drill a well on this property and offered Samson the opportunity to participate in the well. Samson elected to participate in the well and demanded to be allowed to operate the well. Upon the Company's initial preparation of the drill site, which began in August 2005, Samson filed a lawsuit seeking a judicial declaration of Samson's exclusive right to operate the well and injunctive relief enjoining the Company from continuing its drilling operations or serving as operator. The Company subsequently completed construction of the drillsite. The Company intends to drill the well in order to protect its interests in the underlying leases until such time as the issue is fully adjudicated.

The Company will continue to vigorously pursue and defend its rights with respect to the foregoing litigations.

On January 9, 2006, the Venus Exploration Trust ("Trust") dismissed the adversary proceeding it had filed against the Company on November 2, 2005, in the on-going bankruptcy proceeding of Venus Exploration Company ("Venus") in the U.S. Bankruptcy Court for the Eastern District of Texas. In this proceeding, the Trust, representing the interests of the secured creditors, also demanded a full accounting and, in the future, direct payment of the net profits interest accounts established under the Net Profits Conveyance by which the Company purchased Venus' assets. Through these accounts, the Company accounts for net proceeds from income-generating projects, presently, the Nome and Madison projects in Jefferson County, Texas. The Company anticipates that final dismissal papers will be signed and filed in the near future.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The information required by this item was previously filed on October 4, October 13, and October 26, 2005, respectively, on three Forms 8-K.

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

Exhibits

Exhibit Index

Number Description

Rule 13a-14(a) Certifications of Chief Executive Officer and Chief Financial Officer

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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 and	January 17, 2006
D. Scott Singdahlsen	Chief Financial Officer



/s/ Jane M. Richards	Principal Accounting Officer	January 17, 2006
Jane M. Richards