Shellbridge Oil & Gas 20FR12G Initial registration of securities (foreign private issuers)

As filed with the Securities and Exchange Commission on May 1, 2006

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 20-F

[ x ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
[           ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended ________________________________________________
OR
[           ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
[           ] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report ______________________
For the transition period from _______________________ to ___________________________
Commission file number ________________

SHELLBRIDGE OIL & GAS, INC.
(Exact name of registrant as specified in its charter)

Alberta, Canada
(Jurisdiction of incorporation or organization)

#230, 10991 Shellbridge Way, Richmond, B.C. Canada V6X 3C6
(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act. None

Securities registered pursuant to Section 12(g) of the Act:

Title of Each Class:	Name of each exchange on which registered:
Common Stock Without Par Value	Toronto Stock Exchange

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of the issuer’s classes of capital or common stock as of the close of the period covered by
the annual report - 29,087,612 as of December 31, 2005.

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
[ ] Yes [ x ] No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Securities Exchange Act of 1934. [ ] Yes [ ] No

Indicate by check mark whether the registrant (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 Company was required to file such
reports), and (2) has been subject to such filing requirements for the past 90 days. [ ] Yes [ ] 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. (Check one):
Large accelerated filer [ ] Accelerated Filer [ ] Non-accelerated Filer [ x ]

Indicate by check mark which financial statement item the registrant has elected to follow. Item 17 [ x ] Item 18 [ ]

If this is an annual report, indicated by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). [ ] Yes [ ] No

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of
the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
[ ] Yes [ ] No

TABLE OF CONTENTS

		Page

Glossary of Terms		3

Part I.
Item 1.	Identity of Directors, Senior Management and Advisers	6
Item 2.	Offer Statistics and Expected Timetable – Not Applicable	6
Item 3.	Key Information	6
Item 4.	Information on the Company	13
Item 4A.	Unresolved Staff Comments – Not Applicable	24
Item 5.	Operating and Financial Review and Prospects	24
Item 6.	Directors, Senior Management and Employees	39
Item 7.	Major Shareholders and Related Party Transactions	46
Item 8.	Financial Information	47
Item 9.	The Offer and Listing	48
Item 10.	Additional Information	49
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	56
Item 12.	Description of Securities Other than Equity Securities – Not Applicable	57

Part II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	57
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	57
Item 15.	Controls and Procedures	58
Item 16(A).	Audit Committee Financial Expert	58
Item 16(B).	Code of Ethics	58
Item 16(C).	Principal Accountant Fees and Services	58
Item 16(D).	Exemption from the Listing Standards for Audit Committees	58
Item 16(E).	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	58

Part III.
Item 17.	Financial Statements
Item 18.	Financial Statements – Not Applicable
Item 19.	Exhibits

Glossary of Terms

Bakken	From the early Carboniferous period, approximately 355 million years of age. This unit consists of fine-grained, deltaic terragenous clastics and organic rich shales (hydrocarbon source rocks) deposited in an extensive embayment present over southern Saskatchewan during this period.
Basal Mannville	A clean quartzose sandstone reservoir containing heavy oil that is present as discrete shoreline trends deposited 105 million years of age in southwestern Saskatchewan. The Basal Mannville is included as a member in the Mannville Group of formations.
Basal Quartz zone	A name generally applied to the Ellerslie formation as it occupies the “bottom” sandstone of the Lower Mannville gas formation of lower Cretaceous Age about 124 millions years of age.
Bbl or Barrel	42 U.S. gallons liquid volume of crude oil or natural gas liquids.
Bcf	Billion cubic feet of gas. Usual expression of proved reserve gas volume.
Birdbear	From the late Devonian period, approximately 370 million years of age. This formation consists of mixed carbonates and anhydrites deposited in a restricted shelf and exposed mud-flat environments.
Blairmore formation	Formation encompassing clastic sediments deposited in the Early Cretaceous Age from about 100 to 120 million years ago.
Bluesky formation	Sandstones of the lower Cretaceous Age, about 112 million years old, occurring in Northern Alberta and NE BC.
boe	Barrels of Oil Equivalent. Generally one barrel of oil equals six mcf of gas. Allows reserves of oil and gas to be added together.
boe/d	An expression of barrels of oil equivalent produced per day.
Carbonates	Rocks composed predominantly of Calcium Carbonate (CaCO₃).
Condensate	A mixture comprising pentanes and heavier hydrocarbons recovered as a liquid from field separators, scrubbers or other gathering facilities or at the inlet of a processing plant before the gas is processed.
Cretaceous Age	Rocks from 144 million to 66.4 million years of age.
Crude oil	A mixture, consisting mainly of pentanes and heavier hydrocarbons that may contain sulphur compounds, that is liquid at the conditions under which its volume is measured or estimated, but excluding such liquids obtained from the processing of natural gas.
Debolt	From the Mississipian Age, approximately 340 million years old, and is comprised most of shales that are separated by regional disconformities.
Depletion	The reduction in petroleum reserves due to production that is used to write down the historical capital costs that were first incurred to establish such reserves.
Development or developed	Refers to the phase in which a proven oil or gas field is brought into production by drilling and completing production wells and the wells, in most cases, are connected to a petroleum gathering system.
Devonian Age	Rocks from 408 million to 360 million years of age.
Discovery	The location, learned through drilling of a well, where there exists an accumulation of gas, condensate or oil reserves. The size of the reserves may be estimated but not precisely quantified and may or may not be commercially economic, depending on a number of factors.
Dry hole	A well drilled without finding commercially economic quantities of hydrocarbons.
Ellerlsie zone or formation	A name applied to a group of sandstones that are clear and Quartzose with good porosity and permeability for oil and gas about 124 millions years of age.
Exploration well	A well drilled in a prospect without knowledge of the underlying sedimentary rock or the contents of the underlying rock.
Farmin	By way of agreement, a party earns (farmin) an interest in lands comprising petroleum and natural gas rights from another party by drilling a well or similar activity that evaluates, explores or develops the lands for the production of petroleum substances.
Farmout	By way of agreement, a party gives up (farmout) an interest in lands comprising petroleum and natural gas rights to another party who earns the interest by drilling a well or similar activity that evaluates, explores or develops the lands for the production of petroleum substances.
Field	An area that is producing, or has been proven to be capable of producing, hydrocarbons.
Field netbacks	Revenues from the sale of all commodities produced, less applicable resource and production royalties, less operating costs.
Formation	A reference to a group of rocks of the same age extending over a substantial area of a basin.
Freehold royalty	An amount payable to a mineral rights holder in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on non-Crown lands.
GAAP	Generally accepted accounting principles.
Geology	The science relating to the history and development of the Earth.
Gross acres	The total acreage in which the Company has an interest.

Hectare	A land measurement equaling 2.471 acres.
Horizontal well	A vertical well bore that is gradually deviated (usually horizontally to 90⁰) in order to intersect the targeted formation.
Hydrocarbon	The general term for oil, gas, condensate, liquids and other petroleum products.
Jean Marie formation	A patch reef carbonate reservoir within the Upper Devonian Age formation, about 367 to 369 million years old. The Jean Marie is found in NE British Columbia and is the stratigraphic equivalent to the lower Nisku formation in Alberta.
kilometer	A measurement of distance equaling 0.621 miles or 3,281 feet.
Lower Mannville gas	Any gas sands found in the lower half of the lower Cretaceous Age zones, about 110 million years old. These sands may comprise the Ostracod, Basal Quartz or Ellerlsie zones.
Mbbl	1,000 barrels of oil and/or natural gas liquids.
mboe	1,000 barrels of oil equivalent. See ‘boe’ for further details.
mcf	1,000 cubic feet of natural gas.
mcf/d	1,000 cubic feet of natural gas production per day. Usually used to express the production rate of a group of gas wells.
Mannville	From the early Cretaceous period, approximately 110 million years old and represents a major episode of subsidence and sedimentation.
Meter	A physical measurement equaling 3.281 feet.
Mineral taxes (freehold)	An amount levied by the government of Alberta in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on non- government (freehold) lands in Alberta.
Mississipian Age	Rocks from 360 to 325 million years of age.
Mmcf	1,000,000 cubic feet of natural gas.
mmcf/d	1,000,000 cubic feet of natural gas production per day. Usually used to express the production rate of a gas well or group of gas wells.
NYMEX	New York Mercantile Exchange, the largest physical commodity exchange in the world.
Natural gas	The lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially a gas, but that may contain liquids.
NGL’s	Natural gas liquids. Hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butane and pentane plus, or combinations thereof.
Net acres	The percentage of gross acreage in which the Company has a working interest.
Ostracod zone	Rocks from the lower Cretaceous Age approximately 119 million years ago comprised of sandstones and marlstones that contain a small fossil named Ostracod.
Ostracod well	A gas well capable of producing commercially from the lower Cretaceous Age Ostracod zone.
Operator	That party to a joint venture agreement whose responsibility it is to carry out all exploratory, development, maintenance and record-keeping duties on behalf of other joint venture partners in relation to hydrocarbon extraction on the joint-ventured lands.
Overriding royalty	An amount payable to a third party other than Crown or freehold royalties in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on lands in which the interest of the third party usually arises out of a separate agreement.
Pentanes	A hydrocarbon by-product of natural gas generally referred to as condensate that is of the paraffin series having a chemical formula of C₅H₁₂and having all its carbon atoms joined in a straight chain.
Permeability	Capacity of a rock for transmitting a fluid.
Permit or licence area	An area that is granted for a prescribed period of time for exploration, development or production under specific contractual or legislative conditions.
Pipeline	A system of interconnected pipes that gather and transport hydrocarbons from a well or field to a processing plant or to a facility that is built to take the hydrocarbons for further transport, such as a gas liquefaction plant.
Proved reserves	Those reserves estimated as recoverable with current technology and under existing economic conditions, from that portion of a reservoir that can be reasonably evaluated as economically productive through analysis of drilling, geological, geophysical and engineering data. This includes the reserves to be obtained by enhanced recovery processes demonstrated to be economically and technically successful in the subject reservoir.
Quartzose	Rocks composed of mostly quartz.
Raw gas	Gaseous effluent from a wellhead or pipeline that is not processed. Contains water vapor, carbon dioxide, nitrogen and possibly hydrogen sulphide (H₂S) gas.
Reservoir rock	Porous limestones, dolomites or sandstones that can trap oil and/or gas in

	interconnected holes, like a sponge.
Royalty	A stated or determinable percentage of the proceeds received from the sale of hydrocarbons calculated as prescribed in applicable legislation or in the agreement with the royalty holder.
Seals	Impermeable barriers to hydrocarbon flow such as shale, lime muds, salt or anhydrite.
Seismic	A geophysical technique using low frequency sound waves to determine the subsurface structure of sedimentary rocks.
Slave Point	From the middle Devonion Age, approximately 375 million years old and is restricted to open- marine carbonate, dominated by shales and argillaceous carbonates.
Sour gas	Raw gas with an amount of hydrogen sulphide (H₂S) gas above pipeline requirements of 10 parts H₂ S per million raw gas.
Source rock	Usually shales and clays with a high carbon content deposited in a marine environment.
Sweet gas	Natural gas containing no hydrogen sulphide (H₂S) gas.
Stabilized absolute open flow	The maximum rate of gas production that a wellhead will produce assuming no backpressure when the well is stable.
Tertiary sediment	Soft rock of sands, clays, coals and siltstones from 66.4 to 1.6 million years old.
Triassic Age	Rocks from 245 to 208 million years of age.
Undeveloped	Prior to the time in which a proven oil or gas field is brought into production by drilling and completing production wells.
Vertical well	A well bore that intersects the section(s) containing hydrocarbons at about 90⁰.
Viking	From the middle Cretaceous Age, 98 – 133 Million years old, and is comprised of interbedded, predominatly marine influenced sandstones and shales.
Viking gas well	A well capable of commercial gas production from the upper Cretaceous Age Viking formation sands deposited about 98 million years ago.
Working interest	Those lands in which the Company receives its share acreage of net production revenues.

Item 1. Identity of Directors, Senior Management and Advisors

A. Directors and Senior Management

Name	Business Address	Functions

Wayne Babcock	#230, 10991 Shellbridge Way, Richmond, B.C.	President, Chief Executive Officer
	Canada V6X 3C6	and Director

Donald Umbach	#230, 10991 Shellbridge Way, Richmond, B.C.	Vice-President, Chief Operating
	Canada V6X 3C6	Officer and Director

John Greig	#230, 10991 Shellbridge Way, Richmond, B.C.	Director
	Canada V6X 3C6

David Jennings	#230, 10991 Shellbridge Way, Richmond, B.C.	Director
	Canada V6X 3C6

Bill Thompson	#230, 10991 Shellbridge Way, Richmond, B.C.	Director
	Canada V6X 3C6

Michael Bardell	#230, 10991 Shellbridge Way, Richmond, B.C.	Chief Financial Officer
	Canada V6X 3C6

B. Advisers

Name	Business Address	Position

Irwin, White & Jennings	Suite 2620 - 1055 W. Georgia Street	Canadian legal counsel
	Vancouver, B.C. Canada V6E 3R5

Perkins Coie LLP	1620 26^thStreet, Sixth Floor South Tower	United States legal counsel
	Santa Monica, California 90404 USA

National Bank of Canada	6th Floor - 407 Eighth Avenue S.W.	Principal bank
	Calgary, Alberta Canada T2P 1E5

C. Auditors

Name	Business Address	Professional Body Membership

Ernst & Young LLP	P.O. Box 10101 Pacific Centre 700 West Georgia	Institute of Chartered Accountants of British
	Street Vancouver, British Columbia V7Y 1CY	Columbia and the Canadian Institute of
		Chartered Accountants

Item 2. Offer Statistics and Expected Timetable – Not applicable

Item 3. Key Information

We incorporated under the Business Corporations Act (Alberta) on July 7, 2005 and commenced commercial operations following the closing on September 30, 2005 of a Plan of Arrangement among Dynamic Oil & Gas, Inc. (“Dynamic”), Sequoia Oil & Gas Trust and Shellbridge Oil & Gas, Inc., pursuant to which we acquired certain oil and natural gas properties, undeveloped lands and related assets previously owned by Dynamic in British Columbia and Saskatchewan. At the closing of the Plan of Arrangement, the former shareholders of Dynamic became our initial shareholders and each such shareholder received one voting common share in our capital structure for every one common share they held of Dynamic.

Following the completion of the Plan of Arrangement, on October 3, 2005, we completed a non-brokered private placement of 3,333,333 common shares, of which 1,666,666 were flow-through shares and 1,666,667 were non-flow through shares, all at a price of $1.20 per share, for gross proceeds of $4,000,000. The proceeds of this private placement were used for the initiation of our exploration and development program and general working capital purposes.

A. Selected Financial Data

obligations from Dynamic (the “Acquired Items”). Prior to the Arrangement, the net assets transferred to us pursuant to the Arrangement (see Note 4 to our Financial Statements - “Transfer of Assets and Commencement of Commercial Operations”) constituted a group of properties, not a separate legal entity or a separate division, thus no accounting records were separately maintained by Dynamic. Financial statement information covering periods prior to the Arrangement, including the nine months ended September 30, 2005 and the years ended December 31, 2004 and 2003, is information for the properties transferred to us pursuant to the Arrangement that has been derived from the accounting records of Dynamic using the historical results of operations and historical basis of assets and liabilities now comprising us. As a result, the financial information included herein may not necessarily reflect our results of operations, financial position and cash flows in the future or what our results of operations, financial position and cash flows would have been had we been a stand-alone company during the periods prior to the Arrangement.

Selected financial data presented in the tables below, includes assumptions and allocations of certain Dynamic assets, liabilities and expenses. We believe the assumptions and allocations underlying the financial statements are reasonable (see Note 2 to our Financial Statements).

In addition to the above comment, some of the following data is derived from and should be read in conjunction with our Financial Statements and Item 5 – “Operating and Financial Review and Prospects” included elsewhere in this Registration Statement. The selected financial data has been prepared in accordance with Canadian Generally Accepted Accounting Principles (“Canadian GAAP”). The Financial Statements and the notes thereto included pursuant to Item 17 of this Registration Statement are also prepared under Canadian GAAP. Included in Note 12 to the Financial Statements is the reconciliation between Canadian GAAP and United States Generally Accepted Accounting Principles (“U.S. GAAP”). Unless otherwise stated in this Registration Statement, all references to dollars or “$” are to Canadian dollars.

Selected Financial Data Presented According to Canadian GAAP

	As at		As at		As at
($000’s)	Dec 31, 2005		Dec 31, 2004		Dec 31, 2003
Balance Sheets
Working capital (deficiency)	3,021		(10,786	)	(3,115	)
Total assets	32,967		26,565		19,626
Current liabilities	11,861		12,484		3,649
Long-term liabilities	1,238		560		185
Future income tax asset	765		-		-
Net assets	19,869		13,522		15,792
Share capital	19,869		13,522		15,792
Deficit	(1,868	)	-		-
Owner’s net investment ⁽¹⁾	-		13,522		15,792

(1)	We began accumulating deficits subsequent to the Plan of Arrangement. Changes in Owner’s net investment in 2004 and 2003 represent the net contributions by Dynamic to us after giving effect to our accumulated deficits, as well as cash transfers from and to Dynamic.

	Three Months		Nine Months
	Ended		Ended		Twelve Months Ended
($ 000’s, except per share data)	Dec 31, 2005		Sep 30, 2005		Dec 31, 2005		Dec 31, 2004		Dec 31, 2003
Statements of Operations
Crude oil and natural gas sales	3,574		9,171		12,745		7,642		1,523
Crude oil and natural gas sales,
less royalties (net of provincial credits)
and production costs	1,943		5,329		8,110		4,068		1,005
Net loss	(1,868	)	(15,316	)	(17,184	)	(25,934	)	(3,918	)
Cash provided by (used in)
operating activities	(2,124	)	5,495		3,371		1,310		(427	)
Common shares – wtd. avg. ⁽¹⁾(# 000’s)	28,979		-		-		-		-
Common shares – outstanding ⁽¹⁾(# 000’s)	29,088		-		-		-		-
Net loss per share, ⁽¹⁾basic ($)	(0.06	)	-		-		-		-
Net loss per share, ⁽¹⁾diluted ($)	(0.06	)	-		-		-		-

(1)

Prior to the Plan of Arrangement, we had issued one Common Share to incorporate as a separate legal entity. Therefore, historical losses per share have not been presented in our financial statements. Losses per share have been presented using our Common Shares outstanding subsequent to the Plan of Arrangement.

The following tables show the major differences in the application of Canadian GAAP and U.S. GAAP.

Selected Financial Data Presented According to U.S. GAAP

	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($ 000’s)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Net loss under Canadian GAAP	(1,868)	(15,316)	(17,184)	(25,934)	(3,918)
Write-downs on natural gas
and oil properties	-	-	-	182	(182)
Net loss before cumulative effect of change
in accounting principle under U.S. GAAP	(1,868)	(15,316)	(17,184)	(25,752)	(4,100)
Cumulative effect of change in accounting
Principle, net of applicable taxes	-	-	-	-	44
Net loss after cumulative effect of change
In accounting principle under U.S. GAAP	(1,868)	(15,316)	(17,184)	(25,752)	(4,056)
Net loss per share, ⁽¹⁾basic ($)	(0.06)	-	-	-	-
Net loss per share, ⁽¹⁾diluted ($)	(0.06)	-	-	-	-

(1)

Prior to the Plan of Arrangement, we had issued one Common Share to incorporate as a separate legal entity. Therefore, historical losses per share have not been presented in the financial statements. Losses per share have been presented using our Common Shares outstanding subsequent to the Plan of Arrangement.

Dividends

We have never paid or declared dividends on our shares of Common Stock.

Exchange Rates

Our Financial Statements, as provided under Items 8 and 17 and all dollar amounts presented in this Registration Statement, are presented in Canadian dollars, unless otherwise expressly stated. For comparison purposes, exchange rates into U.S. dollars are provided. The following tables set forth the exchange rate as of the latest practicable date, high and low exchange rates for the months indicated and the average exchange rates for the reporting periods indicated, based on the noon U.S. dollar buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York (Canadian Dollar = U.S. $1.00) .

Exchange Rates for Canadian Versus U.S. Dollars

The exchange rate as of April 26, 2006 was CDN $1.13 per U.S. $1.00.

Exchange Rates for Canadian Versus U.S. Dollars
(High/low rates for latest six months)	High	Low
March, 2006	1.17	1.13
February, 2006	1.16	1.14
January, 2006	1.17	1.14
December, 2005	1.17	1.15
November, 2005	1.20	1.17
October, 2005	1.19	1.17

Exchange Rates for Canadian Versus U.S. Dollars	Average ($)
For the twelve months ended December 31, 2005	1.21
For the twelve months ended December 31, 2004	1.30
For the twelve months ended December 31, 2003	1.40

B. Indebtedness and Capitalization

The following table sets forth our indebtedness and capitalization as at December 31, 2005 and should be read in conjunction with the information provided under Item 5. “Operating and Financial Review and Prospects” and the financial statements, the accompanying Notes and other financial information in this Registration Statement on Form 20-F.

Indebtedness and Capitalization	Amount (000’s	)
Indebtedness
Accounts payable and accrued liabilities	11,861
Asset retirement obligation	1,237
Total indebtedness	13,098

Shareholder equity
Share capital (29,087,612, no par value outstanding)	21,107
Contributed surplus	630
Accumulated deficit	(1,868	)
Net shareholders’ equity	32,967

C. Reasons for the Offer and Use of Proceeds – Not Applicable

D. Risk Factors

Risk factors that could materially adversely affect our cash flow from operations, operating results and financial condition are set forth below.

Dependence on One Major Property
Mantario East, Saskatchewan comprised 86% of total production and 72% of total revenue during the three months ended December 31, 2005 and 80% of total production and 77% of total revenue during the nine months ended September 30, 2005. Cypress/Chowade, British Columbia contributed 89% of total production and 94% of total revenue during the year ended December 31, 2004 and nearly all of total production and total revenue during the year ended December 31, 2003. Unless we can successfully drill for or acquire economically viable reserves of crude oil and natural gas in other areas, as our production depletes the reserves at Mantario East, our revenue may be materially adversely affected.

Exploration and Development Risks
Exploration and development of crude oil and natural gas involves a high degree of risk that no commercial production will be obtained or that the production will be insufficient to recover drilling and completion costs. The costs of drilling, completing and operating wells are sometimes uncertain, and cost overruns in exploration and development operations can adversely affect the economics of a project. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, joint venture partner and/or operator decisions, equipment failures, weather conditions, marine accidents, fires and explosions, compliance with governmental requirements, and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not ensure a profit on the investment or a recovery of drilling, completion and tie-in costs.

Replacement of Reserves
In general, the rate of production from crude oil and natural gas properties declines as reserves are depleted. The rate of decline depends on reservoir characteristics and other factors. Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our estimated proved reserves will decline as reserves are produced. Our future crude oil and natural gas production, and therefore operating cash flows and net earnings/(loss), are highly dependent upon our level of success in finding or acquiring additional economically recoverable reserves. The business of exploring for, developing and acquiring reserves is capital intensive. To the extent operating cash flows are reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves could be materially impaired.

Estimating of Reserves and Future Net Cash Flows Risk
Estimating crude oil and natural gas reserves, and future net cash flows includes numerous uncertainties, many of which may be beyond our control. Such estimates are essential in our decision-making, as to whether further investment is warranted. These estimates are derived from several factors and assumptions, some of which are:

reservoir characteristics based on variable geological, geophysical and engineering assessments;
future rates of production based on historical draw-down rates;
future net cash flows based on commodity price/quality assumptions, production costs, taxes and investment decisions;
recoverable reserves based on estimated future net cash flows; and
compliance expectations based on assumed federal, provincial and environmental laws and regulations.

Ultimately, actual production rates, reserves recovered, commodity prices, production costs, government regulations or taxation may differ materially from those assumed in earlier reserve estimates. Higher or lower differences could materially impact our production, revenues, production costs, depletion expense, taxes and capital expenditures.

Reserve estimates and net present values reported by us elsewhere in this Registration Statement are based on estimated commodity prices and associated production costs that are assumed constant for the life of the reserves. Actual future prices and costs may be materially higher or lower.

We have historically invested a significant portion of our capital budget in drilling exploratory wells in search of unproved oil and gas reserves. We cannot be certain that the exploratory wells we drill will be productive or that we will recover all or any portion of our investments. In order to increase the chances for exploratory success, we often invest in seismic or other geoscience data to assist us in identifying potential drilling objectives. Additionally, the cost of drilling, completing and testing exploratory wells is often uncertain at the time of our initial investment. Depending on complications encountered while drilling, the final cost of the well may significantly exceed that which we originally estimated.

Limited Financial Resources
We expect the combination of cash flow from operating activities, our bank credit facility that we established on March 17, 2006, and the proceeds from the private placement that closed in the fourth quarter of 2005 to support land acquisitions, drilling operations, facilities construction, and general/administration costs in Fiscal 2006. There can be no assurance that we will be able to raise additional capital in light of factors such as the market demand for our securities, the state of financial markets for independent oil companies (including the markets for debt), crude oil and natural gas prices and general market conditions (see Item 4 - "Our Information" and Item 5 – “Operating and Financial Review and Prospects”, for discussions of our Fiscal 2006 capital investment program budget).

Commodity Price Fluctuations
Our products, including crude oil and natural gas, are commodities. Because our contracts do not fix a long-term price for the products we purchase or sell, market changes in the price of such products have a direct and immediate effect (whether favorable or adverse) upon our revenues and profitability. Prices for products may be subject to material change in response to relatively minor changes in supply and demand, general economic conditions and other market conditions over which we have no control.

Other conditions affecting our business include the level of domestic crude oil and natural gas production, the availability and prices of competing commodities and of alternative energy sources, the availability of local, intraprovincial and interprovincial transportation systems with adequate capacity, the proximity of natural gas production to pipelines and facilities, the availability of pipeline capacity, government regulation, the seasons, the weather and the impact of energy conservation efforts.

Dependence on Key Personnel
Our success depends in large part on the professional efforts and expertise of our President & Chief Executive Officer, Wayne J. Babcock, our Vice President & Chief Operating Officer, Donald K. Umbach, and our Chief Financial Officer, Michael A. Bardell. While the loss of the services of any of these persons could have a material adverse effect on us, we do not carry key-man life insurance.

Drilling Plans Subject to Change
This Registration Statement includes descriptions of our future drilling plans with respect to our prospects. A prospect is a property on which our geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of review. Whether or not we ultimately drill a prospect may depend on the following factors: receipt of additional seismic data or reprocessing of existing data; material changes in crude oil or natural gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; availability and cost of capital; changes in the estimates of costs to drill or complete wells; our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; decisions of our joint working interest owners and operators; and restrictions imposed by governmental agencies. We will continue to gather data about our prospects, and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all.

Potential Variability in Quarterly Operating Results
Demand for our products will generally increase during the winter because they are often used as heating fuels. The amount of such increased demand will depend to some extent upon the severity of winter. Accordingly, our net operating revenues are likely to increase during winter months, although the amount of increase and its effect on profitability cannot be predicted. Because of the seasonality of our business and continuous fluctuations in the prices of our products, our operating results for any past quarterly period may not necessarily be indicative of results for future periods and there can be no assurance that we will be able to achieve or maintain steady levels of profitability on a quarterly or annual basis in the future.

Competition and Business Risk Management
The crude oil and natural gas industry is highly competitive. We experience competition in all aspects of our business, including searching for, developing and acquiring reserves, obtaining pipeline and/or facilities processing capacity, leases, licenses and concessions, and obtaining the equipment and labor needed to conduct operations and market crude oil and natural gas. Our competitors include multinational energy companies, other independent crude oil and natural gas concerns and individual producers and operators. Because both crude oil and natural gas are fungible commodities, the principal form of competition with respect to product sales is price competition. Many competitors have financial and other resources substantially greater than those available to us and, accordingly, may be better positioned to acquire and exploit prospects, hire personnel and market production. In addition, many of our larger competitors may be better able to respond to factors such as changes in worldwide crude oil and natural gas prices, levels of production, the cost and availability of alternative fuels or the application of government regulations. Such factors, which are beyond our control, may affect demand for our crude oil and natural gas production. We expect a high degree of competition to continue.

Risks Pertaining to Acquisitions and Joint Ventures
Part of our business strategy is to expand through acquisitions and is therefore dependent upon our ability to complete suitable acquisitions and effectively integrate acquired assets into our operations. Suitable acquisitions, on terms acceptable to us, may not be available in the future or may require us to assume certain liabilities, including, without limitation, environmental liabilities, known or unknown.

Shortage of Supplies and Equipment
Our ability to conduct operations in a timely and cost effective manner is subject to the availability of crude oil and natural gas field supplies, rigs, equipment and service crews. Although none are expected currently, any shortage of certain types of supplies and equipment could result in delays in our operations as well as in higher operating and capital costs.

Interruption From Severe Weather
Our operations are conducted principally in the northeastern region of British Columbia, and the southwestern region of Saskatchewan. The weather during colder seasons in these areas can be extreme and can cause interruption or delays in our drilling and construction operations.

Limited Operating History
While properties that we own have produced historically under Dynamic, we commenced operations of them on October 1, 2005 and during the ensuing three months ended December 31, 2005, we experienced a net loss of $1,867,777 ($0.06 per share, basic and diluted). As at December 31, 2005, we had an accumulated deficit of $1,867,777. Our future viability should be considered in light of the risks and difficulties frequently encountered by companies engaged in the junior stages of crude oil and natural gas exploration, development and production activities, particularly those with very limited operating history.

Operating Hazards and Uninsured Risks
The crude oil and natural gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally-pressured formations, adverse weather conditions, governmental and political actions, premature reservoir declines, and environmental hazards such as oil spills, gas leaks and discharges of toxic gases. The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by us could have a material adverse impact on us. We, and the operators of our properties, maintain insurance in accordance with customary industry practices and in amounts that we believe to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on our financial condition.

As our reserves of crude oil and natural gas decline, our success at replacing and adding to them is highly reliant on further exploration and development. To the extent we succeed, our operating cash flows and other capital sources may become insufficient so as to impair our ability to re-invest capital.

Limited and Volatile Trading Volume
Although our shares trade on the Toronto Stock Exchange, the volume of trading has been limited and volatile in the past and is likely to continue to be so in the future, reducing the liquidity of an investment in our Common Stock and making it difficult for investors to readily sell their shares in the open market. Without a liquid market for the our shares, investors may be unable to sell their shares at favorable times and prices and may be required to hold their shares in declining markets or to sell them at unfavorable prices. Our shares do not trade on an established market in the United States and we cannot make any assurances that our shares will ever trade in such a market, or if they do so trade, that a market for our shares will develop and be sustained.

Volatility of Share Price
In recent years, securities markets in Canada have experienced a high level of price volatility. The market price of many resource companies, particularly those, like us, that are considered speculative exploration companies, have experienced wide fluctuations in price, resulting in substantial losses to investors who have sold their shares at a low price point. These fluctuations are based only in part on the level of progress of exploration, and can reflect general economic and market trends, world events or investor sentiment, and may sometimes bear no apparent relation to any objective factors or criteria. During the period October 5 to December 31, 2005, our share price fluctuated between a low of $1.10 and a high of $1.85. To date during Fiscal 2006, our share price has fluctuated between a low of $1.35 and a high of $2.35. Significant fluctuation in our share price is likely to continue, and could potentially increase, in the future.

Difficulty for U.S. Investors to Effect Service of Process
We are incorporated under the laws of the Province of Alberta, Canada. Consequently, it will be difficult for United States investors to effect service of process in the United States upon our directors or officers, or to realize in the United States upon judgments of United States’ courts predicated upon civil liabilities under the Exchange Act. All of our directors and officers are residents of Canada and all of our assets are located outside of the United States. A judgment of a United States court predicated solely upon such civil liabilities would probably be enforceable in Canada by a Canadian court if the United States court in which the judgment was obtained had jurisdiction, as determined by the Canadian court, in the matter. There is substantial doubt whether an original action could be brought successfully in Canada against any of such persons or the company predicated solely upon such civil liabilities.

Restoration, Safety and Environmental Risk
All our operations are in western Canada and, in particular, the western provinces of British Columbia, Saskatchewan and Alberta. Certain laws and regulations exist that require companies engaged in petroleum activities to obtain necessary safety and environmental permits to operate. Such legislation may restrict or delay us from conducting operations in certain geographical areas. Further, such laws and regulations may impose liabilities on us for remedial and clean-up costs, personal injuries related to safety and environmental damages.

To ensure that we provide for future estimated asset retirement obligations, we recognized $1.2 million of asset retirement obligations on our balance sheet as at December 31, 2005. We engage independent engineering consultants to assist in assessing our total asset retirement obligations related to removal and clean-up costs. While we cannot predict their ultimate cost, we currently estimate the undiscounted future cost to clean up all our operating facilities to be $1.7 million.

While our safety and environmental activities have been prudent and have enabled us to operate successfully in managing such risks, there can be no assurance that we will always be successful in protecting ourselves from the impact of all such risks.

Government Regulation and Environmental Matters
We are subject to various federal and provincial laws and regulations including environmental laws and regulations. We believe that we are in substantial compliance with such laws and regulations; however, such laws and regulations may change in the future in a manner that will increase the burden and cost of compliance. In addition, we could incur significant liability for damages, cleanup costs and penalties in the event of certain discharges into the environment.

Certain laws and governmental regulations may impose liability on us for personal injuries, clean-up costs, environmental damages and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages, but do not maintain insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damage. Accordingly, we may be subject to liability or may be required to cease production from properties in the event of such damages.

The main bodies of regulations that apply to us in the areas in which we have significant field operations are The Oil and Gas Conservation Act of Alberta, The Petroleum and Natural Gas Act of British Columbia and The Oil & Gas Conservation Act and Regulations of Saskatchewan and the Crown Minerals Act of Saskatchewan and Petroleum and Natural Gas Regulations of Saskatchewan.

Kyoto Protocol Risk
The Kyoto Protocol treaty (Protocol) was established in 1997 to reduce emissions of greenhouse gases (GHG) that are believed to be responsible for increasing the Earth’s surface temperatures and affecting the global climate change. Canada ratified the Protocol in December 2002. Since the implementation of the Protocol, approximately 160 countries have committed to reduce GHG internationally. The Protocol was legally made effective internationally on February 16, 2005 and Canada committed to meet a 6% reduction of emission over base-year 1990 during the period 2008 to 2012. Canadian government assurances of cost and volume limits suggest that incremental risks and liabilities attributable to addressing Protocol related policies are manageable. While we believe we are a low-emission producer, it is not possible to predict the impact of how Protocol-related issues will ultimately be resolved and to what extent their impact will affect our future unit operating costs and capital expenditures.

Item 4. Information on the Company

A. History and Development of the Company

Shellbridge Oil & Gas, Inc. was incorporated under the Business Corporations Act (Alberta) Canada on July 7, 2005.

Our principal executive office is located in leased space at Suite #230, 10991 Shellbridge Way, Richmond, British Columbia V6X 3C6. Our telephone number is (800) 663-8072. Our web address is www.shellbridge.ca. Our registered office is located at Suite 3300, 421-7^th Avenue S.W., Calgary, Alberta, T2P 4K9.

Our contact person is Michael Bardell, Chief Financial Officer.

Our fiscal year end is December 31^st.

On July 16, 2005, one share of our Common Stock was issued to Dynamic upon our initial organization.

On July 20, 2005, we entered into agreements, including a Plan of Arrangement with Dynamic, Sequoia Oil & Gas, Inc., an Alberta Canada oil and gas trust (Sequoia) and 0730008 B.C. Ltd. (a wholly-owned subsidiary of Sequoia) to acquire certain properties in southwestern Saskatchewan, and northeastern and southwestern British Columbia, working capital items, capital assets and asset retirement obligations from Dynamic (the “Acquired Items”) in exchange for 25,754,278 of our shares of Common Stock that were subsequently distributed to Dynamic’s shareholders. The closing of the Plan of Arrangement occurred on September 30, 2005.

Upon the closing of the Plan of Arrangement on September 30, 2005, we acquired certain properties in southwestern Saskatchewan, and northeastern and southwestern British Columbia, working capital items, capital assets and asset retirement obligations from Dynamic (the “Acquired Items”). Prior to the Arrangement, the net assets transferred to us pursuant to the Arrangement (see Note 4 to our Financial Statements - “Transfer of Assets and Commencement of Commercial Operations”) constituted a group of properties, not a separate legal entity or a separate division, thus no accounting records were separately maintained by Dynamic. Financial statement information covering periods prior to the Arrangement is information for the properties transferred to us pursuant to the Arrangement that has been derived from the accounting records of Dynamic using the historical results of operations and historical basis of assets and liabilities now comprising us. As a result, the financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future or what our results of operations, financial position and cash flows would have been had we been a stand-alone company during the periods prior to the Arrangement.

In connection with the Plan of Arrangement, we completed on October 3, 2005, a private placement in which we sold 3,333,333 shares of our Common Stock, of which 1,666,666 were sold on a flow-through basis. Such shares were issued at $1.20 per share with aggregate gross proceeds of $4,000,000.

Our shares of Common Stock were listed and began trading on the Toronto Stock Exchange on October 5, 2005 under the symbol “SHB”.

As of March 31, 2006, we had 29,087,612 shares of Common Stock outstanding.

Our authorized capital is an unlimited number of shares of Common and Preferred Stock, without par value.

We are a Canadian-based energy company engaged in the production and exploration of western Canada's crude oil and natural gas reserves. We own working interests in producing and early-stage exploration properties in southwestern Saskatchewan, and northeastern and southwestern British Columbia.

          Capital Investment Program
          (Including Exploration Expense Related to Unsuccessful Drilling and Seismic, and Capital Assets)
          Our capital transactions included under this section include exploration expenses relating to seismic and unsuccessful drilling efforts. Seismic and unsuccessful drilling costs comprise the majority of our Exploration expense as reported in our Statements of Operations and Deficit. Capital expenditures are reported on our Balance Sheets. When combined, expenditures for capital and expenses for unsuccessful drilling and seismic costs represent the majority of spending on our capital investment program.

During the three months ended December 31, 2005, nine months ended September 30, 2005 and years ended December 31, 2004 and 2003 capital spending on properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 aggregated $60.2 million, an amount that is broken down by reporting period and spending classification in the following table:

Capital Investment Program Spending During the Following Periods ⁽¹⁾
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($000’s)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Land acquisitions	241	279	520	4,072	3,834
Drilling, completions and
equipping:
Exploratory ⁽²⁾	734	408	1,142	10,925	5,700
Development	1,999	5,506	7,505	7,649	1,654
Facilities and pipelining	630	2,365	2,995	5,740	1,336
Seismic	511	213	724	3,686	1,437
Other	180	450	630	360	275
Total	4,295	9,221	13,516	32,432	14,236

(1)	We follow the successful efforts method of accounting, whereby costs of drilling an unsuccessful well are recorded as exploration expense when it becomes known the well did not result in a discovery of proved reserves or where one year has elapsed since the completion of drilling and near- term efforts to establish proved reserves are not foreseeable, intended, or in our control.

(2)	As at December 31, 2005, exploratory well-drilling costs of $3.1 million remain capitalized on our balance sheet. These costs relate to six wells. Various projects are planned in Fiscal 2006 to determine if proved reserves can be assigned to each of the six wells. The wells are as follows: four heavy crude oil wells at Mantario East and Flaxcombe, Saskatchewan; and two natural gas wells at Pica, Alberta and Rigel, British Columbia.

Three Months Ended December 31, 2005
During the three month period, our capital investment program expenditures totaled $4.3 million, an amount that was allocated by property and classification as shown in the table that follows:

Capital Investment Program Expenditures During the Three Months Ended December 31, 2005
		Drilling,
		Completions
		and	Facilities and
($ 000’s)	Land	Equipping	Pipelining	Seismic	Other	Total
British Columbia
Cypress/Chowade	-	10	14	-	2	26
Orion	4	-	-	-	64	68
Rigel	220	836	-	-	-	1,056
Total British Columbia	224	846	14	-	66	1,150
Saskatchewan
Mantario East	17	1,661	616	511	50	2,855
Flaxcombe	-	182	-1	-	-	182
Total Saskatchewan	17	1,843	616	511	50	3,037
Pica, Alberta	-	44	-	-	-	44
Other	-	-	-	-	64	64
Total	241	2,733	630	511	180	4,295

Land
During the three month period ended December 31, 2005, our investment in land was $0.2 million, most of which was at Rigel for the acquisition of 3,990 gross acres (1,596 net).

Drilling, Completions and Equipping
We drilled five wells for a total cost of $2.7 million. We drilled three wells targeting natural gas, one at Rigel and one at Flaxcombe at a working interest of 50% and one at Pica at a working interest of 12.5% . We also drilled two wells targeting heavy oil at Mantario East at a working interest of 75%. All three wells targeting natural gas were completed as standing gas wells, one of the two targeting heavy oil was completed as a standing well and the other was unsuccessful.

Facilities and Pipelining
Expenditures incurred on facilities and pipelining during the three month period ended December 31, 2005, totaled $0.6 million. These expenditures were incurred mainly on the construction of our battery at Mantario East.

Seismic and Other
Also during the three month period ended December 31, 2005, we invested $0.7 million on seismic data activity and other. Most of the seismic was for 2D and 3D programs covering 20.8 square kilometers on our Mantario East property.

The Twelve Months Ended December 31, 2005
During this period, capital spending on the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 totaled $13.4 million, an amount that was allocated by property and classification as follows:

Capital Investment Program Expenditures During the Twelve Months Ended December 31, 2005
		Drilling,
		Completions
		and	Facilities and
($ 000’s)	Land	Equipping	Pipelining	Seismic	Other	Total
British Columbia
Cypress/Chowade	47	2,470	(126)	-	85	2,476
Orion	4	313	(55)	-	166	428
Rigel	220	836	-	-	-	1,056
Total British Columbia	271	3,619	(181)	-	251	3,960
Saskatchewan
Mantario East	249	4,781	3,176	707	186	9,099
Flaxcombe	-	182	-	17	-	199
Sandgren	-	21	-	-	-	21
Total Saskatchewan	249	4,984	3,176	724	186	9,319
Pica, Alberta	-	44	-	-	-	44
Other	-	-	-	-	198	198
Total	520	8,647	2,995	724	630	13,516

Land
During this period, investment in land was $0.5 million, most of which was at Rigel ($0.2 million for 1,596 net acres) and at Mantario East and other associated Saskatchewan properties ($0.2 million for 5,000 net acres).

Drilling, Completions, Equipping, Facilities and Pipelining
During this period, 15 wells were drilled for a total cost of $8.6 million. Eleven of the wells targeted heavy crude oil at Mantario East at an average working interest of 65%. The other four wells targeted natural gas, one each at Rigel, Pica, Flaxcombe and Mantario East at an aggregate average working interest of 53%. The $2.5 million that was invested at Cypress/Chowade related primarily for installing compression, and for completing and equipping two wells, the drilling costs of which were mainly recorded in the twelve months ended December 31, 2004.

Facilities and Pipelining
During this period, expenditures incurred on facilities and pipelining during the period totaled $3.0 million. These expenditures were incurred mainly on the construction of production facilities at Mantario East.

Seismic and Other
Also during this period, $1.4 million was invested on seismic data activity and other capital assets. Most of the seismic was for 2D and 3D programs covering 20.8 square kilometers on the Mantario East property.

Twelve months ended December 31, 2004
During this period, an aggregate of $32.4 million was invested - $25.5 million or 79% on British Columbia properties and $6.5 million or 20% on Saskatchewan properties. The amount invested in British Columbia was for land, drilling,

completions, equipping and facilities at Cypress/Chowade ($16.7 million) and Orion ($8.8 million). The amount invested in Saskatchewan for similar-type expenditures at Mantario East, Flaxcombe and Sandgren.

Twelve months ended December 31, 2003
During this period, an aggregate of $14.2 million was invested - $13.6 million or 96% on British Columbia properties and $0.4 million or 3% on Saskatchewan properties. The amount invested in British Columbia was for land, drilling, completions, equipping and facilities at Cypress/Chowade ($10.6 million) and Orion ($3.0 million). The amount invested in Saskatchewan was invested on similar-type expenditures at Mantario East.

Fiscal 2006 – Budgeted Capital Investment Program
During Fiscal 2006, our budgeted capital investment program totals $9.0 million, an amount that is broken down by spending classification and property in the following table:

Fiscal 2006 – Budgeted Capital Investment Program
		Drilling,		Seismic
	Land	Completions	Facilities and	and
($ 000’s)	Acquisitions	and Equipping	Pipelining	Other	Total
British Columbia
Cypress/Chowade	-	250	-	-	250
Rigel	-	475	-	120	595
Total British Columbia	-	725	-	120	845
Saskatchewan
Mantario East and Area	56	5,951	1,159	90	7,256
Total Saskatchewan	56	5,951	1,159	90	7,256
Other ⁽¹⁾	-	-	-	850	850
Total – All Provinces	56	6,676	1,159	1,060	8,951

(1)	Included in Other is $100,000 for computer and office equipment, and $750 for contingencies.

Recent Material Events
In connection with the Plan of Arrangement, we completed on October 3, 2005, a private placement in which we sold 3,333,333 shares of our Common Stock, of which 1,666,666 were sold on a flow-through basis. Such shares were issued at $1.20 per share with aggregate gross proceeds of $4,000,000.

Under joint announcement with True Energy Trust of Calgary, Alberta (“True”) on April 11, 2006, we entered into an agreement with True and True Energy Inc. (“True Energy”), a wholly-owned subsidiary of True, whereby, subject to certain conditions, True Energy will acquire all of our issued and outstanding Common Shares on the basis of 0.14 trust units of True for each outstanding share of Common Stock of ours. The contemplated transactions have received unanimous support of both our and True’s board of directors. Shareholders representing approximately 10.6% of our outstanding Common Stock, 14.5% on a fully-diluted basis assuming the full vesting and exercise of outstanding options (including all of our directors and officers) have entered into lock-up agreements pursuant to which they agree to support the transactions. Our board of directors has determined that the transactions are in the best interests of the holders of our Common Stock. We have agreed, as has True Energy, to pay the other a non-completion fee of $2.0 million in certain circumstances if the transactions are not completed. The agreement includes provisions whereby we will terminate discussions with any other parties and not solicit any other offers. The agreement also gives True the right to match any competing offer. Orion Securities Inc. is acting as our exclusive financial advisor to the transactions and has advised our board of directors that they are of the opinion, as of the date hereof, that the consideration to be received by the holders of our Common Stock pursuant to the transactions is fair, from a financial point of view.

Subsequent to the filing of this Registration Statement, shareholders will be provided with an Information Circular outlining the details of the transactions, following which they will be given the opportunity to cast their vote in favour of the transactions at a Special Meeting of Securityholders.

Share Repurchases
We have not made any shares repurchases since our incorporation.

B. Business Overview

General
Our principal business is acquiring, exploring and developing crude oil and natural gas properties. Our crude oil and natural gas properties are located mainly in the Canadian provinces of British Columbia and Saskatchewan. We explore for, produce and market crude oil and natural gas. We intend to continue this type of business activity and pursue strategic

opportunities to buy or sell assets or transact with another company in our industry, in the event the Transaction discussed under “Recent Material Events” above does not close.

The crude oil and natural gas industry deals in two basic forms of ownership interests, namely Working Interests and Overriding Royalties:

	(i)	Working Interest (WI): means the percentage of undivided interest held by a Joint Operator (i.e. leaseholder) in a specific tract of land (i.e. joint lands). The Working Interests held by all Joint Operators in any specific tract of joint lands must total 100%. Each WI party is responsible for its WI percentage share of costs incurred to conduct "work" (i.e. drilling, seismic, production etc.) on the joint lands. Working Interests are always considered to be an active interest in the costs, risks and benefits associated with the joint lands and operations conducted thereon and the oil or gas produced there from.

	(ii)	Overriding Royalties (ORR): Overriding Royalties are a specified share of oil and/or gas as and when produced. ORR's are free and clear of costs, risk and expense to the holder of the ORR. Usually ORR's are based on gross production and as such are referred to as "Gross" Overriding Royalties or GORR's. ORR's are considered a passive interest in as much as the holder of an ORR is not subject to any cost, risk or expense nor is the ORR holder involved in any decision- making with respect to the royalty lands.

The majority of our interests are Working Interests and our Overriding Royalty interests would typically be immaterial.

Concentration of Commodities
We derive our revenue principally from the sale of crude oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing spot prices for these commodities. The market prices for our commodities are dictated by supply and demand. Accordingly, our operating cash flows and net loss are greatly affected by changes in prices for crude oil and natural gas. We will experience reduced operating cash flows and may experience additional net losses when prices for crude oil and natural gas are low (see Item 5 – “Operating and Financial Review Prospects” and Item 11 - “Quantitative and Qualitative Disclosures About Market Risk”).

Under extreme circumstances, our commodity sales may not generate sufficient revenue to meet our financial obligations and to fund planned capital expenditures. Moreover, significant price decreases could negatively affect our reserves by reducing the quantities of reserves that are recoverable on an economic basis, necessitating write-downs to reflect the realizable value of the reserves in the lower-price environment.

We are unable to control the market prices for crude oil and natural gas. Such market prices depend on numerous factors that include:

the extent of domestic production and exportation of crude oil and natural gas;
the proximity of pipelines or other economically-feasible transportation;
the availability of pipeline capacity;
the demand for crude oil and natural gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of weather variability; and
the effects of regulations on transporting, marketing and exporting natural gas and crude oil within Canada.

Because of these and other factors, we may be unable to market all of the natural gas and crude oil that we have available for sale. Additionally, we may be unable to obtain favorable prices for the natural gas and crude oil that we produce.

Concentration of Operations
Mantario East, Saskatchewan comprised 86% of total production and 72% of total revenue during the three months ended December 31, 2005 and 80% of total production and 77% of total revenue during the nine months ended September 30, 2005. Cypress/Chowade, British Columbia contributed 89% of total production and 94% of total revenue during the year ended December 31, 2004 and nearly all of total production and total revenue during the year ended December 31, 2003. Unless we can successfully drill for or acquire economically viable reserves of crude oil and natural gas in other areas, as our production depletes the reserves at Mantario East, our revenue may be materially adversely affected.

Revenue Breakdown
Total revenue generated during the twelve months ended December 31, 2005 by the properties we acquired on October 1, 2005 was $12.7 million. Of this total, 75% came from the sales of heavy crude oil in southeastern Saskatchewan and the balance came mainly from the sales of natural gas originating from northeastern British Columbia.

The following table shows revenue by commodity that was generated by the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 for each of the periods indicated.

Crude Oil and Natural Gas Revenue
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($ 000’s)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Heavy crude oil	2,558	7,048	9,606	469	-
Natural gas	1,017	2,107	3,124	7,158	1,512
Light/medium crude oil	-	15	15	15	12
Total	3,575	9,170	12,745	7,642	1,524

Seasonality and Raw Materials
The seasonality of our main revenue-generating commodity, heavy crude oil, relates mainly to its price. During the peak winter months prices tend to be lower than during summer months due to limited heavy crude oil refining and handling capacities.

We do not rely on the availability of raw materials, because we operate in an extractive industry.

Marketing
We market our crude oil production based on the index, Hardisty Heavy 12⁰ API, for heavy crude oil in the proximity of southern Saskatchewan. Production from our Mantario East field is, for the most part, approximately 13.4 ⁰ API. Marketing of our natural gas production is currently managed by the field operator at Cypress in northeastern British Columbia.

Competition
We regularly compete with other companies in bidding for the acquisition of petroleum interests from the Alberta, British Columbia, and Saskatchewan governments and other corporations or individuals holding such interests. Further, we regularly compete for the availability of drilling rigs, production equipment, processing facilities, pipeline capacity and other transportation services. We do not have a competitive position that allows us any material or significant advantages compared to other companies within the same industry. Many competitors have substantially greater financial and other resources than we do.

Governmental Regulations
Government regulations have a material effect on us to the extent that they require us to conduct field operations and hydrocarbon extraction activities according to prescribed environmentally-safe, sensitive regulations. Also, government regulations may restrict the commencement or re-commencement of field activities in certain properties in which we hold an interest for the purpose of exploration. Examples of types of governmental laws and regulations that may have a material effect on our business include:

requirements to acquire permits before commencing drilling operations;
requirements to restrict the substances that can be released into the environment in connection with drilling and production activities;
limitations on, or prohibitions to, drilling in protected areas such as offshore areas; and
requirements to mitigate and remediate the effects caused by drilling and production operations.

C. Organizational Structure – Not Applicable

D. Property, Plant and Equipment

We own various interests in properties located in the western Provinces of Canada. For purposes of identification, discussion and differentiation, we have named them based on their location. They are as follows:

British Columbia	Saskatchewan	Alberta
Cypress/Chowade	Mantario East	Pica
Orion	Elmore
Fraser Valley	Rapdan
Rigel	Flaxcombe
	Sandgren

Our total land holdings as at December 31, 2005 were 99,697 net acres, of which 89,889 net acres, or 90%, were undeveloped. The following table shows the gross and net land acreages by area in which we own working interests.

Land Holdings (Acres)
As at December 31, 2005
	Developed		Undeveloped		Total		Weighted
Area	Gross	Net	Gross	Net	Gross	Net	Avg WI %
Alberta
Pica	640	80	1,920	240	2,560	320	13%

British Columbia
Cypress/Chowade	10,978	4,642	44,255	16,327	55,233	20,969	38%
Orion	4,005	3,337	61,941	43,130	65,946	46,467	70%
Rigel	480	192	3,350	1,340	3,830	1,532	40%
Fraser Valley	-	-	54,502	18,278	54,502	18,278	34%
Total British Columbia	15,463	8,171	164,048	79,075	179,511	87,246	49%
Saskatchewan
Mantario East	2,088	1,511	10,407	7,475	12,495	8,986	72%
Flaxcombe	-	-	3,887	2,103	3,887	2,103	54%
Sandgren	40	24	1,902	996	1,942	1,020	53%
Rapdan	160	14	-	-	160	14	9%
Elmore	162	8	-	-	162	8	5%
Total Saskatchewan	2,450	1,557	16,196	10,574	18,646	12,131	65%
Total to December 31, 2005	18,553	9,808	182,164	89,889	200,717	99,697	50%

          British Columbia Properties
          Cypress/Chowade
          Cypress/Chowade is located in the foothills of northern British Columbia approximately 100 kilometers northwest of Fort St. John.

Geological Description
The area is prospective for multiple, natural gas-bearing Triassic Age and deep Mississippian Age carbonate reservoirs contained within classic foothill anticlines that trend northwest/southeast through the area.

Land Holdings
We have crown petroleum and natural gas leases over 20,969 net acres (55,233 gross) for a weighted average working interest of 38%. Of our total net acreage, 77% is undeveloped.

Seismic
Our seismic database contains a total of 440 kilometers of licensed, trade 2D seismic data, as well as a 100% working interest in 15 kilometers of 2D proprietary seismic data.

Wells and Facilities
We have four (1.8 net) producing gas wells, 33% of a central compression facility and 40% of an 8” 19-kilometer pipeline that crosses beneath the Halfway River and connects Cypress to the Sikanni Gas Plant.

Activities During the Twelve Months Ended December 31, 2005
During the period, the property averaged 185 boe/d from four producing natural gas wells. During the period, two of the producing wells at 50% working interest were completed, equipped and tied-in and a central natural gas compressor facility was constructed and installed at 33% working interest.

Fiscal 2006 Outlook
We plan to optimize current production levels by installing a new, sour, natural gas separator and re-configuring our existing dehydrator to minimize back pressure.

Orion
Orion is strategically located between the Sierra and Helmet natural gas fields approximately 56 kilometers west of the Alberta border and 112 kilometers south of the Northwest Territories border. The property is dissected by the Sierra Yoyo Desan Road, which provides year-round access for drilling operations.

A large independent Canadian oil and gas company has referred to the regional Devonian Age Jean Marie carbonate reservoir in this area as “The Greater Sierra Gas Play” and has described the area as the largest gas play discovered in Western Canada. Orion is a part of this area and is a key element in our long-term growth strategy.

Geological Description
The area is prospective for natural gas exploration and development in Cretaceous Age Bluesky sandstone reservoirs and Mississippian and Devonian Age Debolt, Jean Marie and Slave Point formation carbonate reservoirs.

Land Holdings
We hold under lease 46,467 net acres (65,946 gross) for a weighted average working interest of 70%. Approximately 93% of our net holdings are undeveloped.

Wells and Facilities
We own a 15% gross overriding royalty interest (convertible to a 50% working interest after payout of our initial capital expenditures) in one cased and standing potential Jean Marie gas well and a 100% working interest in one cased and standing potential Bluesky formation gas well. Both wells are cased and standing and awaiting further evaluation and area development.

Two major pipeline systems terminate at the edge of our property. To the southwest, the Duke Energy Pipeline System connects to Fort Nelson for delivery to Washington State and to the northeast. The Duke Energy Field Services Pipeline System connects to Tooga Compressor Station for delivery to Alberta.

Activities During the Twelve Months Ended December 31, 2005
The property did not produce during the period. Pursuant to a farmin agreement, an industry third-party drilled one unsuccessful well targeting natural gas. Also, one 100% working interest non-producing cased well was sold to an industry third-party.

Fiscal 2006 Outlook
Pursuant to a third-party drilling commitment, an exploration test well targeting the Bluesky formation was drilled in the first quarter of Fiscal 2006 by an independent third party. The well has been completed as an untested, potential standing natural gas well. We will retain a 15% gross overriding royalty in the well, converting to a 50% working interest upon payout of the third party’s initial capital expenditures.

Rigel
Rigel is located in the plains region of northern British Columbia approximately 65 kilometres north of Fort St. John and 40 kilometres west of the British Columbia/Alberta border.

Geological Description
The area has multi-zone potential for both oil and natural gas reservoirs. The main targets in the region include the Cretaceous-Dunlevy formation and the Triassic, Baldonnel, Charlie Lake, Halfway and Doig formations.

Land Holdings
We hold crown petroleum and natural gas leases covering 1,532 net acres (3,830 gross) for a weighted average working interest of 40%. Approximately 87% of our net holdings are undeveloped.

Wells and Facilities
We own one standing gas well (0.4 net).

Activities During the Twelve Months Ended December 31, 2005
The property did not produce during the period. A 40% working interest in 3,380 (1,532 net acres) of land was acquired and one well targeting natural gas was drilled and completed at 50% working interest.

Fiscal 2006 Outlook
In the first quarter of Fiscal 2006, we commenced drilling of the second commitment well for a 50% working interest. We also plan to participate in the equipping and tie-in of the first standing gas well (0.4 net) in the second quarter.

Fraser Valley
The property is located in the Lower Mainland area of southwest British Columbia near Vancouver.

Land Holdings
Under a joint venture agreement with a large, multi-national energy company, we continue to hold a weighted average working interest of 34% in approximately 18,278 net acres (54,502 gross) of undeveloped onshore and offshore petroleum and natural gas rights associated with Permit 802, a validated British Columbia Exploration Permit. Permit 802 is under provincial jurisdiction and includes offshore petroleum and natural gas rights in the Georgia Basin, located in the Strait of Georgia between the Lower Mainland and Vancouver Island.

Activities During the Twelve Months Ended December 31, 2005
We were inactive in the Fraser Valley area during this period.

Fiscal 2006 Outlook
Areas offshore are subject to a restricted-access moratorium for petroleum and natural gas activities; however, discussions are underway between the Provincial and Federal Governments in regards to lifting the moratorium. The Provincial Government has indicated its desire to move forward, and the Federal Government has been engaged in a public review to identify environmental and social concerns arising from offshore activities along the Pacific West Coast. A recent Federal Election has resulted in a change in government. As a result, the Provincial Government is expressing greater post-election optimism toward a joint Federal/Provincial lifting of the moratorium that may or may not occur in Fiscal 2006.

We have identified, through analysis of our proprietary onshore 2D seismic data, a large structural feature approximately 19 square kilometers in size extending offshore. Government-owned gravity data supports our interpretations and refers to the feature as the Robert’s Bank Gravity Anomaly. The Geological Survey of Canada has assigned the Georgia Basin an estimated reserve potential of 6.5 trillion cubic feet of natural gas. A commercial quantity of gas is yet to be discovered in the area.

          S.W. Saskatchewan and Alberta Properties
          Mantario East and Surrounding Areas
          Mantario East is located 30 kilometers southwest of the Town of Kindersley and 30 kilometers east of the Alberta Border.

Geological Description
The area is prospective for multiple Cretaceous, Mississippian and Devonian aged sandstone and carbonate reservoirs. Primary targets include natural gas-bearing Viking, Upper Mannville and Bakken formations and heavy-oil in the Basal Mannville and Birdbear formations.

Land Holdings
We hold under lease 8,986 net acres (12,495 gross) for a weighted average working interest of 72%. Approximately 83% of our net holdings are undeveloped.

Well and Facilities
We have 16 (10.5 net) producing heavy-oil wells, two (1.5 net) standing gas wells and three (2.3 net) standing heavy oil wells at Mantario East. We also own a 75% working interest in a heavy oil battery/heater-treater facility with a processing capacity of up to 3,500 barrels per day.

Activities During the Twelve Months Ended December 31, 2005
During the period the property averaged 823 bbls/d from 16 producing heavy oil wells. Drilling activities during the period resulted in 15 (9.1 net) wells of which: eight (4.5 net) were cased as heavy-oil wells; two (1.25 net) were cased as natural gas wells; one (0.8 net) was cased as a dual, heavy-oil/natural gas well; three (1.9 net) were unsuccessful; and one (0.8 net) was cased as a potential water disposal well. In addition, a heater-treater facility was constructed, and multiple 2D and 3D seismic programs were conducted covering an aggregate of 20.8 square kilometers at a 75% working interest.

Fiscal 2006 Outlook
We have budgeted to drill 10 (9.5 net) development in-fill and field-delineation wells targeting Basal Mannville oil. Of the 10 wells two horizontal wells drilled in the first quarter and are currently being tied in to production. The remaining eight vertical development wells are planned for the second and third quarters. We also plan to drill two (1.5 net) heavy oil exploration wells and two (1.5 net) natural gas exploration wells in the second and third quarters.

Our Fiscal 2006 budget includes the cost of a gas gathering and field compression facility, capable of processing up to 1.5 mmcf/day of gas from two (1.5 net) existing non-associated gas wells and from recovered solution gas currently sent to flare at our oil battery. The gas gathering and field compression facility has been completed in the first quarter.

Funds have also been budgeted to acquire additional lands and seismic data in the area. On March 17, 2006, we established a bank loan facility which, along with our year-end daily average production target of 2,000 boe/d and forecast of strong commodity prices, is expected to provide us with adequate resources to meet our Fiscal 2006 cash requirements.

Other Non-Core Properties
In Saskatchewan, properties include: Flaxcombe, Sandgren, Elmore, and Rapdan, and in Alberta, Pica. In total, these properties comprise 3,465 net acres (8,711 gross) with a weighted average working interest of 40%. Of our total net acreage in these areas, 96% is undeveloped.

Summary of Drilling Activity
The following table shows the drilling record during the three month period ended December 31, 2005, nine month period ended September 30, 2005 and twelve month periods ended December 31, 2004 and 2003 related to the properties we acquired on September 30, 2005 pursuant to the Plan of Arrangement.

Results of Drilling Activity
	Three Months		Nine Months		Twelve Months Ended
	Ended		Ended
	Dec 31, 2005		Sep 30, 2005		Dec 31, 2005		Dec 31, 2004		Dec 31, 2003
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Heavy crude oil	1	0.8	8	4.5	9	5.3	11	9.0	-	-
Natural gas	1	0.5	1	0.7	2	1.2	1	1.0	3	2.0
Unsuccessful	1	0.7	3	1.9	4	2.6	3	2.5	1	0.2
Total	3	2.0	12	7.1	15	9.1	15	12.5	4	2.2

Estimated Reserves of Crude Oil and Natural Gas
We began our operations on October 1, 2005, pursuant to a Plan of Arrangement that closed on September 30, 2005. Under the Plan of Arrangement, we received all of the benefits and obligations of producing assets and undeveloped lands formerly owned by Dynamic Oil & Gas, Inc., located in the provinces of Saskatchewan and British Columbia. We present in the tables below, estimated reserve data and their associated net present values effective December 31, 2005 – subsequent to the Plan of Arrangement. Comparative data is also presented effective December 31, 2004 and 2003, as though all Saskatchewan and British Columbia properties had been owned by us as at those dates.

As a Canadian issuer, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (NI 51-101) issued by the Canadian Securities Administrators, in all of our reserves related disclosures.

Under NI 51-101, proved reserves is an estimate, the premise of which means there must be at least a ninety percent probability that actual quantities of crude oil and natural gas proved reserves recovered will equal or exceed the estimated proved reserves.

In the United States, registrants, including foreign private issuers like us, are required to disclose proved reserves using the standards contained in Rule 4-10(a) of the United States Securities and Exchange Commission’s (“SEC”) Regulation S-X. Proved reserves estimated and reported below pursuant to NI 51-101 also meet the definition of estimated proved reserves required to be disclosed under Rule 4-10(a) of Regulation S-X.

The crude oil and natural gas industry commonly applies a conversion factor to production and estimated proved reserve volumes of natural gas in order to determine an “all commodity equivalency” referred to as barrels of oil equivalent (“boe”). The conversion factor we have applied in this Registration Statement is the current convention used by many oil and gas companies, where six thousand cubic feet (“mcf”) is equal to one barrel (“bbl”). A boe is based on an energy equivalency conversion method primarily applicable at the burner tip. It may not represent equivalency at the wellhead and may be misleading if used in isolation.

The reserve data set out in the summary table below is based on Sproule Associates Limited’s (“Sproule”) independent engineering evaluation of the estimated proved crude oil and natural gas reserves pertaining to the properties which we acquired on September 30, 2005.

Summary of Estimated Reserves (After Royalties) of Properties Acquired by Us on September 30, 2005
				Natural Gas
	Heavy Oil	Light/Medium Oil	Natural Gas ⁽¹⁾	Liquids	Total ⁽¹⁾
	(mbbl)	(mbbl)	(mmcf)	(mbbl)	(mboe)
Proved
Developed producing	593	5	460	-	675
Developed non-producing	54	-	294	5	108
Undeveloped	210	-	412	-	278
Total proved – Dec 31, 2005	857	5	1,166	5	1,061
Total proved – Dec 31, 2004	510	4	1,268	-	725
Total proved – Dec 31, 2003	-	4	4,264	-	715

(1)	Estimates of reserves of natural gas includes solution gas.

Estimated Reserves Reconciliation
The following reconciliation shows the changes in the estimated reserves after royalties that occurred on our Saskatchewan and British Columbia properties during the twelve months ended December 31, 2005.

Reconciliation of Estimated Reserves (After Royalties)
	Heavy Oil	Light/Medium Oil	Natural Gas ⁽¹⁾	Natural Gas Liquids	Total⁽¹⁾
		(mbbl)	(mmcf)	(mbbl)	(mboe)
Dec 31, 2004	510	4	1,268	-	725
Acquisitions	-	-	-	-	-
Extensions	224	-	528	-	312
Discoveries	-	-	292	5	53
Improved Recovery	93	-	5	-	94
Revisions	225	2	(693)	-	112
Production	(195)	(1)	(234)	-	(235)
Dec 31, 2005	857	5	1,166	5	1,061

⁽¹⁾	Estimates of reserves of natural gas include solution gas.

Net Present Values (NPV) of Reserves
In the following two tables, we present Sproule’s estimated net present values associated with the estimated proved reserves shown in the above tables. The undiscounted and discounted net present values presented may not represent the fair market values of the reserves, as the use of other assumptions could give rise to different results.

NPV of Estimated Reserves (After Royalties) Associated with Properties Acquired by Us on September 30, 2005
	Before Income Taxes		After Income Taxes
	Discount Rate		Discount Rate
($000’s)	0%	10%	0%	10%
Proved
Developed producing	11,200	9,865	10,781	9,431
Developed non-producing	2,823	2,484	2,071	1,770
Undeveloped	4,122	2,951	3,332	2,214
Total proved – Dec 31, 2005	18,145	15,300	16,184	13,416
Total proved – Dec 31, 2004	6,804	5,368	5,456	4,277
Total proved – Dec 31, 2003	14,725	10,217	10,376	7,074

In accordance with SEC regulations, the above disclosure of our reserve information is on an after-royalties basis. As our production is on a before-royalties basis consistent with other Canadian oil and gas companies, we also disclose in the following tables, a before-royalties summary and a reconciliation of our estimated proved reserves that occurred on the Saskatchewan and British Columbia properties during the twelve months ended December 31, 2005:

Summary of Estimated Reserves (Before Royalties) of Properties Acquired by Us on September 30, 2005
	Heavy Oil	Light/Medium Oil	Natural Gas⁽¹⁾	Natural Gas Liquids	Total⁽¹⁾
	(mbbl)	(mbbl)	(mmcf)	(mbbl)	(mboe)
Proved
Developed producing	745	5	623	-	854
Developed non-producing	66	-	377	6	135
Undeveloped	260	-	562	-	354
Total proved – Dec 31, 2005	1,071	5	1,562	6	1,343
Total proved – Dec 31, 2004	615	5	1,737	-	909
Total proved – Dec 31, 2003	-	5	6,067	-	1,016

(1)	Estimates of reserves of natural gas includes solution gas.

Reconciliation of Estimated Reserves (Before Royalties)
	Heavy Oil	Light/Medium Oil	Natural Gas ⁽¹⁾	Natural Gas Liquids	Total ⁽¹⁾
	(mbbl)	(mbbl)	(mmcf)	(mbbl)	(mboe)
Dec 31, 2004	615	5	1,737	-	909
Acquisitions	-	-	-	-	-
Extensions	307	-	722	-	427
Discoveries	-	-	375	6	69
Improved Recovery	114	-	5	--	115

Revisions	313	1	(959)	-	155
Production	(278)	(1)	(318)	-	(332)
Dec 31, 2005	1,071	5	1,562	6	1,343

⁽¹⁾	Estimates of reserves of natural gas include solution gas.

The estimate of our proved reserves on a constant-pricing basis, and their associated net present values as at December 31, 2005, have been based on posted commodity prices on December 31, 2005 as determined by Sproule. These prices have been adjusted for applicable quality and transportation differentials to reflect actual historical prices received by us from each of our properties. Adjusted prices and our associated operating costs incurred have been assumed to remain constant over the life of the reserves. The following table shows the base prices used by Sproule in determining their estimates:

Summary of December 31, 2005 Base Prices Used in the Estimate of Reserves on a Constant-Pricing Basis
Indices	Crude Oil	Natural Gas and By-Products	$US/$Cdn
Hardisty Heavy 12° API ($Cdn/bbl)	30.86
Cromer Medium 20.3° API ($Cdn/bbl)	52.28
Hardisty Lloyd Blend 22.30 API
($Cdn/bbl)	39.73
AECO ($Cdn/mcf)		9.99
BC Westcoast Station 2 ($Cdn/mcf)		9.27
Butanes ($Cdn/bbl)		59.32
Exchange Rate			0.860

Item 4A. Unresolved Staff Comments – Not applicable

Item 5. Operating and Financial Review and Prospects

A. Operating Results

Unless otherwise noted, tabular amounts are in thousands of Canadian dollars, and production volumes and reserves are before royalties. We have presented our working interest before royalties, as we measure our performance on this basis, which is consistent with other Canadian oil and gas companies.

In this discussion and analysis, we may analyze expense factors on a unit cost of production basis. It is industry practice among our peer-group to monitor trends in expenses against daily average production volumes and the common unit of production used is the barrel of oil equivalent (“boe”). We do not analyze expense trends based on gross revenues, as commodity price volatility may lead to less-reliable comparisons.

Plan of Arrangement and Related Party Transaction - On September 30, 2005, we received our initial asset base under the terms of the Plan of Arrangement, which resulted in all our shareholders effectively receiving, among other consideration, one share of our Common Stock for each common share of Dynamic held. At the time of this transaction, we were a related company to Dynamic, resulting in a transfer of assets to us from Dynamic at their carrying values.

Following the close of the Plan of Arrangement, we commenced operations on October 1, 2005 with daily average production of approximately 900 barrels of oil equivalent per day (“boe/d”), 190,716 gross acres (92,515 net acres) and

approximately $29.7 million in income tax pools available for deduction against future taxable income. Of our total acreage, approximately 90% was undeveloped, 71% of which was located in northeastern British Columbia.

In terms of our balance sheet and pursuant to the Plan of Arrangement, we were allocated the following net assets:

Net Assets Received
($000’s unless otherwise stated)	Amount
Cash	3,564
Assumed working capital deficit (net of cash)	(983)
Crude oil and natural gas interests	15,321
Capital assets	341
Asset retirement obligation	(989)
Common Shares issued pursuant to the Plan of Arrangement (25,754,278)	17,254

Executive Overview

Key Measures for the Comparative Periods Presented
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($ 000’s unless otherwise stated)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Crude oil and natural gas sales	3,575	9,170	12,745	7,642	1,524
Cash provide by (used in)
operating activities	(2,124)	5,495	3,371	1,536	(455)
Net loss	1,868	15,316	17,184	25,934	3,918
Net loss per share ($/share)⁽¹⁾
basic and diluted	0.06	-	-	-	-
Daily average production (boe/d)	1,070	989	1,009	582	127
Total production (mboe)	98	270	368	213	46
Capital investment program ⁽²⁾	4,295	9,221	13,516	32,432	14,236
Total assets	32,967	22,777	32,967	26,791	19,626
Working capital (deficit) ⁽³⁾	3,021	1,634	3,021	(10,786)	(3,115)
Working capital ratio ⁽⁴⁾	1.3:1	1.3:1	1.3:1	0.1:1	0.1:1

(1)	Prior to the Plan of Arrangement, we had issued one Common Share to incorporate as a separate legal entity. Therefore, historical losses per share have not been presented in the financial statements. Losses per share have been presented using our Common Shares outstanding subsequent to the Plan of Arrangement.

(2)	We report capital transactions under the title, “Capital investment program”. Capital investment program includes expenditures on crude oil and natural gas assets, exploration expenses relating to seismic and unsuccessful drilling efforts, and capital assets. Seismic and unsuccessful drilling costs comprise the majority of our Exploration expense as reported in our Statements of Operations and Deficit.

(3)	Working capital is defined as current assets less current liabilities.

(4)	We have no long-term debt. Working capital ratio is defined as current assets divided by current liabilities.

Our gross revenue, cash flow from operating activities and net losses are impacted by three key performance measures. The first of these is the weighted average price that we realize upon the sale of our commodities, the second is our total and daily average production levels. The third performance measure is related to our success in establishing or replacing proved reserves, as we recognize the costs of unsuccessful drilling efforts as exploration expense.

During the twelve months ended December 31, 2005, the realized weighted average price related to the sale of heavy crude oil from the properties that we began operating on October 1, 2005, was $33.58 per barrel, compared to $21.07 during the twelve months ended December 31, 2004. There was no heavy oil production from the properties during 2003. The weighted average price realized from the sale of natural gas was $9.51 during the twelve months ended December 31, 2005, and $6.59 and $5.83 per mcf during the twelve months ended December 31, 2004 and 2003, respectively.

Total production during the twelve months ended December 31, 2005 was 368 mboe, compared to 213 and 46 mboe during the twelve months ended December 31, 2004 and 2003, respectively. The daily average production rates were 1,009 boe/d over the twelve months ended December 31, 2005, and 582 boe/d and 127 boe/d during the twelve months ended December 31, 2004 and 2003, respectively. Compared to the twelve months ended December 31, 2005, heavy crude oil production from Mantario East increased by 762 boe/d due to tie-ins of standing and newly-drilled wells, while natural gas production from Cypress/Chowade declined by 335 boe/d due to higher-than-expected decline rates.

During the twelve months ended December 31, 2005, exploration expenses of $12.9 million included costs of drilling twelve dry holes, of acquiring and/or shooting 3D and 2D seismic and of certain drill-site preparations. During 2004, exploration

expenses of $12.2 million included costs of drilling ten dry holes and of shooting a 44-square kilometer 3-D seismic program at Orion. During 2003, exploration expenses were $1.4 million, most of which was for seismic data gathering at Cypress/Chowade and Orion.

We obtained financing to meet our budgeted capital investment program for the fourth quarter of 2005 and Fiscal 2006 from three different sources. First, we were provided with initial funding cash of $1.2 million pursuant to the Plan of Arrangement. The other two sources were operating cash flows and a private placement financing completed on October 3, 2005 that resulted in cash proceeds, net of fees and financing costs, of approximately $3.9 million. Upon closing of the private placement, we issued at $1.20 per share, 1,666,666 flow-through shares and 1,666,667 common shares (non-flow-through).

The gross proceeds of the flow-through portion of the private placement were $2.0 million, all of which must be spent by December 31, 2006 on qualifying expenses for exploration-only activities that are specifically defined in the Income Tax Act (Canada). As at December 31, 2005, we had incurred approximately 53% of the required obligation. On January 19, 2006, we officially renounced the tax benefits of the entire $2.0 million in favour of the flow-through shareholders.

On March 17, 2006, we established a $6.5 million revolving demand credit facility which, along with our production targets and forecasts of strong commodity prices, is expected to provide adequate resources to meet our Fiscal 2006 cash requirements.

Effective December 31, 2005, our total proved reserves on an after-royalties, constant-price basis were independently estimated at 1,061 mboe, with light/medium crude oil comprising 862 mboe or 81% of our total proved reserves, and natural gas and natural gas liquids comprising 199 mboe or 19%. As at December 31, 2004 and 2003, the same properties that we acquired pursuant to the Plan of Arrangement were assigned estimated proved reserves of 725 and 715 mboe, respectively.

As at December 31, 2004, crude oil comprised 71% of total proved reserves discussed above, with natural gas and liquids as the remainder. During the twelve months ended December 31, 2004, proved reserves of natural gas decreased by 70% due to production, and downward technical revisions and economic factors associated with wells in the Cypress/Chowade area. Such revisions were due to a combination of higher-than-expected decline rates from six wells. Also during the period, estimated proved reserves of heavy crude oil increased by 99% due to the discovery and exploitation of a new pool at Mantario East.

As at December 31, 2003, crude oil comprised only 1% of total proved reserves discussed above, while natural gas was 99%.

Financial Results

Revenues
During the twelve months ended December 31, 2005, revenues generated from the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 totaled $12.7 million, compared to $7.6 and $1.5 million for each of the two preceding years, respectively. The revenue mix for the twelve months ended December 31, 2005, was 75% crude oil based and 25% natural gas based. Comparatively, the mix for the twelve months ended December 31, 2004 and 2003 was 94% and 99% natural gas based, respectively.

During the three months ended December 31, 2005, crude oil comprised 72% of our total revenue generated, a trend that is expected to continue from our properties in Fiscal 2006.

In comparing the twelve months ended December 31, 2004 and 2003, natural gas revenues increased by $5.6 million, in part due to a 13% increase in weighted average prices. However, most of the increase was due to significant new production in the Cypress/Chowade field. In comparing the twelve months ended December 31, 2005 and 2004, daily natural gas production

and revenues from Cypress/Chowade decreased by 64% (1,110 mdf/d from 3,120 mcf/d) or 56% ($3.1 million from $7.2 million), respectively. The decrease in production was due to higher-than-expected decline rates, a factor that was partially mitigated by an increase in realized weighted average natural gas prices of 44% or $2.92/mcf, to $9.51/mcf. Late in 2004, a new oil pool discovery was made at Mantario East that, during the twelve months ended December 31, 2005, increased crude oil revenues by $9.1 million.

Revenues by Commodity
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($ 000’s)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Heavy crude oil	2,558	7,048	9,606	469	-
Natural gas	1,017	2,107	3,124	7,158	1,512
Light/medium crude oil	-	15	15	15	12
Total	3,575	9,170	12,745	7,642	1,524

Daily Average Production Rates and Total Production
Our daily average production for the three months ended December 31, 2005 was 1,070 boe/d and our exit rate was approximately 1,550 boe/d. We anticipate our exit production rate at the end of Fiscal 2006 will reach 2,000 boe/d, subject to rig availability, drilling successes and the timing of completions and tie-ins.

Of our daily average production rate for the three months ended December 31, 2005, 86% is heavy crude oil originating from our Mantario East field in southeast Saskatchewan. We expect that our Fiscal 2006 exit rate will be comprised of approximately 86% heavy crude oil and the balance, mainly sweet natural gas.

The following table shows the daily average production rates and total production by commodity and field related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005, for the twelve months ended December 31, 2005, 2004 and 2003.

Daily Average Production Rates by Commodity and Field, and Total Production
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
(Units as stated)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Daily average production rates
Mantario East	915	791	823	61	-
Total heavy crude oil (bbl/d)	915	791	823	61	-
Light/medium crude oil (bbl/d)
Other, Saskatchewan	1	1	1	1	1
Total light/medium
crude oil (bbl/d)	1	1	1	1	1
Natural gas (mcf/d)
Cypress/Chowade, B.C.	927	1,176	1,110	3,120	756
Total natural gas (mcf/d)	927	1,176	1,110	3,120	756
Total natural gas (boe/d 6:1)	154	196	185	520	126
Total daily average
production (boe/d)	1,070	989	1,009	582	127
Total production
all products (mboe)	98	270	368	213	46

In comparing the twelve months ended December 31, 2004 and 2003, daily production of natural gas increased by 313% (3,120 over 756 mcf/d) due to new drilling and tie-in activity in the Cypress/Chowade field. In comparing the twelve months ended December 31, 2005 and 2004, daily natural gas production from the Cypress/Chowade field declined by 64% (1,110 from 3,120 mcf/d) due to higher-than-expected decline rates. Late in the twelve month period ended December 31, 2004, a new oil pool discovery was made at Mantario East that would later serve to increase daily crude oil production during the twelve months ended December 31, 2005 by a factor in excess of thirteen times.

Weighted Average Commodity Prices
Our weighted average heavy crude oil prices are based on the index, Hardisty Heavy 12^o API, for heavy crude oil in the proximity of southern Saskatchewan. Company-operated production from our Mantario East field is, for the most part, approximately 13.4 ^o API.

Our weighted average natural gas prices are currently managed by the field operator at Cypress in northeastern British Columbia.

Sproule Associates Limited, an engineering firm in Calgary, Alberta and independent evaluator of reserves, maintains a website showing historical and forecasted prices, which helps to provide trends of the above-described index affecting our weighted average prices. The website address is: www.sproule.com/prices/defaultprices.htm.

Management also regularly employs price-trending information for its internal cash flow forecasting purposes from the websites of two firms that regularly market hydrocarbon commodities. They are www.progas.com and www.nexenmarketing.com.

The following table shows the weighted average prices realized by commodity related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005, for the twelve months ended December 31, 2005, 2004 and 2003. During the twelve months ended December 31, 2003, heavy crude oil had not yet been discovered at Mantario East.

Weighted Average Commodity Prices
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
(Units as stated)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Heavy crude oil ($/bbl)	30.33	34.95	33.58	21.07	-
Natural gas ($/mcf)	11.92	8.66	9.51	6.59	5.83
Light/medium crude oil ($/bbl)	59.24	48.67	49.99	44.24	34.90

Royalties and Royalty Credits (Net Royalties)
Of our total net royalties for the three months ended December 31, 2005, 52% were crown burdens and 48% were freehold and gross overriding burdens. Net royalty expense for the three months was $0.9 million or $8.97 per boe, a unit net royalty rate per boe that we expect will remain relatively consistent throughout Fiscal 2006.

During the twelve months ended December 31, 2005, net royalty expense related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 was $3.4 million or $9.30 per boe. Comparatively, net royalty expense for the twelve months ended December 31, 2004 and 2003 was $2.1 million or $9.85 per boe and $0.3 million or $7.29 per boe, respectively. Unit royalty expense between the twelve months ended December 31, 2005 and 2004 remained relatively constant. In comparison, unit royalty expense between the twelve months ended December 31, 2004 and 2003 increased by 35% or $2.56, to $9.85 per boe due to a relatively higher contribution made by British Columbia royalty credits to total net royalty expense during the earlier period.

Production and Transportation Costs
Production and transportation costs (“P&T”) for the three months ended December 31, 2005 totalled $1.0 million or $10.22 per boe. Currently, we operate approximately 86% of our production, allowing us to better control P&T costs. Our corporate average P&T costs for Fiscal 2006 are expected to range from $7 - $8 per boe. The expected reduction in P&T costs is mainly due to anticipated, improved processing efficiencies created through the recent start-up of a new battery facility at Mantario East.

During the twelve months ended December 31, 2005, P&T costs related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 were $3.1 million or $8.53 per boe. Comparatively, P&T costs for the twelve months ended December 31, 2004 were $2.6 million or $12.19 per boe. Unit P&T costs decreased between these two periods due to the impact of decreased production from the higher unit-cost Cypress/Chowade field, compared to increased production from the lower unit-cost Mantario field.

During the twelve months ended December 31, 2003, P&T costs were $0.4 million or $9.09 per boe, a unit cost that was relatively lower than that of the twelve months ended December 31, 2004 due to the fact that a few wells produced flush production longer in 2003 than in 2004.

Amortization and Depletion Expense
Amortization and Depletion (“A&D”) expense for the three months ended December 31, 2005 was $1.4 million or $14.33 per boe. Included in this amount are certain asset retirement obligation adjustments of $0.2 million. After removing the

impact of the adjustments, our unit A&D expense was $12.21 per boe. It is anticipated our Fiscal 2006 A&D rate per boe will rise as increases in the current cost environment exceed historical costs.

During the twelve months ended December 31, 2005, A&D expense related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 was $9.0 million or $24.55 per boe. This unit cost is double that of the $12.21 per boe discussed above, mainly due to the fact that A&D expense recorded in 2005 prior to the Plan of Arrangement was based on the December 31, 2004 reserves that were available at the time, as opposed to the higher December 31, 2005 reserves that were later available in determining A&D for the three months ended December 31, 2005.

A&D expense for the twelve months ended December 31, 2004 was $14.8 million or $69.66 per boe. This unit cost was higher than the twelve months ended December 31, 2005 due to significant downward technical revisions to natural gas reserves and an impairment test adjustment of $3.6 million at Cypress/Chowade that were taken into account in 2004. The technical revisions and the impairment test adjustment were caused by a combination of higher-than-anticipated decline rates from six wells.

A&D expense for the twelve months ended December 31, 2003 was $1.9 million or $41.17 per boe, a unit factor that reflected relatively greater capital costs of non-producing leaseholds versus a lower production base than in the twelve months ended December 31, 2004. An impairment test adjustment of $0.3 million related to Cypress/Chowade was recorded in the twelve month period ended December 31, 2003.

There were no impairment test adjustments in the twelve months ended December 31, 2005.

Exploration Expenses
We follow the successful efforts method of accounting, whereby costs of drilling an unsuccessful well are expensed immediately if it is known the well did not result in a discovery of proved reserves. If the economic importance was not immediately known after drilling, the expensing of our drilling costs may be temporarily deferred. We expense such deferred costs after one year if near-term efforts to establish proved reserves are not foreseeable, intended, or in our control. Collectively, we report these costs as “Drilling” in the table below.

While we report our budgeted annual drilling costs, it is difficult to forecast year-over-year drilling success rates. However, two factors tend to increase or decrease our exploration expenses as they relate to drilling. They are as follows:

Exploratory wells generally involve a greater degree of risk than development wells, due to the increased uncertainty in establishing proved reserves; and
Wells in which we participate at higher working interests increase costs accordingly.

The amount of our exploration expenses each year also depends upon how much seismic data we add to our library. Although seismic science does not remove all uncertainty, we incur such expenses in order to improve our knowledge base, develop new prospects and decrease the risk of drilling failures.

The following table shows our exploration expenses by expense category related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005, for the twelve months ended December 31, 2005, 2004 and 2003.

Exploration Expenses
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($ 000’s unless otherwise stated)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Drilling	471	11,132	11,603	8,322	12
Seismic data activity	511	221	732	3,686	1,249
Other	477	128	605	186	135
Total exploration expenses	1,459	11,481	12,940	12,194	1,396

During the twelve months ended December 31, 2005, exploration expenses related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005 were $12.9 million. Comparatively, exploration expenses for the 2004 and 2003 years were $12.2 and $1.4 million, respectively.

During the twelve months ended December 31, 2005, exploration expenses included costs of drilling twelve dry holes, of acquiring and/or shooting 3D and 2D seismic and of certain drill-site preparations. During the twelve months ended December 31, 2004, exploration expenses included costs of drilling ten dry holes and of shooting a 44-square kilometer 3-D seismic program

at Orion. During the twelve months ended December 31, 2003, exploration expenses were mostly for seismic data gathering at Cypress/Chowade and Orion.

Interest Expense - Net
As at December 31, 2005, we did not have an established line of bank credit, therefore, we had no bank interest expense. However, short-term deposit interest of $0.1 million was earned during the three months ended December 31, 2005, the principal amounts of which originated from three sources: cash paid to us pursuant to the Plan of Arrangement; cash from the private placement consummated on October 3, 2005; and cash generated from operations during the three months. During the first half of Fiscal 2006, we do not anticipate any material interest expense.

During the three months ended December 31, 2005, we became responsible for our own cash and cash requirements and generated interest income through short-term deposits of $0.1 million. Prior to the Plan of Arrangement, portions of interest expense incurred by Dynamic have been allocated to each of the periods prior to September 30, 2005 in the following table (see Note 2 to our Financial Statements for details). There were no significant variances between the periods shown.

Interest Expense - Net
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($ 000’s unless otherwise stated)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Interest expense (income) - net	(68)	228	160	248	234

General and Administrative Expenses
Total cash general and administrative (“G&A”) costs during the three months ended December 31, 2005 were $0.9 million or $8.91 per boe. Actual cash G&A costs for the period since the close of the Plan of Arrangement, on a per-boe basis, are slightly higher than our expected normalized annual basis going forward, as certain costs normally incurred over a full year have been accrued for in the three months. Examples of such costs relate to the preparation of our: reserves and annual reports; audited financial statements; information circular; Form 20-F; Annual Information Form; and our NI 51-101 Form, “Standards of Disclosure for Oil and Gas Activities”.

Our cash G&A costs for Fiscal 2006 are expected to be between $3 and $4 per boe. The projected decrease from the $8.91 per boe level discussed above is a result of an anticipated growth in annual production levels and our first, full-year normalization of costs going forward.

We account for all stock-based compensation using the fair-value based method. Under this method, compensation expense is recorded in our statement of operations over the vesting period. During the three months ended December 31, 2005, we recognized a stock-based compensation expense of $0.6 million related to the granting on October 18, 2005 of 2,265,000 options at an exercise price $1.44 per share to our directors, officers, employees and certain key consultants.

Portions of cash and non-cash G&A expenses incurred by Dynamic have been allocated in the following table to each of the periods prior to September 30, 2005 (see Note 2 to our Financial Statements for details). Year-to-year variances in cash G&A expenses, in general, trended according to changes in staff size and compensation levels. Due to the allocation method used to determine expense, unit analysis per boe is not meaningful.

G&A Expenses
	Three Months	Nine Months
	Ended	Ended	Twelve Months Ended
($ 000’s unless otherwise stated)	Dec 31, 2005	Sep 30, 2005	Dec 31, 2005	Dec 31, 2004	Dec 31, 2003
Cash G&A expenses	870	834	1,704	1,448	1,003
Non-cash: stock-based compensation	631	214	845	154	118
Total G&A	1,501	1,048	2,549	1,602	1,121

Asset Retirement Obligation (ARO)
We record the fair value of our legal obligations associated with the de-commissioning and reclamation of long-lived tangible assets, such as well, plant and battery sites. All carrying amounts are depleted using the unit-of-production method, and associated liabilities accrete until retirement obligations are settled. Actual settlement costs of retiring tangible assets are deducted from the estimated settlement liability as they are incurred, at which time gains or losses are recorded appropriately.

The total undiscounted amount of estimated cash flows required to settle the asset retirement obligations related to the properties which were acquired by us on September 30, 2005 and which began operations under our control effective October 1, 2005, as at December 31, 2005 was $1.7 million ($1.2 million on a discounted basis, using an average credit-adjusted risk-free rate of 5.7%) . These payments are expected to be made over the next 29 years with 37% of the costs incurred within the next five

years. As at December 31, 2004 and 2003, the undiscounted amounts were $0.8 and $0.4 million discounted annually, respectively.

Asset retirement obligations reflect the increase of drilled well-bores and constructed facilities on the British Columbia and Saskatchewan properties throughout the 2003 to 2005 period.

Income Tax Valuation Allowance and Tax Pools
We use the liability method of tax allocation in accounting for income taxes. Future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantively-enacted rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance is recorded against any future income tax asset if it is more likely than not that the asset will not be realized.

As at December 31, 2005, our tax pools exceeded the carrying value of our assets for accounting purposes. This excess pool balance has been included in a valuation allowance amounting to $5.6 million, resulting in a future income tax asset of $0.8 million. With greater certainty of utilization of these income tax pools, future income tax assets may be recognized in future periods of operations.

The following table shows tax pools by classification that we had available for deduction against future taxable income as at December 31, 2005, each pool allowing maximum annual deductions ranging from 10% to 100%.

Income Tax Pools Available for Deduction Against Future Taxable ⁽¹⁾
	As at	Maximum Annual
($ 000’s)	Dec 31, 2005	Deduction
Canadian exploration expense ⁽²⁾	2,322	100%
Canadian development expense	688	30%
Undepreciated capital cost	6,936	20% - 100%
Canadian oil and gas property expense	22,968	10%
Total income tax pools	32,914

(1)	Tax pool balances of December 31, 2004 and 2003 are not presented, as they do not impact pro-forma financial statement presentations.

(2)	The tax pool balance as at December 31, 2005 is before taking into account the renunciation of $2.0 million to flow-through shareholders of Canadian exploration expense, such renunciation having occurred in Fiscal 2006 (see Note 7 to our Financial Statements for further details).

Prior to the Plan of Arrangement, there were no taxable earnings generated and realization of future income tax assets was not considered to be more likely than not. Therefore, no current income tax or future income taxes were recorded in the financial statements for the periods prior to the Plan of Arrangement.

Hedging
In 2005, we had no hedging activity.

Critical Accounting Policies and Estimates

Our critical accounting policies are defined as those that are important to the portrayal of our financial position and results of operations and require us to make judgments based on underlying estimates and assumptions about future events and their effects. Such underlying estimates and assumptions are based on historical experience and other factors that we believe to be reasonable under the circumstances. These estimates and assumptions are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as our operating environment changes. We believe the following are the most critical areas where estimates and our accounting policies can materially impact our Financial Statements. For information concerning our other significant accounting policies, see Note 3 to our Financial Statements.

Reserves Estimates
As at December 31, 2005, we engaged independent petroleum consultants to conduct an evaluation of our reserves. The accuracy of reserves estimates is a matter of interpretation and judgment and is a function of the quality and quantity of available data gathered over time. For further details and a discussion of the risks involved in the reserves estimating process, see “Business Risk Management - - Estimating of Reserves and Future Net Cash Flows Risk”.

Crude Oil and Natural Gas Interests
We follow the successful efforts method of accounting for our crude oil and natural gas activities, as described in Note 3 to our Financial Statements. The application of this method requires us to make significant judgments and decisions based on available geological, geophysical, engineering and economic data. The results from drilling can take considerable time to analyze. When it is determined that drilling has been unsuccessful in establishing proved reserves or where one year has elapsed since the completion of drilling and near-term efforts to establish proved reserves are not foreseeable, intended, or in

our control, the costs of drilling are written off and reported as exploration expense. Drilling costs for wells that have been successful in establishing proved reserves are capitalized as crude oil and natural gas interests on our balance sheet.

Where we assess that the estimated undiscounted future cash flows are below the book value of a property as recorded in our crude oil and natural gas interests (“impairment test”), we either partially or fully adjust the book value downward and record a depletion expense on our income statement accordingly (“impairment test adjustment”).

Estimates of undiscounted future cash flows that we use for conducting impairment tests are subject to significant judgment decisions based on assumptions of highly uncertain future factors such as, crude oil and natural gas prices, production quantities, estimates of recoverable reserves, and production and transportation costs. Given the significant assumptions required and the strong possibility that actual future factors will differ, we consider the impairment test to be a critical accounting procedure.

During the three months ended December 31, 2005 and the nine months ended September 30, 2005, no property impairment adjustments were recorded. During the years ended December 31, 2004 and 2003, $3.6 million and $0.3 million were recorded as impairment adjustments, respectively.

Accounting Policy Changes

Canadian Pronouncements
The following pronouncements were issued by the CICA during Fiscal 2005. While we are not materially affected by these pronouncements, we will continue to assess their applicability.

CICA 3831, Non-Monetary Transactions
In June 2005, the AcSB issued CICA 3831, Non-Monetary Transactions, replacing the former CICA 3830, Non-Monetary Transactions. The new Section requires all non-monetary transactions to be measured at fair value unless: the transaction lacks commercial substance; the transaction is an exchange of a product or property held for sale in the ordinary course of business for a product or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange; neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation.

The new requirements apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006. Early adoption is permitted for non-monetary transactions initiated in periods beginning on or after July 1, 2005. Retroactive application is prohibited.

Financial Instruments
In April 2005, the AcSB issued three new sections in conjunction with its financial instruments project:

CICA 3855, Financial Instruments – Recognition and Measurement. It prescribes when to recognize a financial instrument on the balance sheet and at what amount—sometimes using fair value; other times using cost-based measures. It also specifies how to present financial instrument gains and losses.
CICA 3865, Hedges. Application of this Section is optional. It provides alternative treatments to CICA 3855 when a company chooses to designate qualifying transactions as hedges for accounting purposes. It replaces the guidance formerly in CICA 1650, Foreign Currency Translation, and Accounting Guideline AcG-13, Hedging Relationships, and prescribes the actual accounting treatment for qualifying hedge relationships and what disclosures are necessary when it is applied.
CICA 1530, Comprehensive Income. This Section introduces new requirements for situations when a company must temporarily present certain gains and losses outside net income.

Transition
We are permitted a “fresh start” in applying the new standards for classification of financial assets and liabilities. Any adjustments to carrying amounts are recognized as adjustments to opening retained earnings or, in the case of assets classified as available for sale or amounts previously deferred in respect of cash flow hedges which will be redesignated as new cash flow hedges, to other comprehensive income.

Changes Introduced by the New Standards
Changes to the Canadian accounting standards include, but are not limited to:

A new definition for derivative which is different from that under U.S. GAAP;
A new categorization for financial instruments;
Derivatives must be recorded on the balance sheet at fair value. Off-balance sheet treatment is no longer allowed;
Use of non-derivative financial instruments as hedging items is restricted to hedges of foreign currency risks. A non-derivative financial instrument was previously allowed to be the hedging item in any hedging relationship;
Method of hedge accounting, which was previously unspecified, is now specified;
Gains and losses resulting from any ineffectiveness in hedging relationships are identified, measured and recognized in income immediately; and
A new location for recognizing certain gains and losses—other comprehensive income—has been introduced. This provides an ability for certain gains and losses arising from changes in fair value to be temporarily recorded outside the income statement, but in a transparent manner.

Canadian-U.S. GAAP/IFRS Differences
The new standards are a hybrid of U.S. GAAP and International Financial Reporting Standards (“IFRS”). Although they close the gap with the U.S. in many respects, they open up differences in other areas.

These new requirements become effective for the interim periods and fiscal years beginning on or after October 1, 2006. Earlier adoption will be permitted only as of the beginning of a fiscal year ending on or after December 31, 2004.

We expect to adopt the new requirements of CICA 3855, 3865 and 1530 beginning in Fiscal 2007.

EIC–159, Accounting for Conditional Asset Retirement Obligations
The AcSB issued EIC-159, based on FASB FIN 47, Accounting for Conditional Asset Retirement Obligations, to provide guidance on when a conditional asset retirement obligation should be recognized in accordance with CICA 3110.

Under EIC-159, an entity should recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. An asset retirement obligation would be reasonably estimable if:

	(a)	It is evident that the fair value of the obligation is embodied in the acquisition price of the asset;

	(b)	An active market exists for the transfer of the obligation; or

	(c)	Sufficient information exists to apply an expected present value technique.

An entity would have sufficient information to apply an expected present value technique, and therefore an asset retirement obligation would be reasonably estimable, if either of the following conditions exists:

(a)	The settlement date and method of settlement for the obligation have been specified by others;

(b)	The information is available to reasonably estimate:

	(i)	The settlement date or the range of potential settlement dates;

	(ii)	The method of settlement or potential methods of settlement;

	(iii)	The probabilities associated with the potential settlement dates and potential methods of settlement.

If sufficient information is not available at the time the liability is incurred, a liability should be recognized initially in the period in which sufficient information becomes available to estimate its fair value, in accordance with CICA 3110.05.

The Abstract should be applied retroactively, with a restatement of prior periods, to all financial statements for annual and interim periods ending after March 31, 2006, although earlier adoption is encouraged. The adoption of this statement has not had a material impact on our results of operations or financial position.

Inflation
We operate in Canada only, where inflation for our operational costs is at low levels, i.e. in the 2%-5% range.

Impact of Foreign Currency Fluctuations
We hold our cash reserves and receive the majority of our revenues in Canadian dollars. We incur the majority of our expenses and capital expenditures also in Canadian dollars. Therefore, an increase or decrease in the value of the Canadian dollar versus the U.S. dollar would have a minimal effect on us.

Government Policies
We are subject to regulations of the Government of Canada and the Governments of Alberta and British Columbia. Such regulations may relate directly and indirectly to our operations including production, marketing and sale of hydrocarbons, royalties, taxation, environmental matters and other factors. There is no assurance that the laws relating to our operations will not change in a manner that may materially and adversely affect us, however, there has been no material impact on us from changes to such laws in the past three fiscal periods.

B. Liquidity and Capital Resources

Sources and Uses of Cash
Our main business strategy is to focus on growth through full-cycle exploration and development. We supplement our main strategy with targeted acquisitions when appropriate. To carry out these capital-intensive strategies, we require operating cash flows and an operating bank line of credit.

Operating activities - In any given year, our operating activities may result in cash flow timing differences where capital expenditures exceed operational cash flows. The two key underlying drivers behind this are volatility in our weighted average commodity prices and timing differences in our operating cash flows arising from the development of longer-term projects.

Historically, cash used for exploration, development and production operations on properties that we acquired (the “Acquired Properties”) pursuant to the Plan of Arrangement was sourced through a revolving, demand operating bank loan and equity financing by Dynamic prior to the Plan of Arrangement. All cash collected by or required by the Acquired Properties was the responsibility of Dynamic Oil & Gas, Inc. and any outstanding operating loan balances were secured by all of Dynamic’s assets. Subsequent to the Plan of Arrangement, we became responsible for our own cash and cash requirements.

The table below shows weighted average prices realized from all of our commodities and reconciles the cash flow timing differences that occurred during the three months ended December 31, 2005, the period during which we became responsible for our own cash and cash requirements. It is not practicable to estimate the cash flow timing differences that we would have reported for the nine months ended September 30, 2005 or for the years ended December 31, 2004 and 2003 had we been a separate, stand-alone company during such periods.

Weighted Average Prices and Cash Flow Information Subsequent to the Plan of Arrangement
	Three Months
	Ended
($ 000’s unless otherwise stated)	Dec 31, 2005
Weighted average prices realized:
Heavy crude oil ($/bbl)	30.33
Natural gas ($/mcf)	11.92
Light/medium crude oil ($/bbl)	59.24
Cash flow timing differences:
Cash used in operating activities⁽¹⁾	(2,124)
Changes in non-cash working capital affecting operating activities	3,006
Capital investment and exploration expenditures	(4,246)
Capital assets	(49)
Total cash timing differences between operating and investing activities	(3,413)
Bank operating indebtedness	-
Issuance of common shares	3,853
Cash received pursuant to the Plan of Arrangement	3,564
Changes in non-cash working capital affecting operating and investing activities	1,827
Cash as at December 31, 2005	5,831

(1)	Included in this amount are payments relating to the lease of our office space (see Note 13 to our Financial Statements).

Financing activities – On October 3, 2005, we closed a private placement resulting in cash proceeds, net of fees and financing costs, of approximately $3.9 million. In exchange for the cash proceeds, we issued 1,666,666 flow-through shares and 1,666,667 non-flow-through shares, all at $1.20 per share (see Note 7 to our Financial Statements for further details). The gross proceeds of the flow-through private placement must be spent by December 31, 2006 on qualifying expenses for exploration-only activities that are specifically defined in the Income Tax Act (Canada). (see Note 7 to our Financial Statements for further details). Renunciation of $2.0 million to flow-through shareholders of Canadian exploration expense occurred on January 19, 2006. Net proceeds of the non-flow-through became general working capital.

On March 17, 2006, we established a revolving, demand bank operating loan facility of $6.5 million with our corporate bank. Principal balances outstanding are charged interest at prime plus 1/2 of a percent and are collateralized by a general assignment of book debts and a floating charge debenture of $20 million covering our major producing reserves. A standby fee of one-eighth of a percent per annum is levied on the unused portion of the facility.

The facility is subject to a periodic review and the maintenance of a working capital ratio greater than one, such ratio to include, as a current asset, the unused portion of the loan. This review will include assessments of our December 31, 2005 reserves and daily production estimates and a full evaluation of our financial position and operations. Our loan agreement contains certain covenants that require prior approval of our bank (e.g. mergers, capital distributions, other pledges of security and asset disposals).

The winter season is often the best time for our drilling activities, therefore, dependence on our borrowing facility may tend to be heavier at those times.

At December 31, 2005, our authorized capital was an unlimited number of Common Shares and Preferred Shares without par value, of which 29,087,612 Common Shares were issued and outstanding, such amount still outstanding at March 17, 2006. Also outstanding were 2,265,000 options at an exercise price of $1.44, each option entitling the holder to acquire one of our Common Shares. The weighted average remaining contractual exercise life of these options was 4.75 years. We have no Preferred Shares outstanding.

Working capital – Changes in our working capital are primarily dependent upon our operating cash flows, the size of our capital investment program, and the timing of incurred field activities.

Our sales receivables and trade payables are typically settled in accordance with normal industry standards and our working capital liquidity during Fiscal 2006 is expected to be maintained by drawing from and repaying our unutilized bank credit facility, as needed. Our December 31, 2005 working capital ratio was 1.3:1, which included certain disputed items in accounts payable and accrued liabilities in favour of one of our joint venture partners. While we believe that the amount we have recorded is sufficient to provide for the eventual resolve of the disputed items, the ultimate settlement of the obligation could result in a material adjustment.

Cash Requirements
Our future liquidity is dependent upon operating cash flows, our capital investment program and the flexibility of capital sources. Changes in our daily average production levels and the weighted average prices we obtain for the sales of our commodities will impact our operating cash flows and the extent to which we may draw from, or have made available to us, bank operating credit.

We may seek equity to fuel accelerated project exploration or acquisition opportunities. In the event the prices of our commodities increase or decrease materially, we may choose to expand or contract our spending plans. Based on our production targets, our forecasts of strong commodity prices, and support from our $6.5 million bank loan facility established on March 17, 2006, we expect to have adequate resources to meet our Fiscal 2006 cash requirements.

Cash Management
As in most upstream oil and gas companies, we manage our cash throughout both increasing and decreasing commodity price cycles. We work toward accomplishing all projects specified in our annual capital investment program budget, however, in the event our commodity prices increase or decrease materially, we may choose to expand or contract our spending plans, as warranted.

Increases or decreases in our capital spending activities may have corresponding effects on our production, net revenues, any established operating loan interest expense and cash taxes, and counter-effects on our amortization and depletion expense.

Outlook for Fiscal 2006
Our planned primary strategy for Fiscal 2006 is to continue to explore and develop our Mantario East property and to enhance production at Cypress/Chowade. Our secondary strategy for maximizing shareholder value is to target strategic acquisitions that would broaden production in Fiscal 2006, subject mostly to timing issues, equipment availability and adequate financing.

Our capital expenditure and exploration expense budget for Fiscal 2006 is $9.0 million. The allocation of the budget is 81% to Saskatchewan and 9% to British Columbia and 10% to properties yet to be allocated later in Fiscal 2006.

Developed Properties (68% of our Fiscal 2006 Capital Investment Program Budget)
In our Fiscal 2006 Capital Investment Program budget, we have allowed for the drilling, completion and equipping of 11 development wells. We have also allowed for other development projects that are designed to add new production and enhance existing production. The expected outcome of the 11 wells has been factored into our 2006 targeted exit production rate.

Our planned Fiscal 2006 drilling and development projects by target, project type and property, accompanied by our expected participating working interests, are as follows:

Development Drilling Wells Planned
Heavy crude oil targets

Mantario East – eight vertical and three horizontal in in-fill wells, each at 75% working interest.

Other Development Projects Planned
Production enhancements

Cypress/Chowade – our 50% share of the cost to enhance natural gas productivity through the addition of new equipment and facility re-organization; and
Mantario East – our 75% share of the cost to construct gas gathering, compression and water disposal facilities.

Undeveloped Properties (22% of our Fiscal 2006 Capital Investment Program Budget)
In our Fiscal 2006 Capital Investment Program budget, we have allowed for the drilling, completion, equipping and tie-in of two development and three exploration wells. The expected outcome of these wells has not been considered in our 2006 target production rate table below.

Our planned Fiscal 2006 projects on undeveloped acreage by target and property, accompanied by our expected participating working interests are as follows:

Development Drilling Wells Planned
Natural gas targets

Mantario East – two Viking formation wells are planned, each at 75% working interest.

Exploratory Drilling Wells Planned
Natural gas targets

Rigel – one vertical well, at 50% working interest.

Heavy crude oil targets

Mantario East – two Viking formation wells are planned, each at 75% working interest.

Other Exploration Projects Planned
Land acquisitions and seismic data activity

Mantario East – an allowance for two sections of land and the acquisition of trade 2D seismic, all at 75% working interest; and
Rigel – an allowance for a 2D seismic shoot to define channel gas, at 40% working interest.

Our Fiscal 2006 targeted exit production rate is 2,000 boe per day, subject to rig availability, drilling successes and the timing of completions and tie-ins. Our targeted exit production rate is comprised of 86% heavy crude oil and 14% sweet natural gas.

Sensitivity Analysis
The following table shows the effect on cash flow of certain changes in volume, price and interest rates. Numbers presented reflect the sensitivity impact on our estimated Fiscal 2006 activity.

Sensitivities
	---------------- Changes in ----------------			Effect on Cash Flow
	Volume	Price	Rate	$(000’s)
Production
Heavy crude oil (bbl/d)	100	-	-	201
Natural gas (mcf/d)	100	-	-	682
Price
Heavy crude oil ($/bbl)	-	0.50	-	169
Natural gas ($/mcf)	-	1.00	-	270
Interest rate (%)	-	-	1	9

C. Research and Development, Patents and Licenses, etc.

We have no material research and development programs, patents and licenses etc.

D. Trend Information

There are a number of trends in the crude oil and natural gas industry that are shaping the near future of the business. The first trend has been the continuation of crude oil and natural gas companies converting to royalty or income trusts. These conversions occur because the equity markets have generally valued trusts at higher multiples than exploration and development firms.

Efforts of trusts to replace annual production declines have resulted in continued high levels of competition for the acquisition of crude oil and natural gas properties and related assets. This increased competition has raised valuation parameters for corporate and asset acquisitions.

Natural gas prices have been somewhat volatile over the past year. With the supply and demand balance for natural gas being tight, the market has experienced volatility in pricing due to a number of factors, including weather, drilling activity, declines, storage levels, fuel switching and demand.

Crude oil prices are clearly dependent upon the world economy and the global supply-demand balance. The current environment of geopolitical unrest has increased prices well above those supported by current supply-demand balances. While pricing in the future may more accurately reflect supply-demand fundamentals, it would appear that the current tight supply environment is highly sensitive to political and terrorist risks as evidenced by the risk premium in the current price structure. The magnitude of this risk premium may change over time.

Although commodity prices are higher than historical levels, the appreciation of the Canadian dollar in 2004 and 2005 relative to its U.S. counterpart has offset a portion of the economic benefit of higher prices on Canadian crude oil and natural gas producers. The strong Canadian dollar may result in decreased revenues in Fiscal 2006 for crude oil and natural gas producers on a per-barrel basis.

E. Off-Balance Sheet Arrangements

As at December 31, 2005, we had no off-balance sheet arrangements.

F. Tabular Disclosure of Contractual Obligations

As at December 31, 2005, we had the following contractual and commercial commitments:

We have an operating lease in respect of our office premises (see Note 13 to our Financial Statements). Additionally, we have asset retirement obligations relating to the clean up and restoration of well, plant and battery sites (see Note 6 to our Financial Statements). The following table shows our obligations and commitments as at December 31, 2005.

Contractual Obligations and Commitments
	Payments or Work Commitments Due by Period
		< 1	1 – 3	4 -5	> 5
($000’s)	Total	Year	Years	Years	Years
Operating lease obligations (office lease)	172	71	101	-	-
Asset retirement obligations ⁽¹⁾	1,660	60	439	452	709
Total	1,832	131	540	452	709

⁽¹⁾	Asset retirement obligations represent estimates of future clean-up and restoration commitments and are undiscounted.

As at December 31, 2005, we recognized $1.2 million of asset retirement obligations on our Balance Sheet. We engage independent engineering consultants to assist in assessing our total asset retirement obligations related to removal and clean-up costs. While we cannot predict their ultimate cost, we currently estimate the undiscounted future cost to clean up all our operating facilities to be $1.7 million.

On October 3, 2005, we completed a private placement that included 1,666,666 flow-through common shares resulting in gross cash proceeds of $2.0 million. Gross proceeds from the flow-through shares will be used to incur qualifying Canadian Exploration Expense (CEE) as defined by the Income Tax Act (Canada). On January 19, 2006, we renounced the tax benefits of the CEE in favor of the original flow-through shareholders in an amount equal to the issue price for each flow-through share. (See Note 13 to our Financial Statements for further details).

G. Safe Harbor

Certain statements in this Registration Statement, including those appearing under this Item 5, constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. Additionally, forward looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us on our behalf. Such statements are generally identifiable by the terminology used such as “plans”, “expects, “estimates”, “budgets”, “intends”, anticipates”, “believes”, “projects”, “indicates”, “targets”, “objective”, “could”, “may” or other similar words.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for natural gas, natural gas liquids and oil products; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdown; actions by governmental authorities including increases in taxes, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; and the other factors discussed in Item 3 Key Information – “Risk Factors”, and in other documents that we file with the United States Securities and Exchange Commission. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors; our course of action would depend upon our assessment of the future considering all information then available. In that regard, any statements as to future natural gas, or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectibility of receivables; availability of trade credit; expected operating costs; expenditures and allowances relating to environmental matters; debt levels; and changes in any of the foregoing are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

Item 6. Directors, Senior Management and Employees

A. Directors and Senior Management

We are managed by our Board of Directors and our executive officers. Since our inception, we have adopted and operated corporate governance structures and mechanisms which have been regularly reviewed to reflect internal corporate developments and national and international best practices.

The following is information regarding our Directors, Senior Management and Employees as of December 31, 2005.

Name	Position Held	Age	Residence
Directors and Executive Officers:
Wayne J. Babcock	President & CEO, Director	62	Vancouver, B.C.
Donald K. Umbach	Vice President & COO, Director	52	Vancouver, B.C.
John A. Greig	Director	64	Vancouver, B.C.
David J. Jennings	Director	42	Vancouver, B.C.
William B. Thompson	Director	61	Kelowna, B.C.
Michael A. Bardell	Chief Financial Officer	59	Vancouver, B.C.
Sharon L. Howatt	Corporate Secretary	40	Vancouver, B.C.

Wayne J. Babcock President, Chief Executive Officer, Director

Mr. Babcock, P. Geoph., holds a degree in Geophysics from the University of British Columbia and joined Amoco Canada Petroleum Company Ltd. in 1966.

Mr. Babcock was a founder and President, Chief Executive Officer and director of Dynamic Oil & Gas, Inc. until September 2005. Before establishing Dynamic Oil & Gas, Inc. in 1979, Mr. Babcock managed Amoco's geophysical exploration of Saskatchewan and Southern Alberta, Canada's western sedimentary basin.

He is a member of the Alberta Association of Professional Engineers, Geologists and Geophysicists, the Canadian Institute of Energy and is on the Board of Directors of Redcorp Ventures Ltd., a Toronto Stock Exchange listed mining company.

Mr. Babcock has been our President, Chief Executive Officer and a director since our inception.

Donald K.
Umbach
Vice President, Chief Operating Officer, Director

Mr. Umbach holds diplomas in Business Administration & Petroleum Land Management from the Mount Royal College of Calgary, Alberta and is a member of the Canadian Association of Petroleum Landmen. He has over 28 years experience in the Canadian oil and gas industry, beginning with Hudson's Bay Oil & Gas Limited, followed by a time with a junior oil and gas company. Prior to joining Shellbridge, Mr. Umbach was a director of Dynamic Oil & Gas, Inc. since 1990 and was Vice

President and Chief Operating Officer of Dynamic Oil & Gas, Inc. from 1999 through 2005. Prior to that, Mr. Umbach was principal of his own Petroleum Landman consulting firm.

Mr. Umbach has been our Vice President and Chief Operating Officer and a director since our inception.

John A. Greig Director

Mr. Greig, M.Sc./P.Geol., holds a B.Sc. (honours) in Geology from McGill University in Montreal and a M.Sc. in Geology from the University of Alberta. He is a member of the British Columbia Association of Professional Engineers and Geoscientists, the Alberta Association of Professional Engineers, Geologists and Geophysicists and the Geological Association of Canada.

Mr. Greig was a director of Dynamic Oil & Gas, Inc. from 1990 to 2005 and is presently a director of Blackstone Ventures Inc., Eurozinc Mining Corp., and Diamondex Resources Ltd. He was a founder or co-founder of various successful mining companies including Sutton Resources Ltd., Eurozinc Mining Corp. and Winspear Resources Ltd.

Mr. Greig has been a director of ours since our inception.

David J.
Jennings
Director

Mr. Jennings is a principal of the law firm Irwin, White & Jennings in Vancouver, Canada and has been such since 1999.

Over the past decade Mr. Jennings has specialized in corporate finance and securities law with several publicly-traded companies. Mr. Jennings' practice includes initial public and additional offerings, debt offerings, venture capital financings, take-over bids and issuer bids, proxy contests, reorganizations, corporate governance matters and related transactions. He specializes in corporate finance and securities law.

Mr. Jennings was the past Chair of the Securities Subsection of the Canadian Bar Association, British Columbia branch, and was a member of the British Columbia Securities Commission Law Advisory Committee. Mr. Jennings has written articles and lectured on the areas of corporate and securities law and venture capital financing. Mr. Jennings received his B.A. from the University of Western Ontario in 1984 and his J.D. from the University of Toronto in 1988. Mr. Jennings was a director of Dynamic Oil & Gas, Inc. from 1999 through 2005.

Mr. Jennings has been a director of ours since our inception.

William B. Thompson
Director

Mr. Thompson holds a B.Sc. in physics from the University of British Columbia and is a graduate of the Stanford Executive Program. He is a member in good standing of the Professional Engineers Geologists and Geophysicists Associations of Alberta and British Columbia.

Mr. Thompson has a distinguished background in Western Canada’s oil and natural gas industry. From 1967 to 1976, Mr. Thompson worked as a district geophysicist headquartered at the Calgary and Houston offices of Amoco. During the next twenty-four years, he held numerous senior executive responsibilities for Petro-Canada of Calgary, Alberta, including the positions of vice-president Provincial and Frontier Exploration, and vice-president Business Analysis and Support Services.

In 1989, Mr. Thompson served on the Executive Committee of the Canadian Petroleum Association and for the four-year period ending 1992, he served as a director of PanArctic Oil Limited. From 1985 to 1990 he served as a director, and in 1989 he was chairman of the British Columbia Division of the Canadian Petroleum Association. Mr. Thompson was a director of Dynamic Oil & Gas, Inc. from 2002 through 2005.

Mr. Thompson has been a director of ours since our inception.

Michael A.
Bardell
Chief Financial Officer

Mr. Bardell holds a diploma in finance and accounting and has over 31 years experience developing and directing financial, informational reporting and money management systems. Beginning his career with Hudson's Bay Oil and Gas, he later held senior management positions in junior oil and gas companies, and in the drilling service industry.

Before joining the Company, he was controller for one of the world's largest sulphur marketing consortiums consisting of 28 major energy companies including Gulf Canada, Chevron Canada, Canadian Occidental and Union Oil.

Mr. Bardell was controller from 1988 to 1999 and Chief Financial Officer from 1999 to 2005 of Dynamic Oil & Gas, Inc. Mr. Bardell has been our Chief Financial Officer since our inception.

Mr. Bardell is a member of Financial Executives International.

Sharon L.
Howatt
Corporate
Secretary

Ms. Howatt has over 20 years experience as a legal assistant in the fields of corporate finance, governance and securities laws. Ms. Howatt started her career working in laws firms and, over the past 10 years, has been working for public companies holding legal assistant and corporate officer positions. Sharon was the Assistant Corporate Secretary for Dynamic Oil & Gas, Inc. from 2003 to 2005.

Ms. Howatt has been our Corporate Secretary since our inception.

None of our directors, officers or employees has any family relationship with one another. To the best of our knowledge, there are no arrangements or understandings with major shareholders, customers, suppliers or others, pursuant to which any person referred to above was selected as a director or member of senior management.

Our non-employee directors do not have service contracts or any agreement providing for benefits on termination of employment.

Messrs. Babcock and Umbach, both of which are employee-directors have employment agreements with us providing that they may receive a severance package including an amount equal to 24 months salary, the economic benefit of any stock options then outstanding, and certain health and insurance benefits for a period not to exceed six months upon termination of their employment.

          B.      Compensation
          Total Compensation Paid, and Benefits Granted to Named Executive Officers and Directors
          The following table sets forth all annual and long-term compensation for services in all capacities subsequent to the Plan of Arrangement in Fiscal 2005 for our Chief Executive Officer and our other four most highly compensated executive officers whose individual total compensation for Fiscal 2005 exceeded $100,000 and any individual who would have satisfied these criteria but for the fact that the individual was not serving as an officer at the end of Fiscal 2005 (collectively “the Named Executive Officers”). The information is presented in accordance with applicable Canadian and U.S. regulations regarding reporting financial information on individual persons. The information provided is based on the period from our commencement of operations through December 31, 2005.

Named Executive Officers
			Other Annual	Options	Exercise
	Salary ⁽¹⁾	Bonus	Compensation ⁽²⁾	Granted ⁽³⁾	Price
Name/Position	($)	($)	($)	(#)	($)	Expiry Date

Wayne J. Babcock
President & CEO	29,400	Nil	460	300,000	$1.44	October 17, 2010

Donald K. Umbach
Vice President & COO	29,400	Nil	460	300,000	$1.44	October 17, 2010

Michael A. Bardell
Chief Financial Officer	29,400	Nil	460	200,000	$1.44	October 17, 2010

(1)	$117,600 on an annualized basis. Subsequent to the Plan of Arrangement, salaries of the named executive officers were significantly reduced from those paid by Dynamic, therefore not applicable to us.
(2)	The Other Annual Compensation paid during reporting periods is in respect to life insurance premiums paid on behalf of the executive officer during the reporting period ($1,840 on an annualized basis).
(3)	We have a formalized stock option plan for the discretionary granting to the Named Executive Officers of incentive stock options that are exercisable for shares of our Common Stock.

Subsequent to the Plan of Arrangement in Fiscal 2005, we paid cash compensation to our named executive officers in the aggregate sum of $89,580.

Subsequent to the Plan of Arrangement in Fiscal 2005, we had no compensatory plan or arrangement in respect of compensation received or that may be received by the Named Executive Officers to compensate Named Executive Officers in the event of the termination of employment (resignation, retirement, change of control) or in the event of a change in responsibilities following a change in control, where in respect of the Named Executive Officer the value of such compensation exceeds $100,000, a threshold required by Canadian securities regulations.

The following table sets forth all compensation for services in all capacities to us subsequent to the Plan of Arrangement in Fiscal 2005 with respect to each of the non-employee directors. None of our directors have service contracts with the company relating to their serving as a director, and none of the directors will receive benefits upon termination of their position as a director.

Compensation of Non-Employee Directors
			Other Annual	Options	Exercise
Name/Position	Salary ⁽¹⁾	Bonus	Compensation	Granted (#) ⁽²⁾	Price	Expiry Date
John A. Greig	Nil	Nil	Nil	200,000	$1.44	Oct 17, 2010

David J. Jennings ⁽³⁾	Nil	Nil	Nil	175,000	$1.44	Oct 17, 2010

William B. Thompson	Nil	Nil	Nil	200,000	$1.44	Oct 17, 2010

(1)	Subsequent to the Plan of Arrangement in Fiscal 2005, we did not pay any cash compensation to our directors (employee and non-employee), in their capacities as such.
(2)	We have a formalized stock option plan for the non-discretionary, automatic granting of incentive stock options to independent directors that are exercisable for shares of our Common Stock. All such grantings are allocated at the time of the director’s first election or annually based on the director’s participation as a standing committee chair or member. The options indicated above were granted pursuant to that plan.
(3)	Mr. Jennings performs legal work on our behalf as a Barrister and Solicitor with the firm of Irwin, White & Jennings. Irwin, White & Jennings did not bill us any legal fees subsequent to the Plan of Arrangement in Fiscal 2005.

Non-Cash Compensation to Directors, Officers and Employees
We have a formalized incentive stock option plan for our directors, officers and employees. The purpose of such options is to assist us in compensating, attracting, motivating and retaining those persons and to closely align the personal interests of such persons to that of our shareholders. The number of shares subject to such plan at any particular time is equivalent to 10% of our issued and outstanding shares.

The following table shows the number of shares of Common Stock subject to outstanding stock options held by our directors and officers, as a group as of March 31, 2006.

Stock Options Outstanding as of March 31, 2006
(Directors/Officers, as a group)
		Number of Shares
		of
Expiry Date	Exercise Price	Common Stock
October 17, 2010	$1.44	1,450,000

The following table shows the number of shares of Common Stock subject to outstanding stock options held by employees and consultants who are neither our directors nor officers as of March 31, 2006.

Stock Options Outstanding as of March 31, 2006
(Non-Directors/Non-Officers)
		Number of Shares
		of
Expiry Date	Exercise Price	Common Stock
October 17, 2010	$1.44	815,000

Stock Options Granted to and Exercised by Named Executive Officers
Subsequent to the Plan of Arrangement in Fiscal 2005 there were a total of 800,000 options granted to the Named Executive Officers as a group.

Subsequent to the Plan of Arrangement in Fiscal 2005, there were no options exercised by named executive officers, employee directors and non-employee directors.

The following table sets forth details of the number of stock options held as of March 31, 2006 by each of the Named Executive Officers. The table also sets forth the March 31, 2006 value of unexercised in-the-money options on an aggregated basis. We have no stock appreciation rights outstanding.

Stock Options Held by Named ExecutiveOfficers
		Dollar Value of Unexercised In-the-
	Number of Unexercised Options	Money Options Held At
	Held At March 31, 2006	March 31, 2006⁽¹⁾
Name	Exercisable / Unexercisable	Exercisable / Unexercisable
Wayne J. Babcock	127,778/172,222	$67,722/$91,278
Donald K. Umbach	127,778/172,222	$67,722/$91,278
Michael A. Bardell	27,778/172,222	$14,722/$91,278

⁽¹⁾	Value of unexercised in-the-money options calculated using the closing price of our shares of Common Stock on the Toronto Stock Exchange on March 31, 2006 ($1.97), less the exercise price of in-the-money stock options.

Options
Subsequent to the Plan of Arrangement in Fiscal 2005, members of the Compensation Committee recommended, and the Board of Directors approved, the granting of 2,265,000 options to our employees.

The maximum number of options under the 2005 Incentive Stock Option Plan available to any one eligible director, officer or employee is 5% of our outstanding shares. The number of shares subject to the 2005 Incentive Stock Option Plan at any particular time is based on a rolling 10% of our total issued and outstanding shares of Common Stock. As of March 31, 2006, there were an aggregate of 2,265,000 shares subject to outstanding stock option grants and 10% of our total issued and outstanding shares of Common Stock as of that date was 2,908,761.

C. Board Practices

Term of Office
At the end of Fiscal 2005, we had five directors. The terms of all five expire at the annual meeting of shareholders:

Name	Term of Office Remaining	Held Office Since
Wayne J. Babcock	one year	2005
Donald K. Umbach	one year	2005
John Grieg	one year	2005
David J. Jennings	one year	2005
William B. Thompson	one year	2005

Our executive officers are not appointed by the Board of Directors for any specific term but serve until they resign, their successor is duly elected and qualified, or they are removed from office or otherwise disqualified from service as one of our officers.

Committees: Audit, Audit Reserves, Compensation and Corporate Governance
The following table sets forth details relating to the composition of our Board Committees as of the end of Fiscal 2005.

List of Directors, Committees and Committee Members
		Corporate		Reserves
	Full Board	Governance	Compensation	Audit	Audit
Non-Employee Directors
John Greig	x	x	x	x	Chair
David Jennings	x	Chair	Chair		x
Bill Thompson	x	x	x	Chair	x

Employee Directors
Wayne Babcock	Chair
Don Umbach	x

Audit Committee - the Audit Committee is mandated to:

assist the Board of Directors in fulfilling its fiduciary responsibilities relating to accounting and reporting practices and internal controls;
Review audited financial statements and management’s discussion and analysis of operations with the auditors;
Review the annual report and all interim reports with the auditors;
ensure that no restrictions are placed by management on the scope of the auditor's review and examination of our accounts; and
recommend to the Board of Directors the firm of auditors to be nominated by the Board of Directors for appointment by the shareholders at the annual general meeting.

Reserves Audit Committee - the Reserves Audit Committee is mandated to:

assist the Board of Directors in fulfilling its oversight responsibilities with respect to our annual reserves estimates;
recommend to the Board of Directors for appointment, the firm of independent qualified engineers to evaluate our annual reserves;
examine the work scope, information access, resolved opinion differences and determine the independence of the independent engineering firm; and
review the annual estimated reserves as prepared by the independent engineers.

Corporate Governance Committee – the Corporate Governance Committee is mandated to deal generally with corporate governance obligations and opportunities presented to us. It has prepared written mandates that define the stewardship responsibilities of the Board of Directors and its committees, implemented a risk management system, and ensured that effective communications systems are in place among the Company, its shareholders and the public. As well, the Corporate Governance Committee recommends nominees for the Board of Directors, and oversees the effective functioning of the Board of Directors and its relationship with management. In all activities the Corporate Governance Committee adheres to Canadian and U.S. statutory obligations to ensure we are in compliance with all applicable laws.

Compensation Committee - the Compensation Committee is mandated to consider and make recommendations to the Board of Directors for appropriate compensation packages for our executive officers and directors. The guiding philosophy of the Compensation Committee in determining compensation for executives has been to provide a compensation package that is flexible, entrepreneurial and geared towards attracting, retaining and motivating executive officers. The policies of the Compensation Committee encourage performance by executives to enhance our growth and profitability. Achievement of these objectives is intended to contribute to an increase in shareholder value.

The Compensation Committee has approved the salaries of senior management and noted that the salary levels for these individuals are on the low end of salaries for executives in comparable positions in the peer group of oil and gas exploration and development companies. There are discretionary bonus provisions in the management contracts for senior management. However, no bonuses have been awarded as of the date hereof.

The Committee considers it prudent to ensure that remuneration arrangements for key executives are competitive with the Corporation’s peers and to include an element of reward when warranted to reflect above-average performance.

The Compensation Committee resolved that, consistent with the peer group of companies, all of the Named Executive Officers would be eligible for discretionary stock option participation.

Indebtedness and Material Interest of Committee Members
Our Board of Directors is composed of five directors. None of the members of the Audit, Audit Reserves, Compensation and Corporate Governance Committees has any indebtedness to us nor does any have any material interest, or have any associates or affiliates that have any material interest, direct or indirect, in any actual or proposed transaction in the last fiscal year that has materially affected or would materially affect us. Additionally, no employee directors serve on any of our Board committees.

D. Employees

As of December 31, 2005, we employed 15 people full time in our Richmond, British Columbia office. The persons employed are the President & CEO, the Vice President & COO, and the Chief Financial Officer and 12 persons in technical support, company and joint venture accounting, financial reporting, office management and land administration. None of our employees are related.

In addition to the foregoing, we also receive technical services from a number of exploration, geophysical, geological, engineering, accounting and legal consultants.

E. Share Ownership

The following table sets forth the Common Stock ownership of each of our directors and officers. All ownership shown is of record and reflects beneficial ownership as of March 31, 2006, and represents the number of shares of Common Stock beneficially owned, directly or indirectly, or controlled by the person listed. Unless otherwise indicated, such shares are held directly.

Beneficial Share Ownership of Directors and Officers
		Number of Shares of		Percent of
Name	Position	Common Stock ⁽¹	⁾	Class
Wayne J. Babcock	President & CEO, Director	1,614,580		5.55%
Donald K. Umbach	Vice President & COO, Director	900,227		3.09%
John A. Greig	Director	528,577		1.82%
David J. Jennings	Director	245,000		*
William B. Thompson	Director	300,000		1.03%
Michael A. Bardell	Chief Financial Officer	410,563	⁽²⁾	1.41%
Sharon L. Howatt	Corporate Secretary	19,583		*

(1)	Includes options exercisable within 60 days of March 31, 2006.

(2)	Includes 20,500 shares owned by spouse.

*	Less than 1%.

Item 7. Major Shareholders and Related Party Transactions

A. Major Shareholders

To the best of our knowledge, no person beneficially owns, directly or indirectly, or exercises control or direction over shares constituting more than five percent of the voting rights of our shares, other than our President and CEO, Wayne Babcock, who beneficially owns approximately 5.55% of our outstanding shares. Mr. Babcock’s ownership as of March 31, 2006 is set forth below:

Name	Number of Shares	Percentage
Wayne Babcock	1,614,580 ⁽¹⁾	5.55%

(1)	Includes options exercisable within 60 days of March 31, 2006.

All of our outstanding shares are Common Stock without par value, each possessing equal voting rights. Mr. Babcock obtained his beneficial ownership through a combination of the Plan of Arrangement, participating in the Private Placement that closed on October 3, 2005 and option grants.

As of March 31, 2006, we had 29,087,612 shares of Common Stock outstanding. We have approximately 699 holders of record.

B. Related Party Transactions

Except as follows, none of our officers, directors or persons owning at least five percent of our outstanding securities, or affiliate thereof, has or has had any material interest, directly or indirectly, in any transaction involving us since our incorporation, or in any proposed transaction involving us.

The following officers, directors and employees participated in our initial private placement that closed on October 3, 2005 in which we issued 1,666,666 flow-through common shares. Of the total number of flow-through common shares issued, the directors and officers in the following list purchased 595,168 flow-through common shares (34% of the total issued). All shares purchased by these persons were on the same terms and conditions as all other participants in the private placement.

Name	Number of Shares Purchased		Aggregate Purchase Price
Wayne Babcock	162,084		194,500
Michael Bardell	83,000	⁽¹⁾	99,600
Donald Umbach	162,084		194,500
Sharon Howatt	5,000		6,000
David Jennings	25,000		30,000

John Greig		83,000			99,600
William Thompson		75,000			90,000

(1)

Includes 20,500 shares purchased by spouse.

C. Interests of Experts and Counsel – N/A

Item 8. Financial Information

A. Financial Statements and Other Financial Information

Financial statements are provided under Item 17.

Legal or Arbitration Proceedings
As of the date of this Registration Statement, we are not a party to any active or pending legal proceedings initiated by us, to the best of our knowledge, we are not subject to any active or pending legal proceedings or claims against us or any of our properties. However, from time to time, we may be subject to claims and litigation generally associated with any business venture. Additionally, our operations are subject to risks of accident and injury, possible violations of environmental and other regulations, and claims associated with the risks of exploration operations some of which cannot be covered by insurance or other risk reduction strategies.

Since we are a Canadian corporation and our officers, directors and certain of our professional advisors are resident in Canada, it may be difficult to effect service within the United States upon such persons or to realize on any judgment by a court in the United States which is predicated on civil liabilities under the Securities Act of 1933, as amended (1933 Act). Our Canadian counsel has advised that there is doubt as to the enforceability in Canada, either in original actions or through enforcement of United States judgments, of liabilities predicated solely upon violations of the 1933 Act or the rules and regulations promulgated thereunder.

Dividend Policy
We have not paid any cash dividends on our Common Stock and have no present intention of paying dividends. Our current policy is to retain earnings, if any, for use in operations and in business development.

B. Significant Changes

On March 17, 2006, we established a revolving, demand credit facility with National Bank of Canada. The facility makes available to us up to $6,500,000. Outstanding principal balances bear interest at prime plus ½% (bank prime at March 17, 2006 was 5.50%) . The credit facility is subject to periodic review and is collateralized by a general assignment of book debts and a floating charge debenture of $20,000,000 covering all of our assets. We must also maintain a working capital ratio greater than 1.0, to include as a current asset, the undrawn credit available to us. A standby fee of 0.125% is levied on the unused portion of the facility.

Item 9. The Offer and Listing

A. Offer and Listing Details – Not Applicable

B. Plan of Distribution – Not Applicable

C. Markets

Our shares of Common Stock are traded in Canada on the Toronto Stock Exchange (“TSX”) under the symbol “SHB”. We currently have no established market for trading our shares in the United States.

As of March 31, 2006, we had 29,087,612 shares of Common Stock outstanding. At that date, we estimate 54 shareholders of record resident in Canada holding 15,405,761 shares of common stock and 644 shareholders of record resident in the United States holding 13,676,650 shares of Common Stock. Our shares of Common Stock are issued in registered form and the number of shares of Common Stock reported to be held by record holders in Canada and the United States is taken from the records of The CIBC Mellon Trust Company, the registrar and transfer agent for our shares of Common Stock. For U.S. reporting purposes, we are a foreign private issuer.

The high and low prices for our Common Stock from October 31, 2005, the commencement of trading on the TSX through December 31, 2005 are as follows:

	TSX (in Cdn $)
	High	Low
Oct 31 to Dec 31, 2005	1.85	1.10

The high and low prices for our common stock for each quarter from our inception through December 31, 2005 on the TSX are as follows:

Prices of Common Stock	TSX (in Cdn $)
	High	Low
Oct 1 to Dec 31, 2005	1.85	1.10

The high and low prices for our common stock for the most recent six months on the TSX are as follows:

	TSX (in Cdn $)
Month/Year	High	Low
Mar/2006	2.05	1.47
Feb/2006	1.75	1.35
Jan/2006	1.70	1.35
Dec/2005	1.65	1.15
Nov/2005	1.43	1.10
Oct/2005	1.85	1.30

D. Selling Shareholders – Not Applicable

E. Dilution – Not Applicable

F. Expenses of the Issue – Not Applicable

Item 10. Additional Information

A. Share Capital

Our share capital consists of an unlimited number of authorized shares of Common and Preferred Stock without par value. Our issued capital as of December 31, 2005 and March 31, 2006 is 29,087,612 fully paid shares of Common Stock. All shares were fully paid. Of our total Common Stock, 25,754,278 were issued to our shareholders as part of the Plan of Arrangement. We currently have no treasury shares. As of March 31, 2006, we have 2,908,761 shares of our Common Stock reserved for issuance upon exercise of options under our 2005 Incentive Stock Option Plan with 2,265,000 options outstanding.

	Number of Shares of Common	Description of Issuance of Shares	Total Number of Shares
Date of Issuance	Stock Issued	of Common Stock	Outstanding
Quarter ended	3,333,333	• 3,333,333 shares pursuant to a	29,087,612
December 31, 2005		private placement at $1.20 per share

Quarter ended	25,754,278	• 25,754,278 shares pursuant to	25,754,279
September 30, 2005		the Plan of Arrangement valued
		at $1.20 per share

	1	• Issued to Dynamic Oil & Gas,	1
		Inc. to create wholly-owned
		subsidiary

B. Memorandum and Articles of Association

Articles of Incorporation
The following describes certain terms and provisions of our Articles of Incorporation filed under the Business Corporations Act (Alberta) Canada on July 7, 2005, as amended.

Authorized Capital – Section 2 provides that we have an unlimited number of shares of Common and Preferred Stock each without par value authorized.

Nature of our Business – Section 5 provides that we are not limited to engaging in any particular business.

Number of Directors – Section 4 provides that we may have a minimum of one and a maximum of fifteen directors.

Payment of Dividends – Section 6 holders of our Common Stock are entitled to receive dividends, if, as and when declared by our Board of Directors out of legally available assets.

Participation upon Liquidation, Dissolution or Winding Up – Section 6 provides that in the event of our liquidation, dissolution or winding up or other distribution of our assets among our shareholders for purpose of winding up our affairs, holders of our Common Stock will, subject to the rights of any other class of shares entitled to receive priority on distributions, be entitled to participate in the distribution. Such distribution will be made in equal amounts per share on all Common Stock at the time outstanding without preference or distinction.

Voting Rights – Section 6 provides that holders of our Common Stock are entitled to receive notice of and to attend all annual and special meetings of our shareholders and to vote one (1) vote in respect of each share of Common Stock held at all meetings.

Rights, Preferences and Privileges – Section 6 provides that the rights, privileges, restrictions and conditions attaching to our preferred shares, none of which are outstanding, are as follows:

Series – At any time, our Board of Directors may approve the issuance of preferred shares in one or more series, in such number and with such rights, privileges, restrictions and conditions attaching to such shares as the Board of Directors designates.

Priority – preferred shares have priority over Common Stock and all other shares ranking junior to preferred shares with respect to payment of dividends and distribution of our assets in the event that we liquidate, dissolve or wind up or otherwise distribute our assets among our shareholders to wind up our affairs. Additionally, in such events, the preferred shares rank on parity with preferred shares of every other series with respect to priority of payment of dividends and distributions.

Bylaws
The following describes certain terms and provisions of our Bylaws adopted July 15, 2005.

Calling of and Notice of Directors Meetings – Section 1 provides that board meetings shall be held at such place and time and on such day as the chairman of the board, president or a vice-president, if any, or any two directors may determine. Notice of board meetings must be given to each director not less than 48 hours before the time the meeting is to be held. Each newly elected board may without notice hold its first meeting for the purposes of organization and the appointment of officers immediately following the shareholders’ meeting at which the board was elected.

Votes to Govern – Section 2 provides that at all board meetings, every question must be decided by a majority of the votes casts on the question; and in case of equality of votes the chairman of the meeting shall not be entitled to a second or casting vote.

Interest of Directors and Officers Generally in Contracts – Section 3 provides that no director or officer shall be disqualified by his office from contracting with us nor will any contract or arrangement entered into by us or on our behalf with any director or officer or in which any director or officer is in any way interested be voidable nor will any such officer or director be liable to us for profits realized under such contract or arrangement by reason of such director or officer holding that office or of the fiduciary relationship established; provided that the director or officer has complied with the provisions of the Business Corporations Acct (Alberta).

Quorum of Shareholders’ Meetings – Section 4 provides that at any shareholders’ meeting, a quorum shall be one person present in person entitled to vote and holding or representing or representing by proxy not less than 10% of the votes entitled to be cast at such meeting.

Telephonic Meetings – Section 5 provides that a director may participate in a board or committee meeting and a shareholder may participate in a shareholders’ meeting by means of telephone or other communication facilities that permit all persons participating in any such meeting to hear each other.

Indemnification of Directors and Officers – Section 6 provides that we indemnify directors and officers (including former directors and officers) to the extent provided by the Business Corporations Act (Alberta).

Indemnity of Others – Section 7 provides that except as otherwise required by the Business Corporations Act (Alberta) and subject to Section 6, we may from time to time indemnify any person who was or is a party or is threatened to be a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by us or in our right) by reason of the fact that he is or was our employee or agent, or is or was serving at the request of one of our directors, officers, employees or agents, against expenses (including legal fees), judgments, fines and any amount actually and reasonably incurred by him inn connection with such action, suit or proceeding if he acted honestly and in good faith with a view to our best interests and with respect to any criminal or administrative action or proceeding that is enforced by monetary penalty, had reasonable grounds for believing his conduct was lawful. The termination of any action, suit or proceeding by judgment, order, settlement or conviction shall not, of itself, create a presumption that the person did not act honestly and in good faith with a view to our best interests and, with respect to any criminal or administrative action or proceeding that is enforced by a monetary penalty, had no reasonable grounds for believing that his conduct was lawful.

Right of Indemnity Not Exclusive – Section 8 provides that Sections 6 and 7 regarding indemnification are not exclusive of any other rights to which any person seeking indemnification may be entitled under any agreement, vote of the shareholders of directors or otherwise.

Limitation or Exclusion of Liability – Section 9 provides that to the extent permitted by law, no director or officer shall be liable for acts, receipts, neglects or defaults of any other director or officer or employee or for joining in any receipt or act of conformity or for any loss, damage or expense happening to us in a variety of circumstances.

Execution of Instruments – Section 11 provides that written contracts, documents or instruments requiring execution by us may be signed by any one officer or director, and all written contracts, documents or instruments so signed shall bind us without any further authorization or formality. Our Board of Directors is authorized to resolve to appoint any officer or officers or other persons on our behalf to sign and deliver written contracts, documents or instruments.

Voting Rights in Other Corporations – Section 12 provides that our signing officers may execute and deliver proxies and arrange for the issuance of voting certificates or other evidence of the right to exercise the voting rights attached to any securities we hold. Our Board of Directors may direct the manner in which such votes are exercised.

Limitations on rights to own securities of the Company
Except as provided in the Investment Canada Act (the "Act"), enacted on June 20, 1985, as amended, as further amended by the North American Free Trade Agreement (NAFTA) Implementation Act (Canada) and the World Trade Organization (WTO) Agreement Implementation Act, there are no limitations under the laws of Canada, the Province of British Columbia or in the charter or any other of our constituent documents on the right of non-Canadians to hold and/or vote the Common Stock.

The Act requires a non-Canadian who is a WTO investor (defined below) making a direct acquisition of control of a Canadian business with assets of $250 million or more (for 2006), to file an application for review with Investment Canada, a federal agency created by the Act. At present we would constitute a Canadian business under the Act, although at present our asset value does not exceed the $250 million threshold. Under the Act, control of a corporation is deemed to be acquired through the acquisition of a majority of the voting shares of a corporation, and is presumed to be acquired where one-third or more, but less than a majority, of the voting shares of a corporation are acquired, unless it can be established that the Company is not controlled in fact through the ownership of voting shares.

If the non-Canadian investor is not a WTO investor, additional types of indirect acquisitions are reviewable and the financial thresholds for reviews are significantly less. As well, if a Canadian business is involved in cultural businesses, financial services, uranium or transportation services, the financial thresholds for reviews are significantly less. We are engaged in none of those businesses.

For the purposes of determining who is a “WTO investor” when an acquisition of a Canadian business occurs, the Act provides a definition that includes: an individual who is a national or a lawful permanent resident of a state that is a member of the World Trade Organization (“WTO”) (which includes the United States of America and an additional 147 member states); a government or government agency of a WTO state; an entity that is controlled by a WTO investor-controlled entity (other than a Canadian–controlled entity); and a corporation, limited partnership or trust which is not a Canadian-controlled entity of which two-thirds of its Board of Directors, general partners or trustees, as the case may be, are Canadian or WTO investors.

If a review occurs and the Minister responsible for Investment Canada is not satisfied that the investment is likely to be a net benefit to Canada, the non-Canadian shall not implement the investment or, if the investment has been implemented, shall divest himself of control of the business that is the subject of the investment.

A non-Canadian making (i) an investment to establish a new Canadian business or (ii) an investment to acquire control of a Canadian business which is not subject to review under the Act, must notify Investment Canada, before the investment is completed or within 30 days afterward, of such investment. It is intended that investments requiring only notification will proceed without government intervention unless the investment is in a specific type of business activity related to Canada's cultural heritage or national identity.

Provisions of our Notice of Articles or Articles that have the effect of delaying, deferring or preventing a change in control of us and that would operate only with respect to a merger, acquisition, or corporate restructuring involving us.

There are no such limitations in our Notice of Articles or Articles. However, all of our executive officers have contractual rights under employment agreements to have their stock options vest immediately and obtain 12 to 18 months severance pay in the event of a change of control of our company.

As well, under Alberta corporate legislation, some business combinations, including a merger or reorganization or the sale, lease or other disposition of all or a substantial part of our assets, must be approved by at a special resolution of

shareholders, which is set in our Articles to be at least three-quarters of the votes cast by our shareholders or, in some cases, holders of each class of shares. In some cases, a business combination must be approved by a court. Shareholders may also have a right to dissent from the transaction, in which case, we would be required to pay dissenting shareholders the fair value of their common shares provided they have followed the required procedures.

Provisions of our Notice of Articles or Articles governing the ownership threshold above which shareholder ownership must be disclosed

There are no such provisions in our Notice of Articles or Articles.

Significant differences between law applicable to us and law of the United States with respect to the matters addressed above in this Item 10.

Canadian securities legislation provides that a person that has direct or indirect beneficial ownership of, control or direction over, or a combination of direct or indirect beneficial ownership of, and of control or direction over, securities of the issuer carrying more than 10% of the voting rights attached to all the issuer’s outstanding voting securities must, within 10 days of becoming an “insider”, file an insider report in the required form effective the date on which the person became an insider, disclosing any direct or indirect beneficial ownership of, or control or direction over, securities of the reporting issuer. Canadian securities legislation also provides for the filing of a report by an “insider” of a reporting issuer who acquires or transfers securities of the issuer. This insider report must be filed within 10 days after the end of the month in which the change takes place.

The U.S. rules governing the ownership threshold above which shareholder ownership must be disclosed are more stringent than those under Canadian securities legislation. Section 13 of the Exchange Act imposes reporting requirements on persons who acquire beneficial ownership (as such term is defined in the Rule 13d-3 under the Exchange Act) of more than 5% of a class of an equity security registered under Section 12 of the Exchange Act. In general, such persons must file, within 10 days after such acquisition, a report of beneficial ownership with the SEC containing the information prescribed by the regulations under Section 13 of the Exchange Act. This information is also required to be sent to the issuer of the securities and to each exchange where the securities are traded.

C. Material Contracts and Agreements

On October 3, 2005, we closed a bought-deal private placement. Pursuant to the terms of the placement, we issued 3,333,333 shares of our Common Stock, of which 1,666,666 were sold on a flow-through basis. Such shares were issued at $1.20 per share with aggregate gross proceeds of $4,000,000. Please also see Item 7 “Major Shareholders and Related Party Transactions – Related Party Transactions”.

Arrangement Agreement (including exhibits) dated July 20, 2005, among us, Dynamic Oil & Gas, Inc. and Sequoia Oil & Gas Trust, and others, pursuant to which the shareholders of Dynamic Oil & Gas, Inc. exchanged their shares for cash from Sequoia Oil & Gas Trust and shares of our common stock.

Oil & Gas Purchase Agreement dated July 20, 2005, between us and Dynamic Oil & Gas, Inc. whereby we purchased Dynamic Oil & Gas, Inc.’s right, title and interest in certain oil and gas assets.

          Employment Agreement dated January 26, 2006 between us and Wayne Babcock.
          Employment Agreement dated January 26, 2006 between us and Don Umbach.
          Employment Agreement dated January 26, 2006 between us and Michael Bardell.
          2005 Incentive Stock Option Plan.

D. Exchange Controls

U.S. shareholders may experience impediments to the enforcement of civil liabilities in the United States against foreign persons such as an officer, director or expert acting on our behalf in Canada. Such difficulty arises out of the uncertainty as to whether a court in the United States would have jurisdiction over a foreign person in the United States, whether a U.S. judgment is enforceable under Canadian law and whether suits under federal securities laws could initially be brought in Canada.

There are no governmental laws, decrees, or regulations in Canada that restrict the export or import of capital or that affect the remittance of dividends, interest, or other payments to nonresident holders of the Common Stock. However, any

such remittance to a non-corporate resident of the United States may be subject to a 15% withholding tax pursuant to Article XI of the reciprocal tax treaty between Canada and the United States.

Except as provided in the Investment Canada Act (the "Act"), enacted on June 20, 1985, as amended, as further amended by the North American Free Trade Agreement (NAFTA) Implementation Act (Canada) and the World Trade Organization (WTO) Agreement Implementation Act, there are no limitations under the laws of Canada, the Province of British Columbia or in the charter or any other of our constituent documents on the right of non-Canadians to hold and/or vote the Common Stock (see further comments under Item 10 – “Limitations on rights to own securities of the Company”).

E. Taxation

The following paragraphs set forth certain United States and Canadian federal income tax considerations in connection with the payment of dividends on and purchase or sale of our shares of Common Stock. The tax considerations are stated in general terms and are not intended to be advice to any particular shareholder. Each prospective investor is urged to consult his or her own tax advisor regarding the tax consequences of his or her purchase, ownership and disposition of shares of Common Stock.

The discussion set forth below is based upon the provisions of the Income Tax Act (Canada) (the "Tax Act"), the Internal Revenue Code of 1986, as amended (the "Code") and the Convention between Canada and the United States of America with respect to Taxes on Income and on Capital (the "Convention"), as well as United States Treasury regulations and rulings and judicial decisions. Except as otherwise specifically stated, the following discussion does not take into account or anticipate any changes to such laws, whether by legislative action or judicial decision. The discussion does not take into account the provincial tax laws of Canada or the tax laws of the various state and local jurisdictions in the United States.

Canadian Federal Income Tax Considerations
The following discussion applies only to citizens and residents of the United States and United States corporations who are not resident in Canada and will not be resident in Canada and who do not use or hold nor are deemed to use or hold such shares of Common Stock in carrying on a business in Canada.

The payment of cash dividends and stock dividends on the shares of Common Stock will generally be subject to Canadian withholding tax. The rate of the withholding tax will be 25% or such lesser amount as may be provided by treaty between Canada and the country of residence of the recipient. Under the Convention, the withholding tax generally would be reduced to 15%.

Neither Canada nor any province thereof currently imposes any estate taxes or succession duties. Provided a holder of shares of Common Stock has not, within the preceding five years, owned (either alone or together with persons with whom he or she does not deal at arm's length) 25% or more of the shares of Common Stock, the disposition (or deemed disposition arising on death) of such shares of Common Stock will not be subject to the capital gains provisions of the Tax Act.

United States Federal Income Tax Considerations
The following discussion is addressed to US holders. As used in this section, the term "US holder" means a holder that is (1) an individual citizen or resident of the United States, (2) a corporation, partnership or other entity created or organized in or under the laws of the United States or any political subdivision thereof, (3) an estate the income of which is subject to United States federal income taxation regardless of its source, or (4) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust, or a trust that has elected to be treated as a United States person. The discussion does not address all aspects of United States federal income taxation that may be relevant to US holders in light of their particular circumstances, nor does it address the United States federal income tax consequences to US holders that are subject to special rules under the Code, including, but not limited to, (i) dealers or traders in securities, (ii) financial institutions, (iii) tax-exempt organizations or qualified retirement plans, (iv) insurance companies, (v) persons holding Common Stock as a hedge or as part of a straddle, constructive sale, conversion transaction, or other risk management transaction, and (vi) holders who hold their Common Stock other than as a capital asset.

Dividends
Subject to the discussion of the "passive foreign investment company" rules below, a US holder owning shares of Common Stock must generally treat the gross amount of dividends paid by us to the extent of our current and accumulated earnings and profits without reduction for the amount of Canadian withholding tax, as dividend income for United States federal income tax purposes. To the extent that distributions exceed our current or accumulated earnings and profits, they will be treated first as a tax-free return of capital, which will reduce the holder's adjusted tax basis in his or her Common Stock (but not below zero), then as capital gain. The dividends generally will not be eligible for the "dividends received" deduction allowed to United States corporations. The amount of Canadian withholding tax on dividends may be available, subject to

certain limitations, as a foreign tax credit or, alternatively, as a deduction (see discussion at "Foreign Tax Credit" below). Dividends paid by us will be treated as income from sources outside the United States, but generally will be "passive income," or in the case of certain types of taxpayers, "financial services income" for foreign tax credit purposes.

If we make a dividend distribution in Canadian dollars, the U.S. dollar value of the distribution on the date of receipt is the amount includible in income. Any subsequent gain or loss in respect of the Canadian dollars received arising from exchange rate fluctuations generally will be U.S. source ordinary income or loss.

Long-term capital gain of noncorporate taxpayers generally is eligible for preferential tax rates. Additionally, for taxable years beginning after December 31, 2002 and before January 1, 2009, subject to certain exceptions, dividends received by certain noncorporate taxpayers from “qualified foreign corporations” are taxed at the same preferential rates that apply to long-term capital gain. The maximum federal tax rate on net long-term capital gains recognized by noncorporate taxpayers currently is 15%. Provided that we are not a “passive foreign investment company,” as discussed below, we currently should meet the definition of “qualified foreign corporation.” As a consequence, dividends paid to certain noncorporate taxpayers should be taxed at the preferential rates.

Sale or Exchange of Common Stock
Subject to the discussion of the "passive foreign investment company" rules below, the sale of a share of our Common Stock generally results in the recognition of gain or loss to the US holder in an amount equal to the difference between the amount realized and the US holder's adjusted tax basis in such share. Gain or loss upon the sale of the share will be long-term or short-term capital gain or loss, depending on whether the share has been held for more than one year. The maximum federal tax rate on net long-term capital gains currently is 15% for noncorporate taxpayers and 35% for corporations. Capital gain that is not long-term capital gain is taxed at ordinary income rates. The deductibility of capital losses is subject to certain limitations.

Foreign Tax Credit
Subject to the limitations set forth in the Code, as modified by the Convention, a US holder may elect to claim a credit against his or her U.S. federal income tax liability for Canadian income tax withheld from dividends received in respect of shares of our Common Stock. Holders of our Common Stock and prospective US holders of our Common Stock should be aware that dividends we pay generally will constitute “passive income” for purposes of the foreign tax credit, which could reduce the amount of foreign tax credit available to them. The rules relating to the determination of the foreign tax credit are complex. US holders of our Common Stock and prospective US holders of our Common Stock should consult their own tax advisors to determine whether and to what extent they would be entitled to such credit. Holders who itemize deductions may instead claim a deduction for Canadian income tax withheld.

Passive Foreign Investment Company Considerations
Special rules apply to US holders that hold stock in a "passive foreign investment company" ("PFIC"). A non-U.S. corporation generally will be a PFIC for any taxable year in which either (i) 75% or more of its gross income is passive income or (ii) 50% or more of the average value of its assets consists of assets that produce, or that are held for the production of, passive income. For this purpose, passive income generally includes, among other things, interest, dividends, rents, royalties and gains from certain commodities transactions.

We believe that we should not be classified as a PFIC for the current taxable year or prior taxable years, and we do not anticipate being a PFIC with respect to future taxable years. However, there can be no assurance that we will not be considered a PFIC for any taxable year, because (1) the application of the PFIC rules to our circumstances is unclear and (2) status under the PFIC rules is based in part on factors not entirely within our control (such as market capitalization). Furthermore, there can be no assurance that the Internal Revenue Service will not challenge our determination concerning our PFIC status. Therefore, US holders and prospective US holders are urged to consult with their own tax advisors with respect to the application of the PFIC rules to them.

If, contrary to our expectations, we were to be classified as a PFIC for any taxable year, a US holder may be subject to an increased tax liability (including an interest charge) upon the receipt of certain distributions from us or upon the sale, exchange or other disposition of Common Stock, unless such US holder timely makes one of two elections. First, if, for any taxable year that we are treated as a PFIC, a US holder makes a timely election to treat us as a qualified electing fund ("QEF") with respect to such Holder's interest in Common Stock, the electing US holder would be required to include annually in gross income (1) such Holder's pro rata share of our ordinary earnings, and (2) such Holder's pro rata share of any of our net capital gain, regardless of whether such income or gain is actually distributed. In general, a US holder may make a QEF election for any taxable year at any time on or before the due date (including extensions) for filing such Holder's United States federal income tax return for such taxable year. However, Treasury regulations provide that a US holder may be entitled to make a retroactive QEF election for a taxable year after the election's due date if certain conditions are satisfied. In the event of a determination by us or the Internal Revenue Service that we are a PFIC, we intend to comply with all record-keeping,

reporting and other requirements so that US holders, at their option, may maintain a QEF election with respect to us. However, if meeting those record-keeping and reporting requirements becomes onerous, we may decide, in our sole discretion, that such compliance is impractical, and will notify US holders accordingly.

As an alternative to the QEF election, US holders may elect to mark their Common Stock to its market value (a "mark-to-market election"). If a valid mark-to-market election is made, the electing US holder generally will recognize ordinary income for the taxable year an amount equal to the excess, if any, of the fair market value of their Common Stock as of the close of such taxable year over the US holder's adjusted tax basis in the Common Stock. In addition, the US holder generally is allowed a deduction for the lesser of (1) the excess, if any, of the US holder's adjusted tax basis in the Common Stock over the fair market value of the Common Stock as of the close of the taxable year, or (2) the excess, if any of (A) the mark-to-market gains for the Common Stock included in gross income by the US holder for prior taxable years, over (B) the mark-to-market losses for Common Stock that were allowed as deductions for prior tax years.

The PFIC rules are complex. Accordingly, US holders and prospective US holders of our Common Stock are strongly urged to consult their own tax advisors concerning the impact of these rules, including the making of QEF or mark-to-market elections, on their investment or prospective investment in our Common Stock.

Financing Exploration and Development Drilling Through Canadian Income Tax Incentives
In order to encourage investment in the exploration for and development of its mineral deposits, the Canadian Income Tax Act allows Canadian taxpayers to make investments in oil and gas companies and deduct on their personal income tax return qualifying amounts spent by the oil and gas company on Canadian property. Qualifying amounts cover 100% of annual “exploration” expenses. In addition to being able to deduct their investment as an expense, the investor receives stock in the company for his or her investment. The terms of this type of investment are usually set forth in a "Flow Through Agreement" in which the company agrees not to take as an income tax deduction the amount of the proceeds expended for exploration and/or development work, but to allow the deduction to “flow through” to the investors. This flow-through type of financing is of benefit only to Canadian taxpayers.

Under the Flow-Through type of financing, the investors pay their subscription amount to us. Shares of Common Stock are issued to the investor, and we covenant to renounce to the investor, with an effective date of December 31 of a particular year, certain exploratory or specified development expenses incurred by us under a flow through share arrangement within the first 60 days of the year following that particular year.

F. Dividends and Paying Agents

Holders of our Common Stock are entitled to receive such dividends as may be declared from time to time by our Board of Directors, in its discretion, out of funds legally available for that purpose. We have not paid any dividends since our inception and have no plans to pay dividends.

G. Statement of Experts

Our auditors, Ernst & Young LLP of P.O. Box 10101 Pacific Centre 700 West Georgia Street, Vancouver, British Columbia V7Y 1CY, have consented to the inclusion in this Registration Statement of the report on our audited financial statements for the three months ended December 31, 2005, nine months ended September 30, 2005 and the years ended December 31, 2004 and 2003.

Sproule Associates Limited, 900 North Tower Sun Life Plaza, 140 Fourth Avenue Southwest, Calgary, Alberta, T2P 3N3, Canada, have consented to the inclusion in this Registration Statement of its independent engineering report of our proved reserves as at December 31, 2005.

H. Documents on Display

We have filed this Registration Statement on Form 20-F with the SEC, under the Securities and Exchange Act of 1934, as amended, with respect to our Common Stock. You may read and copy all or any portion of the Registration Statement or other information in our files in the SEC’s public reference room at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington D.C. 20549. You can also request copies of these documents upon payment of a duplicating fee, by writing the SEC. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference rooms. The SEC maintains a web site (http://www.sec.gov) that contains all of our filings with the SEC.

The documents concerning us may also be viewed at our head offices in Richmond, British Columbia, during normal business hours.

I. Subsidiary Information

We have no subsidiaries.

Item 11. Quantitative and Qualitative Disclosures About Market Risk

The oil and gas industry is exposed to a variety of risks including the uncertainty of finding and recovering new economic reserves, the performance of hydrocarbon reservoirs, securing markets for production, commodity prices, interest rate fluctuations, potential damage to or malfunction of equipment and changes to income tax, royalty, environmental or other governmental regulations.

We mitigate these risks to the extent we are able by:

employing highly-skilled staff and focusing them in areas where they have a strong knowledge base in order to maximize value.
utilizing competent, professional consultants as support teams to company staff.
performing careful and thorough geophysical, geological and engineering analyses of each prospect.
using current, cost-effective and where feasible, leading-edge technology.
maintaining adequate levels of property liability and business interruption insurance.
focusing on a limited number of core properties.
striving to be a low-cost producer to maximize Field netbacks.
maintaining a balanced portfolio of sales contracts.
staying informed about industry changes and trends through appropriate association memberships, publications, subscriptions and conferences.

Market risk is the possibility that a change in the prices for crude oil and natural gas, foreign currency exchange rates, or interest rates will cause the value of a financial instrument to decrease or become more costly to settle. Our financial instruments in Fiscal 2005 consist of cash and cash equivalents, accounts receivable and accounts payable.

We are exposed to commodity price risks, interest rate risks and credit risk. Foreign currency exchange rate risks are not applicable to our operations.

Commodities Price Risk
Our future financial performance remains closely linked to hydrocarbon commodity prices, which can be influenced by many factors including global and regional supply and demand, worldwide political events and weather. These factors, among others, can result in a high degree of price volatility.

Our weighted average heavy crude oil prices are based on the index, Hardisty Heavy 12^o API, for heavy crude oil in the proximity of southern Saskatchewan. Company-operated production from our Mantario East field is, for the most part, approximately 13.4 ^o API.

Our weighted average natural gas prices are currently managed by the field operator at Cypress in northeastern British Columbia.

Sproule Associates Limited, an engineering firm in Calgary, Alberta, independently evaluates our reserves each year. They maintain a website showing historical and forecasted prices, which helps to provide trends of the above-described index affecting our weighted average prices. The website address is: www.sproule.com/prices/defaultprices.htm.

Management regularly employs price-trending information for its internal cash flow forecasting purposes from the websites of two firms that regularly market hydrocarbon commodities. They are www.progas.com and www.nexenmarketing.com.

We currently have no hedge positions, however, we manage our potential exposure to commodity price volatilities through diversification of commodities having differing price volatilities.

A financial swap is a derivative instrument whereby we and a third party agree to settle, at specified intervals, the difference between an agreed fixed commodity price, interest rate or exchange rate and floating prices or rates calculated by reference to an agreed notional volume or principal amount. We are currently not using swap contracts and have no obligation to deliver or receive quantities of natural gas or crude oil pursuant to a swap.

Weighted Average Prices and the Effect of Adversity
We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of natural gas and crude oil may have on the fair value of our gross revenues. The following tables demonstrate the effects of adversity on our weighted average prices and gross revenues by commodity for the three and twelve months ended December 31, 2005 (see also Item 5 – “Liquidity and Capital Resources - Sensitivity Analysis”). Our operating cash flows and earnings/loss before taxes would experience similar effects.

Effects of Adversity on Weighted Average Prices by Commodity
	Three Months	Nine Months	After Consideration of Adversity %
	Ended	Ended	(Based on Twelve Months of 2005)
(Units as stated)	Dec 31, 2005	Sep 30, 2005	10%	20%	30%
Heavy crude oil ($/bbl)	30.33	34.95	30.22	26.84	23.51
Natural gas ($/mcf)	11.92	8.66	44.99	39.99	34.99
Light/medium crude oil ($/bbl)	59.24	48.67	8.56	7.61	6.66

Effects of Adversity on Gross Revenues by Commodity
	Three Months	Nine Months	After Consideration of Adversity %
	Ended	Ended	(Based on Twelve Months of 2005)
($ 000’s)	Dec 31, 2005	Sep 30, 2005	10%	20%	30%
Heavy crude oil ($/bbl)	2,558	7,048	8,645	7,685	6,724
Natural gas ($/mcf)	1,017	2,107	2,812	2,499	2,187
Light/medium crude oil ($/bbl)	-	15	14	12	11

Credit Risk
In addition to market risk, our financial instruments involve, to varying degrees, risk associated with trade credit and risk associated with operatorship of joint venture properties. Fifty-two percent of our accounts receivable balance as at December 31, 2005, results from the sale of our commodities and from the collection of partner liabilities pursuant to joint venture agreements under which we have operatorship responsibilities. Further, while our largest producing property, Mantario East, is self-operated, three properties in which we have interests are operated by other industry partners that are subject to normal industry credit risk. The remaining 48% of our accounts receivable is pursuant to the Plan of Arrangement.

We do not require collateral or other security to support financial instruments nor do we provide collateral or security to counterparties. Currently, we do not expect non-performance by any counterparty. While there can be no assurance that our no-loss record will continue, the parties who are obligated to us contractually have been consistently reliable in the past.

Interest Rate Risk
During the three months ended December 31, 2005, we were not exposed to a risk of interest rate fluctuations on borrowings, as we did not employ a bank line of credit. Alternatively, had our cash, that was invested in short term deposits during the three months ended December 31, 2005, been subject to a 1% change in interest rates, we estimate it would have varied our interest income by nine thousand dollars.

On March 17, 2006, we established an operating line of credit of $6.5 million with our corporate bank. Under the facility, our borrowing rate is set at Canadian Dollar Prime as established by the National Bank of Canada, plus 1/2 of a percent per annum and our standby fee is one-eighth of a percent per annum on the undrawn borrowing capacity. We do not expect significant usage of the facility in the first half of Fiscal 2006.

We do not engage in interest rate swaps to hedge the interest rate exposure associated with the credit agreement.

At December 31, 2005, we had no floating debt outstanding.

Item 12. Description of Securities Other than Equity Securities – Not applicable

Part II.

Item 13. Defaults, Dividend Arrearages and Delinquencies - None

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds – None

Item 15. Controls and Procedures

We have carried out an evaluation, under the supervision and with the participation of our management, including our Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a–13e and 15d–15e under the Securities Exchange Act of 1934, as amended). Based upon that evaluation, as of December 31, 2005, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the year ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our Chief Executive Officer and Chief Financial Officer do not expect that our disclosure controls or our internal controls will prevent all error and all fraud. Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objective, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based partly on certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Item 16(A). Audit Committee Financial Expert

The Board of Directors has determined that Mr. William Thompson has the necessary attributes and experience for designation as our audit committee financial expert and our Board of Directors has designated him as its audit committee financial expert.

Item 16(B). Code of Ethics

Our website at http://www.shellbridge.ca/corporate/conductethics.htm contains our combined Code of Conduct and Ethics, which applies to all of our directors, officers and employees. Any amendment to the Code of Conduct and Ethics that applies to our directors or executive officers will be disclosed on our website, and any waiver of the Code of Conduct and Ethics for directors or executive officers may be made only by our Board of Directors or our Audit Committee and will be disclosed on our website.

Item 16(C). Principal Accountant Fees and Services

The following table shows the fees billed for the audit and other services provided by Ernst & Young LLP related to the period of our incorporation commencing July 7, 2005 and ending December 31, 2005.

Independent Registered Public Accounting Firm Fees
(000’s)	Fees
Audit-related	Nil
Tax	Nil
All other	Nil
Total	Nil

The Audit Committee pre-approves all audit services to be performed by Ernst &Young, LLP.

Item 16(D). Exemption from the Listing Standards for Audit Committees – None

Item 16(E). Purchases of Equity Securities by the Issuer and Affiliated Purchasers – None

Part III.

Item 17. Financial Statements

Independent Auditors’ Report	F-1

Balance Sheets as of December 31, 2005 and December 31, 2004	F-2

Statements of Operations and Deficit for the Three Months Ended December 31, 2005, Nine Months Ended September 30, 2005, and Years Ended December 31, 2004 and December 31, 2003	F-3

Statements of Cash Flows for the Three Months Ended December 31, 2005, Nine Months Ended September 30, 2005, and Years Ended December 31, 2004 and December 31, 2003	F-4

Notes to Financial Statements	F-5

Financial Statements

Shellbridge Oil & Gas, Inc.
December 31, 2005 and 2004

F-1

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of
Shellbridge Oil & Gas, Inc.

We have audited the balance sheets of Shellbridge Oil & Gas, Inc. as at December 31, 2005 and 2004, and the statements of operations and deficit and cash flows for the three months ended December 31, 2005, the nine months ended September 30, 2005, and the years ended December 31, 2004 and 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2005 and 2004, and the results of its operations and its cash flows for the three months ended December 31, 2005, the nine months ended September 30, 2005, and the years ended December 31, 2004 and 2003 in accordance with Canadian generally accepted accounting principles.

Vancouver, Canada,
March 10, 2006.	Chartered Accountants
(except for Note 17, which is as of April 27, 2006)

F-2

Shellbridge Oil & Gas, Inc.
Incorporated under the laws of the Province of Alberta

BALANCE SHEETS

As at December 31	(in Canadian dollars)

	2005		2004
	$		$

ASSETS
Current
Cash and cash equivalents	5,831,357		—
Accounts receivable [note 11]	8,942,391		1,541,724
Prepaid expenses	108,233		155,733
Total current assets	14,881,981		1,697,457
Crude oil and natural gas interests [note 5]	17,002,598		24,452,712
Capital assets [note 5]	317,693		414,913
Future income tax asset [note 8]	765,200		—
	32,967,472		26,565,082

LIABILITIES AND BUSINESS/SHAREHOLDERS’ EQUITY
Current
Accounts payable and accrued liabilities [note 15]	11,860,554		12,483,735
Total current liabilities	11,860,554		12,483,735
Asset retirement obligation [note 6]	1,237,535		559,654
Total liabilities	13,098,089		13,043,389
Commitments and contingencies [notes 11, 13, and 15]

Business/shareholders’ equity
Share capital [note 7[a]]	21,106,626		—
Contributed surplus [note 7[c]]	630,534		—
Deficit	(1,867,777	)	—
Owner’s net investment [note 2]	—		13,521,693
Total business/shareholders’ equity	19,869,383		13,521,693
	32,967,472		26,565,082

See accompanying notes

On behalf of the Board:


Director	Director

F-3

Shellbridge Oil & Gas, Inc.

STATEMENTS OF OPERATIONS AND DEFICIT

(in Canadian dollars)

	Three Months		Nine Months
	Ended		Ended		Year Ended		Year Ended
	December 31,		September 30,		December 31,		December 31,
	2005		2005		2004		2003
	$		$		$		$

REVENUE
Crude oil and natural gas sales	3,574,607		9,170,430		7,641,989		1,523,864
Royalties	(883,364	)	(2,713,343	)	(2,367,809	)	(461,446	)
Production costs	(747,919	)	(1,427,784	)	(2,036,027	)	(301,015	)
	1,943,324		5,029,303		3,238,153		761,403
Provincial royalty credits	—		172,136		272,069		121,913
	1,943,324		5,201,439		3,510,222		883,316

EXPENSES
Transportation costs	258,519		706,644		557,478		121,953
General and administrative	870,331		833,906		1,447,519		1,002,718
Interest expense	—		231,204		249,202		237,808
Interest income	(67,663	)	(3,752	)	(791	)	(3,830	)
Stock-based compensation	630,534		214,513		154,166		117,520
Accretion of asset retirement
obligation [note 6]	14,460		29,484		20,228		11,544
Amortization and depletion [note 5]	1,410,635		7,624,889		14,822,407		1,916,797
Exploration expenses	1,459,485		11,480,382		12,194,015		1,396,495
Gain on sale of natural gas
and oil interests	—		(600,000	)	—		—
Loss before income taxes	(2,632,977	)	(15,315,831	)	(25,934,002	)	(3,917,689	)
Income tax recovery [note 8]
- Current	—		—		—		—
- Future	(765,200	)	—		—		—
Net loss	(1,867,777	)	(15,315,831	)	(25,934,002	)	(3,917,689	)

Deficit, beginning of period	—		—		—		—
Transfer to Dynamic [note 2]	—		15,315,831		25,934,002		3,917,689
Deficit, end of period	(1,867,777	)	—		—		—

Net loss per share [notes 2 and 9]
- Basic	(0.06	)	—		—		—
- Diluted	(0.06	)	—		—		—

See accompanying notes

F-4

Shellbridge Oil & Gas, Inc.

STATEMENTS OF CASH FLOWS

(in Canadian dollars)

	Three Months		Nine Months
	Ended		Ended		Year Ended		Year Ended
	December 31,		September 30,		December 31,		December 31,
	2005		2005		2004		2003
	$		$		$		$

OPERATING ACTIVITIES
Net loss	(1,867,777	)	(15,315,831	)	(25,934,005	)	(3,917,689	)
Add (deduct) items not involving cash:
Accretion of asset retirement
obligation [note 6]	14,460		29,484		20,228		11,544
Amortization and depletion [note 5]	1,410,635		7,624,889		14,822,407		1,916,797
Stock-based compensation [note 7[c]]	630,534		214,513		154,166		117,520
Exploration expenses	1,459,485		11,480,382		12,194,015		1,396,495
Future income tax recovery	(765,200	)	—		—		—
Gain on sale of oil and gas assets	—		(600,000	)	—		—
Changes in non-cash working
capital affecting
operating activities [note 10]	(3,005,916	)	2,061,189		278,990		19,916
Cash provided by (used in)
operating activities	(2,123,779	)	5,494,626		1,535,801		(455,417	)

FINANCING ACTIVITIES
Net transfers from (to) Dynamic	—		(1,985,916	)	23,504,649		14,335,116
Shares issued for cash	3,852,505		—		—		—
Cash provided by financing activities	3,852,505		(1,985,916	)	23,504,659		14,335,116

INVESTING ACTIVITIES
Capital investment and
exploration expenditures	(4,245,608	)	(9,071,863	)	(32,207,307	)	(13,927,744	)
Purchase of capital assets	(48,905	)	(149,401	)	(225,087	)	(308,387	)
Proceeds on sale of oil and gas assets	—		600,000		—		—
Cash received pursuant to
Plan of Arrangement [note 4]	3,563,870		—		—		—
Changes in non-cash working capital
affecting investing activities
[notes 4 and 10]	4,833,274		5,112,554		7,391,934		356,432
Cash provided by (used in)
investing activities	4,102,631		(3,508,710	)	(25,040,460	)	(13,879,699	)

Increase in cash and cash equivalents	5,831,357		—		—		—
Cash and cash equivalents,
beginning of period	—		—		—		—
Cash and cash equivalents, end of period	5,831,357		—		—		—

Supplemental disclosures of cash flow information
Cash paid during the year for:
Interest	—		232,494		256,894		182,271
Income taxes	—		—		—		—

See accompanying notes

F-5

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

1. DESCRIPTION OF BUSINESS

Shellbridge Oil & Gas, Inc. (the “Company”) was incorporated under the laws of the Province of Alberta on July 7, 2005 and commenced commercial operations following the closing on September 30, 2005 of a Plan of Arrangement (“Arrangement”) entered into with Dynamic Oil & Gas, Inc. (“Dynamic”) and Sequoia Oil & Gas, Trust (“Sequoia”). Under the Arrangement, the Company acquired certain properties in southwestern Saskatchewan, and northeastern and southwestern British Columbia, working capital items, capital assets and asset retirement obligations from Dynamic [note 4].

2. BASIS OF PRESENTATION

The accompanying financial statements comprised of the Company’s balance sheets as at December 31, 2005 and 2004, and the statements of operations and deficit and cash flows for the three months ended December 31, 2005, the nine months ended September 30, 2005 and the years ended December 31, 2004 and 2003 are presented using accounting principles generally accepted in Canada. Prior to the Arrangement, the net assets transferred to the Company pursuant to the Arrangement [see note 4 - “Transfer of Assets and Commencement of Commercial Operations”] constituted a group of properties, not a separate legal entity or a separate division, thus no accounting records were separately maintained by Dynamic. Financial statement information covering periods prior to the Arrangement, which include the balance sheet as at December 31, 2004, and the statements of operations and deficit and cash flows for the nine months ended September 30, 2005 and the years ended December 31, 2004 and 2003, is information for the properties transferred to the Company pursuant to the Arrangement that has been derived from the accounting records of Dynamic using the historical results of operations and historical basis of assets and liabilities now comprising the Company. As a result, the financial statements included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what the Company’s results of operations, financial position and cash flows would have been had the Company been a stand-alone company during the periods prior to the Arrangement.

These financial statements include allocations of certain Dynamic assets, liabilities and expenses. Management believes the assumptions and allocations underlying the financial statements are reasonable. In circumstances described below where allocations are made of certain assets, liabilities and expenses, it is not practicable to estimate the actual amounts of those assets, liabilities and expenses that the Company would have recognized as at December 31, 2004, and for the nine month period ended September 30, 2005, and the years ended December 31, 2004 and 2003 had it been a separate, stand-alone company during such periods.

F-6

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

2. BASIS OF PRESENTATION (cont’d.)

The Company began accumulating deficits subsequent to the Arrangement. Changes in Owner’s net investment in the nine month period ended September 30, 2005, and in 2004 and 2003 represent Dynamic’s contribution to the Company after giving effect to the accumulated deficits of the Company, as well as cash transfers from and to Dynamic.

Crude oil and natural gas interests, asset retirement obligation, crude oil and natural gas sales, royalties, production costs, transportation costs, accretion of asset retirement obligation, amortization and depletion, exploration expenses, and gain on sale of natural gas interests

In the financial statements, historical amounts for the above items have been based upon actual amounts that were recorded in the accounting records of Dynamic and were attributable directly to the properties that were transferred to the Company at the time of the Arrangement.

Cash

Prior to the Arrangement, Dynamic frequently made use of a revolving, demand credit facility (“Operating Loan”) provided by its corporate bank that was secured by a general assignment of book debts and a floating charge debenture covering all the assets of Dynamic. In the financial statements, none of Dynamic’s Operating Loan or bank indebtedness has been allocated to the Company, as cash collected by or required by the Company was transferred between Dynamic and the Company, such transfers netted against Owner’s net investment. Subsequent to the Arrangement, the Company became responsible for its own cash and cash requirements.

Accounts receivables

In the financial statements of the Company, a portion of Dynamic’s accounts receivable has been allocated to the Company. After accounting for certain amounts that were transferred to the Company pursuant to the Arrangement, the balance of accounts receivable was allocated based on the pro-rata share of revenue from crude oil and natural gas sales that would have been generated from the producing assets of the Company that were transferred pursuant to the Arrangement, as compared to the total revenue from crude oil and natural gas sales of all of Dynamic’s producing assets.

F-7

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

2. BASIS OF PRESENTATION (cont’d.)

Prepaid expenses

In the financial statements of the Company, a portion of Dynamic’s prepaid expenses has been allocated to the Company. The portion of prepaid expenses allocated was based on the pro-rata share of net book values of crude oil and natural gas interests that were transferred to the Company at the time of the Arrangement, as compared to the total net book values of crude oil and natural gas interests of Dynamic.

Accounts payable and accrued liabilities

In the financial statements of the Company, a portion of Dynamic’s accounts payables and accrued liabilities has been allocated to the Company. After accounting for certain amounts that were transferred to the Company pursuant to the Arrangement, the balance of accounts payables and accrued liabilities was allocated based on the pro-rata share of incurred capital expenditures and expensed production, transportation and royalty costs (collectively, the “Payables Basis”) that would have been recorded in connection with the producing assets of the Company that were transferred pursuant to the Arrangement, as compared to Dynamic’s total Payables Basis.

Capital assets

The financial statements reflect that all capital assets that once belonged to Dynamic were acquired by the Company pursuant to the Arrangement.

Income tax assets and liabilities

Historically, tax pools exceeded the carrying value of the related assets, therefore, the financial statements provide a valuation allowance against future tax assets on the basis that future income tax assets did not meet the more-likely-than-not realization test.

The Company has not generated taxable income, therefore, there are no income tax liabilities reflected in the financial statements.

F-8

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

2. BASIS OF PRESENTATION (cont’d.)

General and administrative expense, stock-based compensation expense, interest expense and interest income.

Dynamic’s general and administrative expenses were primarily comprised of human resources, legal, audit, insurance, investor relations, annual filing costs and general office expenses. Dynamic’s stock-based compensation expense pursuant to its stock option plan with respect to awards made periodically to its employees, officers, directors and certain key consultants. Dynamic’s interest expense was mainly comprised of interest incurred in connection with balances outstanding pursuant to its Operating Loan. Interest income was comprised of short-term deposit interest earned and amounts owed to Dynamic by third parties pursuant to reassessments of such amounts.

In the financial statements of the Company, a portion of Dynamic’s general and administrative expenses, stock-based compensation expense, interest expense and interest income have been allocated to the Company based on the pro-rata share of net book values of crude oil and natural gas interests that were transferred to the Company at the time of the Arrangement, as compared to the total net book values of crude oil and natural gas interests of Dynamic.

Loss per share

On July 7, 2005, the Company had issued one common share to incorporate as a separate legal entity. Therefore, historical earnings per share have not been presented in the financial statements. Earnings per share have been presented using the Company’s common shares outstanding subsequent to the Arrangement.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting principles

The Company prepares its accounts in accordance with Canadian generally accepted accounting principles, which as applied in the financial statements, conform in all material respects to the accounting principles generally accepted in the United States, except as explained in note 12.

F-9

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)

Use of estimates

The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statement and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

Crude oil and natural gas interests

The Company uses the successful efforts method to account for its crude oil and natural gas interests. Lease acquisition costs are amortized on a straight-line basis over their lease term prior to the discovery of proved producing reserves. Geological and geophysical costs are expensed in the period in which they are incurred and costs of drilling an unsuccessful well are expensed when it becomes known the well did not result in a discovery of proved reserves or where one year has elapsed since the completion of drilling and near-term efforts to establish proved reserves are not foreseeable, intended, or in the Company’s control. All other costs of exploring and developing for proved reserves become capitalized crude oil and natural gas interests.

Capitalized proved producing crude oil and natural gas interests, including related plant and equipment, are depleted on a unit-of-production basis using the Company’s working interest share of proved crude oil and natural gas reserves, before royalties.

Crude oil and natural gas interests are recorded at cost less accumulated amortization and depletion. Natural gas and oil interests are assessed periodically for potential impairment to ensure that the carrying value of properties on the balance sheet is recoverable. If a property’s carrying value exceeds the sum of undiscounted future cash flows resulting from its use and eventual disposition, its value is impaired. The property is then assigned a fair value equal to its estimated discounted future cash flows and the excess carrying value is charged to amortization and depletion expense.

Joint interests

Substantially all acquisition, exploration, development and production activities of the Company are conducted jointly with others. These financial statements reflect only the Company’s proportionate interest in such activities.

F-10

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)

Cash and cash equivalents

Cash and cash equivalents include short-term, highly liquids investments that mature within one month of their purchase. They are recorded at cost which approximates their market value.

Capital assets

Capital assets are recorded at cost, less accumulated amortization. Amortization is provided on a straight-line basis as follows - furniture and fixtures at 10.0% per annum; computer hardware at 33.3% per annum; computer software at 100% per annum; and leasehold improvements over the lease term.

Income taxes

The liability method is used in accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantively-enacted tax rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance is recorded against any future income tax asset if it is not more likely than not that the asset will be realized.

Asset retirement obligations

The Company’s asset retirement obligations relate primarily to retirement obligations associated with tangible assets, such as well-sites and associated facilities. The fair value of an asset retirement obligation (“ARO”) is recognized in the period in which it is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of the associated proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings/loss in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted costs also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the accreted liability recorded. Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company’s earnings/loss at that time.

Revenue recognition

Revenues from crude oil and natural gas are recorded when delivered and title passes to customers.

F-11

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)

Stock-based compensation

The Company grants stock options to employees, directors and consultants pursuant to a Stock Option Plan described in note 7. The Company and Dynamic use the fair value method of accounting for all stock-based awards granted, modified or settled since January 1, 2003. Under this method, compensation costs attributable to the options are measured at the fair-value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. For stock-based compensation allocated to the Company for awards granted, modified or settled by Dynamic prior to January 1, 2003, the Company discloses the pro-forma effects to the net loss for the period as if the fair market value had been used at the date of grant. The pro-forma information is presented in note 7[c].

Foreign currency translation

All monetary assets and liabilities expressed in foreign currencies are translated at rates of exchange in effect at the end of the year. All other assets and liabilities are translated at the rates prevailing at the dates the assets were acquired or liabilities incurred. The resulting foreign currency translation gains and losses are included in the determination of net earnings/loss. Revenue and expenses are translated at the average exchange rate for the period.

Measurement uncertainty

The amounts recorded for depletion and amortization of crude oil and natural gas interests and asset retirement obligations are based on estimates. Assessments for impairments in asset carrying costs are based on independent estimates of the future cash flows from the Company’s proved reserves. Such estimates result mainly from studies that combine well-by-well recovery factors, future commodity prices and field operating costs. By their nature these estimates are subject to measurement uncertainty and the effect of the financial statements of changes in such estimates in future years could be significant.

Earnings per share

The Company utilized the treasury stock method in the determination of diluted per share amounts. Under this method, the diluted weighted average number of shares is calculated assuming that the proceeds arising from the exercise of outstanding, in-the-money options, are used to purchase common shares of the Company at their average market price for the period.

F-12

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

4. TRANSFER OF ASSETS AND COMMENCEMENT OF COMMERCIAL OPERATIONS

Under the Plan of Arrangement, Dynamic transferred to the Company certain producing and exploratory crude oil and natural gas properties. At the time of this transaction, Dynamic and the Company were related companies resulting in a transfer of assets to the Company from Dynamic at their carrying values at September 30, 2005 as follows:

Net Assets Received	Amount

Cash	3,563,870
Assumed working capital deficit (net of cash)	(982,573	)
Crude oil and natural gas interests	15,321,165
Capital assets	340,558
Asset retirement obligation	(988,900	)
Common Shares issued pursuant to the Plan of Arrangement
(25,754,278 shares) [note 7[a]]	17,254,120

5. CRUDE OIL AND NATURAL GAS INTERESTS, AND CAPITAL ASSETS

		Accumulated
		Amortization and	Net Book
	Cost	Depletion	Value
	$	$	$

December 31, 2005
Crude oil and natural gas interests	41,959,496	24,956,898	17,002,598
Capital assets	907,396	589,703	317,693

December 31, 2004
Crude oil and natural gas interests	40,669,611	16,216,899	24,452,712
Capital assets	709,089	294,176	414,913

At December 31, 2005, costs of $3,134,510 [December 31, 2004 - $14,043,088] related to non-producing assets have been excluded from the calculation of amortization and depletion.

In the three month period ended December 31, 2005 and the nine month period ended September 30, 2005 there were no asset write-downs recorded due to impairment tests [December 31, 2004 and 2003 - $3,648,038 and $316,213, respectively].

F-13

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

6. ASSET RETIREMENT OBLIGATION

The following table presents the reconciliation of the change in the carrying amount of the obligation associated with the retirement of crude oil and natural gas properties:

	Three Months	Nine Months
	Ended	Ended	Year Ended	Year Ended
	December 31,	September 30,	December 31,	December 31,
	2005	2005	2004	2003
	$	$	$	$

Asset retirement obligation,
beginning of period	—	559,654	185,032	126,260
Asset retirement obligation, following
Plan of Arrangement [note 4]	988,900	—	—	—
Liabilities incurred during the period	66,502	414,222	277,633	47,227
Revisions in estimated cash flows	167,673	—	76,761	—
Accretion expense	14,460	15,024	20,228	11,545
Asset retirement obligation, end of period	1,237,535	988,900	559,654	185,032

The total undiscounted amount of estimated cash flows required to settle the obligation at December 31, 2005 is $1,660,195 [December 31, 2004 - $801,500, December 31, 2003 -$380,000] which has been discounted using an average credit-adjusted risk free rate of 5.7% . These payments are expected to be made over the next 29 years with 37% of the costs incurred within the next five years.

7. SHARE CAPITAL

Authorized

The Company is authorized to issue an unlimited number of voting Common Shares, without nominal or par value, and an unlimited number of non-voting Preferred Shares, without nominal or par value.

[a] Issued and outstanding

The following table sets forth the issued and outstanding Common Shares as at December 31, 2005:

F-14

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

7. SHARE CAPITAL (cont’d.)

	Number of
	Shares	Amount
Common Shares	#	$

Issued upon incorporation, July 7, 2005	1	1
Issued pursuant to Plan of Arrangement [note 4]	25,754,278	17,254,120
Shares issued on flow-through private placement	1,666,666	1,926,252
Shares issued on non-flow-through private placement	1,666,667	1,926,253
Issued and outstanding	29,087,612	21,106,626

On October 3, 2005 the Company issued 1,666,666 flow-through Common Shares at $1.20 per share through private placement for total gross proceeds of $2,000,000, less issue costs of $73,748. Also on that date, the Company issued 1,666,667 non-flow-through Common Shares at $1.20 per share for total gross proceeds of $2,000,000, less issue costs of $73,747.

Gross proceeds from the flow-through shares will be used to incur qualifying Canadian Exploration Expense (“CEE”) as defined in the Income Tax Act (Canada), and the Company has renounced officially on January 19, 2006 such CEE in favour of the original holders of the flow-through shares in an amount equal to the issue price for each flow-through share.

As at December 31, 2005, the Company had not issued any Preferred Shares.

[b] Stock Option Plan and Options Outstanding

The Company’s Stock Option Plan (the “Stock Option Plan”) approved by the shareholders authorizes the Board of Directors of the Company to issue stock options to directors, officers, employees or other service providers of the Company.

Under the Stock Option Plan, the maximum number of stock options granted and outstanding shall not exceed 10% of the issued and outstanding Common Shares of the Company, or such additional amount as may be approved by the shareholders of the Company. The term of the options granted shall be determined by the Board of Directors of the Company in its discretion, to a maximum of five years from the date of the grant. The Board of Directors has the authority to set vesting provisions and the exercise price of the options. Such exercise price shall not be lower than the market price. The market price means the closing price per Common Share on the day prior to the date of grant on the stock exchange on which the Common Shares are listed.

During the three month period ended December 31, 2005, options issued totaled 2,265,000 [1,690,000 to inside directors, officers, employees and non-employees; 575,000 to outside directors]. Options granted to directors, in their capacity as such, vest immediately, whereas all other options granted vest over thirty-six months. The exercise price of each option granted under

F-15

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

7. SHARE CAPITAL (cont’d.)

the Stock Option Plan equals the amount designated in the individual agreement, which is based on the fair value of the stock at the date of grant.

A summary of the status of the Company’s Stock Option Plan as of December 31, 2005 is presented below:

	Number of	Exercise
	Shares	Price
Common Shares	#	$

Granted during the three month period ended
December 31, 2005	2,265,000	1.44
Outstanding at period end	2,265,000	1.44
Options exercisable at period end	857,778	1.44

The exercise price for all the options outstanding as at December 31, 2005 is $1.44 per share. These options have a remaining contractual life of 4.75 years at December 31, 2005.

[c] Accounting for Stock Options

During the three month period ended December 31, 2005 the Company used the fair-value based method to account for stock options granted to directors, employees and non-employees, resulting in a stock-based compensation expense and a corresponding increase to contributed surplus of $630,534.

The following table shows the pro-forma net loss had the Company applied the fair-value based method of accounting for all stock options outstanding that were related to the stock-based compensation allocated to the Company:

	Three Months		Nine Months
	Ended		Ended		Year Ended		Year Ended
	December 31,		September 30,		December 31,		December 31,
	2005		2005		2004		2003
	$		$		$		$

Net loss:
as reported	(1,867,777	)	(15,315,831	)	(25,934,002	)	(3,917,689	)
pro-forma	(1,867,777	)	(15,322,949	)	(25,977,411	)	(3,957,630	)
Net loss per share:
basic	(0.06	)	—		—		—
diluted	(0.06	)	—		—		—

F-16

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

7. SHARE CAPITAL (cont’d.)

The Black-Scholes options valuation model was used to estimate the fair value of stock options. In addition, option valuation models require the input of highly-subjective assumptions, including the expected stock-price volatility.

The fair value of the stock options granted was estimated based on the date of the grant using the Black-Scholes option pricing model with the following assumptions:

Three Months

Nine Months

Ended

Year Ended

December 31,

September 30,

December 31,

2005

2004

2003

Dividend yield

—

Expected volatility

71%

—

47%

51%

Risk-free interest rate

5.0%

—

4.25%

4.00%

Expected lives

3 years

—

3 years

The weighted average fair value per share of stock options granted during the three months ended December 31, 2005 was $0.72 [years ended December 31, 2004 and 2003 - $1.44 and $1.78, respectively]. There were no options granted during the nine month period ended September 30, 2005.

F-17

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

8. INCOME TAXES

The Company’s tax pools exceed the carrying value of the assets for accounting purposes. The Company has provided a valuation allowance against future tax assets that are not more likely than not to be realized.

	As at
	December 31,
	2005
	$
Long term future tax asset:
Crude oil and natural gas interests	5,842,332
Finance charges	53,049
Asset retirement obligation	463,704
	6,359,085
Valuation allowance	(5,593,885	)
Future income tax asset	765,200

Future income taxes result primarily from temporary differences in the recognition of certain assets and liabilities for income tax and financial reporting purposes. The Company has net unrecognized temporary differences as at December 31, 2005 of approximately $15,050,000 [December 31, 2004 - $31,236,852] primarily related to the excess of the tax basis of crude oil and natural gas interests, asset retirement obligation and finance charges over net book value. The related income tax benefits with respect to these net deductible temporary differences have not been fully recorded in the accounts, as they are not more likely than not to be realized.

The reconciliation of income tax attributable to operations computed at the statutory tax rates is as follows:

	Three Month				Nine Month
	Period Ended				Period Ended				Year Ended				Year Ended
	December 31,				September 30,				December 31,				December 31,
	2005				2005				2004				2003
(in Canadian dollars)	$		%		$		%		$		%		$		%

Tax at combined federal
and provincial rates	(1,060,037	)	(40.26	)	(5,795,032	)	(38.80	)	(10,563,172	)	(40.73	)	(1,631,101	)	(41.63	)
Tax effect of:
Non-deductible expenses	355,003		13.48		334,647		2.24		387,868		1.49		144,064		3.67
Resource allowance	(60,166	)	(2.29	)	(234,320	)	(1.57	)	(182,451	)	(0.70	)	(6,227	)	(0.16	)
Unrecognized future
tax asset	—		—		5,694,705		38.13		10,357,755		39.94		1,493,264		38.12
Future income tax recovery	(765,200	)	(29.07	)	—		—		—		—		—		—

F-18

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

9. NET LOSS PER SHARE

Basic net loss per share was calculated on the basis of the weighted average number of shares outstanding for the three month period ended December 31, 2005 of 28,978,915. The effect of any potential common share issuances due to the exercise of stock options in 2005 is anti-dilutive, therefore, all of the options outstanding have been excluded from the diluted loss per share calculation.

	Three Month
	Period Ended
	2005

Numerator
Net loss for the period	(1,867,777	)
Denominator
Weighted average number of common shares outstanding	28,978,915
Effect of dilutive stock options	—
	28,978,915

Basic net loss per share	(0.06	)
Diluted net loss per share	(0.06	)

10. CHANGES IN NON-CASH WORKING CAPITAL BALANCES

[a] Changes affecting operating activities comprise:

	Three Months		Nine Months
	Ended		Ended		Year Ended		Year Ended
	December 31,		September 30,		December 31,		December 31,
	2005		2005		2004		2003
	$		$		$		$

Accounts receivable	(4,674,420	)	(4,686,514	)	(1,125,099	)	(149,795	)
Prepaid expenses	(108,233	)	24,118		(38,797	)	(41,578	)
Accounts payable and
accrued liabilities	1,776,737		6,723,585		1,442,886		211,289
	(3,005,916	)	2,061,189		278,990		19,916

F-19

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

10. CHANGES IN NON-CASH WORKING CAPITAL BALANCES (cont’d.)

[b] Changes affecting investing activities comprise:

	Three Months	Nine Months
	Ended	Ended		Year Ended	Year Ended
	December 31,	September 30,		December 31,	December 31,
	2005	2005		2004	2003
	$	$		$	$

Accounts receivable	157,852	—		—	—
Accounts payable
and accrued liabilities	4,675,422	(5,112,554	)	7,391,934	356,432
	4,833,274	(5,112,554	)	7,391,934	356,432

11. FINANCIAL INSTRUMENTS

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable and accounts payable. The carrying values of these financial instruments approximate their fair value. The Company’s accounts receivables principally result from the sale of its various hydrocarbon commodities and from the collection of partner liabilities pursuant to joint venture agreements under which it has operatorship responsibilities. Substantially all of the Company’s accounts receivable as at December 31, 2005 and 2004 are from other companies in the oil and gas industry. This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that such entities may be similarly affected by industry-wide changes in economic or other conditions. To date, the Company has not incurred credit losses against its receivables. At December 31, 2005, one customer and three joint venture partners represent 42% of the accounts receivable balance [December 31, 2004 - 64%]. As at December 31, 2005, amounts representing 48% of accounts receivable and 54% of accounts payable are yet to be resolved pursuant to the Plan of Arrangement.

F-20

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

12. RECONCILIATION TO U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The Company prepares its accounts in accordance with Canadian generally accepted accounting principles (Canadian GAAP), which for the most part, are similar to United States generally accepted accounting principles (U.S. GAAP). The following tables reflect the major differences in accounting principles:

Net loss under U.S. GAAP would be:

	Three Months		Nine Months
	Ended		Ended		Year Ended		Year Ended
	December 31,		September 30,		December 31,		December 31,
	2005		2005		2004		2003
	$		$		$		$

Net loss under
Canadian GAAP	(1,867,777	)	(15,315,831	)	(25,934,002	)	(3,917,689	)
Write-down on natural gas
and oil properties [b]	—		—		182,000		(182,000	)
Net loss before cumulative
effect of change in
accounting principle
under U.S. GAAP	(1,867,777	)	(15,315,831	)	(25,752,002	)	(4,099,689	)
Cumulative effect of change
in accounting principle,
net of applicable taxes [a]	—		—		—		43,728
Net loss after cumulative
effect of change in
accounting principle
under U.S. GAAP	(1,867,777	)	(15,315,831	)	(25,752,002	)	(4,055,961	)

Net loss per common share
under U.S. GAAP
- basic	(0.06	)	—		—		—
- diluted	(0.06	)	—		—		—

[a]	Asset retirement obligation

	During 2003, Dynamic early-adopted CICA Handbook section 3110 - “Asset Retirement Obligations” for Canadian GAAP and SFAS 143 - “Accounting for Asset Retirement Obligations” for U.S. GAAP. The transitional provisions differ between Canadian GAAP and U.S. GAAP in that Canadian GAAP requires restatement of comparative amounts whereas

F-21

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

12. RECONCILIATION TO U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

U.S. GAAP does not allow restatement, but rather requires a cumulative catch-up adjustment to earnings.

[b]	Under both U.S. and Canadian GAAP, property, plant and equipment must be assessed for potential impairments. Under U.S. GAAP, if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, then an impairment loss (the amount by which the carrying amount of the asset exceeds the fair value of the asset) should be recognized. Fair value is calculated as the present value of estimated expected future cash flows. Prior to 2004, under Canadian GAAP, the impairment loss was recognized as the difference between the carrying value of the asset and its net recoverable amount (undiscounted). Dynamic adopted a new standard effective for 2004 that eliminated this U.S./Canadian GAAP difference.

[c]	For U.S. GAAP, the premium received by the Company on the issuance of flow-through shares which is in excess of the fair value of common shares is required to be credited to liabilities. The liability is reversed when tax benefits are renounced and, at that time, a deferred tax liability is recognized in respect of renounced Canadian exploration expenses. Any difference arising between the liability and deferred tax liability is accounted for as an income tax expense. During 2005, the total flow-through share premium received was $375,000.

[d]	For U.S. GAAP, dry hole expenses of $470,939 for the three month period ended December 31, 2005 [nine months ended September 30, 2005 - $2,204,567, years ended December 31, 2004 and 2003 - $8,321,774 and $11,948, respectively], included in investing activities on the statement of cash flows would be reported in operating activities.

[e]	For U.S. GAAP, the Company is required to present a statement of comprehensive income/loss. For the three month period ended December 31, 2005, comprehensive loss is equal to $1,867,777 [nine months ended September 30, 2005 - $15,315,831, years ended December 31, 2004 and 2003 - $25,934,002, and $3,917,689, respectively].

F-22

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

12. RECONCILIATION TO U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

After differences discussed above have been adjusted for, selected balance sheet items under Canadian and U.S. GAAP would be:

	December 31, 2005		December 31, 2004
	Canadian GAAP	U.S. GAAP	Canadian GAAP	U.S. GAAP
	$	$	$	$

Crude oil and
natural gas interests [b]	17,002,598	17,002,598	24,452,712	24,270,712
Owner’s net investment [b]	—	—	13,521,693	13,339,693
Share capital [c]	21,106,626	20,606,046	—	—
Accounts payable and
accrued liabilities [c]	11,860,554	12,235,554	12,483,735	12,483,735

Newly-issued U.S. Accounting Standards

Conditional Asset Retirement Obligations

During 2005, the FASB issued Financial Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies that the term “conditional asset retirement obligations” as used in the FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this statement has not had a material impact on the Company’s results of operations or financial position.

F-23

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

12. RECONCILIATION TO U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

Accounting Changes and Error Corrections

In June 2005, the FASB issued Statement 154, Accounting Changes and Error Corrections which replaces APB Opinion 20 and FASB Statement 3. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principles be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. In the absence of explicit transition provisions provided for in new or existing accounting pronouncements, Statement 154 now requires retrospective application of changes in accounting principle to prior-period financial statements, unless it is impracticable to so do. The Statement is effective for fiscal years beginning after December 15, 2005. The Company does not expect the adoption of this statement will have a material impact on its results of operations or financial position.

13. COMMITMENTS

[a]	The Company has entered into an operating lease in respect of its office premises. The minimum payments under this lease commitment, including estimated operating costs are as follows:

			$(000’s)

	2006		71
	2007		71
	2008		30
			172

[b]

As part of the Company’s flow-through share financing [see note 7], the Company is committed to renounce Canadian Exploratory Expense (“CEE”) in favour of the original holders of the flow-through Common Shares. The Company renounced CEE of $2,000,000 officially on January 19, 2006. As at December 31, 2005, the Company had incurred approximately 53% of the qualifying expenditures. The remainder of the qualifying expenditures must be incurred by December 31, 2006.

F-24

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

14. ECONOMIC DEPENDENCY

The Mantario East property in Saskatchewan is a core property of the Company and the majority of crude oil production from the property is processed through facilities owned and operated on-site by the Company. During years ended December 31, 2004 and 2003, the Cypress/Chowade property in British Columbia was a core property providing the majority of natural gas production through partner-operated facilities.

During the three month period ended December 31, 2005, 72% of the Company’s total crude oil and natural gas sales revenue originated from Mantario East [nine month period ended September 30, 2005 - 77% from Mantario East, twelve months ended December 31, 2004 - 94% from Cypress/Chowade, twelve months ended December 31, 2003 - 99% from Cypress/Chowade.]

15. JOINT VENTURE OBLIGATION

Included in accounts payable and accrued liabilities is an accrual for an obligation related to one of the Company’s joint venture partners. The amount of the obligation is in dispute. Management believes that the amount accrued will be sufficient to provide for the eventual settlement of this obligation. The eventual resolution of this disputed obligation could result in a material adjustment.

16. RELATED PARTY TRANSACTIONS

As discussed in note 7, on October 3, 2005, the Company issued 1,666,666 flow-through Common Shares at $1.20 per share through private placement for total gross proceeds of $2,000,000. Of the total number of flow-through Common Shares issued, directors and officers acquired 574,668 flow-through Common Shares or 34% of the total issued.

17. SUBSEQUENT EVENTS

[a]

On March 17, 2006, the Company established a revolving, demand credit facility with its bank, the National Bank of Canada. The facility makes available to the Company the amount of $6,500,000 under a revolving, demand credit facility. Principal balances outstanding bear interest at prime plus 1/2% (bank prime at March 17, 2006 was 5.50%). The credit facility is subject to periodic review and is collateralized by a general assignment of book debts and a floating charge debenture of $20,000,000 covering all the assets of the Company. The Company covenants to maintain a working capital ratio greater than 1.0, such ratio (comprised of current assets divided by current liabilities), to include as a current asset, the undrawn credit available to the Company. A standby fee of 0.125% per annum is levied on the unused portion of the facility.

F-25

Shellbridge Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS

December 31, 2005	(in Canadian dollars)

17. SUBSEQUENT EVENTS (cont’d.)

[b]

Under joint announcement with True Energy Trust of Calgary, Alberta (“True”) on April 11, 2006, the Company entered into an agreement with True and True Energy Inc. (“True Energy”), a wholly-owned subsidiary of True, whereby, subject to certain conditions, True Energy will acquire all of the Company’s issued and outstanding common shares on the basis of 0.14 trust units of True for each outstanding share of the Company’s common stock. The contemplated transactions have received unanimous support of both the Company’s and True’s board of directors. Shareholders representing approximately 10.6% of the Company’s outstanding common stock, 14.5% on a fully-diluted basis assuming the full vesting and exercise of outstanding options (including all of the Company’s directors and officers) have entered into lock-up agreements pursuant to which they agree to support the transactions. The Company’s board of directors has determined that the transactions are in the best interests of the Company’s common stockholders. The Company has agreed, as has True Energy, to pay the other a non-completion fee of $2.0 million in certain circumstances if the transactions are not completed. The agreement includes provisions whereby the Company will terminate discussions with any other parties and not solicit any other offers. The agreement also gives True the right to match any competing offer. Orion Securities Inc. is acting as the Company’s exclusive financial advisor to the transactions and has advised the Company’s board of directors that they are of the opinion, as of the date hereof, that the consideration to be received by the Company’s common stockholders pursuant to the transactions is fair, from a financial point of view.

F-26

Item 18. Financial Statements

(a)	See Item 17.

(b)	n/a

Item 19. Exhibits

(a)	Financial Statements: See Contents to our Financial Statements.
(b)	Exhibits: See Index to Exhibits.

Signatures

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Registration Statement on its behalf.

Date: May 1, 2006

Shellbridge Oil & Gas, Inc.

/s/ Michael A. Bardell

Michael A. Bardell
Chief Financial Officer

INDEX TO EXHIBITS

Exhibit Numbers	EXHIBITS

1(a) and 2(a)	Articles of Incorporation, dated July 7, 2005 of 1180602 Alberta Inc.

1(b) and 2(b)	Amendment of Articles of Incorporation, dated July 13, 2005, changing the name from 1180602 Alberta Inc. to Shellbridge Oil & Gas, Inc.

4 (i)	Arrangement Agreement dated July 20, 2005, by and among Shellbridge Oil & Gas, Inc., Sequoia Oil & Gas Trust, Dynamic Oil & Gas, Inc. and 0730008 B.C. Ltd.

4 (ii)	Plan of Arrangement (attached as Exhibit 1 to the Arrangement Agreement dated July 20, 2005).

4 (iii)	Oil and Gas Asset Purchase Agreement dated July 20, 2005, by and between Shellbridge Oil & Gas, Inc. and Dynamic Oil & Gas, Inc.

4 (iv)	Shellbridge Oil & Gas, Inc. 2005 Incentive Stock Option Plan.

4 (v)	Employment Agreement, dated January 25, 2006, by and between Shellbridge Oil & Gas, Inc. and Wayne J. Babcock .

4 (vi)	Employment Agreement, dated January 25, 2006, by and between Shellbridge Oil & Gas, Inc. and Donald K. Umbach.

4 (vii)	Employment Agreement, dated January 25, 2006, by and between Shellbridge Oil & Gas, Inc. and Michael A. Bardell.

4 (viii)	National Instrument 51-101, Canadian Standards of Disclosure for Oil and Gas Activities, Form 1, Form 2, and Form 3.

4 (ix)	Audit Committee Charter.

Shellbridge Oil & Gas Inactive 20FR12GInitial registration of securities (foreign private issuers)