Shellbridge Oil & Gas 20FR12G Initial registration of securities (foreign private issuers) | SEC 1 May 06

REPORT ON RESERVES DATA AND OTHER

OIL AND GAS INFORMATION

NI 51-101

TABLE OF CONTENTS

		Pages

Glossary of Terms		3
Form 51-101F1
Item 2.1	Reserves Data - Constant Prices and Costs	5
Item 2.2	Reserves Data - Forecast Prices and Costs	6
Item 2.3	Reserves Disclosure Varies with Accounting	7
Item 2.4	Future Net Reserves Disclosure Varies with Accounting	7
Item 3.1	Constant Prices Used in Estimates	7
Item 3.2	Forecast Prices Used in Estimates	8
Item 4.1	Reserves Reconciliation	9
Item 4.2	Future Net Revenue Reconciliation	9
Item 5.1	Undeveloped Reserves	9
Item 5.2	Significant Factors and Uncertainties	9-10
Item 5.3	Future Development Costs	10
Item 6.1	Oil and Gas Properties and Wells	11-14
Item 6.2	Undeveloped Properties Having No Attributed Reserves	14-15
Item 6.3	Forward Contracts	15
Item 6.4	Additional Information - Abandonment and Reclamation Costs	16
Item 6.5	Tax Horizon	16
Item 6.6	Costs Incurred	16
Item 6.7	Exploration and Development Activities	16
Item 6.8	Production Estimates	17
Item 6.9	Production History	17-18
Form 51-101F2		19-20
Form 51-101F3		21-22

Glossary of Terms
Reserves	Estimated reserves of natural gas, natural gas liquids and crude oil.
Working interest	Those lands in which the Company receives its share acreage of net production revenues.
Gross reserves	Estimated reserves before royalties based on working interest.
Net reserves	Estimated reserves after royalties based on working interest
Future net revenue	Working interest revenues after royalties, development costs, production costs and well abandonment costs, but before administrative, overhead and other such indirect costs. Future net revenue may be presented either before or after tax.
Proved reserves	Reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable reserves	Reserves that are less certain than proved reserves at being recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves
Developed reserves	Reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
Developed producing reserves	Reserves that are expected to be recovered from completion intervals open at the time of estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
Developed non-producing reserves	Reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
stb or stock tank barrel	A 42-gallon barrel of crude oil at standard conditions of temperature and pressure.
mbbl	1,000 barrels of oil and/or natural gas liquids.
MMBtu	A unit of heat equal to one million British thermal units.
mcf	1,000 cubic feet of natural gas.
bbl or barrel	42 U.S. gallons liquid volume of crude oil or natural gas liquids.
Undeveloped reserves	Reserves that are expected to be recovered from known accumulation where a significant expenditure is required to render them capable of production (e.g. in comparison to the cost of drilling a well). Such reserves must fully meet the requirements of the reserves classification to which they are assigned (proved or probable).

Form 51-101F1

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION FOR SHELLBRIDGE OIL & GAS, INC.

This is the form referred to in item 1 of section 2.1 of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

We commenced operations on October 1, 2005, when certain assets of Dynamic Oil & Gas, Inc. (“Dynamic”) were transferred to us upon the completion of a Plan of Arrangement. The Plan of Arrangement resulted in, amongst other things, the shareholders of Dynamic obtaining cash and voting common shares in our capital.

The information in this report is as at December 31, 2005 and is the first disclosure of our reserves since the effective date of the Plan of Arrangement (September 30, 2005). As a result, there is no historical reserves information of a comparative or reconciling nature.

The following information is related to our reserves, future net revenue and discounted value of future net cash flow of natural gas, natural gas liquids, light/medium crude oil and heavy crude oil. Sproule Associates Limited (“Sproule”), independent qualified evaluators of Calgary, Alberta estimated these reserves effective December 31, 2005. We used these reserves in the preparation of our Financial Statements for the fiscal year ended December 31, 2005.

All our reserves are in Saskatchewan, Alberta and British Columbia, Canada.

The reserves on our properties described herein are estimates only. Actual reserves on our properties may be greater or less than those calculated.

The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the Sproule evaluation will be attained, and variances could be material. Assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables.

The following tables provide reserves data and a breakdown of future net revenue by commodity and reserve category using forecast prices and costs and/or constant prices and costs, based on our working interest portion before royalties (gross) and/or after royalties (net) (see “Glossary of Terms”).

The pricing used in tables that reflect constant and forecast price evaluations is set forth in Items 3.1 and 3.2, respectively.

Item 2.1 Reserves Data (Constant Prices and Costs)

Item 2.1(1)

The following table shows our gross and net reserves by reserve category using constant prices and costs.

Summary of Reserves
Based on Constant Prices and Costs
	Light and						Natural Gas
	Medium Oil		Heavy Oil		Natural Gas⁽¹⁾		Liquids
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Reserve Category	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mmcf)	(mmcf)	(mbbl)	(mbbl)
Proved
Developed producing	5	5	745	593	623	460	-	-
Developed non-
producing	-	-	66	54	377	294	6	5
Undeveloped	-	-	260	210	562	412	-	-`
Total proved	5	5	1,071	857	1,562	1,166	6	5
Probable	2	2	1,118	896	904	686	7	5
Total proved + probable	7	7	2,189	1,753	2,466	1,852	13	10

⁽¹⁾Includes solution gas.

Item 2.1(2)

The following table shows the net present values of the future net revenue of our net reserves by reserve category using constant prices and costs.

Summary of Net Present Values of Future Net Revenue
Based on Constant Prices and Costs
($000’s)	Before Income Taxes		After Income Taxes
	Annual Discount Rate		Annual Discount Rate
Reserve Category	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	18,145	15,300	16,184	13,416
Probable	17,008	12,110	12,676	8,475
Total proved plus probable	35,153	27,410	28,860	21,891

Item 2.1(3)(a)
and (b)

The following table shows the net present values of the future net revenue of our net reserves by reserve category using constant prices and costs, undiscounted.

Total Future Net Revenue – Undiscounted

Based on Constant Prices and Costs

($000’s)

Well

Future Net

Abandonment

Revenue

Future Net

Reserve

Operating

Development

and Other

Before Income

Income

Revenue After

Category

Revenue

Royalties

Costs

Taxes

Income Taxes

Proved

53,626

12,233

14,896

4,035

1,399

21,063

3,461

17,602

Proved

plus

probable

100,045

22,448

27,030

8,996

2,480

39,091

8,462

30,629

Item 2.2(3)(c)

The following table shows the net present value of future net revenue of our net reserves by reserve category using forecast prices and costs before deducting future income tax expense, discounted at 10%.

Future Net Revenue by Production Group
Based on Forecast Prices and Costs
($000’s)		Future Net Revenue Before Income
Reserves Category	Production Group	Taxes – Discounted Annually @ 10%
Proved reserves	Light and medium crude oil ⁽¹⁾	81
	Heavy oil ⁽¹⁾	12,358
	Natural gas ⁽²⁾	5,814
Proved plus probable	Light and medium crude oil ⁽¹⁾	98
	Heavy oil ⁽¹⁾	23,037
	Natural gas ⁽²⁾	8,436

⁽¹⁾	Includes solution gas and associated by-products.
⁽²⁾	Includes associated by-products but excluding solution gas from oil wells.

Item 2.3	Reserves Disclosure Varies with Accounting

	We have no subsidiary interests.

Item 2.4	Future Net Reserves Disclosure Varies with Accounting

	We have no subsidiary interests.

Item 3.1	Constant Prices Used in Estimates

	The following table shows benchmark reference prices that have been used by Sproule in evaluating our reserves.

Summary of Pricing Assumptions
Based on Constant Prices and Costs
		Crude Oil			Natural Gas
		WTI	Hardisty	Cromer	Natural Gas ⁽¹⁾	Butanes
Year		Cushing	Heavy	Medium	AECO Gas	FOB Field	Exchange
		Oklahoma	12^oAPI	29.3^oAPI	Prices	Gate	Rate ⁽²⁾
Historical		($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/MMBtu)	($Cdn/bbl)	($US/$Cdn)
Dec. 31,	2000	26.83	6.11	32.58	13.34	46.69	0.667
Dec. 31,	2001	19.78	15.47	22.41	3.64	16.73	0.628
Dec. 31,	2002	31.23	16.20	41.95	5.97	38.91	0.634
Dec. 31,	2003	32.56	23.32	36.39	6.88	37.73	0.771
Dec. 31,	2004	44.04	15.26	32.10	6.78	39.78	0.832
Forecast
Dec. 31,	2005	61.04	30.86	52.28	9.99	59.32	0.860

⁽¹⁾	This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
⁽²⁾	Exchange rates used to generate the benchmark reference prices in this table.

Notes: Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale.

Item 3.2

Forecast Prices Used in Estimates

The following table shows historical and future pricing and inflation rate assumptions used by Sproule in evaluating our reserves.

Summary of Pricing and Inflation Rate Assumptions
Based on Forecast Prices and Costs
	Crude Oil			Natural Gas	Natural Gas Liquids
	WTI	Edmonton	Cromer	Natural Gas ⁽¹⁾	Pentanes	Butanes
Year	Cushing	Par Price	Medium	AECO Gas	plus FOB	FOB Field	Inflation	Exchange
	Oklahoma	40^oAPI	29.3^oAPI	Prices	Field Gate	Gate	Rates	Rate ⁽³⁾
Historical	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/MMBtu)	($Cdn/bbl)	($Cdn/bbl)	%/Yr ⁽²⁾	($US/$Cdn)
2001	25.94	39.06	31.56	6.23	42.46	27.93	2.0	0.646
2002	26.09	40.12	35.46	4.04	40.80	25.39	2.7	0.637
2003	31.14	43.23	37.53	6.66	44.16	34.55	2.5	0.716
2004	41.42	52.91	45.72	6.87	53.91	41.37	2.5	0.825
2005	56.45	69.28	57.38	8.58	69.13	45.20	1.6	0.850
Forecast
2006	60.81	70.07	59.62	11.58	71.77	47.01	2.5	0.850
2007	61.61	70.99	60.39	10.84	72.71	47.62	2.5	0.850
2008	54.60	62.73	53.48	8.95	64.25	42.08	2.5	0.850
2009	50.19	57.53	49.18	7.87	58.92	38.59	1.5	0.850
2010	47.76	54.65	46.75	7.57	55.97	36.66	1.5	0.850
Thereafter	Various Escalation Rates

⁽¹⁾	This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
⁽²⁾	Inflation rates for forecasting prices and costs.
⁽³⁾	Exchange rates used to generate the benchmark reference prices in this table.

Notes: Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale.

Item 4.1 Reserves Reconciliation

Item 4.1(1)

As we first-commenced operations on October 1, 2005, we do not have historical information of a comparative or reconciling nature versus our December 31, 2005 reserves.

Item 4.2 Future Net Revenue Reconciliation

As we first-commenced operations on October 1, 2005, we do not have historical information of a comparative or reconciling nature versus our December 31, 2005 reserves.

Item 5.1 Undeveloped Reserves

Item 5.1(1)

As we first-commenced operations on October 1, 2005, we do not have historical information of a comparative or reconciling nature versus our December 31, 2005 reserves.

Proved Undeveloped Reserves (Gross) as at December 31, 2005 – Constant Prices and Costs
Light and Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids
(mbbl)	(mbbl)	(mmcf)	(mbbl)
-	260	562	-

Of our total proved reserves as at December 31, 2005, 26% were undeveloped. Most of our undeveloped proved reserves are located where there is capital required to tie in tested wells. A portion of these projects has already been completed in the first quarter of 2006 and the remaining projects are expected for completion by the end of 2006. One of the projects is not scheduled for completion until the currently-producing zone is depleted.

Item 5.1(2) Probable Undeveloped Reserves

As we first-commenced operations on October 1, 2005, we do not have historical information of a comparative or reconciling nature versus our December 31, 2005 reserves.

Of our total probable reserves as at December 31, 2005, we had 590.7 mbbls of heavy crude oil, 29 mmcf of solution gas and 220 mmcf of natural gas that were classified as undeveloped. In aggregate, probable undeveloped reserves comprised 49.5% of our total probable reserves.

In estimating all our probable reserves, the capital spending required to develop such reserves has been factored into Fiscals 2006 and 2007.

Item 5.2 Significant Factors and Uncertainties

The process of evaluating reserves is inherently complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. These factors and assumptions include among others: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulation; and (viii) other government levies imposed over the life of the reserves.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions. Revisions to reserve estimates can arise from changes in year-end prices, reservoir performance and geologic conditions or production. These revisions can be either positive or negative.

Item 5.3 Future Development Costs

The table below sets out the future development costs deducted in the estimation of future net revenue attributable to proved reserves (using both constant and forecast prices and costs) and proved plus probable reserves (using forecast prices only).

Future Development Costs
	Total Proved	Total Proved	Total Proved Plus Probable
($000’s)	Estimated Using	Estimated Using	Estimated Using
Period	Constant Prices and Costs	Forecast Prices and Costs	Forecast Prices and Costs
2006	3,943	3,943	6,136
2007	90	92	2,860
Total for all years
- undiscounted	4,033	4,035	8,996
- 10% discounted	3,972	3,974	8,518

The future development costs are capital expenditures required in the future for us to convert proved undeveloped reserves and probable reserves into proved developed producing reserves.

On an ongoing basis, we will typically use internally-generated cash flow from operations, debt (where deemed appropriate) and new equity issues if available on favourable terms to finance our capital investment program. When financing corporate acquisitions, we may also assume certain future liabilities.

Item 6.1 Oil and Gas Properties and Wells

Item 6.1(1) Important Properties, Plants, Facilities and Installations

The following is information describing our important properties, plants, facilities and equipment.

Cypress/Chowade, British Columbia	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, approximately 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 Three Month Period Ended December 31, 2005	During the period, we averaged 1.0 mmcf/d from four producing gas wells or approximately 17% of our total production. Production operations were maintained during the period without significant capital expenditures.

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, British Columbia	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 Aged 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 has the potential to contribute to long-term growth.

Geological Description	The area is prospective for natural gas exploration and development in Cretaceous Aged Bluesky sandstone reservoirs and Mississippian and Devonian Aged 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 standing potential Bluesky gas well. Both wells are cased and standing awaiting further evaluation and area development.

	Two major pipeline systems terminate at the edges 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 Three Month Period Ended December 31, 2005	We signed a farm-out agreement with an industry third party requiring them to drill one exploration test well on the property.

Fiscal 2006 Outlook	Subject to rig availability, the third party has committed, at their cost, to drill the exploration test well in the first quarter of 2006, targeting gas in the Bluesky formation. We will retain a 15% gross overriding royalty in the well, converting to a 50% working interest upon payout of their initial capital expenditures.

Rigel, British Columbia	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	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.

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

Activities During the Three Month Period Ended December 31, 2005	We signed a farm-in agreement to earn a 40% working interest in 3,380 gross acres by drilling two commitment wells. We drilled the first commitment well and cased it as a potential gas well during the period.

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 first quarter.

Mantario East, Saskatchewan	Mantario East is located 30 kilometers southwest of the Town of Kindersley, Saskatchewan 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.

Wells 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 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 Three Month Period Ended December 31, 2005	We drilled one (0.5 net) successful Viking gas well, one (0.8 net) successful horizontal heavy oil well and one (0.8 net) unsuccessful exploration well. In addition, we completed construction of our heater-treater facility at 75% working interest. We began operations on October 1, 2005 at an initial production rate of approximately 750 boe/d from nine (6.5 net) producing heavy oil wells. By the end of the period, we had increased production to approximately 1,430 boe/d from 16 producing heavy oil wells (11 net) or 90% of our total exit rate production.

	The 13.2⁰API oil at Mantario East is classified by regulation as Basal Mannville heavy-gravity crude. The nearest analogs to our heavy oil discovery is located directly west of us on non-company lands at Marengo, Mantario North, and Mantario East. The Mantario East pools have produced over three million barrels of heavy oil from 36 wells in pool sizes of approximately 800 acres. On our lands at Mantario East, the number of pools and their sizes has not yet been determined.

Fiscal 2006 Outlook	We have budgeted to drill 11 (8.3 net) development in-fill and field- delineation wells targeting Basal Mannville oil. Of the 11 wells, one horizontal well commenced drilling in late 2005, two other horizontal and three vertical wells are scheduled for drilling in the first quarter. The remaining five 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 development 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/d of gas from two (1.5 net) existing non-associated gas wells and from recovered solution gas currently being sent to flare at our oil battery. The gas gathering and field compression facility is scheduled for completion in the first quarter.

	Funds have also been budgeted to acquire additional lands and seismic data in the area.

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

Item 6.1(2) Oil and Gas Wells

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2005. The stated interests are subject to landowner’s and other royalties, where applicable, in addition to usual crown royalties and mineral taxes. All the following wells are located in the British Columbia and Saskatchewan, as noted.

	Producing				Non-Producing
	Oil		Natural Gas		Oil		Natural Gas
	Gross ⁽¹⁾	Net ⁽²⁾	Gross ⁽¹⁾	Net ⁽²⁾	Gross ⁽¹⁾	Net ⁽²⁾	Gross ⁽¹⁾	Net ⁽²⁾

British Columbia
Cypress/
Chowade	-	-	4	1.8	-	-	2	0.6
Orion	-	-	-	-	-	-	2	1.0
Rigel	-	-	-	-	-	-	1	0.4

Saskatchewan
Mantario
East	16	10.5	-	-	3	2.3	2	1.5
Elmore	3	.2	-	-	-	-	-	-
Rapdan	1	.1	-	-	-	-	-	-
Flaxcombe	-	-	-	-	-	-	1	0.5
Sandgren	-	-	-	-	-	-	-	-
Total	20	10.8	4	1.8	3	2.3	8	4.0

⁽¹⁾	“Gross” wells are defined as the total number of wells in which we have an interest.
⁽²⁾	“Net” wells are defined as the aggregate of the numbers obtained by multiplying each gross well by our percentage working interest therein.

Item 6.2 Undeveloped Properties Having No Attributed Reserves

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

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, approximately 77% is undeveloped.

Fiscal 2006 Outlook	We have no current plans to explore unproved acreage in Fiscal 2006.

Orion, British Columbia	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 Aged 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 has the potential to contribute to long-term growth.

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.

Fiscal 2006 Outlook	We have no current plans to explore unproved acreage in Fiscal 2006.

Fraser Valley (Under Moratorium)	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 Three Month Period 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 have been continuing 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 a reserve estimate of 6.5 trillion cubic feet of natural gas. A commercial quantity of gas is yet to be discovered in the area.

	We have no current plans to explore unproved acreage in Fiscal 2006.

Item 6.3 Forward Contracts

We have no forward contracts as at December 31, 2005.

Item 6.4 Additional Information Concerning Abandonment and Reclamation Costs

The following table discloses the abandonment and reclamation costs of our anticipated costs at December 31, 2005, calculated on an undiscounted and a 10% discount rate with a portion thereof anticipated for settlement in each of the next three years. We currently anticipate incurring abandonment and reclamation costs in respect of 32.3 net wells, one compressor and one battery site.

Abandonment and Reclamation Costs Net of Salvage Value
($000s)	2006	2007	2008	2009	2010	2011	2012	Remainder	Total	Discounted
*Facility Type*										at 10%
Plant	0	0	0	0	0	0	0	33,000	33,000	13,995

Well	59,667	15,000	216,143	208,500	116,663	335,490	351,698	324,034	1,627,195	667,056

Total	59,667	15,000	216,143	208,500	116,663	335,490	351,698	357,034	1,660,195	681,051

Item 6.5 Tax Horizon

We commenced operations on October 1, 2005 and as of the close of our first quarter ended December 31, 2005, we were not required to pay income taxes. Based on management’s current expectations, income taxes may become payable in Fiscal 2006.

Item 6.6 Costs Incurred

The following table summarizes the capital expenditures made by us on oil and natural gas properties for the three months ended December 31, 2005.

Costs Incurred
Property Acquisition Costs		Exploration Costs	Development Costs
(M$)		(M$)	(M$)
Proved Properties	Unproved Properties
-	241	1,245	2,641

We own interests in certain properties located in the Western Provinces of Canada. They are as follows:

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

Item 6.7 Exploration and Development Activities

The following table sets forth the number of exploratory and development wells which we completed during the three month period ended December 31, 2005.

	Exploratory Wells		Development Wells
	Gross ⁽¹⁾	Net ⁽²⁾	Gross ⁽¹⁾	Net ⁽²⁾
Oil Wells	-	-	1	0.8
Gas Wells	1	0.5	1	0.1
Dry Holes	1	0.8	-	-
Total Completed Wells	2	1.3	2	0.9

⁽¹⁾	“Gross” wells are defined as the total number of wells in which we have an interest.
⁽²⁾	“Net” wells are defined as the aggregate of the numbers obtained by multiplying each gross well by our percentage working interest therein.

Item 6.8 Production Estimates

The following table sets forth our estimated total production volumes for Fiscal 2006. Our fields at Mantario East are the only fields that individually meet or exceed 20% of our estimated total production.

	Light & Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids
Total Proved	(mbbl)	(mbbl)	(mmcf)	(mbbl)
All Fields	365	534,968	499,989	-
Mantario East	-	534,968	220,825	-

Item 6.9 Production History

Item 6.9(1)

As we first-commenced operations on October 1, 2005, we do not have historical production information of a comparative nature for quarters prior to our first quarter ended December 31, 2005.

The following table sets forth certain information in respect of production, product prices received, royalties, production costs and netbacks received by us for the three months ended December 31, 2005.

	Three Months Ended
	Dec. 31, 2005
Average Daily Production
Light and Medium Oil (bbl/d)	-
Heavy Oil (bbl/d)	916
Natural Gas (mcf/d)	927
Natural Gas Liquids (bbl/d)	-
Average Net Prices Received(1)
Light and Medium Oil ($/bbl)	-
Heavy Oil ($/bbl)	30.36
Natural Gas ($/mcf)	11.92
Natural Gas Liquids ($/bbl)	-
Royalties
Light and Medium Oil ($/bbl)	-
Heavy Oil ($/bbl)	7.77
Natural Gas ($/mcf)	2.68
Natural Gas Liquids ($/bbl)	-
Production Costs
Light and Medium Oil ($/bbl)	-
Heavy Oil ($/bbl)	9.00
Natural Gas ($/mcf)	2.91
Natural Gas Liquids ($/bbl)	-
Netback Received
Light and Medium Oil ($/bbl)	-
Heavy Oil ($/bbl)	13.59
Natural Gas ($/mcf)	6.33
Natural Gas Liquids ($/bbl)	-

⁽¹⁾Unit production cost measures by reserve category require certain allocations to by-products.

Item 6.9(2)

The following table shows our total production before royalties during the three month period ended December 31, 2005 from our core property, Mantario East.

	Light & Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids
Total Proved	(mbbl)	(mbbl)	(mmcf)	(mbbl)
Mantario East	-	84	-	-

Form 51-101F2

REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR OR AUDITOR

Report on Reserves Data

To the Board of Directors of Shellbridge Oil & Gas, Inc. (the “Company”):

1.	We have evaluated the Company’s Reserves Data as at December 31, 2005. The reserves data consist of the following:

	(a)(i)		proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs; and

	(ii)		the related estimated future net revenue; and

	(b)(i)		proved oil and gas reserve quantities were estimated as at December 31, 2005 using constant prices and costs; and

	(ii)		the related estimated future net revenue.

2.	The Reserves Data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Reserves Data based on our evaluation.

	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us as of December 31, 2005, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s management and Board of Directors:

Independent			Net Present Value of Future Net Revenue
Qualified				(10% Discount Rate)
Reserves	Description	Location of
Evaluator or	and Preparation Date	Reserves	Audited	Evaluated	Reviewed	Total
Auditor	of Evaluation Report	(Country)	(M$)	(M$)	(M$)	(M$)
Sproule	Evaluation of the P&NG	Canada
	Reserves of Shellbridge
	Oil & Gas, Inc., as of
	December 31, 2005,
	prepared November
	2005 to January 2006.
Total			Nil	31,572	Nil	31,572

5.	In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook.

6.	We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.

7.	Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

Sproule Associates Limited
Calgary, Alberta
January 27, 2006

“Cameron P. Six”
Cameron P. Six, P.Eng.
Associate

“Michael W. Maughan”
Michael W. Maughan, C.P.G., P.Geol.
Manager, Geoscience, & Associate

“Harry J. Helwerda”
Harry J. Helwerda, P.Eng.
Vice-President, Engineering

Form 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

This is the form referred to in item 3 of section 2.1 of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). This form does not apply in British Columbia

1.	Terms to which a meaning is ascribed in NI 51-101 have the same meaning in this form.

2.	The report referred to in item 3 of section 2.1 of NI 51-101 shall in all material respects be as follows:

Report of Management and Directors On Reserves Data and Other Information

Management of Shellbridge Oil & Gas, Inc. (the “Company”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

	a)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 using forecast prices and costs;

	b)	the related estimated future net revenue;

	c)	proved oil and gas reserves estimated as at December 31, 2005 using constant prices and costs; and

	d)	the related estimated future net revenue.

Sproule Associates Limited, an independent qualified reserves evaluator, has evaluated the Company’s reserves data. The report of Sproule Associates Limited is presented above on Form 51-101F2.

The Reserves Audit Committee of the Board of Directors of the Company has:

	a)	reviewed the Company’s procedures for providing information to Sproule Associates Limited;

	b)	met with Sproule Associates Limited to determine whether any restrictions affected the ability of Sproule Associates Limited to report without reservation; and

	c)	reviewed the reserves data with Management and Sproule Associates Limited.

The Reserves Audit Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with Management. The Board of Directors has, on the recommendation of the Reserves Audit Committee, approved:

	a)	the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

	b)	the filing of the report of Sproule Associates Limited on the reserves data; and

	c)	the content and filing of this report.

The reserves data are based on judgements regarding future events. Actual results may vary and the variations may be material.

“Wayne J. Babcock”
_______________________________
Wayne J. Babcock
President & Chief Executive Officer

“Michael A. Bardell”
_______________________________
Michael A. Bardell
Chief Financial Officer

“William B. Thompson”
_______________________________
William B. Thompson
Director

“John Greig”
_______________________________
John Greig
Director

Summary of Net Present Values of Future Net Revenue
Based on Forecast Prices and Costs
($000’s)		Before Income Taxes					After Income Taxes
Reserve		Annual Discount Rate					Annual Discount Rate
Category	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Proved
Developed
producing	13,428	12,669	12,014	11,442	10,937	12,280	11,533	10,892	10,332	9,840
Developed
non-producing	3,169	2,990	2,831	2,690	2,563	1,989	1,854	1,735	1,630	1,537
Undeveloped	4,466	3,887	3,408	3,005	2,663	3,333	2,800	2,363	2,001	1,696
Total proved	21,063	19,546	18,253	17,137	16,163	17,602	16,187	14,990	13,963	13,073
Probable	18,028	15,382	13,319	11,671	10,330	13,027	10,794	9,087	7,751	6,682
Total proved
plus probable	39,091	34,928	31,572	28,808	26,493	30,629	26,981	24,077	21,714	19,755

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