Exhibit 99.5

NuLoch Resources Inc.
STATEMENT OF RESERVES DATA
AND OTHER OIL AND GAS INFORMATION
FORM 51-101F1
Effective December 31, 2010

This Statement of Reserves Data and Other Oil and Gas Information is designed to provide the disclosures prescribed in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (NI 51-101). This document was prepared by the management of NuLoch Resources Inc. (the Company) with an effective date of December 31, 2010 with information available up to February 14, 2011. Certain of the information contained herein has been derived from a report entitled “Reserve Estimation and Economic Evaluation — December 31, 2010” (the AJM Report) as prepared by AJM Petroleum Consultants (AJM) dated February 15, 2011. AJM is a Qualified Reserves Evaluator as defined pursuant to NI 51-101.

Reserves Definitions

The crude oil, natural gas and natural gas products reserves estimates presented in the AJM Report have been based on the definitions and guidelines prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society) as presented in the Canadian Oil and Gas Evaluators Handbook (COGE Handbook). A summary of those definitions is presented below.

Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:

	•		analysis of drilling, geological, geophysical and engineering data;
	•		the use of established technology; and
	•		specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

Reserves are classified according to the degree of certainty associated with the estimates.

	•		Proved reserves are those 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 are those additional reserves that are less certain to be recovered than proved reserves. 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.
	•		Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Development and Production Status

Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories:

	•		Developed reserves are those 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
	•		Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the 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 are those 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.
	•		Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest-level sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

	•		at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
	•		at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and
	•		at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

Net Present Value Estimates

The net present values of the crude oil, natural gas and natural gas products reserves were obtained by employing future production and revenue analyses. The future crude oil production was generally predicated on the anticipated performance characteristics of the individual wells and reservoirs in question. The future natural gas production was also predicated on the anticipated performance characteristics of the individual wells and reservoirs in question with an allowance for any gas sales contract or gas processing facility restrictions. In those areas where shut-in natural gas reserves exist, the commencement of production was based on the proximity to a pipeline connection and the relevant factors relating to the future marketing of the reserves. The future production of gas-cap reserves was assumed to occur near the end of the oil producing life. Solution gas production was based on the forecast of the oil producing rates and current and forecast sales gas-oil ratios. The natural gas products production forecasts were based on the anticipated recoveries of these products from the produced natural gas.

The Company’s share of future crude oil revenue was derived by employing the Company’s share of production and the indicated reference crude oil price less the historical quality and transportation price differential for each respective field. The indicated natural gas prices with an adjustment for the heating value of the gas were employed to calculate the Company’s share of future natural gas revenues. The indicated reference natural gas products prices with adjustments to reflect historical price differentials realized by the Company in each respective property were employed to calculate the Company’s share of future natural gas products revenues. Royalties and mineral taxes payable to the Crown were estimated based on the methods in effect as of December 31, 2010. Freehold and overriding royalties payable to others were estimated based on the indicated applicable rates. In those cases where a

proportionate share of the natural gas gathering and processing charges were indicated to be payable by the Crown or royalties owned by others, these charges have been deducted in determining the net royalties payable.

In all cases, estimates of the applicable capital expenditures and operating costs were deducted in arriving at the Company’s share of future net revenues. An allowance for future well abandonment costs was made for all of the Company’s existing working interest wells, however, no allowance was made for the reclamation of well sites or the abandonment and reclamation of any facilities. To the extent that undeveloped reserves are assigned to undrilled locations, then both abandonment and reclamation costs are factored into the forecast future net revenues associated with those locations. The net present values were then obtained by employing 5, 10, 15 and 20 percent nominal annual discount rates compounded annually.

Presentation of Reserve Information

“Gross” reserves are the company working interest share before deduction of royalties.

“Net” reserves are the company working interest share after deduction of royalties.

General and administrative expenses and overhead recoveries are not deducted in the determination of future net revenues.

Use of Barrels of Oil Equivalent (boe)

Disclosure provided herein in respect of boe units may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf of natural gas to 1 bbl of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Significant Risk Factors and Uncertainties

Estimating reserves is forecasting the future and is inherently uncertain. The reserve and recovery information contained in the AJM Report are only estimates and the actual production and reserves may be different than the estimates prepared by AJM. When estimating reserves, AJM considers a number of factors and makes assumptions including, among others:

-		historical production compared with production rates from similar properties;

-		assumptions regarding initial production and subsequent decline rates;

-		ultimate recovery of reserves;

-		assumptions about future commodity prices, development and operating costs;

-		the effect of governmental regulation, royalty and tax regimes;

-		timing and amount of capital expenditures; and

-		forecasts of results of future development activity.

These factors and assumptions were based on information at the date the evaluation was prepared. Many of these factors are subject to change and are beyond the Company’s control. If these factors and assumptions prove to be inaccurate, the actual results may vary materially from the reserve and cash flow estimates. Results may be less than those contained in the evaluation to the extent that forecast development activities do not achieve the level of success assumed in the evaluation.

Caution to Reader

The following tables set forth certain information relating to the oil and natural gas reserves of the Company and the present value of the estimated future net revenue associated with such reserves, and is derived from the AJM Report. It should not be assumed that the estimated present worth values of net production revenue contained in the following tables represents the fair market value of the reserves. There is no assurance that the price and cost assumptions contained herein will be attained and variances could be material.

Certain tables may not add due to rounding.

Abbreviations

Certain terms and abbreviations used in this document are defined below:

“bbl”		barrel of oil or NGL;
“bcf”		billion cubic feet of natural gas;
“bpd”		barrel of oil or NGL per day;
“boe”		barrel of oil equivalent determined by converting a volume of      natural gas to barrels using the ratio of 6 Mcf to one barrel;
“boe/d”		barrel of oil equivalent per day;
“Company”		NuLoch Resources Inc.;
“Mbbl”		thousand barrels;
“Mboe”		thousand barrels of oil equivalent;
“Mcf”		thousand cubic feet of natural gas;
“Mcfe”		Mcf of gas equivalent determined by converting a volume of      oil or NGL to
		Mcf using the ratio of 0.1667 barrels to 1 Mcf;
“Mcf/d”		thousand cubic feet of natural gas per day;
“MMcf”		million cubic feet of natural gas;
“MMcf/d”		million cubic feet of natural gas per day;
“NGLs”		natural gas liquids;
“$US”		United States dollar;
“$C”		Canadian dollar.

Conversion

In this document measurements are given in standard Imperial or metric units only. The following table sets forth certain standard conversions.

To Convert From		To		Multiply By
Mcf		cubic metres			28.174
cubic metres		cubic feet			35.494
bbls		cubic metres			0.159
cubic metres		bbls			6.290
feet		metres			0.305
metres		feet			3.281
miles		kilometers			1.609
kilometers		miles			0.621
acres		hectares			0.405
hectares		acres			2.471

Summary of Oil and Natural Gas Reserves
as of December 31, 2010
Forecast Prices and Costs

		Light and
		Medium Oil								Heavy Oil								Natural Gas(1)								NGLs								MBOE
		Mbbl																MMcf								Mbbl								MBOE
Reserves Category		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
CANADA
Proved
Developed Producing			775.3				624.2				8.0				7.2				2,574.8				2,093.4				1.6				1.1				1,214.0				981.4
Developed Non-Producing			260.0				242.4				—				—				429.2				299.6				2.2				1.2				333.8				293.5
Undeveloped			1,217.0				1,086.1				—				—				4,084.9				3,264.9				0.4				0.2				1,898.3				1,630.5
Total Proved			2,252.3				1,952.8				8.0				7.2				7,088.9				5,657.8				4.3				2.5				3,446.0				2,905.4
Probable			1,258.1				1,084.6				5.8				5.1				4,033.4				3,219.7				1.9				1.1				1,938.0				1,627.5
Total Proved plus Probable			3,510.4				3,037.4				13.8				12.3				11,122.3				8,877.6				6.1				3.6				5,384.0				4,532.9
UNITED STATES
Proved
Developed Producing			369.5				299.4				—				—				35.0				28.9				—				—				375.4				304.2
Developed Non-Producing			189.4				153.6				—				—				—				—				—				—				189.4				153.6
Undeveloped			2,282.4				1,817.9				—				—				—				—				—				—				2,282.4				1,817.9
Total Proved			2,841.3				2,270.9				—				—				35.0				28.9				—				—				2,847.4				2,275.7
Probable			1,767.3				1,411.9				—				—				27.1				22.3				—				—				1,771.8				1,415.6
Total Proved plus Probable			4,608.6				3,682.7				—				—				62.1				51.3				—				—				4,618.9				3,691.3
TOTAL
Proved
Developed Producing			1,144.8				923.6				8.0				7.2				2,609.8				2,122.3				1.6				1.1				1,589.4				1,285.6
Developed Non-Producing			449.4				396.0				—				—				429.2				299.6				2.2				1.2				523.2				447.1
Undeveloped			3,499.4				2,904.0				—				—				4,084.9				3,264.9				0.4				0.2				4,180.6				3,448.4
Total Proved			5,093.6				4,223.7				8.0				7.2				7,123.9				5,686.8				4.3				2.5				6,293.2				5,181.1
Probable			3,025.4				2,496.4				5.8				5.1				4,060.5				3,242.1				1.9				1.1				3,709.8				3,043.1
Total Proved plus Probable			8,119.0				6,720.1				13.8				12.3				11,184.4				8,928.9				6.1				3.6				10,003.0				8,224.1

 

Note:

(1)

Natural gas volumes include associated, non-associated and solution gas.

Net Present Value of Future Net Revenue
Before Income Taxes Discounted at %/Year
as of December 31, 2010
Forecast Prices and Cost

																						Unit Value
																						Before
																						Income
																						Taxes
																						Discounted at
		0%				5%				10%				15%				20%				10%/year(1)
Reserves Category		(M$)				(M$)				(M$)				(M$)				(M$)				($/boe)
CANADA
Proved
Developed Producing			48,725.2				36,626.3				29,367.0				24,639.2				21,328.9				29.92
Developed Non-Producing			19,005.1				12,076.7				8,600.1				6,547.8				5,193.1				29.30
Undeveloped			68,016.6				36,487.3				20,528.3				11,371.4				5,626.9				12.59
Total Proved			135,746.8				85,190.3				58,495.4				42,558.4				32,148.9				20.13
Probable			133,865.0				54,061.3				29,212.6				18,482.4				12,751.6				17.95
Total Proved plus Probable			269,611.8				139,251.6				87,708.0				61,040.8				44,900.5				19.35
UNITED STATES
Proved
Developed Producing			17,813.4				13,587.1				11,018.7				9,352.0				8,188.4				36.22
Developed Non-Producing			10,474.0				7,557.1				6,038.3				5,102.0				4,461.1				39.32
Undeveloped			77,536.5				39,893.5				21,293.0				10,589.2				3,781.4				11.71
Total Proved			105,823.9				61,037.7				38,350.1				25,043.2				16,430.9				16.85
Probable			121,932.0				49,362.1				25,717.0				15,212.7				9,554.4				18.17
Total Proved plus Probable			227,755.9				110,399.7				64,067.1				40,255.9				25,985.3				17.36
TOTAL
Proved
Developed Producing			66,538.6				50,213.4				40,385.8				33,991.3				29,517.3				31.41
Developed Non-Producing			29,479.1				19,633.8				14,638.4				11,649.8				9,654.2				32.74
Undeveloped			145,553.1				76,380.7				41,821.3				21,960.6				9,408.3				12.13
Total Proved			241,570.7				146,228.0				96,845.5				67,601.6				48,579.8				18.69
Probable			255,797.0				103,423.3				54,929.6				33,695.1				22,305.9				18.05
Total Proved plus Probable			497,367.7				249,651.3				151,775.1				101,296.7				70,885.8				18.45

 

Note:

(1)

The unit values are based on net reserve values.

Net Present Value of Future Net Revenue
After Income Taxes Discounted at %/Year
as of December 31, 2010
Forecast Prices and Cost

		0%				5%				10%				15%				20%
Reserves Category		(M$)				(M$)				(M$)				(M$)				(M$)
CANADA
Proved
Developed Producing			48,725.2				36,626.3				29,367.0				24,639.2				21,328.9
Developed Non-Producing			19,000.0				12,075.7				8,599.9				6,547.7				5,193.1
Undeveloped			49,612.7				27,714.9				15,877.4				8,711.3				4,018.1
Total Proved			117,337.9				76,416.9				53,844.3				39,898.2				30,540.1
Probable			98,349.6				39,964.9				21,840.1				14,014.5				9,812.6
Total Proved plus Probable			215,687.5				116,381.8				75,684.4				53,912.8				40,352.7
UNITED STATES
Proved
Developed Producing			17,813.4				13,587.1				11,018.7				9,352.0				8,188.4
Developed Non-Producing			10,474.0				7,557.1				6,038.3				5,102.0				4,461.1
Undeveloped			77,536.5				39,893.5				21,293.0				10,589.2				3,781.4
Total Proved			105,823.9				61,037.7				38,350.1				25,043.2				16,430.9
Probable			121,932.0				49,362.1				25,717.0				15,212.7				9,554.4
Total Proved plus Probable			227,755.9				110,399.7				64,067.1				40,255.9				25,985.3
TOTAL
Proved
Developed Producing			66,538.6				50,213.4				40,385.8				33,991.3				29,517.3
Developed Non-Producing			29,474.0				19,632.8				14,638.2				11,649.8				9,654.2
Undeveloped			127,149.2				67,608.4				37,170.4				19,300.5				7,799.5
Total Proved			223,161.8				137,454.6				92,194.4				64,941.4				46,971.0
Probable			220,281.6				89,327.0				47,557.1				29,227.2				19,367.0
Total Proved plus Probable			443,443.4				226,781.5				139,751.5				94,168.7				66,338.0

Total Future Net Revenue
(Undiscounted)
as of December 31, 2010
Forecast Prices and Costs

																														Future
																						Future Net								Net
																		Abandonment				Revenue								Revenue
																		and				Before								After
										Operating				Development				Reclamation				Income				Income				Income
		Revenue(1)				Royalties(1)				Costs				Costs				Costs				Taxes				Taxes				Taxes
Reserves Category		(M$)				(M$)				(M$)				(M$)				(M$)				(M$)				(M$)				(M$)
CANADA
Proved Reserves			287,253.3				37,965.4				59,946.8				45,714.6				7,879.6				135,746.8				18,408.9				117,337.9
Proved Plus Probable Reserves			504,219.6				67,079.5				108,316.1				50,745.5				8,466.7				269,611.8				53,924.3				215,687.5
UNITED STATES
Proved Reserves			230509.2				23,973.0				46,643.3				51,415.8				2,653.3				105,823.9				—				105,823.9
Proved Plus Probable Reserves			412793.8				42,930.6				76,399.2				62,971.3				2,736.9				227,755.9				—				227,755.9
TOTAL
Proved Reserves			517762.5				61,938.4				106,590.1				97,130.4				10,532.9				241,570.7				18,408.9				223,161.8
Proved Plus Probable Reserves			917013.4				110,010.1				184,715.3				113,716.8				11,203.6				497,367.7				53,924.3				443,443.4

 

Note:

(1)

Revenue on United States’ properties is calculated on a net revenue interest and in Canada is calculated on gross company interest.

Future Net Revenue
By Production Group
as of December 31, 2010
Forecast Prices and Costs

		Future Net Revenue
		Before Income Taxes
		(Discounted at 10%/yr)				Unit Value
		(M$)				($/boe)
Proved Reserves
Light and Medium Crude Oil (including solution gas and other by-products)			94,940.9				22.39
Heavy Oil (including solution gas and other by-products)			175.0				21.87
Natural Gas (including by-products but excluding solution gas and by-products from oil wells)			1,729.6				1.85
Total			96,845.5				18.69
Proved Plus Probable Reserves
Light and Medium Crude Oil (including solution gas and other by-products)			146,250.1				21.68
Heavy Oil (including solution gas and other by-products)			281.3				20.49
Natural Gas (including by-products but excluding solution gas and by-products from oil wells)			5,243.7				3.58
Total			151,775.1				18.45

AJM employed the following pricing, exchange rate and inflation rate assumptions in estimating the net present value of the future net revenue of the Company’s reserves data using forecast prices and costs as of December 31, 2010.

Summary of Pricing and Inflation Rate Assumptions

		Crude Oil								Natural Gas				Other Factors
						Edmonton
		WTI @ Cushing				City Gate				AECO				Exchange Rate
Year		$US/bbl				$CDN/bbl				$CDN/Mcf				$US/$C				Inflation %
Historical
2006			66.06				73.34				6.54				0.88				2.0	%
2007			72.38				77.09				6.44				0.92				2.1	%
2008			99.58				102.83				8.18				0.95				2.4	%
2009			61.78				66.21				3.96				0.87				0.3	%
2010			79.35				77.77				4.01				0.97				1.7	%
Forecast
2011			85.00				82.80				4.10				1.00				0.0	%
2012			89.25				88.80				4.60				0.98				2.0	%
2013			91.55				94.05				5.20				0.95				2.0	%
2014			95.50				98.15				5.50				0.95				2.0	%
2015			102.85				105.80				5.75				0.95				2.0	%
2016			110.40				113.70				6.20				0.95				2.0	%
2017			112.60				116.05				6.55				0.95				2.0	%
2018			114.85				118.35				7.00				0.95				2.0	%
2019			117.15				120.75				7.30				0.95				2.0	%
2020			119.50				123.15				7.45				0.95				2.0	%
2021			121.90				125.60				7.60				0.95				2.0	%
Thereafter			2.0	%			2.0	%			2.0	%			0.95				2.0	%

In 2010, the Company received net weighted average selling prices of $75.04 per barrel for oil and natural gas liquids and $4.06 per Mcf for natural gas.

Reconciliation of Gross Reserves by Country
as of December 31, 2010
Forecast Prices and Costs

The following tables set forth a reconciliation of the Company’s total gross proved, probable and proved plus probable reserves as at December 31, 2010 against such reserves as at December 31, 2009 based on forecast price and cost assumptions:

		Light And Medium Oil												Heavy Oil												Natural Gas(1)
										Gross												Gross												Gross
										Proved												Proved												Proved
		Gross				Gross				Plus				Gross				Gross				Plus				Gross				Gross				Plus
		Proved				Probable				Probable				Proved				Probable				Probable				Proved				Probable				Probable
Factors		(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(Mbbl)				(MMcf)				(MMcf)				(MMcf)
CANADA
December 31, 2009			455.2				178.5				633.7				16.0				6.8				22.8				8,281.7				4,301.6				12,583.3
Acquisitions			—				—				—				—				—				—				—				—				—
Extensions			1,923.9				1,083.8				3,007.7				—				—				—				—				—				—
Technical Revisions			25.8				(1.5	)			24.3				(1.4	)			(0.9	)			(2.3	)			(465.9	)			(284.7	)			(750.6	)
Economic Factors			0.1				0.1				0.2				—				(0.1	)			(0.1	)			(136.3	)			17.6				(118.7	)
Dispositions			(6.7	)			(2.8	)			(9.5	)			—				—				—				(3.0	)			(1.1	)			(4.1	)
Gross Production			(146.0	)			—				(146.0	)			(6.6	)			—				(6.6	)			(587.6	)			—				(587.6	)
December 31, 2010			2,252.3				1,258.1				3,510.4				8.0				5.8				13.8				7,088.9				4,033.4				11,122.3
UNITED STATES
December 31, 2009			350.7				313.8				664.4				—				—				—				24.7				20.2				45.0
Acquisitions			17.4				8.8				26.2				—				—				—				—				—				—
Extensions			2,466.8				1,380.1				3,846.9				—				—				—				7.6				7.3				14.8
Technical Revisions			78.8				64.2				142.9				—				—				—				8.6				(0.5	)			8.1
Economic Factors			(0.2	)			1.2				1.0				—				—				—				—				—				—
Dispositions			—				—				—				—				—				—				—				—				—
Gross Production			(72.2	)			—				(72.2	)			—				—				—				(5.8	)			—				(5.8	)
December 31, 2010			2,841.3				1,768.0				4,609.3				—				—				—				35.0				27.1				62.1
TOTAL
December 31, 2009			805.9				492.3				1,298.2				16.0				6.8				22.8				8,306.4				4,321.8				12,628.3
Acquisitions			17.4				8.8				26.2				—				—				—				—				—				—
Extensions			4,390.7				2,463.9				6,854.6				—				—				—				7.6				7.3				14.8
Technical Revisions			104.5				62.7				167.2				(1.4	)			(0.9	)			(2.3	)			(457.3	)			(285.2	)			(742.5	)
Economic Factors			(0.1	)			1.3				1.2				—				(0.1	)			(0.1	)			(136.3	)			17.6				(118.7	)
Dispositions			(6.7	)			(2.8	)			(9.5	)			—				—				—				(3.0	)			(1.1	)			(4.1	)
Gross Production			(218.2	)			—				(218.2	)			(6.6	)			—				(6.6	)			(593.4	)			—				(593.4	)
December 31, 2010			5,093.6				3,026.1				8,119.7				8.0				5.8				13.8				7,123.9				4,060.5				11,184.4

Note:

Additional Information Relating to Reserves Data

Significant Factors or Uncertainties

The process of estimating reserves is complex. It requires significant judgments 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 natural gas prices and costs change. The reserve estimates contained herein are based on AJM’s production forecasts, prices and economic conditions at the time of preparation of the AJM Report.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required over time due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.

The Company does not anticipate any unusually high development costs or operating costs, the need to build a major pipeline or other major facility before production of reserves can begin, or contractual obligations to produce and sell a significant portion of production at prices substantially below those which could be realized but for those contractual obligations.

Undeveloped Reserves

Natural Gas

Most of the proved undeveloped and probable undeveloped natural gas reserves are located in the shallow natural gas Second White Specks (“SWS”) formation located at Enchant, Alberta. The Company has 38 wells producing from this formation at Enchant. AJM has reviewed the landholdings and geological mapping across the area and has assigned 6.25 gross sections as having proved undeveloped and probable undeveloped reserves based on the proximity of these sections to current producing wells. These undrilled proved and probable reserve assignments have been assigned using statistical averages. Proved undeveloped reserves from 25 (25.0 net) locations total 3,375 MMcf with a further 1,688 MMcf assigned as probable. In addition to these 25 undrilled SWS locations, there are nine (8.9 net) producing SWS wells in which additional unperforated intervals have been assigned proved undeveloped and probable undeveloped reserves totalling 710 MMcf and 355 MMcf, respectively. The bulk of these undeveloped reserves were first assigned in 2005 and 2006. Development of these proved and probable undeveloped reserves is estimated to occur in 2013 and 2015. The total capital required is $8,516,000 although the project can be broken into smaller functional units.

Light and Medium Oil

In Divide County, North Dakota, AJM has reviewed the landholdings and geological mapping across the area and has assigned proved developed reserves to 53 Bakken and Three Forks Sanish oil wells. Generally, additional proved undeveloped reserves have been assigned to each of these 53 wells in the form of a second well on the same section of land and in the form of a third well in acreage that directly offsets the drilled section. In addition to these locations, probable undeveloped reserves have been assigned to 21 locations based on their proximity to the proved locations. The average working interest is approximately 8.8%. Proved undeveloped light and medium oil reserves of 2,104 Mbbls have been assigned to 106 proved locations. Probable assignments on those wells total 714 Mbbls. The 21 probable undeveloped locations total a further 619 Mbbls. Costs to develop the 106 proved locations total $49 million and the nine probable locations total $11 million and are estimated to occur over the years 2011 to 2013.

In Burke County, North Dakota, AJM has reviewed the landholdings and geological mapping across the area and has assigned proved developed reserves to four Bakken and Three Forks Sanish oil wells. Four locations have been assigned proved undeveloped reserves. In addition to these locations, probable undeveloped reserves have been assigned to one location based on its proximity to the proved locations. The average working interest is approximately 18.6%. Proved undeveloped light and medium oil reserves of 179 Mbbls have been assigned to four proved locations. Probable assignments on those wells total 38 Mbbls and the single probable location is assigned 90 Mbbls. Costs to develop the five undeveloped locations are $5 million and are estimated to occur in 2011 and 2012.

In Tableland Saskatchewan, AJM has reviewed the landholdings and geological mapping across the area and has assigned proved developed reserves to 10 Three Forks Sanish oil wells. Fourteen locations have been assigned proved undeveloped reserves. In addition to these locations, probable undeveloped reserves have been assigned to two locations based on their proximity to the proved locations. The average working interest is approximately 75%. Proved undeveloped light and medium oil reserves of 1,217 Mbbls have been assigned to 14 proved locations. Probable assignments on those wells total 518 Mbbls. The two probable undeveloped locations total a further 268 Mbbls. Costs to develop the 14 proved locations total $32 million and the two probable locations total $5 million and are estimated to occur in 2011 and 2012.

The following tables present the undeveloped reserves that were first attributed in each of the most recent three financial years and, in the aggregate, before that time.

Proved Undeveloped Reserves — Gross

		Light & Medium Oil								Natural Gas								Natural Gas Liquids
		Mbbls								MMcf								Mbbls
Year first		First								First								First
attributed		Attributed				Cumulative				Attributed				Cumulative				Attributed				Cumulative
Prior thereto			—				—				5,033				5,033				15				15
2008			—				—				—				3,680				—				—
2009			174				174				405				4,085				2				2
2010			3,417				3,499				—				4,085				—				—

Probable Undeveloped Reserves — Gross

		Light & Medium Oil								Natural Gas								Natural Gas Liquids
		Mbbls								MMcf								Mbbls
Year first		First								First								First
attributed		Attributed				Cumulative				Attributed				Cumulative				Attributed				Cumulative
Prior thereto			—				—				2,883				2,883				10				10
2008			—				—				—				1,840				—				—
2009			208				208				203				2,043				2				2
2010			2,122				2,275				—				2,043				—				—