January 7, 2010 - 6-K: Report of foreign issuer [Rules 13a-16 and 15d-16]

Natural Gas
	Mcf	1,000 cubic feet
	MMcf	1,000,000 cubic feet
	Mcf/d	1,000 cubic feet per day
Oil and Natural Gas Liquids
	Bbl	Barrel
	Mbbls	1,000 barrels
	Blpd	Barrels of liquid per day
	Boe	Barrel of oil equivalent (1)
	Bpd	Barrels per day
	Boepd	Barrels of oil equivalent per day
	Bopd	Barrels of oil per day
	NGLs	Natural gas liquids

(1)	A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By

Mcf	cubic metres	28.317
Metres	cubic feet	35.494
Bbls	cubic metres	0.159
Cubic metres	Bbls	6.289
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometers	1.609
Kilometers	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471

PART 1

DATE OF STATEMENT

Item 1.1 Relevant Dates:

1.	Date of Statement:	December 15, 2009

2.	Effective Date of Statement:	August 31, 2009

3.	Preparation Date of Statement:	December 2, 2009

PART 2

DISCLOSURE OF RESERVES DATA

In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, Sproule Associates Limited (“Sproule”) prepared a report (the “Sproule Report”) dated August 31, 2009. The Sproule Report evaluated 100% of Eagleford Energy Inc.’s (“Eagleford” or the “Company”) natural gas reserves, as at August 31, 2009. The tables below are summaries of the Company’s natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Sproule Report based on forecast price and cost assumptions. The tables summarize the data contained in the Sproule Report and as a result may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to the Company’s reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by Sproule. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Company’s reserves estimated by Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The Sproule Report is based on certain factual data supplied by the Company and Sproule’s opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Company’s natural gas property and contracts (except for certain information residing in the public domain) were supplied by the Company to Sproule and accepted without and further investigation. Sproule accepted this data as presented and neither title searches nor field inspections were conducted.

The Company’s interest covered by this report is located in the Province of Alberta, Canada.

All monetary references contained in this Statement of Reserves Data and Other Oil and Gas Information are in Canadian dollars unless otherwise specified.

Item 2.1 Reserves Data (Forecast Prices and Costs):

1. Breakdown of Reserves ((Forecast Case):

Table 1 attached– Forecast prices

2. Net Present Value of Future Net Revenue (Forecast Case):

Table 2 attached – Forecast prices

3. Additional Information Concerning Future Net Revenue (Forecast Case):

Table 3 attached – Forecast prices

Table 4 attached – Forecast prices

Item 2.2 Supplemental Disclosure of Reserves Data (Constant Prices and Costs):

Not Applicable

Item 2.3 Reserves Disclosure Varies With Accounting:

Not Applicable

Item 2.4 Future Net Revenue Disclosure Varies With Accounting:

Not Applicable

PART 3

PRICING ASSUMPTIONS

Item 3.1 Constant Prices Used in Supplemental Estimates:

Not Applicable

Item 3.2 Forecasted Prices Used in Estimates:

Table 5 attached – Forecast Prices (as determined by Sproule Associates Limited).

The weighted average historical natural gas price received by Eagleford for the year ended August 31, 2009was $3.42/Mcf.

PART 4

RECONCILIATION OF CHANGES IN RESERVES

Item 4.1 Reserves Reconciliation

Table 6 attached – Forecast Prices

PART 5

ADDITIONAL INFORMATION RELATING TO RESERVES DATA

Item 5.1 Undeveloped Reserves:

1. Proved Undeveloped Reserves:

Not Applicable

2. Probable Undeveloped Reserves:

Not Applicable

Item 5.2 Significant Factors or Uncertainties:

The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economics 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 changes. 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, reserves estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required for 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 geological conditions or production. These revisions can be either positive or negative.

Item 5.3 Future Development Costs:

Not Applicable

PART 6

OTHER OIL AND GAS INFORMATION

Item 6.1 Oil and Gas Properties and Wells:

1. Properties, Plants, Facilities and Installations

Properties: For the fiscal year ended August 31, 2009 the Company held a 5.1975% working interest in a natural gas unit located in the Botha area Northwest, near the town of Manning, Alberta and a 0.5% overriding royalty in a natural gas well located in the Haynes area of Alberta, Canada.

Acreage. The following table sets forth the developed and undeveloped acreage of the projects in which the Company holds an interest, on a gross and a net basis as of August 31, 2008. The developed acreage is stated on the basis of spacing units designated by provincial authorities and typically on the basis of 160 acre spacing unit for oil production and 640 acre spacing unit for gas production in Alberta. Our acreage is located in Alberta, Canada.

August 31	2009		2008		2007
Alberta, Canada	Gross	Net	Gross	Net	Gross	Net
Leasehold Acreage-Developed	8,320	432.43	Nil	Nil	Nil	Nil
Leasehold Acreage-Undeveloped	Nil	Nil	Nil	Nil	Nil	Nil

2. Producing and Non Producing Wells:

The following table sets forth the number of Eagleford’s gross and net wells natural gas producing and non-producing as of August 31, 2009. A gross well is a well in which the Company owns an interest. A net well represents the fractional interest the Company owns in gross wells.

August 31	2009		2008		2007
Alberta, Canada	Gross	Net	Gross	Net	Gross	Net
Natural Gas Wells-Producing	3	5.1975	Nil	Nil	Nil	Nil
Natural Gas Wells-Non Producing	6	5.1975	Nil	Nil	Nil	Nil

Item 6.2 Properties With No Attributed Reserves:

Not Applicable

Item 6.3 Forward Contracts:

The Company has no forward contracts.

Item 6.4 Additional Information Concerning Abandonment and Reclamation Costs:

The Company bases its estimates for costs of abandonment and reclamation of surface leases and wells on previous experience with similar well site locations and area terrain. The Company believes that its range of estimates at $30,000 gross per well for abandonment and reclamation costs are reasonable and applicable to its wells. The Company’s independent engineering evaluator has also estimated similar costs in deriving the Company’s estimate of future net revenue. Ultimately all wells in the natural gas unit will require abandonment and reclamation. The total of such costs estimated for 5.1975 net wells for the fiscal year ended August 31, 2009 was $12,474 and $2,080 calculated using a discount rate of 10% percent. The Company does not expect to pay abandonment and reclamation costs over the next 3 fiscal years.

Item 6.5 Tax Horizon:

The Company has non-capital losses of $525,825 at August 31, 2009 and does not anticipate paying significant income taxes in the near term.

Item 6.6 Costs Incurred:

Nil.

Item 6.7 Exploration and Development Activities:

Not applicable

Item 6.8 Production Estimates:

The following table indicates the volume of production estimated for the first year reflected in the estimates of gross proved reserves and gross probable reserves based on forecast prices and costs.

Property	Associated and Non-Associated Gas (MMcf) Proved	Associated and Non-Associated Gas (MMcf) Probable
Botha, Alberta	27	1

Item 6.9 Production History:

1.	The following table sets forth certain information in respect of production, product prices received, production costs and netbacks received by the Company for each quarter of fiscal 2009.

Production History	Fiscal 2009
	August 31	May 31	February 28	November 30
Average Daily Production
Natural gas (Mcf per day)	84	94	2	-
Average Commodity Prices
Natural gas ($/Mcf)	$2.99	$3.80	$4.86	$8.57
Royalties
Natural gas ($/Mcf)	0.64	0.62	1.68	-
Production Costs
Natural gas ($/Mcf)	2.90	3.61	6.80	-
Netback by Product
Natural gas ($/Mcf)	$(0.55)	$(0.43)	$(3.62)	$8.57

2. The following table indicates the Company’s total production for fiscal 2009 from its core property.

Property	Associated and Non-Associated Gas (MMcf)
Botha, Alberta	16
Haynes, Alberta	-

2009/11/2510:53:08 -17617

National Instrument 51-101

Table 1 NI 51-101 Summary of Oil and Gas Reserves as of August 31, 2009 Forecast Prices and Costs
Reserves
	Light and Medium Oil		Heavy Oil		Natural Gas (non-associated & associated)		Natural Gas Liquids
Reserve Category	Gross (Mbbl)	Net (Mbbl)	Gross (Mbbl)	Net (Mbbl)	Gross (MMcf)	Net (MMcf)	Gross (Mbbl)	Net (Mbbl)
Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable	0.0 0.0 0.0 0.0 0.0 0.0	0.0 0.0 0.0 0.0 0.0 0.0	0.0 0.0 0.0 0.0 0.0 0.0	0.0 0.0 0.0 0.0 0.0 0.0	248 0 0 248 91 339	177 0 0 177 59 236	0.0 0.0 0.0 0.0 0.0 0.0	0.0 0.0 0.0 0.0 0.0 0.0

Reference: Item 2.2(1) of Form 51-101 F1

2009/11/2510:53:08 -17617

National Instrument 51-101

Table 2 NI 51-101 Summary of Net Present Values of Future Net Revenue as of August 31, 2009 Forecast Prices and Costs
Reserves Category	Net Present Values of Future Net Revenue
	Before Income Taxes Discounted at (%/Year)					Bef Tax Net Val 10%/yr ($/boe)
	0 (M$)	5 (M$)	10 (M$)	15 (M$)	20 (M$)	Bef Tax Net Val 10%/yr ($/boe)
Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable	605 0 0 605 256 861	433 0 0 433 129 561	333 0 0 333 75 407	269 0 0 269 48 317	226 0 0 226 34 260	11.28 0.00 0.00 11.28 7.64 10.38

Reference Item 2.2(2) of Form 51-101F1

Notes:	NPV of FNR include all resource income: Sale of oil, gas, by-product reserves Processing third party reserves Other income	Income Taxes: Includes all resource income Apply appropriate income tax calculations Include prior tax pools
	Unit Values are based on net reserve volumes

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2009/11/2510:53:08 -17617

National Instrument 51-101

Table 3 NI 51-101 Total Future Net Revenue Undiscounted as of August 31, 2009 Forecast Prices and Costs
Reserves Category	Revenue (M$)	Royalties (M$)	Operating Costs (M$)	Development Costs (M$)	Well Abandonment / Other Costs (M$)	Future Net Revenue Before Income Taxes ($/boe)
Proved Proved Plus Probable	1,888 2,766	460 717	815 1,179	0 0	7 8	605 861

Reference Item 2.2(3)(b) of Form 51-101F1

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2009/11/2510:53:08 -17617

National Instrument 51-101

Table 4 NI 51-101 Net Present Value of Future Net Revenue by Production Group as of August 31, 2009 Forecast Prices and Costs
Reserves Category	Production Group	Future Net Revenue Before Income Taxes (Discounted at 10% Year) (M$)	Unit Value Before Income Taxes (Discounted at 10% Year) ($/boe)
Proved	Light and Medium Crude Oil (including solution gas and associated by-products) Heavy Oil (including solution gas and associated by-products) Natural Gas (including associated by-products)*	0 0 333	0 0 11.28
Proved Plus Probable	Light and Medium Crude Oil (including solution gas and associated by-products) Heavy Oil (including solution gas and associated by-products) Natural Gas (including associated by-products)*	0 0 407	0 0 10.38

Reference Item 2.1 (3)(c) of Form 51-101F1

* Includes corporate Capital GCA, if applicable

Unit Values are based on net reserve volumes

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2009/11/2510:53:08 -17617

National Instrument 51-101

Table 5 NI 51-101 Summary of Pricing and Inflation Rate Assumptions as of August 31, 2009 Forecast Prices and Costs
Year	WTI Cushing Oklahoma ($US/bbl)	Edmonton Par Price 40° API ($Cdn/bbl)	Cromer Medium 29.3° API ($Cdn/bbl)	Natural Gas1 AECO Gas Prices ($Cdn/MMBtu)	Pentanes Plus FOB Field Gate ($Cdn/bbl)	Butanes F.O.B. Field Gate ($Cdn/bbl)	Inflation Rate2 (%/Yr)	Exchange Rate3 ($US/$Cdn)

Historical
2004 2005 2006 2007 2008	41.42 56.46 66.09 72.27 99.59	52.91 69.29 73.30 77.06 102.85	45.72 57.36 62.35 65.36 93.05	6.87 8.58 7.16 6.65 8.15	53.91 69.13 75.03 77.33 104.70	41.37 45.20 59.32 63.71 75.09	1.4 1.3 1.5 2.0 1.0	0.770 0.826 0.882 0.935 0.943

Forecast
2009 2010 2011 2012 2013	71.47 77.03 80.20 84.62 92.01	77.61 83.76 87.27 89.62 94.97	73.73 78.74 80.28 81.55 85.48	3.65 5.50 6.44 6.78 7.50	79.48 85.78 89.37 91.78 97.27	54.95 62.43 65.04 66.80 70.79	2.0 2.0 2.0 2.0 2.0	0.900 0.900 0.900 0.925 0.950
Thereafter				Escalation Rate of 2%

(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.

Reference Item 3.2 of Form 51-101F1

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National Instrument 51-101

Table 6

NI 51-101

Reconciliation of Company Gross(1) Reserves (Before Royalty)

by Principal Product Type

As of August 31, 2009

Forecast Prices and Costs

(1) Gross Reserves means the Company's working interest reserves before calculation of royalties, and before consideration of the Company's royalty interests.

Reference: Item 4.1 of Form 51-101F1

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Appendix A- Page 1

Appendix A - Definitions

The following definitions form the basis of our classification of reserves and values presented in this report. They have been prepared by the Standing Committee on Reserves Definitions of the Petroleum Society of the CIM ("CIM"), incorporated in the Society of Petroleum Evaluation Engineers ("SPEE") Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and specified by National Instrument 51-101 ("NI 51-101").

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;

·	specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed; and

·	a remaining reserve life of 50 years.

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

1. Proved Reserves

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.

2. Probable 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.

3. Possible 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. Possible reserves have not been considered in this report.

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Appendix A- Page 2

Other criteria that must also be met for the categorization of reserves are provided in Section 5.5 of the CaGE Handbook.

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

4. Developed Reserves

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 (e.g., 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.

5. Developed Producing Reserves

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.

6. Developed Non-Producing Reserves

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.

7. Undeveloped Reserves

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., 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.

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Appendix A- Page 3

8. Levels of Certainty for Reported Reserves

The qualitative certainty levels contained in the definitions in Sections 1, 2 and 3 are applicable to individual reserves entities, which refers to the lowest level at which reserves estimates are made, and to reported reserves, which refers to the highest level sum of individual entity estimates for which reserve estimates are made.

Reported total reserves estimated by deterministic or probabilistic methods, whether comprised of a single reserves entity or an aggregate estimate for multiple entities, should target the following levels of certainty under a specific set of economic conditions:

a. There is a 90% probability that at least the estimated proved reserves will be recovered.

b. There is a 50% probability that at least the sum of the estimated proved reserves plus probable reserves will be recovered.

c. There is a 10% probability that at least the sum of the estimated proved reserves plus probable reserves plus possible reserves will be recovered.

A quantitative measure of the probability associated with a reserves estimate is generated only when a probabilistic estimate is conducted. The majority of reserves estimates will be performed using deterministic methods that do not provide a 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 Section 5.5.3 of the COGE Handbook. Whether deterministic or probabilistic methods are used, evaluators are expressing their professional judgment as to what are reasonable estimates.

9. Remaining Recoverable Reserves are the total remaining recoverable reserves associated with the acreage in which the Company has an interest.

10. Company Gross Reserves are the Company's working interest share of the remaining reserves, before deduction of any royalties.

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Appendix A- Page 4

11. Company Net Reserves are the gross remaining reserves of the properties in which the Company has an interest, less all Crown, freehold, and overriding royalties and interests owned by others.

12. Net Production Revenue is income derived from the sale of net reserves of oil, non associated and associated gas, and gas by-products, less all capital and operating costs.

13. Fair Market Value is defined as the price at which a purchaser seeking an economic and commercial return on investment would be willing to buy, and a vendor would be willing to sell, where neither is under compulsion to buy or sell and both are competent and have reasonable knowledge of the facts.

14. Barrels of Oil Equivalent (BOE) Reserves – BOE is the sum of the oil reserves, plus the gas reserves divided by a factor of 6, plus the natural gas liquid reserves, all expressed in barrels or thousands of barrels. Equivalent reserves can also be expressed in thousands of cubic feet of gas equivalent (McfGE) using a conversion ratio of 1 bbl:6 Mcf.

15. Oil (or Crude Oil) – a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non hydrocarbons, but does not include liquids obtained from the processing of natural gas.

16. Gas (or Natural Gas) – a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs, but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.

17. Non-Associated Gas – an accumulation of natural gas in a reservoir where there is no crude oil.

18. Associated Gas – the gas cap overlying a crude oil accumulation in a reservoir.

19. Solution Gas – gas dissolved in crude oil.

20. Natural Gas Liquids – those hydrocarbon components that can be removed from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate, and small quantities of non-hydrocarbons.

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Appendix B- Page 1

Appendix B - Prices (As of August 31, 2009)

Sproule's short-term outlook for oil and gas prices adopts the NYMEX futures market for the forecast period ending August 31, 2012. The forecast used in this evaluation was derived as of August 31, 2009, and reflects the arithmetic average of the futures market at the close of trading each day, for the month prior to the Termination of Trading date for a September contract. The oil price forecasts are based on the NYMEX Division light, sweet (low-sulphur) crude oil futures contract, which specifies the West Texas Intermediate crude as a deliverable, and the gas price forecasts are based on the NYMEX Division Henry Hub natural gas futures contract.

The NYMEX oil and gas futures prices are the foundation of Sproule's energy pricing models in the early years. This data is combined with Sproule's assumptions respecting long-term prices, inflation rates, and exchange rates, together with estimates of transportation costs and prices of competing fuels, to forecast wellhead and plantgate prices for Canadian oil, natural gas, and natural gas by-product production. The following paragraphs briefly describe some of the key considerations included in Sproule's long-term outlook for oil and natural gas price forecasts.

Oil Prices

In the long term, the price of oil will be governed by supply and demand, and the degree that OPEC is able to manage supply will be a major determinant in establishing oil prices for the next 10 years. A strong demand for crude oil, instability in the Middle East, and the increasing cost of exploration and development has served to increase the price of crude oil throughout the world. In recognition of these factors, Sproule's long-term forecast has been set at $85.00 US per barrel (2009 dollars).

Transmission costs, a significant item in forecasting Canadian wellhead prices, are expected to increase at rates that are generally less than the rate of inflation. The exchange rate ($U.S. per $Canadian) reflects a projection from 0.90 to 0.95.

The oil price forecasts set out in Table P-1 are based on a forecast of prices for West Texas Intermediate crude at Cushing, Oklahoma. The price of this marker crude is expected to directly reflect world oil prices over the forecast period. The Edmonton par price is for a 40 to 45 degree API crude having less than 0.5 percent sulphur. The actual wellhead price of oil will vary with the quality of the crude and the cost of the transportation from the wellhead to the trading hub in Edmonton. This cost, which is referred to as the price differential, is based on the actual difference between the revenue received at the wellhead and the Edmonton par price postings of major crude oil purchasers. In the absence of actual crude oil price statistics, the differential is based on the price of similar quality crude in the area.

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Appendix B- Page 2

Natural Gas Prices

The New York Mercantile Exchange (NYMEX) posted price for gas bought and sold at the Henry Hub in Louisiana has become a common index for Canadian natural gas producers with access to the American marketplace. In Alberta and Saskatchewan, the AECO price at Suffield is a reflection of the market price for natural gas sold locally, and the Sumas price on the British Columbia/ Washington border is critical to the BC producer.

Developing a balance between supply and demand for natural gas produced in Western Canada has proved a challenge to the Canadian producer, where drilling activity, which leads to gas well completions, must serve to replace declining gas well production and fill new or expanded pipeline systems. In the early 1990's, the Alberta, Saskatchewan and BC price of natural gas has often been suppressed, relative to the market opportunities in the United States, because local natural gas delivery exceeded the pipeline capacity leaving the provinces. Various new pipeline projects have provided sufficient market access to allow Western Canadian producers to double their production since 1986. With each new pipeline, the drilling activity expanded to ensure the pipeline was full and continued until a surplus in local productive capacity would once again depress the price of natural gas in the western provinces. An additional 1.1 Bcf per day of pipeline capacity completed during the 1998/99 winter, followed by 1.2 Bcf per day of capacity in the Alliance Pipeline, created additional market access for Canadian gas. This has strengthened the Canadian gas price and has created an integrated North American market. The average long-term price at Alberta AECO-C is approximately $Cdn 6.90 per MMBtu in real terms. In the United States, Sproule maintains a long-term threshold of $7.50 U.S. per MMBtu, in real terms. Detailed price schedules are set out in Table P-2. The actual plantgate price will vary with the heat content of the natural gas and the cost of transportation from the plantgate to the trading hub. In the absence of actual natural gas price statistics, the differential is based on the price of natural gas in the area.

The evaluation of uncontracted shut-in gas reserves in Western Canada considers the proximity to existing infrastructure, and the production start date varies with the magnitude of the reserves and the development plans of the operator. To the extent the plant and gathering facilities of sufficient capacity are currently available, the production start date is deferred a year or two and the economics of plant development may curtail the production of the reserves to an average daily rate of 1.0 MMcfpd per 3.5 Bcf of reserves. For reserves located in remote areas, or reserves that are considered of poor quality, the production start date is no earlier than 2012.

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Appendix B- Page 3

Natural Gas By-Products

Ethane, propane, butanes, and pentanes plus prices were forecast to continue their historic relationships with crude prices in major Eastern Canadian and U.S. market areas. Ethane prices are expected to increase from present levels at a rate that corresponds to the local Alberta spot price of gas. Sulphur prices reflect the current market. The price forecasts for natural gas by-products are set out in Table P-1. The prices for these by-products were adjusted in this report to reflect the actual prices received at the plantgate.

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Appendix B- Page 4

Table P-1 Summary of Price Forecasts and Inflation and Exchange Rates ($Cdn) Effective August 31, 2009
Year	Light Crude Oil				Heavy & Medium Oil					Natural Gas Liquids & Sulphur
Year	WTI Cushing Oklahoma 40° API ($US/bbl)	Edmonton Par Price 40° API ($/bbl)		Synthetic Crude Oil Edmonton 32° API ($/bbl)	Hardisty Heavy 12° API ($/bbl)	Hardisty Lloyd Blend 20.5° API ($/bbl)	Western Canada Select 20.5° API ($/bbl)	Cromer Medium 29.3° API ($/bbl)	Hardisty Bow River 24.9° API ($/bbl)	Ethane Plant Gate ($/bbl)	Edmonton Propane ($/bbl)	Edmonton Butane ($/bbl)	Edmonton Pentanes Plus ($/bbl)	Plant Gate Sulphur ($/LT)	Operating & Capital Cost Inflation Rate (%/Yr)	Exchange Rate ($US/$Cdn)
Historical
2002 2003 2004 2005 2006 2007 2008	26.09 31.14 41.42 56.46 66.09 72.27 99.59	40.12 43.23 52.91 69.29 73.30 77.06 102.85		107.11	27.58 27.39 30.40 34.35 43.32 44.77 76.32	30.59 31.16 36.18 42.79 50.30 51.93 82.58	43.83 50.57 52.24 83.62	35.46 37.53 45.72 57.36 62.35 65.36 93.05	31.85 33.00 37.98 45.62 51.54 53.16 83.85	11.20 18.44 19.05 23.78 19.83 18.42 22.59	20.36 32.97 35.95 38.54 44.09 49.53 58.80	25.39 34.55 41.37 45.20 59.32 63.71 75.09	40.80 44.16 53.91 69.13 75.03 77.33 104.70	12.71 41.32 40.42 41.26 19.30 38.02 303.84	2.7 2.5 1.4 1.3 1.5 2.0 1.0	0.637 0.716 0.770 0.826 0.882 0.935 0.943
Forecast
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019	71.47 77.03 80.20 84.62 92.01 93.85 95.72 97.64 99.59 101.58 103.61	77.61 83.76 87.27 89.62 94.97 96.89 98.85 100.84 102.88 104.96 107.08	80.11 86.26 89.77 92.12 97.47 99.39 101.35 103.34 105.38 107.46 109.58		65.97 70.36 69.81 69.90 72.18 73.64 75.12 76.64 78.19 79.77 81.38	68.30 72.87 72.43 73.49 76.93 78.48 80.07 81.68 83.33 85.02 86.73	68.30 72.87 72.43 73.49 76.93 78.48 80.07 81.68 83.33 85.02 86.73	73.73 78.74 80.28 81.55 85.48 87.20 88.96 90.76 92.59 94.46 96.37	70.62 75.39 76.79 77.97 81.68 83.33 85.01 86.73 88.48 90.26 92.09	10.13 15.24 17.85 18.79 20.77 21.24 21.73 22.22 22.72 23.23 23.76	46.03 52.44 54.63 56.10 59.45 60.66 61.88 63.13 64.41 65.71 67.03	54.95 62.43 65.04 66.80 70.79 72.22 73.68 75.16 76.68 78.23 79.81	79.48 85.78 89.37 91.78 97.27 99.23 101.23 103.28 105.36 107.49 109.66	25.00 25.50 52.02 53.06 81.18 82.81 84.46 86.15 87.87 89.63 91.42	2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0	0.900 0.900 0.900 0.925 0.950 0.950 0.950 0.950 0.950 0.950 0.950
Thereafter									Escalation Rate of 2.0%

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Appendix B- Page 5

Table P-2 Natural Gas Price Forecasts, Various Trading Points ($Cdn/MMbtu) Effective August 31, 2009
Year	Alberta Gas Reference Price Plant Gate	AECO-C Spot	Aggregator Intra-Alta	Alliance Pipeline	B.C. Average Wellhead	B.C. Westcoast Station 2	Huntingdon / Sumas 30-day Spot	Dawn	Henry Hub Price ($US/MMbtu)
Historical
2002 2003 2004 2005 2006 2007 2008	3.88 6.12 6.31 8.30 6.56 6.20 7.88	4.04 6.66 6.87 8.58 7.16 6.65 8.15	3.78 5.95 6.37 8.46 6.57 6.34 8.03	3.65 6.28 6.54 8.45 6.56 6.04 7.91	3.57 6.05 6.19 8.16 5.85 6.00 7.33	4.10 6.42 6.53 8.22 6.58 6.40 8.20	4.20 6.55 6.82 8.59 7.13 7.01 8.78	5.33 8.20 7.96 10.59 7.76 7.69 9.60	3.22 5.39 6.14 8.62 7.23 6.86 9.04

Forecast
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019	3.30 5.15 6.11 6.46 7.19 7.36 7.53 7.71 7.89 8.07 8.26	3.65 5.50 6.44 6.78 7.50 7.67 7.84 8.02 8.20 8.38 8.57	3.28 5.12 6.13 6.53 7.30 7.47 7.64 7.82 8.00 8.18 8.37	3.20 5.05 6.09 6.53 7.30 7.47 7.64 7.82 8.00 8.18 8.37	2.73 4.58 5.52 5.86 6.58 6.75 6.92 7.10 7.28 7.46 7.65	3.35 5.20 6.14 6.48 7.20 7.37 7.54 7.72 7.90 8.08 8.27	3.90 5.75 6.69 7.03 7.75 7.92 8.09 8.27 8.45 8.63 8.82	4.95 6.80 7.74 8.08 8.80 8.97 9.14 9.32 9.50 9.68 9.87	4.23 5.89 6.74 7.24 8.12 8.28 8.45 8.62 8.79 8.96 9.14
Thereafter					Escalation Rate of 2.0%

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Appendix C- Page 1

Appendix C – Abbreviations

This appendix contains a list of abbreviations that may be found in Sproule reports, as well as a table comparing Imperial and Metric units. Two conversion tables, used to prepare this report, are also provided.

Alberta Royalty Tax Credit

barrels of oil equivalent

barrels of oil per day

barrels of water per day

Crown

daily contract quantity

drilling spacing unit

Freehold

gas cost allowance

gas-oil ratio

gross overriding royalty

liquid petroleum gas

thousands of cubic feet of gas equivalent

thousands of cubic feet per day

maximum permissive rate

maximum rate limitation

'new' Crown

net carried interest

natural gas liquids

net overriding royalty

net profits interest

'old' Crown

overriding royalty interest

petroleum and natural gas

production spacing unit

pressure-volume-temperature

TransCanada Gas Services Limited

Unit Operating Cost Rates for operating gas cost allowance

working interest

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Appendix C- Page 2

Imperial Units			Metric Units
M (103) MM (106) B (109) T (1012)	one thousand million one billion one trillion	Prefixes	k (103) M (106) G (109) T (1012) E (1018)	one thousand million one billion one trillion one milliard
in. ft mi	inches feet mile	Length	cm m km	centimeters metres kilometers
ft2 ac	square feet acres	Area	m2 ha	square metres hectares
cf or ft3 scf gal Mcf Mcfpd MMcf MMcfpd Bcf bbl Mbbl stb bbl/d bbl/mo	cubic feet standard cubic feet gallons thousand cubic feet thousand cubic feet per day million cubic feet million cubic feet per day biIIion cubic feet ( 109) barrels thousand barrels stock tank barrel barrels per day barrels per month	Volume	m3 L m3 stm3 m3/d	cubic metres litres cubic metre stock tank cubic metres cubic metre per day
Btu	British thermal units	Energy	J MJ/m3 TJ/d	joules megajoules per cubic metre (106) terajoule per day (1012)
oz lb ton lt Mlt	ounce pounds ton long tons thousand long tons	Mass	g kg t	gram kilograms tonne
psi psla pslg	pounds per square inch pounds per square inch absolute pounds per square inch gauge	Pressure	Pa kPa	pascals kilopascals (103)
°F °R	degrees Fahrenheit degrees Rankine	Temperature	°C K	degrees Celsius Kelvin
M$	thousand dollars	Dollars	k$	thousand dollars
sec min hr day wk mo yr	second minute hour day week month year	Time	s min h d a	second minute hour day week month annum

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Appendix C- Page 3

Conversion Factors – Metric to Imperial

cubic metres (m3) (@ 15°C)	x 6.29010	= barrels (bbl) (@600F), water
m3 (@ 15°C)	x 6.3300	= bbl (@ 60°F), Ethane
m3 (@ 150C)	x 6.30001	= bbl (@ 60°F), Propane
m3 (@ 15°C)	x 6.29683	= bbl (@ 60°F), Butanes
m3 (@ 15°C)	x 6.29287	= bbl (@ 60°F), oil, Pentanes Plus
m3 (@ 101.325kPaa, 15°C)	x 0.0354937	= thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F)
1,000 cubic metres (103m3) (@101.325 kPaa, 15°C)	x 35.49373	= Mcf (@ 14.65 psia, 60°F)
hectares (ha)	x 2.4710541	= acres
1,000 square metres (103m2)	x 0.2471054	= acres
10,000 cubic metres (ha.m)	x 8.107133	= acre feet (ac-ft)
m3/103m3 (@ 101.325 kPaa, 15° C)	x 0.0437809	= Mcf/Ac.ft, (@ 14,65 psia, 60°F)
joules (j)	x 0.000948213	= Btu
megajoules per cubic metre (MJ/m3) (@ 101.325 kPaa, 15°C)	x 26.714952	= British thermal units '" standard cubic foot (Btu/scf) (@ 14,65 psia, 60°F)
dollars per gigajoule ($/GJ)	x 1.054615	= $/Mcf (1,000 Btu gas)
metres (m)	x 3.28084	= feet (ft)
kilometres (km)	x 0.6213712	= miles (mi)
dollars per 1,000 cubic metres ($/103m3)	x 0.0288951	= dollars per thousand cubic feet ($/Mcf) (@ 15.025 psia) B,C.
($/103m3)	x 0.02817399	= $/Mcf (@14,65psia)Alta.
dollars per cubic metre ($/m3)	x 0.158910	= dollars per barrel ($/bbl)
gas/oil ratio (GOR) (m3/m3)	x 5.640309	= GOR (scf/bbl)
kilowatts (kW)	x 1.341022	= horsepower
kilopascals (kPa)	x 0.145038	= psi
tonnes (t)	x 0.9842064	= long tons (LT)
kilograms (kg)	x 2.204624	= pounds (Ib)
litres (L)	x 0.2199692	= gallons (Imperial)
litres (L)	x 0.264172	= gallons (U.S.)
cubic metres per million cubic metres (m3/106m3) (C3)	x 0.177496	= barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia)
m3/106m3) (C4)	x 0.1774069	= bbl/MMcf (@ 14,65 psia)
m3/106m3) (C5+)	x 0.1772953	= bbl/MMcf (@ 14,65 psia)
tonnes per million cubic metres (t/106m3) (sulphur)	x 0.0277290	= LT/MMcf (@ 14,65 psia)
millilitres per cubic meter (mL/m3) (C5+)	x 0.0061974	= gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf)
(mL/m3) (C5+)	x 0.0074428	= gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf)
Kelvin (K)	x 1.8	= degrees Rankine (°R)
millipascal seconds (mPa's)	x 1.0	= centipoise
barrels (bbl) (@ 60°F)	x 0.15898	= cubic metres (m3) (@ 15°C), water
bbl (@ 60°F)	x 0.15798	= m3 (@ 15°C), Ethane
bbl (@ 60°F)	x 0.15873	= m3 (@ 15°C), Propane
bbl (@ 60°F)	x 0.15881	= m3 (@ 15°C), Butanes
bbl (@ 60°F)	x 0.15891	= m3 (@ 15°C), oil, Pentanes Plus

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Appendix C- Page 4

thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F)	x 28.17399	= m3 (@ 101.325 kPaa, 15°C)
Mcf (@ 14,65 psia, 60°F)	x 0.02817399	= 1,000 cubic metres (103m3) (@ 101.325 kPaa, 15°C)
acres	x 0.4046856	= hectares (ha)
acres	x 4.046856	= 1,000 square metres (103m2)
acre feet (ac-ft)	x 0.123348	= 10,000 cubic metres (104m3) (ha.m)
Mcf/ac-ft (@ 14.65 psia, 60°F)	x 22.841028	= 10'm3/m3 (@ 101.325 kPaa, 15°C)
Btu	x 1054.615	= joules (J)
British thermal units per standard cubic foot (Btu/Scf) (@14.65 psia, 60°F )	x 0.03743222	= megajoules per cubic metre (MJ/m3) (@ 101.325 kPaa, 15°C)
$/Mcf (1,000 Btu gas)	x 0.9482133	= dollars per gigajoule ($/GJ)
$/Mcf (@ 14.65 psia, 60°F) Alta.	x 35.49373	= $/103m3 (@ 101.325 kPaa, 15°C)
$/Mcf (@ 15.025 psia, 60°F), B.C.	x 34.607860	= $/10'm3 (@ 101.325 kPaa, 15°C)
feet (ft)	x 0.3048	= metres (m)
miles (mi)	x 1.609344	= kilometres (km)
$/bbl	x 6.29287	= $/m3 (average for 30°-50° API)
GOR (scf/bbl)	x 0.177295	= gas/oil ratio (GOR) (m3/m3)
horsepower	x 0.7456999	= kilowatts (kW)
psi	x 6.894757	= kilopascals (kPa)
long tons (LT)	x 1.016047	= tonnes (t)
pounds (Ib)	x 0.453592	= kilograms (kg)
gallons (Imperial)	x 4.54609	= litres (L) (.001 m3)
gallons (U.S.)	x 3.785412	= litres (L) (.001 m3)
barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia) (C3)	x 5.6339198	= cubic metres per million cubic metres (m3/106m3)
bbl/MMcf (C4)	x 5.6367593	= (m3/106m3)
bbl/MMcf (C5+)	x 5.6403087	= (m3/106m3)
LT/MMcf (sulphur)	x 36.063298	= tonnes per million cubic metres (t/106m3)
gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf) (C5+)	x 161.3577	= millilitres per cubic meter (mL/m3)
gallons (U,S,) per thousand cubic feet (gal (U.S.)/Mcf) (C5+)	x 134.3584	= (mL/m3)
degrees Rankine (°R)	x 0.555556	= Kelvin (K)
centipoises	x 1.0	= millipascal seconds (mPa's)

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Appendix D- Page 1

Appendix D - General Evaluation Parameters

Royalties and Mineral Taxes

The lessor and overriding royalties were based on existing agreements and government regulations. The Crown royalty rates and the Freehold Mineral Taxes were based upon existing provincial regulations.

In October 2007, the Government of Alberta announced new royalties for the Province of Alberta. These royalties were enacted by legislation to be effective January 1, 2009 and, therefore, have been included in this report. In addition, the Alberta New Well Royalty Reduction program and the Alberta Drilling Royalty Credit program, announced in March 2009 and enacted by legislation in June 2009, have been included.

Operating and Capital Costs

Operating and capital costs were based on current costs and were escalated to the dates when these costs would be incurred. When escalated, the operating costs and capital costs were escalated based upon the schedule of escalation factors included in Appendix B, Table P-1. Where applicable, a fee for dehydration, gathering, compression and processing was applied against royalty gas and credited to the Company.

Gas Cost Allowance

The operating portion of the gas cost allowance (GCA) has been included with each individual entity. The value has been estimated based on either custom processing fees or actual operating costs, as reported by the Facility Cost Centre (FCC) operator. The Alberta Department of Energy Unit Operating Cost Rates (UOCR) Plant Types, or UOCR-designated facility rates, are replaced by the FCC in 2009. These FCC costs have been estimated based on the old custom processing fees or UOCR's.

The Corporate Effective Royalty Rate is replaced by the Facility Effective Royalty Rate (FERR) in 2009. The FERR will include a capital cost component, which will replace the Capital GCA pools. As this GCA is in the transitional stages of changing to new regulations, the capital portion of the GCA is estimated based on the historical Capital GCA pools until enough information is available to include it with the operating portion.

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Appendix D- Page 2

Abandonment and Reclamation

Well abandonment and disconnect costs were estimated and included in our report at the individual entity level for all wells that were assigned reserves. No allowance for surface lease reclamation and salvage value was included. No abandonment costs have been estimated for suspended wells, gathering systems, batteries, plants, or processing facilities.

Corporate Income Taxes

At the request of the Company, income taxes have not been considered in this report. However for completeness, the procedure used in calculating Canadian income tax is set out below.

All royalties on production from Indian Lands are deductible. Non-Crown (that is, freehold or overriding) royalties are subdivided as follows, for income tax calculations:

(a) Production royalties are those non-Crown royalties which are subject to payments to the Crown (including Freehold Mineral Taxes (Alberta), Freehold Production Taxes (Saskatchewan), and Incremental Taxes (Manitoba)).

(b) Resource Royalties are those non-Crown royalties which are not subject to non deductible Crown payments.

The procedure for calculating Canadian income taxes used in this report, is as follows:

1. Determine revenues from the production and sale of oil, gas, and by-products, including sulphur, from field processing of gas of other producers, and from gas production royalties. (This calculation is to be made gross of any Crown charges.)

2. Deduct operating and direct overhead costs.

3. Deduct capital cost allowance (depreciation).

4. Deduct production royalties paid or payable.

5. Deduct Crown charges (Crown royalties and freehold mineral taxes).

6. Deduct resource royalties paid.

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Appendix D- Page 3

7. Deduct intangible costs:

·	10 percent of non-amortized balance at end of year for Canadian Oil and Gas Property Expense (COGPE),

·	30 percent of non-amortized balance at end of year for Canadian Development Expense (CDE),

·	100 percent of Canadian Exploration Expense (CEE).

8. Deduct interest, NPI expenses, abandonment costs, and Saskatchewan capital tax.

9. Deduct earned depletions. This deduction was discontinued many years ago. However, some companies could have a residual balance available. If so, the amount that can be claimed is the lesser of production profits (for this purpose includes resource royalties earned and is reduced by deduction for resource royalties paid or payable, and COGPE, CDE, and CEE deductions and interest) and the remaining balance of earned depletion.

10. Add resource royalties received or receivable, and other income (including NPI income).

11. Calculate taxable income for federal and provincial tax purposes, which equals the amount by which the aggregate of Items 1 and 10 exceed the aggregate of Items 2 through 9.

12. Calculate federal income taxes payable by multiplying federal taxable income by the federal tax rate.

13. Calculate provincial income taxes payable by multiplying provincial taxable income by the appropriate provincial tax rate.

Processing Income

Some clarification is required with regard to the definition of field processing plants. The following describes plants where the processing revenue would be included in the resource revenue.

(a) Field separation and dehydration facilities.

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Appendix D- Page 4

(b) A natural gas processing plant which processes raw natural gas to the point of acceptance by a common carrier, including the processing of hydrogen sulphide.

(c) Fully integrated plants that take raw natural gas through the whole process of converting such gas to natural gas liquids and to further convert the natural gas liquids to liquefied petroleum products.

The following describes plants where the processing revenue would not be included in the resource revenue.

(a) Straddle plants which enhance the recovery of natural gas liquids.

(b) Any part of a natural gas processing plant that is devoted primarily to the recovery of ethane.

Capital Cost Allowance

Capital cost allowance (CCA) is the rate at which the government allows depreciation on tangible capital investment items.

The principal classes of interest to an oil or gas producer for new capital investments are:

Class	Description	Write-Off

2	Oil or gas transmission pipelines of more than 15 years' life.	6% declining balance
7	Vessels, including offshore drilling vessels.	25% declining balance
8	Oil or gas transmission pipelines with a life of 15 years or less, any refineries, separators not included in Class 43, compressors.	20% declining balance
12	The cost, after November 16, 1978, of removing overburden after the start of production at a mine. Computer software, other than systems software.	100%
28	Mining assets acquired in a major expansion of a mine or before the start of production which would otherwise be in Class 41.	25% declining balance

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Appendix D- Page 5

Class	Description	Write-Off

41	Drilling rigs, gas or oil well equipment. Oil or gas gathering lines leading to a transmission pipeline or natural gas processing plant, and field processing plants. Automotive equipment. Mining buildings, equipment, social capital and spur lines not included in Class 28. Electric data processing equipment including systems software.	25% declining balance
43	Refineries acquired after May 8, 1972. Plants acquired after April 10, 1978 to upgrade heavy oil, straddle plants, and any part of a gas processing plant devoted primarily to the recovery of ethane.	30% declining balance

When using the declining balance, the prescribed rate is applied to the undepreciated portion of the capital costs in a particular class at the end of the fiscal year. It is not necessary to claim full capital cost allowance, and any amount from zero to the stated maximum can be claimed. In the year that the capital cost is incurred, only one-half of the stated maximum is allowed.

The asset descriptions contained in the Income Tax Act are drafted precisely. If an asset does not exactly fit the description of a class, then it is not to be included in that class.

Class 8 is a residual class. If property does not qualify for inclusion in any other class, and if it is not specifically excluded from Class 8, then it falls into Class 8.

Resource Allowance

As of January 1, 2007, there is no further deductible percentage for Resource Allowance.

Intangible Costs

Intangible costs are certain of the capital costs which, for taxable net income calculation purposes, are expensed or written off in the year of expenditures or at a specified rate over a number of years.

A distinction is made for tax purposes between Canadian Exploration Expense, Canadian Development Expense, and Canadian Oil and Gas Property Expense. All these expenses may be carried forward indefinitely. These expenses must be reduced by the amount of any incentive payments made by the Federal government for exploration or development.

(a) Canadian Exploration Expense (CEE) includes intangible costs of drilling exploratory wells, as well as geological and geophysical expenses and all dry wells. These costs may be written off at the rate of 100 percent by principal business corporations in the year in which the expenditure was made.

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Appendix D- Page 6

(b) Canadian Development Expense (CDE) includes intangible development drilling costs. Canadian Development Expense is written off at the rate of 30 percent per annum of the diminishing balance.

(c) Canadian Oil and Gas Property Expense (COGPE) includes the cost of purchasing any producing oil and gas reserves and any unproven P&NG properties. This expense is written off at the rate of 10 percent per annum of the diminishing balance.

Income Tax Rates

The tax rates used for an escalated case reflect the current position of the Federal and Provincial governments with respect to income taxes in Canada. A constant case will reflect the current tax rates held flat for the projection period. The following table provides the taxation rates for the current year and the final year of the transition period.

Resource and Processing Income

	Resource Income					Processing Income(1)
	2008	2009	2010	2011	2012	2008	2009	2010	2011	2012

Net Federal Rate:	19.5	19.0	18.0	16.5	15.0	19.5	19.0	18.0	16.5	15.0

Provincial Rates:
Alberta	10.0	10.0	10.0	10.0	10.0	10.0	10.0	10.0	10.0	10.0
British Columbia	12.0	12.0	12.0	12.0	12.0	12.0	12.0	12.0	12.0	12.0
Manitoba	14.0/13.0	13.0	13.0	13.0	13.0	14.0/13.0	13.0	13.0	13.0	13.0
Newfoundland	14.0	14.0	14.0	14.0	14.0	5.0	5.0	5.0	5.0	5.0
Nova Scotia	16.0	16.0	16.0	16.0	16.0	16.0	16.0	16.0	16.0	16.0
Ontario	14.0	14.0	14.0	14.0	14.0	12.0	12.0	12.0	12.0	12.0
Saskatchewan	13.0/12.0	12.0	12.0	12.0	12.0	10.0	10.0	10.0	10.0	10.0

(1) Manufacturing and processing,

Capital Taxes

A federal "Large Corporation Tax" of 0.175 percent is employed in Canada on capital in excess of $50 million. The capital tax is fully creditable against the existing corporate surtax which is currently 1.12 percent for all types of income. This report includes the cost of the corporate surtax but does not reflect the impact of the federal Large Corporation Tax.

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Appendix D- Page 7

Successor Rules

Successor rules may apply where there has been an acquisition by a corporation, in which case resource tax pools that are transferred to the purchaser will be streamed so that they will only be allowed as deductions against proceeds attributable to the resource properties acquired from the vendor. This report does not reflect the impact of Successor Rules.

Net Present Values

The estimates of the P&NG reserves and their respective net present values are summarized by property and by reserves category in the Discussion section of this report.

Detailed forecasts of production and net revenue for the various reserves categories are presented in Tables in the Summary and Discussion sections.

Form 51-101F2

Report on Reserves Data

by Independent Qualified Reserves Evaluator or Auditor

Report on Reserves Data

To the Board of Directors of Eugenic Corp. (the "Company"):

1.	We have evaluated the Company's Reserves Data as at August 31, 2009. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at August 31, 2009, estimated using forecast prices and costs.

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).

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.

Sproule Associates Limited

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 percent, included in the reserves data of the Company evaluated by us as of August 31, 2009, 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 Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location Of Reserves (Country)	Net Present Value of Future Net Revenue Before Income Taxes (10% Discount Rate)
Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location Of Reserves (Country)	Audited (M$)	Evaluated (M$)	Reviewed (M$)	Total (M$)

Sproule	Evaluation of the P&NG Reserves of Eugenic Corp., As of August 31, 2009, prepared in November 2009	Canada

Total			Nil	407	Nil	407

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 judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

Executed as to our report referred to above:

Sproule Associates Limited Calgary, Alberta November 30, 2009	Original Signed by James D. Hudson, R.P.T. (Eng.) James D. Hudson, R.P.T.(Eng.) Project Leader and Shareholder Original Signed by Harry J. Helwerda, P.Eng. Harry J. Helwerda, P.Eng. Executive Vice-President

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EAGLEFORD ENERGY INC.

(Formerly: Eugenic Corp.)

FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS

ON RESERVES DATA AND OTHER INFORMATION

Management of Eagleford Energy 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 are estimates of proved reserves and probable reserves and related future net revenue as at August 31, 2009, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.

The board of directors of the Company has

(a)	reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator;

(b)	met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c)	reviewed the reserves data with management and the independent qualified reserves evaluator.

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 approved

(a)	the content and filing with securities regulatory authorities of Form 51-101F1 containing the reserves data and other oil and gas information;

(b)	the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c)	the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

“SANDRA J. HALL”

Sandra J. Hall, President, Secretary and Director

“MILTON KLYMAN”

Milton Klyman, Director

“WILLIAM JARVIS”

William Jarvis, Director

December 23, 2009