December 30, 2010 - 6-K: Report of foreign issuer [Rules 13a-16 and 15d-16]

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a – 16 OR 15d – 16 OF

THE SECURITIES EXCHANGE ACT OF 1934

For the month of December 2010

Commission File No. 0-53646

Eagleford Energy Inc.

(Registrant’s name)

1 King Street West, Suite 1505

Toronto, Ontario, Canada M5H 1A1

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40F

Form 20-F x Form 40-F ¨

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

TABLE OF CONTENTS

1. Eagleford Energy Inc. Statement of Reserves Data and Other Oil and Gas Information for the year ended August 31, 2010, filed on Forms NI 51-101F1, F2 and F3 as filed on Sedar on December 29, 2010.

2. Eagleford Energy Inc. Press Release on Reserves Data and Other Oil and Gas Information and Audited Consolidated Financial Statements for the year ended August 31, 2010, as filed on Sedar on December 29, 2010.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Dated: December 30, 2010	EAGLEFORD ENERGY INC.

	By: /s/ James Cassina
	Name: James Cassina
	Title: President

Item 1.

(Formerly: Eugenic Corp.)

FORM 51-101F1

STATEMENT OF RESERVES DATA

AND OTHER OIL & GAS INFORMATION

FOR THE YEAR ENDED

AUGUST 31, 2010

1 King Street West, Suite 1505, Toronto, ON, Canada Telephone: 416 364 4039, Facsimile: 416 364-8244

GLOSSARY OF TERMS

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

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.

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.

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.

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

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

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 nonproducing.

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.

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.

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.

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 judgement as to what are reasonable estimates.

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

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

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.

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.

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.

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.

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.

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.

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

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

Solution Gas – gas dissolved in crude oil.

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.

PART 1

DATE OF STATEMENT

Item 1.1 Relevant Dates:

1.	Date of Statement:	December 9, 2010

2.	Effective Date of Statement:	August 31, 2010

3.	Preparation Date of Statement:	December 2, 2010

PART 2

DISCLOSURE OF RESERVES DATA

In accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, the Company’s qualified reserves evaluator Sproule Associates Limited (“Sproule”) prepared a report (the “Sproule Report”) dated August 31, 2010. The Sproule Report evaluated 100% of Eagleford Energy Inc.’s (“Eagleford” or the “Company”) natural gas reserves, as at August 31, 2010. 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 interests covered by the Sproule Report are 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):

NI 51-101

Summary of Oil and Gas Reserves

As of August 31, 2010

Forecast Prices and Costs

Reserves

	Natural Gas (non-associated & associated)
Reserves Category	Gross (MMcf)		Net (MMcf)
Proved
Developed Producing		213		162
Total Proved		213		162
Probable		69		51
Total Proved Plus Probable		282		212

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

NI 51-101

Summary of Net Present Values of

Future Net Revenue

As of August 31, 2010

Forecast Prices and Costs

	Net Present Values of Future Net Revenue
											Before Tax
	Before Income Taxes Discounted at (%/Year)										Net Value
Reserves	0		5		10		15		20		10%/Year
Category	(M$)		(M$)		(M$)		(M$)		(M$)		($/boe)
Proved
Developed Producing		563		369		264		201		161		9.80
Total Proved		563		369		264		201		161		9.80
Probable		233		98		50		29		19		5.89
Total Proved Plus Probable		796		467		314		231		180		8.87

Notes: Net Present Value of Future Net Revenue includes all resource income:

Sale of oil, gas, by-product reserves

Processing third party revenue

Other income

Unit Values are based on net reserve volumes

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

NI 51-101

Total Future Net Revenue

Undiscounted

As of August 31, 2010

Forecast Prices and Costs

Reserves Category	Revenue (M$)		Royalties (M$)		Operating Costs (M$)		Development Costs (M$)		Well Abandonment/Other Costs (M$)		Future Net Revenue Before Income Taxes (M$)
Proved		1,584		343		671		0		6		563
Proved Plus Probable		2,249		500		945		0		7		796

NI 51-101

Net Present Value of Future Net Revenue

By Production Group

As of August 31, 2010

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	Natural Gas (including associated by-products)*		264		9.80
Proved Plus Probable	Natural Gas (including associated by-products)*		314		8.87

*Includes corporate Capital GCA, if applicable

Unit values are based on net reserve volumes

Item 2.2 Supplementary Disclosure (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 Supplementary Estimates:

Not Applicable

Item 3.2 Forecasted Prices Used in Estimates:

Forecast Prices (as determined by Sproule Associates Limited).

NI 51-101

Summary of Pricing and

Inflation Rate Assumptions

As of August 31, 2010

Forecast Prices and Costs

Year	WTI Cushing Oklahoma ($US/bbl)		Edmonton Par Price 40o API ($Cdn/bbl)		Cromer Medium 29.3o API ($Cdn/bbl)		Natural Gas (1) AECO Gas Prices ($Cdn/MMBtu)		Pentanes Plus F.O.B. Field Gate ($Cdn/bbl)		Butanes F.O.B. Field Gate ($Cdn/bbl)		Inflation Rate (2) (%/Yr)		Exchange Rate (3) ($US/ $Cdn)
Historical
2004		41.42		52.91		45.72		6.87		53.91		41.37		1.4		0.770
2005		56.46		69.29		57.36		8.58		69.13		45.20		1.3		0.826
2006		66.09		73.30		62.35		7.16		75.03		59.32		1.5		0.882
2007		72.27		77.06		65.36		6.65		77.33		63.71		2.0		0.935
2008		99.59		102.85		93.05		8.15		104.70		75.09		1.0		0.943
2009		61.63		66.20		62.77		4.19		68.13		44.13		2.0		0.880

Forecast
2010		79.06		82.80		78.66		4.03		84.80		58.63		1.5		0.934
2011		82.38		86.34		81.16		4.50		88.42		61.13		1.5		0.934
2012		84.48		88.57		81.48		4.98		90.71		62.71		1.5		0.934
2013		86.48		90.69		82.53		6.00		92.88		64.22		1.5		0.934
2014		90.22		94.67		85.20		7.75		96.95		67.03		1.5		0.934
2015 and thereafter escalated at 1.5%

(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.

The weighted average historical natural gas price received by Eagleford for the year ended August 31, 2010 was $4.22/Mcf.

PART 4

RECONCILIATION OF CHANGES IN RESERVES

Item 4.1 Reserves Reconciliation

NI 51-101

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

By Principal Product Type

As of August 31, 2010

Forecast Prices and Costs

	Associated and Non-Associated Gas
Factors	Gross Proved (MMcf)			Gross Probable (MMcf)			Gross Proved Plus Probable (MMcf)
August 31, 2009		248			91			339
Technical Revisions		(10	)		(22	)		(32	)
Production		(25	)		-			(25	)
August 31, 2010		213			69			282

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

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:

All of the properties which the Company has an interest are located onshore in Canada and the United States.

Canada

At August 31, 2010 the Company has 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.

United States

Matthews Lease, Zavala County, Texas

At August 31, 2010 the Company holds through its wholly owned subsidiary Dyami Energy Inc. (“Dyami Energy”) a 75% working interest before payout which reduces to a 61.50% working interest after payout of $12,500,000 of production revenue. The Company holds directly a 10% working interest before payout which reduces to a 7.50% working interest after payout of $15,000,000 of production revenue. The Matthews lease comprises approximately 2,629 gross acres of land in Zavala County, Texas. The royalties payable under the Matthews lease are 25%.

Murphy Lease, Zavala County, Texas

At August 31, 2010 the company holds through Dyami Energy a 100% working interest in the Murphy Lease comprising approximately 2,637 acres of land in Zavala County, Texas subject to a 10% carried interest on the drilling costs on the first well drilled from surface to base of the Austin Chalk formation, and a 3% carried interest on the drilling costs on the first well drilled from the top of the Eagle Ford shale formation to basement. Thereafter the Company’s working interests range from 90% to 97%. The royalties payable under the Murphy Lease are 25%.

Acreage:

The following table sets forth the developed acreage of the projects in which the Company holds an interest, on a gross and a net basis as of August 31, 2010. 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 developed acreage is as follows:

August 31

2010

2009

2008

Alberta, Canada

Gross

Net

Gross

Net

Gross

Net

Leasehold Acreage-Developed

8,320

432.43

8,320

432.43

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, 2010. 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. All of the Company’s producing wells at August 31, 2010 were located in Alberta, Canada

August 31	2010				2008				2008
Alberta, Canada	Gross		Net		Gross		Net		Gross	Net
Natural Gas Wells-Producing		3		5.1975		3		5.1975	Nil	Nil
Natural Gas Wells-Non Producing		6		5.1975		6		5.1975	Nil	Nil

Item 6.2 Properties With No Attributed Reserves:

On August 31, 2010 the Company acquired all of the issued and outstanding membership interests of Dyami Energy an exploration stage company. Dyami Energy’s properties include its interests in the Matthews Lease and the Murphy Lease.

Matthews Lease, Zavala County, Texas

At August 31, 2010 the Company holds through its wholly owned subsidiary Dyami Energy a 75% working interest before payout which reduces to a 61.50% working interest after payout of $12,500,000 of production revenue. The Company holds directly a 10% working interest before payout which reduces to a 7.50% working interest after payout of $15,000,000 of production revenue. The Matthews lease comprises approximately 2,629 gross acres of land in Zavala County, Texas. The royalties payable under the Matthews lease are 25%.

Dyami Energy acquired its interest in the Matthews Lease through a Purchase and Sale Agreement dated effective February 23, 2010 (the “Agreement”). Under the terms of the Agreement, Dyami Energy has the following commitments:

(a)	On or before August 23, 2010 Dyami Energy shall commence operations to drill an Initial Test Well on Matthews Lease to a depth of not less than 3,000 feet below the surface or to the base of the San Miguel “D” formation.

(b)

On or before July 8, 2011, Dyami Energy shall commence operations to perform an injection operation (by use of steam, nitrogen or other ) in the San Miguel formation on the Initial Test Well or any other well located on the Matthews Lease or, all of the interest acquired by Dyami Energy in the Matthews Lease shall be forfeited without further consideration;

(c)	On or before January 1, 2011, Dyami Energy shall commence a horizontal well to test the Eagle Ford Shale formation with a projected lateral length of not less than 2,500 feet (the “Second Test Well”).

(d)

Dyami Energy’s 15% working interest partner in the Matthews Lease has an obligation to participate in each of the operations provided for in (a), (b) and (c) above and if the partner fails to bear its share of the costs of such operations, the partner shall forfeit its interest in and to the well and the applicable spacing unit.

During August 2010, Dyami Energy commenced operations to drill its Initial Test Well on the Matthews Lease. Subsequent to August 31, 2010 the well was drilled to a measured depth of 8,563 feet, which includes a 3,300 foot “in section” lateral into the Eagle Ford shale formation; accordingly Dyami Energy has satisfied (a) and (c) above.

Dyami Energy is the designated operator under the provisions of the Matthews Lease Operating Agreement.

The Matthews Oil and Gas Lease has a primary term of three years commencing April 12, 2008, unless commercial production is established from a well or lands pooled therewith or the lessee is then engaged in actual drilling or reworking on any well within 90 days thereafter. The lease shall remain in force so long as the drilling or reworking is processed without cessation of more than 90 days. The lease requires that such operations be continuous, without cessation of more than ninety days, and if production is established, then the lease will continue. If the lessee has completed a well as a producer or abandoned a well within forty-five days prior to the expiration of the primary term, the lessee may extend the lease by commencing a well within ninety days following the end of the primary term.

Murphy Lease, Zavala County, Texas

Dyami Energy acquired its interest in the Murphy Lease through an Assignment Agreement dated effective February 3, 2010 (the “Assignment Agreement”). The Murphy Oil and Gas Mineral Lease (“Mineral Lease Agreement’) has a primary term of three years commencing on February 2, 2010. Under the terms of the Assignment Agreement and the Mineral Lease Agreement, Dyami Energy has the following commitments:

to commence drilling (spud) a well to a depth to sufficiently test the Eagle Ford Shale formation by August 3, 2010 or pay a lease delay payment of US $25 per acre or US$65,925 in the aggregate (paid July 28, 2010) to extend the period to commence drilling for 180 days to January 30, 2011 or Dyami Energy shall be required to release and re-assign its rights in the Murphy Lease.

During the development of the Murphy Lease, Dyami Energy is required to commence drilling a well within 180 days, or otherwise release and re-assign its rights to the Murphy Lease, but excluding the unit acreage area it has already drilled and earned. Likewise, if a producing well ceases to produce, and such well is not timely re-worked or re-drilled within a six month period, Dyami Energy shall also be required to release and re-assign its rights to the Murphy Lease.

Three years after the cessation of continuous drilling, all rights below the deepest producing horizon in each unit then being held by production, shall be released and re-assigned to the Lessor, unless the drilling of another well has been proposed on said unit, approved in writing by Lessor, and timely commenced.

Acreage:

The following table sets forth the undeveloped acreage of the projects in which the Company holds an interest, on a gross and a net basis as of August 31, 2010. Our undeveloped acreage is as follows:

August 31

2010

2009

2008

Texas, USA

Gross

Net

Gross

Net

Gross

Net

Leasehold Acreage-Undeveloped

5,266

4,872

Nil

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 qualified reserves 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, 2010 was $8,568 and $2,568 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 $794,304 at August 31, 2010 and does not anticipate paying significant income taxes in the near term.

Item 6.6 Costs Incurred:

For the year ended August 31, 2010 the Company incurred the following costs:

USA - Undeveloped	2010
Acquisition of oil and gas interests	$	212,780
Exploration expenditures		10,046
Total costs incurred	$	222,826

Item 6.7 Exploration and Development Activities:

During August 2010, through Dyami Energy, the Company commenced operations to drill an initial Eagle Ford shale test well on the Matthews Lease in Zavala County, Texas. The well was spud in on October 15, 2010 and was drilled to a measured depth of 8,563, feet which includes a 3,300 foot “in section” lateral into the Eagle Ford shale formation. A shot point sleeve was installed in the Eagle Ford shale formation to protect the well bore and facilitate a multi stage frac completion.

The well was logged extensively and 36 sidewall cores were taken from 4 key formations in descending order, the San Miguel, the Austin Chalk, the Eagle Ford and the Buda. The logs were interpreted by Weatherford International Ltd and the sidewall cores were analyzed by Core Laboratories and Weatherford and based on those results the Company is formulating a detailed frac design and completion plan for the Dyami/Matthews #1 H well.

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, Canada			21				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 2010.

Production History	Fiscal 2010
	August 31		May 31		February 28		November 30
Average Daily Production
Natural gas (Mcf per day)		68		54		74		78
Average Commodity Prices
Natural gas ($/Mcf)	$	3.75	$	3.90	$	5.45	$	3.71
Royalties
Natural gas ($/Mcf)		0.71		0.93		1.58		0.69
Production Costs
Natural gas ($/Mcf)		2.12		2.27		2.40		3.53
Netback by Product
Natural gas ($/Mcf)	$	0.92	$	0.70	$	1.47	$	(0.51	)

2. The following table indicates the Company’s total production for fiscal 2010 from its core property.

Property	Associated and Non-Associated Gas (MMcf)
Botha, Alberta		25
Haynes, Alberta		-

Form 51-101F2

Report on Reserves Data

by Independent Qualified Reserves Evaluator or Auditor

Report on Reserves Data

To the Board of Directors of Eagleford Energy Inc. (the “Company”):

1. We have evaluated the Company’s Reserves Data as at August 31, 2010. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at August 31, 2010, 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).

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.

Eagleford Energy Inc.	- 2 -	Form 51-101F2
Sproule

4. 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, 2010, 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:

Qualified

Reserves

Description

Location

Net Present Value of Future Net Revenue

Before Income Taxes (10% Discount Rate)

Evaluator or

Auditor

and Preparation Date

of Evaluation Report

Reserves

(Country)

Audited

(M$)

Evaluated

(M$)

Reviewed

(M$)

Total

(M$)

Sproule

Evaluation of the

P&NG Reserves of

Eagleford Energy

Inc.,

As of August 31,

2010, prepared in

November 2010

Canada

Total

Nil

314

Nil

314

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.

Eagleford Energy Inc.	- 3 -	Form 51-101F2
Sproule

Executed as to our report referred to above:

Sproule Associates Limited

Calgary, Alberta

November 30, 2010

Original Signed by James D. Hudson, P.L. (Eng.)


	James D. Hudson, P.L. (Eng.),
	Project Leader,
	Senior Petroleum Technologist and
	Shareholder

Original Signed by Harry J. Helwerda, P.Eng., FEC


	Harry J. Helwerda, P.Eng., FEC
	Executive Vice-President and Director

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, 2010, 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.

“JAMES CASSINA”

James Cassina, President, Secretary and Director

“MILTON KLYMAN”

Milton Klyman, Director

“COLIN MCNEIL”

Colin McNeil, Director

December 29, 2010

Item 2

FOR IMMEDIATE RELEASE

Eagleford Reports Year End Reserves Data and Other Oil and Gas Information

and Audited Consolidated Financial Statements

Toronto, Canada – December 29, 2010 – Eagleford Energy Inc. (OTCBB: EFRDF) (“Eagleford” or the “Company”) announces that it has filed its reserves data and other oil and gas information as of August 31, 2010 on Forms 51-101F1, 51-101F2 and 51-101F3, as mandated by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators. The Company also filed its Audited Consolidated Financial Statements together with the Auditors Report for the year ended August 31, 2010. Copies of the Company’s reserves data and other oil and gas information and its Audited Consolidated Financial Statements may be obtained on SEDAR at www.sedar.com or EDGAR at www.sec.gov.

About Eagleford Energy Inc.

Eagleford Energy Inc. is a growth orientated oil and gas company with a focus on growing hydrocarbon reserves, cash flow, and net asset value per share through exploration and production of mineral properties in South Texas. There are approximately 30.9 million shares issued and outstanding in the capital of the Company.

For further information, please contact:

James Cassina

President

Eagleford Energy Inc.

Telephone: (416) 364-4039

Suite 1505, 1 King Street West, Toronto, Ontario, M5H 1A1, Telephone: 416 364-4039, Facsimile: 416 364-8244

Certain information regarding the Company in this news release may constitute forward-looking statements under applicable securities laws. The forward-looking information includes, without limitation, projections or estimates made by us and our management in connection with our business operations. Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this press release, which assumptions are based on management analysis of historical trends, experience, current conditions and expected future developments pertaining to the Company and the industry in which it operates as well as certain assumptions as specifically outlined in the release above. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by the Company and described in the forward-looking information contained in this press release. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties. Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is released and the Company disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities laws.

1 King Street West, Suite 1505, Toronto, ON, Canada Telephone: 416 364 4039, Facsimile: 416 364-8244