Nimin Energy (NEYYF) 20FR12G/A Initial registration of securities (foreign private issuers) (amended)

Exhibit 99.1

November 30, 2010

Mr. Clarence Cottman
NiMin Energy Corp.
1160 Eugenia Place, Suite 100
Carpinteria, CA 93013

Re: Estimated Reserves and Revenues
Proved Reserves Only — SEC Parameters
As of January 1, 2010 (Revised)

Dear Mr. Cottman:

Pursuant to your request, we have estimated future reserves and projected revenues for properties owned by NiMin Energy Corp. (“NiMin”). The properties are located in California, Louisiana, and Wyoming. It is our understanding that the properties shown herein represent 100% of the Proved oil and gas reserves owned by NiMin.

Our conclusions, as of January 1, 2010, are as follows:

	Net to NiMin Energy, Corp. (Revenues in $US)*
	Proved Developed					Proved			Total
	Producing		Nonproducing			Undeveloped			Proved
Estimated 8/8ths Oil, Mbbl		2,477.4		182.6			9,706.8			12,366.9
Estimated 8/8ths Gas, MMcf		3,021.0		1026.0			355.0			4,402
Estimated Future Net Oil, Mbbl		1,797.3		49.4			7,204.6			9,051.4
Estimated Future Net Gas, MMcf		571.0		252.6			79.4			903.0
Constant Product Prices**
Future Gross Revenue, $M		94,914		3,975			369,869			468,758
Operating Costs, $M		44,512		369			75,512			120,393
Direct Taxes, $M		8,499		421			37,019			45,939
Capital Costs, $M		1,746		935			57,414			60,096
Future Net Revenue (FNR), $M		40,158		2,250			199,923			242,330
Present Worth FNR, Disc. @ 10%, $M		21,557		1,123			76,261			98,942
Projected Revenues by Year, $M (Constant Product Prices)
2010		5,115		(200	)		(2,870	)		2,045
2011		4,090		5			(10,423	)		(6,328	)
2012		3,347		(417	)		14,648			17,577
2013		2,772		42			24,096			26,910
Thereafter		24,834		2,820			174,472			202,126
Total		40,158		2,250			199,923			242,330

*	Totals subject to rounding.
**	Prices projected in accordance with SEC parameters as discussed hereinafter.

Mr. Clarence Cottman
November 30, 2010
Page Two

Report Preparation

Securities and Exchange Commission (“SEC”) Regulation S-K, Item 102, and Regulation S-X, Rule 4-10, and the Financial Accounting Standards Board (“FASB”) require oil and gas reserve information to be reported by publicly held entities as supplemental financial data. As of January 1, 2010, SEC regulations require that revenues be based on the average of first-of-the-month prices for the twelve-month period prior to the effective date of the report and discounted at 10%. The regulations and standards provide for estimates of Proved reserves and permit, but do not require, reporting of Probable and Possible reserve quantities. Reserves prepared for SEC reporting purposes are required to conform to reserve definitions contained within Regulation S-X, Rule 4-10.

The Society of Petroleum Engineers (“SPE”) has promulgated reserve classification definitions and Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information which specify requirements for the qualifications and independence of reserve estimators and auditors and accepted methods for the estimation of future reserves. SPE reserve definitions vary significantly from those specified by the SEC and require reserves to be economically recoverable with prices and costs being received on the effective date of the report.

The estimated reserves and revenues shown herein have been prepared with consideration for SEC regulations and requirements for public reporting purposes.

Under separate cover we have provided projections of future reserves and revenues, including Probable reserves, which were based on forecast pricing assumptions and prepared in a manner consistent with Canadian reporting requirements and definitions. The estimated Proved reserve volumes shown herein are consistent with the prior projections with the only variance being the economic limits of some wells.

Product Prices

As we understand the SEC requirements issued on January 14, 2009, oil and gas prices utilized to determine the Standardized Measure of discounted cash flows should be based on the trailing twelve-month average of the first-of-the-month prices. The estimated revenues shown herein reflect the average of first-of-the-month prices including adjustments on a property by property basis. The projected prices for both oil and gas were based on our understanding of SEC requirements. It is noted that the pricing requirements vary significantly from those previously required for reporting purposes.

The projected revenues shown herein were based on average oil prices of $61.03/bbl and $4.20 per MMBtu and were adjusted for wellhead differentials. Gas prices were reduced by $0.50 per MMBtu to reflect our estimates of marketing and transportation costs for the Louisiana properties. No gas sales were projected for the remaining properties. Oil prices for Pleito Creek Field, located in California, were projected as NYMEX less 11% to reflect quality and marketing adjustments. Oil prices for the Louisiana and Wyoming properties were projected on the basis of $1.50 and $10.60 per barrel reductions, respectively. In the absence of evidence to the contrary, we have estimated the Btu content for all gas to be 1100 per Scf. Differentials were based on values derived from actual receipts for 2009 as supplied by NiMin.

Market prices for both oil and gas continue to be influenced by a variety of market and seasonal factors and future revenues are likely to be influenced by such variations in product prices.

Mr. Clarence Cottman
November 30, 2010
Page Three

A comparison of the average product prices, weighted as a composite for all properties, follows:

	Constant Product Prices
	Oil, $/bbl		Gas, $/Mcf
2010		51.31		4.07
Maximum		51.71		4.07
Average Over Life		51.38		4.07

Product price hedges, if any, were not considered for the purposes of this report.

Projections

The attached reserve and revenue projections have been prepared on a calendar year basis with the first time period being January 1, 2010, through December 31, 2010.

The reserve projections shown herein were prepared in February 2010. No information was considered which would have been the result of operations or performance occurring after December 31, 2009. The revenue projections were prepared in September 2010 to reflect SEC pricing requirements.

Interests Included

The ownership shown herein reflects the NiMin share of participation in existing properties and locations identified by NiMin and other operators. It is our understanding that NiMin has obtained the necessary lease rights to achieve the projected ownership.

The “Pleito Creek — PRI” projection, which included both negative volumes and revenues, represents a baseline production level that is payable to the previous owners of Pleito Creek Field.

Reserve Estimates

The estimated reserves include limited volumes for seven producing completions in Louisiana, eleven producing completions in Pleito Creek Field, California, and twenty-four producing wells in Wyoming. Producing reserves were based on the extrapolation of production history where there was sufficient data to indicate a performance trend and were further supported by volumetric calculations and analogy.

Pleito Creek Field — The field was discovered by Exxon in 1951 and is located in Section 35, Township 11N, Range 21W, Kern County, California. Since 1951, the Pleito Creek Field has produced 2.18 million barrels of 17° API oil from the Santa Margarita reservoir. Fluid expansion has been the field’s primary drive mechanism, with limited recoveries as a result of pilot in-situ combustion operations conducted by Exxon.

Geologically, the field is a faulted anticline with a steeply dipping north limb that rolls over into the Wheeler Ridge thrust fault. The Miocene-aged Santa Margarita sand is the primary producing reservoir in the field. It ranges in depth from -1,700’ subsea to -3,500’ subsea and is on average 115’ thick.

NiMin is the operator of all wells at Pleito Creek Field and also is the operator for all historical leases, which have been combined into a single lease referred to as the “Ten West Lease,” covering 225 acres. There are currently nine active wells in the field.

NiMin has drilled a total of five horizontal producing wells in the Santa Margarita formation. As part of the combined miscible displacement (“CMD”) pilot project, NiMin has two monitoring wells and one injection

Mr. Clarence Cottman
November 30, 2010
Page Four

well. NiMin plans to drill up to seven additional horizontal producing wells and nine vertical producing wells. NiMin has also installed new production and injection facilities.

During 2009 NiMin initiated injection operations and has achieved combustion in the reservoir. The company continues to closely monitor pressure, temperature, produced gas composition, oil production rates, and oil quality. All indications to date are consistent with those expected of the CMD project and are viewed to be positive results. However, we have not reclassified secondary reserves from the Probable to Proved category pending further confirmation through production performance.

With the CMD pilot project, NiMin intends to demonstrate the use of horizontal and vertical wells to capture gravity-draining residuum from the steam chest and upgraded oil from a near-miscible, carbon dioxide displacement front. This procedure is expected to substantially increase recovery of in-place oil reserves.

The near-miscible, carbon dioxide gas cap and steam chest will be created with in-situ, super-wet oxygen combustion. The project will also demonstrate the use of hot carbon dioxide gas to precipitate asphaltenes, thus upgrading the oil by approximately 4 API units. The precipitated asphaltene will be hydro-cracked by hot steam and potassium carbonate catalyst into light ends and coke. The coke will be burned as fuel by the oxygen gas and the light ends will be produced by production wells. The conversion of co-injected water to steam will scavenge the heat behind the burn front and increase the burn front velocity across the top of the reservoir. Carbon dioxide and steam displacement of the oil above the production wells is expected to result in increased oil production and overall recovery efficiency.

Reserve assignments for the producing properties have been based on the extrapolation of production history and analogy to prior completions. For the purposes of our analysis we have projected that horizontal completions will recover approximately 1.8 times that of a vertical completion.

In addition, NiMin drilled and completed an initial test well into the Olcese sand that produced at a rate of approximately 30 barrels of 19° API oil per day. This well was subsequently converted to a Santa Margarita injector and a follow-up location, O-2, was drilled. The projections reflect two proved undeveloped locations targeting the Olcese formation. Reserve assignments for the Olcese formation have been based on volumetric assignments, utilizing an 8% recovery factor of original oil in place.

Louisiana Properties — The reserve assignments for the Louisiana properties, consisting of seven producing completions, two recompletions, and six drilling locations as identified by NiMin, have been based on volumetric calculations and analogy to offset production. Performance data has been considered for the producing completions in which a performance trend has been established. Proved reserves were assigned only where a completion could be made updip to a prior completion or where production tests, geological and other information indicated producible reserves.

It is noted that the reserve assignments shown herein for all Louisiana properties have been based on a combination of information derived from past operations conducted by other operators, seismic data, and subsurface interpretations. The results of drilling operations may lead to material changes in the estimated reserves, particularly on a location by location basis.

Wyoming Properties — The properties, acquired in late 2009, consist of four mature oil fields located in Park County, Wyoming. The fields produce from the Phosphoria and Tensleep formations.

Mr. Clarence Cottman
November 30, 2010
Page Five

The properties are as follows:

	No. of		Cumulative		Proved
Field	Completions		Recovery, Mbbl		Undeveloped Locations
Ferguson Ranch		13		5,269		12
Hunt		6		952		6
Sheep Point		6		647		5
Willow Draw		21		2,469		21

The gravity of oil produced from the subject fields varies between 14°-18° API.

Estimated reserves shown for the producing properties have been projected on the basis of the extrapolation of performance data. All of the completions have extensive production histories and provide substantial data with respect to performance trends. In some cases the information suggests that recent well intervention work has been performed. In such cases we have considered prior historical performance in estimating future reserves.

Proved Undeveloped reserves were assigned to certain locations which represent downspacing of the prior field development. On an overall basis, estimated reserves for the Proved Undeveloped locations averaged 69% of the average estimated recovery for the existing wells. On a field by field basis, reserves varied between 63% and 80% of the average estimated ultimate recoveries of the existing wells. Proved Undeveloped locations were limited to one location per existing completion and all locations are direct offsets to existing wells.

Support for the ability to successfully develop the subject fields is derived from eight other fields producing from the Phosphoria and Tensleep formations that have now been developed on 5- to 17-acre spacing. The subject fields are currently drilled on spacing of 25- to 108-acres.

We have also considered volumetric calculations in the assignment of future reserves.

General Comments — Estimates of recoverable reserves are subject to variation as a result of a variety of operational and physical parameters. The accuracy of the techniques utilized to estimate such volumes will be affected by a variety of factors, including the nature and extent of the technical data available. Reserve estimates for nonproducing intervals and undeveloped locations will be subject to a significantly greater level of variation than for producing properties that have demonstrated established decline trends. In some cases, the estimated undeveloped reserves may be affected by the performance of drilling operations.

We have considered certain geological interpretations as provided, but in all cases we have exercised the final judgments for the estimated reserves.

Operating and Capital Costs

Operating costs, shown as dollars per well per month, were based on our estimates of the level of operations necessary for the subject completions. Costs were held constant over the life of the properties.

Severance taxes, shown as dollars per unit of production or as a percentage of gross revenues in accordance with statutory rates, have been deducted separately. We have been informed that the California properties are not subject to severance taxes.

Mr. Clarence Cottman
November 30, 2010
Page Six

Capital expenditures, shown under “Other Costs,” were supplied by NiMin and are intended to reflect costs necessary to develop the estimated reserves and the remedial costs required to recomplete to behind-pipe zones. Abandonment costs of $50,000 per well have been included for each wellbore. Since all of the properties are located onshore, abandonment costs are anticipated to be minimal relative to the estimated future revenues.

We have reviewed these costs and believe they are appropriate for the subject operations. Capital costs have been held constant over the life of the properties.

Huddleston & Co., Inc.

Huddleston & Co., Inc., is registered with the Texas Board of Professional Engineers (Registration Number F-001024). Substantially all of the engineering calculations and conclusions shown herein were prepared by Peter D. Huddleston, P.E., who was licensed by the Texas Board of Professional Engineers under Sec. 12(b), Senate Bill No. 74, which required graduation from an accredited engineering curriculum, four years of experience, and successful completion of the Engineer in Training and Principles and Practice examinations. Mr. Huddleston has been practicing as a petroleum engineer for over 29 years and has been a licensed professional engineer in the State of Texas (serial number 57166) since 1985.

Huddleston & Co., Inc., was formed in 1967 and has been providing engineering services continuously since that time.

Factors Not Included

Values were not assigned to nonproducing acreage or to the salvage of surface and subsurface equipment.

General office overhead, and allowances for depletion, depreciation, and amortization have not been deducted from future revenues.

We have not attempted to apply risk adjustments to any of the projections shown herein.

Report Qualifications

THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED AS MARKET VALUE.

The projections shown herein have been based on drilling schedules as indicated by NiMin. The timing of actual drilling operations will be controlled by rig availability and other factors. Deviations from the proposed operational schedule may affect the projections of discounted revenues; however, capital contributions would not be expected to be required until such time that drilling operations for the individual projects are imminent. We have accepted NiMin’s representation that capital will be available to meet the requirements as projected herein.

Estimates for individual completions should be considered in context with the total or overall estimated revenues. Actual performance of the individual completions can be expected to vary considerably from the projections, particularly in comparison to the total composite production.

The estimated reserves shown herein may be affected by future changes in regulatory requirements and/or the ability of NiMin to secure the necessary permits to conduct future operations.

Mr. Clarence Cottman
November 30, 2010
Page Seven

We did not inspect the properties or NiMin’s land files. Ownership, product prices, and other factual data have been accepted as represented by NiMin.

Respectfully submitted,

Peter D. Huddleston, P.E.
Texas Registered Engineering Firm F-1024

PDH:klh