Exhibit 99.1

Huddleston & Co., Inc.

Petroleum and Geological Engineers

1 Houston Center

1221 McKinney, Suite 3700

Houston, Texas 77010

PHONE (713) 209-1100 ¨ FAX (713) 752-0828

January 30, 2012

Mr. Clarence Cottman

NiMin Energy Corp.

1160 Eugenia Place, Suite 100

Carpinteria, CA 93013

As of January 1, 2012

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 and Wyoming.

Our conclusions, as of January 1, 2012, are as follows:

Mr. Clarence Cottman

January 30, 2012

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 reserve classification definitions. Future revenues have been projected on the basis of pricing assumptions consistent with those required for SEC reporting.

Under separate cover we have provided projections of future reserves and revenues based on forecast pricing assumptions. These projections were prepared in a manner consistent with Canadian reporting requirements and definitions. The estimated Proved reserve volumes shown herein are consistent with the aforementioned report; however, such volumes may vary somewhat due to the effect of economic limits. In our opinion, the projections shown herein conform to SEC requirements, and we have utilized the appropriate methodologies and procedures in the preparation of both the estimated reserves and revenues.

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 were based on the average of first-of-the-month prices, including adjustments, on a property by property basis. Benchmark prices for oil and gas were projected at $96.19/bbl. It is noted that these pricing requirements vary significantly from those required for SEC reporting purposes prior to 2010.

The projected revenues shown herein were based on posted prices for West Texas Intermediate oil at Cushing and were adjusted for wellhead differentials. Oil prices for Pleito Creek Field, located in California, were projected as NYMEX plus 8.4% to reflect location, quality and marketing adjustments. Oil prices for the Wyoming properties were projected on the basis of a 16.90% per barrel reduction. There are no gas sales for the existing properties owned 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.

Huddleston & Co., Inc.

Mr. Clarence Cottman

January 30, 2012

Page Three

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

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, 2012, through December 31, 2012.

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 includes 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 ten producing completions in Pleito Creek Field, California and thirty-six 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. We have been informed that properties previously owned by NiMin in Louisiana were divested during 2011.

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 2.36 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. On the effective date of the report there were ten active producing wells and one (inactive) injection well. 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 well. NiMin has informed us that it intends to drill up to nineteen additional 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

Huddleston & Co., Inc.

Mr. Clarence Cottman

January 30, 2012

Page Four

rates, and oil quality. Definitive response was achieved with respect to all the above parameters and production response has been observed in the H-01, H-02, and H-03 completions; however, it is our understanding that injection operations have been suspended pending the installation of permanent injection facilities. As a result of the response to the CMD pilot, we have transferred a portion of the estimated secondary reserves to the Proved category as discussed below.

The NiMin objective of the CMD pilot project has been 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 has been designed to be created with in-situ, super-wet oxygen combustion. The project was also expected to result in the precipitation of asphaltenes in-situ as the result of contact with hot carbon dioxide. 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 histories and analogy to prior completions. Total secondary reserves (8,565 Mbbl) were projected to be approximately 22% of original oil in place (39,185 Mbbl); however, technical analysis and comparisons to other similar secondary projects suggest that actual recoveries are likely to be significantly higher. On an overall basis, primary recovery has been projected to be approximately 13% of original oil in place and primary plus secondary (“2P”) recovery is 36% of original oil in place. We have reviewed information for three other analogous projects in which the ultimate recovery has exceeded 50% of oil in place. Of the estimated total secondary reserves, 11.5% (989 MBO) have been included in the Proved category to reflect observed results. The remaining secondary reserves are shown in the Probable category pending further development and implementation operations.

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 four 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.

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.

The properties are as follows:

Huddleston & Co., Inc.

Mr. Clarence Cottman

January 30, 2012

Page Five

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. The legacy producing 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. Proved Undeveloped locations are all within known productive boundaries and all locations are direct offsets to existing wells. Probable Undeveloped reserves were assigned to additional locations such that each field’s ultimate drilling density was consistent with that of offset fields.

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 7- to 14-acre spacing. The subject fields are currently drilled on spacing of 19 to 75 acres.

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

Ferguson Ranch – Through the end of 2011, NiMin had drilled a total of six wells, all of which are now shown in the producing category. However, these completions have been found to be significantly less prolific than the prior completions. Reserve estimates for the remaining undeveloped locations are consistent with our prior report. On an overall basis, the performance of wells drilled to date have been lower than our original projections and the performance has been attributed to lower reservoir pressures in comparison to expectations. As a result, NiMin has proposed and initiated the implementation of waterflood operations to efficiently recover remaining reserves. Secondary reserves were assigned on the basis of analogy to the performance of other waterfloods conducted in the same horizons as Ferguson Ranch.

Hunt – Three development wells were drilled in 2011. In comparison to our previous report, the total number of future locations has been held constant (adjusted for wells transferred to producing and nonproducing) and 3 Probable locations were transferred to the Proved category to reflect one Proved location per existing well. Reserves for the remaining locations were adjusted to reflect the results of drilling operations. In addition, NiMin has approved the installation of waterflood operations and additional reserves have been assigned on the basis of analogy to the performance of other waterfloods conducted in the same horizons as Hunt.

Sheep Point – Three development wells were drilled during 2011. As a result of the drilling activity we have moved all remaining undeveloped locations to the Proved category to reflect a ratio of one development location per existing wellbore. As is the case for Ferguson Ranch and Hunt, NiMin has approved the installation of waterflood facilities and secondary reserves were assigned on the basis of analogy to the performance of other waterfloods conducted in the same horizons as Sheep Point.

Willow Draw – Activity during 2011 included drilling two new wells, completion of previous new wells, and workover operations including polymer injection operations. As a result of the successful implementation of workover and polymer operations, NiMin has identified additional remedial operations and we have assigned incremental reserves based on the performance of operations conducted during the year. In addition, five locations were moved to the Proved Undeveloped category from Probable Undeveloped to reflect one Proved location per existing well.

General Comments – 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. The Probable reserve category will be subject to a greater level of risk than

Huddleston & Co., Inc.

Mr. Clarence Cottman

January 30, 2012

Page Six

that which would be expected for the Proved reserve assignments. In some cases, the estimated Proved and Probable Undeveloped reserves may be affected by the performance of drilling operations.

In those cases where multiple productive horizons exist within a given wellbore, we have preferentially projected that the Proved reserves will be completed first with the lowermost Proved horizon being the initial completion. However, it is our expectation that after the wells are drilled, the lowermost productive horizon in each wellbore will be the first completed.

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 plus a variable component based on barrels of oil and water produced, were based on our estimates of the level of operations necessary for the subject completions. Injection gas (oxygen) costs were projected on a variable basis with consideration for the timing of installation of air plant facilities. Operating costs for secondary operations in Ferguson Ranch, Hunt, and Sheep Point Fields were scheduled on the basis of a fixed monthly charge plus variable expenses for produced oil, produced water, and water injection. All costs have been 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.

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. Because all of the properties are located onshore, abandonment costs are anticipated to be minimal relative to the estimated future revenues.

A summary of capital costs (before escalation) necessary for full implementation of the Pleito Creek secondary recovery project are as follows:

Overall capital expenditures (before escalation) associated with the implementation of waterflood operations in Ferguson Ranch, Hunt, and Sheep Point include:

Huddleston & Co., Inc.

Mr. Clarence Cottman

January 30, 2012

Page Seven

We have reviewed these costs and believe they are appropriate for the subject operations. Capital investments represent the most recent estimates prepared by NiMin. Costs were held at current levels 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 30 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 and development 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.

Huddleston & Co., Inc.

Mr. Clarence Cottman

January 30, 2012

Page Eight

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. If the reserves are recovered, the resulting revenues and the related costs could be more or less than the estimated amounts. As a result of governmental regulations and policies and uncertainties in supply and demand, the sales rates, the prices received for produced reserves, the ability to recover the reserves and the costs incurred in recovering such reserves may vary from the assumptions made in the preparation of this report. Estimates of reserves may increase or decrease as a result of future operations, market conditions, and/or changes in governmental regulations or policies.

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,

/s/ Peter D. Huddleston

Peter D. Huddleston, P.E.

Texas Registered Engineering Firm F-1024

PDH:klh

Huddleston & Co., Inc.