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As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to all interests of Black Hills Exploration and Production, Inc and its affiliates. Our reports, completed on January 31, 2011 and presented herein, were prepared for public disclosure by Black Hills Corporation in filings made with the Securities and Exchange Commission (SEC) in accordance with the disclosure requirements set forth in SEC regulations. The methods employed in estimating these reserves are outlined in the attached appendices. Attached are three reports summarizing the reserves for Black Hills Exploration and Production, Inc. and affiliates Black Hills Gas Resources, Inc. and Black Hills Plateau Production, LLC. The reserves are associated with conventional formations, tight gas sands, coal seams, and shales in the following states: New Mexico, Colorado, Wyoming, Montana, Oklahoma, Texas, North Dakota, and California.

The oil, condensate, gas and plant products prices utilized were average prices for the 12 months of 2010. The average was calculated using the posted first-day-of-the-month price for each month. Operating expenses and investments were supplied by Black Hills and were accepted as furnished. Neither expenses nor investments were escalated.

The proved reserve classifications conform to criteria of the Securities and Exchange Commission as defined in the Appendix. The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered and such changes could affect Black Hills' ability to recover the estimated reserves. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts. The reserve estimates were based on interpretations of factual data furnished by Black Hills. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

Cawley, Gillespie & Associates, Inc. is an independent petroleum engineering consulting firm. Our firm provides services throughout the world for many clients and has offices in Fort Worth, Houston and Austin. Many of our staff have professional accreditation in the form of registered or certified professional licenses (including the undersigned, TX No. 71055) or the equivalent from appropriate governmental authorities or self-regulating professional organizations. We have no affiliation with the Subject Company that would influence our estimates.

Black Hills Corporation makes periodic filings with the SEC under the Securities Exchange Act of 1934, as amended. Furthermore, Black Hills Corporation has certain registration statements filed with the SEC under the Securities Act of 1933, as amended, into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-8 and Form S-3 of Black Hills Corporation of the references to our name as well as the references to our reports for Black Hills Corporation, which consent appears in the 2010 Annual Report on Form 10-K of Black Hills Corporation. Our written consent for such use is included as a separate exhibit to the Black Hills Corporation 2010 Annual Report on Form 10-K.

As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the Black Hills Exploration and Production, Inc. (“Black Hills”) interests. It is our understanding that the proved reserves estimated in this report constitute 100 percent of all proved reserves owned by Black Hills.


			Proved
		Proved	Developed
		Developed	Non-	Proved	Total
		Producing	Producing	Undeveloped	Proved
Net Reserves
Oil/Condensate	- Mbbl	4,419.0	0.6	1,506.3	5,925.9
Gas	- MMcf	24,779.7	688.5	5,400.7	30,868.8
Revenue
Oil/Condensate	- M$	315,232.0	40.8	104,418.4	419,691.1
Gas	- M$	88,777.5	2,526.7	20,001.2	111,305.4
Plant	- M$	14,495.4	0	0	14,495.4
Severance and
Ad Valorem Taxes	- M$	44,399.6	333.8	13,692.7	58,426.2
Operating Expenses	- M$	103,152.1	500.6	12,957.9	116,610.6
Investments	- M$	0	355.5	35,560.9	35,916.5
Operating Income (BFIT)	- M$	270,953.3	1,377.5	62,208.0	334,538.7
Discounted at 10.0%	- M$	129,786.8	1,041.7	23,338.7	154,167.2

The detailed forecasts of reserves and economics are presented in the attached tables. Tables I-Proved, I-PDP, I-PDNP and I-PUD are summaries of the reserves and associated economics by reserve category. Under tabs by reserve category, these tables are then presented along with corresponding Table II's, which are summaries of the ultimate recovery, gross and net reserves, ownership, revenue, expenses, investments, net income and discounted cash flows for the individual wells in each Table I. These tables are sorted by state and then lease/well name. Page 1 of the Appendix explains the type of data in these tables. The methods employed in estimating reserves are described in page 2 of the Appendix.

The oil, condensate, gas and plant products prices utilized were average prices for the 12 months of 2010. The average was calculated using the posted first-day-of-the-month price for each month. The resulting hydrocarbon pricing of $4.38 per MMBtu of gas and $79.43 per barrel of oil/condensate was applied without escalation. Basis differentials, contractual differentials, heating value adjustments and transportation/processing/gathering fees were supplied by Black Hills and applied to these prices by producing area. The average adjusted product prices were $3.61 per Mcf and $70.82 per barrel. Deductions were applied to the net gas volumes for fuel and shrinkage.

Operating expenses were supplied by Black Hills and were accepted as furnished. Operating cost components include direct operating expenses, compression fees, water disposal costs and appropriate COPAS charges. Severance and ad valorem rates were specified by state based on historical averages. Neither expenses nor investments were escalated. The cost of plugging and the salvage value of equipment have not been considered.

Black Hills owns 44.7% of the Newcastle Gas Processing Plant. Future revenues are earned on residue volumes available from the plant after processing gas supplied by production from Finn-Shurley, Jiggs-Thompson and Boggy Creek fields. Future residue volumes were estimated by application of historical plant residue volume percentages to future gas volumes expected to be processed at the plant. The volume of future gas to be processed at the plant was estimated by extrapolation of the historical decline of the gas into the plant to the estimated economic limit of profitable operation for the plant. The revenues and expenses associated with the plant are included in Table I - PDP and reflect only Black Hills' net ownership.

The proved reserve classifications conform to criteria of the Securities and Exchange Commission as defined in pages 3-4 of the Appendix. The reserves were estimated using a combination of the production performance, volumetric and analogy methods, in each case as we considered appropriate and necessary, under the circumstances, to establish the conclusions set forth herein. The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions have not been considered and such changes could affect Black Hills' ability to recover the estimated reserves. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates were based on interpretations of factual data furnished by Black Hills. Production and pressure data comes from internal oil and gas measurement systems for operated properties, by well. Third party production is derived from state reports submitted by the operator for each well. Oil and gas price forecasts, operating expenses and ownership interests were supplied by Black Hills and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. An on-site inspection of these properties has not been made nor have the wells been tested by Cawley, Gillespie & Associates, Inc.

Mr. Meekins has been practicing consulting petroleum engineering at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas and has over 23 years of practical experience in petroleum engineering, with over 21 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a BS in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the Black Hills Gas Resources, Inc. (“Black Hills”) interests. It is our understanding that the proved reserves estimated in this report constitute 100 percent of all proved reserves owned by Black Hills.


			Proved
		Proved	Developed
		Developed	Non-	Proved	Total
		Producing	Producing	Undeveloped	Proved
Net Reserves
Oil/Condensate	- Mbbl	14.7	0	0	14.7
Gas	- MMcf	29,881.0	830.8	619.9	31,331.6
Revenue
Oil/Condensate	- M$	993.1	0	0	993.1
Gas	- M$	106,342.6	2,932.6	2,188.1	111,463.3
Severance and
Ad Valorem Taxes	- M$	20,341.9	578.3	431.5	21,351.7
Operating Expenses	- M$	27,706.2	764.1	289.6	28,759.9
Investments	- M$	0	704.3	650.5	1,354.8
Operating Income (BFIT)	- M$	59,287.6	885.9	816.5	60,990.0
Discounted at 10.0%	- M$	36,764.5	440.3	443.7	37,648.6

The oil, condensate, gas and plant products prices utilized were average prices for the 12 months of 2010. The average was calculated using the posted first-day-of-the-month price for each month. The resulting hydrocarbon pricing of $4.38 per MMBtu of gas and $79.43 per barrel of oil/condensate was applied without escalation. Basis differentials, contractual differentials, heating value adjustments and transportation/processing/gathering fees were supplied by Black Hills and applied to these prices by producing area. The average adjusted product prices were $3.56 per Mcf and $67.52 per barrel. Deductions were applied to the net gas volumes for fuel and shrinkage.

As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the Black Hills Plateau Production, LLC (“Black Hills”) interests. It is our understanding that the proved reserves estimated in this report constitute 100 percent of all proved reserves owned by Black Hills.


			Proved
		Proved	Developed
		Developed	Non-	Proved	Total
		Producing	Producing	Undeveloped	Proved
Net Reserves
Oil/Condensate	- Mbbl	0	0	0	0
Gas	- MMcf	10,469.4	1,005.9	21,776.8	33,252.0
Revenue
Oil/Condensate	- M$	0	0	0	0
Gas	- M$	35,092.3	2,997.5	68,546.4	106,636.2
Severance and
Ad Valorem Taxes	- M$	1,968.1	168.2	3,845.5	5,981.8
Operating Expenses	- M$	11,939.0	638.1	12,747.5	25,324.6
Investments	- M$	0	323.7	36,209.9	36,533.7
Operating Income (BFIT)	- M$	21,185.2	1,867.5	15,743.5	38,796.2
Discounted at 10.0%	- M$	11,443.2	707.9	-7,413.2	4,737.9

The oil, condensate, gas and plant products prices utilized were average prices for the 12 months of 2010. The average was calculated using the posted first-day-of-the-month price for each month. The resulting hydrocarbon pricing of $4.38 per MMBtu of gas and $79.43 per barrel of oil/condensate was applied without escalation. Basis differentials, contractual differentials, heating value adjustments and transportation/processing/gathering fees were supplied by Black Hills and applied to these prices by producing area. The average adjusted gas price was $3.21 per Mcf. Deductions were applied to the net gas volumes for fuel and shrinkage.

The reserve estimates were based on interpretations of factual data furnished by Black Hills. Oil and gas price forecasts, operating expenses and ownership interests were supplied by Black Hills and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. An on-site inspection of these properties has not been made nor have the wells been tested by Cawley, Gillespie & Associates, Inc.

(2) (3) Gross Production (8/8th) for the years/months which are economical. These are expressed as thousands of barrels (Mbbl) and millions of cubic feet (MMcf) of gas at standard conditions. Total future production, cumulative production to effective date, and ultimate recovery at the effective date are shown following the annual/monthly forecasts.

(17) Other Deductions include operator's overhead, compression-gathering expenses, transportation costs, water disposal costs and net profits burdens. These are the share of costs payable by the evaluated expense interests and take into account any changes in interests.

(18) Investments, if any, include work-overs, future drilling costs, pumping units, etc. and may be included either tangible or intangible or both, and the costs for plugging and the salvage value of equipment at abandonment may be shown as negative investments at end of life.

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

Production performance. This method employs graphical anal-yses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increas-ing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the com-plexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric meth-od is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncompli-cated.

Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

"(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations- prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

"(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

"(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

"(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

"(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

"(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

"(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S-K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

"(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”