Exhibit 99.2

[CAWLEY, GILLESPIE & ASSOCIATES, INC. LETTERHEAD]

January 9, 2012

Mr. J. Douglas Lang

Vice President - Reservoir

Engineering/Acquisitions

Whiting Petroleum Corporation

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

Re:       Evaluation Summary – SEC Price

Whiting Petroleum Corporation Interests

Total Proved Reserves

Various States

As of December 31, 2011

Pursuant to the Guidelines of the Securities and

Exchange Commission for Reporting Corporate

Reserves and Future Net Revenue

Dear Mr. Lang:

As requested, we are submitting our estimates of total proved reserves and forecasts of economics attributable to the interests in certain oil and gas properties located in various states within the United States.  This report, completed January 9, 2012 covers 100% of the proved reserves estimated for Whiting Petroleum Corporation.  This report includes results for an SEC pricing scenario.  The results of this evaluation are presented in the accompanying tabulations, with a composite summary presented below:

		Proved Developed Producing	Proved Developed Behind Pipe	Proved Developed Non-Producing	Proved Undeveloped	Total Proved
Net Reserves
Oil	- Mbbl	162,662.9	1,492.9	16,819.7	79,169.0	260,144.6
Gas	- MMcf	194,927.5	10,753.3	5,616.1	73,678.3	284,975.4
NGL	- Mbbl	18,043.1	511.5	3,553.8	15,500.2	37,608.5
Revenue
Oil	- M$	14,440,153.0	135,831.8	1,533,104.4	7,089,353.5	23,198,444.0
Gas	- M$	882,521.6	48,827.2	25,340.4	293,089.4	1,249,778.4
NGL	- M$	1,213,717.3	29,016.9	223,747.1	900,383.0	2,366,863.8
Severance Taxes	- M$	1,281,367.5	13,222.6	93,150.6	604,971.0	1,992,711.4
Ad Valorem Taxes	- M$	250,112.3	2,160.2	63,577.2	169,964.9	485,814.5
Operating Expenses	- M$	4,722,635.0	43,679.0	388,711.2	1,274,580.5	6,429,606.0
Investments	- M$	148,778.8	11,064.6	132,398.8	1,690,570.6	1,982,813.0
Net Operating Income	- M$	10,133,503.0	143,549.5	1,104,354.1	4,542,739.5	15,924,139.0
Discounted @ 10%	- M$	5,459,062.5	34,537.8	427,403.2	1,483,680.1	7,404,684.0

The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

Hydrocarbon Pricing

As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $96.19 per Bbl and $4.12 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $92.81 per Bbl and Houston Ship Channel pricing at $4.06 per MMBtu, as of December 31, 2011.  Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office. Prices were not escalated in the SEC scenario.  The average adjusted prices used in the estimation of proved reserves were $89.18 per Bbl of oil, $62.93 per Bbl of natural gas liquids and $4.39 per Mcf of natural gas.

Capital, Expenses and Taxes

Capital expenditures, lease operating expenses and Ad Valorem tax values were forecast as provided by your office.  As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for operated properties and no credit or deduction is made for producing overhead paid to the company by other owners of the operated properties. Capital costs and lease operating expenses were held constant in accordance with SEC guidelines.  Severance tax rates were applied at normal state percentages of oil and gas revenue.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 3 and 4 of the Appendix.  The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein.  The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered.  However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

Reserve Estimation Methods

The methods employed in estimating reserves are described on page 2 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Miscellaneous

An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc.  Possible environmental liability related to the properties has not been investigated nor considered.  The cost of plugging and the salvage value of equipment at abandonment have not been included.

The reserve estimates were based on interpretations of factual data furnished by your office.  We have used all methods and procedures as we considered necessary under the circumstances to prepare the report.  We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report.  Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied by you 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 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.

The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.

Yours very truly,

/s/ Robert D. Ravnaas                                                                   

Robert D. Ravnaas, P.E.

President

Cawley, Gillespie & Associates

Texas Registered Engineering Firm F-693

APPENDIX

Explanatory Comments for Individual Tables

HEADINGS

Table Number

Effective Date of the Evaluation

Identity of Interest Evaluated

Reserve Classification and Development Status

Operator – Property Name

Field (Reservoir) Names – County, State

FORECAST

(Columns)
(1) (11) (21)	Calendar or Fiscal years/months commencing on effective date.
(2) (3) (4)	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.
(5) (6) (7)	Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production.  These values take into account changes in interest and gas shrinkage.
(8)	Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)	Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)	Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)	Revenue derived from oil sales -- column (5) times column (8).
(13)	Revenue derived from gas sales -- column (6) times column (9).
(14)	Revenue derived from NGL sales -- column (7) times column (10).
(15)	Revenue derived from other sources.
(16)	Revenue derived from hedge positions.
(17)	Total Revenue – sum of column (12) through column (16).
(18)	Production-Severance taxes deducted from gross oil and NGL revenue.
(19)	Production-Severance taxes deducted from gross gas revenue.
(20)	Revenue after taxes – column (17) less column (18) and column (19).
(22)	Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)	Ad Valorem taxes.
(24)	Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(25)	3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(26)	Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
(27)	Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include 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.
(28) (29)	Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27).  The data in column (28) are accumulated in column (29).  Federal income taxes have not been considered.
(30)	Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

Input Data	•	Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
Interests	•	Initial and final expense and revenue interests are shown below columns (27-28).
DCF Profile	•	The cash flow discounted at six different rates are shown at the bottom of columns (29-30).  Interest has been compounded monthly.
Life	•	The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes	•	Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.

Cawley, Gillespie & Associates, Inc.

Appendix

Page 1

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) productionperformance, (2) materialbalance, (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.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.  This method employs graphical anal­yses 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 increas­ing 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 com­plexity 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 meth­od 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 uncomplicated.

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.

Cawley, Gillespie & Associates, Inc.

Appendix

Page 2

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210­.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adher­ence to the following definitions of oil and gas reserves:

“(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.

“(6)           Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)         Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii)         Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(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.

“(ii)         Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(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.

Cawley, Gillespie & Associates, Inc.

Appendix

Page 3

“(18)           Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(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.

“(iii)         Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)         See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

"(17)           Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(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.

“(iii)         Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(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).”

Cawley, Gillespie & Associates, Inc.

Appendix

Page 4

[CAWLEY, GILLESPIE & ASSOCIATES, INC. LETTERHEAD]

January 10, 2012

Mr. J. Douglas Lang

Vice President - Reservoir

Engineering/Acquisitions

Whiting Petroleum Corporation

1700 Broadway, Suite 2300

Denver, Colorado 80290-2300

Re:           Evaluation Summary – SEC Price

Whiting Petroleum Corporation Interests

Probable and Possible Reserves

Various States

As of December 31, 2011

Pursuant to the Guidelines of the Securities and

Exchange Commission for Reporting Corporate

Reserves and Future Net Revenue

Dear Mr. Lang:

As requested, we are submitting our estimates of probable and possible reserves and forecasts of economics attributable to the interests in certain oil and gas properties located in various states within the United States.  This report, completed January 10, 2012 covers 100% of the probable and possible reserves estimated for Whiting Petroleum Corporation.  This report includes results for an SEC pricing scenario.  The results of this evaluation are presented in the accompanying tabulations, with a composite summary presented below:

		Probable Developed	Probable Undeveloped	Total Probable	Possible Developed	Possible Undeveloped	Total Possible
Net Reserves
Oil	- Mbbl	987.0	56,140.6	57,127.6	780.8	128,285.2	129,066.0
Gas	- MMcf	8,337.3	202,536.3	210,873.6	1,890.6	185,321.5	187,212.1
NGL	- Mbbl	124.8	13,581.3	13,706.1	123.8	34,863.6	34,987.4
Revenue
Oil	- M$	90,550.8	5,042,621.0	5,133,171.5	70,031.6	11,467,247.0	11,537,278.0
Gas	- M$	40,178.9	842,643.3	882,822.3	8,401.1	729,419.4	737,820.6
NGL	- M$	7,214.5	736,694.9	743,909.5	7,630.4	2,067,387.8	2,075,018.3
Severance Taxes	- M$	8,382.7	428,721.4	437,104.0	4,782.5	941,148.6	945,931.1
Ad Valorem Taxes	- M$	1,957.6	161,798.4	163,756.0	1,455.7	363,348.7	364,804.3
Operating Expenses	- M$	33,936.8	1,120,704.5	1,154,641.3	13,036.6	1,734,642.5	1,747,679.1
Investments	- M$	6,370.3	1,676,497.0	1,682,867.4	7,145.6	2,575,933.5	2,583,079.3
Net Operating Income	- M$	87,296.9	3,234,238.0	3,321,534.3	59,642.7	8,648,980.0	8,708,623.0
Discounted @ 10%	- M$	43,371.4	992,051.6	1,035,422.6	35,313.7	1,988,436.4	2,023,750.1

The discounted cash flow value shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

Hydrocarbon Pricing

As requested for the SEC scenario, initial WTI spot oil and Henry Hub Gas Daily prices of $96.19 per Bbl and $4.12 per MMBtu, respectively, were adjusted individually to WTI posted pricing at $92.81 per Bbl and Houston Ship Channel pricing at $4.06 per MMBtu, as of December 31, 2011.  Further adjustments were applied on a lease level basis for oil price differentials, gas price differentials and heating values as furnished by your office.  Prices were not escalated in the SEC scenario.  The average adjusted prices used in the estimation of Probable reserves were $89.86 per Bbl of oil, $54.28 per Bbl of natural gas liquids and $4.19 per Mcf of natural gas.  For the Possible reserves, the average adjusted prices were $89.39 per Bbl of oil, $59.31 per Bbl of natural gas liquids and $3.94 per Mcf of natural gas.

Capital, Expenses and Taxes

Capital expenditures, lease operating expenses and Ad Valorem tax values were forecast as provided by your office.  As you explained, the capital costs were based on the most current estimates, lease operating expenses were based on the analysis of historical actual expenses, operating overhead is included for operated properties and no credit or deduction is made for producing overhead paid to the company by other owners of the operated properties.  Capital costs and lease operating expenses were held constant in accordance with SEC guidelines.  Severance tax rates were applied at normal state percentages of oil and gas revenue.

SEC Conformance and Regulations

The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined on page 4 of the Appendix.  The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein.  The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered.  However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

Reserve Estimation Methods

The methods employed in estimating reserves are described on pages 2 through 4 of the Appendix. Reserves for producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.

Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting developed non-producing and undeveloped reserves.  The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

Miscellaneous

An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc.  Possible environmental liability related to the properties has not been investigated nor considered.  The cost of plugging and the salvage value of equipment at abandonment have not been included.

The reserve estimates were based on interpretations of factual data furnished by your office.  We have used all methods and procedures as we considered necessary under the circumstances to prepare the report.  We believe that the assumptions, data, methods and procedures were appropriate for the purpose served by this report.  Production data, gas prices, gas price differentials, expense data, tax values and ownership interests were also supplied by you 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 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.

The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter.

Yours very truly,

/s/ Robert D. Ravnaas                                                                

Robert D. Ravnaas, P.E.

President

Cawley, Gillespie & Associates

Texas Registered Engineering Firm F-693

APPENDIX

Explanatory Comments for Individual Tables

HEADINGS

Table Number

Effective Date of the Evaluation

Identity of Interest Evaluated

Reserve Classification and Development Status

Operator – Property Name

Field (Reservoir) Names – County, State

FORECAST

(Columns)
(1) (11) (21)	Calendar or Fiscal years/months commencing on effective date.
(2) (3) (4)	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.
(5) (6) (7)	Net Production accruable to evaluated interest is calculated by multiplying the revenue interest times the gross production.  These values take into account changes in interest and gas shrinkage.
(8)	Average (volume weighted) gross liquid price per barrel before deducting production-severance taxes.
(9)	Average (volume weighted) gross gas price per Mcf before deducting production-severance taxes.
(10)	Average (volume weighted) gross NGL price per barrel before deducting production-severance taxes.
(12)	Revenue derived from oil sales -- column (5) times column (8).
(13)	Revenue derived from gas sales -- column (6) times column (9).
(14)	Revenue derived from NGL sales -- column (7) times column (10).
(15)	Revenue derived from other sources.
(16)	Revenue derived from hedge positions.
(17)	Total Revenue – sum of column (12) through column (16).
(18)	Production-Severance taxes deducted from gross oil and NGL revenue.
(19)	Production-Severance taxes deducted from gross gas revenue.
(20)	Revenue after taxes – column (17) less column (18) and column (19).
(22)	Operating Expenses are direct operating expenses to the evaluated working interest and may include combined fixed rate administrative overhead charges for operated oil and gas producers known as COPAS.
(23)	Ad Valorem taxes.
(24)	Work-over Expenses are non-direct operating expenses and may include maintenance, well service, compressor, tubing, and pump repair.
(25)	3rd Party COPAS are combined fixed rate administrative overhead charges for non-operated oil and gas producers.
(26)	Other Deductions may include compression-gathering expenses, transportation costs and water disposal costs.
(27)	Investments, if any, include re-completions, future drilling costs, pumping units, etc. and may include 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.
(28) (29)	Future Net Cash Flow is column (18) less the total of column (19), column (22), column (24), column (25), column (26) and column (27).  The data in column (28) are accumulated in column (29).  Federal income taxes have not been considered.
(30)	Cumulative Discounted Cash Flow is calculated by discounting monthly cash flows at the specified annual rates.

MISCELLANEOUS

Input Data	•	Evaluation parameters such as rates, tax percentages, and expenses are shown below columns (21-26).
Interests	•	Initial and final expense and revenue interests are shown below columns (27-28).
DCF Profile	•	The cash flow discounted at six different rates are shown at the bottom of columns (29-30).  Interest has been compounded monthly.
Life	•	The economic life of the appraised property is noted in the lower right-hand corner of the table.
Footnotes	•	Well ID information or other pertinent comments may be shown in the lower left-hand footnotes.

Cawley, Gillespie & Associates, Inc.

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APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) productionperformance, (2) materialbalance, (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.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance.  This method employs graphical anal­yses 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 increas­ing 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 com­plexity 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 meth­od 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 uncomplicated.

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.

Cawley, Gillespie & Associates, Inc.

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APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210­.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

“(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.

“(6)           Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

“(i)         Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

“(ii)         Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“(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.

“(ii)         Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

“(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.

Cawley, Gillespie & Associates, Inc.

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“(18)           Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(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.

“(iii)         Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)         See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

“(17)           Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(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.

“(iii)         Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(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).”

Cawley, Gillespie & Associates, Inc.

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[CAWLEY, GILLESPIE & ASSOCIATES, INC. LETTERHEAD]

Professional Qualifications of Robert D. Ravnaas, P.E.

President of Cawley, Gillespie & Associates

Mr. Ravnaas has been a Petroleum Consultant for Cawley, Gillespie & Associates (CG&A) since 1983, and became President in 2011.  He has completed numerous field studies, reserve evaluations and reservoir simulation, waterflood design and monitoring, unit equity determinations and producing rate studies.  He has testified before the Texas Railroad Commission in unitization and field rules hearings.  Prior to CG&A he worked as a Production Engineer for Amoco Production Company.  Mr. Ravnaas received a B.S. with special honors in Chemical Engineering from the University of Colorado at Boulder, and a M.S. in Petroleum Engineering from the University of Texas at Austin.  He is a registered professional engineer in Texas, No. 61304, and a member of the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers, the American Association of Petroleum Geologists and the Society of Professional Well Log Analysts.