DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 This is a digital representation of a DeGolyer and MacNaughton report. Each file contained herein is intended to be a manifestation of certain data in the subject report and as such is subject to the definitions, qualifications, explanations, conclusions, and other conditions thereof. The information and data contained in each file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 August 2, 2019 Evolution Petroleum Corporation 1155 Dairy Ashford Rd., Suite 425 Houston, Texas 77079 Ladies and Gentlemen: Pursuant to your request, this report of third party presents an independent evaluation, as of June 30, 2019, of the extent and value of the estimated net proved, probable, and possible oil, natural gas liquids (NGL), and gas reserves of certain properties in which Evolution Petroleum Corporation and its subsidiaries (collectively referred to herein as Evolution) have represented they hold an interest. This evaluation was completed on August 2, 2019. The properties evaluated herein are located in the Delhi field located in Franklin, Madison, and Richland Parishes, Louisiana. Evolution has represented that these properties account for 100 percent on a net equivalent barrel basis of Evolution’s net proved reserves as of June 30, 2019. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with the guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Evolution. Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after June 30, 2019. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Evolution after deducting all interests held by others. Values for proved, probable, and possible reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes,

2 DeGolyer and MacNaughton operating expenses, capital costs, and abandonment costs from future gross revenue. Operating expenses include field operating expenses, carbon dioxide purchase expenses, transportation and processing expenses, compression charges, and overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field maintenance costs. Abandonment costs are represented by Evolution to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with abandonment. At the request of Evolution, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at the arbitrary nominal discount rate of 10 percent per year compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold. Estimates of reserves and revenue should be regarded only as estimates that may change as production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Information used in the preparation of this report was obtained from Evolution and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Evolution with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report. Definition of Reserves Petroleum reserves included in this report are classified by degree of proof as proved, probable, or possible. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were

3 DeGolyer and MacNaughton estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: 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 the 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.

4 DeGolyer and MacNaughton (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. 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

5 DeGolyer and MacNaughton 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 (iv) and (vi) of the definition of possible reserves. 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

6 DeGolyer and MacNaughton 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 (iii) of the proved oil and gas reserves definition, 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. 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.

7 DeGolyer and MacNaughton 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 [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Estimates of probable and possible reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable with estimates of proved reserves.

8 DeGolyer and MacNaughton Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definition of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, the development plans provided by Evolution, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved, probable, or possible. Evolution has represented that its senior management is committed to the development plan provided by Evolution and that Evolution has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities. The volumetric method was used to estimate the original oil in place (OOIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report. In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

9 DeGolyer and MacNaughton Data provided by Evolution from wells drilled through June 30, 2019, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available through June 30, 2019. Cumulative production, as of June 30, 2019, was deducted from the estimated gross ultimate recovery to estimate gross reserves. Oil reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions. NGL reserves are the result of low-temperature plant processing. Oil and NGL reserves included in this report are expressed in thousands of barrels (Mbbl) representing 42 United States gallons per barrel. Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. All gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 15.025 pounds per square inch absolute (psia). Gas reserves included in this report are expressed in millions of cubic feet (MMcf). All of the produced gas is consumed as fuel or lost in processing, so sales gas reserves were estimated herein to be zero. Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein are associated gas. All developed reserves estimated herein are considered to be developed producing. The proved, probable, and possible oil, NGL, and gas reserves estimated for the evaluated interests are located in the Holt-Bryant reservoir in the Delhi field. This reservoir was originally discovered in 1944, produced under primary means until unitized for water injection in 1953, and was purchased by Denbury Onshore LLC (Denbury) in 2006 in order to initiate a carbon dioxide injection program. Average depth is 3,235 feet subsea. The Delhi Holt-Bryant Unit area is 13,636 acres,

10 DeGolyer and MacNaughton and the reservoir area is 6,189 acres. Denbury began carbon dioxide injection in 3 patterns in November 2009 and has since expanded to 15 patterns, which have all seen production response to injection. Cumulative recovery from the Delhi Holt-Bryant Unit prior to carbon dioxide injection was about 195 million barrels. Estimates of ultimate recovery resulting from carbon dioxide injection in the Holt-Bryant reservoir were obtained after applying recovery factors to the current carbon dioxide flood area OOIP (flood area OOIP) of 336.3 million barrels. This recovery factor was based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. Oil production response to the carbon dioxide injection was observed in March 2010. Based on the production response from a number of producers, and noting the amount of carbon dioxide injection to date, the total recovery factor for proved reserves was estimated to be about 14.4 percent of the flood area OOIP. The recovery factor for incremental probable reserves was estimated to be about 4.6 percent of the flood area OOIP, and the recovery factor for incremental possible reserves was estimated to be about 4.2 percent of the flood area OOIP. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production. Primary Economic Assumptions Revenue values in this report were estimated using initial prices, expenses, and costs provided by Evolution. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein: Oil and NGL Prices Evolution has represented that the oil and NGL prices were based on West Texas Intermediate (WTI) pricing, calculated as the unweighted arithmetic average of the first-day-of-the- month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The oil and NGL prices were calculated using differentials furnished by Evolution to the reference price of $61.62 per barrel and held constant thereafter. The volume-weighted average prices attributable to

11 DeGolyer and MacNaughton the estimated proved reserves over the lives of the properties were $64.54 per barrel of oil and $23.83 per barrel of NGL. Production and Ad Valorem Taxes Production taxes were based on current Louisiana tax rates. Evolution has represented that the Delhi carbon dioxide flood has been qualified as a tertiary recovery project and that no oil production taxes will be charged until certain investment and interest expenses have been paid out from the project revenue. Oil production taxes then revert to a 12.5-percent rate, which rate is held constant until average oil production per well drops below 25 barrels per day, and then reduced to 6.25 percent thereafter. Payout is not expected to occur prior to depletion, so no oil production taxes are included herein. Production taxes for NGL are included at 16 cents per barrel of the NGL revenue as represented by Evolution. Evolution has also represented that ad valorem taxes are modeled at 0.48 percent. Operating Expenses, Capital Costs, and Abandonment Costs Estimates of operating expenses, provided by Evolution and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2019 values, provided by Evolution, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Evolution for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

12 DeGolyer and MacNaughton In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235- 50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50- 31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year. To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. Summary of Conclusions The estimated net proved, probable, and possible reserves, as of June 30, 2019, of the properties evaluated herein were based on the definition of proved, probable, and possible reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

13 DeGolyer and MacNaughton Estimated by DeGolyer and MacNaughton Net Reserves as of June 30, 2019 Oil NGL Sales Gas (Mbbl) (Mbbl) (MMcf) Proved Developed Producing 6,274 1,124 0 Developed Non-Producing 00 0 Undeveloped 1,342 241 0 Total Proved 7,616 1,365 0 Probable Developed Producing 3,516 630 0 Developed Non-Producing 00 0 Undeveloped 540 97 0 Total Probable 4,056 727 0 Possible Developed Producing 3,323 596 0 Developed Non-Producing 00 0 Undeveloped 341 61 0 Total Possible 3,664 657 0 Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves. The estimated future revenue to be derived from the production and sale of the net proved, probable, and possible reserves, as of June 30, 2019, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$): Proved Developed Developed Total Producing Non-Producing Undeveloped Proved (M$) (M$) (M$) (M$) Future Gross Revenue 431,706 0 92,331 524,037 Production Taxes 175 0 37 212 Ad Valorem Taxes 1,880 0 402 2,282 Operating Expenses 173,144 0 32,902 206,046 Capital Costs 2,866 0 8,600 11,466 Abandonment Costs 6,252 0 677 6,929 Future Net Revenue 247,389 0 49,713 297,102 Present Worth at 10 Percent 140,493 0 16,120 156,613

14 DeGolyer and MacNaughton Probable Developed Developed Total Producing Non-Producing Undeveloped Probable (M$) (M$) (M$) (M$) Future Gross Revenue 241,926 0 37,172 279,098 Production Taxes 98 0 15 113 Ad Valorem Taxes 1,053 0 162 1,215 Operating Expenses 67,749 0 8,211 75,960 Capital Costs 0 0 0 0 Abandonment Costs 0 0 0 0 Future Net Revenue 173,026 0 28,784 201,810 Present Worth at 10 Percent 62,609 0 5,618 68,227 Possible Developed Developed Total Producing Non-Producing Undeveloped Possible (M$) (M$) (M$) (M$) Future Gross Revenue 228,661 0 23,487 252,148 Production Taxes 92 0 10 102 Ad Valorem Taxes 996 0 102 1,098 Operating Expenses 53,881 0 7,500 61,381 Capital Costs 0 0 0 0 Abandonment Costs 0 0 0 0 Future Net Revenue 173,692 0 15,875 189,567 Present Worth at 10 Percent 36,681 0 1,346 38,027 Notes: 1. Future income taxes have not taken into account in the preparation of these estimates. 2. Values for probable and possible reserves have not been risk adjusted to make them comparable to values for proved reserves. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the June 30, 2019, estimated reserves.