EX-99.1 11 engrsreportexh991.htm EXHIBIT 99.1
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 14, 2018 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, 2018, of the extent and value of the estimated net proved, probable, and possible oil, condensate, 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 own an interest. This evaluation was completed on August 14, 2018. The properties evaluated consist of working and royalty interests 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, 2018. 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 United States Securities and Exchange Commission (SEC). 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. Estimates of reserves 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, 2018. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Evolution after deducting all interests owned 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 that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is

2 DeGolyer and MacNaughton calculated by deducting production and ad valorem taxes, operating expenses, and capital and abandonment costs from the future gross revenue. Operating expenses include field operating expenses, carbon dioxide purchase expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at 10 percent 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 future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue 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 this report was obtained from Evolution, from records on file with the appropriate regulatory agencies, 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. It was not considered necessary to make a field examination of the physical condition and operation of the properties. 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 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

3 DeGolyer and MacNaughton 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 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 the 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 proved, probable, and possible oil, condensate, 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, 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. The volumetric method was used to estimate the original oil in place (OOIP). Structure maps were utilized to delineate each reservoir, and isopach maps were utilized to estimate reservoir volume. Electrical logs, radioactivity logs, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. 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

9 DeGolyer and MacNaughton Holt-Bryant reservoir were obtained after applying recovery factors to the current carbon dioxide flood area OOIP (flood area OOIP) of 325.1 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 4.6 percent of the flood area OOIP. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production. Future oil and gas producing rates estimated for this report were based on production rates considering the most recent data available. The rates used for future production were estimated to be within the capacity of a well or reservoir to produce. In the preparation of this report, as of June 30, 2018, production data through June 2018 were available. Gross production through June 30, 2018, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves. Data available from wells drilled through June 2018 were used in this report. Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation and are expressed in thousands of barrels (Mbbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity. Evolution has represented that it owns an interest in the Delhi Plant that began operation in December 2016 and that the Delhi Plant processes gas from the Delhi Holt-Bryant Unit to produce NGL and methane. The methane is used for fuel in the field and for plant operations. The NGL yield through the plant was provided by Evolution. This NGL yield was used to estimate the NGL reserves attributable to the leases within the Delhi Holt-Bryant Unit. NGL reserves are expressed in thousands of barrels (Mbbl) representing 42 United States gallons per barrel.

10 DeGolyer and MacNaughton Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be delivered into a gas pipeline for sale after field separation, processing, fuel use, and flare. All gas reserves are expressed at a temperature base of 60 degrees Fahrenheit and at a pressure base of 15.025 pounds per square inch absolute. 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 the sales gas reserves are zero. The estimated net proved, probable, and possible reserves attributable to Evolution from the properties evaluated, as of June 30, 2018, are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf): Net Reserves Oil and Sales Condensate NGL Gas (Mbbl) (Mbbl) (MMcf) Proved Developed Producing 6,292 994 0 Developed Non-Producing 000 Undeveloped 1,798 284 0 Total Proved 8,090 1,278 0 Probable Developed Producing 3,123 493 0 Developed Non-Producing 000 Undeveloped 757 120 0 Total Probable 3,880 613 0 Possible Developed Producing 3,458 546 0 Developed Non-Producing 000 Undeveloped 488 77 0 Total Possible 3,946 623 0 Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves. 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:

11 DeGolyer and MacNaughton Oil and Condensate Prices An oil and condensate price differential was estimated from data provided by Evolution. The oil and condensate price was calculated by applying this differential to a West Texas Intermediate (WTI) crude oil price of $57.50 per barrel and was held constant over the lives of the properties. The WTI price of $57.50 is the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to June 30, 2018. The volume-weighted average price attributable to the proved reserves over the lives of the properties was $58.31 per barrel. NGL Prices Evolution has represented that the NGL price was calculated by applying a differential to a WTI crude oil price of $57.50 per barrel and was held constant over the lives of the properties. The WTI price of 57.50 is the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12- month period prior to June 30, 2018. The volume-weighted average price attributable to the proved reserves over the lives of the properties was $38.97 per barrel. Operating Expenses, Capital Costs, and Abandonment Costs Estimates of operating expenses, capital costs, and abandonment costs, based on information provided by Evolution for current costs, were used for the lives of the properties with no increases in the future based on inflation. Future capital and abandonment costs as provided by Evolution were estimated using 2018 values and were not adjusted for inflation. Evolution has represented that the abandonment costs include site restoration and reclamation.

12 DeGolyer and MacNaughton Production and Ad Valorem Taxes Production taxes were based on current state tax rates. Evolution has represented that the Delhi carbon dioxide flood has been qualified as a tertiary recovery project and that no oil and condensate production taxes will be charged until payout of investment and certain interest expenses from the project revenue. Oil and condensate 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 and condensate production taxes are included herein. Production taxes for NGL are included at 0.82 percent of the NGL revenue as represented by Evolution. Evolution has also represented that no ad valorem taxes are charged to the Louisiana royalty owners, so no ad valorem taxes are included herein for the royalty interests. The estimated future revenue to be derived from the production and sale of the estimated net proved, probable, and possible reserves, as of June 30, 2018, of the properties evaluated 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 405,604 0 115,930 521,534 Production Taxes 319 0 91 410 Ad Valorem Taxes 1,518 0 434 1,952 Operating Expenses 184,927 0 41,190 226,117 Capital Costs 2,866 0 12,805 15,671 Abandonment Costs 5,909 0 633 6,542 Future Net Revenue 210,065 0 60,777 270,842 Present Worth at 10 Percent 125,637 0 20,407 146,044

13 DeGolyer and MacNaughton Probable Developed Developed Total Producing Non-Producing Undeveloped Probable (M$) (M$) (M$) (M$) Future Gross Revenue 201,331 0 48,812 250,143 Production Taxes 158 0 38 196 Ad Valorem Taxes 753 0 183 936 Operating Expenses 72,692 0 11,474 84,166 Capital Costs 0 0 0 0 Abandonment Costs 0 0 0 0 Future Net Revenue 127,728 0 37,117 164,845 Present Worth at 10 Percent 48,937 0 7,708 56,645 Possible Developed Developed Total Producing Non-Producing Undeveloped Possible (M$) (M$) (M$) (M$) . Future Gross Revenue 222,941 0 31,452 254,393 Production Taxes 175 0 25 200 Ad Valorem Taxes 834 0 117 951 Operating Expenses 51,981 0 10,291 62,272 Capital Costs 0 0 0 0 Abandonment Costs 0 0 0 0 Future Net Revenue 169,951 0 21,019 190,970 Present Worth at 10 Percent 40,571 0 1,820 42,391 Notes: 1. Future income tax expenses were 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. 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, condensate, 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 Financial Accounting Standards Board 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 Securities and Exchange Commission; 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.