EX-99.6 13 a2216543zex-99_6.htm EX-99.6

Exhibit 99.6

June 28, 2013

Evolution Petroleum Corp

2500 City West Blvd., Suite 1300

Houston, Texas 77042

Attn: Mr. Daryl Mazzanti

| Re: | Reserves and Economic Evaluation
|  | Effective July I, 2013
|  | SEC Pricing-Fiscal Year-End 2012-13

EXECUTIVE SUMMARY

An evaluation was performed on primarily undeveloped acreage located in Kay County, Oklahoma in which Evolution Petroleum Corp. (“‘Evolution”) owns leasehold. The lands are located in thirty-eight sections within six townships (26N, 27N, 28N, Ranges IE, 2E) as depicted (highlighted) on the attached maps. Evolution and another party have acquired approximately 11,878 net acres in the sections and Evolution owns 33.91841% of the leasehold rights acquired (approximately 4,029 acres). The attached Exhibit A is a summary listing of the sections, leased acreage net to Evolution, and the projected working and net interests. Information used in this evaluation was provided by Evolution and their partners, and was supplemented by public data and Pinnacle in-house data.

The primary hydrocarbon target in these sections is the Mississippian formation which is being commercially developed horizontally in multiple counties in Northern Oklahoma and Southern Kansas. including Kay and other Oklahoma Counties located in the eastern part of the play. There are presently two horizontal producing (PDP) wells associated with Evolution’s ownership in the 38 sections and there are no horizontal Mississippian wells directly offsetting the acreage. All forecasted undeveloped wells are presently categorized as Non-Proven (Probable).

An engineering analysis and economic evaluation of the producing properties and potential of the undeveloped acreage was prepared using the SEC pricing guidelines for a year-end evaluation and an effective date as of July 1, 2013. The evaluation includes two (2) Proven (Producing) locations, one hundred eleven (111) Non-Proven (Probable) undeveloped locations and eleven (11) disposal wells to be drilled. Summary results of this analysis are provided below and details are presented in referenced attachments.

|  | # |  | Est Gross Rem’g Rsvs |  | Est Net Rem’g Rsvs |  | Net Capital |  | Net Rem’g |  | Net Pres Value |
|  | Wells |  | Oil.MBO |  | Gas. MMcf |  | Oil.MBO |  | Gas. MMcf |  | M$ |  | Cashflow, M$ |  | Dic @ 10%, M$ |
PDP |  | 2 |  | 0.51 |  | 13.70 |  | 0.04 |  | 0.94 |  | 0 |  | 0.65 |  | 0.63 |
Prob UD |  | 111 |  | 15,062.70 |  | 55,828.92 |  | 2,028.03 |  | 7,516.63 |  | 54,544.09 |  | 93,051.96 |  | 20,929.59 |
SWDW |  | 11 |  | 0.00 |  | 0.00 |  | 0.00 |  | 0.00 |  | 2,237.72 |  | -2,237.72 |  | -1,410.96 |
Total |  | 124 |  | 15,063.21 |  | 55,842.61 |  | 2,028.06 |  | 7,517.57 |  | 56,781.81 |  | 90,814.88 |  | 19,519.25 |

Pinnacle Energy Services, LLC
9420 Cedar Lake Ave. Oklahoma City. OK 73114
Ofc: 405-810-9151 Fax: 405-843-4700 www.PinnacleEnergy.com

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The results of the evaluations showing forecasts of production, reserves, revenues, and income for the project are presented in a yearly format, and are attached and made part of this evaluation. One-line economic summaries (by well) of the results from the evaluation are also included in the attachments along with a cumulative project net production graph.

Economic Parameters

Future Income

Future net revenue in this report includes deductions for state production taxes. Future net income is after deducting these taxes, future capital costs, and operating expenses, but before consideration of any state and/or federal income taxes. The future net income has not been adjusted for any outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. The future net income has been discounted at various annual rates. including the standard ten percent (10%), to dete1mine its “present worth.” The present worth is shown to indicate the effect of time on the value of money.

Pricing

The oil and gas prices employed in this evaluation were determined according to the SEC pricing regulations for year-end evaluations. As stated, it is the un-weighted arithmetic average of the first-day-of-the-month price for each month of the 12-month reporting period. The natural gas price is based on the NYMEX Henry Hub postings and the oil price is based on NYMEX Cushing postings.

Evolution’s fiscal year end is on June 30, thus the prices are calculated using July 1, 2012 through June 1, 2013 prices for this analysis. For this period, the unadjusted average NYMEX SEC prices were $91.60/bbl for oil and $3.44/MMBTU for natural gas. These product prices were adjusted to reflect estimated differentials associated with transportation, BTU content, field losses and usage, basis differentials. gathering and processing costs. An oil differential of -3.00 $/BBl was applied to the oil price, and no differential was applied to the gas pricing to account for the projected 1000 BTU gas.

Interests

Net and gross leasehold ownership (acres) by section were provided by Evolution. Working interests for Evolution were calculated by applying their net acres in each section to the standard and normal 640 acre units as shown in the attached Exhibit A. Calculated interests for each section were applied to wells drilled in those sections. The overall average Evolution working interest of all wells is approximately 17% and was applied as the interest in the disposal wells.

Due to Forced Pooling rules where additional interests from owners not capable or desiring to participate in wells can be acquired by participating owners, it is expected - but not incorporated into this evaluation - that Evolution will have working interests greater than their current leasehold position in a majority of future wells.

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Development

A one rig development schedule was employed, starting in the summer of 2013. Horizontal Mississippian wells are projected to be drilled at a rate of 1 well per month, with a disposal well drilled every ten wells. A sixty (60) day period from spud to on-line dates was assumed.

Operating Methods, Capital, and Operating Expenses

The Horizontal Mississippian wells will require lifting assistance to produce back frac and reservoir fluids during their life. Some operators choose to initially run electric submersible pumps (ESPs), while others elect to install gas lift mandrels to lift the high initial and possible future volumes of produced fluid. For ESP’s, three-phase electricity is necessary, either purchased from local power companies, or produced from rented/purchased gas powered generators. For gas lift, compression and natural gas is required to be injected and if insufficient supply gas is unavailable from the well, must be purchased from a nearby gas line/supplier, also if available. Conventional pumping units will likely be capable of being used after several years of production.

Evolution, as most operators will, have elected to drill a salt water disposal well in conjunction with producing wells, which makes disposal oflarge volumes of water operationally more efficient and significantly more economical than hauling off the water and paying a disposal fee. The Arbuckle fom1ation is a thick (600’-1000’+) dolomitic formation that lies beneath the Mississippian and can take tens of thousands of barrels of water per day for many years. One disposal well is projected for approximately every 10 producing wells.

Reoccurring operating expenses will be higher initially but are expected to decrease over time to a fairly constant monthly expense. Fixed monthly costs are expected to average approximately $3,000 per month while additional variable costs are estimated to be 4.00 $/BBL of oil produced and $0.50/Mcf of gas produced. An additional 0.10 $/BBL for produced water is also included. This provides a model for decreasing operating expenses, however, these operating expense parameters were held constant.

Abandonment costs were assumed to be offset by future salvageable equipment values, which is a reasonable and common assumption for the activities projected and producing wells in the mid-continent region.

The capital expenditure estimated to drill and complete a horizontal Mississippian well was based on AFEs provided by Evolution. The cost to drill and complete a horizontal Mississippian well with approximately 4,000’ of lateral is estimated to be $2,900,000. An Arbuckle disposal well and related facilities are estimated to cost approximately $1,228,000.

In addition, the following leasehold investment will be necessary to maintain acreage:

2013: |  | $ | 112,000 |
2014: |  | $ | 693,000 |
2015: |  | $ | 201,000 |

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In Oklahoma, a production tax credit allows for severance taxes to be 1% of revenues for the first 4 years of a horizontal weirs production before increasing to 7% thereafter.

Reservoir, Development, and Resenes

Mississippian Formation

The Mississippian formation is a thick and fractured marine carbonate formation lying above the Woodford Shale source rock and below the Pennsylvanian-aged (Cherokee, Red Fork. et al) rocks. The top of the Mississippian is an unconformity. Porosity development, as identified on logs, can occur throughout the reservoir and occurs at different stratigraphic levels -upper and lower -of the Mississppian formation.

In the Eastern Area, the Mississippian formation ranges in (true vertical) depth from approximately 3,000’ to 6000’, and in thickness from approximately 200’ to over 500’. The zone is comprised primarily of limestone, with areas of low and high concentrations of chert. The Mississippi Chat is the uppermost member of the Misissippian, and is comprised of dolomite, limestone, and tripolitic chert in varying quantities due to the erosion effects of the unconformity, yielding high porosity. The majority of the Mississipian formation has low matrix permeability but is highly fractured, especially in areas with moderate to higher concentrations of chert where the formation will average 4-8% porosity.

The formation is likely a pressure depletion reservoir enhanced by water/fluid expansion. This description is supported by the observance of the gas-oil ratios and water-oil ratios leveling off after “flush” production in both vertical and horizontal wells. Wells east of the Nemaha Ridge are expected to yield less gas - lower Gas-Oil Ratios -than Mississippian wells west of the Nemaha Ridge, although it appears this natural gas has higher BTU’s and will yield significant natural gas liquids (NGL) when processed and generate similar total gas revenues as wells in the Western Area.

Tvpe Curve and Estimated Reserves

Forecasts of future rates and reserves for Evolution’s projected undeveloped wells are primarily based on a review of public and private production and well perfonnance data on existing analogous wells horizontally drilled in the Mississippian formation east of the Nemaha Ridge. A review of well logs, vertical well performance, reservoir parameters and use of volumetric calculations on the Mississippian formation was also performed.

The undeveloped locations are projected to have average recoverable reserves of approximately 135 MBBLs oil and 500 MMcf gas per well. Although these reserve volumes were used to model all undeveloped locations, actual recoveries are expected to exhibit a significant range above and below the average. Three horizontal wells per section are currently projected with the potential for additional wells in some sections.

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Initial (first day) well rates of 253 BOPD and 410 Mcf/d were estimated based on the review of analogy well perfonnances. Production is expected follow a hyperbolic decline with initial decline rates of 99.99417% for oil and 91.669% for gas (as defined in the PhdWin economics program) and a hyperbolic exponent (“b” factor) of 1.50, which accounts for the production transitioning from early transient flow to (pseudo) steady-state flow through the multiple porosity, permeability, and fracture systems within the reservoir. Oil cuts will also vary by well and area, but are expected to range between 5-15%.

Reserve Classifications

Remaining recoverable reserves are those quantities of petroleum that are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty depending primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty is conveyed by classifying reserves as Proved (highly certain) or Non-Proved (less certain).

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geological 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 for 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 reasonable time.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Developed Producing (PDP) is assigned to wells with sufficient production history to allow material balance and decline curve analysis to be the primary methods of estimation. PDP reserves are the most reliable reserves, generally with a high degree of confidence that actually recovered quantities will equal or exceed published reserve estimates.

Proved Developed Non-Producing (PNP) reserves include reserves from zones that have been penetrated by drilling but have not produced sufficient quantities to allow material balance or decline curve analysis with a high degree of confidence. This category includes Proved Developed Behind-Pipe (PNPBP) zones and tested wells awaiting production equipment (PNP).

Proved undeveloped (PUD) oil and gas reserves are reserves 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. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with reasonably certainty that there is continuity of production from the existing productive fom1ation. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. The Proven Undeveloped and Non-Producing wells were forecasted based on geological data presented, volumetric calculations, and analog comparisons to existing completions. Non-Proven (Probable) Undeveloped locations have been evaluated to be more likely than not to be commercially productive but do not meet SEC criteria to be classified as Proved at this time.

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General

The reserves and values included in this report are estimates only and should not be construed as being exact quantities. The reserve estimates were performed using accepted engineering practices and were primarily based on volumetric analysis and analogy performance. As additional pressure and production performance data becomes available, reserve estimates may increase or decrease in the future. The revenue from such reserves and the actual costs related may be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the prices actually received for the reserves included in this report and the costs incurred in recovering such reserves may vary from the price and cost assumptions referenced. Therefore, in all cases. estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information available for this analysis, items excluded from consideration were all matters as to which legal or accounting, rather than engineering interpretation, may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering data and such conclusions necessarily represent only informed professional judgments.

The titles to the properties have not been examined nor has the actual degree or type of interest owned been independently confirmed. A field inspection of the properties is not usually considered necessary for the purpose of this report.

Information included in this report includes the graphical decline curves for individual wells, projected production and cashtlow economic results by entity, one-line economic results summaries for each well. and miscellaneous individual well information. Additional information reviewed will be retained and is available for review at any time. Pinnacle Energy Services. L.L.C. can take no responsibility for the accuracy of the data used in the analysis, whether gathered from public sources or otherwise.

Pinnacle Energy Services, LLC |
/s/ Richard J. Morrow |
Richard J. Morrow, P.E. |
Petroleum Engineer |
John Paul Dick, P.E. |
Petroleum Engineer |

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Pinnacle Energy Services, LLC |  | 9420 Cedar Lake Ave, Oklahoma City, OK 73114 |  | Office: 405.810.9151

Qualifications of Reserve Estimator

John Paul (J.P.) Dick, P.E., a Registered Professional Engineer in the States of Oklahoma and Texas, and founder of Pinnacle Energy Services, LLC, since 1998, is primarily responsible for overseeing the preparation of the reserve report. His professional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications include: Bachelor’s of Science degree in Petroleum Engineering from The University of Tulsa, 1983; member of the Society of Petroleum Engineers, member of the Society of Petroleum Evaluation Engineers; and more than 29 years of practical experience in estimating and evaluating reserve information and estimating and evaluating reserves.

The technical person primarily responsible for the preparation of the reserve report is Richard J. (Dick) Morrow, P.E., a Registered Petroleum Engineer in the States of Oklahoma and Wyoming. He earned a Bachelor’s of Science degree in Petroleum Engineering from the University of Kansas in 1976. Richard joined Pinnacle in 2012 as a consulting petroleum engineer. Prior employment includes Devon Energy, Woods Petroleum and Exxon Mobil. He has over thirty years of experience in oil and gas reservoir studies and reserves evaluations. Richard is also an active member of the Society of Petroleum Engineers.