February 14, 2017

Mr. John P. Atwood

Senior Vice President

Exaro Energy III, LLC

1800 Bering Drive, Suite 540

Houston, Texas 77057

        Re:  Engineering Evaluation

          Estimate of Reserves & Revenues

          SEC Year End 2016 Pricing

        “As of” January 1, 2017

Dear Mr. Atwood:

At your request, W.D. Von Gonten & Co. has estimated future reserves and projected net revenues attributable to certain oil and gas interests currently owned by Exaro Energy  III, LLC (Exaro).    The properties represented herein are located in the Jonah field of Sublette County, Wyoming.  A summary of the discounted future net revenue attributable to Exaro’s Proven reserves, “As of” January 1, 2017, is as follows:

Report Preparation

Purpose of Report – The purpose of this report is to provide Exaro with a projection of future reserves and revenues attributable to certain Proved oil and gas interests presently owned.

Scope of Report – W.D. Von Gonten & Co. was engaged by Exaro to estimate the reserves and revenues associated with the properties included in this report.  Once reserves were estimated, future revenue projections were generated utilizing SEC pricing guidelines.    

Reporting Requirements –  Securities and Exchange Commission (SEC) Regulation S-X 210, Rule 4-10 and Regulation S-K 229, Item 1200 (as revised in December 2008, effective 1-1-10), and Financial Accounting Standards Board (FASB) Statement No. 69 require oil and gas reserve information to be reported by publicly held companies as supplemental financial data. These regulations and standards provide for estimates of Proved reserves and revenues discounted at 10% and based on unescalated prices and costs.  Revenues based on alternate product price scenarios may be reported in addition to the current pricing case.  Reporting probable and possible reserves is optional. Probable and possible reserves must be reported separately from proved reserves.

The Society of Petroleum Engineers (SPE) requires Proved reserves to be economically recoverable with prices and costs in effect on the “as of” date of the report.  In conjunction with the World Petroleum Council (WPC), American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE), the SPE has issued Petroleum Resources Management System (2007 ed.), which sets forth the definitions and requirements associated with the classification of both reserves and resources.  In addition, the SPE has issued Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information, which sets requirements for the qualifications and independence of reserve estimators and auditors. 

The estimated Proved reserves herein have been prepared in conformance with all SEC, SPE, WPC, AAPG, and SPEE definitions and requirements. 

Projections – The reserve and revenue projections represented herein are on a calendar year basis, with the first time period beginning January 1, 2017 and ending December 31, 2017.

Property Discussion

Exaro signed an Earning and Development Agreement (EDA) with Encana Oil & Gas (Encana) in April 2012 that allowed them to gradually obtain increasing levels of ownership in the Jonah field. As part of the EDA, Exaro’s interest in each well drilled prior to the April 2012 agreement (old Proved Developed Producing (PDP) wells) continued to increase as Encana drilled additional wells (new wells) within the field. Exaro’s interest in the new wells stayed constant for the life of the well. For each new well drilled within the EDA, Exaro paid for 100% of the capital costs and earned 32.5% of Encana’s interest in the new wellbore until Exaro was fully earned into their devoted interest. In addition, for each new well drilled, Exaro earned 0.40% interest in the old PDP wells and related leasehold if Encana’s working interest in the new well location was 100% and a proportional share if not.

As of the date of this report, Encana has sold its ownership to Jonah Energy, LLC (Jonah Energy). Exaro notified Jonah Energy of its intent to terminate the EDA effective May 12, 2014, and thereafter participate under the existing Joint Operating Agreements (JOA’s) going forward.  Exaro currently has no locations left under the EDA. All wells are proposed under the JOA and Exaro has the right to participate for its working interest in each well.  At the current time, there are no rigs running within Exaro’s acreage and there is no indication when Jonah Energy might restore drilling. Due to the uncertainty of timing and the current pricing scenario, there are no upside locations scheduled to be drilled within this report.

Within the PNP category, Jonah Energy and Exaro have scheduled 39 currently producing wells for their artificial lift program. The goal is to lower tubing into the active perfs of each well to more efficiently lift the produced liquids. The total gross cost of each will be approximately $24,000 and the average expected reserve uplift around 50 MMcf. W.D. Von Gonten & Co. was able to calculate the reserve uplift based on wells with tubing lowered in 2015 and 2016. 

Production in this area is primarily from the Lance sand which can range from 8,000’ to 11,000’ in depth and approach 3000’ in interval thickness. 

Exaro has divided the Jonah field into three areas based on location and production performance characteristics. The Updip area covers the western portion of Exaro’s acreage. The Downdip area covers the central and northern acreage. The Antelope area covers the acreage in the eastern portion of the field. Since the signing of the original EDA, Encana drilled 158 wells in the Jonah field. These wells were spread across the Antelope, Downdip, and Updip areas of the field. W.D. Von Gonten & Co. originally developed three type curves for these areas. Due to an increasing amount of production history, W.D. Von Gonten & Co. decided to further divide the Updip and Antelope sections into several parts and adjust the type curves as necessary.

At the beginning of 2014, Jonah Energy drilled a horizontal well in section 29 of the Antelope area. This well may have suffered damage caused by an altered frac fluid. It is currently producing at a gross rate of 2.1 MMcf/day with an EUR of 8.0 Bcf. Mid 2015, a second horizontal with a longer lateral and more frac stages was drilled to the north of the original horizontal well. The horizontal portion was drilled approximately 400’ below the original and is only producing at a gross rate of 0.68 MMcf/day. There are no horizontal locations scheduled to be drilled within this report.

Starting in February 2015, Jonah Energy began line pressure reduction projects in the field on varying groups of wells. They started by lowering the pressure from 200 psi to 50 psi in 17 wells located in section 35 and named the project 10-35. Lowering the pressure caused an increase in the production rate and reserves on most of the connected wells. Based on provided daily production data, W.D. Von Gonten & Co. was able to give these wells a brief uplift in the production projections. Jonah Energy has since begun and maintained several projects throughout the updip sections. Though other similar projects are reportedly planned, there are no future projects scheduled in the non-producing categories of this report. As Exaro is not the operator of the field and therefore has no control over the implementation of such projects, intent and/or timing cannot be determined.

Figure 1 displays the comparison of Exaro’s historical monthly net production and W.D. Von Gonten & Co.’s forecasted net monthly production beginning January 1, 2017.

Figure 1: Historical Net Production and PDP Reserves Forecast as of January 1, 2017

Figure 2 below is a graphical comparison of Exaro’s October 2015 through September 2016 historical net revenue and W.D. Von Gonten & Co.’s forecasted net revenue beginning in January 2017.  

Figure 2: Historical Net Revenue and Forecasted Net Revenue as of January 1, 2017

Reserves Discussion

Reserves estimates represented herein were generally determined through the implementation of various methods including, but not limited to, performance decline,  analogy and type curve analysis.  Based on the amount of available data, one or more of the above methods was utilized as deemed appropriate.        

Reserves and schedules of production included in this report are only estimates. The amount of available data, reservoir and geological complexity, reservoir drive mechanism, and mechanical aspects can have a material effect on the accuracy of these reserve estimates. Due to inherent uncertainties in future production rates, commodity prices, and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Product Prices Discussion

SEC pricing is determined by averaging the first day of each month’s closing price for the previous calendar year using published benchmark oil and gas prices.  This method, as applied for the purposes of this report, renders a price of $42.60 per barrel of oil and $2.50 per MMBtu of gas. These prices were held constant throughout the life of the properties, as per SEC guidelines.

Pricing differentials were applied on a field basis to reflect the actual prices received at the wellhead.  Differentials typically account for transportation costs, geographical differentials, marketing bonuses or deductions, and any other factors that may affect the price actually received at the wellhead.     W.D. Von Gonten & Co. originally determined historical pricing differentials from lease operating data provided by Exaro representing the time period of October 2015 through September 2016. At the request of Exaro, only data from April 2016 through September 2016 was used to calculate the oil differential in part due to the rapidly changing pricing environment. The oil differential, as a result, has been decreased from             -$4.00/bbl to -$3.00/bbl.

Figures 3 and 4 illustrate the comparison between historical differentials versus what is being projected in the report.

Figure 3: Historical and Forecasted Oil Differential

Figure 4: Historical and Forecasted Gas Differential

W.D. Von Gonten & Co. has included the historical NGL revenue and processing fees within the gas price differential for the new wells only. Due to existing and new contracts, the old wells do not include any NGL revenue or fees.

Operating Expenses and Capital Costs Discussion

Projected monthly operating expenses associated with the Jonah properties were based on the review of lease operating data provided by Exaro for the time period of October 2015 through September 2016.  Using the supplied data, W.D. Von Gonten & Co. applied a  gross direct expense to each well based on its classification of new and old. If the well was involved in a line pressure reduction project, the operating expenses for those wells were higher. The horizontal wells also have an increased monthly operating cost which is based on their historical numbers. All new wells have a net variable revenue deduct of $0.58 per Mcf and $0.57 per Mcf on the old wells. In addition, all wells have a $4.16/bbl salt water disposal (SWD) variable cost. All direct and variable operating expenses were held constant for the economic life of the properties.

Figure 5 below is a graphical comparison of historical net lease operating expenses for October 2015 through September 2016 versus comparable forecasted expenses for January through December 2017. October 2015 is irregularly high due to revenue adjustments, increased water disposal and handling costs, and capital costs billing for prior periods.

Figure 5: Historical and Forecasted Lease Operating Expense

Capital costs necessary to perform well completion operations and to drill undeveloped locations were supplied by Exaro.  These costs were not verified from actual recent work in the area of interest, and therefore W.D. Von Gonten & Co. expresses no warranties as to the accuracy or reasonableness of these assumptions.

Other Considerations

Abandonment Costs –  Cost estimates regarding future plugging and abandonment liabilities associated with these properties were supplied by Exaro for the purposes of this report.  As we have not inspected the properties personally, W.D. Von Gonten & Co. expresses no warranties as to the accuracy or reasonableness of Exaro’s estimates regarding abandonment.  A third party study would be necessary in order to accurately estimate all future abandonment liabilities.    

Data Sources – Data furnished by Exaro included basic well information, lease operating statements, ownership, pricing, and production information on certain leases. IHS Energy archives was utilized to view the monthly production for some of the wells included in this report.  

Context – We specifically advise that any particular reserve estimate for a specific property not be used out of context with the overall report. The revenues and present worth of future net revenues are not represented to be market value either for individual properties or on a total property basis.

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 oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the estimated oil and gas volumes represented herein. The reserves in this report can be produced under current regulatory guidelines.  Actual future commodity prices may differ substantially from the utilized pricing scenario which may or may not extend or limit the estimated reserve and revenue quantities presented in this report.