Exhibit 99.3

 

 

 

 

 

January 27, 2016

 

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 2015 Pricing

        “As of” January 1, 2016

 

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 oil and gas reserves, “As of” January 1, 2016, is as follows:

 

*Due to computer rounding, numbers in the above table may not sum exactly.

 

 

---

 

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, 2016 and ending December 31, 2016.

 

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% 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.  Currently there are 19 economic vertical locations proposed to be drilled starting in 2018 with two scheduled to drill each month.

 

 

 

 

---

 

Within the PNP category, Jonah Energy and Exaro have scheduled 49 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 per well and the average expected reserve uplift is around 50 MMcf. W.D. Von Gonten & Co. was able to calculate the reserve uplift based on wells with tubing lowered in 2015. 

 

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 agreement, Encana has drilled 158 new wells in the Jonah field. These new wells span across the Antelope, Downdip, and Updip areas of the field. W.D. Von Gonten & Co. originally developed three type curves for these areas and applied the reserves to the upside locations scheduled in this report.  Due to the increasing amount of production data available, W.D. Von Gonten & Co. decided to break 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 suffered damage caused by an altered frac fluid. It is currently producing at a gross rate of 2.6 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 0.75 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 wells. Based on provided daily production data, W.D. Von Gonten & Co. has assigned incremental reserves of +3.5% to the 10-35 compression project wells. Jonah Energy has since begun two similar projects, 13-26 (27 wells) and 01-29 (45 wells). Based on the success of the 10-35 project, and limited daily production demonstrating increases, W.D. Von Gonten & Co. has assigned a PDP uplift of 3.5% in reserves to both the 13-26 and 01-29 projects. 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.

 

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.        

 

Over the course of August 2013 through May 2014, 50 new wells were drilled and completed with substantially lower IP rates and estimated ultimate recoveries (EUR). Encana and Schlumberger altered a chemical additive in the frac fluids which negatively impacted the performance of the wells. By mid-2014, the frac fluid had been returned to the original formula and results using the original frac formula have shown a return to the EUR numbers and curves pre-August 2013.  

W.D. Von Gonten & Co. reviewed diagnostic plots of wells frac’d with the original fluid and wells frac’d with the altered fluid. This diagnostic analysis applies the concept of material balance time developed by W. John Lee and Tom A. Blasingame. This analysis consists of plotting the gas production data as adjusted-pressure-normalized gas rate versus adjusted time. The wells frac’d with the altered fluid showed lower initial deliverability than the wells frac’d with the original frac fluid. As time progressed, the deliverability increased for the wells frac’d with the altered fluid, indicating reservoir damage instead of reduced reservoir quality.  

---

 

Even though the deliverability is increasing, it will never reach the level of the original frac fluid wells indicating overall poorer performance. This increase in deliverability may be the result of perforation unplugging and fractures, which were not previously connected to the wellbore, beginning to produce.

 

Using the diagnostic analysis described above, W.D. Von Gonten & Co. was able to support the theory of well damage due to the altered frac fluid. Results observed since this initial analysis was performed continue to add confidence to this position.

 

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 $50.28 per barrel of oil and $2.58 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 November 2014 through October 2015. At the request of Exaro, only data from August through October 2015 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 -$9.00/bbl to -$6.00/bbl.

 

It should be noted that Exaro has terminated its marketing arrangement with Jonah Energy. The $0.26/MMBtu fee that Exaro has previously paid is no longer valid. Going forward, Exaro has indicated that it will hire office contractors to handle the revenue distribution and gas marketing which was the basis of the Jonah Energy fee.  

W.D. Von Gonten & Co. has included the historical NGL uplift within the gas price differential for the new wells.  Due to existing and new contracts, the old wells do not receive the NGL uplift whereas the new wells receive the uplift for the life of each property.

 

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 January through December 2015.  Using the supplied data, W.D. Von Gonten & Co. applied a  gross direct expense of $3,200 per month per well and a net variable cost of $0.57 per Mcf to the new wells and $0.53 per Mcf to the old wells. All direct and variable operating expenses were held constant for the economic life of the properties.   

 

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 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.

 

I:/data/company/reports/client_letters/Miscellaneous\Exaro Energy III - SEC 01-2016.doc

---