Exhibit 99.1

Cambrian Management, Ltd.
PO Box 272
Midland, Texas 79702
Ofc: 432-620-9181
Fax: 432-570-0102

February 9, 2017

Mr. Kenny Hill
Chief Executive Officer Aurora Energy Partners
3355 Bee Caves Road, Suite 608
Austin, Texas 78746


Dear Mr. Hill:

Per your request an oil and gas reserve and economic appraisal has been performed for the properties owned by Aurora Energy Partners (Aurora) and listed on Exhibit A. The objective of this study is to estimate reserves and value for these properties as of January 1, 2017. The methodology, assumptions and results of the study are discussed below.

With the assumptions discussed below the reserves and value for the Aurora properties are estimated as:

SEC Case, As of 1/1/2017
 
 
Total Proved Reserves
 
Oil, MBO
33.4
Gas, MMCF
113.5
 
 
Total Proved Value
 
PW@ 0%, $
$756,750
PW@ 10%, $
$524,550


This report is intended to serve as the Aurora Energy Partners report for the United States Securities and Exchange Commission (SEC) for reserves and projected economics as of January 1, 2017.

Property Overview

The properties consist of 36 wells in five Texas and New Mexico counties. All except the Eagle Ford wells are in the Permian Basin of West Texas and Southeastern New Mexico.

January 2017 Assets:

Eight wells are in Crockett County, Texas and are operated for Aurora by Cambrian Management. These gas wells are completed in the Canyon sand formation. Due to the high interest owned by Aurora these wells have been a significant asset for Aurora.
Six wells are “Wolfberry” completions located in Howard County.





The Sage 25 and Hamlin 26 wells were drilled in 2011 by Clear Water Inc. The Hamlin 24#1 was drilled by OGX Resources in 2007 and acquired by Clear Water in December 2009. Aurora has a 1.5% working interest in these wells and the accompanying acreage.
The two Hamlin 26P wells were drilled by Element Petro Operating and are offsets to the Clear Water Hamlin wells. Aurora’s over-riding royalty interest (ORRI) is due to a land deal with Element. These wells were sold to Surge during 2016.
Note the Morgan #1 was drilled in 2013 by V-F Petroleum with Aurora as a co-owner and was included in previous reserve reports. This well was sold during 2016.
As a result of the land deal with Element, Aurora owns an over-riding royalty interest in twelve horizontal wells in six sections offsetting the Hamlin lease. The original well in this group was drilled in 2013. Five wells were drilled in 2016. The operator has changed from Element to Surge Operating, LLC.
Three wells are located in Pecos County and operated by V-F Petroleum.
The University 6#1 was completed in July 2011. This was followed in July 2012 with the completion of the University 6#2. Both wells are Ellenburger completions at a depth of 6855 ft.
The University 7#1 was completed in April of 2013. It tested the Ellenburger and then was completed in the Connell.
Current geological interpretation indicates a third well can be drilled in the existing University 6 fault block. This well is included in this report as a 2018 PUD well.
One well is located in Lea County, New Mexico.
The Uno Mas #1 is a re-entry of the Manzano Apple #1, which was a 1993 completion in the Mississippian zone at around a depth of 13,022 ft. The zone was brought back on production in December 2011.
The 2016 reserve report included three leases and seven wells which are operated by Trilogy in their Martin and Glasscock Counties development. These wells are no longer owned by Aurora.
During 2015 Aurora acquired working interest in five horizontal Eagle Ford wells located in Lavaca County and operated by Penn Virginia.

It is estimated that the monthly net cashflow for January 2016 will be $14,832, assuming SEC pricing. Net production for the month is estimated as 14.8 BOPD and 46.5 MCFD.

Data

Data furnished or available for this analysis included well drilling reports, logs, test data, operating costs, and revenue statements. Production data was obtained from the Texas Railroad Commission records and was supplemented as needed by data from the Operators. Monthly prices received for the gas and oil produced were obtained from (1) check summaries and from (2) the State of Texas tax records as reported by DrillingInfo.com, a commercial oil and gas information service.

Interests

The properties evaluated are listed on the attached Exhibit A. No attempt was made as part of this evaluation to verify ownership of the interests through detailed title work. The interests were confirmed from the Joint Interest Billings (JIB’s) and the revenue check detail.

Revenue from the wells operated by Penn Virginia is currently not available to Aurora. The Penn Virginia revenue is being held in suspense to recover costs owed to the operator by Aurora. From information provided it is expected that Aurora will receive revenue after payment of the costs owed. Details of these arrangements are not included in this report and the calculated value for the leases does not account for the money owed.

Assumptions and Methodology

All estimated reserves contained in this report are expressed as gross and net reserves on all properties. Net reserves represent those reserves attributable to the appraised interest. Values for reserves are expressed in terms of future





net revenue and present worth of future net revenue. Future net revenue is defined as revenue accruing to the appraised interests from production and sale of the estimated net reserves after deducting production taxes and operating expenses. Present worth (PW) is defined as the future net revenue discounted at a set discount rate compounded daily. All values are calculated as of January 1, 2017.

No plugging costs or salvage values were considered in this evaluation, nor was any consideration given to Federal income tax.

The properties evaluated for this analysis have proved developed producing reserves (PDP) and proved undeveloped reserves (PUD) as defined by the Society of Petroleum Engineers (SPE). The reserve guidelines as published by the SPE in March 2007 in the Petroleum Reserve Management System (SPE- PRMS) are being used for this analysis. Discussion and details of the SPE-PRMS are available on the SPE website.

Production forecasts were made using methods appropriate for the individual property with the majority of forecasts being made with decline curve analysis.

For the Adams wells in Crockett County the future production rates were estimated using decline curve analysis in conjunction with a review of offset production. All of the Adams wells had established, well behaved decline trends.
The University 6-#1 & 6#2 are believed to have a water drive. The Operator has restricted the production to avoid excess water production. The basis for this analysis was the reserves estimated using volumetric analysis. A forecast was then constructed honoring the Operator’s production rate and recovering the estimated reserves in a reasonable time period. Based on the continued flat production, an additional year at the fixed rate has added to the forecast.
The estimated reserves for the University 6#3 undeveloped well were set equal to the original volumetric reserves for a well on the University 6 Lease. The production curve has the same shape as the #1 and #2.
The Uno Mas well forecast was estimated using decline curve analysis of the existing production.
Forecasts for all six vertical Wolfberry wells were based on the “curve shape” established on other Wolfberry wells in the Permian Region. This curve shape was used with the reported
production for each well to forecast the future production. All six vertical wells have adequate production history to make reliable forecasts. One well is currently shut-in.
Eight of Surge’s horizontal Wolfcamp (Trend) wells have sufficient production data for decline curve analysis. Reserves for the remaining four were estimated using the limited production data and analogy to the curve shape for the older wells.
Production for the Lavaca County Eagle Ford wells was forecast using a type curve developed from offset wells. The parameters estimated from these wells were used in a decline curve analysis on the production for the five Eagle Ford wells, with the wells summed on the two leases.

The resulting forecasts are shown on the attached production plots.

Cash flow for the individual well cases were calculated until the monthly cash flow becomes negative; i.e., costs exceed revenue and the well is not economic. The individual cases were summed to produce the total value.

Using SEC guidelines in place for 2017, the gas and oil prices for this analysis were set at the average price received on the “first-day-of-the-month” for the last 12 months, adjusted for appropriate differentials. The “benchmark” prices are $42.75 per barrel and $2.49 per MMBTU, as estimated by Ryder Scott. For each well, or case, the actual monthly prices received during the last 12 months were compared to NYMEX average prices for the month. For each well a differential to the average was estimated. These differentials were applied to the “benchmark” prices and the resulting values were used for the future cashflow estimates. The resulting pricing is shown on Exhibit B. All prices were held constant per SEC guidelines.

Actual 2016 lease operating costs (LOE) for the properties were furnished for this review for all working interest wells. The monthly costs were averaged for each well to determine a $/month/well operating cost. Non-recurring costs were omitted. Per SEC guidelines the operating costs are held constant for the life of the wells.






Actual LOE values for the royalty wells were not available. For these wells a generic operating cost for other like kind wells was used. Note this is only used for estimating the economic limit since a royalty interest does not pay operating cost.

Values used for LOE are shown on Exhibit B.

Drill and complete costs for the University 6#3 development well were based on estimates (an AFE) provided by the operator for the University 6#2.

Results

The total proven value and reserves for the twenty-one PDP working interest wells, the twelve ORRI wells, and the one PUD well are summarized above. Expanding on the summary, the estimated value and reserves over the life of the wells are shown on Table 1 below.
Detailed cashflow sheets are attached, including summary analysis of the total reserves and individual well analyses. A listing of the reserves, costs, and value for each well, a one-liner, is also attached.


Table 1

PDP
PUD
Total
 
 
 
 
Net Oil, MBO
26.5
6.9
33.4
Net Gas, MMCF
111.8
1.8
113.5
Net Revenue, $
$1,272,940
$260,160
$1,533,100
Expenses, $
$543,330
$28,600
$571,930
Net Investment, $
 
$87,650
$87,650
Taxes, $
$98,190
$18,590
$116,780
Net Income, $
$631,420
$125,320
$756,750
 
 
 
 
Present Worth Profile
 
 
 
Disc 10%, $
$472,000
$52,540
$524,550
Disc 12%, $
$449,040
$43,250
$492,290
Disc 15%, $
$418,430
$31,480
$449,920

Qualifications

The value estimated in this report is based on the assumption that the properties are not adversely affected by the existence of any hazardous substances or detrimental environmental conditions. No field inspection was made of the properties as part of this review.

This study was performed using industry-accepted principles of engineering and evaluation that are predicated on established scientific concepts. However, the application of such principles involves extensive judgment and assumptions and is subject to changes in performance data, technical knowledge, economic conditions and statutory provisions. Consequently, reserve estimates and future value are furnished with the understanding that actual performance of the wells could vary from that predicted.


Sincerely,
Cambrian MANAGEMENT, LTD.