Competent Person s Report on the Reserves Potential of the Lowry Bombing Range, Colorado, USA

Competent Person s Report on the Reserves Potential of the Lowry Bombing Range, Colorado, USA On behalf of Highlands Natural Resources Plc Project Number: KRNACRR160769 Version: (Release) Date Submitted: 1/6/2017 Prepared By: Pete Jackson Quanjun Wang Ross Andrews Greg Hepguler Project Director: Andy Kirchin 1800, West Loop South Suite 1000 Houston Texas 77027 rpsgroup.com

Location End Client Internal Reviewer(s) East Denver Lowry Range Highlands Natural Resources Plc A.K. Release Preliminary File Name Date Submitted Draft Highlands DJ_Lowry Range CPR_ver 1 12/8/16 Draft Notes Preliminary Draft Draft Highlands DJ_Lowry Range CPR_ver 5FINAL 12/12/16 Final Draft Release Highlands DJ_Lowry Range CPR_Release_30Dec 12/30/16 Release Version Release Highlands DJ_Lowry Range CPR_Release_6Jan 1/6/17 Economics Re-run Disclaimer: This document contains confidential information that is intended only for use by the client and is not for public circulation, publication, nor any third party use without the prior written approval of RPS Group Plc. Client understands that modeling is predictive in nature and while this report is based on information from sources that RPS Group Plc considers reliable, the accuracy and completeness of said information cannot be guaranteed. Therefore, RPS Group Plc, its directors, agents, assigns, and employees accept no liability for the result of any action taken or not taken on the basis of the information given in this report, nor for any negligent misstatements, errors, and omissions. This report was compiled with consideration for the specified client's objectives, situation, and needs. (Release) Jan 6th, 2017

Table of Contents 1.0 EXECUTIVE SUMMARY 2 1.1 DJ Basin Location 6 1.2 Lowry Bombing Range: Location 6 1.3 Hydrocarbon Field Setting 7 2.0 REGIONAL OVERVIEW 10 2.1 DJ Basin Overview and Structural Setting 10 2.2 Niobrara Play Summary 13 2.2.1 Play Stratigraphy 13 2.2.2 Niobrara Deposition 16 3.0 LOWRY BOMBING RANGE PROSPECT GEOLOGY 18 3.1.1 Geological Continuity of the Niobrara Formation 18 3.1.2 Niobrara Structure Map 20 3.1.3 Resistivity Mapping 20 4.0 DRILLING AND COMPLETION EVOLUTION IN LOWRY BOMBING RANGE AREA 27 4.1 Completion Evolution 27 4.2 Anticipated Completion and Stimulation Strategy Future Wells 32 4.3 Associated Drilling and Completion Costs 32 5.0 DATA ANALYSIS 33 5.1 Type Curve Assumptions 33 5.2 Workflow 34 6.0 DEVELOPMENT 35 6.1 Acreage Position 35 6.2 Farm In #1 36 6.3 Farm In #2 with possible additional acreage 36 6.4 Development Scenarios 36 6.5 24 Well Development Schedule 37 7.0 ECONOMIC ASSUMPTIONS & RESERVES 42 7.1 Economic Assumptions 42 7.2 Reserves 42 8.0 CONCLUSIONS 44 (Release) iii Jan 6th, 2017

List of Figures Figure 1: Location map showing the Denver Basin and Niobrara Play... 6 Figure 2: Denver East: Area of Exploration & Study (~ 65,000 Acres)... 7 Figure 3: Map showing regional context of LBR prospect acreage... 8 Figure 4: Map showing HNR acreage in orange in relation to LBR acreage position and producing wells... 9 Figure 5: Stratigraphic overview of the DJ Basin... 10 Figure 6: Showing Denver Basin and Key Basin Bounding Structural Features... 11 Figure 7: The northern two-thirds of the Denver Basin of Colorado, Nebraska, and Wyoming. Shown are oil (yellow), oil and gas (blue), and gas (red) wells across the basin. Major fields within the Front Range area are labeled (white text).... 12 Figure 8: Stratigraphic column showing Niobrara formation... 14 Figure 9: Type Log from the Wattenberg Field to north of Highlands acreage... 15 Figure 10: Map showing location and extent of Western Interior Seaway during Upper Cretaceous... 16 Figure 11: W-E Cross section showing Upper Cretaceous sedimentary fill... 17 Figure 12: 3D Schematic depositional model during Niobrara Fm. deposition... 17 Figure 13: Type Log and Location... 18 Figure 14: Denver East: Cross Section from Wattenberg Field Into LBR Area... 19 Figure 15: Lowry Bombing Range: Depth Map... 20 Figure 16: Denver East: Niobrara B Resistivity Map... 21 Figure 17: Denver East: Niobrara B Resistivity and Net Pay Maps... 22 Figure 18: Denver East: Niobrara B Resistivity Map (Zoomed)... 23 Figure 19: Denver East: Niobrara C Resistivity... 24 Figure 20: Denver East: Niobrara C Resistivity & Net Pay Maps... 25 Figure 21: Denver East: Niobrara C Resistivity Map (Zoomed)... 26 Figure 22: DJ Basin: Horizontal Niobrara Completion Summary... 27 Figure 23: DJ Basin: Horizontal Niobrara Production Comparison... 31 Figure 24: Anticipated completion and stimulation information... 32 Figure 25: Indicative drilling/completion costs for an extended lateral well landed in the Niobrara Fm (LBR prospect area)... 32 Figure 26: Map showing HNR acreage position in orange in relation to producing wells to the north... 35 Figure 27: Chart showing indicative drilling schedule... 37 List of Tables Table 1: Showing Reserves and NPV Summary for Cases 1 & 2... 4 Table 2: Reserves Summary for Cases 1 & 2... 5 Table 3: Lowry Bombing Range Completions Summary over time... 28 Table 4: Showing LBR well productivity improvement over time... 29 Table 5: Showing extended laterals and associated well performance... 30 Table 6: Summarizing the well dataset utilised in the RPS type curve derivation... 33 Table 7: Summary Table of P90, P50 & P10 for all Scenarios and Cases... 38 Table 8: RPS Price Deck... 42 Table 9: Reserves and NPV Summary Table... 43 (Release) 1 Jan 6th, 2017

1.0 EXECUTIVE SUMMARY On October 17 th 2016, Knowledge Reservoir LLC dba RPS ( RPS ) was engaged by Highlands Natural Resources Plc ( HNR ) to provide a Competent Person s Report (the Report ) on the Reserves potential of the acreage within the Lowry Bombing Range ( LBR ) prospect area, Colorado, U.S.A. Highland Natural Resources acquired the right to drill up to six wellbores with a 100% WI in 3 sections (1920 acres) from a private operator ( Farmor 1 ) in the LBR prospect area to the east of Denver, south of Denver International Airport. HNR has also recently agreed to a deal to farm in to additional adjacent acreage (1920 acres) with a second operator ( Farmor 2 ) to facilitate a development program of at least 6 and potentially up to 24 extended lateral wells. RPS was engaged to evaluate the HNR acreage position to the south of the LBR prospect area in relation to: Geological continuity of the Niobrara Formation across the HNR acreage position. Determine the economics of the proposed development. Estimate Reserves. The main producing hydrocarbon reservoir in the LBR prospect area is the Upper Cretaceous Niobrara Formation, which is a major tight petroleum resource play. The Niobrara is self-sourced and reservoirs are low permeability chalks, shales, and sandstones. Source beds have TOC contents that range from 2 to 8 weight percent. Source beds are thermally mature in the deeper parts of many of the Laramide basins in the Rocky Mountain region. The Wattenberg Field is the main producing field in the DJ basin and has over 20,000 producing wells. The Niobrara Formation is made up of alternating chalks and organic rich shales and marls with three distinct chalk benches referred to as A, B and C. The majority of Niobrara horizontal wells are landed in one of these benches in the Wattenberg field area with the organic rich shales either side providing the hydrocarbon source. However, in the LBR prospect area (including HNR acreage), only the B and C benches are well developed and hydrocarbon bearing. Resistivity logs from vertical wells in the LBR prospect area show hydrocarbon presence in the Niobrara Formation in both the B and C chalk benches. These resistivity values have been mapped across the LBR prospect area by HNR to prove geological continuity of the prospective zones across their acreage position. The recent drilling and completion evolution across the LBR since 2014 to the present day also plays a key role in understanding the expected productivity of this acreage position and planned development opportunity presented in this report. Conoco and other operators have improved well performance in the LBR prospect area by implementing four changes to the drilling and completion operations: 1. Monobore drilling; 2. Increasing frac fluid and proppant volumes pumped; (Release) 2 Jan 6th, 2017

3. Using a plug and perf completion technique as opposed to sliding sleeve; 4. Drilling extended laterals across multiple sections. The development plan presented by HNR seeks to utilise the same drilling and completion techniques that have proved to be successful for other operators in the LBR prospect area from a Reserves and economics standpoint. In order to derive appropriate type curves to predict the results of development wells in the HNR acreage, 22 modern wells from the existing horizontal well dataset with modern completions were selected. Three distinct development scenarios have been generated as part of this report: 1. Single well development (for economic benchmarking purposes); 2. 6 well development (minimum number of wells to be drilled under farm-in agreements); 3. 24 well development (maximum potential wells available under Farmor 2 agreement). Two cases have been generated for each scenario to model the delta between WI/NRI should Farmor 2 exercise their option to participate as a WI partner, or retain an override only. The results are summarized in Table 1 below. Case 1 after payout: Farmor 1 delivers fixed 80% NRI and 100% WI to HNR, Farmor 2 (after payout) delivers 74% revenue interest on 100% WI to HNR. Blended average is 77% NRI and 100% WI. Case 2 after payout: Farmor 1 same as above, Farmor 2 (after payout) delivers 80% revenue interest on 50% WI to HNR, so effectively HNR gets 40% of the net revenue from Farmor 2 s portion of the wellbore. Blended average across the wellbore is 80% revenue interest on a 75% WI for an NRI of 60%. Prior to payout, Farmor 1 is the same as above, and Farmor 2 delivers 77% revenue interest on 100% WI (blended average of 78.5% NRI and 100% WI). Pricing is based on the RPS 4 th quarter price deck. Basis differentials and transportation deducts are as presented by HNR and have not been independently verified with marketers in the area. P90, P50 and P10 type curves have been generated for each of the development scenarios (single well, 6 well and 24 well development) and Cases (where Farmor 2 chooses whether or not to exercise their option to participate in wider development). RPS is satisfied that the evidence for geologic continuity and therefore production characteristics from wells drilled in the target acreage is sufficient to classify the predicted volumes as Reserves under the PRMS Guidelines. Production uncertainty has been fully modelled to produce the 1P (Proved), 2P (Proved + Probable), 3P (Proved + Probable + Possible) Reserves outcomes and associated discounted (10%) cashflow net present value (NPV 10) shown in Table 1 below. (Release) 3 Jan 6th, 2017

Table 1: Showing Reserves and NPV Summary for Cases 1 & 2 No. of Wells in development plan Gross Oil Gross Gas Net Oil Net Gas NPV10 MBBL MMCF MBBL MMCF M$ 1P 1 290 805 226 624 2,850 2P 1 364 1,054 283 816 5,003 3P 1 646 1,645 500 1,271 12,402 CASE 1 1P 6 1,741 4,828 1,353 3,743 17,369 2P 6 2,185 6,324 1,695 4,896 30,183 3P 6 3,876 9,870 2,998 7,627 74,264 1P 24 6,962 19,311 5,409 14,969 73,679 2P 24 8,740 25,296 6,779 19,578 124,588 3P 24 15,504 39,478 11,990 30,501 299,361 1P 1 290 805 200 538 2,166 2P 1 364 1,054 246 688 3,880 3P 1 646 1,645 416 1,043 9,695 CASE 2 1P 6 1,741 4,828 1,199 3,218 13,181 2P 6 2,185 6,324 1,470 4,120 23,352 3P 6 3,876 9,870 2,494 6,255 58,065 1P 24 6,962 19,311 4,771 12,812 56,300 2P 24 8,740 25,296 5,852 16,420 96,635 3P 24 15,504 39,478 9,944 24,954 234,253 (Release) 4 Jan 6th, 2017

Table 2: Reserves Summary for Cases 1 & 2 Gross Remaining Reserves Net Remaining Reserves Field Name Proved (1P) Proved & Probable (2P) Proved, Probable & Possible (3P) Proved (1P) Proved & Probable (2P) Proved, Probable & Possible (3P) Operator Gas (MMCF) Case 1 (1 Well) 805 1054 1645 624 816 1271 Case 1 (6 Well) 4828 6324 9870 3743 4896 7627 Case 1 (24 Well) 19311 25296 39478 14969 19578 30501 HNR HNR HNR Oil (MBBLS) Case 1 (1 Well) 290 364 646 226 283 500 Case 1 (6 Well) 1741 2185 3876 1353 1695 2998 Case 1 (24 Well) 6962 8740 15504 5409 6779 11990 HNR HNR HNR Gross Remaining Reserves Net Remaining Reserves Field Name Proved (1P) Proved & Probable (2P) Proved, Probable & Possible (3P) Proved (1P) Proved & Probable (2P) Proved, Probable & Possible (3P) Operator Gas (MMCF) Case 2 (1 Well) 805 1054 1645 538 688 1043 Case 2 (6 Well) 4828 6324 9870 3218 4120 6255 Case 2 (24 Well) 19311 25296 39478 12812 16420 24954 HNR HNR HNR Oil (MBBLS) Case 2 (1 Well) 290 364 646 200 246 416 Case 2 (6 Well) 1741 2185 3876 1199 1470 2494 Case 2 (24 Well) 6962 8740 15504 4771 5852 9944 HNR HNR HNR (Release) 5 Jan 6th, 2017

1.1 DJ Basin Location The DJ (Denver) Basin is located on the eastern side of the Rocky Mountains and extends from south of Denver, Colorado to southeast Wyoming, western Nebraska and western Kansas, Figure 1. The basin encompasses more than 70,000 square miles (180,000 square kilometers). Source: http://pacwestcp.com/education/regional-maps/ Figure 1: Location map showing the Denver Basin and Niobrara Play 1.2 Lowry Bombing Range: Location The LBR area lies to the east of Denver, just south of Denver International Airport in Arapahoe and Adams County, Colorado. Highlands have secured 3 sections consisting of 1,920 gross acres of prospective LBR acreage towards the south of the proven producing area, in Arapahoe County, through a farm in deal with Farmor 1. In addition, HNR have agreed to terms for an additional acreage farm out from Farmor 2. Farmor 2 operates a further 65,000 gross acres to the north of the Highland JV acreage, which covers the wells currently on production in core of the LBR area, Figure 2. (Release) 6 Jan 6th, 2017

Source: Highlands Natural Resources Figure 2: Denver East: Area of Exploration & Study (~ 65,000 Acres) 1.3 Hydrocarbon Field Setting The main economic target formation in the DJ (Denver-Julesburg) Basin is the Upper Cretaceous Niobrara Formation, which has been productive from vertical and horizontal wells since 1982, predominantly from the Wattenberg Field, which lies to the north of the Lowry Bombing Range prospect (see Figure 3 and Figure 4 below). Suburban and commercial development has stunted oil and gas development in the LBR area in the past, but horizontal drilling techniques have become more common in Niobrara Formation Development in the Wattenberg Field (and adjacent fields) in recent years, allowing long reach wells to access the otherwise stranded hydrocarbon resource. (Release) 7 Jan 6th, 2017

Source: Highlands Natural Resources Figure 3: Map showing regional context of LBR prospect acreage (Release) 8 Jan 6th, 2017

Source: Highland Natural Resources Figure 4: Map showing HNR acreage in orange in relation to LBR acreage position and producing wells (Release) 9 Jan 6th, 2017

2.0 REGIONAL OVERVIEW 2.1 DJ Basin Overview and Structural Setting The DJ Basin consists of a large asymmetric syncline of Paleozoic, Mesozoic, and Cenozoic sedimentary rocks, trending north to south along the east side of the Front Range. The basin started forming as early as 300 million years ago, during the Colorado Orogeny that created the Ancestral Rockies (see Figure 5 below). Source:: USGS Figure 5: Stratigraphic overview of the DJ Basin (Release) 10 Jan 6th, 2017

The DJ Basin is bounded on the west by the Front Range of the Rocky Mountains, on the northwest by the Hartville uplift, on the northeast by the Chadron arch, on the southeast by the Las Animas arch, and on the southwest by the Apishapa uplift (see Figure 6 below). Source: Modified from Matuszczak, 1973 Figure 6: Showing Denver Basin and Key Basin Bounding Structural Features (Release) 11 Jan 6th, 2017

Oil and gas have been produced from the DJ Basin since the discovery of oil in 1901 in the fractured Pierre Shale at the Boulder oil field in Boulder County. The DJ Basin currently has more than 20,000 producing oil and gas wells, with the majority having been drilling in the Wattenberg Field (see Figure 7 below). Source: Highlands Natural Resources Figure 7: The northern two-thirds of the Denver Basin of Colorado, Nebraska, and Wyoming. Shown are oil (yellow), oil and gas (blue), and gas (red) wells across the basin. Major fields within the Front Range area are labeled (white text). (Release) 12 Jan 6th, 2017

The Denver Basin is an asymmetrical Laramide-age foreland-style structural basin that is approximately oval, stretched north to south, with a steeply dipping western flank and a gently dipping eastern flank. Greatest thickness of sedimentary rocks is along the axis of the Denver Basin, which is a north-southtrending line that approximately connects Denver and Cheyenne (Figure 7). West of the axis, formations dip down steeply eastward; the change in elevation can be more than 9,000 ft (2,700 m) in the space of several miles. Precambrian rocks form the basement of the Denver Basin, are as deep as 13,000 ft (4,000 m) below the ground surface and have been dated at about 1.6 billion years old. Nearly 70 percent of the thickness of sedimentary rocks that overlie Precambrian rocks within the basin are sandstones, shales, and limestones of Cretaceous age (144 to 67 million years old). West of the basin axis, outcrops of east-dipping strata form prominent ridges that parallel the mountain front. The Laramide orogeny began about 67.5 million years ago (Ma) and ended about 50 Ma. This was the major tectonic event that folded these originally flat-lying rocks, formed the current structure of the basin, and uplifted the Rocky Mountains to the west. Amount of uplift is highly variable; estimates are as much as 25,600 ft (7,800 m) in the Mount Evans area of the Rocky Mountains. Between 1,000 ft (300 m) and 6,500 ft (1,910 m) of Tertiary and older strata were removed by erosion in the central Front Range area. Rocks and sediments now exposed across the surface of the Denver Basin are of Tertiary age (less than 66 million years old). They represent redistribution of sediments that were eroded from the Rocky Mountains and redistributed in the subsiding Denver Basin. 2.2 Niobrara Play Summary The Upper Cretaceous Niobrara Petroleum System is a major tight petroleum resource play. The Niobrara is self-sourced and reservoirs are low permeability chalks, shales, and sandstones. Source beds have TOC contents that range from 2 to 8 weight percent. Source beds are thermally mature in the deeper parts of many of the Laramide basins in the Rocky Mountain region. 2.2.1 Play Stratigraphy The Niobrara is a relatively continuous formation (Figure 8) made up of two members: (a) the Lower Fort Hays Limestone Member (b) the Upper Smoky Hill Member. The Lower Fort Hays Limestone Member is a relatively pure limestone that is 20-30 ft. thick around the Wattenberg Field, thickening to the southeast. The Upper Smoky Hill Member is made up of alternating chalks and organic rich shales and marls with three distinct chalk benches called A, B and C. The majority of Niobrara horizontal wells are landed in one of these chalk benches with the organic rich shales either side providing the hydrocarbon source. The Codell Sand is also prospective and is developed using horizontal wells, predominantly in the Wattenberg Field area to the north of the LBR prospect area, which forms the basis of this study. Figure 8 below shows the stratigraphy of the Upper Cretaceous Niobrara Formation and associated hydrocarbon shows in the DJ Basin. (Release) 13 Jan 6th, 2017

Source: Sonnenburg 2010 Figure 8: Stratigraphic column showing Niobrara formation (Release) 14 Jan 6th, 2017

Figure 9 below shows a composite diagram of the Niobrara Formation from the Libsack 43-27 well, which was drilled in Weld County, Colorado. Note increase in the resistivity log response over the Niobrara A, B and C chalk intervals. Source: Modified from Pioneer Resources PowerPoint presentation Figure 9: Type Log from the Wattenberg Field to north of Highlands acreage (Release) 15 Jan 6th, 2017

2.2.2 Niobrara Deposition During the Upper Cretaceous (see Figure 10 below), a seaway extended north-south across North America, splitting it into two landmasses. This seaway was called the Western Interior Cretaceous Seaway. Sediments generally entered the basin from the west due to the uplifted Sevier Orogeny. A maximum of about 15,000 ft of sediment is preserved near the Utah - Colorado border. Siliciclastics dominated the western side of the seaway and marine shales with carbonate intervals dominated the eastern side (inc. the LBR prospect area). The Niobrara Formation is one of the carbonate formations that were deposited to the east (see Figure 11 and Figure 12 below). Source: Modified from Pioneer Resources Figure 10: Map showing location and extent of Western Interior Seaway during Upper Cretaceous (Release) 16 Jan 6th, 2017

Source: modified from Longman et al., 1998 Figure 11: W-E Cross section showing Upper Cretaceous sedimentary fill NOTE: Niobrara Fm. deposited in central and western parts of basin Source: Modified from Longman et al., 1998 Figure 12: 3D Schematic depositional model during Niobrara Fm. deposition (Release) 17 Jan 6th, 2017

3.0 LOWRY BOMBING RANGE PROSPECT GEOLOGY 3.1.1 Geological Continuity of the Niobrara Formation In order to ascertain the development potential of the Highlands acreage to the south of the Lowry Bombing Range prospect area, it is necessary to understand the continuity of the geological characteristics of the Niobrara Formation. As discussed above, the Niobrara Formation produces from three main chalk benches, named A, B & C in the Wattenberg Field to the north (Figure 14). However, in the LBR area, only the B and C benches are well developed, and form the producing intervals for the 39 producing wells to the north of the Highlands acreage. As seen in Figure 13 and below, the productive intervals of the Niobrara Formation are easily correlated from well to well using the resistivity log (curve fill colored green) rather than relying on the gamma ray log. Therefore, to map geological continuity of the play to the south of the PDP wells, the resistivity values are utilized (per bench). Source: Highlands Natural Resources Figure 13: Type Log and Location (Release) 18 Jan 6th, 2017

Source: Highlands Natural Resources Figure 14: Denver East: Cross Section from Wattenberg Field Into LBR Area (Release) 19 Jan 6th, 2017

3.1.2 Niobrara Structure Map The depth to the Niobrara Formation does not change significantly between the 39 producing LBR wells to the north of the Highlands acreage. The depth of the Niobrara Formation in this prospect area is around 2400m. The Niobrara Formation is shallower in the LBR area than the majority of the Wattenberg Field area to the north (Figure 15), resulting in a different hydrocarbon phase constituent between the two producing areas. Source: Highland Natural Resources Figure 15: Lowry Bombing Range: Depth Map 3.1.3 Resistivity Mapping As described above, the productivity of the individual Niobrara chalk benches (B & C) is indicated by increased resistivity readings from the well logs from older vertical wells drilled in the LBR area. The maps below (Figure 16 thru Figure 21) show the continuity in resistivity readings from these vertical wells near the Highlands LBR acreage for the Niobrara B & C benches. Resistivity values derived from the wireline logs that form the basis for mapping have not been independently verified by RPS. (Release) 20 Jan 6th, 2017

Source: Modified from Highland Natural Resources Figure 16: Denver East: Niobrara B Resistivity Map (Release) 21 Jan 6th, 2017

Source: Modified from Highland Natural Resources Figure 17: Denver East: Niobrara B Resistivity and Net Pay Maps (Release) 22 Jan 6th, 2017

Source: Modified from Highland Natural Resources material Figure 18: Denver East: Niobrara B Resistivity Map (Zoomed) (Release) 23 Jan 6th, 2017

Source: Modified from Highland Natural Resources material Figure 19: Denver East: Niobrara C Resistivity (Release) 24 Jan 6th, 2017

Source: Modified from Highland Natural Resources materials Figure 20: Denver East: Niobrara C Resistivity & Net Pay Maps (Release) 25 Jan 6th, 2017

Source: Modified from Highlands Natural Resources materials Figure 21: Denver East: Niobrara C Resistivity Map (Zoomed) (Release) 26 Jan 6th, 2017

4.0 DRILLING AND COMPLETION EVOLUTION IN LOWRY BOMBING RANGE AREA 4.1 Completion Evolution There have been 37 horizontal wells drilled in the LBR prospect area to date (Table 3 & Table 4). Well design and completions have evolved rapidly since the first shorter horizontal wells were drilled between 2011-2013. The first 22 wells, drilled by Anadarko, Conoco, Carrizo and Burlington averaged around 4600ft lateral length. During this period Conoco drilled the Youngberg 10-11 well in December 2013, with a lateral length of 9,498ft to test the viability of long reach laterals in the LBR are, with limited success. The well completion schematic below shows the design of this initial phase of development: The results from a further 11 wells drilled after 14 th October 2014 onwards have been presented by HNR and can be seen in Table 4 & Table 5. Operators started drilling longer lateral lengths (averaging 8350ft) using monobore drilling techniques, utilizing plug and perf completions (as opposed to sliding sleeve) and pumping more frac fluid and proppant during well completions in an attempt to improve well performance. The LBR prospect area now has the highest average proppant and fluid pumped per foot of lateral in the horizontal Niobrara play (Figure 22). Source: Highlands Natural Resources Figure 22: DJ Basin: Horizontal Niobrara Completion Summary (Release) 27 Jan 6th, 2017

Table 3: Lowry Bombing Range Completions Summary over time Source: Highlands Natural Resources (Release) 28 Jan 6th, 2017

Table 4: Showing LBR well productivity improvement over time Source: Highlands Natural Resources Note: Improvement due to longer laterals, increased frac fluid and proppant volumes (Release) 29 Jan 6th, 2017

Table 5: Showing extended laterals and associated well performance Source: Highlands Natural Resources (Release) 30 Jan 6th, 2017

Figure 23 below shows the increase in 6 month cumulative production of oil & gas for both typical horizontal wells (3000 6000ft laterals) and extended horizontal wells (>7000ft) for different parts of the Niobrara Play in the DJ Basin. The charts show that the LBR 6 month cum. oil production increases by 171% from an average of 30,214 bbls from typical laterals to 81,138 bbls from the extended reach laterals. The LBR 6 month cum. gas production increases by 95% from an average of 50,386 MCF from typical laterals to 98,434 MCF from the extended reach laterals. Source: Highlands Natural Resources Figure 23: DJ Basin: Horizontal Niobrara Production Comparison (Release) 31 Jan 6th, 2017

4.2 Anticipated Completion and Stimulation Strategy Future Wells The schematic below (Figure 24) shows the anticipated completion and stimulation strategy for the proposed development of the HNR acreage in the LBR prospect area (as presented by HNR). The suggested volumes of frac fluid and proppant lie within the ranges seen in previously drilled long reach laterals in the LBR prospect area. Source: Highlands Natural Resources Figure 24: Anticipated completion and stimulation information 4.3 Associated Drilling and Completion Costs Figure 25 below (as presented by HNR) shows an indicative drilling and completion costs associated with the drilling of an extended long reach lateral in the LBR Prospect area. These numbers look to be reasonable, and have been developed by costing out the significant items from service providers. These numbers have not been independently verified by RPS. Source: Highlands Natural Resources Figure 25: Indicative drilling/completion costs for an extended lateral well landed in the Niobrara Fm (LBR prospect area) (Release) 32 Jan 6th, 2017

5.0 DATA ANALYSIS 5.1 Type Curve Assumptions A dataset of 38 horizontal wells that produce from the Niobrara Formation in the LBR prospect area have been presented by HNR for the purpose of this study. Of this, 22 wells are horizontal wells of varying lateral lengths that have been completed with modern completion strategies relating to completion design. Production results from these 22 wells have been normalised to account for variation in lateral length to generate an EUR for the wells to be drilled as part of the HNR proposed development plan (see section 6.0 of this report). Burlington drilled the State Elbert lateral well in September 2014 to test the productivity of the Niobrara A bench. However, although the well was completed using modern completion techniques, results were less impressive than those achieved in Benches B & C. Reserves calculated in this Report are related to Benches B & C only. Extended horizontal wells with less than 6 months production and have been excluded from the study on the basis that there is insufficient production data to gain a meaningful analogue. Table 6: Summarizing the well dataset utilised in the RPS type curve derivation Note: These wells have been normalised for lateral length. (Release) 33 Jan 6th, 2017

5.2 Workflow Type curves were developed using the following strategy: Decline curve analysis conducted to determine EUR for oil and gas for each of the wells; Decline curve parameters were determined (shape of curve determined using ARIES); EUR s of the analogue dataset plotted as a cumulative probability plot to determine the P90, P50 and P10 outcome; Type curve for each of the P90, P50 and P10 developed using the decline curve parameters determined above. (Release) 34 Jan 6th, 2017

6.0 DEVELOPMENT 6.1 Acreage Position HNR have secured 1,920 gross acres (3 mile sections) of prospective LBR acreage (Figure 26) through a farm in deal with Farmor 1, to the south of the wells currently on production (with greater than 6 month cum. production). Vertical wells to the south and east of the horizontal wells on production prove the geological continuity and hydrocarbon presence is defined on wireline logs across the acreage position. HNR has also recently agreed to a deal to farm in to additional adjacent acreage (1920 acres) with Farmor 2 to facilitate a potential 24 well development program of extended lateral wells. Source: Highlands Natural Resources Figure 26: Map showing HNR acreage position in orange in relation to producing wells to the north (Release) 35 Jan 6th, 2017

6.2 Farm In #1 HNR farmed into 3 sections to the south of the LBR acquiring 100% WI and 77% NRI. 6.3 Farm In #2 with possible additional acreage HNR have farmed in to adjacent sections to the east and west of the existing position to facilitate the drilling of extended laterals as part of the proposed development, especially relating to the 640 acre section to the north. HNR has also recently agreed to a deal to farm in to additional adjacent acreage (1920 acres) with Farmor 2 to facilitate a development program of at least six and potentially up to 24 extended lateral wells. 6.4 Development Scenarios Three distinct development scenarios have been generated as part of this report: 1. Single well development (for economic benchmarking purposes); 2. 6 well development (minimum number of wells to be drilled under farm-in agreements); 3. 24 well development (maximum potential wells available under Farmor 2 agreement). Two cases have been generated for each scenario to model the delta between WI/NRI should Farmor 2 exercise their option to participate as a WI partner or retain an override only. Case 1 after payout: Farmor 1 delivers fixed 80% NRI and 100% WI to HNR, Farmor 2 (after payout) delivers 74% revenue interest on 100% WI to HNR. Blended average is 77% NRI and 100% WI. Case 2 after payout: Farmor 1 same as above, Farmor 2 (after payout) delivers 80% revenue interest on 50% WI to HNR, so effectively HNR gets 40% of the net revenue from Farmor 2 s portion of the wellbore. Blended average across the wellbore is 80% revenue interest on a 75% WI for an NRI of 60%. Prior to payout, Farmor 1 is the same as above, and Farmor 2 delivers 77% revenue interest on 100% WI (blended average of 78.5% NRI and 100% WI). (Release) 36 Jan 6th, 2017

6.5 24 Well Development Schedule The schedule below (Figure 27) is provided by HNR and related to a 24 well development. It shows a 1-rig development during the initial 6 month period (2 wells landed in the Niobrara B bench, 4 wells landed in the Niobrara C bench) which relates to the 6 well development scenario presented in this report. The proposed schedule then moves to a 2 rig development in month 7 (10 wells landed in the Niobrara B bench, 8 wells landed in the Niobrara C bench), which relates to the 24 well development scenario presented in this report. It is currently anticipated that the development would commence in 1Q 2017. Source: Highlands Natural Resources Figure 27: Chart showing indicative drilling schedule (Release) 37 Jan 6th, 2017

Table 7: Summary Table of P90, P50 & P10 for all Scenarios and Cases No of Wells Case WI BPO NRI BPO WI APO NRI APO Gross Oil Gross Gas Gross Boe Net Oil Net Gas Net Boe Equity Investment Payout ROR NPV10 % % % % MMBL MMCF MBOE MBBL MMCF MBOE M$ Yrs % M$ P90 1 Case 1 100 78.50 100 77.00 290 805 424 226 624 330 5,269 2.02 38.14 2,850 P50 1 Case 1 100 78.50 100 77.00 364 1,054 540 283 816 419 5,269 1.27 69.95 5,003 P10 1 Case 1 100 78.50 100 77.00 646 1,645 920 500 1,271 712 5,269 0.63 100 12,402 P90 1 Case 2 100 78.50 75 60.00 290 805 424 200 538 290 5,269 2.02 33.40 2,166 P50 1 Case 2 100 78.50 75 60.00 364 1,054 540 246 688 361 5,269 1.40 60.85 3,880 P10 1 Case 2 100 78.50 75 60.00 646 1,645 920 416 1,043 590 5,269 0.76 100 9,695 P90 6 Case 1 100 78.50 100 77.00 1,741 4,828 2,545 1,353 3,743 1,977 31,616 2.20 39.44 17,369 P50 6 Case 1 100 78.50 100 77.00 2,185 6,324 3,239 1,695 4,896 2,511 31,616 1.46 72.28 30,183 P10 6 Case 1 100 78.50 100 77.00 3,876 9,870 5,521 2,998 7,627 4,269 31,616 0.85 100 74,264 P90 6 Case 2 100 78.50 75 60.00 1,741 4,828 2,545 1,199 3,218 1,736 31,616 2.24 34.42 13,181 P50 6 Case 2 100 78.50 75 60.00 2,185 6,324 3,239 1,470 4,120 2,156 31,616 1.47 62.60 23,352 P10 6 Case 2 100 78.50 75 60.00 3,876 9,870 5,521 2,494 6,255 3,537 31,616 0.86 100 58,065 P90 24 Case 1 100 78.50 100 77.00 6,962 19,311 10,181 5,409 14,969 7,904 126,463 2.54 44.64 73,679 P50 24 Case 1 100 78.50 100 77.00 8,740 25,296 12,956 6,779 19,578 10,042 126,463 1.86 80.43 124,588 P10 24 Case 1 100 78.50 100 77.00 15,504 39,478 22,083 11,990 30,501 17,073 126,463 1.33 100.00 299,361 P90 24 Case 2 100 78.50 75 60.00 6,962 19,311 10,181 4,771 12,812 6,907 126,463 2.60 38.66 56,300 P50 24 Case 2 100 78.50 75 60.00 8,740 25,296 12,956 5,852 16,420 8,589 126,463 1.88 69.59 96,635 P10 24 Case 2 100 78.50 75 60.00 15,504 39,478 22,083 9,944 24,954 14,103 126,463 1.35 100 234,253 (Release) 38 Jan 6th, 2017

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7.0 ECONOMIC ASSUMPTIONS & RESERVES 7.1 Economic Assumptions Capital assumption is $5.11m/well (see Section 4.3 of this report). No costs savings due to efficiency have been presumed. Initial Opex assumption is $3000/well/month, and has an annual inflation of 3% per year. Pricing is based on RPS 4 th quarter price deck which is shown below in Table 8 Basis differentials and transportation deducts are as presented by HNR and have not been independently verified with marketers in the area. Table 8: RPS Price Deck WI and NRI after payout depend on whether Farmor 2 exercise their option to participate as a WI partner or retain an override only. Should Farmor 2 choose to participate, HNR s interest would reduce to a WI of 75% and an NRI of 60% (Case 2). Should Farmor 2 choose not to participate the HNR s WI would remain at 100% and an NRI of 77% (Case 1). Both of the scenarios are presented in the summary Table 9. 7.2 Reserves P90, P50 and P10 type curves have been generated for each of the development scenarios (single well, 6 well and 24 well development) and Cases (where Farmor 2 chooses whether or not to exercise their option to participate in wider development). RPS is satisfied that the evidence for geologic continuity and therefore production characteristics from wells drilled in the target acreage, is sufficient to classify the predicted volumes as Reserves under the PRMS Guidelines. Production uncertainty has been fully modelled to produce the 1P (Proved), 2P (Proved + Probable), 3P (Proved + Probable + Possible) Reserves outcomes and associated discounted (10%) cashflow net present value (NPV10) shown in Table 9 below. (Release) 42 Jan 6th, 2017

Table 9: Reserves and NPV Summary Table No. of Wells in development plan Gross Oil Gross Gas Net Oil Net Gas NPV10 MBBL MMCF MBBL MMCF M$ 1P 1 290 805 226 624 2,850 2P 1 364 1,054 283 816 5,003 3P 1 646 1,645 500 1,271 12,402 CASE 1 1P 6 1,741 4,828 1,353 3,743 17,369 2P 6 2,185 6,324 1,695 4,896 30,183 3P 6 3,876 9,870 2,998 7,627 74,264 1P 24 6,962 19,311 5,409 14,969 73,679 2P 24 8,740 25,296 6,779 19,578 124,588 3P 24 15,504 39,478 11,990 30,501 299,361 1P 1 290 805 200 538 2,166 2P 1 364 1,054 246 688 3,880 3P 1 646 1,645 416 1,043 9,695 CASE 2 1P 6 1,741 4,828 1,199 3,218 13,181 2P 6 2,185 6,324 1,470 4,120 23,352 3P 6 3,876 9,870 2,494 6,255 58,065 1P 24 6,962 19,311 4,771 12,812 56,300 2P 24 8,740 25,296 5,852 16,420 96,635 3P 24 15,504 39,478 9,944 24,954 234,253 (Release) 43 Jan 6th, 2017

8.0 CONCLUSIONS The RPS analysis conducted as part of this review confirms that the proposed development plan (and expected wells results) is economic. In order to ascertain whether the project can be classified as Proved Reserves, a number of factors have been considered as part of the analysis. Firstly, the geological continuity of the Upper Cretaceous Niobrara reservoir interval have been shown to extend across the HNR acreage position. This was demonstrated through detailed mapping of resistivity values over the reservoir Intervals (Niobrara benches B & C) using wireline logs from existing vertical wells, both within and around the HNR acreage position. Secondly, wells in the LBR prospect area have become economic due to the evolution of drilling and completion techniques utilised from 2014 onwards. Lateral lengths have increased from an average of 4,600ft prior to 2014 to extended lateral well lengths with an average of 8,350ft. This increase in length combined with an increase in frac fluid and proppant volumes has resulted in a significant well performance improvement. The development plan proposed by HNR includes extended laterals drilled across multiple sections, which are analogues to prolific producing wells drilled further north in the LBR prospect area. This development plan seeks to utilise the same drilling and completion techniques that have proved to be successful for other operators in the LBR prospect area from a Reserves and economics standpoint. In order to derive appropriate type curves to predict the results of development wells in the HNR acreage, 22 modern wells from the existing horizontal well dataset with modern completions were selected. Three distinct development scenarios have been generated as part of this report: 1. Single well development (for economic benchmarking purposes); 2. 6 well development (minimum number of wells to be drilled under farm-in agreements); 3. 24 well development (maximum potential wells available under Farmor 2 agreement). Two cases have been generated for each scenario to model the delta between WI/NRI should Farmor 2 exercise their option to participate as a WI partner, or retain an override only. The results are summarized in Table 1 below. Case 1 after payout: Farmor 1 delivers fixed 80% NRI and 100% WI to HNR, Farmor 2 (after payout) delivers 74% revenue interest on 100% WI to HNR. Blended average is 77% NRI and 100% WI. Case 2 after payout: Farmor 1 same as above, Farmor 2 (after payout) delivers 80% revenue interest on 50% WI to HNR, so effectively HNR gets 40% of the net revenue from Farmor 2 s portion of the wellbore. Blended average across the wellbore is 80% revenue interest on a 75% WI for an NRI of 60%. Prior to payout, Farmor 1 is the same as above, and Farmor 2 delivers 77% revenue interest on 100% WI (blended average of 78.5% NRI and 100% WI). (Release) 44 Jan 6th, 2017

Pricing is based on the RPS 4 th quarter price deck. Basis differentials and transportation deducts are as presented by HNR and have not been independently verified with marketers in the area. P90, P50 and P10 type curves have been generated for each of the development scenarios (single well, 6 well and 24 well development) and Cases (where Farmor 2 chooses whether or not to exercise their option to participate in wider development). RPS is satisfied that the evidence for geologic continuity and therefore production characteristics from wells drilled in the target acreage, is sufficient to classify the predicted volumes as Reserves under the PRMS Guidelines. Production uncertainty has been fully modelled to produce the 1P (Proved), 2P (Proved + Probable), 3P (Proved + Probable + Possible) Reserves outcomes and associated discounted (10%) cashflow net present value (NPV 10) shown in Table 8 above. On this basis, all scenarios (in both cases ) stated above have a positive NPV using the current RPS price deck and HNR cost assumptions. (Release) 45 Jan 6th, 2017