9 January East Denver CPR Highlights:

Transcription

1 9 January 2017 Highlands Natural Resources plc ( Highlands or the Company ) Competent Person's Report for the East Denver Oil & Gas Project, Updated Independent Opinion Report for DT Ultravert and Updated Competent Person's Report for Helios Two Highlands Natural Resources, the London-listed natural resources company, is pleased to announce the results from independent evaluations conducted separately for all three of its core assets, the East Denver oil and gas project ( East Denver project ), DT Ultravert re-fracking and parent well protection technology, and the Helios Two natural gas and helium project in Montana ( Helios Two ). These independent reports confirm the intrinsic value of the Company s portfolio and the discounted Net Present Value ( NPV 10 ) potentially available to the Company via the development of its portfolio with a valuation range for the three assets combined defined as between US$441.8 million and US$600.1 million. The Competent Person's Reports ( CPRs ) for the East Denver project and Helios Two, both conducted by Knowledge Reservoir LLC dba RPS ( RPS ), and the Independent Opinion Report ( IOR ), also conducted by RPS, will be made available in full on the Company's website: today. The executive summaries of each report are provided below. East Denver CPR Highlights: Demonstrates an NPV10 range for six wells of US$23.4 million to US$30.1 million, increasing to between US$96.6 million and US$124.6 million for the proposed 24 well development programme, based on Proved plus Probable Reserves Validates recent decision to extend its contiguous acreage to 3,840 acres via a farm-in in Arapahoe County, Colorado, enabling the Company to complete at least six and potentially up to 24 extended horizontal wells DT Ultravert IOR Highlights: Increase in potential NPV 10 range to between US$78 million and US$135 million subject to further successful testing and commercialisation as a well refracturing and anti-bashing technology Based on 75 days of production data, the Company s September 2016 Piceance Basin test confirms that DT Ultravert protected parent wells from bashing and that child wells experienced significantly above-average production performance, relative to adjacent wells completed without DT Ultravert Helios Two CPR Highlights: Un-risked indicative success-case NPV10 in CPR of Helios Two reiterated at US$341 million Notwithstanding variation in gas analyses test results received from multiple laboratories and universities, produced gasses are confirmed to be approximately 88% methane with helium detected in all gas samples up to a concentration of 0.19%. Highlands continues to work towards a definitive gas analysis, which will be released to the market when available.

2 Updated NPV 10 Value Range Summary: Project Name Lower NPV10 Value (US $ Million) Upper NPV10 Value (US $ Million) Denver East Niobrara (2P) US$23.4 (6 wells) US$124.6 (24 wells) DT Ultravert US$78 US$135 Helios Two US$341 Total US$441.8 US$600.6 Chairman and CEO Robert Price said, I am pleased to mark the beginning of 2017 with a positive update and refreshed independent analyses of Highlands core projects. We continue making steps towards our strategy of a mixed portfolio of production and development opportunities, with the weighting towards production. With this goal in mind, we have assembled three core projects that sit at the centre of our company. The potential value available at each project is clear, and with refreshed independent assessments in hand we are now better positioned to secure financing and impactful relationships for their progression. An important focus for the East Denver project has been to secure a meaningful land package during the past months. With our land position now established, we turn our focus to finalising on-going financing discussions with potential industry and financial partners. The Board believes that the CPR analysis generated by RPS should be supportive of these efforts and that the East Denver project represents an important opportunity for near-term cash flow. Testing has shown that DT Ultravert can be used to prevent well bashing and this result has impacted the market potential of this exciting technology. Those positive test results have opened the door to additional potential parent well protection applications in several major shale basins across the United States, and our team continues to advance discussions with multiple potential hosts. Separately, our commercial deployment of DT Ultravert in a DJ Basin re-frack, initially planned for December 2016, has been postponed by the operators due to logistical constraints on their part. The Highlands Board is currently in discussions with the original and additional operators and remains focused on finalising a commercial re-frack in the near term. In the meantime, we are advancing discussions with operators in the Permian, Williston, DJ and other major shale basins. The expanded valuation provided by RPS is encouraging as it now acknowledges a broader potential market for DT Ultravert technology including both parent well protection and re-frack applications. At Helios Two, we continue to advance the de-watering process via installation of new pumping and power generation equipment as indicated in the CPR. This new equipment was installed in late December 2016, and has enabled the higher water discharge rates required to effectively de-water the Muddy Reservoir according to Highlands internal modeling. Additionally, Highlands plans to drill a new deep-zone injection well to further facilitate de-watering by February If de-watering succeeds, we hope to see increasing gas production within three to six months based on Highlands internal modeling. Despite challenges around gas sampling and sample transportation, we confirm that produced gasses are predominantly methane (natural gas) with concentrations of helium up to 0.19%.

3 Due to variability in results from multiple test centers (including noble gas laboratories and universities), Highlands continues to work towards a final and conclusive gas analysis result. While the economic viability of the project remains to be proven by de-watering, these initial gas analyses confirm Highlands thesis that the Muddy formation may contain biogenic methane and helium. Additional gas tests are in progress, and Highlands will release any conclusive results as soon as they are available. Looking ahead to the rest of 2017, we believe that Highlands has the potential to be transformed in the event that any one of our three core projects achieves the economic and technical potential described by RPS in the updated reports released today. Of course, we are working to achieve success on all three platforms. As always, we will continue to update the market with material news as it becomes available. The following are the complete Executive Summary sections taken verbatim from the two Competent Person s Reports and the Independent Opinion Report. Glossary: NPV 10: Net present value of cash flows discounted at an annual rate of 10% Un-risked Indicative Success Case NPV 10: The NPV 10 of a project in the case that the success case is achieved; this value does not take into account the various risks and uncertainties involved in achieving the success case projections. WI: Working Interest, which is the portion of capital and operating expenses borne by a participant in an oil and gas project NRI: Net Revenue Interest, which is the portion of revenues (net of operating expenses and taxes) that is received by a participant in an oil and gas project. In the case of East Denver, Highlands receives an NRI that is less than its WI because Highlands pays certain revenue royalties to Farmor 1 and Farmor 2 as well as royalties retained by the state of Colorado. P90, P50 and P10: Refer to statistical probabilities that 90%, 50% and 10% of results will exceed a stated value. For example, the P50 value is a median scenario. Executive Summary of East Denver CPR: On October 17 th 2016, Knowledge Reservoir LLC dba RPS ( RPS ) was engaged by Highlands Natural Resources Plc ( ) 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. 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 acreage position to the south of the LBR prospect area in relation to:

4 Geological continuity of the Niobrara Formation across the 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 selfsourced 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 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 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; 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 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 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);

5 2. 6 well development (minimum number of wells to be drilled under farm-in agreements); 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, Farmor 2 (after payout) delivers 74% revenue interest on 100% WI to. 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, so effectively 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 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. 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 ,850 2P , ,003 3P , ,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

6 1P 24 6,962 19,311 5,409 14,969 73,679 2P 24 8,740 25,296 6,779 19, ,588 3P 24 15,504 39,478 11,990 30, ,361 1P ,166 2P , ,880 3P , ,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, ,253 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 1,054 1, ,271 Case 1 (6 Well) 4,828 6,324 9,870 3,743 4,896 7,627 Case 1 (24 Well) 19,311 25,296 39,478 14,969 19,578 30,501 Oil (MBBLS) Case 1 (1 Well) Case 1 (6 Well) 1,741 2,185 3,876 1,353 1,695 2,998 Case 1 (24 Well) 6,962 8,740 15,504 5,409 6,779 11,990 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 1,054 1, ,043 Case 2 (6 Well) 4,828 6,324 9,870 3,218 4,120 6,255 Case 2 (24 Well) 19,311 25,296 39,478 12,812 16,420 24,954

7 Oil (MBBLS) Case 2 (1 Well) Case 2 (6 Well) 1,741 2,185 3,876 1,199 1,470 2,494 Case 2 (24 Well) 6,962 8,740 15,504 4,771 5,852 9,944 Executive Summary of DT Ultravert IOR: Highlands Natural Resources has acquired rights to an innovative technology (DT Ultravert) concept that enables the diversion of hydraulic fracturing fluid from low stress regions to high stress regions within the stimulated regions around the well. It involves the injection of a compressible fluid to act as a diverter followed by the injection of an incompressible fluid which will act like the fracturing fluid. This addendum to the original December 2015 independent opinion report focuses on several key components that have affected in the market; advances in their commercialization strategy; and positive results obtained from their parent well protection initiative. Changes and observations covered by this addendum are: Related to market conditions: due to extended commodity pricing and steep declines in the North America O&G drilling and completion activity, the available market for DT Ultravert has been reduced in this evaluation. Along with a reduction in activity there is also a reduction in forecasted wells would be able to apply this technology for 2017 to In light of lower activity for new drill and completed wells, there is optimism for a growing refracturing market once a proven technology has been identified since refracturing existing wells has inherently less cost and risk than for newly drilled wells. As a result of this dichotomy, the model used in this report projects both a conservative and an aggressive well forecast for to deploy DT Ultravert for this market segment. has made significant progress in the pre-job design and planning activities for delivering this technology to the market. This includes expanding their market exposure from frac/refrac activities to include parent/child well protection capabilities. It remains to be fully proven but, after a few more successful field trials of this technology, this might become the largest market for the DT Ultravert technology within the next few years. better understands the refrac market and has the necessary resource in place for job planning, design and post job evaluations of this innovative technology. understands and is supporting industry trends delivering an in-reservoir diversion system which when proven could have a large impact on well estimated ultimate recoveries and associated hydrocarbon recovery factors. Economic modeling suggests a range of potential NPV10 based on 10 year forecasts of $78MM to $135MM for conservative vs. aggressive refrac adoption respectively.

8 has completed a parent well protection job for a US operator with successful results which is regarded as a very positive step in the right direction for. These results prove the technology can be a viable solution for protecting offset wells for a stimulation event. However, barriers to entry, prior art and intellectual property enforcement are still a concern. Multiple jobs will need to be completed to prove the concepts in several major US plays. Once several jobs have been completed, a statistical well decline evaluation and production EUR evaluation should be conducted to define the economic value of these projects applied to this market segment. Financial assessments based on a reduced fracturing market; improved market penetration in a growing parent well protection market and associated application to refracturing markets suggest that, in the event of further proven success, may even be able to improve the potential economic value of this technology within their portfolio, even relative to their initial vision of its application. Executive Summary of Helios Two CPR: On 19th May 2016, Knowledge Reservoir LLC dba RPS ( RPS ) was engaged by Highlands Natural Resources Plc ( Highlands or the Company ) to provide a Competent Person s Report (the Report ) on the resource potential of low saturation gas found in the Muddy Formation in southeast Montana, U.S.A (the Muddy Prospect). A report was issued on June 28, In September 2016, Highlands drilled the Helios appraisal well to test the concept of co-production form a gassy aquifer, in the Muddy interval. On 18 th November 2016, Highlands re-engaged RPS to prepare an update to the June 28 report. This report contains an update including the early test results from that well. No update of volumetrics or indicative success case value has been run at this time since the results of the well, although confirming the existence of initially low saturation gas as expected, are not sufficiently mature to require any re-quantification of potential, either upwards or downwards. In addition to the ongoing production test at the Muddy level, Highlands also drilled a second well (Helios ) and encountered a potential Milk River equivalent in the shallow section (the Eagle Formation) which reportedly produced a small amount of gas (variable length flares) but at low rate but it is noted that no actual flow-rate measurements could be taken at the time. Insufficient data exists to describe this as a prospect as yet but it does provide encouragement that further gas resource may exist in the immediate area over and above the original Muddy target formation. This is more fully described in Section 3.4 of this report. The Muddy Prospect is located within the Northeastern part of the Powder Basin of southeast Montana and Wyoming which has been a prolific producer of hydrocarbons. Conventional exploration in the area has targeted and been developed in fields that exhibit normally expected hydrocarbon saturations with typical conventional flow characteristics. However, many wells were drilled into equivalent reservoirs across the area through time and were reported as finding low gas saturation in brines (high water saturation) which would bubble

9 and/or ignite at the surface but were not thought to be commercially productive, and certainly not in comparison to the high gas saturation accumulations that were being discovered at the time. Consequently, the low gas saturation reservoirs were ignored and classified as waterwet. However, two further developments have occurred since those times: The development of helium gas in the area which now commands very high prices and is forecast to be increasingly short-supply; The advent of commercial co-production in other similar reservoirs which provide good analogues to support the belief that the high water saturation reservoirs in the Cretaceous of southeast Montana (and elsewhere in the local) could be a by-passed play. The combination of these two factors in the Muddy Prospect area means that, if the concept can be proved via a pilot test program, a whole new economic play may open up. The Muddy Formation is of Lower Cretaceous Aptian age and is time equivalent to the Viking/Bow Island formations of Alberta, Newcastle Formation of Manitoba and the J sandstones of Colorado. The sands were deposited in valleys cut during periods of low-stand into the underlying basinal Skull Creek shales and filled with estuarine / tidal delta sediments during the subsequent transgression. A key feature of the Muddy formation is a high clay and fine silt content contained within otherwise reasonably porous and permeable sands (hence the name). These clays (primarily Kaolinite and Illite) are thought to act as a resistivity suppressant resulting in low and unrepresentative water saturations when calculated using the conventional Archie type method. The true initial gas saturations are still very low when compared with less clay rich and conventional reservoirs but the production technique of coproduction has now been documented in several analogue cases from Oklahoma, Japan and elsewhere, and, in one particular well (Jorgenson #1-R drilled into and tested the Virgelle Member of the Milk River Formation in Hill County, Montana), in close proximity to the area which was observed by one of the Company s advisors back in Co-production is a production method whereby a well is produced by lifting (pumping) produced water with low gas saturations and as the reservoir pressure drops gas becomes more mobile and gradually increases in ratio (gas to water ratio), in some cases to the point where gas flows at good to excellent rates. This co-production methodology requires the production, handling and disposal of significant quantities of water (normally via re-injection) and the balance between disposal costs and revenue realization from a slow-buildup of the gas production profile may be uneconomic. However, low concentrations of Helium in the produced gas may well deliver significant net-back economics since the helium price is currently more than $100/Mcf and predicted to increase as stored volumes are drawn down and demand increases. The Muddy sands have been shown to contain 0.36% helium, from analysis of produced gas from a drill stem test of a wildcat well drilled by Pan American Petroleum Corporation in Section 23, Twp 5N Range 52E, Custer County, Montana in 1969.

10 This has the potential to change the economics even at low concentrations but it should be noted that the methane is not valueless if sufficient volume and hence revenue can be achieved to cover the water disposal costs. At the time of the June 28 report, Highlands had secured approximately 60,000 acres within an overall potential area of interest of nearly one million acres. The Company has identified a Priority Leasing Area over a three Township area (6N 51E, 6N 52E and 5N 52E) and the pilot program consisting of two test production wells and one injection well will first be drilled and tested and then expanded to develop the Priority Leasing Area acreage in the event that production is achieved at commercial rates. As of the date of this report, the Company has increased its leased area to approximately 105,000 acres. RPS has reviewed data supplied by the Company and accessed the production database for all gas wells in Southeastern Alberta and Southwestern Saskatchewan, using Accumap, to look for other local analogues. RPS has found good evidence of helium production and has a logical and coherent explanation for the helium concentrations found as well as support for the fact that the sample in the area could well be representative over a wider area and maybe even pessimistic. Based on RPS independent analyses and drawing on suitable analogue data, RPS has developed a model of the in-place volumes expected per acre, the Resource potential for the three Township area and a type well based on production characteristics from two key wells (Howard #17-1 and Jorgenson #1-R). RPS has estimated the Geologic Chance of Success for the prospect at 80%, with the primary identified risk being the risk of being able to mobilize and produce gas at commercial rates from the highly water saturated gas reservoirs. A conceptual development plan for the full three Township area has been modelled for economics in excel and supplied to RPS. RPS has reviewed this model and updated the well production forecast based on an RPS derived type well production, and for capital and operating costs based on RPS estimates. This gives a simplistic but reasonable view of the potential Resource volumes of Methane and helium and also an indicative success case value based on the Company s assumptions which have been reviewed and do not seem unreasonable and will be further demonstrated by the pilot program in terms of cost control etc. The table below summarizes our findings of gross and net attributable Prospective Resources for the three Township areas of the Muddy Prospect and the following Report gives more detail on the work and assumptions behind the results. Table 3: Prospective Resources Summary for Muddy Prospect Muddy Prospect (WI=100%) Co-production Gas (Bcf) Methane (100 Section development) Helium (based on 0.36% concentration) Source: - RPS Low Estimate Gross Best Estimate High Estimate Low Estimate Net Attributable Best Estimate High Estimate Risk Factor Operator , ,021 80% Highlands Montana % Corporation

11 Notes: Gross are the 100% Resources that are attributable to the licence whilst Net Attributable are those estimated to be attributable to Highland s 83.33% NRI after royalties. Risk Factor means the estimated chance or probability of discovering gas in sufficient quantity for it to be tested to the surface (also referred to as GPoS). It should be noted that a pilot test program to confirm that co-production is possible and the development of a 100 Section area is required to achieve the volume range quoted. The Chance of Development is specifically not included in the Risk Factor shown. The unrisked P50 indicative success case valuation (NPV10), before income tax, calculated for the 100 Section development based on capital cost and operating cost estimates built up by RPS is US$341MM. This value does not represent any form of market value for the asset and requires several critical events to occur to be achieved including discovery, appraisal, capital expenditure and the successful negotiation of the third-party midstream service contract described in Section of the Report. This indicative success case valuation does not include specific economics for the helium as it is not possible to estimate Capex and Opex requirements until the helium percentage content has been confirmed as the scale of the processing and methodology for extraction will be critically dependent on this ratio. As noted above, however, helium is in increasing demand and could be a significant upside to the existing success case based on the methane project alone. **ENDS** For further information, please visit or contact: Robert Price Highlands Natural Resources plc +1 (0) Nick Tulloch Cenkos Securities plc +44 (0) Neil McDonald Cenkos Securities plc +44 (0) / +44 (0) Lottie Brocklehurst St Brides Partners Ltd +44 (0) Elisabeth Cowell St Brides Partners Ltd +44 (0) Notes to Editors Highlands Natural Resources (LSE:.L) is a London-listed natural resources company with a portfolio of high-potential oil, gas and helium assets and technologies. The company s core projects include: East Denver Niobrara: a farm-in opportunity for horizontal oil and gas wells targeting the Niobrara shale formation in a well-studied area of the Denver Julesburg Basin. DT Ultravert: a re-fracking and parent well protection technology with 20 patents pending in the United States and internationally. Highlands is advancing commercial

12 conversations with a range of oil and gas operators to create revenue-sharing opportunities for DT Ultravert applications. Helios Two: a 105,000+ acre helium and natural gas prospect in SE Montana with drilling and assessment operations ongoing