Freedom Oil & Gas Limited (ASX: FDM, OTCQX: FDMQF) High growth Eagle Ford shale producer

Transcription

1 30-Sep Dec Mar Jun Sep-18 K1 Capital Freedom Oil & Gas Limited (ASX: FDM, OTCQX: FDMQF) High growth Eagle Ford shale producer Overview Freedom Oil & Gas is an oil and gas producer with ~9,700 net acres in the Eagle Ford Shale in Texas. The company has over 80 potential well locations in the Lower EFS formation, of which the first 6 have been drilled with good results. 2P reserves of 38 MMboe could increase multiple times if drilling expands to other horizons, providing more than 10 years of production growth. Twelve new wells are currently being drilled, which should increase net production to ~5 kboepd by mid-2019, rising to ~18 kboepd by 2021 and providing ~$US160m/yr of free cash over the period. We value Freedom at $0.40/sh, with upside to $0.76/sh as additional EFS horizons are developed and reserves increase. We estimate potential of up to $2.00/sh if the acreage is fully developed and derisked. Key points Good address: Freedom s project is in Dimmit County, southeast Texas, which is the volatile oil and condensate part of the EFS trend, providing good well productivity. The shale is up to 400 feet thick offering the potential for three productive EFS intervals. Freedom s 100% working interest provides operatorship and enables it to control the pace of development. Existing reserves, with significant upside: The latest independent assessment reported 19.1 MMboe of proved and 37.8 MMboe of proved & probable reserves, of which 76% are liquids. We expect upgrades with further drilling. Net resources could increase to over 200 MMboe with development of all horizons and tighter drilling, 6 times current 2P levels. Good well productivity: Freedom drilled six wells during late 2017 and early 2018, achieving initial production rates over the first thirty days (IP30) of ~1,100-1,200 kboepd. Drilling and completion costs of $US5.3m/well should reduce as experience builds, with drilling times now less than 12 days/well. Further improvement in well productivity (currently ~600 kboe/well) is possible with continued optimization. Long term growth profile: The current 2P reserves will support drilling and production growth for the next 2-3 years, using 2 rigs from 2020, and the upside resources will support development for 10 to 15 years. We estimate net 2P production should reach 18 kboepd by 2021, with upside potential of over 50 kboepd within 10 years under a full development scenario. Free-cash flow from 2021: We estimate Freedom requires ~$US200m for drilling until end 2020 but is then self-funding at $US70/bbl Brent. Near term capex will be sourced from cash and a reserves-based lending facility, although extra funding may be required depending upon the pace of development, well productivity and prevailing commodity prices. Key risks relate to gearing and commodity prices: We estimate net debt will peak at ~$US190m, giving D/(D+E) of 56%, in late-2020 for 2P development. Additional horizons can be developed thereafter from free cash flow. We estimate Freedom is cash positive above $US42/bbl Brent on 2P reserves, providing downside protection; this rises to $US55/bbl on 1P. SHARE PRICE PERFORMANCE Closing price as of 2 nd Oct 2018 $US CAPITALIZATION Last price $A week range $A Capitalization $A215m Cash: 30 th Jun $US10m Debt: 30 th Jun $US40m EV $A257m Shares 1,077m Options/rights 88m Conv Notes 0m Balance date December RESERVES AND PRODUCTION 1P (30 Jun 18) 19.1 MMboe 2P 37.8 MMboe 3P - MMboe 2C - MMboe FY17a 0.1 MMboe FY18e 0.5 MMboe FY19e 1.9 MMboe SHAREHOLDERS (%) Board/mgt 8.9 Other Total LEADERSHIP Chairman MD/CEO Mike Yeager Mike Yeager Disclosure: This is a commissioned research report and K1 Capital will receive a fee for preparing this report. Author: John Young jayoung@k1capital.net.au Copyright 2018, K1 Capital Pty Ltd, ABN October

2 Table 1 Financial summary (December year end, net revenue interest basis, USD currency) - Base Case Copyright 2018, K1 Capital Pty Ltd, ABN October

3 Table of Contents 1. Valuation summary Eagle Ford Shale Project summary Valuation Board and management SWOT analysis Near term funding Appendices References Disclosure: This report was commissioned by Freedom Oil & Gas Limited (Freedom). K1 Capital Pty Ltd (K1 Capital) will receive a fee for preparing this report. The purpose of the report is to provide an assessment of the value of Freedom s assets and business. The user of this report is Freedom Oil & Gas Limited and persons designated by them. K1 Capital has prepared this report based on interviews with Freedom s management, inspection of company reports and research using publicly available information. K1 Capital has not undertaken a site visit to Freedom s project. To the best of K1 Capital s knowledge, full, accurate and true disclosure of all material information was provided by Freedom. Given the potential for a perceived conflict of interest it is K1 Capital s policy not to include a share price target or investment recommendation for commissioned research. K1 Capital may seek to do business with companies covered in its reports. Consequently investors should be aware that the firm may have a conflict of interest that could affect the objectivity of its research. Please see the final page of this report for further information on disclosures and disclaimers. Copyright 2018, K1 Capital Pty Ltd, ABN October

4 1. Valuation summary We have estimated Freedom s equity value for four scenarios, based on a risk adjusted NPV analysis. Case Description $A/share Base 2P reserves, $US70/bbl Brent, $US3.20/MMBtu Henry Hub long term 0.40 Bear 1P reserves, $US60/bbl Brent, $US2.80/MMBtu Henry Hub long term 0.03 Bull Base + development of Lower EFS and Upper EFS (at 50% risk) 0.76 Blue Sky Bull + Austin Chalk + EFS down spacing (all unrisked) 2.00 All cases assume 0.75 $US/$A forex long term and 10% nominal discount rate Our base case valuation is shown in further detail below. Our valuation methodology, assumptions and sensitivity analysis are described later in this report. Figure 1 Base case valuation summary Copyright 2018, K1 Capital Pty Ltd, ABN October

5 1.1.1 Investment case High quality acreage: Freedom s acreage is in the volatile oil and condensate window, which provides high production rates, with shale thickness of feet offering the potential for three productive intervals (Lower EFS A, Lower EFS B and Upper EFS) plus exposure to the overlying Austin Chalk. Its proximity to over 350 producing wells plus rock core data provides confidence in performance capability and shale quality. Production rates from the six wells Freedom has drilled in its first two drilling phases have been above expectations, with ~75-80% liquids. Good commercial performance: Freedom leased much of its acreage at attractive prices when oil prices were low during 2015 and The moderate reservoir depths (~2,000 m, ~6,500 ft) and drilling of multiple wells from pads enable low drilling & completion costs of $US m/well, for wells with ~2,200m (7,500 ft) laterals. Lease operating expenses and transportation costs are low, at ~$US6-7/boe and ~$US2-3/bbl oil and <$US1/kscf gas respectively. Technology enhancements continue to drive improvements in production rates and reserves per well. Most of Freedom s acreage is contiguous, allowing for long laterals, delivering high capital productivity. Near term development and long term potential: Freedom commenced its third phase of drilling in August, with wells planned by March Our base case assumes development of 2P reserves. However, the existing acreage has the potential to support over 10 years of drilling, with production continuing for more than 30 years, if all EFS horizons and the Austin Chalk are developed. We estimate full development would deliver net production of over 50 kboepd for the period from 2026 to This would be a major project, with around 590 wells in total and annual capex of ~$US250m for ~13 years (for a total of $US3.2b in real terms), but is self-funding from 2021 onwards from our analysis. Figure 2: Dimmit County project production scenarios (net basis) Bear: 1P, Lower EFS B, 67 wells Base: 2P, Lower EFS B, 84 wells Bull: Lower EFS A+B, Upper EFS, ~252 wells Blue Sky: Lower EFS, Upper EFS, Austin Chalk, down spacing, ~590 wells 600 kboe/well EUR for Lower EFS B and Upper EFS, 480 kboe/well for Lower EFS A, Austin Chalk and EFS down spacing Source: K1 Capital analysis Free cash flow from 2021: Capital requirements for oil and gas developments are front-end loaded, however, the capital spend for shale projects is spread over a longer period due to the extended drilling profile. We estimate the 2P development scenario requires $US429m of capital (real 2018 $) based on 78 PUD wells from August 2018 at $US5.5m/well for drilling, completion and facilities. This may reduce with continued optimization. We expect 2P development will run from mid-2018 until mid-2021 under the current plan utilizing two rigs from 1H 2020, requiring external capital until the project is self-funding from Our modelling indicates development of additional horizons from 2021 can be funded from free cash flow. Copyright 2018, K1 Capital Pty Ltd, ABN October

6 Figure 3: Cash profile, 2P development scenario ($US millions) Source: K1 Capital analysis. Nominal dollar basis at $US70/bbl 2018 real Brent. Near term development is funded: The $US60-63m of capital required for the current 12 well program will be met from existing cash (~US28m after the recent placement) and the planned reserves-based lending facility. The RBL facility should provide a borrowing base of $US15m before the end of 2018, with subsequent increases at six-monthly or more frequent intervals upon proven reserves additions, peaking at ~$US190m in The RBL capacity is difficult to estimate accurately given the range of input parameters (such as drilling rates, timing of reserves redeterminations, production performance, commodity prices, etc.) and additional capacity may be required in Current company plans are to work within the available capacity. Well performance risk: We have adopted well performance parameters based on the recent independent reserves assessment, which are conservative (600 kboe/well EUR) relative to company and independent consultant estimates (~700 kboe/well). However, the EFS play is less than 10 years old and EFS wells have been in production for much less than the expected life of over 30 years. Extrapolation of production rates and ultimate recovery is subject to significant variation with changes in assumptions, and industry and academic studies of EFS well performance note wide variation in decline curve parameters [1] [2] [3] [4] [5]. We have undertaken a range of sensitivity analyses and remain confident that the assumed performance provides sufficient margin of safety in terms of valuation outcomes. Share price catalysts: We believe the following events provide opportunities for share price re-rating as Freedom s EFS project is further derisked. 4Q 2018 Completion of RBL facility Progress on Phase 3 drilling program (12-15 wells), announcement of IP30 rates on completed wells, announcement of production growth 1Q Dec 2018 reserves upgrade. Announcement of RBL borrowing base 2Q 2019 redetermination. Completion of Phase 3 drilling program, confirmation of production targets and well performance 2H Jul 2019 reserves upgrade. Announcement of RBL borrowing base redetermination. Commencement of Phase 4 drilling. Copyright 2018, K1 Capital Pty Ltd, ABN October

7 2. Eagle Ford Shale Overview The Eagle Ford Shale is a hydrocarbon-producing formation in Texas, that extends from the Mexican border in the west to Leon, Madison and Walker counties in the east. The region of economic interest lies at depths of between 1,200 and 4,000 m (4,000 and 14,000 feet) and is ~80 km (50 miles) wide, 700 km (400 miles) long and 75m (250 feet) thick on average. The formation outcrops in the north and dips steeply towards the Gulf of Mexico. The EFS has a very high carbonate shale content, which makes it brittle and conducive to hydraulic fracturing, important for well productivity. Although development of the EFS is relatively recent, starting in 2008, industry activity has been significant, with over 18,000 wells drilled over the past 10 years (i.e. over 5 per day on average). The EFS currently produces ~1.5 MMboepd of oil, condensate and gas. The EFS is composed of three main phase regions, ranging from oil to condensate to dry gas as the trend deepens towards the Gulf Coast. Figure 4: Wells permitted and completed in the Eagle Ford Shale to July 2018 Source: Railroad Commission of Texas, website accessed 17 th September Copyright 2018, K1 Capital Pty Ltd, ABN October

8 2.1.2 Production statistics Major operators in the Eagle Ford include EOG resources, Devon Energy, Chesapeake, Burlington Resources, Marathon Oil, Murphy Oil, Encana, Exco, Rosetta Resources, Statoil and BHP Billiton. Oil, condensate and gas production peaked at ~2.5 MMboepd in 2015 before declining to ~1.6 MMboepd in 1H2018. Production has lagged drilling permits, which peaked at ~5,600 issued in 2015, before dropping sharply due to the oil price fall in late 2014, before recovering in 2017 and The production mix has shifted over time, with the average condensate to gas ratio increasing from around 44 bbl/mmscf in 2009 to 65 bbl/mmscf in 2011, before steadily declining to 35 bbl/mmscf in 2018 as production shifted from liquids-rich to drier areas. The ratio of oil to gas also peaked in Figure 5: Eagle Ford production 2008 to May 2018 Source: K1 Capital analysis of Railroad Commission of Texas data Jan/Jul drilling permits annualized Operating performance Drilling performance has improved over time, with average initial production rates over the whole Eagle Ford trend increasing to ~1.5 kbopd and 6 MMscfd gas. The improvement has been driven by optimization of drilling, completion and production practices, with longer laterals, increased number of stimulation stages and perforation clusters, increased stimulation water and sand volumes, and changes to proppant type and size. The improvement trend is continuing. Figure 6: Eagle Ford Shale rig and well performance Source: US Energy Information Administration, Drilling Productivity Report, September 2018, p 6 and p 2. Notes: Oil production represents both crude and condensate production from all formations in the region; gas production represents gross (before processing) gas production from all formation in the region. Production is not limited to tight formations. The regions are defined by selected counties, which include areas outside of tight oil formations. Copyright 2018, K1 Capital Pty Ltd, ABN October

9 3. Project summary Dimmit County project location Freedom has leased ~9,700 net acres in the Eagle Ford shale trend in Dimmit County, in west Texas near the border with Mexico. The acreage is in the volatile oil and condensate window, adjacent to over 350 offsetting producing wells. The EFS within the acreage is up to 120 m (400) ft thick, allowing development of three producing intervals (the Lower Eagle Ford A, Lower Eagle Ford B and Upper Eagle Ford). Freedom undertook an extensive technical evaluation prior to drilling its first well, comprising petrophysical interpretation of data from over 200 of the offset wells; purchasing core data from five surrounding wells and 3D seismic data over its own acreage; undertaking detailed reservoir characterization of the EFS formation for rock and fluid properties and estimated hydrocarbon in place; and evaluating geological hazards such as faulting and offset well trajectories; prior to independent review of the analysis by independent experts such as Schlumberger. The value of this work has been demonstrated in the good results achieved in Freedom s first six wells. Figure 7: Project location relative to the Eagle Ford shale trend Source: Freedom Oil & Gas Limited, April 2018 fact sheet Development concept Six wells in the Lower EFS B are currently on production from two wells drilled in late 2017 (Phase 1) and four wells drilled in 1H 2018 (Phase 2). Freedom plans to drill 12 to 15 wells in the next phase, which started in late August. The wells will be drilled from three pads, with the first three wells (Vega- 1, 2 & 3) having been being drilled from the Wilson pad used in Phase 1. Hydraulic fracturing will commence after finalizing the drilling of each pad. The two Wilson wells were shut-in during drilling and completion of the Vega wells for safety reasons (to remove potential ignition sources), which will reduce production levels in 2H The acreage is close to existing oil and gas lines. Oil is transported via trucking or pipeline, which costs $US3-4/bbl or $US2-3/bbl respectively. Raw gas containing NGLs is connected to an external gas gathering, compression and transportation network, with total gas treatment and transportation costs of ~$US1.00/kscf. Copyright 2018, K1 Capital Pty Ltd, ABN October

10 Figure 8: Rig site Source: Freedom Oil & Gas Limited, 2017 AGM presentation, 27 th May 2017, p 1 Figure 9: Initial field development map Source: Freedom Oil & Gas Limited, August 2018 investor presentation, p 11 Copyright 2018, K1 Capital Pty Ltd, ABN October

11 3.1.3 Development scenarios Current development is focused on the Lower EFS B horizon. Subsequent development is planned to include the Upper EFS, Lower EFS A and Austin Chalk. Figure 10: Stacked development Source: Freedom Oil & Gas Limited, investor presentation, 27 th November 2018, p Reserves and resources We model four scenarios, with increasing levels of reserve and resource development. Our base case assumes development of current 2P reserves of 37.8 MMboe net to Freedom. Our downside case is based on 1P reserves of 19.1 MMboe net. Both are limited to the Lower EFS B horizon. Our upside scenarios evaluate staged development of additional horizons and down spacing of the EFS, described on the following page. Figure 11: Oil and gas reserves (net to Freedom) Source: K1 Capital analysis of Freedom Oil & Gas Limited, 2017 Annual Report, p 21 and ASX release, 24th September Gas conversion ratio of 6:1 kscf per boe. A portion of reserves for all PUD locations is assigned to the probable category, as noted in the 2017 Annual Report. Assumes 75% net revenue interest. Crimson font denotes K1 Capital estimates, based on the stated 54% oil, 24% NGL and 22% gas split for proved reserves per 24 th September Copyright 2018, K1 Capital Pty Ltd, ABN October

12 Figure 12: Resource development scenarios Source: K1 Capital analysis. NRI of 75%. Lower EFS B includes the 1P and 2P reserves. NSAI reserves as of 1 st July 2017, per Freedom Oil & Gas Limited, ASX release, 24 th September Gross EUR per well for Lower EFS B based on NSAI 2P reserves assessment. The same EUR per well was assumed for the Upper EFS. A 20% reduction was applied to the Lower EFS A, Austin Chalk and EFS down-spacing scenarios, based on the same approximate percentage reduction noted in Freedom s Investor Presentation of 26th November 2017, p 16. Average well spacing for Eagle Ford Shale and EFS down spacing scenarios assumes development of three horizons Type curve Freedom s Lower EFS type curves are shown below. The Original TC is the type curve based on two years of offset well production assessed by independent consultants in April 2016; the Current TC is the type curve estimated by Freedom for its first two Wilson wells; and the Upside TC is the upside case type curve estimated by Freedom, with all curves normalized to a lateral length of 7,000 ft. Figure 13: Freedom Dimmit County Lower EFS type curve Source: Freedom Oil & Gas Limited, Investor Presentation, 26 th November 2017, p 11. Copyright 2018, K1 Capital Pty Ltd, ABN October

13 3.1.6 Well performance Our estimate of EUR for the Lower EFS B wells of 600 kboe is derived from NSAI s 1 st July 2018 reserves data. Freedom s estimates, which have been reviewed by independent consultants, are approximately 15% higher. We have cross-checked these values with recent publicly available information for Dimmit County wells, published by Sundance Energy Australia Limited (ASX: SEA). Freedom assumes a 20% reduction for Lower EFA A given expected well interference to approximately 550 kboe/well and similar EURs for Austin Chalk and down spacing wells. We have assumed a similar percentage discount, to 480 kboe/well. Table 2 Dimmit County well performance assumptions (gross basis) Item NSAI Freedom Sundance Tier 1 / Tier 2 Assumed Gross area (acres) ~12,900 Well spacing (acres) ~ Offset (feet) Lateral length (feet) 7,500 7,220 / 6,433 7,500 Wells/pad Capex ($US millions) / LOE ($US/boe) / Lower EFS B 1P wells (bear case) P wells (base case) Well locations 115-> P EUR/well (kboe) P EUR/well (kboe) / Oil (%) NGL (%) Gas (%) GOR (scf/bbl) 5,500 3,550 NGL yield (bbl/mmscf) Gas shrinkage (%) 59 / 68 IP30 (bopd) / IP30 (boepd) 1, / 700 1,000 Upper EFS Well locations 115->84 84 EUR/well (kboe) Lower EFS A Well locations 92->84 84 EUR/well (kboe) Austin Chalk Well locations 115->84 84 EUR/well (kboe) Down spacing Well locations 322->252 ~252 EUR/well (kboe) Source: K1 Capital analysis of NSAI, Freedom Oil & Gas and Sundance Energy data. Freedom Oil & Gas Limited, 2017 Annual Report, p 21 and Investor Presentation, 26th November 2017, pp 11, 14, 16. Sundance Energy Australia Limited, Eagle Ford Acquisition and Equity Raising presentation, 14 th March 2018, p 35. Freedom expects up to 10% in capex reduction with a continuous drilling program due to longer-term service contracts. Freedom s current development plans are based on foot spacing, with laterals 7,500 ft in length, equivalent to ~110 acres per well (for each horizon). 1 acre = 43,560 sq. ft. K1 Capital assumed IP30 oil rate based on Freedom Oil & Gas Limited, Investor Presentation, 26th November 2017, p 11, Original TC case. IP30 rates for other horizons prorated based on EUR. Copyright 2018, K1 Capital Pty Ltd, ABN October

14 3.1.7 Production development plan Freedom s 26 th November 2017 presentation envisaged a phased development, commencing with the Lower EFS B horizon, followed by the Upper EFS, Lower EFS A and Austin Chalk, before potential down spacing of the Lower and Upper EFS horizons. Originally this contemplated ~115 wells per horizon, based on shorter laterals and closer spacing. We have assumed a similar plan, but with ramp up to 2 rigs and development of other horizons occurring six to twelve months later, and a maximum of 84 wells per horizon. Development times are slightly shorter, due to the lower well count for each stage. Table 3 Dimmit County project development plan (gross basis) Item Start End Rigs Wells (gross) Duration (years) Lower EFS B Phase 1 4Q Q Phase 2 1H H Phase 3 Aug 2018 Mar ~0.5 Phase 4 Jul H ~1.5 Upper EFS 1H H (was 115) ~2.0 Lower EFS A 1H H (was 92) ~2.0 Austin Chalk 2H H (was 115) ~3.5 Down spacing 2H (was 322) ~5.5 Total 4Q 2017 Mid (was 759) ~14 Source: K1 Capital analysis of company data. Assumes 7,500 ft lateral wells at ft spacing. Assumes 24 wells/year/rig, per Freedom Oil & Gas Limited, investor presentation, 27th November 2018, pp 15, days/well * 24 wells/year/rig => 80% utilization factor per rig. Maximum of 2 rigs for EFS development from 2020; 1 additional rig for Austin Chalk development. Figure 14: Production development plan (per Freedom, 27 th November 2018) Source: Freedom Oil & Gas Limited, investor presentation, 27 th November 2017, p 23. Assumes ~115 wells per horizon. Copyright 2018, K1 Capital Pty Ltd, ABN October

15 Table 4 Dimmitt County Project assumptions Item Comment Ref. Project type Permit / Location Liquids-rich Eagle Ford shale 9,766 net acre largely contiguous land position, Dimmit County, Texas. Lease expiry Three main leases, acquired year primary term, expiry from Jan Need to drill 1 well/6 months/lease to hold in perpetuity Status Production and development History Acquired Phase 1 drilling (2 wells) 3Q 2017, Phase 2 (4 wells) 1H 2018 Ownership Partner(s) - Fiscal regime 100% WI, % NRI % gross royalty. 4.6% oil/cond, 7.5% gas severance tax. 21% US federal tax Reserves/Resources 1P/2P/3P: 19.1/37.8/- MMboe net, 1 Jul 2018, NSAI Resources: estimated 227 MMboe net recoverable (EFS, Austin Chalk, down spacing) Geology Volatile oil and condensate window gives high production; 70-90% liquids 6,500 ft depth. Shale thickness of ~400 ft. with three potential intervals 350+ offset producing wells plus full cores confirm shale content and quality Drilling 6 wells drilled H Drill and complete 12 wells Aug 2018/Mar 2019: $US60-63m capex. Existing cash plus RBL facility to cover majority of capex. Well performance Phase 1: 2 wells, completed 3Q 2017, 7,500 ft laterals, IP boepd, ~70% liquids Phase 2: 4 wells, on prod n 28 June 2018, 7,500 ft laterals, 1,187 boepd, ~80% liquids 600 kboe/well EUR per NSAI 1 st Jul 2018 reserves. 52% oil, 24% NGL, 22% gas Reservoir drive Gas expansion. Can apply gas lift to enhance later life production Development concept Existing Infrastructure Capex 84 wells FFD Lower Eagle Ford B. ~3-4x if additional Lower Eagle Ford A, Upper Eagle Ford and Austin Chalk wells offset spacing. Phase 2 wells fractured at twice the intensity as Phase 1. Restricted flow back by smaller choke sizes to preserve reservoir pressure longer, increase EUR. 6 Acre drilling pad allows up to 12 wells Gas gathering and compression. Oil and gas transport pipelines 6,500 ft depth, 7,500 lateral, $US5.5m/well D+C ($1.3m DHC, $4.0 frac, $0.2m facilities). Phase 2 wells drilled in 12 days (average) vs Phase 1 at 16 days. Further 10% reduction possible due to continuous program. Abandonment ~$US50k/well after equipment salvage. Well life ~35 years. Production First oil 4Q kboepd Aug > 6+ kboepd Mid 2019 Wells on production 1-2 months after drilling (frac within days of rig release, drill out plugs 5-7 days later, commence flowback, first production days later). Project life Drilling for 10+ year. Production for 20+ years Quality / Market Sales / Revenue Oil: API, sweet. Direct access to Gulf Coast LLS market (Brent-linked) via Arrowhead Oil Pipeline System or trucking. NGL: 30-35% WTI Gas: Mark West gas gathering/compression on-site; Howard Energy gas pipeline 9 miles to major hub; ETC transportation/gas processing to sales in Houston market. No volume or ship or pay obligations. Opex LOE $US6-7/boe average. ~$US10k/well/mth; ~$US1.30/bbl oil, ~$US0.45/kscf gas Oil transport $US3-4/bbl via trucking, $US2-3/bbl via pipeline. Gas transport/ngl fractionation ~$US0.55/MMBtu. G&A $US0.6m/mth ($US7.2m/yr) (p 16, 6 Aug 2018) Next steps Commence drilling 12 additional wells Aug RBL facility 4Q Generic risks Specific risks Other Commodity prices, well performance Weather (hurricanes / tornados, but miles inland so less severe) Hunting season 1 st Nov to 1 st Feb restricts land access, can still drill on some leases Source: K1 Capital analysis of company and public domain information Copyright 2018, K1 Capital Pty Ltd, ABN October

16 4. Valuation 4.1 Methodology DCF analysis Our primary valuation approach is based on discounted cash flow analysis for projects where sufficient information exists and risk-adjusted enterprise value (EV) to resource metrics for exploration and early stage projects. Our investment model incorporates probability distributions for key variables (such as reserves, commodity prices and exploration outcomes) and uses Monte Carlo simulation to quantify the range of share price outcomes Risk adjusted exploration program We value exploration assets using an enterprise value to resource multiple derived from cash flow models of analogous projects and apply a risk factor to reflect the geological chance of success, commercial probability of development and project maturity. The size of the resource to which the multiple is applied is based on the portion of the prospective resources for the licence area that are expected to be drilled within a reasonable time frame (typically the next one to three years). Individual prospects identified on drilling plans are assigned a specific geological probability of success, in conjunction with a factor to account for the likelihood of commercial development. The risk factors applied to exploration targets are modelled as independent success or failure outcomes. We have not included any value for conventional oil and gas exploration, given there is no exploration planned in the short to medium term Peer comparison We compare companies to their peers using enterprise value to reserve and resource metrics. We compare resources based on an energy price equivalent basis, rather than simply an energy thermal equivalent basis, to better account for the value differences between oil and gas resources. Our energy price equivalence factors are listed below. Table 5 Reserve & resource price equivalence factors Source: K1 Capital analysis Copyright 2018, K1 Capital Pty Ltd, ABN October

17 4.2 General valuation assumptions Table 6 General valuation assumptions Item Comment Ref. Discount rate Base discount rate of 10% (nominal basis) plus a premium for each project to reflect country risk. Risk free rate (%) 3.1 US 10-year bond rate, per Bloomberg, 24 Sep 2018 Market risk premium (%) 6-8 Per Brierly & Myers Beta 1.4 Per Duff & Phelps market cap correlation D/(D+E) (%) 20 Estimated oil & gas company long term average Debt premium (basis pts) 500 Per credit spreads, assuming B/B- rating Size premium (%) - Not included Country risk Project risk factor Forex Crude oil prices Gas prices Carbon price Inflation G&A expenses Project delivery Operating performance Per Aswath Damodaran, New York University, based on bond premia and credit default spreads as proxies for country risk. Alternative methods include equity-based metrics, country or political risk indices, adjustment of credit-based metrics for political risk spreads and including the estimated cost of political risk insurance directly in the project cash flows. Risk premium for Australia & US = 0.0% We apply a risk factor to each project to reflect our assessment of the technical and commercial maturity of the project: 0-20% for exploration prospects, 20-60% for appraisal projects, 40-80% for development projects and % for production projects. Risk factors are progressively relaxed as milestones are achieved. Long run USD/AUD year average forward volatility based on historical analysis (-0.06, +0.09), per K1 Capital. We model oil prices by defining a base level guided by published forecasts and futures markets, and model uncertainty by applying a probability distribution derived from historical price volatility. We construct a valuation matrix for a range of currency and crude price pairs to quantify the sensitivity to variation. We use Brent crude oil as our primary marker. Our base case forecast assumes Brent averages $US73/bbl in 2018 and $US70/bbl (in real Dec-18 dollars) from We assume LLS trades at a 2% premium to Brent (based on historical performance). We model Henry Hub prices by defining a base case price level guided by published forecasts and futures market, and model uncertainty by applying a probability distribution derived from historical price volatility. We assume HH averages $US2.90/MMBtu in 2018, increasing to a long run of $US3.20/MMBtu (real Dec-18 dollars) from Not modelled. N.B. Shell has used a value of $US40/t in all base case economics since 2008; ExxonMobil has included a value of up to $US80/t in its business planning since Australia 2.2% 2018, 2.5% 2019, 2.5% 2020+, per PwC Global Economy Watch projections. USA 2.5% 2018, 2.2% 2019, Previous analysis by K1 Capital indicates production levels are a reasonable predictor of administration costs. We assume $7.2m/yr for 2018 and 2019 and rising to $8-9m/yr given extra resources associated with increased pace of field operations. Industry studies note cost and schedule overruns are common [13] [14] [15] [16]. We assume bear, base and bull case overruns of 20%, 0% and 0% respectively. S&P generally assumes base case availability for of 90% for refiners and 95% for LNG, with at least 5% reduction for downside cases [17] [18] [19]. McKinsey notes availability of <75% to 97%, with an average of 85% [20]. We assume bear, base and bull case utilizations of 90%, 95% and 100% of design stream day respectively, to reflect planned and unplanned downtime. We assume bear, base and bull case opex overruns of 20%, 0% and 0%. The impact of minor incidents is covered in our operating performance assumptions and discount rate. We assume no major or catastrophic operational incidents. Operational incidents Source: K1 Capital analysis of company and public domain information [6] [7] p8 [8] [9] [10] [11] [12] Copyright 2018, K1 Capital Pty Ltd, ABN October

18 4.3 Sensitivity Analysis The following sensitivity analysis assumes development of only the Lower EFS-B horizon. Development of other horizons would result in greater upside potential. Monte Carlo simulation Monte Carlo simulation calculates the distribution of possible share price outcomes given the uncertainty in the underlying assumptions. This gives a more realistic representation of likely outcomes than best or worst case scenarios, which have a low probability of occurrence. Our simulation analysis estimates a median value of A$0.39/share, effectively equal to our base case, with a P90 to P10 range of A$ /share. Tornado chart The Tornado chart shows the sensitivity of the valuation to changes in individual variables (i.e. one at a time), ranking the variables from highest to lowest impact. The level of reserves has the greatest impact on the Australian dollar share price, followed by oil prices and capital costs. Other factors have a relatively small effect. Bar labels show the test range for each input variable Break-even and implied Brent oil price (2018 real US dollar/bbl) Case Break-even oil price Implied oil price Share price of $0.20 as of 2 nd Oct 1P reserves P reserves Source: K1 Capital analysis. 10% nominal discount rate. Forex = 0.75 $US/$A. Henry Hub $US3.20/MMBtu. The break-even oil price is the constant real dollar oil price for the net asset value of the company to be zero, on a discounted cash flow basis, paying all capital, operating and G&A costs. The break-even price in any one year may differ. The implied oil price is the constant real oil price required for the net asset value of the company to equal the current share price. Copyright 2018, K1 Capital Pty Ltd, ABN October

19 4.4 Peer comparison Peer group We have examined a range of ASX oil and gas production companies with predominantly onshore production, as well as established ASX mid-scale oil and gas companies (Senex, Cooper, Beach) for comparison. Table 7 Resource multiple peer group Source: K1 Capital, company data. EV estimated from market capitalization and most recently published cash and debt values (30 th June 2018), plus capital raisings since the date of the most recently published cash/debt values. Table 8 Enterprise value to reserve & resource metrics for peer group (working interest basis) Source: K1 Capital analysis. Companies are sorted in decreasing order of Enterprise Value (EV). Australian companies report reserves on a working interest basis, while US-focused companies commonly (but not always) report reserves on a net revenue interest basis (i.e. after deducting royalty interest). Reserves above are shown on a working interest basis for common comparison. Reserves have been price adjusted to reflect the lower value of gas per unit energy relative to oil. Contingent resources are risked at 80% (in the EV/(2P+0.8*2C) metric). Not all companies report contingent resources (Freedom does not at this point in time). Copyright 2018, K1 Capital Pty Ltd, ABN October

20 Figure 15: Enterprise value metrics (price equivalent basis) Sorted in decreasing EV order Sorted in decreasing 2P order Source: K1 Capital analysis Peer analysis discussion Enterprise Value: Freedom is similar in size to other ASX-listed US producers such as Australis, Byron, and Elk, and approximately half that of Sundance Energy and two of the Australian domestic producers, Senex and Cooper. Reserves: Freedom s reserves are similar to Senex, Elk, Australis and Cooper on a 2P price adjusted basis. Although Freedom doesn t report contingent resources it has upside comparable to Australis and one of the largest resource bases of the ASX mid-scale oil and gas companies (we estimate the Lower EFS-A, Upper EFS, Austin Chalk and down spacing could add ~150 MMboe net to Freedom). EV/reserves: Freedom is cheaper on EV/1P and EV/2P reserves metrics than many of its peers, and broadly similar to others with elevated gearing levels (other than Horizon, which has a high EV/reserves metric despite relatively high gearing, due we believe to value being attributed to its contingent resources). We think Freedom s current market pricing reflects investor uncertainty regarding three main factors: Production growth: will the Lower EFS development drilling program de delivered as planned? Resource size: is the potential upside beyond current 2P levels likely to occur? Funding: can the program be delivered without further equity dilution and how much risk will the proposed RBL program introduce, should oil prices decline? We expect the risk discount associated with these factors will be progressively relaxed as sustained delivery is demonstrated. Copyright 2018, K1 Capital Pty Ltd, ABN October

21 5. Board and management Freedom s board and management have significant previous experience with major and independent oil and gas exploration and production companies. The necessary technical, commercial and operating capabilities appear to be well covered for the current and proposed development programs. The experience and qualifications of the individuals concerned are summarized below. Table 9 Board of Directors and Senior Management Board J. Michael Yeager BSc, MSc - Executive Chairman and CEO Mr. Yeager joined Freedom as Executive Chairman and CEO in October He has over 35 years of experience in the oil and gas business with Mobil Oil Corporation, where he was President, Mobil E&P; ExxonMobil, where he has VP of ExxonMobil Development Company, VP Africa and VP Europe ExxonMobil Producing Company; and BHP Billiton Petroleum, where he was CEO from Roger Brian Clarke BCom, CA - Vice Chairman and NED Mr. Clarke has over thirty years experience in funds management, banking and corporate finance. He is chairman of the advisory board of Morgans Financial Limited and has been involved in a significant number of initial public offerings, capital raisings and corporate transactions. Lee Anthony Clarke CFP - NED Mr. Clarke is the principal and director of a private financial advisory and wealth management firm. He has over twenty years of financial planning and wealth management experience advising families and private investors. Joseph Charles Camulgia BBus, Dip Fin Planning - NED Mr. Camuglia has over twenty-five years experience as a Chartered Accountant and Certified Financial Planner, with Price Waterhouse and then establishing his own practice in 1990, which became one of the largest Hillross Financial businesses in Australia. Nigel H Smith BSc - NED Mr. Smith has over 35 years of experience in the oil and gas industry in engineering, project management, drilling operations and acquisitions, with Shell, ARCO (Atlantic Richfield Company) and BHP Billiton Petroleum. Senior Management Mark Mabile BSc, MSc VP Operations Mr Mabile joined Freedom in November 2017 and has over 35 years experience in drilling, completion, workover, and production operations management. Prior to joining Freedom he spent 10 years at Southwestern Energy and prior to that, Fidelity Oil & Gas, Baker Hughes, and Conoco. Stephen Mullican BSc - VP Engineering Mr Mullican joined Freedom in September 2014 and has over 30 years of engineering management and business development experience, with Grenadier Energy Partners, where he was VP of Business Development and Engineering; several independent oil and gas companies and BP/Vastar/ARCO. Char Lombardo BA, Applied Science VP Business Services Ms Lombardo joined Freedom in January 2016 and has over 35 years experience in human resources, information technology, facilities operations, construction and real estate management in the oil & gas and manufacturing industries. Prior to joining Freedom, Ms. Lombardo spent 13 years at BHP Billiton, RWD Technologies and as a Global Account Executive to General Motors for Electronic Data Systems. Source: Freedom Oil & Gas Limited, company website, accessed 13 th September 2018 Copyright 2018, K1 Capital Pty Ltd, ABN October

22 6. SWOT analysis Table 10 SWOT analysis summary Strengths Large contiguous acreage position in prolific and proven Eagle Ford trend Adjacent to existing acreage with demonstrated production Predictable geology, repeatable drilling High initial production rates, demonstrating improvement with evolving well designs Light sweet crude, with good access to markets and linked to LLS marker (higher than WTI) Moderate depth, low drilling costs (~$US1.5m/well), with moderate completion costs (~$US4.0m/well). Good access to oilfield services (onshore Texas) Operations located in favourable oil & gas regulatory regime Operatorship, 100% working interest, high NRI Relatively high value product mix (52% oil, 24% NGL, 24% gas) Long term production growth possible from existing acreage, low resource risk Opportunities Add to reserves/resources through development of Upper Eagle Ford and Austin Chalk formations Further acreage acquisitions Continued improvement in well productivity Continued reduction in well capital intensity Continued improvement in lease operating expenses Weaknesses Need to drill continuously to meet lease requirements to hold acreage by production (1 well/6 months/major lease) High decline rates from prolific shale wells, requires continuous drilling to build and maintain overall production. High external capex requirement until reach threshold cash flow from operations to become self-funding ASX investors cautious with US-based E&P operations (once bitten, twice shy) Potential for occasional weather-related disruptions (tornados, hurricanes) Threats Global commodity prices Potential well performance variability across acreage Source: K1 Capital analysis Copyright 2018, K1 Capital Pty Ltd, ABN October

23 7. Near term funding Capital structure Freedom has approximately one billion ordinary shares on issue, with a further 88 million shares possible on exercise of existing options and warrants. Figure 16: Current equity capital Source: Freedom Oil & Gas Limited, investor presentation, 5 th August 2018, p Ramas Energy Capital Inc. facility Freedom has $US40m of debt in the form of mandatorily redeemable preferred shares (MRPS) with Ramas Capital, a Houston-based private equity firm, with a balance sheet liability value of $US15.3m. The debt was incurred in two tranches, on 19 th September 2017 and 3 rd April 2018, raising $US20m. The MRPS are redeemable for a total of $US40m, on the earlier of 18 March 2022 (4.5 years after the first issue), the date Freedom lists on a United States exchange, or the date of any fundamental change to the capitalization or ownership of the subsidiary. Freedom has guaranteed the redemption payment. Early redemption is permitted. If the MRPS are redeemed at their full term the effective return to Ramas Capital is 15.75% per annum, excluding the return from 63.3m warrants that were issued with the MRPS. The warrants are effectively options over Freedom shares, which were issued for nil consideration, have an exercise price of $0.001 and may only be exercised after the redemption of each tranche of the MRPS. The Warrants do not have an expiry date. The face value of the debt ($US20m), the discount between the sale price of the shares and their redemption value ($US20m) and the non-cash cost of the warrants are amortized over the life of the debt Wells Fargo reserves-based lending facility Freedom is currently finalizing the terms of a Reserves Based Lending (RBL) facility with Wells Fargo. The notional $US500m facility size is expected to have an initial borrowing base of $US20m, with $US15m being available for immediate funding, from 4Q The borrowing base will be redetermined on a six-monthly or more frequent basis dependent on production and reserves. The liability is secured against Freedom s oil and gas assets and will require up to 50% of production to be hedged. Expected terms are summarized in the accompanying figure. The terms of the Ramas Capital facility effectively constrain the maximum leverage ratio to less than 3.0 times until the Ramas facility matures in early Copyright 2018, K1 Capital Pty Ltd, ABN October

24 Figure 17: Reserves-based lending terms Source: Freedom Oil & Gas Limited, investor presentation, 5 th August 2018, p 15 Our estimate of the RBL borrowing base is shown below. This predominantly follows the level of proven developed reserves, which in turn is driven by the pace of drilling. Key assumptions underlying our estimates are a 100% risk weighting of Proven Developed reserves, 50% risk weighting of Proven Undeveloped reserves (with a maximum PUD/PD ratio of 2) and project life cover ratio of 1.6 times. We assume 1P reserves will increase to the current 2P level with additional drilling and higher attributed EUR per well as confidence in well performance builds. We also assume that reserve redeterminations occur twice each year, with increases in the borrowing base available in the halfyear period after the well additions (and hence reserves additions) occur. We estimate the available borrowing base peaks at ~$US190m around 1H However, the borrowing base profile is difficult to estimate accurately given the range of variables, including drilling rate, reserves additions, timing of reserves redeterminations, well deliverability and production decline rates, commodity prices and various RBL terms. We note this uncertainty and assume that sufficient capacity will exist within the RBL facility, but recognize that additional funding or adjustment to the rate of drilling may be required in practice. Figure 18: Estimated RBL capacity (net 2P base case scenario) Source: K1 Capital analysis. Increase in EUR/well towards the 2P level is assumed after NRI basis. Copyright 2018, K1 Capital Pty Ltd, ABN October

25 7.1.4 Near-term funding outlook External funding, primarily through the RBL facility, is required to execute Freedom s planned drilling program until end-2020, when the company becomes self-funding. Free cash flow builds quickly thereafter. Freedom has indicated that additional funding may be sought for future acquisitions, as required. Table 11 Near term cash balance (calendar year basis, nominal dollars) Source: K1 Capital analysis. Revenue assumes nominal Brent pricing of $US73/bbl in 2018, $US71/bbl in 2019 and $US73/bbl in 2020; and Henry Hub gas prices of $US2.90/MMBtu in 2018, $US3.05/MMBtu in 2019 and $US3.20/MMBtu in Copyright 2018, K1 Capital Pty Ltd, ABN October

26 8. Appendices 8.1 Commodity price assumptions Copyright 2018, K1 Capital Pty Ltd, ABN October

27 8.2 Well performance Table 12 Freedom drilling campaigns Item Phase 1 Phase 2 Phase 3 Full development Well pad Wilson Hovencamp Wilson all + others Number of wells planned 84 Lower EFS-B 84 Lower EFS-A 84 Upper EFS Well names Wilson-B1,B2 Hovencamp-1,2 Vega-1, 2, 3 JC Davis-1,2 tba Start drilling May 2017 Feb 2018 Aug 2018 Finish drilling Mar 2018 Mar 2019 Start production Nov 2017 Jun Q 2018 Depth (ft) 6,500 6,500 6,500 Lateral length (ft) 6,800 7,200-7,600 ~7,500 Drilling time (days/well) Spacing/frac. stage (ft) Fracture stages/well Clusters/stage 6 12 Clusters/well IP30 rate (kboepd) Liquids (%) Source: K1 Capital analysis of company data Figure 19: Dimmit County Lower EFS cumulative production curve Source: Freedom Oil & Gas Limited, investor presentation, 6 th August 2018, p 12 Longer term performance is expected to be improved by slower ramp up, with Freedom restricting flowback from the Phase 2 (Hovencamp) wells relative to the Phase 1 (Wilson) wells through smaller choke sizes. Well life is expected to be years, with two thirds of EUR recovered after 15 years (450 kboe after 15 years divided by 690 kboe EUR assumed by Freedom). Copyright 2018, K1 Capital Pty Ltd, ABN October

28 8.3 Discounted cash flow project analysis Lower EFS-B 1P and Lower EFS-B Probable are the only projects included in the base case for production and cash flow purposes. The other projects have been modelled to determine valuation sensitivity for specific resource scenarios. The Lower EFS-B Probable case includes the probable reserves attributed to the wells in the 1P scenario, and hence the EUR/well appears high. Lower EFS-B 2P is the aggregate of the 1P and Probable resources, modelled as a single project. The reported 2P EUR/well of 0.57 kboe differs from the 0.60 kboe derived from the 2P reserves assessment due to differences in the assumed gas energy equivalent value. (The reserves assessment assumes the standard 6 kscf/boe conversion factor; the actual gas heating value is ~5.63 kscf/boe, based on standard industry values of 1.03 MMBtu/kscf and 5.8 MMBtu/boe.) The LPG (i.e. NGL) % is lower than the 24% liquids reported due to conversion to a boe basis (1 bbl NGL = 0.71 boe, assuming a 50/50 propane/butane mix) Copyright 2018, K1 Capital Pty Ltd, ABN October