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1 PowerPoint Template Title Subsurface: Near-term Potential Eland Oil and Gas Capital Markets Day

2 Subsurface: Near-term Potential ASSET LOCATIONS, GEOLOGICAL SETTING AND FIELD OVERVIEWS 2017 WORK PROGRAMME Opuama-7 sidetrack Gbetiokun-1 EPS Ubima-1 EPS SUBSEQUENT FIELD DEVELOPMENT Opuama infill drilling Gbetiokun full field development (FFD) Slide: 2 Capital Markets Day

3 OML 40 Located in the north western part of the Niger Delta 90 km north west of Warri; (swamp environment). Production licence with area of 498 km 2. Originally operated by SPDC (Shell), which drilled nine exploration wells between 1971 and All were drilled on 2D seismic and but one were vertical. Eight of the nine found oil. 371 km 2 of 3D seismic was acquired in (W) and 1995 (E). OML 40 was transferred to NPDC (55%, Operator) and Eland (Elcrest) (45%) in Benin City Contains one producing field (Opuama); one field being developed (Gbetiokun); five other discoveries and over twenty prospects and leads. Warri Onitsha Owerri Port Harcourt Calabar Slide: 3 Capital Markets Day

4 OML 40: Licence History Omuro Ojumole , CR 1 MMstb (on OML40) Polobo CR 19MMstb Opuama Field Disc Appr / Dev D seismic acquisition 1967 to 1988 Amukuba Ugbo , CR 1MMstb Abiala South 19MMstb North 26MMstboe Tongarafa , CR 1MMstb 2003 Tsekelewu Marginal Field Operatorship passed to Sahara Tsekelewu Gwatto Gwatto Adagbassa CR 4MMstb (SPDC) Appr 1973 and 1974 Up dip potential in 2D area Gbetiokun Field Disc Appr 1990/ Km Slide: 4 Capital Markets Day

5 Ubima Field Located in south east of the Niger Delta, north west of Port Harcourt (dry land). Ubima-1 discovery well drilled in D seismic was acquired in 1997 Ubima was awarded to Allgrace Energy (Operator) in December Area of license is ~ 65 km2 Eland farmed-in as equity and Technical and Financial Partner in July 2014, gaining a 40% interest Benin City Warri Onitsha Owerri Port Harcourt Calabar Slide: 5 Capital Markets Day

6 PowerPoint Template Title Geological Setting Eland Oil and Gas Capital Markets Day

7 OML40 Ubima Geological Setting Slide: 7 Capital Markets Day

8 Geological Setting Benin Formation. Sand-dominated interval of late Miocene to Recent age, deposited in predominantly fluvial environment. No direct hydrocarbon potential but provides burial necessary to mature the Akata source rocks. Agbada Formation. Interbedded sandstones and shales of Eocene to Miocene age deposited in shallow marine / shoreface to channelised fluvial environment at depths of 4,500 to 10,000 feet. Provides reservoir and seal. Major NW-SE trending channels of late Miocene age (15 Ma) cut down into the Agbada Formation. Akata Formation. Thick, shale-dominated, low net to gross interval but with occasional thick sands deposited in deeper water, slope and basin floor environment. Contains numerous organic rich source intervals. Often overpressured. Slide: 8 Capital Markets Day

9 Geological Setting After Reijers, 2011 and Weber, Section from Agbada Formation, Opuama Field Slide: 9 Capital Markets Day

10 Kx (md) Perm kh (md) Geological Setting Reservoir quality is good (porosity 20-25%; permeability mD) The predominant hydrocarbon phase is light, under-saturated, oil. Proportion of saturated oil and gas-condensate increases towards the base of the Agbada and into the Akata Formation Traps are generally structural - four way and three way dip closed structures developed along east-west trending, down to the south, listric faults. However, in some cases there is an element of stratigraphic trapping at shallower levels. Stacked accumulations normal COPHI, phi, (m3/m3) Strong aquifer support with edge-water drive in many reservoirs. High recovery factors. COPHI vs Kx vs. core number (Gbet-02 Core) PHIE FP vs. Perm (All cells) Abet2 phi-kh xplot Gbet2 Core Phi-Kh Gbet-02 Phi-kh General Discrete Core 1 D8.9 & D9.0 Core 2 E2.0 Core 3 Across Fault Slide: 10 Capital Markets Day

11 Trapping mechanisms Combined structural/stratigraphic Four way dip closed Three way dip closed (cross-fault seal on one fault) Two way dip closed (cross-fault seal on two faults) Potential for element of stratigraphic trapping where major shale-filled erosive channel cuts down into Agbada Formation 4 Reservoir correlation across major extensional faults is generally difficult / impossible Sandstone Oil Gas and condensate Slide: 11 Capital Markets Day

12 Opuama dip seismic section North Slide: 12 Capital Markets Day

13 Historical challenges / present day opportunities Slide: 13 Capital Markets Day

14 PowerPoint Template Title Opuama Field Eland Oil and Gas Capital Markets Day

15 Opuama Field - Summary Rollover structure developed between east-west trending down to the south listric faults. Area 3-6 km 2. Discovered in 1972 (Opuama-1) and appraised / developed by six further wells (two dry) between 1975 and 1980 Hydrocarbons encountered in 8 reservoirs between 7,200 and 8,800 feet. Under-saturated oil in most reservoirs, but saturated oil in the E2000 and gas in the E4000 Total STOIIP about 210 MMstb (range 175 to 240 MMstb) EUR (NSAI *) of 72.2 (1P) (2P) MMstb (3P), of which about 45 MMstb has been produced Gross reserves (NSAI*) of 27.2 (1P) 56.4 (2P) 73.3 MMstb (3P) * CPR of ; reserves adjusted for production to date. Slide: 15 Capital Markets Day

16 Opuama dip seismic section North Slide: 16 Capital Markets Day

17 Opuama Field: cross-section Slide: 17 Capital Markets Day

18 Opuama Characteristics of main reservoirs Indicative Production to Thickness (feet) Reservoir Fluid STOIIP API N:G Porosity date (MMstb) (MMstb) Gross Net Gross HC column (feet) D1000 Oil D2000 Oil D4000 Oil D5000 Oil E1000 Oil E2000 Oil and gas (125 oil / 260 gas) Slide: 18 Capital Markets Day STOIIP figures from evaluations by Shell, Eland and NSAI. Reservoir parameters are as calculated by Eland.

19 STOIIP (MMstb) Opuama: STOIIP, and potential STOIIP, by reservoir 70,000 60,000 Possible Hydrocarbons Hydrocarbons Proven in Wells 50,000 40,000 Shallow C reservoirs are untested over crest of structure ,000 20, , C1000 C2000 C3000 C4000 D1000 D2000 D3000 D3500 D4000 D5000 E1000 E2000 Reservoirs Slide: 19 Eland Company Presentation Template Indicative scenario; Company estimate

20 Opuama Field Original development (SPDC) Brought on stream in 1975, producing from five wells (three dual completion and two single completion, one with with IGP). These wells target the four main reservoirs (E2000, D5000, D2000 and D1000). Perforated intervals were small typically 6-12 feet. Oil export (wet) by pipeline to SPDC s Forcados terminal - about 65km. Peak production of about 11,000 bopd, from five wells, achieved in Cumulative production of 44 MMstb when shut-in in in Gross production when shut-in about 2,000 bpd from two wells (Opuama-1 and -3). Slide: 20 Capital Markets Day

21 PowerPoint Template Title Opuama-7 Re-entry and sidetrack Eland Oil and Gas Capital Markets Day

22 Opuama Field Summary Well drilled in 1980 and completed in D2000 using cased hole gravel pack. Gravel pack failed in 1990 after production of only 2.4 MMstb. Slide: 22 Capital Markets Day

23 Opuama-7 re-entry and sidetrack Programme Re-enter and pull tubing Mill window in 7 casing and sidetrack 110m to NE Complete in D1000 and / or D2000 (3½ by 2⅞ single selective or 4½ monobore) Cost $10 million. Opua-7 Sidetrack Forecast initial production rate About 6,000 bopd (Eland) NSAI, CPR forecasts 5,000 (1P) 5,915 (2P) 8,625 (3P) bopd Slide: 23 Capital Markets Day

24 Top D1000 depth structure map Slide: 24 Capital Markets Day

25 PowerPoint Template Title Gbetiokun-1 Early Production System Eland Oil and Gas Capital Markets Day

26 Gbetiokun Undeveloped oil field, discovered in 1987 (Gbetiokun-1) Appraised in 1991 by Gbetiokun-2, Bime-1 and Bime-2 3D seismic acquired 1995; reprocessed 1999 and 2008 GBETIOKUN Slide: 26 Capital Markets Day

27 Gbetiokun Un-faulted four way dip closure; area ~ 2.5 km 2 Light, under-saturated, oil in 20 reservoirs between 5,000 feet (D5.0) and 10,000 feet (E8.0) Total STOIIP ~ 175 MMstb (range MMstb)* 70% of STOIIP (~ 120 MMstb) in nine key reservoirs, including E2.0 and E6.0 Excellent poroperm * Eland estimates. Shell s estimates of STOIIP were between 150 and 218 MMstb. Slide: 27 Capital Markets Day

28 TWT (ms) S Gbetiokun Seismic dip line GBETIOKUN-01 GR / Synthetic N Base Canyon Unc. D5.0 D6.6 D6.9 D7.4 D8.01 D8.5 E3.0 Base Model Slide: 28 Capital Markets Day

29 TWT (ms) W Gbetiokun Seismic strike line GBETIOKUN-01 GR / Synthetic E Base Benin Base Canyon Unc. D5.0 D6.6 D6.9 D7.4 D8.01 D8.5 E3.0 Base Model Capital Markets Day

30 Reservoir correlation (D9.0, E2.0, E6.0) D9.0 D9.0 D9.0 D9.0 E2.0 E2.0 E2.0 E2.0 E6.0 E6.0 E6.0 Slide: 30 Capital Markets Day

31 Gbetiokun-1 EPS Core was acquired in Gbetiokun-2 and PVT samples from the E2.0 and E6.0 reservoirs in Gbetiokun-1, proving light, under-saturated oil in very high quality reservoirs Porosity from 31% (D5.0) to 19% (E2.0); permeability 300 to 2,000 md (E2.0), depending on facies E2.0 STOIIP about 36 MMstb; E6.0 about 16 MMstb * Gbetiokun-1 is located high on the Gbetiokun structure. The well is suspended. * Eland best technical estimate Slide: 31 Capital Markets Day

32 HCPT (deeper reservoirs; feet) Slide: 32 Capital Markets Day

33 Gbetiokun Example reservoir correlation (E2.0) E2.0 OWC Slide: 33 Capital Markets Day

34 Gbetiokun-1 EPS Eland will re-enter well, drill out cement, and run dual completion, producing E2.0 on short string (SS), E6.0 on long string (LS) Production using leased floating facilities, with initial export by ship Eland forecasts a Year 1 production rate of almost 9,400 bopd NSAI (CPR, ) forecasts initial 2P production rate of 7,795 bopd (1P - 5,560 bopd; 3P 11,175 bopd) with ultimate recovery of MMstb Slide: 34 Capital Markets Day

35 PowerPoint Template Title Ubima-1 Early Production System Eland Oil and Gas Capital Markets Day

36 Ubima Located in centre of delta, north of Port Harcourt. Dry land. Relatively low relief rollover structure developed against east-west trending, down to the south listric fault. Discovered by Shell (Ubima-1) in Hydrocarbons in six reservoirs between 4,800 and 9,000 feet. Appraised (largely unsuccessfully) by three wells drilled on 2D seismic in 1965, 1967 and (Essentially a single well discovery.) 3D seismic acquired in Awarded to All Grace in December Eland farmed-in (40%) as equity partner and Technical and Financial Partner in August Slide: 36 Capital Markets Day

37 Seismic dip section through Ubima-1 S UBIMA 01 N Hydrocarbons D Base D Base Thicker sands Hydrocarbons Hydrocarbons E1000 E4000 Base E6000 F1000 MFS Thinner sands Hydrocarbons Hydrocarbons F5000 MFS F7000 Base F6000 Slide: 37 Capital Markets Day

38 Ubima time slice at 1,900 ms Omerelu-1 Ubima-4 Ubima-2 Ubima-1 Ubima-3 Isu-1 Slice depth approximately = E2000 reservoir level Slide: 38 Capital Markets Day

39 Estimated STOIIP by reservoir interval * 300 Low Mid High D D D D D E1000 E2000 E4000 E6000 F6000 F7000 TOTAL Figures shown do not allow for uncertainty in depth structure D1000 high cases require seal on northern boundary fault (not proven) Slide: 39 Capital Markets Day * Company estimates. AGR TRACS figures are similar.

40 Ubima-1 EPS The Ubima-1 well is suspended. It found light oil in the relatively deep F7000 reservoir, oil in the intermediate depth E1000 and E2000 reservoirs and oil in the relatively shallow D1000 reservoirs. Major uncertainties: - STOIIP in D1000 reservoirs (ODT only - depth of OWCs not known). - Oil properties, especially the D1.0 reservoirs. Objectives: Appraise Ubima discovery (substantial upside, especially D1.0 reservoirs) Generate early cashflow (positive NPV). Slide: 40 Capital Markets Day

41 Ubima-1 EPS Eland will re-enter Ubima-1, drill out cement, and install dual completion, producing F7000 and E reservoirs on LS; D1000 reservoirs on SS. Production using minimum facilities, with export by truck. AGR-TRACS (April 2016 CPR) forecasts 2P initial rate of 2,500 bopd with ultimate recovery of 2.4 MMstb gross over 4 years. AGR-TRACS has contingent resources (2C) of 31.2 MMstb gross from full field development (four horizontal wells draining D1000 and E reservoirs). Development could act as regional hub. Exploration potential to east. SS Produce D1 reservoir (IGP) LS 2. Open sliding sleeve to produce E1/E2 (IGP) 1. Produce F7 reservoir before isolating with plug Slide: 41 Capital Markets Day

42 Opuama-1, -3, -7, Gbetiokun-1 EPS and Ubima-1 EPS (Eland best technical estimate) Gross Production Eland Net Entitlement (45% OML40, 88% Ubima) Slide: 42 Capital Markets Day

43 PowerPoint Template Title Opuama: Infill Drilling Eland Oil and Gas Capital Markets Day

44 Opuama: infill drilling Indicative Production to Net thickness Reservoir Fluid STOIIP Porosity date (MMstb) (feet) (MMstb) Gross HC column (feet) D1000 Oil D2000 Oil D4000 Oil D5000 Oil E1000 Oil E2000 Oil and gas (125 oil / 260 gas) Slide: 44 Capital Markets Day STOIIP figures from evaluations by Shell, Eland and NSAI. Reservoir parameters as calculated by Eland STOIIP (PSDM-D)

45 Next Opuama wells (Opuama-7 sidetrack, then Opuama-8 to -10) Slide: 45 Capital Markets Day

46 PowerPoint Template Title Gbetiokun Full Field Development Eland Oil and Gas Capital Markets Day

47 Gbetiokun Full Field Development Un-faulted four way dip closure; area ~ 2.5 km 2 Core taken in Gbetiokun-2 and PVT samples from E2000 and E6000 reservoirs in Gbetiokun-1 Light, under-saturated, oil in 20 reservoirs between 5,000 feet (D5.0) and 10,000 feet (E8.0) Total STOIIP ~ 175 MMstb (range MMstb) * 70% of STOIIP (~ 120 MMstb) in nine key reservoirs, including E2.0 and E6.0 * Excellent poroperm Slide: 47 Capital Markets Day * Company estimates

48 HCPT (deeper reservoirs; feet) Slide: 48 Capital Markets Day

49 HCPT (shallower reservoirs; feet) Slide: 49 Capital Markets Day

50 Gbetiokun Full Field Development Base Case static and dynamic models have been used to optimise the number, location and sequencing of wells required to develop the field Objectives: - Maximise production and recovery by draining the main reservoirs early in the sequence - Gather key appraisal information in advance of subsequent wells Production profiles (oil, water and gas) have been generated and indicative well trajectories and drilling schedule prepared. About twelve new wells (in addition to Gbetiokun-1) are potentially required to fully develop the field, maximising recovery The majority of the wells are dual completion, with additional reservoirs accessed via sliding sleeves as the reservoirs developed initially are depleted. The exceptions are wells I, J and K, which are assumed to be single completion, draining the D5.0 reservoir The twelve wells provide a total of 29 reservoir drainage points over the life of the field Slide: 50 Capital Markets Day

51 HCPT hotspots for deeper reservoirs (D9.0 to E7.0) Slide: 51 Capital Markets Day

52 HCPT hotspots for shallower reservoirs (D5.0 to D7.3) Slide: 52 Capital Markets Day

53 Indicative drilling sequence and completion intervals Reservoir Gbet-01 GBET-A GBET-B GBET-C GBET-D GBET-E GBET-F GBET-G GBET-H GBET-I GBET-J GBET-K GBET-L Completions SS LS SS LS SS LS SS LS SS LS SS LS SS LS SS LS SS LS D5.0 x x x x x x 6 D7.3 x 1 D8.1 D8.9 x (1) x (1) x (1) 3 D9.0 x (1) x (1) x(1) 3 D9.1 x (2) E1 x (2) 1 E2 x x x x x 5 E4 x x (3) 2 E5 x x x (2) 3 E6 x x (1) 2 E6.5 x (1) 1 E7 x x 2 SS Short String x Completion LS Long String x (1) Completion + Production Sequence Slide: 53 Capital Markets Day

54 Gbetiokun Full Field Development: Initial wells The first six new wells drain the D9.0 and deeper reservoirs and appraise the shallower D5.0 and D7.3 reservoirs, providing information on oil properties These six wells are forecast to produce at high rates and to provide high incremental reserves per well Total recovery from Gbetiokun-1 and the first six new wells is provisionally estimated by Eland to be about 65 MMstb by (This assumes gas lift is available for the E2.0 and shallower reservoirs. Without it, the recoverable volume from Gbetiokun-1 and the first six wells falls by 4 to 5 MMstb i.e., to about 60 MMstb.) Slide: 54 Capital Markets Day

55 The first six wells focus on the deeper reservoirs Slide: 55 Capital Markets Day

56 Gbetiokun Full Field Development: later wells The second six wells drain the D5.0 and D7.3 reservoirs. These reservoirs are significantly shallower than the D9.0 and E reservoirs and their oil properties are not known There is some evidence that the D5.0 and D7.3 accumulations may be compartmentalised, structurally and / or stratigraphically. The first six wells will provide information on D5.0 and D7.3 oil properties. However, they are not expected to markedly reduce uncertainty on D5.0 and D7.3 with respect to compartmentilisation, as the D9.0 and D5.0 structural culminations are offset from one another Slide: 56 Capital Markets Day

57 The second six wells focus on the shallower reservoirs Slide: 57 Capital Markets Day

58 Gbetiokun Full Field Development Total recovery from the second six wells is provisionally estimated to be about 14 MMstb * i.e., incremental recovery of 2 to 3 MMstb per well, significantly lower than for the first six wells. However, the D5.0 and D7.3 wells are still expected to have attractive economics Preliminary modelling indicates recovery from the second six wells is increased (i.e., above 14 MMstb) if wells I, J and K are complete as dual completion wells, producing the upper and lower D5.0 sands separately Oil production is forecast to peak at over 50,000 bopd and gas production at 25 MMscfpd * Facilities design and cost estimation work is being carried out by Genesis * Company estimates Slide: 58 Capital Markets Day

59 Gbetiokun Full Field Development Oil production by well * Oil and water production * Slide: 59 Capital Markets Day * Company forecast

60 PowerPoint Template Title Near-term Operations Eland Oil and Gas Capital Markets Day

61 Near-term operations Opuama-7 Q2-Q Gbetiokun-1 EPS Q Ubima-1 EPS Q Opuama infill drilling (3+ wells) 2018 Gbetiokun FFD (first six wells) Ubima FFD (4 wells) New 3D in OML E&A programme 2019 onwards Slide: 61 Capital Markets Day

62 Opuama-1, -3, and -7 to -11; Ubima-1 EPS and Gbetiokun FFD (Eland best estimate)

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