Near-Term Reserves Update

27 April 2016

Eland Oil & Gas PLC

 ("Eland" or the "Company")

Near-Term Reserves Update

Three-fold increase in recoverable reserves attributable to existing Opuama and Gbetiokun well inventory, adding gross 22.6 million barrels

Net 2P Present Value to Eland of US$ 186.8 million

Eland Oil & Gas PLC (AIM: ELA), an oil & gas production and development company operating in West Africa with an initial focus on Nigeria, today makes the following announcement.

Reserves Update

The Company is pleased to announce the results of a Reserves and Resources evaluation on Opuama-1, Opuama-3, Opuama-7 and Gbetiokun-1, all contained within OML 40, ("Op-1", "Op-3", "Op-7" and "Gb-1" respectively) provided by Netherland, Sewell & Associates Inc. ("NSAI") as at 31 March 2017 (collectively, the "NSAI Report" or the "Report").

Following the successful re-entry of Opuama-3 announced on 25 April 2016, Eland, through its joint-venture subsidiary Elcrest Exploration and Production Nigeria Ltd, together with NPDC, its co-venture on OML 40, intend next to initiate production by means of a side track on the Opuama-7 well in Q2 2017 followed by an Early Production System (EPS) on the Gbetiokun Field in the second half of 2017. This is the initial stage of a planned phased development of the Opuama and Gbetiokun fields. The remaining capex associated with Op-7 is $7m (Net: $3.15m) and the Gb-1 of $16m (Net: $7.2m). Eland's joint-venture subsidiary Elcrest Exploration and Production Nigeria Ltd holds 45% equity in the OML 40 license. Opuama fields total reserves previously reported in the NSAI 30 June 2015 CPR remain unchanged. However, the significant increase in oil recovery from the existing well inventory (Op-1, Op-3, Op-7 and Gb-1) are expected to lead to less infill wells being required to access the remaining reserves on OML 40 and therefore reducing future total Capex spend.

The oil reserves and future net revenue to Eland allocated to Op-1, Op-3 and Op-7 as of March 31, 2017 with a flat $55/bbl price deck and Eland cost parameters, are as follows:

Opuama-1, Opuama-3 and Opuama-7 wells

(1) Net Entitlement is based on treating Eland funding of the Starcrest Nigeria Energy Limited (Starcrest) share of Elcrest E&P Nigeria Limited (Elcrest) as a carried working interest, resulting in an Eland participating interest of 45.00 percent and considering no payout of the Starcrest loans resulting from the Opuama field redevelopment project.

(2) The economics above are point forward from 31 March 2017 and do not include any Elcrest tax losses or capital allowances to that date. The economics above assume five years of Pioneer Tax Status, up to 1 May 2019.

The oil reserves and future net revenue to Eland allocated to Op-1, Op-3, Op-7 and Gb-1 as of March 31, 2017 with a flat $55/bbl price deck, are as follows:

Opuama-1, Opuama-3, Opuama-7 and Gbetiokun-1 wells

(1) Net Entitlement is based on treating Eland funding of the Starcrest Nigeria Energy Limited (Starcrest) share of Elcrest E&P Nigeria Limited (Elcrest) as a carried working interest, resulting in an Eland participating interest of 45.00 percentand considering no payout of the Starcrest loans resulting from the Opuama Field redevelopment project and Gbetiokun EPS.

(2) The economics above are point forward from 31 March 2017 and do not include any Elcrest tax losses or capital allowances to that date. The economics above assume five years of Pioneer Tax Status, up to 1 May 2019.

(3) All production and cost assumptions used for the Gbetioken-1 EPS are the same as those used in the NSAI 31 March 2016 CPR, as announced by the Company on 27 April 2016.

George Maxwell, CEO of Eland, commented:

"The confirmation of an additional gross 22.6 million barrels from our existing well re-entry strategy is very exciting. The level of capex investment required to produce this incremental volume is less than a dollar fifty per barrel, contributing to the significant NPV of $186.8 million from the four wells.

This programme will put the Company in a very strong position to move forward with the Opuama infill drilling and the full development of the Gbetiokun and Ubima fields, creating greater value for all our stakeholders."

For further information:

Eland Oil & Gas PLC (+44 (0)1224 737300)

www.elandoilandgas.com

George Maxwell, CEO

Olivier Serra, CFO

Finlay Thomson, IR

Canaccord Genuity Limited (+44 (0)20 7 523 8000)

Henry Fitzgerald O'Connor

Panmure Gordon (UK) Limited (+44 (0)20 7 886 2500)

Adam James / Atholl Tweedie

Tom Salvesen

Camarco (+44 (0) 203 757 4980)

Billy Clegg / Georgia Edmonds

In accordance with the guidelines of the AIM Market of the London Stock Exchange, John Downey, a geologist and Eland's Chief Technical Officer, who has a BSc from Nottingham University, an MSc from Leeds University and has over 30 years of relevant experience in the upstream oil and gas industry and who is a member of the Society of Petroleum Engineers and meets the criteria of qualified person under the AIM guidance note for mining and oil and gas companies, has reviewed and approved the technical information contained in this announcement.

In compiling the Report, NSAI has used the definitions and guidelines as set forth in the 2007 Petroleum Resources Management System ('PRMS') approved by the Society of Petroleum Engineers (SPE)

SUMMARY OF OPUAMA-7 OIL RESERVES AS AT 31 MARCH 2017

Opuama is a producing oil field located in OML 40. It is a rollover structure developed between east-west trending down to the south listric faults. It was discovered in 1972 by well Opuama-1 and was appraised / developed by six further wells, two of which were dry, between 1975 and 1980.

Hydrocarbons were encountered in eight reservoirs between 7,200 and 8,800 feet - under-saturated oil in six reservoirs, including the D1000, D2000 and D5000, but saturated oil in the E2000 reservoir and gas in the E4000 reservoir.

Opuama was brought on stream in 1975, producing from five wells targeting three of the four main reservoirs (D2000, D5000 and E2000). Perforated intervals were small - typically 6 to 12 feet. Oil export was by pipeline to SPDC's Forcados terminal, a distance of about 65km.

Peak production of about 11,000 bopd was achieved in 1976. Cumulative production was about 44 MMstb when the field was shut-in by Shell in 2006, by which time gross production had declined to about 2,000 bpd from two wells (Opuama-1 and -3). Most of the production had come from the D5000 and E2000 reservoirs, with less than 4 MMstb produced from the D2000 and less than 3 MMstb from the D1000.

Opuama-7 was drilled in 1980. The D1000 reservoir was absent in the well (faulted-out) but it encountered oil in, and was completed in, the D2000 reservoir using an internal gravel pack (IGP). It was shut-in in 1990 due to very low rates of production due, it is believed, to failure of the IGP. Cumulative production from the well was only 2.4 MMstb.

The Opuama Field was brought back on stream in 2014, producing at about 3,000 bopd gross from two wells, Opuama-1 and -3. In November 2015 Eland re-entered and recompleted Opuama-1 in the D5000, increasing production from the well to about 3,000 bopd. In April 2016 Eland re-entered the Opuama-3 well and recompleted it in the D1000 and D2000 reservoirs, demonstrating that very high flowrates (about 10,000 bopd) can be obtained from these reservoirs.

The Opuama-7 well was originally scheduled to be sidetracked to produce the D2000 reservoir at the end of a 7 infill well drilling programme. However, the excellent production rates obtained from Opuama-3 following its recompletion in the D1000 and D2000 reservoirs made it logical to bring forward the re-entry and sidetracking of the Opuama-7 well.

Eland will re-enter Opuama-7, retrieve the production tubing, mill a window in the casing and drill a near-vertical sidetrack a short distance to the north east, to a location where seismic data indicate both the D1000 and D2000 reservoirs will be penetrated by the well. It will be completed in the D1000 and / or D2000 reservoirs. NSAI forecasts that the well will produce at an initial rate of between 5,170 (1P) and 8,919 (3P).

The price deck is adjusted for a regional price differential of -31 cents/bbl as Nigerian crudes typically trade at a premium to Brent.

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