Serinus Energy PLC — Management Reports 2018

May 13, 2018

Serinus Energy plc

(formerly Serinus Energy Inc.)

Management's Discussion and Analysis For the three months ended March 31, 2018 (US Dollars)

This Management's Discussion and Analysis ("MD&A") for Serinus Energy plc ("Serinus", or the "Company") is a review of the results of operations and the liquidity and capital resources of Serinus Energy plc and its subsidiaries (collectively "Serinus" or the "Company"). The MD&A should be read in conjunction with the unaudited Condensed Consolidated Interim Financial Statements as at and for the three months ended March 31, 2018 and the December 31, 2017 audited Consolidated Financial Statements of Serinus and the accompanying notes. Readers should also read the "Forward-Looking Statements" legal advisory contained at the end of this document.

Management is responsible for preparing the MD&A, while the audit committee of the Company's Board of Directors ("the Board") reviews the MD&A and recommends its approval by the Board. This MD&A uses United States dollars ("US Dollars" or "USD") which is the reporting currency of the Company. The accompanying financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") also referred to as GAAP. This document is dated May 11, 2018.

In the Advisory section located at the end of this document, readers can find the definition of certain terms used in the disclosure regarding Oil and Gas Information, Non-IFRS Measures as well as information on "Critical Accounting Estimates". Additional information related to Serinus, including its most recently filed Annual Information Form, is available on SEDAR at www.sedar.com or on Serinus' website at www.serinusenergy.com.

Highlights

• Production in Q1 2018 was 380 boe/d compared to 690 boe/d in Q1 2017. The decrease of 45% from Q1 2017 was primarily due to the shut-in of the Chouech Es Saida field since February 28, 2017 and lower production from the Win-12bis well in Sabria, after being shut-in from May 22 until early September 2017, stemming from the social unrest in the southern part of the country. Oil weighting was 73% in Q1 2018 compared to 75% in Q1 2017.
• During Q1 2018, Brent prices averaged \$66.80 per bbl, as compared to \$53.68 per bbl in Q1 2017, an increase of 24%, reflecting the continued climb of oil prices since August 2017 when Brent averaged \$51.70 per bbl. The Company's realized oil price averaged \$66.00 per bbl in Q1 2018, compared to \$50.89 per bbl in Q1 2017, an increase of 30%. The Company realized 99% of the Brent price during Q1 2018 compared to 95% of the Brent price during Q1 2017.
• Capital expenditures of \$2.1 million were incurred for the three months ended March 31, 2018. The capital expenditures were primarily focused on the final phase of the construction of the Moftinu gas facility in Romania, with first production expected in late Q2, 2018.
• Funds from operations for the three months ended March 31, 2018 was \$2.5 million as compared to \$0.2 million for the three months ended March 31, 2017, an increase of \$2.3 million. The additional funds from operations in the current period in 2018 was primarily attributable to a \$2.6 million insurance recovery attributable to the well incident in December 2017. This increase was partially offset by \$0.4 million of transaction costs incurred during the quarter related to the Company's continuance to Jersey and AIM listing transaction.
• The well incident costs of \$4.0 million associated with the emergency operations in December 2017 on the Moftinu 1001 well were fully recognized in 2017. During the first quarter of 2018, the Company submitted its first interim insurance coverage claim related to the Moftinu 1001 well incident and recognized \$2.6 million of insurance proceeds as a recovery in the statement of operations in Q1, 2018. The Company received insurance proceeds of \$1.9 million in Q1 2018, with the remaining \$0.7 million reported as an insurance receivable on the balance sheet. Subsequent to March 31, 2018, the Company received the \$0.7 million related to its first interim insurance claim and a second interim claim is in progress. The well incident has resulted in delays to the construction of the gas facility, which is located on the wellsite of the Moftinu 1001 well. First production is expected to commence late Q2, 2018. The Company has also constructed the platform and access roads and has secured a drilling rig and well services for the immediate drilling of the replacement well, Moftinu 1007, located approximately 300 metres from the Moftinu 1001 well site. This well is expected to spud late May. The redrill portion will form the final part of the Company's insurance claim.
• On May 3, 2018, the Company continued to Jersey, Channel Islands. In connection with the Continuance, the Company changed its name from Serinus Energy Inc. to Serinus Energy plc and adopted new charter documents. The Company is proceeding with the process to list on the AIM market of the London Stock Exchange with completion planned for mid-May 2018.

Operational Overview

Serinus is an international oil and gas exploration and production company with operations in Tunisia and Romania. The Company has its management office in Calgary (Canada) and an investor relations office in Warsaw (Poland).

Included in the MD&A is an analysis of the above operations.

Tunisia

As at March 31, 2018, the Company has the following interests in the concessions in Tunisia:

Concession	Working interest	Expiry date
Chouech Es Saida	100%	December 2027
Ech Chouech	100%	June 2022
Sabria	45%	November 2028
Sanrhar	100%	December 2021
Zinnia	100%	December 2020

The Tunisian state oil and gas company, Enterprise Tunisienne d'Activites Petroliere ("ETAP"), has the right to back into the Chouech Es Saida concession for up to a 50% interest, if and when the cumulative crude oil sales, net of royalties and shrinkage, from the concession exceed 6.5 million barrels. As at March 31, 2018, cumulatively 5.2 million barrels, net of royalties and shrinkage have been sold from the concession. The Company began to generate revenues in Tunisia with its acquisition in September 2013, and since that time has generated \$113.5 million of revenue, net of royalties, in aggregate from these assets.

During the three months ended March 31, 2018, all production came from the Sabria field. The Chouech Es Saida field had been shut-in since February 28, 2017 originally due to strike notices issued by Tunisia General Trade Union ("UGTT"), which represented the Company's employees at the Chouech Es Saida field. The Sabria field was shut-in due to social unrest in the southern part of the country from May to September 2017. Production commenced late September 2017 following the end of the protests and having determined that production at its oilfields could be restarted in a safe and secure environment. For the Chouech Es Saida field, the Company is continuing to evaluate the restart of the field. As the Company's resources are currently dedicated to the completion of the Moftinu Gas Development Project, it is expected that the Chouech Es Saida field will not be brought onto production until the latter half of 2018.

Romania

Serinus, through its wholly owned subsidiary, Serinus Energy Romania S.A. (formerly Winstar Satu Mare S.A.), currently holds a deemed 100% interest in the Satu Mare concession.

Serinus is concentrating on the development of the Moftinu gas discovery, which includes building a gas processing facility. The Company entered into an EPCC contract with Confind S.R.L. on May 9, 2017 and the construction of the gas plant with 15 Mmcf/d of operational capacity is currently in its final phase. In an effort to replace production initially planned from the Moftinu 1001 well, the Company has expedited the drilling of the Moftinu 1007 well which is expected to spud late May. The platform and the access roads have been constructed and rig and drilling services are contracted. The Company is progressing the drilling program to meet work commitments required for the threeyear extension to October 28, 2019 on the concession agreement.

The Company is also proceeding to refine and expand the exploration inventory within the concession. Based on older vintage 2D seismic data and existing wells, management has identified over 25 leads and prospects. The exploration program may include acquiring more seismic.

The defaulted partner, who held a 40% interest in the Satu Mare concession declined to participate in future exploration or development phases under the concession and as such has not contributed their share of expenditures to the joint venture. The Company therefore issued a notice of default to the partner in December 2016 under the terms of the joint operating agreement ("JOA"). The partner did not have the necessary means or intention to remedy the situation and as such the partner is not entitled to participate in joint venture operations and has no right to transfer their interest to a third party. The partner is currently in a tax dispute with the government of Romania, the results of which is that the Romanian fiscal authorities have placed a protective seizure order on an account of the partner relating to their past activities on the Satu Mare concession. The primary goal of this seizure order is to prevent the unauthorized flight of capital by the partner out of Romania whilst the tax dispute is adjudicated. The seizure order also has the effect of preventing the transfer of the partner's 40% interest in the Satu Mare concession without the approval of the Romanian fiscal authorities. Serinus is not involved in any manner with this tax dispute and the dispute only relates to the partner. However, the dispute means that any transfer of the partner's interest to the Company necessarily involves conversations with the Romanian fiscal authorities. In August 2017, the Company provided the partner with a Notice of Deemed Transfer pursuant to the JOA. This Notice of Deemed Transfer states that Serinus has claimed this interest without any obligation to the partner going forward and that the partner must without delay, do any act required to render the transfer of the participating interest legally valid, including obtaining all governmental consents and approvals, and shall execute any document and take such other actions as may be necessary in order to affect a prompt and valid transfer of the interest in the Satu Mare Concession. Serinus fully expects the Partner to fulfil this obligation to transfer its interest in the Satu Mare Concession to Serinus in an expedited manner, subject to the approval of the Romanian Fiscal Authorities.

Under the terms of the JOA and pursuant to the notice of default and notice of deemed transfer, Serinus has commercially assumed 100% of the joint venture. The Company has notified the National Agency for Mineral Resources ("NAMR") of the default of the partner and has provided the requisite guarantees to NAMR for 100% of the project. The Company has also communicated the position to the fiscal authorities in Romania. The Company continues to pursue the Partner's adherence to its obligation to transfer the interest, and should this not be forthcoming, pursue any and all legal remedies that would formally see the rightful transfer of the defaulting 40% working interest to Serinus. The Company maintains its right to 100% of the obligations and benefits of commercial activities conducted within the Satu Mare concession.

Given the defaulted partners legal dispute with fiscal authorities in Romania, it is yet unclear whether the Partner has the ability to transfer its interest in the Satu Mare Concession to Serinus. There is a risk with respect to the timing of the transfer as it is dependent on the Partner in resolving its legal dispute with the fiscal authorities.

The Satu Mare concession is on the border with Hungary and Ukraine within the Pannonian Basin and the term of the concession agreement expires in September 2034.

Other

Serinus has interests in a minor property at Sturgeon Lake in Alberta, Canada. This asset is not currently producing and has a future abandonment liability associated with it of US\$1.1 million (CAD\$1.4 million). No abandonment work was undertaken during Q1 2018 (Q1 2017: \$nil).

Funds from operations

The Company uses funds from operations as a key performance indicator to measure the ability of the Company to generate cash from operations to fund future exploration and development activities.

The following table is a reconciliation of funds from operations to cash flow from operating activities:

Three months ended		Three months ended
For periods ended March 31, 2018 2017	2018	2017
Cashflows (used in) operating activities \$ (3,574) 2,366	(945)	(555)
Changes in non-cash working capital (2,398) (2,734)	3,450	721
Funds from operations \$ (5,972) (368)	2,505	166
Funds from operations per share \$ (0.04) -	\$ 0.02	0.00

Funds from operations for the three months ended March 31, 2018 was \$2.5 million as compared to \$0.2 million for the three months ended March 31, 2017, an increase of \$2.3 million. The additional funds from operations in 2018 was primarily attributable to \$2.6 million of insurance proceeds recognized related to the one-time well incident in December 2017, higher revenues net of production expenses from Tunisia, lower general and administrative ("G&A") costs in the current period, partially offset by higher transaction costs and current tax expense.

Net earnings (loss) and funds from operations

The Company uses funds from operations as a key performance indicator to measure the ability of the Company to generate cash from operations to fund future activities. The following table presents a reconciliation of funds from operations to cash flow from operations and segmented net loss:

	Romania				Tunisia Corporate				Total
For three months ended March 31,	2018	2017	2018	2017	2018	2017	2018	2017
Net earnings (loss)	2,798	(15)	182	(397)	(1,978)	(1,687)	1,002	(2,099)
Adjustments for:
Depletion and depreciation	1	1	414	774	40	38	455	813
Accretion expense	19	1	241	170	-	-	260	171
Share-based compensation	-	-	-	-	129	46	129	46
Unrealized gain (loss) on investments	-	-	-	-	-	17	-	17
Unrealized foreign exchange (gain) loss	(56)	-	35	(5)	(393)	103	(414)	98
Deferred income tax expense (recovery)	-	-	321	403	-	-	321	403
Interest expense	-	-	-	-	776	717	776	717
Decommissioning costs	(24)	-	-	-	-	-	(24)	-
Funds (used in) from operations	2,738	(13)	1,193	945	(1,426)	(766)	2,505	166
Changes in non-cash w orking capital	(2,902)	-	(819)	(453)	271	(268)	(3,450)	(721)
Cashflow s from (used in) operations	(164)	(13)	374	492	(1,155)	(1,034)	(945)	(555)

Production

Three months ended		Three months ended
For the periods ended March 31, 2018 2017	2018	2017
Production-crude oil (bbl/d) 287 842	276	519
Production-natural gas (mcf/d) 652 1,733	626	1,025
Production-total (boe/d) 396 1,131	380	690
% oil weighting 72% 74%	73%	75%
% gas weighting 28% 26%	27%	25%

During the three months ended March 31, 2018, production was from the Sabria field whereas production was from both the Sabria and Chouech Es Saida field during the three months ended March 31, 2017.

Production volumes decreased by 45% in the first quarter of 2018 to 380 boe/d compared to 690 boe/d in the first quarter of 2017. The decrease in production in Q1 2018 was attributable to the shut-in of the Chouech Es Saida field since February 28, 2017 and lower volumes from the WIN-12bis well in Sabria arising from the prolonged shutin of the Sabria field from May to September 2017. The production volumes at Chouech Es Saida in the prior period were additionally impacted by lower production due to the CS-3 and CS-1 wells which went down in the middle of December 2016 and remained off-line in the first quarter of 2017 pending pump replacement and workovers.

The Chouech Es Saida field has been shut-in since February 28, 2017 due to strike notices issued by Tunisia General Trade Union ("UGTT"), which represents the Company's employees at the Chouech Es Saida field. The shut-in was a result of a strike notice and illegal sit-in at the field in response to the Company terminating the employment of 14 of the 52 field employees for economic reasons, even though these terminations were within the right of the Company and strictly followed the appropriate laws, work code and regulations. The terminated employees accepted their termination notices and this sit-in ended early in Q2 2017, but due to social unrest in the south of Tunisia the field remained shut-in. The field was completely shut down during Q3 2017 and all remaining employees terminated. The Company is evaluating the restart of the Chouech Es Saida field in the latter part of 2018.

Production resumed in Sabria in early September 2017 after being shut-in since May 2017 due to social unrest. All wells have returned to pre-shut in production levels except for the Win-12bis well which initially decreased by 60% from pre-shut in levels. The Win-12bis well has a history of producing at high water cuts after being shut-in and has since continued to improve steadily through Q4, 2017 but has stabilized in Q1 2018 at a rate of approximately 160 boe/d, net. The Company performed a slickline operation subsequent to quarter end to investigate the Win-12bis well and will perform a well intervention to improve performance in Q3 2018. Production from Sabria in April 2018 averaged 338 boe/d, net.

Oil and gas revenue

For the periods ended March 31, Three months ended			Three months ended
\$ thousands, except % and per boe 2018	2017	2018	2017
Oil revenue (1) \$ 1,491	3,673 \$	1,638	2,404
Gas revenue 404	783	573	546
Total revenue \$ 1,895	4,456 \$	2,211	2,950
Oil revenue (%) 79%	82%	74%	81%
Gas revenue (%) 21%	18%	26%	19%
Oil (\$/bbl) \$ 56.43	47.40 \$	66.00	50.89
Gas (\$/mcf) 6.73	4.91	10.17	5.85
Average realized price (\$/boe) \$ 52.03	42.82 \$	64.63	46.98
(1) 2017 comparatives include "change in oil inventory"

Revenue is currently generated all from Tunisia. The Company is required to sell 20% of its annual crude oil production from the Sabria concession into the local market, which is sold at an approximate 10% discount to the price obtained on its other crude sales. The remaining crude oil production is sold to the international market, through which the Company has a marketing agreement with Shell International Trading and Shipping Company Limited ("Shell agreement").

For the three months ended March 31, 2018, Brent prices averaged \$66.80 per bbl as compared to \$53.68 per bbl in the comparable period of 2017, reflecting a 24% increase. The Company realized 99% of the Brent price during Q1 2018 and 95% in Q1 2017. The realized price of \$66.00 per bbl in Q1 2018 increased 30% from \$50.89 per bbl in 2017.

Natural gas prices are nationally regulated and were tied to the nine-month trailing average of low sulphur heating oil (benchmarked to Brent) prior to 2018. This has been changed to reference the current month average of high sulphur heating oil (benchmarked to Brent), which nets approximately 10% higher pricing. Gas revenues in the three months ended March 31, 2018 includes a \$78 thousand adjustment relating to November and December 2017 volumes on this price change. Excluding this one-time adjustment, the realized gas price would have been \$8.79 per mcf, 50% higher than the realized gas price in Q1 2017 of \$5.85 per mcf due to increased Brent price and the improved gas price calculation.

Oil and gas revenues totaled \$2.2 million for Q1 2018, compared to the oil and gas revenues and change in oil inventory total of \$3.0 million in Q1 2017. The decrease of 25% is reflective of the 45% decrease in production, offset by a 38% increase in pricing, as discussed above.

Prior to 2018, as the crude oil accumulates, the Company recorded commodity inventory at its net realizable value and the change in inventory was recorded in the income statement as "change in oil inventory". The cash that is received monthly from Shell was presented on the balance sheet as "advances for crude oil sales". Once the crude oil was physically lifted onto tankers and title passes, the inventory and advances were reversed and an accounts receivable was set up for the remaining amount due from Shell, and the change in oil inventory in the income statement was reclassified as revenue. Effective January 1, 2018, on adoption of IFRS 15, revenue is recognized once volumes are delivered for lifting at the loading terminal rather than the prior requirement to recognize upon lifting. Thus, the change in oil inventory is now recognized as petroleum and natural gas revenues. This change in revenue recognition under IFRS 15 has no impact on net earnings. On the statement of financial position, commodity inventory, net of advances is recorded as accounts receivable.

Royalties

For the periods ended March 31, Three months ended		Three months ended
(\$ thousands except for per boe) 2018 2017		2018	2017
Royalties \$ 196 735	\$	213	308
Royalties (\$/boe) \$ 5.38 7.06	\$	6.23	4.91
Royalties (% of revenue) 10.3% 16.5%		9.6%	10.4%

Tunisian royalties are based on individual concession agreements. In two concessions, Sabria and Zinnia, the royalty rate varies depending on a calculation of cumulative revenues, net of taxes, as compared to cumulative investment in the concession, known as the "R factor". As the R factor increases, so does the royalty percentage to a maximum rate of 15%. During 2018, the royalty rate in the Sabria concession was 10% for oil and 8% for gas. In the Chouech Es Saida concession, royalty rates are flat at 15%.

Royalties decreased by 31% to \$0.2 million in the three months ended March 31, 2018 from \$0.3 million in the three months ended March 31, 2017. The decrease was attributable to a 25% decrease in revenue and lower oil royalty rates due to production being only from the Sabria field in the current year. The effective royalty rate decreased from 10.4% in Q1 2017 to 9.6% in Q1 2018. The effective royalty rate in Q1 2018 was lower than Q1 2017 as over 10% of revenues in Q1 2017 were from the Chouech Es Saida field which has a higher royalty rate at 15%. In Q1 2018 royalties only included the Sabria field.

The increase in the per boe metric for the three months ended March 31, 2018 is attributable to higher commodity prices as compared to the three months ended March 31, 2017.

Production expenses

For the periods ended March 31, Three months ended	Three months ended
(\$ thousands except for per boe) 2018 2017		2018	2017
Production expense-Tunisia \$ 728 2,674	\$	728	1,720
Production expense-Canada 11 (65)		11	13
Production expense-Total 739 2,609		739	1,733
Production expense-Tunisia (\$/boe) \$ 21.25 25.70	\$	21.28	27.39

Production expenses for Q1 2018 decreased by 57% to \$0.7 million as compared to Q1 2017 of \$1.7 million. The decrease in 2018 was due to the shut-in of the Chouech Es Saida field in Tunisia, including the termination of the operating personnel in the field, resulting in lower operating costs and transportation charges, a decrease in Sabria production, and a decrease in Tunisian office costs.

Serinus Energy plc Q1 2018 Management's Discussion & Analysis (Thousands of US dollars, unless otherwise noted)

The production expense on a per boe basis in Q1 2018 decreased to \$21.28 per boe as compared to \$27.39 per boe in the comparable period of 2017. The decrease on a per boe basis of 22% was not a direct correlation with the 45% decline in production volumes due to the fixed nature of certain operating expenses.

Canadian production expenses relate to the Sturgeon Lake assets and totaled \$11 thousand for the three months ended March 31, 2018 (\$13 thousand for the three months ended March 31, 2017). The asset is not producing and is incurring minimal operating costs to maintain the property.

Operating netback

Serinus uses operating netback as a key performance indicator to assist management in understanding Serinus' profitability relative to current market conditions and as an analytical tool to benchmark changes in operational performance against prior periods. Operating netback consists of petroleum and natural gas revenues less direct costs consisting of royalties and production expenses. Netback is not a standard measure under IFRS and therefore may not be comparable to similar measures reported by other entities. See section titled "Non-IFRS Financial Measures" for advisory over the use of non-IFRS financial measures.

The following table shows the reconciliation of netback to its most closely related IFRS measure revenue:

	Three months ended			Three months ended
Operating netback by commodity				March 31, 2018					March 31, 2017
(\$ per boe except for volume)		Oil (bbl/d)		Gas (mcf/d)	Total (boe/d)		Oil (bbl/d)		Gas (mcf/d)		Total (boe/d)
Production volume		276		626	380		519		1,025		690
Realized price	\$	66.00	\$	10.17	\$ 64.63	\$	50.89	\$	5.85	\$	46.98
Royalties		(6.73)		(0.82)	(6.23)		(5.65)		(0.44)		(4.91)
Production expense		(21.72)		(3.35)	(21.28)		(29.49)		(3.50)		(27.39)
Operating netback	\$	37.55	\$	6.00	\$ 37.12	\$	15.75	\$	1.91	\$	14.68

Realized price per boe increased by 38% in Q1 2018 as compared to Q1 2017. Production volume was 45% lower between the two periods.

The operating netback of \$37.12 per boe in Q1 2018 was \$22.44 per boe higher than the netback of \$14.68 per boe in the comparative period of 2017. The increase in realized prices, combined with lower production expense per boe contributed to majority of the increase on a per boe basis.

General and administrative expense

For the periods ended March 31,	Three months ended
(\$ thousands except for per boe)		2018	2017
G&A expense	\$	698	774
G&A expense (\$/boe)	\$	20.40	12.33

General and administrative ("G&A") costs incurred by the Company are expensed, with certain costs directly related to exploration and development assets being capitalized or reported as production costs. The G&A costs reported are on a net basis, representing gross G&A costs incurred less recoveries.

General and administrative ("G&A") costs decreased by \$0.1 million, or 10%, from \$0.8 million in Q1 2017 to \$0.7 million in Q1 2018. The decrease is the direct result of lower personnel count in Q1 2018 compared to Q1 2017 in the Calgary and Warsaw offices.

On a per boe basis, the decrease in G&A expenses was negatively impacted by the decrease in production volumes year over year. For the first quarter of 2018, G&A expense per boe increased by 65% to \$20.40 per boe, as compared to \$12.33 per boe in Q1 2017, due to the 45% decrease in production volume, partially offset by the 10% decrease in G&A expenses.

Well incident recovery

On December 18, 2017, the Company suffered a well incident whereby during routine operations, to prepare the Moftinu 1001 well for future production, an unexpected gas release occurred and subsequently ignited. The well was subsequently brought back under control on January 6, 2018. Immediately following the capping operation, the Company performed a flow-kill operation and following a period of evaluation determined that the casing bowl assembly had been exposed to sufficient heat that its integrity was questionable. As such the Company has plugged and abandoned the Moftinu 1001 well. The costs associated with the above emergency operations have been provided in the year end 2017 financial statements in an amount of \$4.0 million. During the first quarter of 2018, the Company incurred a further \$0.1 million related to abandoning the Moftinu 1001 well and the remediation of the well site and access roads damaged as part of the emergency operations.

The Company submitted its first interim insurance claim in Q1 2018 and recognized proceeds of \$2.6 million in the quarter as a recovery in the statement of operations. The Company received cash proceeds of \$1.9 million in Q1 2018, with the remaining \$0.7 million as a receivable on the balance sheet. Subsequent to March 31, 2018, the Company received the \$0.7 million related to its first interim insurance claim and a second interim claim is in progress. The Company has also constructed the platform and access roads and has secured a drilling rig and well services for the immediate drilling of the replacement well, Moftinu 1007, located approximately 300 metres from the Moftinu 1001 well site. The well is expected to spud late May. The redrill will form the Company's final insurance claim. The European Bank for Reconstruction and Development ("EBRD") is the loss payee under the relevant insurance policy and has the right to allocate all insurance proceeds relating to the replacement well toward repaying the Company's indebtedness to the EBRD.

Transaction costs

Transaction costs of \$0.4 million in the three months ended March 31, 2018 relate to the continuance of the Company from Alberta, Canada to Jersey, Channel Islands and the plans to seek admission to be traded on the Alternative Investment Market ("AIM") of the London Stock Exchange. As the transaction were initiated in Q3 2017, there were no transaction costs in Q1 2017. The Company will have additional costs in Q2 2018 for the final phase of these projects.

Stock-based compensation

For the periods ended March 31, Three months ended		Three months ended
(\$ thousands except for per boe) 2018 2017	2018	2017
Stock-based compensation	\$ 129	\$ 46
Stock-based compensation expense (\$/boe)	\$ 3.77	\$ 0.73

Stock-based compensation was \$129 thousand in Q1 2018 compared to \$46 thousand in Q1 2017, an increase of 180%. The increase in the expense recognized in Q1 2018 as compared to Q1 2017 reflects the issuance of 6,680,000 options in the second quarter of 2017, bringing the balance of options at the end of June 2017 to double the 3,611,000 options at the end of December 2016. The Company expects the stock-based compensation expense in Q2 2018 to be consistent with the current quarter.

Depletion, depreciation and impairment

For the periods ended March 31, Three months ended	Three months ended
(\$ thousands except for per boe) 2018 2017		2018		2017
Depletion and depreciation-Tunisia \$ 455 \$ 1,343	\$	416	\$	774
Depletion and depreciation-Corporate 32 42		39		39
487 1,385		455		813
Depletion and depreciation-Tunisia (\$/boe) \$ 12.49 \$ 12.91	\$	12.13	\$	12.33

Depletion and depreciation expense is computed on a concession by concession basis considering the net book value of the concession, future development costs associated with the reserves as well as the proved and probable reserves of the concession.

In Q1 2018, Tunisia depletion and depreciation expense decreased by 46% to \$0.4 million from \$0.8 million in Q1 2017, correlating with the 45% lower production between the two periods. On a per boe basis, the depletion rate was \$12.13 per boe for the three months ended March 31, 2018, compared to \$12.33 per boe in the comparative period of 2017.

Interest and accretion expense

For the periods ended March 31, Three months ended		Three months ended
(\$ thousands except for per boe) 2018	2017	2018	2017
Interest expense \$ 718	703 \$	776	717
Accretion expense on ARO 171	195	260	171
\$ 889	898 \$	1,036	888

Interest expense for Q1 2018 increased by 9% compared to Q1 2017 of \$0.7 million. The average debt balance included in the interest expense calculation for Q1 2018 was \$30.5 million compared to \$30.0 million for Q1, 2017, thus interest expense was slightly higher in Q1 2018. This increase was also a result of increased interest rates on the loans.

Accretion represents the increase in the asset retirement obligation ("ARO") from the previous year end to reflect the passage of time. Accretion expense in 2018 was higher than 2017 as the ARO was increased at December 31, 2017 due to increased future inflation rates in Tunisia as well as an increased provision for the Romania gas facility.

Foreign exchange

Fluctuations in foreign currency exchange rates are an economic factor that affects the Company's cash flow required for operations and for investments. The financial statements are presented in US dollars, which is the reporting currency of the Company.

The foreign currency gain was \$0.3 million for the three months ended March 31, 2018 compared to a loss of \$0.1 million for the three months ended March 31, 2017, due to fluctuations in various currencies against the U.S. dollar.

The Company is exposed to risks arising from fluctuations in currency exchange rates between the Canadian dollar, Polish zloty, Romanian leu, Tunisian dinar, the Euro and the United States dollar. At March 31, 2018, the Company's primary currency exposure related to Canadian dollar ("CAD"), Romanian leu ("LEU"), and Tunisian dinar ("TND") balances. The following table summarizes the Company's foreign currency exchange risk for each of the currencies indicated:

As at March 31, 2018	CAD	LEU	TND
Cash and cash equivalents	\$ 369	1,982	777
Accounts receivable	117	8,553	3,793
Income tax receivable	-	3	1,911
Restricted cash	1,384	-	-
Prepaid expense	10	1,106	262
Accounts payable and accrued liabilities	(582)	(9,758)	(7,510)
Net foreign exchange exposure	\$ 1,298	1,886	(767)
Translation to USD	0.7756	0.2647	0.4128
USD equivalent at period end exchange rate	\$ 1,007	499	(317)

Based on the net foreign exchange exposure at the end of the period, if these currencies had strengthened or weakened by 10% compared to the U.S. dollar and all other variables were held constant, the after tax net earnings would have decreased or increased by approximately the following amounts:

	March 31,	December 31,
Impact on net earnings (loss)	2018	2017
Canadian dollar (CAD)	\$ 101	\$ 437
Romanian leu (LEU)	50	(72)
Tunisian dinar (TND)	(32)	(43)
Total	\$ 119	\$ 322

Capital expenditures

	For the three months ended
	March 31, 2018
		Tunisia	Romania	Corporate	Total
Property, plant and equipment	\$	12	2,052	84	2,148
Exploration and evaluation		-	-	-	-
Total exploration and development	\$	12	2,052	84	2,148
	For the three months ended
				March 31, 2017
		Tunisia	Romania	Corporate	Total
Property, plant and equipment	\$	313	-	-	313
Exploration and evaluation		-	545	-	545
Total exploration and development	\$	313	545	-	858

Serinus Energy plc Q1 2018 Management's Discussion & Analysis (Thousands of US dollars, unless otherwise noted)

In Romania, the Company incurred capital expenditures of \$2.1 million for the three months ended March 31, 2018.

The expenditures consisted of the construction of the Moftinu gas facilities in the period of \$1.6 million and costs associated with the Bucharest office of \$0.6 million.

Liquidity, debt and capital resources

For the periods ended March 31, Three months ended	Three months ended
2018 2017	2018	2017
Operating activities \$ (3,574) 2,366	\$ (945)	(555)
Financing activities (160) (13)	(190)	16,113
Investing activities (2,400) (588)	(3,041)	(613)
Effect of foreign currency translation on cash (65) (107)	394	(100)
Change in cash \$ (6,199) 1,658	\$ (3,782)	14,845

For the three months ended March 31, 2018, the net change in cash was an outflow of \$3.8 million, as compared to an inflow of \$14.8 million in the three months ended March 31, 2017.

Cashflow from operating activities during Q1 2018 was an outflow of \$0.9 million, as compared to an outflow of \$0.6 million in the comparative period. The increase in cash outflows was primarily attributable to the settlement of well incident costs, net of insurance proceeds received, during the quarter. In addition, cash flows from operating activities were also reduced by increased transaction costs associated with the continuance to Jersey and AIM listing. These were partially offset by improved cash flows generated from operations increasing to \$1.2 million during the first quarter of 2018 from \$0.9 million in Q1 2017.

Cash flow used in financing activities during Q1 2018 were \$0.2 million which consisted of cash interest payments. No principal repayments on long-term debt were paid in the current quarter in accordance with the amended terms under the restructured Senior Loan and Convertible Loan agreements. Cash flows from financing activities in the prior period were primarily driven by the equity offering in February 2017 of \$18.0 million, which was partially offset by a scheduled debt repayment of \$1.7 million and interest payments of \$0.2 million.

Cash flows from investing activities during the first quarter was primarily driven by capital expenditures of \$2.0 million in Romania associated with the Moftinu gas development project, compared to \$0.5 million incurred during the same period in 2017.

The near-term liquidity needs of the Company are dependent on the timely completion of the Moftinu gas plant and the successful execution of the drilling of the Moftinu 1007 well, to provide a further cash flow source for the Company.

The Company is planning to list on the AIM market of the London Stock Exchange, which it believes will increase its access to equity in the capital markets. In conjunction with this listing in mid May, the Company is targeting to raise £10 million of equity, which will provide the necessary funding to further develop the Romania asset.

Cash flow generation in Tunisia remains challenging given the current production level, though with stability of production and cost cutting measures, Tunisia was a positive cash flow generating business unit for the quarter.

At March 31, 2018, there are material uncertainties that may cast significant doubt with respect to the ability of the Company to continue as a going concern. The Company's ability to continue as a going concern is dependent on its ability to generate future cash flows from operations and/or obtain the necessary financing required to meet its ongoing production expenditures, corporate general and administrative, development program and discharge its liabilities as they come due. There is no assurance that financing, or cash generated by operations, will be available or sufficient to meet these requirements, or if debt or equity financing is available, that it will be on terms acceptable to the Company. The Company's cash generating ability was impacted by events in Tunisia and Romania. The situation in Tunisia, where social unrest resulted in the Company shutting-in production during 2017, reduced the Company's ability to generate cash flows from operating activities. The well incident in Romania in December 2017 resulted in the delay of first production and cash flows in Romania.

The need to generate cash flows from operations, or other sources of financing, to fund ongoing operations create material uncertainties that may cast significant doubt with respect to the ability of the Company to continue as a going concern.

The Company continues to actively consider alternatives to finance the Company and provide the necessary liquidity and capital. The Company monitors its liquidity position constantly to assess whether it has the funds necessary to meet ongoing cash requirements. The Company's debt is fully drawn and the period for drawdowns expired, therefore there is no access to further debt amounts under the EBRD loan agreements. Alternatives

Serinus Energy plc Q1 2018 Management's Discussion & Analysis (Thousands of US dollars, unless otherwise noted)

available to Serinus to manage liquidity include farm-out arrangements and securing new equity, as well as minimizing costs by cutting operating and administrative costs and deferring capital expenditures. There are no restrictions on the use of the Company's capital resources that could materially affect, directly or indirectly, its operations or activities.

To ensure security and the preservation of capital, the Company's investment policy for cash that is surplus to immediate requirements is to invest such funds in instruments issued by major chartered banks that are rated "triple A", or its equivalent by independent rating agencies.

Working capital

Serinus uses working capital as a key performance indicator to measure the Company's current assets less current liabilities to assist management in understanding Serinus' liquidity relative to current market conditions and as an analytical tool to benchmark changes against prior periods. Working capital is not a standard measure under IFRS and therefore may not be comparable to similar measures reported by other entities. See section titled "Non-IFRS Financial Measures" for advisory over the use of non-IFRS financial measures. The following table shows the reconciliation of working capital to its most closely related IFRS measure current assets and liabilities:

	March 31,	December 31,
Working capital as at:	2018	2017
Current assets	\$ 13,522	15,393
Current liabilities	(22,151)	(21,960)
Working capital (deficit)	\$ (8,629) \$	(6,567)

At March 31, 2018, the working capital deficit was \$8.6 million, as compared to \$6.6 million at December 31, 2017. At March 31, 2018, current liabilities of \$22.2 million increased by \$0.2 million compared to \$22.0 million at December 31, 2017. The increase in current liabilities was the result of \$2.7 million of debt being classified as current at March 31, 2018, as is due to be repaid March 31, 2019. This was partially offset by the settlement of the well incident payables from December 31, 2017. Current assets decreased by \$1.9 million from December 31, 2017 as the result of the use of cash of \$3.8 million in the three months ended March 31, 2018, partially offset by an increase in accounts receivable for crude oil sales of \$0.5 million, increase in commodity tax receivable of \$0.8 million and an insurance receivable of \$0.7 million.

Included in accounts payable was \$8.3 million relating to Brunei at March 31, 2018 and December 31, 2017. Of this amount, \$2.3 million relates to a dispute with a drilling company dating back to 2013 on Block L. The remaining \$6.0 million relates to work commitments on the Brunei Block M production sharing agreement which expired August 2012.

EBRD-Tunisia Loan Facility

The Senior Loan interest is payable semi-annually at a variable rate equal to LIBOR plus 6%. At the Company's option, the interest rate may be fixed at the sum of 6% and the forward rate available to EBRD on the interest rate swap market.

As at March 31, 2018, the principal outstanding under the Senior Loan was \$5.4 million (December 31, 2017 - \$5.4 million). No principal repayment is due until 2019, with the remaining principal to be repaid in two equal amounts of \$2.7 million each on March 31, 2019 and December 31, 2019.

The cash sweep is calculated semi-annually at the corporate level at December 31 and June 30 of each year as long as balances remain outstanding on the Senior Loan. Any cash balance in excess of \$7 million is to be used to prepay the senior loan in inverse order of maturity until the outstanding loan balance is no greater than what it would have been under the original amortization schedule. No pre-payment fees are applicable to the accelerated payments described above.

The Convertible Loan in the amount of \$20 million has a maturity of June 2023, with accrued interest accumulation until June 2020. In June 2020, the total outstanding principal plus accumulated accrued interest will be determined and this amount will constitute the new balance to be equally amortized over the four annual payments to be made each month of June for the years 2020 to 2023. The Convertible loan bears interest at a variable rate that is the LIBOR and a percentage calculated on the basis of incremental net revenues earned, with a floor of 8% per annum and a ceiling of 17% per annum. This margin is based on net revenues of the Tunisian assets and Romanian assets. Serinus can elect, subject to certain conditions, to convert all or any portion of the Convertible Loan principal and accrued interest outstanding for newly issued shares of the Company at the then current market price of the shares on the TSX or WSE, as required by the exchange rules. The EBRD can also at any time, and on multiple occasions elect to convert all or any portion of the Convertible Loan principal and accrued interest outstanding for newly issued shares of the Company at the then current market price of the shares on the TSX or WSE. Conversion of the debt is restricted to 5% of the market capitalization of the Company following conversion.

The conversion feature of the loan is based on market price, which would result in the issuance of a variable number of shares of the Company, and as a result, no value was allocated to the conversion option. The Convertible Loan was recorded as debt and classified as financial liabilities at amortized costs.

The Company can also repay the Convertible Loan at maturity in cash or in-kind, subject to certain conditions, by issuing new common shares valued at the then current market price of the shares on the TSX or WSE. The repayment amount is subject to a discount of approximately 10% if the requirement for substantially all of the Company's assets and operations to be located and carried out in the EBRD countries of operations is not met at the date of repayment.

The loans were available to be drawn for a period of three years, such period has now expired.

The loans are secured by the Tunisian assets, pledges of certain bank accounts, shares of the Company's subsidiaries through which the concessions are owned, benefits arising from the Company's interests in insurance policies, and on-lending arrangements within the Serinus group of companies. In addition, there is an additional security pledge of the shares of Serinus Energy Romania S.A., the holder of the Romanian assets.

Under the terms of the loan agreements EBRD has the right on change of control of the Company to demand repayment of the debt. Given the upcoming AIM listing and proposed equity raise, EBRD has waived its right to require prepayment as long as Kulczyk Investments S.A. shareholding does not drop below 30% and there is no single investor who will hold more than 24.99% of the Company's share capital.

The Senior Loan agreement contains a prepayment clause whereby EBRD has the option to request prepayment in the event that the reserves coverage ratio for Tunisian reserves is less than 1.5, in an amount to bring the ratio back on side. With respect to December 31, 2017 reserves, EBRD has waived its right to require prepayment.

The restructured agreements provide relief from financial covenants until September 2018. The debt service coverage ratio at the consolidated level is applicable to the Senior Loan, must be a minimum of 1.3 and is effective from December 2018. The debt to EBITDA ratio must be a maximum of 10.0 times at September 2018 and December 2018 and then to 2.5 times thereafter.

Covenants	Senior Loan	Convertible loan
Corporate level-DSCR	1.3x	n/a
Corporate level-Debt-EBITDA	Max 10.0x Sept & Dec	Max 10.0x Sept & Dec
	2018; max 2.5x 2019+	2018; max 2.5x 2019+

Covenants

Both loan agreements as part of the EBRD-Tunisia Loan Facility contain a number of affirmative covenants, including maintaining the specified security, environmental and social compliance, and maintenance of specified financial ratios. The covenants use non-GAAP financial measures which are not standard measures under IFRS and may not be comparable to similar measures reported by other entities.

The covenants, as noted above, are as follows:

• The financial debt to EBITDA ratio must be a maximum of 10.0 times at September 2018 and December 2018 and then to 2.5 times thereafter. The debt to EBITDA ratio is applicable to both the Senior Loan and the Convertible Loan.
• The debt service coverage ratio, which is effective as at December 31, 2018, is set at a minimum of 1.3 times and is only applicable to the Senior Loan.

The definitions of the covenants remained the same on the restructured loan agreement and are as follows:

• Financial debt is defined as the principal amount of the loan and other borrowings and obligations identified in the Loan Agreements.
• EBITDA is calculated based on the terms and definitions as set out in the Loan Agreement, which adjusts earnings for interest expense, income tax, and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, impairment losses or provisions, unrealized gains and losses from foreign exchange, and share-based compensation) and is calculated based on a trailing twelve-month basis.

• The debt service coverage ratio is calculated as the ratio of (i) cash flows arising from operating activities for the trailing twelve months as per the statement of cash flows, minus the sum of those cashflows used for acquiring long-term assets or other capital expenditures, excluding those capital expenditures funded by equity, referred by Serinus as "adjusted cashflows, to (ii) the sum of scheduled principal repayments and interest payments on the financial debt on a trailing twelve-month basis.

At March 31, 2018, the Company was not subject to any financial covenants.

Share Data

The Company is authorized to issue an unlimited number of common shares, of which 150,652,138 common shares and 67,000 options, with a USD exercise price, and 9,105,000 options, with a Canadian Dollar ("CAD") exercise price, to purchase common shares, were outstanding as at March 31, 2018.

shares	Amount
78,629,941	\$ 344,479
72,000,000	19,105
22,197	7
	(1,057)
150,652,138	\$ 362,534
	Number of common

The Company is also authorized to issue an unlimited number of preferred shares. No preferred shares are issued or outstanding.

The change in common shares in 2017 is as a result of an equity offering, whereby the Company issued 72,000,000 common shares resulting in 150,629,941 common shares outstanding as at February 24, 2017. During Q2 2017, a further 22,197 common shares were issued to Mr. Jeffrey Auld, the President and Chief Executive Officer of the Company, as part of his compensation, resulting in 150,652,138 shares outstanding.

The Company has the following options outstanding:

		USD denominated options		CAD denominated options
		Weighted average
	Number of	exercise price	Number of	WA exercise
	options	(USD)	options	price (CAD)
Balance, December 31, 2017	67,000	\$ 3.68	9,933,000	\$ 0.36
Expired and cancelled	-	-	(3,000)	3.22
Forfeited	-	-	(825,000)	0.37
Balance, March 31, 2018	67,000	\$ 3.68	9,105,000	\$ 0.36

The following tables summarize information about the USD and CAD options outstanding as at March 31, 2018:

	USD denominated options				CAD denominated options
			Weighted				Weighted
			average				average
Exercise price	Options	Options	contractual life	Exercise price	Options	Options	contractual life
(USD)	outstanding	exercisable	(years)	(CAD)	outstanding	exercisable	(years)
\$3.01 - \$4.00	32,000	32,000	0.5	\$0.30 - \$1.00	9,055,000	1,166,667	4.7
\$4.01 - \$5.00	35,000	35,000	0.6	\$1.01 - \$2.50	50,000	50,000	1.6
	67,000	67,000	0.6		9,105,000	1,216,667	4.7

At the date of issuing this report, the following are the options outstanding and changes to directors, executives and officers shares owned since March 31, 2018, up to the date of this report:

Serinus Energy plc Q1 2018 Management's Discussion & Analysis

(Thousands of US dollars, unless otherwise noted)

	Changes to Ownership
Name of Director/Executive Officer/	Options held as	Shares held at	Change in share	Shares held at
Key Person	at May 11, 2018	March 31, 2018	ownership	May 11, 2018
Evgenij Iorich (a)	100,000	3,415	-	3,415
Jeffrey Auld	4,500,000	22,197	-	22,197
Lukasz Redziniak	-	-	-	-
Dominik Libicki	-	-	-	-
Eleanor Barker	100,000	-	-	-
Tracy Heck	2,750,000	-	-	-
Calvin Brackman	750,000	-	-	-
Jim Causgrove	100,000	-	-	-
Dawid Jakubowicz	-	-	-	-
	8,300,000	25,612	-	25,612

(a) Mr. Iorich holds a position with Pala Investments, which is related to Pala Assets Holdings Limited ("Pala"). Pala owned 11,266,084 Shares as at March 31, 2018. By virtue of his position with Pala Investments, Mr. Iorich is deemed to have direction over such Shares in addition to those Shares that are shown above.

As at the date of issuing this report, management is aware of three shareholders holding more than 5% of the common shares of the Company. KI owns 52.17%, Pala owns 7.48%, and Quercus Towarzystwo Funduszy Investycyjych SA owns 5.25% of the common shares issued.

Commitments

Contractual obligations as at March 31, 2018 are as follows:

	Within 1 Year			2-3 Years		4-5 Years Beyond 5 Years
Operating leases	\$	650	\$	889	\$	4	\$	-	\$	Total 1,543
Gas plant-Romania (1)		1,159		-		-		-		1,159
Long-term debt (2)		2,700		9,444		13,487		6,743		32,374
Total	\$	4,509	\$	10,333	\$	13,491	\$	6,743	\$	35,076

(1) Contractual obligation on the construction of the gas processing facility.

(2) Long-term debt obligations presented exclude deferred financing costs and include accrued interest.

The Company's commitments are all in the ordinary course of business and include the work commitments for Tunisia and Romania.

Tunisia

The Tunisian state oil and gas company, ETAP, has the right to back into up to a 50% working interest in the Chouech Es Saida concession if, and when, the cumulative crude oil sales, net of royalties and shrinkage, from the concession exceeds 6.5 million barrels. As at March 31, 2018, cumulative liquid hydrocarbon sales net of royalties and shrinkage was 5.2 million barrels.

Romania

The work obligations pursuant to the Phase 3 extension, approved on October 28, 2016, include the drilling of two wells, and, at the Company's option, either the acquisition of 120 km2 of new 3D seismic data or to drill a third well. The two firm wells must be drilled to minimum depths of 1,000 and 1,600 metres respectively, and if so elected, the third well to a depth of 2,000 metres. The term of the Phase 3 extension is for three years, expiring on October 28, 2019. On May 5, 2017, the Company signed a letter of guarantee for up to \$12 million to cover the necessary expenses for the fulfillment of the minimal commitments for the Phase 3 extension. This guarantee was made net of any amounts already spent by the Company since the time of the extension's approval.

The Company signed an engineering, procurement, construction and commissioning contract ("EPCC") with Confind S.R.L., a Romanian company, for the construction of a gas processing facility and associated flowlines and pipelines on the Satu Mare concession. As at March 31, 2018, a balance of \$1.1 million is remaining on this contract.

Office Space

The Company has a lease agreement for office space in Calgary, Canada which expires on November 30, 2020 and an office lease agreement in Bucharest, Romania, which expires on August 27, 2020. Operating leases on office buildings are in the ordinary course of business. The Company has the option to renew or extend the leases on its office buildings with new lease terms to be based on current market prices.

Off Balance Sheet Arrangements

The Tunisian state oil and gas company, ETAP, has the right to back into up to a 50% working interest in the Chouech Es Saida concession.

2018 Outlook

The Company is focusing on Romania as the impetus for growth over the next several years. The Moftinu gas development project is a near-term project that is expected to begin producing from the gas discovery well Moftinu-1000 and the Moftinu 1007 well which is scheduled for to be drilled, completed and ready for production by late Q2 2018. Construction of the gas processing facility with 15 Mmcf/d of operational capacity is in its final phase with expected first gas production late Q2 2018.

The Company is also progressing the drilling program to meet work commitments for the extension to October 2019 and plans to drill two additional development wells, Moftinu-1003 and Moftinu-1004 during the latter half of 2018. The EBRD is the loss payee under the relevant insurance policy and if it insists on allocating all insurance proceeds relating to the replacement well, Moftinu-1007, toward repaying the Company's indebtedness to the EBRD, the Company will delay the drilling of the Moftinu 1004 well until early 2019. Combined with the production of the Moftinu 1000 and Moftinu 1007 wells, the Corporation expects the gas plant to be operating at full capacity by early 2019.

In Tunisia, the Company is currently focusing on improving production from Sabria following the shut-in and plans to focus on carrying out low cost incremental work programs to increase production from existing wells, including the Sabria N-2 re-entry and installing artificial lift on another Sabria well, having determined that production at its oil field can be restarted in a safe and secure environment with sufficient comfort that there will be no further production disruptions for the foreseeable future. The Corporation views Sabria as a large development opportunity longer term.

For the Chouech Es Saida field, the Company is evaluating the restart of the field including timing and costs to replace the electric submersible pump for the CS-3 well. The Company views the level of activity pursued in Tunisia as dependent on the following thresholds being achieved and maintained. In terms of oil prices, incremental vertical wells become economic at Brent oil prices of ~\$45 per bbl, with potential multi-leg horizontal wells lowering the threshold to below \$30 per bbl in Sabria. The current capacity of surface facilities would only allow for 1 to 3 incremental wells for each of Sabria and Chouech Es Saida/Ech Chouech. As well for Chouech Es Saida/Ech Chouech, the STEG El Borma gas plant is nearly at its effective capacity. Further gas developments from this concession may have to be delayed until the completion of the Nawara Pipeline for material gas pipeline capacity to come online.

Summary of Quarterly Results

Certain crude oil and natural gas liquids volumes have been converted to mcf or mmcf on the basis of one bbl to six mcf. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Any figure presented in mcf.

	Q1 2018	Q4 2017		Q3 2017		Q2 2017		Q1 2017		Q4 2016		Q3 2016		Q2 2016
Oil and gas revenues & change in	2,211			382		1,342		2,950		4,456		3,632		4,080
oil inventory, net of royalties (a)		1,895
Net earnings (loss) attributed to:
Common shares	1,002	(9,681)		(7,043)		31				(2,099) (14,419)		(4,971)		(3,994)
Earning (loss) per share:	########
-basic and diluted	\$ 0.01	\$ (0.06) \$		(0.05) \$		-	\$	(0.02) \$		(0.19) \$		(0.06) \$		(0.05)

(a) Amounts have been restated as a result of the reclassification of Ukrainian operations to discontinued operations, see note 20 to the December 31, 2017 Audited Consolidated Financial Statements.

• In Q2 2016, total income was impacted by low commodity prices in Tunisia.

• In Q3 2016, total income was impacted by low commodity prices in Tunisia and an increase in G&A due to one-time senior executives' termination payments incurred in the quarter.
• In Q4 2016, total income was impacted by recovering commodity prices in Tunisia and decreased corporate G&A, offset by a decrease in production. In addition, total income was negatively impacted by an impairment charge of \$16.8 million for Tunisia.
• In Q1 2017, total income was impacted by a decrease in production due to the shut-in of the Chouech Es Saida field, offset by recovering commodity prices, decreased production expenses and corporate G&A.

• In Q2 2017, total income was negatively impacted by the shut-in in Tunisia, with Chouech Es Saida being shut-in for the full quarter and Sabria being shut-in from May 22, 2017. In addition, Q2 2017, was impacted by a gain on of \$2.2 million resulting from the sale of the subsidiary holding the Syrian asset.

• In Q3 2017, oil and gas revenues were negatively impacted by the shut-in in Tunisia, with Chouech Es Saida being shut-in for the full quarter (since end of February 2017) and Sabria being shut-in from May 22, 2017 to the start of September 2017. Sabria came back on production with an average rate of 286 bbl/d in September 2017. During this period, 100% of the production was from the Sabria concession. Net earnings was negatively impacted by an impairment expense of \$5.0 million for Tunisia assets.

• In Q4 2017, oil and gas revenues were negatively impacted by the shut-in in Tunisia, with Chouech Es Saida being shut-in for the full quarter. All production is from the Sabria concession with an average production rate of 396 boe/d in Q4 2017. Net earnings were negatively impacted by the one-time well incident expense of \$4.0 million and a provision for \$0.6 million for potential severance costs for termination of employees in the Chouech Es Saida field in Tunisia.

In Q1 2018, all of the production was from the Sabria concession with an average of 380 boe/d. Net earnings were positively impacted by the insurance proceeds recognized of \$2.6 million, stemming from the prior year one-time well incident expenses of \$4.0 million recognized in 2017.

Changes in Accounting Policies

For the three months ended March 31, 2018, the Company adopted the following IFRS standards:

Revenue from Contracts with Customers

The Company has adopted IFRS 15 "Revenue from Contracts with Customers" ("IFRS 15") on January 1, 2018, using the modified retrospective transition approach. Management has reviewed its revenue streams and major contracts with customers using the IFRS 15 principles-based five step model and concluded that upon transition no adjustments were required to opening retained earnings as of January 1, 2018.

Under IFRS 15, revenue for crude oil sales is recognized once volumes are delivered for lifting at the loading terminal rather than the prior requirement to recognize upon lifting. The presentation in the statement of operations of amounts previously recorded as "change in oil inventory" are now recognized as part of "petroleum and natural gas revenues". This has no impact on net earnings. Likewise, on the statement of financial position, commodity inventory net of advances for crude oil sales are now recognized as part of accounts receivable.

Financial Instruments

The Company has adopted the new IFRS 9 "Financial Instruments" ("IFRS 9") on January 1, 2018. There was no impact upon adoption of IFRS 9 except for an adjustment for debt modifications as the Company renegotiated the repayment terms on its long-term debt effective October 31, 2017. The Company calculated a modification loss of \$0.4 million on the Senior Loan, and a modification gain of \$1.4 million on the Convertible Loan. A net \$1.0 million modification gain was recorded as a decrease to long-term debt and an increase to opening retained earnings as at January 1, 2018.

Recent Accounting Pronouncements

Leases

In January 2016, the IASB issued IFRS 16 "Leases" ("IFRS 16"), which requires entities to recognize assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements, and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue and what assets would be recorded.

IFRS 16 is effective for years beginning on or after January 1, 2019 with early adoption permitted if IFRS 15 "Revenue From Contracts With Customers" has been adopted. The standard shall be applied retrospectively to each period presented or using a modified retrospectively approach where the Company recognizes the cumulative effect as an adjustment to the opening retained earnings and applies the standard prospectively. The Company is currently in the process of identifying, gathering, and analyzing contracts that fall into the scope of the standard. The extent of the impact of the adoption of the standard has not yet been determined. The Company plans to apply IFRS 16 effective January 1, 2019. The Company intends to adopt the standard using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of January 1, 2019 and apply several of the practical expedients available such as low-value and short-term exemptions.

Disclosure Controls and Procedures and Internal Controls Over Financial Reporting

The preparation of this MD&A is supported by a set of disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICFR") as at March 31, 2018.

Disclosure controls and procedures as defined in National Instrument 52-109 means controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure;

Internal control over financial reporting means a process designed by, or under the supervision of, an issuer's certifying officers, and effected by the issuer's board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer's Generally Accepted Accounting Principles ("GAAP") and includes those policies and procedures that:

(a) Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;

(b) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the issuer's GAAP, and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and

(c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer's assets that could have a material effect on the annual financial statements or interim financial statements.

The Company's Chief Executive Officer and Chief Financial Officer of the Company have designed DC&P and ICFR, or caused them to be designed under their supervision, to provide reasonable assurance that all material information required to be disclosed by Serinus in its annual filings and interim filings are recorded, processed, summarized and reported within the time periods specified in applicable securities legislation, and to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with IFRS. The ICFR is based on criteria established in "Internal Control – Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in 2013.

The board of directors, through its Audit Committee, is responsible for ensuring that management fulfils its responsibilities for financial reporting and internal control. The Audit Committee meets at least annually with the Company's external auditors to review accounting, internal control, financial reporting, and audit matters.

There have been no material changes to the Company's internal controls over financial reporting from January 1, 2018 to March 31, 2018 that have materially affected or are reasonably likely to affect the Company's internal controls over financial reporting.

Non-IFRS Measures

The financial information presented in this MD&A has been prepared in accordance with IFRS except for the terms "netback" and "working capital" which are not recognized measures under IFRS and do not have standardized meanings prescribed by IFRS. These non-IFRS measures are presented for information purposes only and should not be considered an alternative to, or more meaningful than information presented in accordance with IFRS. Management believes netback and working capital may be useful supplemental measures as they are used by the Company to measure operating performance and to evaluate the timing and amount of capital required to fund future operations. The Company's method of calculating these measures may differ from those of other companies and, accordingly, they may not be comparable to measures used by other companies.

Serinus calculates "netback" and "working capital" as presented earlier in this document.

Forward-Looking Statements

This MD&A contains forward-looking statements. These statements relate to future events or future performance of the Company. When used in this MD&A, the words "may", "would", "could", "will", "intend", "plan", "anticipate", "believe", "estimate", "predict", "seek", "propose", "expect", "potential", "continue", and similar expressions, are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties, and other factors that may cause actual results or events to differ materially from those anticipated in such forwardlooking statements. Such statements reflect the Company's current views with respect to certain events, and are subject to certain risks, uncertainties and assumptions. Many factors could cause the Company's actual results, performance, or achievements to vary from those described in this MD&A. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual

results may vary materially from those described in this MD&A as intended, planned, anticipated, believed, estimated, or expected.

Specific forward-looking statements in this MD&A, among others, include statements pertaining to the following:

• factors upon which the Company will decide whether or not to undertake a specific course of action;
• world-wide supply and demand for petroleum products;
• expectations regarding the Company's ability to raise capital;
• treatment under governmental regulatory regimes; and
• commodity prices.

With respect to forward-looking statements in this MD&A, the Company has made assumptions, regarding, among other things:

• the impact of increasing competition;
• the ability of partners to satisfy their obligations;
• the Company's ability to obtain additional financing on satisfactory terms; and
• the Company's ability to attract and retain qualified personnel.

The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A:

• general economic conditions;
• volatility in global market prices for oil and natural gas;
• competition;
• liabilities and risks, including environmental liability and risks, inherent in oil and gas operations;
• the availability of capital;
• geopolitical volatility in the countries of operations; and
• alternatives to and changing demand for petroleum products.

Furthermore, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitable in the future.

The forward–looking statements contained in this MD&A are expressly qualified in their entirety by this cautionary statement. These statements speak only as of the date of this MD&A.

Abbreviations

The following abbreviations may be used throughout this MD&A document:

bbl	Barrel(s)	bbl/d	Barrels per day
boe	Barrels of Oil Equivalent	boe/d	Barrels of Oil Equivalent per day
mcf	Thousand Cubic Feet	mcf/d	Thousand Cubic Feet per day
mmcf	Million Cubic Feet	mmcf/d	Million Cubic Feet per day
mcfe	Thousand Cubic Feet Equivalent	mcfe/d	Thousand Cubic Feet Equivalent per day
mmcfe	Million Cubic Feet Equivalent	mmcfe/d	Million Cubic Feet Equivalent per day
mboe	Thousand boe	Bcf	Billion Cubic Feet
mmboe	Million boe	mcm	Thousand Cubic Metres
CAD	Canadian Dollar	USD	U.S. Dollar
\$M	Thousands of Dollars	UAH	Ukrainian Hryvnia
\$MM	Millions of Dollars	TND	Tunisian Dinar

Measurement Conversions

Certain crude oil and natural gas liquids volumes have been converted to mcfe or mmcfe on the basis of one bbl to six mcf. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Any figure presented in mcfe, mmcfe, boe or mboe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or natural gas liquids to six mcf of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the wellhead.

Investor Information

Additional information regarding Serinus and its business and operations is available at www.sedar.com. Information is also accessible on the Company's website at www.serinusenergy.com.

We welcome questions from interested parties. Contact should be directed to the Calgary office of Serinus via address: Suite 1500, 700 – 4th Avenue S.W., Calgary, Alberta T2P 3J4 Canada, phone: +1 403 264-8877 or e-mail: info@serinusenergy.com.