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RNS Number : 9958R
SEPLAT Petroleum Development Co PLC
06 March 2019
 

         

Seplat Petroleum Development Company Plc

 

Full Year Results

 

For the year ended 31 December 2018
(Expressed in Naira and US Dollars)

 

Please see a print friendly version by clicking on the link below; 

http://www.rns-pdf.londonstockexchange.com/rns/9958R_1-2019-3-6.pdf

 

Announcement

Lagos and London, 6 March 2019:  Seplat Petroleum Development Company Plc ("Seplat" or the "Company"), a leading Nigerian indigenous oil and gas company, listed on both the Nigerian Stock Exchange and London Stock Exchange, today announces its full year 2018 financial results and provides an operational update.

Commenting on the results Austin Avuru, Seplat's Chief Executive Officer, said 

"Seplat has delivered an excellent operational and financial performance resulting in robust profitability and cash flow generation providing us with an extremely solid foundation for growth in the coming years. At our core assets in the West, OMLs 4, 38 and 41, the extension of the license to 2038 means that we can confidently plan and invest long into the future to realise the full potential of those blocks. As we continue to enhance production and revenue diversification with new wells scheduled at OML 53 in the East, the board took the Final Investment Decision to invest in the large scale ANOH gas and condensate development which will form the next phase of transformational growth for our gas business. Disciplined capital allocation continues to remain at the core of our activities evidenced by our continual deleveraging of our debt levels to the current balance of US$350m. In 2018, we reinstated the dividend, increased capital investments and with the resources and headroom in our capital structure, we are equipped to capitalise on organic and inorganic growth opportunities as they may arise."   

Full year 2018 results highlights

2018 working interest production within guidance; license renewal secured for OMLs 4, 38 and 41

Full year working interest production of 49,867 boepd (comprising 25,669 bopd liquids and 145 MMscfd gas) within guidance range of 48,000 - 55,000 boepd; Uptime on the Trans Forcados System during 2018 was 85% (in line with budget), while average reconciliation losses stood at 8%

License renewal for OMLs 4, 38 and 41 obtained with a new expiry date of 21 October 2038. US$25.9 million renewal bonus paid ensuring all conditions have been met (renewal bonus included in 2018 capex)

2019 production guidance set at 49,000 boepd to 55,000 boepd (liquids production range of 24,000 bopd to 27,000 bopd and gas production range of 146 MMscfd to 164 MMscfd)

 

Strong profitability, cash flow generation and dividend reinstated

Full year revenue US$746 million; operating profit US$310 million, profit before deferred tax US$238 million; after adjusting for deferred tax of US$91 million, net profit after tax stood at US$147 million

Cash flow from operations US$502 million significantly ahead of capital expenditures of US$88 million

The board has recommended a final dividend of US$0.05 per share. 

2018 gas revenue at a record level of US$156 million and accounts for 21% of total revenue in the year

 

Refinanced balance sheet, continued to deleverage and preserve significant headroom in the capital structure

Successfully concluded debt refinancing in Q1 2018, including debut US$350 million bond which diversifies the long-term capital base and new four year US$300 million RCF

Cash at bank US$585 million and gross debt US$450 million resulting in a net cash position of US$135 million at end 2018

Deleveraged further post period end by paying down US$100 million to bring the RCF to zero while retaining the undrawn headroom in the capital structure to support growth; as a result, current gross debt is solely the bond at US$350 million

 

Project updates - FID sanctioned at the large scale ANOH project

Final investment decision sanctioned by Seplat's board for the ANOH project post period end; Phase I to comprise a 300 MMscfd gas processing plant with accommodation space for future expansion

Amukpe to Escravos alternate export pipeline nearing completion; anticipated to be fully commissioned and operational in Q2 2019, ramping up to initial permitted capacity of 40 kbpd during Q3 2019; access to three separate export routes at our western assets and two at our eastern assets providing adequate redundant capacity will significantly de-risk distribution of oil production to market

 

Financial overview

 

US$ million

 

billion

 

2018

2017

% change

2018

2017

Revenue

746

452

65%

228

138

Gross profit

391

212

84%

120

 65

Operating Profit

310

112

177%

95

 34

Profit before deferred tax

238

41

480%

73

 13

Net Profit after all taxes

147

265

(45)%

45

 81

Basic earnings per share (US$/)

0.26

0.47

(45)%

79.04

143.96

Cash flow from operations

502

447

12%

154

137

 

 

 

 

 

 

Working interest production (boepd)

49,867

36,923

35%

 

 

Realised oil price (US$/ per bbl)

70.1

50.4

39%

21,458

15,406

Realised gas price (US$/ per Mscf)

2.94

2.97

(1)%

900

908

 

Conference call

At 8:30 am GMT (London), 09:30 am WAT (Lagos) on 6 March 2019, Austin Avuru (CEO), Roger Brown (CFO) and Effiong Okon (Operations Director) will host a conference call to discuss the Company's results. Access details are:

Telephone Number: +44 (0) 20 3059 5868

The Company requests that participants dial in 10 minutes ahead of the call. When dialing in, please state the title of the call: "Seplat Petroleum Full Year Results 2018" when prompted by the operator.

The webcast can be accessed via the Company's website www.seplatpetroleum.com or at the following address: https://secure.emincote.com/client/seplat/seplat001 

Enquiries

Seplat Petroleum Development Company Plc

Roger Brown, CFO

Andrew Dymond, Head of Investor Relations

Ayeesha Aliyu, Investor Relations

Chioma Nwachuku, GM - External Affairs and Communications

 

 

+44 203 725 6500
+44 203 725 6500

+234 12 770 400

+234 12 770 400

FTI Consulting

Ben Brewerton/Sara Powell

seplat@fticonsulting.com

 


+44 203 727 1000

Citigroup Global Markets Limited

Tom Reid/Luke Spells

 


+44 207 986 4000

Investec Securities

Chris Sim/Jonathan Wolf

 


+44 207 597 4000

 

Notes to editors

Seplat Petroleum Development Company Plc is a leading indigenous Nigerian oil and gas exploration and production company with a strategic focus on Nigeria, listed on the Main Market of the London Stock Exchange ("LSE") (LSE:SEPL) and Nigerian Stock Exchange ("NSE") (NSE:SEPLAT).  Seplat is pursuing a Nigeria focused growth strategy and is well-positioned to participate in future divestment programmes by the international oil companies, other acquisition and farm-in opportunities and future licensing rounds.  For further information please refer to the Company website, http://seplatpetroleum.com/

Important notice

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulation. Upon the publication of this announcement via Regulatory Information Service, this inside information is now considered to be in the public domain. Certain statements included in these results contain forward-looking information concerning Seplat's strategy, operations, financial performance or condition, outlook, growth opportunities or circumstances in the countries, sectors or markets in which Seplat operates. By their nature, forward-looking statements involve uncertainty because they depend on future circumstances, and relate to events, not all of which are within Seplat's control or can be predicted by Seplat. Although Seplat believes that the expectations and opinions reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations and opinions will prove to have been correct. Actual results and market conditions could differ materially from those set out in the forward-looking statements. No part of these results constitutes, or shall be taken to constitute, an invitation or inducement to invest in Seplat or any other entity, and must not be relied upon in any way in connection with any investment decision. Seplat undertakes no obligation to update any forward-looking statements, whether as a result of new information, future events or otherwise, except to the extent legally required.

 

Full year 2018 results overview

Working interest reserves

Working interest 2P reserves as assessed independently by Ryder Scott at 1 January 2019 stood at 481 MMboe, comprising 227 MMbbls of oil and condensate and 1,473 Bscf (254 MMboe) of natural gas. This represents an increase in overall 2P reserves of 1% year-on-year.  The main driver of the upward revision year-on-year is due to the incorporation of updated 3D seismic data into field reservoir models (in the case of oil) and the anticipated compression benefits resulting from upgrades to the Sapele gas plant. Sustained good performance from the Oben gas wells also contributed to the upward revision, partially offsetting the gas volumes that were produced during the year.

 

W.I reserves at 1/1/2018

 

W.I reserves at 1/1/2019

 

 

Liquids

Gas

Oil equivalent

 

Liquids

Gas

Oil equivalent

 

 

MMbbls

Bscf

MMboe

 

MMbbls

Bscf

MMboe

 

 

 

 

 

 

 

 

 

OMLs 4, 38 & 41

 

174.7

657.1

288.0

 

174.1

669.0

289.4

OPL 283

 

5.1

62.2

15.8

 

6.1

64.5

17.2

OML 53

 

41.5

736.4

168.5

 

42.7

739.4

170.2

OML 55(1)

 

5.0

-

5.0

 

3.7

0.0

3.7

Total

 

226.3

1,455.7

477.3

 

226.6

1,473.0

480.5

(1) Under the revised commercial terms in relation to OML 55 Seplat will no longer be a shareholder in BelemaOil but will instead have a financial interest until a discharge sum of US$330 million has been paid to Seplat through the monetisation of oil reserves at OML 55.

At 1 January 2019 working interest 2C resources stood at 80 MMboe, comprising 38 MMbbls of oil and condensate and 244 Bscf of natural gas.  Consequently, the Company's working interest 2P+2C reserves and resources stood at 561 MMboe at 1 January 2019, comprising 265 MMbbls oil and condensate and 1,717 Bscf of natural gas.

Full year average daily production

 

Gross production

 

Working Interest production

 

 

Liquids(1)

Gas

Oil equivalent

 

Liquids

Gas

Oil equivalent

 

Seplat %

bopd

MMscfd

boepd

 

bopd

MMscfd

boepd

 

 

 

 

 

 

 

 

 

OMLs 4, 38 & 41

45.0%

52,620

323

106,392

 

23,679

145

47,876

OPL 283

40.0%

2,541

-

2,541

 

1,017

-

1,017

OML 53

40.0%

2,435

-

2,435

 

974

-

974

Total

 

57,596

323

111,368

 

25,669

145

49,867

1) Liquid production volumes as measured at the LACT unit for OMLs 4, 38 and 41.  Volumes stated are subject to reconciliation and will differ from sales volumes within the period.

2018 full year average working interest production stood at 49,867 boepd and represents an overall increase of 35% year-on-year. Within this liquids production was up 44% year-on-year whilst gas production was up 27% year-on-year.  The 2018 figures reflect a production uptime of 85%, compared to a production uptime of 50% in full year 2017 when the first six months of that year continued to be impacted by force majeure at the Forcados terminal. Overall reconciliation losses arising from use of third party infrastructure were around 8% for the year. 

Alternative oil export routes

The Company's policy of creating multiple export routes for all of its assets has resulted in it actively pursuing alternative crude oil evacuation options for production at OMLs 4, 38 and 41 and potential strategies to further grow and diversify production in order to reduce any over-reliance on one particular third party operated export system. In line with this objective, the Company has retained access to two jetties at the Warri refinery that will enable sustained exports of 30,000 bopd (gross) if required in the future. Exports via this route are not subject to the reconciliation losses or terminal crude handling and transport charges when exporting via the TFS.  In 2018 it was not necessary for the Company to activate this alternative export route.

Looking ahead, the Amukpe to Escravos 160,000 bopd capacity pipeline is set to provide a third export option for liquids production at OMLs 4, 38 and 41.  While completion work on the pipeline has been slower than anticipated due to delays on historical payments between the pipeline owner and the contractor, these have now been amicably resolved and based on information provided by the pipeline owners and contractor undertaking completion works and connection to the Escravos terminal and offshore export pipeline, the Company expects the pipeline now to be commissioned by the end of Q2 2019 and fully operational to the initial permitted volume for the Seplat / NPDC joint venture of 40kbpd in Q3 2019.

With line of sight on the availability of three independent export routes it is Seplat's ultimate intention to utilise all three to ensure there is adequate redundancy in evacuation routes, reducing downtime which has adversely affected the business over a number of years, significantly de-risking the distribution of production to market.

Gas business

Alongside its oil business, the Company has also prioritised the commercialisation and development of the substantial gas reserves and resources identified at its blocks and is today a leading supplier of processed natural gas to the domestic market in Nigeria.

Oben processing hub - Western Niger Delta

With overall operated gas processing capacity standing at the 525 MMscfd level, the Company is actively engaged with counterparties to increase contracted gas sales with the intention of taking gross production towards the 400 MMscfd level on a consistent basis. Of the 525 MMscfd total processing capacity, 465 MMscfd is located at Oben with the remaining 60 MMscfd located at Sapele. The 375 MMscfd expansion at Oben (Phases I and II) was completed by Seplat as a 100% investment project. The gas processing capacity expansion is also designed to allow the Company to accept third party gas and receive a processing tariff.  In 2018 the gas projects undertaken were focused on reducing gas flaring and maximising gas monetisation. Key projects completed in the year include the Oben non associated gas ("NAG") booster compression project whereby the installation of additional compressors at the Oben gas plant will boost the pressure of existing NAG wells and translate into higher achievable gas recovery at the Oben gas field. The company also successfully completed the hook-up of a 10 kbpd condensate stabiliser train at the Oben Gas plant to allow for handling of additional condensate production in the future that will accompany higher future gas production.  Furthermore, having initiated supplies of commissioning gas to the Azura Edo independent power plant at the start of the year, full operations commenced in May 2018 at which point gross deliveries stepped up to the contracted 116 MMscfd level on a take-or-pay basis.

ANOH processing hub (future) - Eastern Niger Delta

The ANOH gas development at OML 53 (and adjacent OML 21 with which the upstream project is unitised) is expected to underpin the next phase of growth for the gas business and Seplat's involvement positions it at the heart of one of the largest green field gas and condensate developments onshore the Niger Delta to date. Seplat is well positioned to leverage the experience gained at the Oben gas processing hub to incorporate operational and cost efficiencies. In August 2018 Seplat signed the Shareholder Agreement and Share Subscription Agreement with the Nigerian Gas Company ("NGC"), a wholly owned subsidiary of Nigerian National Petroleum Corporation ("NNPC") whereby NGC subscribed for fifty per cent of the shares in ANOH Gas Processing Company Limited ("AGPC"), a company that was incorporated in 2017, for the purpose of processing future wet gas production from the upstream unitised gas fields at OML 53 & OML 21, which is operated by Shell.  The signed Shareholder Agreement will govern Seplat's and NGC's respective interests in the AGPC incorporated joint venture. Other commercial agreements with NNPC and the Nigerian Gas Marketing Company ("NGMC") were also executed during a signing ceremony held at NNPC headquarters in Abuja.  Subsequent to the period end, the Seplat Plc board has taken the Final Investment Decision ("FID") to proceed with the ANOH project.

Rig based activity and other capital projects

Rig based activity at OMLs 4,38 and 41 was limited in the year to the drilling of one new gas production well at the Oben field and the workover on one further existing gas well. Upgrades to the liquid treatment infrastructure at OMLs 4,38 and 41 were also made that will enable Seplat to inject export grade dry crude via alternative routes and at the same time eliminate crude handling charges that have historically been incurred on water in the wet crude injected into the TFS. At OML 53 the Company re-entered two wells drilled by the previous operator at the Ohaji South oil field in order to complete them as oil producers. The Company expects the two wells to be brought onstream in Q2 2019 when the connection pipeline is completed, with the wells expected to flow at a combined initial rate for the joint venture of approximately 5,000 bopd.

License renewal of OMLs 4,38 and 41 for a further 20 years

In November Seplat announced that the President and Honourable Minister of Petroleum Resources had given consent for the licence renewal of OMLs 4, 38 and 41 to a new expiry date of 21 October 2038.  Seplat holds a 45% working interest in OMLs 4, 38 and 41 and in 2018 production from the licences accounted for 92% of Seplat's total oil production and 100% of Seplat's gas production.  In connection with the licence renewal Seplat paid in full a Renewal Bonus of US$25.9 million, thus ensuring all conditions for licence renewal had been met.

Finance

The higher oil production together with higher oil price realisations positively impacted oil revenue which stood at US$590 million. Alongside this, gas revenue reached a new record of US$156 million.  Consequently, total revenue for 2018 was up 65% from 2017 at US$746 million.  Operating profit for the year stood at US$310 million and profit before deferred tax of US$238 million. After adjusting for deferred tax of US$91 million net profit after tax stood at US$147 million.

Cash flow from operations was US$502 million and capital investments US$88 million. Cash at bank and net cash at year end stood at US$585 million and US$135 million respectively. During the year the NPDC receivables balance was reduced to zero.

In March the Company successfully concluded a refinancing of the existing US$300 million revolving credit facility ("RCF") with a new four-year US$300 million RCF at LIBOR +6% and issued a debut US$350 million bond priced at 9.25%. Proceeds of the refinancing were used to repay and cancel pre-existing indebtedness and also to cash settle crude oil prepayments entered into during 2016 and 2017.  The refinancing has enabled the Company to longer date its debt maturities which in turn has freed up significant free cash flow in 2018 and beyond, providing a greater financial resource to reinvest in Seplat's organic and inorganic growth plans.  The bond issuance has also, in particular, diversified Seplat's long term capital base.  In August the bond was listed on the International Securities Market of the London Stock Exchange in addition to the original listing on the Euro MTF market of the Luxembourg Stock Exchange, further raising Seplat's profile in the international capital markets.

Dividend

Having emerged from a period of weak macro conditions and a disrupted operating environment in 2016 and 2017, where Seplat's key focus was on preservation of liquidity and selective capital allocation to ensure the Company maintained a necessary level of financial flexibility, the Board reinstated the dividend in 2018 with a special dividend of US$0.05 per share in April paid to normalise returns to shareholders after the dividend suspension and an interim dividend of US$0.05 per share declared in October in line with our normal dividend distribution timetable. 

Further to this, the board of Seplat is recommending a final dividend of US$0.05 per share. Subject to approval of shareholders, the dividend will be paid shortly after the AGM which will be held on 16 May 2019 in Lagos, Nigeria.

2019 guidance

Production guidance for 2019 is set at 49,000 to 55,000 boepd on a working interest basis, comprising 24,000 to 27,000 bopd liquids and 146 to 164 MMscfd (25,000 to 28,000 boepd) gas production.  Capex guidance for 2019 is set at US$200 million.

Rig based activity will step-up significantly in 2019.  In the western Niger Delta at OMLs 4, 38 and 41 the Company plans to drill up to seven new oil production wells, one new gas well, one rig based re-entry of an existing oil well and one appraisal well. Facilities and engineering projects will focus on delivery of an upgraded integrated gas processing facility at Sapele and further upgrades to the liquid treatment facility to enable increased deliveries of dry crude in sapele and Amukpe.  At OPL 283 preparation work for development of the Igbuku gas field will continue with concept selection and FEED studies.

In the eastern Niger Delta at OML 53 development of the Ohaji South oil reserves will continue with the drilling of three planned oil production wells while the Company expects to also undertake a rig based workover of one existing oil production well at the jisike field.  In addition to this two appraisal wells are planned, one of which will be at the undeveloped Owu oil discovery.  Facilities and engineering work will focus on the expansion of oil production facilities at the Jisike and Ohaji South oil fields.  At OML 55 the Company will continue to monetise liftings towards full recovery of the US$330 million discharge sum.

 

Operations review

Seplat's current portfolio comprises direct interests in five oil and gas blocks and a revenue interest in one further block, all of which are located in the onshore to swamp areas of the prolific Niger Delta.  This portfolio provides the Company with a robust platform of oil and natural gas reserves and production capacity together with material upside opportunities through future development projects, 2C to 2P conversion and exploration and appraisal drilling. We also continue to view the shallow water offshore areas of the Niger Delta as an appealing opportunity set and one we hold ambitions to access in the future.

OMLs 4, 38 and 41

Operator:

Seplat

Working interest:

45.0%

Partner:

NPDC

Main fields:

Oben, Amukpe, Okporhuru, Ovhor, Orogho, Sapele, Sapele Shallow

2018 working interest liquids production:

23,679 bopd

2018 working interest gas production:

145 MMscfd

Remaining working interest 2P oil reserves:

174.1 MMbbls

Remaining working interest 2P gas reserves:

669.0 Bscf

2019 activities:

Production and development

 

Background

OML 4 covers an area of 267km2 and is located 78km north east of Warri, Delta State. The Oben field is located in OML 4 and is the main producing field on the block. Facilities on the block include a 60,000 bopd capacity flow station, a 465 MMscfd capacity non-associated gas processing plant and an associated gas compressor station with five 10 MMscfd associated gas ('AG') compressors. Oil exports from the Oben flow station are routed via the Oben - Amukpe pipeline to the Amukpe facilities and onwards to either the Forcados terminal or Warri Refinery. Production operations and facilities are supported by the Oben Field Logistics Base. The Oben field in particular is central to the Company's future gas expansion plans and is strategically located as an important gas hub with access to Nigeria's main gas demand centres. The license was renewed in 2018 for a further 20 years and is next due for renewal on 21 October 2038.

OML 38 covers an area of 2,094km2 and is located 48km north of Warri, Delta State. There are currently four producing fields on the block, namely Amukpe, Okpohuru, Orogho and Ovhor (which straddles OML 38 and OML 41). There are two further discoveries in OML 38: the Mosogar and Jesse discoveries, which have not yet been brought into production. Facilities on the block include a 45,000 bpd capacity flow station, a Liquid Treatment Facility ('LTF') and two 50,000 bbls crude storage tanks, all located at Amukpe. The license was renewed in 2018 for a further 20 years and is next due for renewal on 21 October 2038.

OML 41 covers an area of 291km2 and is located 50km from Warri, Delta State. There are currently three producing fields on the block, namely Sapele, Sapele Shallow and Ovhor (which straddles OML 41 and OML 38), and two discoveries with contingent resources, the Ubaleme and Okoporo discoveries. Facilities on the block include a flow station with 60,000 bpd capacity, a 60 MMscfd capacity non associated gas processing plant and a 26 MMscfd NGC owned gas compressor station. Produced oil is exported via the Sapele - Amukpe delivery line to the Amukpe facilities and onwards to either the Forcados terminal or Warri refinery. The condensate stream is combined with the oil for export and produced gas is exported via the NGC owned Oben-Sapele pipeline system which feeds into the Sapele power plant. The license was renewed in 2018 for a further 20 years and is next due for renewal on 21 October 2038.

2018 activity

On OML 4, the Company completed the Oben NAG booster compression project whereby the installation of additional compressors at the Oben gas plant will boost the pressure of existing NAG wells and translate into higher achievable gas recovery at the Oben gas field. The company also successfully completed the hook-up of a 10 kbpd condensate stabiliser train at the Oben Gas plant to allow for handling of additional condensate production in the future that will accompany higher future gas production.  Furthermore, having initiated supplies of commissioning gas to the Azura Edo independent power plant at the start of the year, full operations commenced in May 2018 at which point gross deliveries stepped up to the contracted 116 MMscfd level on a take-or-pay basis. Seplat also drilled a new gas production well at Oben which is expected to come onstream in Q1 2019.

On OML 38, further to the earlier commissioning of the liquid treatment facility ("LTF") at the Amukpe field, the Company undertook a crude quality upgrade project aimed at achieving an export grade specification of 0.5 BS&W MAX. By doing this, Seplat has scope to eliminate in the future the cost component of crude handling charges that have historically been incurred for exporting wet crude to the Forcados terminal and also free up additional haulage on the export pipeline for dry crude.  With the completion of the project, Seplat will also be able to deliver increased export quality dry crude shipments via the alternative routes. The company also completed upgrades to the 2 x 7,000 bbl storage tanks at Amukpe in Q4 2018 that will further help ensure continuous evacuation of dry crude via the alternative routes during periods of outage on the Trans Forcados Pipeline.

On OML 41 the ongoing focus is full development of the Sapele Shallow field. Seplat is defining a full development and drilling strategy for Sapele Shallow, which overlies the productive reservoirs in the main Sapele field and is estimated to hold a significant accumulation of oil (around 500 MMbbls STOIIP). Prior to this Sapele Shallow had remained largely undeveloped due to the heavier nature of the oil (21°API) relative to that in neighbouring blocks. The Company believes that the full development of Sapele-Shallow represents a material upside opportunity.

OPL 283

Operator:

Pillar Oil/OPGC

Working interest:

40.0%

Partner:

Pillar Oil

Main fields:

Umuseti and Igbuku

2018 working interest liquids production:

1,017 bopd

2018 working interest gas production:

n/a

Remaining working interest 2P oil reserves:

6.1 MMbbls

Remaining working interest 2P gas reserves:

64.5 Bscf

2019 activities:

Production

 

Background

Seplat has a 40% non-operated working interest in the Umuseti/Igbuku Marginal Field Area that is carved out of OML 56. The block is located in the northern onshore depo-belt of the Niger Delta and is operated by Pillar Oil Limited. The block contains one producing field, Umuseti, which came onstream in May 2012 and is currently producing from three development wells. There are 15 identified oil-bearing reservoirs in Umuseti with production currently coming from four of these reservoirs. Further development drilling will be required to drain the remaining reservoirs. The Igbuku field contains predominantly gas and condensate and is currently undergoing appraisal prior to development. The block also contains four satellite exploration leads, namely Igbuku North, Igbuku Deep, Umuseti East and Umuseti North-East, which the joint venture partners intend to further evaluate. Facilities on the block include a 5,000 bopd Early Production Facility ('EPF') and two 20,000 bbls crude storage tanks. Umuseti production is evacuated to a Group Gathering Facility ('GGF') where it is metered and thereafter exported either via Agip's Kwale facilities to the Brass terminal or via NPDC's pipeline to Forcados.

2018 activity

The Anagba-1 appraisal well, completed in November 2017, is supporting unitisation discussions for OPL 283 partners to receive a share of production from wells at the Ashaka field on adjacent OML 60 operated by Nigeria Agip Oil Company. The Company also acquired Igbuku 3D seismic to support further development in the asset.

OML 53

Operator:

Seplat

Working interest:

40.0%

Partner:

NNPC

Main fields:

Jisike (producing) and Ohaji South (discovery)

2018 working interest liquids production:

974 bopd

2018 working interest gas production:

n/a

Remaining working interest 2P oil reserves:

42.7 MMbbls

Remaining working interest 2P gas reserves:

739.4 Bscf

2019 activities:

Production and development

 

Background

OML 53 covers an area of approximately 1,585km2 and is located onshore in the north eastern Niger Delta. The Jisike oil field, located in the north western area of the block, is currently the only producing field on OML 53. Existing infrastructure at Jisike comprises flow-lines, phase one separation facilities and a flow station with a design capacity of 12,000 bopd and 8 MMscfd. Oil production is sent for further processing at the nearby Izombe facilities on OML 124 from where it is exported via pipeline to the Brass oil terminal. The block also contains the large undeveloped Ohaji South gas and condensate field, the development of which will be coordinated with the SPDC operated Assa North field on adjacent OML 21, together referred to as the ANOH project which is set to be one of the largest greenfield gas condensate development projects in Nigeria to date. The expectation is that future gas production from the ANOH project will supply the domestic market, for which significant work on commercialisation terms and development concepts has been undertaken. There is also shallow oil development potential at Ohaji South that is being pursued as a separate oil production project in the near term. Prior to initiating development of the ANOH project, Seplat expects to focus efforts on increasing oil production at the Jisike field and development of the shallow oil reservoirs in Ohaji South. Pursuant to the Joint Operating Model, Seplat is designated operator of OML 53.

2018 activity

Seplat undertook a rig-based re-entry and completion of two wells drilled by the previous operator at the Ohaji South oil field which are due to come onstream in 2019. Other projects carried out during the year were focused on sustaining production at the Jisike oil field, developing infrastructure and improving existing facilities.

OML 53, as part of the Assa North - Ohaji South ("ANOH") development is at the core of Seplat's plans to significantly increase gas production and operated processing capacity in the near to medium term.  In August 2018, Seplat signed the Shareholder Agreement and Share Subscription Agreement with the Nigerian Gas Company ("NGC"), a wholly owned subsidiary of Nigerian National Petroleum Corporation ("NNPC").  NGC will subscribe for fifty percent of the shares in ANOH Gas Processing Company Limited ("AGPC"), a company that was incorporated in 2017, for the purpose of processing future wet gas production from the upstream unitised gas fields at OML 53 & OML 21, which is operated by Shell.  The signed Shareholder Agreement will govern Seplat's and NGC's respective interests in the AGPC incorporated joint venture. Other commercial agreements with NNPC and the Nigerian Gas Marketing Company ("NGMC") were also executed at the same time. . Subsequent to the period end, the Seplat Plc board has taken the Final Investment Decision ("FID") to proceed with the ANOH project. The upstream development, including the drilling of production wells, will be delivered by the upstream unit operator SPDC.

OML 55

Operator:

Asset Management Team

Working interest:

Revenue interest

Partner:

NNPC, Belemaoil

Main fields:

Robertkiri, Idama and Inda (producing)

2018 working interest liquids production:

n/a

2018 working interest gas production:

n/a

Remaining working interest 2P oil reserves:

3.7

Remaining working interest 2P gas reserves:

n/a

2019 activities:

Recovery of discharge sum

 

Background

OML 55 covers an area of approximately 840km2 and is located in the swamp to shallow water offshore areas in the south eastern Niger Delta. The block contains five producing fields (Robertkiri, Inda, [Belema] North, Idama and [Jokka]). The majority of production on the block is from the Robertkiri, Idama and Inda fields. The Robertkiri field is located in swamp at a water depth of five metres and has a production platform and utility platform installed. Production capacity at the Robertkiri facilities is 20,000 bpd and 10 MMscfd. Production facilities at the Idama field comprise a jack-up mobile offshore production unit ('MOPU') and riser platform that have a capacity of 30,000 bpd of total fluids and 34 MMscfd. The Jokka field is produced through a manifold tied-back to the Idama facilities. Production facilities at the Inda field comprise a MOPU with a capacity of 30,000 bpd of total liquids and 34 MMscfd. Overall, the infrastructure on OML 55 comprises four flow stations, a network of flow-lines, and two eight-inch pipelines that connect to third party operated infrastructure. The Belema field is unitised with OML 25 and is produced via a flow station on that block. All produced liquids from OML 55 are delivered via third-party infrastructure to the Bonny terminal for processing and shipping. In addition to the oil potential on the block there is also an opportunity to develop the significant gas resources that have also been identified.

2018 activity

In accordance with the revised commercial arrangement that was agreed in July 2016, which provides for a discharge sum of US$330 million to be paid to Seplat over a six year period through allocation of crude oil volumes produced at OML 55, Seplat received payments amounting to US$48 million in 2018. Total payments received from inception to the end of 2018 stood at US$84 million and the outstanding discharge sum to be paid to Seplat is US$246 million.  The 40.00% operated interest in OML 55 continues to be jointly controlled by Seplat and BelemaOil over the period of this arrangement through an Asset Management Team comprising representatives of both parties.

 

Financial review

In 2018 the Group benefitted from the higher year-on-year oil and gas production volumes and an oil price tailwind, the combined effect of which was a sharp increase in both profitability and cash flow generation. Discretionary investments during the year were primarily directed towards the gas business, which is de-linked from oil prices, while a refinancing of the balance sheet reset the Group's capital structure and enables it now to optimally capture the numerous organic growth opportunities within the existing portfolio in addition to the potentially valuable inorganic acquisition opportunities that exist in the Nigerian oil and gas space.     

Revenue

Total revenue for 2018 stood at US$746 million for the full year, up 65% from 2017 at US$452 million.  The increase arises principally from higher oil production in 2018, further impacted by higher oil price realisations. Alongside this gas revenue reached a new record of US$156 million, up 26% year-on-year and accounting for 21% of total revenue. 

An increased full year uptime of 85% in 2018 resulted in average working interest liquids production of 25,669 bopd, up 44% from 17,853 bopd in 2017, whilst the total volume of crude lifted in the year was 8.4 MMbbls compared to 6.9 MMbbls in 2017. The Group's realised weighted average oil price of US$70.1/bbl in 2018 was up 39% year-on-year (2017: US$50.38/bbl), while the actual Brent oil price averaged US$71/bbl over 2018. Brent remained volatile throughout the year, trading between a low of US$62/bbl in February to a high of US$86/bbl in October before selling off sharply to exit the year at around US$51/bbl.

In 2018, the Group had in place dated Brent put options covering a volume of 6.60 MMbbls to year end at a combined weighted average strike price of US$44.5/bbl. The net cost of these instruments in the year was US$6.4 million. This hedging programme has been continued in 2019 where upfront premium put options at a strike price of US$50.0/bbl were entered into, protecting a volume of 4.0 MMbbls. The board and management continue to closely monitor prevailing oil market dynamics, and will consider further measures to provide appropriate levels of cash flow assurance in times of oil price weakness and volatility.

The higher year-on-year gas revenue was driven by a 27% increase in production volumes to 145 MMscfd while the average realised gas price remained relatively stable at US$2.94/Mscf (2017: US$2.97/Mscf).  The increase in volume is from the benefit of production being fully de-constrained in a full year of normalized production following the lifting of force majeure. Also, the company initiated supplies of commissioning gas to the Azura Edo independent power plant at the start of the year and full operations commenced in May 2018 at which point gross deliveries stepped up to the contracted 116 MMscfd level on a take-or-pay basis. Management remains in active negotiations with new gas off take customers to ultimately reach gross production of 400 MMscf on a consistent basis.

Gross profit

Gross profit for the year was US$391 million, an increase of 84% to the prior year (2017: US$212 million). This principally reflects the resumption of a full year of production operations after force majeure was lifted and higher oil price realisations.  Direct operating costs which include crude handling fees, rig-related costs and Operations & Maintenance costs amounted to US$105 million in 2018 as against US$80 million in 2017. This increase in cost is as a result of higher crude handling fees corresponding with higher production.  On a cost per barrel basis, production opex were slightly lower at US$5.77/boe when compared to prior year of US$5.96/boe and reflects efficiencies generated with an increase of 35% in production volumes in 2018 when compared to 2017. A further improved performance in the overall running & maintenance of the production facility also positively impacted on production costs. Non- production costs primarily consisting of royalties and DD&A were US$250 million compared to US$160 million in the prior year. The DD&A charge for oil and gas assets increased during 2018 to US$119 million (2017: US$82 million) reflecting higher depletion of reserves because of the increased production during the year.

Operating profit

Operating profit for the year was US$310 million compared with a prior year of US$112 million.  Impairment adjustments based on IFRS 9 requirements affected prior year numbers and resulted in an increase in G&A expenses for 2017 to US$92 million. Emphasis on careful cost management led to a 13% reduction year-on-year in general and administrative expenses which stood at US$80 million and helped the increased operating profit.

Tax

The pioneer tax incentive granted by Nigerian Investment Promotion Commission for three-year period elapsed at the end of 2015. The Company has prepared its 2018 financial statements including the effect of post pioneer tax status which resulted in a tax expense of US$117 million, compared to a net tax credit of US$221 million for the same period in 2017, owing primarily to deferred tax credits of US$224 million.

Following a significant improvement in the financial position of the Group in 2017, the Group conducted an assessment of the assessable profit based on a five-year business plan in order to determine the possibility of future profit making prospects for

2018 to 2022. The Group reviewed previously unrecognised tax losses and determined that it was now probable that taxable profits will be available against which the tax losses can be utilised. As a result, deferred tax assets of $133 million (2017: US$224 million) were recognised for those losses. This resulted in a deferred tax charge of US$91 million being charged in the year (2017: US$ 224 million credit).

In May 2015, in line with Sections of the Companies Income Tax Act which provides incentives to companies that deliver gas utilisation projects, Seplat was granted a tax holiday for three years with a possible extension of two years. In 2018, on review of the performance of the business, the Group provided a notification to the Federal Inland Revenue Service (FIRS) for the extension of claim for the additional two years tax holiday.

Net profit

Profit for the period before tax adjustments was US$263 million, up 498% compared to US$44 million in 2017. This profitability was sustained through six consecutive quarters from the third quarter of 2017 when production was unconstrained. Net Profit in 2018 was US$147 million (2017: US$265 million). The resultant EPS for 2018 was US$0.26 compared to an EPS of US$0.47 in 2017 when the deferred tax credit increased net profit by US$224 million to US$265 million.

Dividends

Having emerged from a period of weak macro conditions and a disrupted operating environment in 2016 and 2017, where Seplat's key focus was on preservation of liquidity and selective capital allocation to ensure the Company maintained a necessary level of financial flexibility, the Board reinstated the dividend in 2018 with a special dividend of US$0.05 per share in April paid to normalise returns to shareholders after the dividend suspension and an interim dividend of US$0.05 per share declared in October in line with our normal dividend distribution timetable. 

Further to this, the board of Seplat is recommending a final dividend of US$0.05 per share. Subject to approval of shareholders, the dividend will be paid shortly after the AGM which will be held on 16 May 2019 in Lagos, Nigeria.

Cash flows and liquidity

Cash flows from operating activities

Operating cash flow before movements in working capital was US$454 million (2017: US$194 million) Net cash flows from operating activities after movements in working capital was up 12% at US$502 million (2017: US$447 million). The Group has continued to receive the proceeds of gas sales from its partner NPDC in lieu of cash calls for ongoing operations. Tolling fees arising from NPDC's share of processed gas from the Oben Gas Expansion Project, which was financed on a sole risk basis by Seplat, are yet to be settled by NPDC and Seplat is currently in discussions with NPDC to finalise terms.

Cash flows from investing activities

Capital expenditures on oil and gas assets in 2018 stood at US$88 million and includes the license renewal fee of US$25.6 million; drilling costs for the Oben gas production well, re-entry of two Ohaji South wells and the well workover of Jisike. Gas project costs include the NAG booster compression station at Oben and other costs associated with plans towards ANOH FID.

Having reached agreement in 2016 with partner BelemaOil on a revised commercial arrangement at OML 55, which provides for a discharge sum of US$330 million to be paid to Seplat over a six-year period through allocation of crude oil volumes, the Group received total proceeds of US$48 million in 2018 under this arrangement. Consequently, after adjusting for interest receipts of US$10 million, net cash outflow from investing activities for the full year was US$31 million compared to a net cash inflow in 2017 of US$7 million, reflecting the higher capex spend.

Cash flows from financing activities

Net cash at year-end was US$135 million, compared to a net debt US$141 million at December 2017. Net cash outflows from financing activities were US$329 million (2017: cash outflow US$173 million).

In March the Group successfully refinanced its existing US$300 million revolving credit facility ("RCF") with a new four year US$300 million RCF at LIBOR + 6% (US$200 million drawn at 30 June 2018) and issued a debut US$350 million bond priced at 9.25%, diversifying the long-term capital base. Proceeds from the re-financing were used to repay and cancel pre-existing indebtedness and also to cash settle crude oil prepayments undertaken during the extended period of force majeure in 2016 and 2017. In October, US$100 million loan repayment in respect of the RCF was settled to reduce the outstanding balance on the facility to US$100 million.

Overall Seplat's aggregate indebtedness at 31 December 2018 stood at US$450 million and cash at bank US$585 million to give a net cash position of US$135 million with US$163 million undrawn headroom on the RCF facility. Post period end, the company paid down an additional US$100 million against the RCF facility taking its balance to zero and a headroom of US$263 million.  This is a significant deleveraging of the balance sheet from its peak levels of US$1 billion in 2015. The Group is well capitalised and fully funded to execute its organic growth plans and therefore well positioned to pursue inorganic growth opportunities in line with its price disciplined approach balanced with a robust dividend yield.

 

 

US$ Million

Coupon

Maturity

Senior Notes

350

9.25%

June 2023

3 year secured RCF*

100

L+6.00%

June 2022

Gross debt at parent

450

 

 

Cash and cash equivalents

585

 

 

Net cash

135

 

 

*  Total commitment under the RCF is US$263 million

 

Following the reinstatement of a dividend of US$0.10/share during the year, the Group returned US$58.8 million to shareholders.

Brexit

The Group's activities in the UK are limited to providing capital management, investor relations, business development and other support services to the Nigerian operations. Brexit may result in a change in the financial reporting standards applicable to Seplat UK financial statements which currently reports under IFRS for the EU. However, the Group does not envisage that this would result in a material variance from what is currently reported.

With regards to taxes, including incentives, exemptions and reliefs, there are no uncertain tax positions as a result of Brexit. Changes in accounting treatments and disclosures may also result in changes in taxes. As mentioned, it is not envisaged that there would be any material impact on accounting for transactions in Seplat UK.

Seplat is not exposed to any material financial risk arising from Brexit. It is not exposed to additional market risk, liquidity risk or credit risk from its UK subsidiary. 

It is the view of the Board that, given the Group's single country focus on Nigeria, Seplat's business, assets and operations will not be materially affected by Brexit.  Seplat also derives most of its income from crude oil, a globally-traded commodity which is priced in US Dollars.  Furthermore, Seplat's gas revenues are derived solely from sales to the domestic market in Nigeria and therefore are unaffected by international factors. The Board has therefore assessed and concludes that there are no material uncertainties arising from Brexit that would significantly impact Seplat as a result of its UK subsidiary.

Outlook

In 2019 we will retain our price disciplined approach to only allocating capital to the highest cash returning organic and value accretive acquisition growth opportunities. Combined with a robust dividend yield, we aim to ensure that Seplat is the investment of choice in Nigeria to access sub-Sahara Africa's most prolific oil and gas opportunities.

 

General information

 

Board of directors:

Ambrosie Bryant Chukwueloka Orjiako

Chairman

 

Nigerian

 

Ojunekwu Augustine Avuru

Managing Director and Chief Executive Officer

 

Nigerian

 

Roger Thompson Brown

Chief Financial Officer (Executive Director)

 

British

 

Effiong Okon

Operations Director (Executive Director)

 

Nigerian

 

Michel Hochard*

Non-Executive Director

 

French

 

Macaulay Agbada Ofurhie

Non-Executive Director

 

Nigerian

 

Michael Richard Alexander

Senior Independent Non-Executive Director

 

British

 

Ifueko M. Omoigui Okauru

Independent Non-Executive Director

 

Nigerian

 

Basil Omiyi

Independent Non-Executive Director

 

Nigerian

 

Charles Okeahalam

Independent Non-Executive Director

 

Nigerian

 

Lord Mark Malloch-Brown

Independent Non-Executive Director

 

British

 

Damian Dinshiya Dodo, SAN

Independent Non-Executive Director

 

Nigerian

 

 

*Madame Nathalie Delapalme acts as alternate Director to Michel Hochard

 

Company Secretary

Mirian Kachikwu

 

Registered office and business
address of Directors

25a Lugard Avenue

Ikoyi

Lagos

Nigeria

 

Registered number

RC No. 824838

 

FRC number

FRC/2015/NBA/00000010739

 

Auditor

Ernst & Young

(10th & 13th Floors), UBA House

57 Marina Lagos, Nigeria

 

Registrar

DataMax Registrars Limited

7 Anthony Village Road

Anthony

P.M.B 10014

Shomolu

Lagos, Nigeria

 

Solicitors

Olaniwun Ajayi LP

Adepetun Caxton-Martins Agbor & Segun ("ACAS-Law")

Banwo & Ighodalo

Templars Law

White & Case LLP

Whitehall Solicitors

Bracewell (UK) LLP

Herbert Smith Freehills LLP

Chief J.A. Ororho & Co.

Ogaga Ovrawah & Co.

Consolex LP

J.E. Okodaso & Company

V.E. Akpoguma & Co.

Thompson Okpoko & Partners

G.C. Arubayi & Co.

Streamsowers & Kohn

 

Bankers

First Bank of Nigeria Limited

Stanbic IBTC Bank Plc

United Bank for Africa Plc

Zenith Bank Plc

Citibank Nigeria Limited

Standard Chartered Bank

HSBC Bank

 

 

 

Report of the Directors

For the year ended 31 December 2018

The Directors are pleased to present to the shareholders of the Company their report with the audited financial statements for the year ended 31 December 2018.

Principal activity

The Company is principally engaged in oil and gas exploration and production.

Corporate structure and business

Seplat Petroleum Development Company Plc (''Seplat'' or the ''Company''), the parent of the Group, was incorporated on 17 June 2009 as a private limited liability company and re-registered as a public company on 3 October 2014, under the Companies and Allied Matters Act 2004. The Company commenced operations on 1 August 2010.

The Company acquired, pursuant to an agreement for assignment dated 31 January 2010 between the Company, SPDC, TOTAL and AGIP, a 45 percent participating interest in the following producing assets:

OML 4, OML 38 and OML 41 located in Nigeria. The total purchase price for these assets was US$340 million paid at the completion of the acquisition on 31 July 2010 and a contingent payment of US$33 million payable 30 days after the second anniversary, 31 July 2012, if the average price per barrel of Brent Crude oil over the period from acquisition up to 31 July 2012 exceeds US$80 per barrel.

US$358.6 million was allocated to the producing assets including US$18.6 million as the fair value of the contingent consideration as calculated on acquisition date. The contingent consideration of US$33 million was paid on 22 October 2012.

Seplat Petroleum Development Company Plc was successfully listed on the Nigerian Stock Exchange and the main market of the London Stock Exchange on 14 April 2014. However, Seplat on the 4th April 2018, was migrated to the Premium Board of the Nigerian Stock Exchange. 

In 2013, Newton Energy Limited (''Newton Energy''), an entity previously beneficially owned by the same shareholders as Seplat, became a subsidiary of the Company. On 1 June 2013, Newton Energy acquired from Pillar Oil Limited (''Pillar Oil'') a 40 percent Participant interest in producing assets: the Umuseti/Igbuku marginal field area located within OPL 283 (the ''Umuseti/Igbuku Fields'').

In 2015, the Group purchased a 40% participating interest in OML 53, onshore north eastern Niger Delta, from Chevron Nigeria Ltd. for US$259.4 million. It also concluded negotiations to buy 56.25% of BelemaOil Producing Ltd., a Nigerian special purpose vehicle that bought a 40% interest in the producing OML 55, located in the swamp to coastal zone of south eastern Niger Delta. NNPC holds the remaining 60.00% interest in OML 55, and Seplat's effective participating interest in OML 55 as a result of the acquisition was 22.50%.

Based on the above, Seplat consolidated BelemaOil in its 31 December 2015 consolidated financial statements.

During the year, the minority shareholders of BelemaOil began to dispute Seplat's majority shareholding in the entity. In July 2016, Seplat instituted legal action in a bid to secure its investment in OML 55.

Subsequent to the year end, the Asset Management Team of OML 55 has been formally inaugurated, and first lifting has taken place, the proceeds of which have been deposited into the escrow account as prescribed in the agreements.

Subsequently, and in a bid to resolve pending legal disputes, representatives of both Seplat and BelemaOil have agreed to a new arrangement which provides for a discharge sum of US$330 million, as at the reporting date fair valued at US$250 million, to be paid to Seplat over a six-year period, through allocation of crude oil reserves of OML 55. In turn, Seplat relinquishes all claims to its shareholding of BelemaOil as an entity. The 40% stake in OML 55 will be held by Seplat and BelemaOil over the period of this arrangement through an Asset Management Team comprising equal representatives of both parties. The Asset Management Team makes all the key decisions regarding the relevant activities of the underlying asset, and consent of all parties is required for decision making. The agreements have been signed by both parties but are subject to ministerial consent. The Group however believes consent will be received as the agreements were brokered by the Ministry of Petroleum Resources.

As a result of the foregoing, Seplat no longer exercises control and has now deconsolidated BelemaOil in the financial statements in accordance with IFRS 10 (par B97). Seplat has recorded its rights to receive the discharge sum from the crude oil reserves of OML 55 as other asset.

The Company together with its subsidiary, Newton Energy, and other wholly owned subsidiaries, namely, Seplat Petroleum Development Company UK Limited (''Seplat UK''), which was incorporated on 21 August 2013; Seplat East Onshore Limited (''Seplat East''), which was incorporated on 12 December 2013; Seplat East Swamp Company Limited (''Seplat Swamp''), which was incorporated on 12 December 2014;  Seplat Gas Company Limited (''Seplat Gas''), which was incorporated on 12 December 2013; Seplat West Limited ("Seplat West") which was incorporated on 16 January, 2018 and ANOH Gas Processing Company Limited which was incorporated on 18 January 2017 is referred to as the Group.

Subsidiary

Country of incorporation and place of business

Shareholding %

Principal activities

Newton Energy Limited

Nigeria

100%

Oil & gas exploration and production

Seplat Petroleum Development UK

United Kingdom

100%

Oil & gas exploration and production

Seplat East Onshore Limited

Nigeria

100%

Oil & gas exploration and production

Seplat East Swamp Company Limited

Nigeria

100%

Oil & gas exploration and production

Seplat Gas Company

Nigeria

100%

Oil & gas exploration and production

Seplat West Limited

Nigeria

100%

Oil & gas exploration and production

ANOH Gas Processing Company Limited

Nigeria

100%

Gas processing

 

Operating results:

 

Nigerian million

US$'000

 

2018

 2017

2018

 2017

Revenue

228,391

138,281

746,140

452,179

Operating profit

94,875

34,376

309,951

112,414

Profit before taxation

80,615

13,454

263,364

43,997

Profit for the year

44,867

81,111

146,576

265,230

 

 

 

 

 

           

 

Dividend

Having emerged from a period of weak macro conditions and a disrupted operating environment in 2016 and 2017, where Seplat's key focus was on preservation of liquidity and selective capital allocation to ensure the Company maintained a necessary level of financial flexibility, the Board reinstated the dividend in 2018 with a special dividend of US$0.05 per share in April paid to normalise returns to shareholders after the dividend suspension and an interim dividend of US$0.05 per share declared in October in line with our normal dividend distribution timetable (2017: nil).

Further to this, the board of Seplat is recommending a final dividend of US$0.05 per share. Subject to approval of shareholders, the dividend will be paid shortly after the AGM which will be held on 16 May 2019 in Lagos, Nigeria.

Unclaimed dividend

The total amount outstanding as at 31 December 2018 is US$2,713.50 and 88,777,086.54. A list of shareholders and corresponding unclaimed dividends is available on the Company's website: www.seplatpetroleum.com.

Changes in property, plant and equipment

Movements in Property, plant and equipment and significant additions thereto are shown in note 17 to the financial statements.

Rotation of Directors

In accordance with the provisions of Section 259 of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria ('LFN') 2004, one third of the Directors of the Company shall retire from office. The Directors to retire every year shall be those who have been longest in office since their last election. However, in accordance with Article 131 of the Company's Articles of Association, apart from the Executive Directors and Founding Directors (who are referred to as the Non-Executive Directors), all other Directors are appointed for a fixed term. Upon expiration of the terms, they become eligible for re-appointment. The Directors who are eligible for re-appointment this year are Mrs. Ifueko M. Omoigui Okauru and Mr. Damian Dodo, SAN.

Board changes

The Board appointed an Executive Director since the last Annual General Meeting. Effiong Okon was appointed Operations Director effective 23 February 2018 and ratified by shareholders at the 2018 Annual General Meeting. Effiong brings a wealth of relevant Nigerian and international operational experience from 26 years in the industry with Shell. He is an asset to the Board and we look forward to his contribution to the growth of the Company.

The appointment and removal or reappointment of Directors is governed by its Articles of Association and Companies and Allied Matters Act (CAMA) LFN 2004. It also sets out the powers of Directors.

Corporate governance

The Board of Directors of the Company is committed to sound corporate governance and ensures that the Company complies with Nigerian and UK corporate governance regulations as well as international best practice.

The Board is aware of the Code of Corporate Governance issued by the Securities and Exchange Commission, the Nigerian Code of Corporate Goverance, 2018 issued by the Financial Reporting Council of Nigeria and the UK Corporate Governance Code, 2018 issued by the Financial Reporting Council in the administration of the Company and is ensuring that the Company complies with it. The Board is responsible for keeping proper accounting records with reasonable accuracy. It is also responsible for safe guarding the assets of the Company through prevention and detection of fraud and other irregularities.

In order to carry out its responsibilities, the Board has established 6 Board Committees and has delegated aspects of its responsibilities to them. The Committees of the Board and members are as follows:

1.

Finance Committee

 

 

Charles Okeahalam

Committee Chairman

 

Michael Alexander

Member

 

Ifueko M. Omoigui Okauru

Member

 

Lord Mark Malloch-Brown

Member

2.

Nomination and Establishment Committee

 

 

A.B.C. Orjiako

Committee Chairman

 

Basil Omiyi

Member

 

Michael Alexander

Member

 

Damian Dinshiya Dodo, SAN

Member

3.

Remuneration Committee

 

 

Michael Alexander

Committee Chairman

 

Basil Omiyi

Member

 

Charles Okeahalam

Member

 

Damian Dinshiya Dodo, SAN      

Member

4.

Risk Management and HSSE Committee

 

 

Basil Omiyi    

Committee Chairman

 

Macaulay Agbada Ofurhie

Member

 

Ifueko M. Omoigui Okauru      

Member

5.

Corporate Social Responsibility Committee

 

 

Lord Mark Malloch-Brown

Committee Chairman

 

Macaulay Agbada Ofurhie

Member

 

Ifueko M. Omoigui Okauru      

Member

6.

Gas Committee

 

 

Basil Omiyi

Committee Chairman

 

Macaulay Agbada Ofurhie

Member

 

Michael Alexander     

Member

 

The Board constituted the Gas Committee in 2018 to help fine tune the Company's gas strategy and bring greater focus to the management of gas business risks. The Committee will help the Company to successfully navigate the changing gas market landscape and position it to function as a robust, stand-alone midstream business.

In addition to these Board Committees, the Company formed a statutory Audit Committee at its 30 June 2014 Annual General Meeting ("AGM") in compliance with Sections 359(3) and (4) of the Companies and Allied Matters Act ("CAMA"). In compliance with CAMA, three shareholder representatives and three Non-Executive Directors are elected at every AGM to sit on the Committee.

1.

Statutory Audit Committee

 

 

Chief Anthony Idigbe, SAN.

Committee Chairman (Shareholder Member)

 

Ifueko M. Omoigui Okauru

Director Member

 

Macaulay Agbada Ofurhie

Director Member

 

Michel Hochard        

Director Member

 

Dr. Faruk Umar          

Shareholder Member

 

Sir Sunday Nnamdi Nwosu

Shareholder Member

 

All seven Committees have terms of reference that guide their members in the execution of their duties, and these terms of reference are available for review by the public. All the Committees present a report to the Board with recommendations on the matters within their purview.

Record of attendance of Board and Committee meetings

The Board met thirteen times during the year and at least once every quarter in line with Section 12.1 of the SEC Code. Board meetings were well attended with attendance of all Directors exceeding two-thirds as required by Section 12.2 of the SEC Code. The record of attendance of Directors at Board meetings and that of its Committees in the year under review is published herewith:

Board of Directors

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

A.B.C. Orjiako

Chairman                                                 

13

13

2.

Austin Avuru

Chief Executive Officer

13

13

3.

Roger Brown

Chief Financial Officer

13

13

4.

Michel Hochard*

Non-Executive Director

13

13

5.

Macaulay Agbada Ofurhie

Non-Executive Director

13

9

6.

Michael Alexander

Senior Independent Non-Executive Director

13

13

7.

Charles Okeahalam

Independent Non-Executive Director

13

12

8.

Basil Omiyi

Independent Non-Executive Director

13

12

9.

Ifueko M. Omoigui-Okauru

Independent Non-Executive Director

13

11

 

10.

Lord Mark Malloch-Brown

Independent Non-Executive Director

13

10

 

11.

Damian Dodo, SAN

Independent Non-Executive Director

13

13

 

12.

Effiong Okon

Operations Director

10

10

 

                   

Meeting dates: 23 January; 13, 23 February; 19, 26,27 April; 16 May; 6, 11 June; 19 July; 20, 27 September; 19 October

Finance Committee

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

Charles Okeahalam

Chairman

5

5

2.

Michael Alexander 

 

5

5

3.

Ifueko Ifueko Omoigui Okauru

 

5

5

4.

Lord Mark Malloch-Brown

 

5

4

Meeting dates: 23 January, 23 February, 18 April, 17 July, 24 October.

Nomination and Establishment Committee

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

A.B.C. Orjiako

Chairman

3

3

2.

Basil Omiyi

 

3

3

3.

Michael Alexander

 

3

3

4.

Damian Dodo

 

3

3

Meeting dates: 18 April, 17 July, 24 October

Remuneration Committee

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

Michael Alexander

Chairman

5

5

2.

Basil Omiyi

 

5

5

3.

Charles Okeahalam

 

5

4

4.

Damian Dodo

 

5

5

Meeting dates: 23 January, 23 February, 7 March, 18 April, 24 October.

Risk Management and HSSE Committee

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

Basil Omiyi

Chairman

4

4

2.

Macaulay Agbada Ofurhie

 

4

4

3.

Ifueko Omoigui-Okauru

 

4

4

Meeting dates:17 January, 10 April, 13 July, 12 October.

Corporate Social Responsibility Committee

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

Lord Mark Malloch-Brown

Chairman

3

3

2.

Macaulay Agbada Ofurhie

 

3

3

3.

Ifueko Omoigui-Okauru

 

3

3

Meeting dates:18 April, 17 July, 24 October.

Gas Committee

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

Basil Omiyi

Chairman

2

2

2.

Macaulay Agbada Ofurhie

 

2

2

3.

Michael Alexander

 

2

2

Meeting dates:17 July, 25 October.

Statutory Audit Committee

S/N

Name

 

No. of Meetings
in the year

No. of times
in Attendance

1.

Chief Anthony Idigbe, SAN

Chairman

4

4

2.

Dr. Faruk Umar

Shareholder Member

4

4

3.

Sir Sunday Nnamdi Nwosu

Shareholder Member

4

4

4.

Michel Hochard

Director Member

4

3

5.

Ifueko Omoigui Okauru

Director Member

4

3

6.

Macaulay Agbada Ofurhie 

Director Member

4

4

Meeting dates: 22 February, 18 April, 16 July, 24 October.

Directors' interest in shares

In accordance with Section 275 of the Companies and Allied Matters Act, CAP C20 LFN 2004, the interests of the Directors (and of persons connected with them) in the share capital of the Company (all of which are beneficial unless otherwise stated) are as follows:

 

31-Dec-17

31-Dec-18

 

28-Feb-19

As a percentage
of Ordinary
Shares in issue 

 

No. of

Ordinary Shares

No. of

Ordinary Shares

As a percentage
of Ordinary
Shares in issue 

No. of
Ordinary Shares

A.B.C. Orjiako(1)

47,251,325

45,951,325

7.81%

45,951,325

7.81%

Austin Avuru (2)

74,546,740

70,823,189

12.04%

70,823,189

12.04%

Roger Brown

807,942

1,327,207

0.23%

1,327,207

0.23%

Effiong Okon

n/a

0

0.00%

0

0.00%

Michel Hochard

95,238

95,238

0.02%

95,238

0.02%

Macaulay Agbada Ofurhie

4,901,611

4,001,611

0.68%

4,001,611

0.68%

Michael Alexander

105,238

115,238

0.02%

115,238

0.02%

Charles Okeahalam

597,238

495,238

0.08%

495,238

0.08%

Basil Omiyi

495,238

495,238

0.08%

495,238

0.08%

Ifueko Omoigui Okauru

95,238

95,238

0.02%

95,238

0.02%

Lord Mark Malloch-Brown

31,746

31,746

0.01%

31,746

0.01%

Damian Dodo

0

0

0.00%

0

0.00%

Total

128,927,554

123,431,268

 

20.98%

 

123,431,268

 

20.98%

 

 

Notes:

(1)      16,151,325 ordinary shares are held directly by A.B.C. Orjiako and Shebah Petroleum Development Company Limited; 16,300,000 ordinary shares are held by Vitol Energy Limited for the benefit of Shebah Petroleum Development Company Limited, which is an entity controlled by A.B.C. Orjiako and members of his family; 900,000 ordinary shares are held by Pursley Resources Limited, a company owned by A.B.C's wife; and 12,600,000 ordinary shares are held directly by A.B.C. Orjiako's siblings

(2)      27,217,010 ordinary shares are held by Professional Support Limited and 1,920,000 ordinary shares are held by Abtrust Integrated Services Limited, each of which is an entity controlled by Austin Avuru. 40,659,695 ordinary shares, are held by Platform Petroleum Limited, which is an entity in which Austin Avuru has a 23% equity interest (during the year, 3,500,305 shares previously held through Platform Petroleum Limited are now directly held by certain shareholders of Platform and are therefore not considered to be connected persons) and 1,026,484 ordinary shares are held by Austin Avuru.

Director's interest in contracts

The Chairman and the Chief Executive Officer have disclosable indirect interest in contracts with which the Company was involved as at 31 December 2018 for the purpose of section 277 of the Companies and Allied Matters Act, CAP C20, LFN, 2004. These have been disclosed in note 31.

Substantial interest in shares

According to the register of members at 31 December 2018 and also the date of this report, the following shareholders held more than 5.0% of the issued share capital of the Company:

Shareholder

Number of Holdings 

%

CIS PLC - MAIN(1)

414,415,996

70.43

Platform Petroleum Limited

40,659,695

 6.91

(1)CIS PLC - MAIN is made up of the total shareholdings held in the UK by the registrars.

Free float

The Company's free float at 31 December 2018 was 52.47%

Acquisition of own shares

The Company did not acquire any of its shares during the year.

Shareholding analysis

The shareholding pattern as at 31 December 2018 is as stated below: 

Share Range

Number of Shareholders

% of
Shareholders

Number of
Holdings

%
Shareholding

1-10,000

1,921

86.3371

1,445,520

0.2457

10,001-50,000

148

6.6517

3,813,454

0.6481

50,001-100,000

50

2.2472

3,642,452

0.6190

100,001-500,000

68

3.0562

16,237,145

2.7593

500,001-1,000,000

14

0.6292

10,867,172

1.8468

1,000,001-5,000,000

18

0.8090

39,755,584

6.7560

5,000,001-10,000,000

2

0.0899

13,506,800

2.2953

10,000,001-50,000,000

3

0.1348

84,760,438

14.4042

50,000,001-100,000,000

0

0.0000

0

0.0000

100,000,001-500,000,000

1

0.0449

414,415,996

70.4257

Total

2,225

100.0000

588,444,561

100.0000

 

Share Capital History

Year

Authorised increase

 Cummulative

Issued  increase

 Cummulative

Consideration

Jun-09

-

100,000,000

100,000,000

100,000,000

cash

Mar-13

100,000,000

200,000,000

100,000,000

200,000,000

stock split from N1.00 to 50k

Jul-13

200,000,000

400,000,000

200,000,000

400,000,000

bonus (1 for 2)

Aug-13

600,000,000

1,000,000,000

153,310,313

553,310,313

cash

Dec-14

-

1,000,000,000

-

553,310,313

No change

Dec-15

-

1,000,000,000

10,134,248

563,444,561

staff share scheme

Dec-16

-

1,000,000,000

-

563,444,561

No change

Dec-17

-

1,000,000,000

-

563,444,561

No change

Feb-18

-

1,000,000,000

25,000,000

588,444,561

staff share scheme

 

Donations

The following donations were made by the Group during the year (2017: N105,361,000; US$344,535).

 

Name of beneficiary

N'000

 US$

AOW Conference

 805

 2,634

Augustine University

 46,125

 150,571

Brandzone Innovations

 338

 1,104

Chartered institute of procurement

 608

 1,988

Edo festival

 900

 2,941

Ehimade Nigeria Limited

 7,200

 23,556

Energy Institute

 2,186

 7,152

Lagos Caledonian Society

 450

 1,469

Lagos Institute of Public Relation

 225

 733

Lagos state security trust fund

 900

 2,943

Malabite Magazine

 180

 589

Ministry of Oil and Gas

 900

 2,941

National Identity Management Commission

 90

 296

National Oil spill detection and response agency

 4,041

 13,220

National Orthopedic Hospital

 900

 2,943

Nigeria LP Gas Association

 675

 2,202

Nigerian Army

 900

 2,934

Nigerian Association of Petroleum Explorationists

 11,700

 38,294

Nigerian Conservation centre

 450

 1,466

Nigerian Conservation Foundation

 225

 734

Nigerian Environmental Society

 1,215

 3,975

Nigerian Gas Association

 4,126

 13,500

Nigerian Oil and Gas Industry Games

 135

 442

Nigerian Orthopaedic Association

 675

 2,208

Nigerian Sport Media Awards

 1,163

 3,792

NNPC Postgraduate scholarship

 1,350

 4,397

NNPC undergraduate scholarship

 12,015

 39,286

Oben Cottage Hospital

 236

 771

Okparavero Memorial Hosipital

 4,712

 15,416

Others

 5,178

 16,927

Pearl Awards

 223

 727

Petroleum Technology Association

 2,751

 9,000

Society of Petroleum Engineer

 5,069

 16,583

Soja Magazine

 113

 366

St. Saviours Hospital

 900

 2,945

The Institute of Internal Auditors Nigeria

 225

 736

The Niche Newspaper

 450

 1,472

Tribalmarks Media production

 450

 1,472

Union of National Africa paediatric societies

 900

 2,945

Total

121,683

397,672

 

Employment and employees

a)

Employees involvement and training: The Company continues to observe industrial relations practices such as joint Consultative Committee and briefing employees on the developments in the Company during the year under review. Various incentive schemes for staff were maintained during the year while regular training courses were carried out for the employees. Educational assistance is provided to members of staff. Different cadres of staff were also assisted with payment of subscriptions to various professional bodies during the year. The Company provides appropriate HSSE training to all staff, and Personal Protective Equipment ('PPE') to the appropriate staff.

b)

Health, safety and welfare of employees: The Company continues to enforce strict health and safety rules and practices at the work environment which are reviewed and tested regularly. The Company provides free medical care for its employees and their families through designated hospitals and clinics. Fire prevention and fire-fighting equipment are installed in strategic locations within the Company's premises. The Company operates Group life insurance cover for the benefit of its employees. It also complies with the requirements of the Pension Reform Act, 2004 regarding its employees.

c)

Employment of disabled or physically challenged persons: The Company has a policy of fair consideration of job applications by disabled persons having regard to their abilities and aptitude. The Company's policy prohibits discrimination of disabled persons in the recruitment, training and career development of its employees.  As at the end of the reporting period, the Group has no disabled persons in employment.

 

Auditor

The Auditor, Ernst & Young, has indicated its willingness to continue in office in accordance with Section 357(2) of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria, 2004. A resolution will be proposed for the re-appointment of Ernst & Young as the Company's Auditor and for authorization to the Board of Directors to fix Auditor's remuneration.

By Order of the Board

 

Dr. Mirian Kene Kachikwu

FRC/2015/NBA/00000010739

Company Secretary,

Seplat Petroleum Development Company Plc

25a Lugard Avenue

Ikoyi, Lagos

Nigeria

 

Date:   6 March 2019

 

Statement of directors' responsibilities

For the year ended 31 December 2018

The Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004, requires the Directors to prepare financial statements for each financial year that give a true and fair view of the state of financial affairs of the Group at the end of the year and of its profit or loss. The responsibilities include ensuring that the Group:

1.    keeps proper accounting records that disclose, with reasonable accuracy, the financial position of the Group and comply with the requirements of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004;

2.    establishes adequate internal controls to safeguard its assets and to prevent and detect fraud and other irregularities; and

3.    prepares its financial statements using suitable accounting policies supported by reasonable and prudent judgments and estimates, and are consistently applied.

The Directors accept responsibility for the annual financial statements, which have been prepared using appropriate accounting policies supported by reasonable and prudent judgments and estimates, in conformity with International Financial Reporting Standards (IFRS), the requirements of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004 and Financial Reporting Council of Nigeria Act, No. 6, 2011.

The Directors are of the opinion that the financial statements give a true and fair view of the state of the financial affairs of the Group and of its financial performance and cashflows for the year. The Directors further accept responsibility for the maintenance of accounting records that may be relied upon in the preparation of financial statements, as well as adequate systems of internal financial control.

Nothing has come to the attention of the Directors to indicate that the Group will not remain a going concern for at least twelve months from the date of this statement.

Signed on behalf of the Directors by:

 

A.B.C Orjiako

ChairmanChief

FRC/2014/IODN/00000003161

6 March 2019   

 

Austin Avuru

Executive Officer

FRC/2014/IODN/00000003100

6 March 2019

 

Audit Committee's Report

For the year ended 31 December 2018

To the members of Seplat Petroleum Development Company Plc

 

In accordance with the provisions of Section 359 (6) of the Companies and Allied Matters Act, CAP C20, LFN 2004, members

of the Audit Committee of Seplat Petroleum Development Company Plc hereby report on the financial statements of the

Group for the year ended 31 December 2018 as follows:

 

   The scope and plan of the audit for the year ended 31 December 2018 were adequate;

   We have reviewed the financial statements and are satisfied with the explanations and comments obtained;

   We have reviewed the external auditors' management letter for the year and are satisfied with the management's

   responses and that management has taken appropriate steps to address the issues raised by the Auditors;

   We are of the opinion that the accounting and reporting policies of the Company are in accordance with legal   requirements and ethical practices.

 

The external Auditors confirmed having received full co-operation from the Company's management in the course of the

statutory audit and that the scope of their work was not restricted in any way.

 

Dated this 6th day of March 2019

 

Chief Anthony Idigbe, S.A.N.

Chairman, Audit Committee

FRC/2015/NBA/00000010414

 

Ernst & Young

10th Floor, UBA House

57, Marina

Lagos, Nigeria

 

Tel: +234 (01) 844 996 2/3

Fax: +234 (01) 463 0481

Email: services@ng.ey.com

www.ey.com

 

 

 

 

Independent auditors' report

to the members of Seplat Petroleum Development Company Plc

 

 

Opinion

We have audited the consolidated financial statements of Seplat Petroleum Development Company Plc ("the Company") and its subsidiaries (together "the Group") which comprise:

 

Consolidated and Separate statement of profit or loss and other comprehensive income

For the year ended 31 December 2018

Consolidated and Separate statement of financial position as at 31 December 2018

Consolidated and Separate statement of changes in equity for the year ended 31 December 2018

Consolidated and Separate statement of cash flows for the year ended 31 December 2018

Related Notes to the Consolidated and Separate financial statements

 

In our opinion:

the consolidated and separate financial statements give a true and fair view of the financial position of the Group as at 31 December 2018, and of the Group's financial performance and cash flows for the year then ended;

the consolidated and separate financial statements of the Group have been properly prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB); and

the consolidated and separate financial statements of the Group have been prepared in accordance with the requirements of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004 and in compliance with the Financial Reporting Council of Nigeria Act, No. 6, 2011.

 

Basis for Opinion

We conducted our audit in accordance with International Standards on Auditing (ISAs). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the audit of the consolidated and separate financial statements section of our report. We are independent of the Group in accordance with the International Ethics Standards Board for Accountants' Code of Ethics for Professional Accountants (IESBA Code) and other independence requirements applicable to performing audits of Seplat Petroleum Development Company Plc and its Subsidiaries. We have fulfilled our other ethical responsibilities in accordance with the IESBA Code, and in accordance with other ethical requirements applicable to performing the audit of Seplat Petroleum Development Company Plc and its Subsidiaries. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

 

Key Audit Matters

Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the consolidated and separate financial statements of the current year. These matters were addressed in the context of our audit of the consolidated and separate financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. For the matter stated below, our description of how our audit addressed it is provided in that context.

 

We have fulfilled the responsibilities described in the auditors' responsibilities for the audit of the consolidated and separate financial statements section of our report, including in relation to this matter. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated and separate financial statements. The results of our audit procedures, including the procedures performed to address the matter below, provide the basis for our audit opinion on the accompanying consolidated and separate financial statements.

 

Key Audit Matter

How the matter was addressed in the audit

Impact of the estimation of the quantity of oil and gas reserves on impairment testing, depreciation, depletion and amortisation (DD&A), decommissioning provisions and the going concern assessment

As at 31 December 2018, Seplat reported 480.6 MMboe (2017: 477.2 MMboe) of proved plus probable reserves.

The estimation and measurement of oil and gas reserves impacts a number of material elements of the consolidated and separate financial statements including DD&A, decommissioning provisions and impairments.

This is a significant area of judgement due to the technical uncertainty in assessing reserve quantities and hence has been considered as a key audit matter.

We focused on management's estimation process, including whether bias exists in the determination of reserves and resources. We carried out the following procedures:

As a result of the technicality and uncertainty in assessing reserve quantities, we have assessed management's estimation process including whether bias exists in the determination of reserves and resources

We performed analytical review procedures on reserve revisions based on the CPR report which management obtained from Ryder Scott Company (RSC). As at December 2018, the group proved plus probable reserves was estimated at 480.6 million barrels (2017: 477.2 mmboe) with an increase in asset life from 2034 to 2037.

We have assessed RSC as experts and considered their objectivity, independence and competence which we found to be okay.

We reviewed disclosures in the Group financial statements to ensure consistency with the reserves data that we have reviewed.

 

 

 

Other Information

The directors are responsible for the other information. The other information comprises of the Report of the Directors, Audit Committee's Report, Statement of Directors' Responsibilities and Other National Disclosures, which we obtained prior to the date of this report, and the Annual Report, which is expected to be made available to us after that date. Other information does not include the consolidated financial statements and our auditors' report thereon.

 

Our opinion on the consolidated and separate financial statements does not cover the other information and we do not express an audit opinion or any form of assurance conclusion thereon.

 

In connection with our audit of the consolidated and separate financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the consolidated and separate financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated.

 

If, based on the work we have performed on the other information obtained prior to the date of this auditors' report, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

 

When we read the Annual Report, if we conclude that there is a material misstatement therein, we are required to communicate the matter to those charged with governance.

 

Responsibilities of the directors for the consolidated financial statements

The directors are responsible for the preparation and fair presentation of the consolidated and separate financial statements in accordance with International Financial Reporting Standards, the requirements of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004 and in compliance with the Financial Reporting Council of Nigeria Act, No. 6, 2011, and for such internal control as the directors determine is necessary to enable the preparation of  consolidated and separate financial statements that are free from material misstatement, whether due to fraud or error.

 

In preparing the consolidated and separate financial statements, the directors are responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Group's financial reporting processes.

 

Auditors' responsibilities for the audit of the consolidated and separate financial statements

Our objectives are to obtain reasonable assurance about whether the consolidated and separate financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors' report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated and separate financial statements.

 

As part of an audit in accordance with ISAs, we exercise professional judgement and maintain professional scepticism throughout the audit. We also:

 

Identify and assess the risks of material misstatement of the consolidated and separate financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group's internal control.

Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the directors.

Conclude on the appropriateness of the directors' use of the going concern basis of accounting and based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditors' report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditors' report. However, future events or conditions may cause the Group to cease to continue as a going concern.

Evaluate the overall presentation, structure and content of the consolidated and separate financial statements, including the disclosures, and whether the consolidated and separate financial statements represent the underlying transactions and events in a manner that achieves fair presentation.

Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated and separate financial statements. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion.

 

We communicate with the directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

 

We also provide the directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

 

From the matters communicated with the directors, we determine those matters that were of most significance in the audit of the consolidated and separate financial statements of the current year and are therefore the key audit matters. We describe these matters in our auditors' report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

 

Report on other legal and regulatory requirements

In accordance with the requirement of Schedule 6 of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004, we confirm that:

 

i)

we have obtained all the information and explanations which to the best of our knowledge and belief were necessary for the purpose of our audit;

ii)

in our opinion, proper books of account have been kept by the Group, so far as appears from our examination of those books;

iii)

the statement of financial position and profit or loss and other comprehensive income are in agreement with the books of account; and

iv)

in our opinion, the consolidated and separate financial statements have been prepared in accordance with the provisions of the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004 so as to give a true and fair view of the state of affairs and financial performance.

 

 

Bernard Carrena, FCA

FRC/2013/ICAN/00000000670

Partner

For: Ernst & Young

Lagos, Nigeria.

6 March 2019

 

Consolidated financial statements

Statement of profit or loss and other comprehensive income

For the year ended 31 December 2018

 

 

 

 

 

 

 

31 Dec 2018

31 Dec 2017

31 Dec 2018

31 Dec 2017

 

 

Notes

million

million

$'000

$'000

 

 

 

 

 

 

 

 

Revenue

7

 228,391

 138,281

 746,140

 452,179

 

Cost of sales

8

 (108,641)

 (73,414)

 (354,926)

 (240,059)

 

Gross profit

 

 119,750

 64,867

 391,214

 212,120

 

Other income - net

9

 4,618

209

 15,085

682

 

General and administrative expenses

10

 (24,417)

 (28,175)

 (79,769)

 (92,130)

 

(Impairment)/reversal of losses on financial assets - net

11

 (4,483)

3,138  

 (14,643)

10,260

 

Fair value loss - net

12

 (593)

 (5,663)

 (1,936)

 (18,518)

 

Operating profit

 

 94,875

 34,376

 309,951

 112,414

 

Finance income

13

 3,032

 1,326

 9,905

 4,335

 

Finance cost

13

 (17,292)

 (22,248)

 (56,492)

 (72,752)

 

Profit before taxation

 

 80,615

 13,454

 263,364

 43,997

 

Income tax (expense)/credit

14

 (35,748)

 67,657

 (116,788)

 221,233

 

Profit for the year

 

 44,867

 81,111

 146,576

 265,230

 

Other comprehensive income:

 

 

 

 

 

 

Items that may be reclassified to profit or loss:

 

 

 

 

 

 

Foreign currency translation difference

 

2,283

 441

 1,244

(1,778)

 

Items that will not be reclassified to profit or loss:

 

 

 

 

 

 

Remeasurement of post-employment benefit obligations

33

 178

 (90)

 579

(294)

 

Deferred tax (expense)/credit on remeasurement (gains)/losses

14

 (80)

76

 (261)

250

 

 

 

 98

(14)

 318

(44)

 

Other comprehensive income/(loss) for the year(net of tax)

 

2,381

 427

 1,562

(1,822)

 

 

 

 

 

 

 

 

Total comprehensive income for the year(net of tax)

 

47,248

 81,538

   148,138

 263,408

 

 

 

 

 

 

 

 

Basic earnings per share ()/($)

35

79.04

 143.96

 0.26

 0.47

 

Diluted earnings per share ()/($)

35

77.36

141.89

 0.25

 0.46

 

               

*There is no revenue other than revenue from contracts with customers in 2018.

Notes 1 to 41 further on are an integral part of these financial statements.

 

Consolidated financial statements

Statement of financial position

As at 31 December 2018

 

 

 

31 Dec 2018

31 Dec 2017

31 Dec 2018

31 Dec 2017

 

Notes

million

million

$'000

$'000

ASSETS

 

 

 

 

 

Non-current assets

 

 

 

 

 

Oil & gas properties

17

 399,475

 393,377

 1,301,220

 1,286,387

Other property, plant and equipment

17

 1,300

 1,553

 4,237

 5,078

Other asset

18

 51,299

 66,368

 167,100

 217,031

Tax paid in advance

19

 9,708

9,670

 31,623

31,623

Prepayments

20

 7,950

 287

 25,893

939

Deferred tax

15

42,487

 68,417

138,393

 223,731

Total non-current assets

 

512,219

 539,672

 1,668,466

 1,764,789

Current assets

 

 

 

 

 

Inventories

22

 31,485

 30,683

 102,554

 100,336

Trade and other receivables

23

 41,874

 94,904

 136,393

 310,345

Prepayments

20

 3,549

 595

 11,561

 1,948

Contract assets

24

 4,327

 -  

 14,096

-

Derivative financial instruments

25

 2,693

 -  

 8,772

-

Cash and bank balances

26

 179,509

 133,699

 584,723

 437,212

Total current assets

 

 263,437

 259,881

 858,099

 849,841

Total assets

 

 775,656

 799,553

  2,526,565

 2,614,630

EQUITY AND LIABILITIES

 

 

 

 

 

Equity

 

 

 

 

 

Issued share capital

27

 286

 283

 1,834

 1,826

Share premium

27

 82,080

 82,080

 497,457

 497,457

Share based payment reserve

27

 7,298

 4,332

 27,499

 17,809

Capital contribution

28

 5,932

 5,932

 40,000

 40,000

Retained earnings

 

 192,723

 166,149

 1,030,954

 944,108

Foreign currency translation reserve

29

 203,153

 200,870

 3,141

 1,897

Total shareholders' equity

 

 491,472

 459,646

1,600,885

1,503,097   

Non-current liabilities

 

 

 

 

 

Interest bearing loans and borrowings

30

 133,799

 93,170

 435,827

 304,677

Contingent consideration

31

 5,676

 4,251

 18,489

 13,900

Provision for decommissioning obligation

32

 43,514

 32,510

 141,737

 106,312

Defined benefit plan

33

 1,819

 1,994

 5,923

 6,518

Total non-current liabilities

 

 184,808

 131,925

 601,976

 431,407

Current liabilities

 

 

 

 

 

Interest bearing loans and borrowings

30

 3,031

 81,159

 9,872

 265,400

Trade and other payables

34

 87,360

 125,559

 284,565

 410,593

Current tax liabilities

14

 8,985

 1,264

 29,267

 4,133

Total current liabilities

 

 99,376

 207,982

 323,704

 680,126

Total liabilities

 

 284,184

 339,907

 925,680

 1,111,533

Total shareholders' equity and liabilities

 

 775,656

 799,553

 2,526,565

 2,614,630

 

Notes 1 to 41 further on are an integral part of these financial statements.

The Group's financial statements of Seplat Petroleum Development Company Plc and its subsidiaries for the year ended 31 December 2018 were authorised for issue in accordance with a resolution of the Directors on 6 March 2019 and were signed on its behalf by:

 

A. B. C. Orjiako

A. O. Avuru

R.T. Brown 

FRC/2013/IODN/00000003161

FRC/2013/IODN/00000003100

FRC/2014/ANAN/00000017939

Chairman

Chief Executive Officer

Chief Financial Officer

6 March 2019

6 March 2019

6 March 2019

 

 

Consolidated financial statements

Statement of changes in equity

For the year ended 31 December 2018

 

Issued
share
capital

Share
premium

Share
based payment

reserve

Capital
contribution

Retained

earnings

Foreign

currency

translation

reserve

Total equity

 

million

million

million

million

million

million

million

At 1 January 2017

 283

 82,080

 2,597

 5,932

 85,052

 200,429

 376,373

Profit for the year

 -  

 -  

 -  

 -  

 81,111

 -  

 81,111

Other comprehensive (loss)/income

 -  

 -  

 -  

 -  

 (14)

 441

 427

Total comprehensive income for the year

 -  

 -  

 -  

 -  

 81,097

 441

 81,538

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

Share based payments (Note 27)

 -  

 -  

 1,735

 -  

 -  

 -  

 1,735

Total

 -  

 -  

 1,735

 -  

 -  

 -  

 1,735

At 31 December 2017 as originally presented

 283

 82,080

 4,332

 5,932

 166,149

 200,870

 459,646

Impact of change in accounting

policy:

 

 

 

 

 

 

 

Adjustment on initial application of IFRS 9 - net of tax (Note 41.1)

-

-

-

-

(355)

-

(355)

At 1 January 2018 - Restated

 283

 82,080

 4,332

 5,932

 165,794

 200,870

 459,291

Profit for the year

 -

 -

 -

 -

 44,867

 -  

44,867

Other comprehensive income

 -

 -

 -

 -

 98

 2,283

2,381

Total comprehensive  income for the year

 -

 -

 -

 -

 44,965

 2,283

47,248

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

Dividends paid

 -

 -

 -

 -

(18,036)

-

(18,036)

Share based payments (Note 27)

 -

 -

2,969

 -

 -

 -

2,969

Vested shares (Note 27)

 3

 -

(3)

 -

 -

 -

 -

Total

 3

 -  

2,966

-

 (18,036)

 -  

(15,067)

At 31 December 2018

 286

 82,080

7,298

5,932

192,723

 203,153

491,472

 

Notes 1 to 41 further on are an integral part of these financial statements.

 

Consolidated financial statements

Statement of changes in equity

For the year ended 31 December 2018

 

Issued
share
capital

Share
premium

Share
based payment

reserve

Capital
contribution

Retained

earnings

Foreign

currency

translation

reserve

Total

equity

 

$'000

$'000

$'000

$'000

$'000

$'000

$'000

At 1 January 2017

 1,826

 497,457

 12,135

 40,000

 678,922

 3,675

 1,234,015

Profit for the year

 -  

 -  

 -  

 -  

 265,230

 -  

 265,230

Other comprehensive loss

 -  

 -  

 -  

 -  

 (44)

 (1,778)

 (1,822)

Total comprehensive income/(loss) for the year

 -  

 -  

 -  

 -  

 265,186

 (1,778)

 263,408

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

Share based payments (Note 27)

 -  

 -  

 5,674

 -  

 -  

 -  

 5,674

Total

 -  

 -  

 5,674

 -  

 -  

 -  

 5,674

At 31 December 2017 as originally presented

 1,826

 497,457

 17,809

 40,000

 944,108

 1,897

1,503,097

Impact of change in accounting

policy:

 

 

 

 

 

 

 

Adjustment on initial application of IFRS 9 - net of tax (Note 41.1)

 -  

 -  

 -  

 -  

(1,160)

 -  

(1,160)

At 1 January 2018 - Restated

 1,826

 497,457

 17,809

 40,000

 942,948

 1,897

 1,501,937

Profit for the year

 -  

 -  

 -  

 -  

 146,576

 -  

 146,576

Other comprehensive income

 -  

 -  

 -  

 -  

 318

 1,244

 1,562

Total comprehensive  income for the year

 -  

 -  

 -  

 -  

 146,894

 1,244

 148,138

Transactions with owners in their capacity as owners:

 

 

 

 

 

 

 

Dividends paid

 -  

 -  

 -  

 -  

 (58,888)

 -  

 (58,888)

Share based payments (Note 27)

 -  

 -  

9,698

 -  

 -  

 -  

  9,698

Vested share (Note 27)

8

 -  

(8)

 -  

 -  

 -  

 -  

Total

 8

 -  

  9,690

 -  

 (58,888)

 -  

(49,190)

At 31 December 2018

 1,834

 497,457

  27,499

 40,000

 1,030,954

 3,141

  1,600,885

 

Notes 1 to 41 further on are an integral part of these financial statements.

Consolidated financial statements
Statement of cash flows

For the year ended 31 December 2018

 

 

31 Dec 2018

31 Dec 2017

31 Dec 2018

31 Dec 2017

 

Notes

million

million

$'000

$'000

Cash flows from operating activities

 

 

 

 

 

Cash generated from operations

16

 153,624

 136,870

501,750

 447,574

Defined benefits paid

 

 (63)

(163)  

 (206)

(532)

Net cash inflows from operating activities

 

 153,561

 136,707

 501,544

447,042

Cash flows from investing activities

 

 

 

 

 

Investment in oil and gas properties

17

(26,229)

 (9,777)

  (85,689)

 (31,970)

Investment in other property, plant and equipment

17

 (705)

 (459)

 (2,302)

 (1,500)

Proceeds from disposal of other property plant and equipment

17

 

71

 50

 

 231

 162

Receipts from sale of other asset

18

 14,777

 10,947

 48,276

 35,794

Payments for plan assets

33b

 (502)

 -  

 (1,635)

 

Interest received

13

 3,032

 1,326

 9,905

 4,335

Net cash (outflows)/inflows from investing activities

 

(9,556)

 2,087

(31,214)

6,821

Cash flows from financing activities

 

 

 

 

 

Repayments of loans

30

 (207,532)

 (29,970)

 (678,000)

 (98,000)

Proceeds from loans

30

 163,775

 -  

 535,045

 -

Dividends paid

36

 (18,036)

 -  

 (58,888)

 -

Principal repayments on crude oil advance

34a

 (23,193)

 -  

 (75,769)

-

Interest repayments on crude oil advance

34a

 (530)

 (1,770)

 (1,730)

(5,789)

Payments for other financing charges

30

 (1,809)

 -  

 (5,910)

-

Interest paid on bank financing

30

 (13,343)

 (21,213)

 (43,465)

 (69,366)

Net cash outflows from financing activities

 

 (100,668)

 (52,953)

 (328,717)

 (173,155)

Net increase in cash and cash equivalents

 

43,337

 85,841

141,613

 280,708

Cash and cash equivalents at beginning of the year

 

 133,699

 48,684

 437,212

 159,621

Effects of exchange rate changes on cash and cash equivalents

 

 

1,424

 (826)

 

2,480

 (3,117)

Cash and cash equivalents at end of the year

26

   178,460

 133,699

581,305

437,212

Notes 1 to 41 further on are an integral part of these financial statements. 

 

Notes to the consolidated financial statements

 

1.    Corporate Structure and business

Seplat Petroleum Development Company Plc ('Seplat' or the 'Company'), the parent of the Group, was incorporated on 17 June 2009 as a private limited liability company and re-registered as a public company on 3 October 2014, under the Companies and Allied Matters Act, CAP C20, Laws of the Federation of Nigeria 2004. The Company commenced operations on 1 August 2010. The Company is principally engaged in oil and gas exploration and production and gas processing activities.

The Company's registered address is: 25a Lugard Avenue, Ikoyi, Lagos, Nigeria.

The Company acquired, pursuant to an agreement for assignment dated 31 January 2010 between the Company, SPDC, TOTAL and AGIP, a 45% participating interest in the following producing assets:

OML 4, OML 38 and OML 41 located in Nigeria. The total purchase price for these assets was 50.4 billion ($340 million) paid at the completion of the acquisition on 31 July 2010 and a contingent payment of 4.8 billion ($33 million) payable 30 days after the second anniversary, 31 July 2012, if the average price per barrel of Brent Crude oil over the period from acquisition up to 31 July 2012 exceeds 11,850 ($80) per barrel. 53.1 billion ($358.6 million) was allocated to the producing assets including 2.8 billion ($18.6 million) as the fair value of the contingent consideration as calculated on acquisition date. The contingent consideration of ₦5.1 billion ($33 million) was paid on 22 October 2012.

In 2013, Newton Energy Limited ('Newton Energy'), an entity previously beneficially owned by the same shareholders as Seplat, became a subsidiary of the Company. On 1 June 2013, Newton Energy acquired from Pillar Oil Limited ('Pillar Oil') a 40% Participant interest in producing assets: the Umuseti/Igbuku marginal field area located within OPL 283 (the 'Umuseti/Igbuku Fields').

On 21 August 2014, the Group incorporated a new subsidiary, Seplat Petroleum Development UK. The subsidiary provides technical, liaison and administrative support services relating to oil and gas exploration activities.

On 12 December 2014, Seplat Gas Company Limited ('Seplat Gas') was incorporated as a private limited liability company to engage in oil and gas exploration and production and gas processing. On 12 December 2014, the Group also incorporated a new subsidiary, Seplat East Swamp Company Limited with the principal activity of oil and gas exploration and production.

In 2015, the Group purchased a 40% participating interest in OML 53, onshore north eastern Niger Delta (Seplat East Onshore Limited), from Chevron Nigeria Ltd for 43.5 billion ($259.4 million).

In 2017, the Group incorporated a new subsidiary, ANOH Gas Processing Company Limited. The principal activities of the Company is the processing of gas from OML 53.

The Company together with its other wholly owned subsidiaries namely, Newton Energy Limited, Seplat Petroleum Development Company UK Limited ('Seplat UK'), Seplat East Onshore Limited ('Seplat East'), Seplat East Swamp Company Limited ('Seplat Swamp'), Seplat Gas Company Limited ('Seplat gas'), ANOH Gas Processing Company Limited and Seplat West Limited are collectively referred to as the Group.

Subsidiary

Date of incorporation

Country of incorporation and place of business

Principal activities

Newton Energy Limited

1 June 2013

Nigeria

Oil & gas exploration and production

Seplat Petroleum Development Company UK Limited

21 August 2014

United Kingdom

Technical, liaison and administrative support services relating to oil & gas exploration and production

Seplat East Onshore Limited

12 December 2014

Nigeria

Oil & gas exploration and production

Seplat East Swamp Company Limited

12 December 2014

Nigeria

Oil & gas exploration and production

Seplat Gas Company Limited

12 December 2014

Nigeria

Oil & gas exploration and production and gas processing

ANOH Gas Processing Company Limited

18 January 2017

Nigeria

Gas processing

Seplat West Limited

16 January 2018

Nigeria

Oil & gas exploration and production and gas processing

 

2.    Significant changes in the current accounting period

The following significant changes occurred during the reporting year ended 31 December 2018:

The offering of 9.25% senior notes with an aggregate principal amount of 107 billion ($350 million) due in April 2023. The notes were issued by the Group in March 2018 and guaranteed by some of its subsidiaries. The proceeds of the notes are being used to refinance existing indebtedness and for general corporate purposes.

In March 2018, the Group obtained a 92 billion ($300 million) revolving facility to refinance an existing 92 billion ($300 million) revolving credit facility due in December 2018. The facility has a tenor of 4 years (due in June 2022) with an initial interest rate of the 6% +Libor. Interest is payable semi-annually and principal repayable annually. 61 billion ($200 million) was drawn down in March 2018. The proceeds from the notes are being used to repay existing indebtedness. In October 2018, the Group made a principal repayment of 30.7 billion ($100 million) out of its existing cash surplus.

25,000,000 additional shares were issued in furtherance of the Group's Long Term Incentive Plan, in February 2018. The additional issued shares, less 5,052,464 shares which vested in April 2018, are held by Stanbic IBTC Trustees Limited as Custodian. The Group's share capital as at the reporting date consists of 568,497,025 ordinary shares (excluding the additional shares held in trust) of 0.50k each, all with voting rights.

 

3.    Summary of significant accounting policies

3.1 Introduction to summary of significant accounting policies

This note provides a list of the significant accounting policies adopted in the preparation of these consolidated financial statements. These accounting policies have been applied to all the years presented, unless otherwise stated.

3.2 Basis of preparation          

 

i)             Compliance with IFRS

The consolidated financial statements of the Group for the year ended 31 December 2018 have been prepared in accordance with International Financial Reporting Standards ("IFRS") and interpretations issued by the IFRS Interpretations Committee (IFRS IC). The financial statements comply with IFRS as issued by the International Accounting Standards Board (IASB). Additional information required by National regulations is included where appropriate.

The financial statements comprise the statement of profit or loss and other comprehensive income, the statement of financial position, the statement of changes in equity, the statement of cash flows and the notes to the financial statements.     

ii)            Historical cost convention

The financial information has been prepared under the going concern assumption and historical cost convention, except for contingent consideration, and derivate financial instruments measured at fair value through profit or loss on initial recognition. The financial statements are presented in Nigerian Naira and United States Dollars, and all values are rounded to the nearest million ('million) and thousand ($'000) respectively, except when otherwise indicated.

iii)           Going concern

Nothing has come to the attention of the directors to indicate that the Group will not remain a going concern for at least twelve months from the date of these financial statements.

iv)            New and amended standards adopted by the Group

The Group has applied the following standards and amendments for the first time in the annual reporting period commencing 1 January 2018.

IFRS 9 Financial instruments, and

IFRS 15 Revenue from contracts with customers

Amendments to IFRS 15 Revenue from contracts with customers

The impact of the adoption of these standards and the new accounting policies are disclosed in note 41. Other new accounting standards effective for reporting periods beginning on or after 1 January 2018 did not have any impact on the Group's accounting policies and did not require retrospective adjustments to the financial statements.

v)             New standards, amendments and interpretations not yet adopted

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2018 reporting periods and have not been early adopted by the Group. The Group's assessment of the impact of these new standards and interpretations is set out below.

a.      IFRS 16 Leases

 

Title of standard

IFRS 16 Leases

Nature of change

IFRS 16 was issued in January 2016. It will result in almost all leases being recognised on the statement of financial position, as the distinction between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases. The accounting for lessors will not significantly change.

Impact

Operating leases: The standard will affect primarily the accounting for the Group's operating leases which include leases of drilling rigs, buildings and land. As at the reporting date, the Group had non-cancellable operating lease commitments (8 billion, $26 million).

Short term leases & low value leases: The Group's one-year contracts with no planned extension commitments mostly applicable to leased staff flats will be covered by the exception for short-term leases. Of these non-cancellable lease commitments, approximately 191.9 million ($0.6 million) relate to short-term leases. None of the Group's other leases will be covered by the exception for low value leases. Short term leases will be recognised on a straight line basis as an expense in profit or loss.

Service contracts: Some commitments such as contracts for the provision of drilling, cleaning and community services were identified as service contracts as they did not contain an identifiable asset which the Group had a right to control. It therefore did not qualify as leases under IFRS 16.

Right of use assets and lease liabilities: As at January 1 2019, the Group expects to recognise right-of-use assets and lease liabilities of approximately 6.8 billion, $22.2 million and 5.6 billion, $18.4 million respectively. The overall net current assets will be lower by approximately 141.4 million, $0.5 million due to the presentation of a portion of the liability as current liability. Cash flows from principal repayments would be recognised in financing activities while cash flows from interest repayments and short term lease payments would be recognised in operating activities.

The Group does not have arrangements where they are lessors.

Date of adoption

The standard for leases is mandatory for financial years commencing on or after 1 January 2019. The Group does not intend to adopt the standard before its effective date.

The Group intends to apply the modified retrospective approach and will not restate comparative amounts for the year prior to first adoption.

 

b.      Amendments to IAS 19 Employee benefits

These amendments were issued in February 2018. The amendments issued require an entity to use updated assumptions to determine current service cost and net interest for the remainder of the period after a plan amendment, curtailment or settlement. They also require an entity to recognise in profit or loss as part of past service cost or as a gain or loss on settlement, any reduction in a surplus, even if that surplus was not previously recognised because of the impact of the asset ceiling.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendments before its effective date and does not expect it to have a material impact on its current or future reporting periods.

c.       IFRIC 23 Uncertainty over income tax treatment

These amendments were issued in June 2017. IAS 12 Income taxes specifies requirements for current and deferred tax assets and liabilities. An entity applies the requirements in IAS 12 based on applicable tax laws. It may be unclear how tax law applies to a particular transaction or circumstance. The acceptability of a particular tax treatment under tax law may not be known until the relevant taxation authority or a court takes a decision in the future. Consequently, a dispute or examination of a particular tax treatment by the tax authority may affect an entity's accounting for a current or deferred tax asset or liability.

This Interpretation clarifies how to apply the recognition and measurement requirements in IAS 12 when there is uncertainty over income tax treatments. In such a circumstance, an entity shall recognise and measure its current or deferred tax asset or liability applying the requirements in IAS 12 based on taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates determined applying this Interpretation.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendments before its effective date and does not expect it to have a material impact on its current or future reporting periods.

d.      Conceptual framework for financial reporting - Revised

These amendments were issued in March 2018. Included in the revised conceptual framework are revised definitions of an asset and a liability as well as new guidance on measurement and derecognition, presentation and disclosure. The amendments focused on areas not yet covered and areas that had shortcomings.

These amendments are mandatory for annual periods beginning on or after 1 January 2020. The Group does not intend to adopt the amendments before its effective date and does not expect it to have a material impact on its current or future reporting periods.

e.      Amendments to IAS 23 Borrowing costs

These amendments were issued in December 2017. The amendments clarify that if any specific borrowing remains outstanding after the related asset is ready for its intended use or sale, that borrowing becomes part of the funds that an entity borrows generally when calculating the capitalisation rate on general borrowings.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendments before its effective date and does not expect it to have a material impact on its current or future reporting periods.

f.        Amendments to IAS 12 Income taxes

These amendments were issued in December 2017. These amendments clarify that all income tax consequences of dividends (including payments on financial instruments classified as equity) are recognized consistently with the transactions that generated the distributable profits. In effect, the income tax consequences of dividends are linked more directly to past transactions or events that generated distributable profits than to distributions to owners. Therefore, an entity shall recognise the income tax consequences of dividends in profit or loss, other comprehensive income or equity according to where the entity originally recognised those past transactions or events.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendments before its effective date and does not expect it to have a material impact on its current or future reporting periods.

g.       Amendments to IFRS 11 Joint arrangement

These amendments were issued in December 2017. These amendments clarify how a company accounts for increasing its interest in a joint operation that meets the definition of a business. If a party maintains (or obtains) joint control, then the previously held interest is not remeasured. If a party obtains control, then the transaction is a business combination achieved in stages and the acquiring party remeasures the previously held interest at fair value. In addition to clarifying when a previously held interest in a joint operation is remeasured, the amendments also provide further guidance on what constitutes the previously held interest. This is the entire previously held interest in the joint operation.

These amendments are mandatory for annual periods beginning on or after 1 January 2019. The Group does not intend to adopt the amendments before its effective date and does not expect it to have a material impact on its current or future reporting periods.

3.3 Basis of consolidation          

i)   Subsidiaries

Subsidiaries are all entities (including structured entities) over which the Group has control.

The consolidated financial information comprises the financial statements of the Company and its subsidiaries as at 31 December 2018. Control is achieved when the Group is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Specifically, the Group controls an investee if and only if the Group has:

   Power over the investee (i.e. existing rights that give it the current ability to direct the relevant activities of the investee);

   Exposure, or rights, to variable returns from its involvement with the investee; and

   The ability to use its power over the investee to affect its returns.

 

Subsidiaries are consolidated from the date on which control is obtained by the Group and are deconsolidated from the date control ceases.

Generally, there is a presumption that a majority of voting rights results in control. To support this presumption and when the Group has less than a majority of the voting or similar rights of an investee, the Group considers all relevant facts and circumstances in assessing whether it has power over an investee, including:

   The contractual arrangement(s) with the other vote holders of the investee

   Rights arising from other contractual arrangements

   The Group's voting rights and potential voting rights

 

ii)      Change in the ownership interest of subsidiary

The Group re-assesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control. Consolidation of a subsidiary begins when the Group obtains control over the subsidiary and ceases when the Group loses control of the subsidiary. Assets, liabilities, income and expenses of a subsidiary acquired or disposed off during the year are included in the statement of financial position and profit or loss and other comprehensive income from the date the Group gains control until the date the Group ceases to control the subsidiary.

Profit or loss and each component of OCI are attributed to the equity holders of the parent of the Group and to the non-controlling interests, even if this results in the non-controlling interests having a deficit balance. When necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies into line with the Group's accounting policies. All intra-group assets and liabilities, equity, income, expenses and cash flows relating to transactions between members of the Group are eliminated in full on consolidation.

The financial statements of the subsidiaries are prepared for the same reporting periods as the parent company using consistent accounting policies.

A change in the ownership interest of a subsidiary, without a loss of control, is accounted for as an equity transaction.

iii)    Disposal of subsidiary

If the Group loses control over a subsidiary, it:

   Derecognises the assets (including goodwill) and liabilities of the subsidiary;

   Derecognises the carrying amount of any non-controlling interests;

   Derecognises the cumulative translation differences recorded in equity;

   Recognises the fair value of the consideration received;

   Recognises the fair value of any investment retained;

   Recognises any surplus or deficit in profit or loss; and

   Reclassifies the parent's share of components previously recognised in OCI to profit or loss or retained earnings, as appropriate, as would be required if the Group had directly disposed of the related assets or liabilities.

 

vi)            Joint arrangements

Under IFRS 11 Joint Arrangements investments in joint arrangements are classified as either joint operations or joint ventures. The classification depends on the contractual rights and obligations of each investor, rather than the legal structure of the joint arrangement. As at the reporting date, the Group has joint operations and not joint ventures

vii)          Joint operations

The Group recognises its right to the assets, liabilities, revenues and expenses of joint operations and its share of any jointly held or incurred assets, liabilities, revenues and expenses. These have been incorporated in the financial statements under the appropriate headings.

The Group recognises its share in its accounting records as follows:

 

a)

Its share of the mineral properties which is shown within property, plant and equipment.

b)

Any liabilities that it has incurred.

c)

Its share of any liabilities incurred jointly with other venturers, including the decommissioning liability of production and field facilities.

d)

Any income from its sale or use of its share of the output.

e)

Any expenses that it has incurred, together with its share of any expenses incurred by the joint operation.

 

In addition to joint costs, the Group also incurs exclusive costs, which are fully borne by the Group.      

3.4 Functional and presentation currency

Items included in the financial statements of each of the Group's subsidiaries are measured using the currency of the primary economic environment in which the subsidiaries operate ('the functional currency'), which is the US dollar except the UK subsidiary which is the Pound Sterling. The consolidated financial statements are presented in Nigerian Naira and the US Dollars.

The Group has chosen to show both presentation currencies and this is allowable by the regulator.

i)       Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation of monetary assets and liabilities denominated in foreign currencies at year end are generally recognised in profit or loss.

Foreign exchange gains and losses that relate to borrowings are presented in the statement of profit or loss, within finance costs. All other foreign exchange gains and losses are presented in the statement of profit or loss on a net basis within other income or other expenses.

Non-monetary items that are measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss or other comprehensive income depending on where fair value gain or loss is reported.

ii)      Group companies

The results and financial position of foreign operations that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

assets and liabilities for each statement of financial position presented are translated at the closing rate.

income and expenses for statement of profit or loss and other comprehensive income are translated at average exchange rates (unless this is not - a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the respective exchange rates that existed on the dates of the transactions), and

all resulting exchange differences are recognised in other comprehensive income.

 

On disposal of a foreign operation, the component of other comprehensive income relating to that particular foreign operation is recognised in profit or loss.

3.5 Oil and gas accounting

i) Pre-licensing costs

Pre-license costs are expensed in the period in which they are incurred.

ii)      Exploration license cost

Exploration license costs are capitalised within oil and gas properties. License costs paid in connection with a right to explore in an existing exploration area are capitalised and amortised on a straight-line basis over the life of the permit.

License costs are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or firmly planned, or that it has been determined, or work is under way to determine that the discovery is economically viable based on a range of technical and commercial considerations and sufficient progress is being made to establish development plans and timing. If no future activity is planned or the license has been relinquished or has expired, the carrying value of the license is written off through profit or loss.

iii)    Acquisition of producing assets

Upon acquisition of producing assets which do not constitute a business combination, the Group identifies and recognises the individual identifiable assets acquired (including those assets that meet the definition of, and recognition criteria for, intangible assets in IAS 38 Intangible Assets) and liabilities assumed. The purchase price paid for the Group of assets is allocated to the individual identifiable assets and liabilities on the basis of their relative fair values at the date of purchase.

iv)     Exploration and evaluation expenditures

Geological and geophysical exploration costs are charged to profit or loss as incurred.

Exploration and evaluation expenditures incurred by the entity are accumulated separately for each area of interest. Such expenditures comprise net direct costs and an appropriate portion of related overhead expenditure, but do not include general overheads or administrative expenditure that is not directly related to a particular area of interest. Each area of interest is limited to a size related to a known or probable hydrocarbon resource capable of supporting an oil operation.

Costs directly associated with an exploration well, exploratory stratigraphic test well and delineation wells are temporarily suspended (capitalised) until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. If hydrocarbons ('proved reserves') are not found, the exploration expenditure is written off as a dry hole and charged to profit or loss. If hydrocarbons are found, the costs continue to be capitalised.

Suspended exploration and evaluation expenditure in relation to each area of interest is carried forward as an asset provided that one of the following conditions is met:

the costs are expected to be recouped through successful development and exploitation of the area of interest or alternatively, by its sale;

exploration and/or evaluation activities in the area of interest have not, at the reporting date, reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves; and

active and significant operations in, or in relation to, the area of interest are continuing.

 

Exploration and/or evaluation expenditures which fail to meet at least one of the conditions outlined above are written off. In the event that an area is subsequently abandoned or exploration activities do not lead to the discovery of proved or probable reserves, or if the Directors consider the expenditure to be of no value, any accumulated costs carried forward relating to the specified areas of interest are written off in the year in which the decision is made. While an area of interest is in the development phase, amortisation of development costs is not charged pending the commencement of production. Exploration and evaluation costs are transferred from the exploration and/or evaluation phase to the development phase upon commitment to a commercial development.

v)  Development expenditures

Development expenditure incurred by the entity is accumulated separately for each area of interest in which economically recoverable reserves have been identified to the satisfaction of the Directors. Such expenditure comprises net direct costs and, in the same manner as for exploration and evaluation expenditure, an appropriate portion of related overhead expenditure directly related to the development property. All expenditure incurred prior to the commencement of commercial levels of production from each development property is carried forward to the extent to which recoupment is expected to be derived from the sale of production from the relevant development property.

3.6 Revenue recognition

3.6.1 Revenue recognition (policy from 1 January 2018)

The Group has adopted IFRS 15 as issued in May 2014 which has resulted in changes in accounting policy of the Group. IFRS 15 replaces IAS 18 which covers revenue arising from the sale of goods and the rendering of services, IAS 11 which covers construction contracts, and related interpretations. In accordance with the transitional provisions in IFRS 15, comparative figures have not been restated as the Group has applied the modified retrospective approach in adopting this standard.

IFRS 15 introduces a five-step model for recognising revenue to depict transfer of goods or services. The model distinguishes between promises to a customer that are satisfied at a point in time and those that are satisfied over time.

It is the Group's policy to recognise revenue from a contract when it has been approved by both parties, rights have been clearly identified, payment terms have been defined, the contract has commercial substance, and collectability has been ascertained as probable. Collectability of customer's payments is ascertained based on the customer's historical records, guarantees provided, the customer's industry and advance payments made if any.

Revenue is recognised when control of goods sold has been transferred. Control of an asset refers to the ability to direct the use of and obtain substantially all of the remaining benefits (potential cash inflows or savings in cash outflows) associated with the asset. Seplat has two promises to its customers which is the sale of crude oil and gas. For crude oil, this occurs when the crude products are lifted by the customer (buyer) Free on Board at the Group's loading facility. Revenue from the sale of oil is recognised at a point in time when performance obligation is satisfied. For gas, revenue is recognised when the product passes through the custody transfer point to the customer. Revenue from the sale of gas is recognised over time using the practical expedient of the right to invoice.

The surplus or deficit of the product sold during the period over the Group's share of production in line with entitlement method is termed as an overlift or underlift. With regard to underlifts, if the over-lifter does not meet the definition of a customer or the settlement of the transaction is non-monetary, a receivable and other income is recognised. Conversely, when an overlift occurs, cost of sale is debited and a corresponding liability is accrued. Overlifts and underlifts are initially measured at the market price of oil at the date of lifting, consistent with the measurement of the sale and purchase. Subsequently, they are remeasured at the current market value. The change arising from this remeasurement is included in the profit or loss as other income/expenses-net.

Definition of a customer

A customer is a party that has contracted with the Group to obtain crude oil or gas products in exchange for a consideration, rather than to share in the risks and benefits that result from sale. The Group has entered into collaborative arrangements with its Joint arrangement partners to share in the production of oil. Collaborative arrangements with its Joint arrangement partners to share in the production of oil are accounted for differently from arrangements with customers as collaborators share in the risks and benefits of the transaction, and therefore, do not meet the definition of customers. Revenue arising from these arrangements are recognised separately in other income.

Contract enforceability and termination clauses

It is the Group's policy to assess that the defined criteria for establishing contracts that entail enforceable rights and obligations are met. The criteria provides that the contract has been approved by both parties, rights have been clearly identified, payment terms have been defined, the contract has commercial substance, and collectability has been ascertained as probable. Revenue is not recognised for contracts that do not create enforceable rights and obligations to parties in a contract. The Group also does not recognise revenue for contracts that do not meet the revenue recognition criteria. In such cases where consideration is received it recognises a contract liability and only recognises revenue when the contract is terminated. For crude oil and gas sales, contract is enforceable at the inception of the contract.

The Group may also have the unilateral rights to terminate an unperformed contract without compensating the other party. This could occur where the Group has not yet transferred any promised goods or services to the customer and the Group has not yet received, and is not yet entitled to receive, any consideration in exchange for promised goods or services.

Identification of performance obligation

At inception, the Group assesses the goods or services promised in the contract with a customer to identify as a performance obligation, each promise to transfer to the customer either a distinct good or series of distinct goods. The number of identified performance obligations in a contract will depend on the number of promises made to the customer. The delivery of barrels of crude oil or units of gas are usually the only performance obligation included in oil and gas contract with no additional contractual promises. Additional performance obligations may arise from future contracts with the Group and its customers.

The identification of performance obligations is a crucial part in determining the amount of consideration recognised as revenue. This is due to the fact that revenue is only recognised at the point where the performance obligation is fulfilled.

Management has therefore developed adequate measures to ensure that all contractual promises are appropriately considered and accounted for accordingly.

Transaction price

Transaction price is the amount allocated to the performance obligations identified in the contract. It represents the amount of revenue recognised as those performance obligations are satisfied. Complexities may arise where a contract includes variable consideration, significant financing component or consideration payable to a customer.

Variable consideration not within the Group's control is estimated at the point of revenue recognition and reassessed periodically. The estimated amount is included in the transaction price to the extent that it is highly probable that a significant reversal of the amount of cumulative revenue recognised will not occur when the uncertainty associated with the variable consideration is subsequently resolved. As a practical expedient, where the Group has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the Group's performance completed to date, the Group may recognise revenue in the amount to which it has a right to invoice.

Sales contracts for crude oil and gas often incorporates provisional pricing - at the date of delivery of the oil or gas, a provisional price is recognised as revenue. The amount of revenue to be recognised is estimated based on the market price of the commodity being sold at the delivery date. The final price is based on agreements between the Group and counterparty with any adjustments recognised within revenue. The existence of provisionally priced arrangements may result in variable consideration. The Group applies judgement to determine if there is an amount that is variable consideration and, if so, whether it is subject to a significant reversal. Such a reversal would occur if there were a significant downward adjustment of the cumulative amount of revenue recognised for that performance obligation.

For crude oil contracts, revenue recognition is delayed until the invoice date. As a result, crude contracts are not categorised as provisionally pricing contracts. However for gas contracts, revenue is recognised on the date of delivery at a provisional price. At the invoice date, revenue is marked to market with any adjustments being recognised in revenue. A lag period exists between the delivery of the gas and the date gas volumes are agreed. As a result of the differences in gas volumes that may give rise to variable quantities, the Group recognizes the corresponding transaction as contract assets until the point at which the variable consideration becomes unconditional, and is then considered a financial asset within the scope of IFRS 9.

Although variable considerations are subject to a constraint, revenue recognised as the performance obligation is satisfied is not subject to a significant reversal in future periods.

Significant financing component (SFC) assessment is carried out (using a discount rate that reflects the amount charged in a separate financing transaction with the customer and also considering the Group's incremental borrowing rate) on contracts that have a repayment period of more than 12 months.

As a practical expedient, the Group does not adjust the promised amount of consideration for the effects of a significant financing component if it expects, at contract inception, that the period between when it transfers a promised good or service to a customer and when the customer pays for that good or service will be one year or less.

Instances when SFC assessment may be carried out include where the Group receives advance payment for agreed volumes of crude oil or receives take or pay deficiency payment on gas sales. Take or pay gas sales contract ideally provides that the customer must sometimes pay for gas even when not delivered to the customer. The customer, in future contract years, takes delivery of the product without further payment. The portion of advance payments that represents significant financing component will be recognised as interest expense.

Consideration payable to a customer is accounted for as a reduction of the transaction price and, therefore, of revenue unless the payment to the customer is in exchange for a distinct good or service that the customer transfers to the Group. Examples include barging costs incurred, demurrage and freight costs. These do not represent a distinct service transferred and is therefore recognised as a direct deduction from revenue.

Breakage

The Group enters into take or pay contracts for sale of gas where the buyer may not ultimately exercise all of their rights to the gas. The take or pay quantity not taken is paid for by buyer called take or pay deficiency payment. The Group assesses if there is a reasonable assurance that it will be entitled to a breakage amount. Where it establishes that a reasonable assurance exists, it recognises the expected breakage amount as revenue in proportion to the pattern of rights exercised by the customer. However, where the Group is not reasonably assured of a breakage amount, it would only recognise the expected breakage amount as revenue when the likelihood of the customer exercising its remaining rights becomes remote.

Contract modification and contract combination

Contract modifications relate to a change in the price and/or scope of an approved contract. Where there is a contract modification, the Group assesses if the modification will create a new contract or change the existing enforceable rights and obligations of the parties to the original contract.

Contract modifications are treated as new contracts when the performance obligations are separately identifiable and transaction price reflects the standalone selling price of the crude oil or the gas to be sold. Revenue is adjusted prospectively when the crude oil or gas transferred is separately identifiable and the price does not reflect the standalone selling price.

The Group enters into new contracts with its customers only on the expiry of the old contract. In the new contracts, prices and scope may be based on terms in the old contract. In gas contracts, prices change over the course of time. Even though gas prices change over time, the changes are based on agreed terms in the initial contract i.e. price change due to consumer price index. The change in price is therefore not a contract modifications. Any other change expected to arise from the modification of a contract is implemented in the new contracts.

The Group combines contracts entered into at near the same time (less than 12 months) as one contract if they are entered into with the same or related party customer, the performance obligations are the same for the contracts and the price of one contract depends on the other contract.

Portfolio expedients

As a practical expedient, the Group may apply the requirements of IFRS 15 to a portfolio of contracts (or performance obligations) with similar characteristics if it expects that the effect on the financial statements would not be materially different from applying IFRS to individual contracts within that portfolio.

Contract assets and liabilities

The Group recognises contract assets for unbilled amounts from crude oil and gas sales. The Group recognises contract liability for consideration received for which performance obligation has not been met.

Disaggregation of revenue from contract with customers

The Group derives revenue from two types of products, oil and gas. The Group has determined that the disaggregation of revenue based on the criteria of type of products meets the disaggregation of revenue disclosure requirement of IFRS 15. It depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors. See further details in note 6.

3.6.2 Revenue recognition (policy prior to 1 January 2018)

Revenue arises from the sale of crude oil and gas. Revenue comprises the realised value of crude oil lifted by customers. Revenue is recognised when crude products are lifted by a third party (buyer) Free on Board ('FOB') at the Group's designated loading facility or lifting terminals. At the point of lifting, all risks and rewards are transferred to the buyer. Gas revenue is recognised when gas passes through the custody transfer point.

Overlift and underlift

The excess of the product sold during the period over the Group's ownership share of production is termed as an overlift and is accrued for as a liability and not as revenue. Conversely, an underlift is recognised as an asset and the corresponding revenue is also reported.            

Overlifts and underlifts are initially measured at the market price of oil at the date of lifting, consistent with the measurement of the sale and purchase.

Subsequently, they are remeasured at the current market value. The change arising from this remeasurement is included in the profit or loss as revenue or cost of sales.

 

3.7 Property, plant and equipment

Oil and gas properties and other plant and equipment are stated at cost, less accumulated depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of any decommissioning obligation and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Where parts of an item of property, plant and equipment have different useful lives, they are accounted for as separate items of property, plant and equipment.

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the entity, the expenditure is capitalised. Inspection costs associated with major maintenance programmes are capitalised and amortised over the period to the next inspection. Overhaul costs for major maintenance programmes are capitalised as incurred as long as these costs increase the efficiency of the unit or extend the useful life of the asset. All other maintenance costs are expensed as incurred.

Depreciation

Production and field facilities are depreciated on a unit-of-production basis over the estimated proved developed reserves. Assets under construction are not depreciated. Other property, plant and equipment are depreciated on a straight-line basis over their estimated useful lives. Depreciation commences when an asset is available for use. The depreciation rate for each class is as follows:

Plant and machinery

20%

Motor vehicles

25%

Office furniture and IT equipment

33.33%

Leasehold improvements

Over the unexpired portion of the lease

The expected useful lives and residual values of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

Gains or losses on disposal of property, plant and equipment are determined as the difference between disposal proceeds and carrying amount of the disposed assets. These gains or losses are included in profit or loss.

3.8 Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

Borrowing costs consist of interest and other costs incurred in connection with the borrowing of funds. These costs may arise from; specific borrowings used for the purpose of financing the construction of a qualifying asset, and those that arise from general borrowings that would have been avoided if the expenditure on the qualifying asset had not been made. The general borrowing costs attributable to an asset's construction is calculated by reference to the weighted average cost of general borrowings that are outstanding during the period.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on the qualifying assets is deducted from the borrowing costs eligible for capitalisation. All other borrowing costs are recognised in profit or loss in the period in which they are incurred.

3.9 Finance income and costs

Finance income

Finance income is recognised in the statement of profit or loss as it accrues using the effective interest rate (EIR), which is the rate that exactly discounts estimated future cash payments or receipts through the expected life of the financial instrument or a shorter period, where appropriate, to the amortised cost of the financial instrument. The determination of finance income takes into account all contractual terms of the financial instrument as well as any fees or incremental costs that are directly attributable to the instrument and are an integral part of the effective interest rate (EIR), but not future credit losses.

Finance cost

Finance costs includes borrowing costs, interest expense calculated using the effective interest rate method, finance charges in respect of lease liabilities, the unwinding of the effect of discounting provisions, and the amortisation of discounts and premiums on debt instruments that are liabilities.

3.10 Impairment of non-financial assets

Goodwill and intangible assets that have an indefinite useful life are not subject to amortisation and are tested annually for impairment, or more frequently. Other non -financial assets are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. This should be at a level not higher than an operating segment.

If any such indication of impairment exists or when annual impairment testing for an asset group is required, the entity makes an estimate of its recoverable amount. Such indicators include changes in the Group's business plans, changes in commodity prices, evidence of physical damage and, for oil and gas properties, significant downward revisions of estimated recoverable volumes or increases in estimated future development expenditure.

The recoverable amount is the higher of an asset's fair value less costs of disposal ('FVLCD') and value in use ('VIU'). The recoverable amount is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or group of assets, in which case, the asset is tested as part of a larger cash generating unit to which it belongs. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount.

Non-financial assets other than goodwill that suffered an impairment are reviewed for possible reversal of the impairment at the end of each reporting period.

In calculating VIU, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset/CGU. In determining FVLCD, recent market transactions are taken into account. If no such transactions can be identified, an appropriate valuation model is used. These calculations are corroborated by valuation multiples, quoted share prices for publicly traded companies or other available fair value indicators.

Impairment - exploration and evaluation assets

Exploration and evaluation assets are tested for impairment once commercial reserves are found before they are transferred to oil and gas assets, or whenever facts and circumstances indicate impairment. An impairment loss is recognised for the amount by which the exploration and evaluation assets' carrying amount exceeds their recoverable amount. The recoverable amount is the higher of the exploration and evaluation assets' fair value less costs to sell and their value in use.

Impairment - proved oil and gas production properties

Proven oil and gas properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs of disposal and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows.

3.11 Cash and bank balances

Cash and bank balances in the statement of cash flows comprise cash at banks and at hand and short-term deposits with an original maturity of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of change in value. Please see note 3.15.1(b) for accounting policies on impairment of cash and bank balances.

3.12 Inventories

Inventories represent the value of tubulars, casings and wellheads. These are stated at the lower of cost and net realisable value. Cost is determined using the invoice value and all other directly attributable costs to bringing the inventory to the point of use determined on a first in first out basis. Net realisable value is the estimated selling price in the ordinary course of business, less estimated costs of completion and the estimated cost necessary to make the sale.

3.13 Other asset

The Group's interest in the oil and gas reserves of OML 55 has been classified as other asset. On initial recognition, it is measured at the fair value of future recoverable oil and gas reserves.

 

Subsequently, the other asset is recognised at fair value through profit or loss.

 

3.14 Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker.

The Board of directors has appointed a steering committee which assesses the financial performance and position of the Group, and makes strategic decisions. The steering committee, which has been identified as the chief operating decision maker, consists of the chief financial officer, the general manager (Finance), the general manager (Gas) and the financial reporting manager. See further details in note 6.

3.15 Financial instruments

3.15.1 Financial instruments (policy from 1 January 2018)

 

The Group's accounting policies were changed to comply with IFRS 9. IFRS 9 replaces the provisions of IAS 39 that relate to the recognition, classification and measurement of financial assets and financial liabilities; derecognition of financial instruments; impairment of financial assets and hedge accounting. IFRS 9 also significantly amends other standards dealing with financial instruments such as IFRS 7 Financial Instruments: Disclosures.

a)    Classification and measurement

Financial assets

It is the Group's policy to initially recognise financial assets at fair value plus transaction costs, except in the case of financial assets recorded at fair value through profit or loss which are expensed in profit or loss.

Classification and subsequent measurement is dependent on the Group's business model for managing the asset and the cashflow characteristics of the asset. On this basis, the Group may classify its financial instruments at amortised cost, fair value through profit or loss and at fair value through other comprehensive income.

All the Group's financial assets as at 31 December 2018 satisfy the conditions for classification at amortised cost under IFRS 9 except derivative financial instruments which is measured at fair value through profit or loss.

The Group's financial assets include trade receivables, NPDC receivables, NAPIMS receivables, other receivables, derivative financial instruments and cash and bank balances. They are included in current assets, except for maturities greater than 12 months after the reporting date. Interest income from these assets is included in finance income using the effective interest rate method. Any gain or loss arising on derecognition is recognised directly in profit or loss and presented in finance income/cost.

Financial liabilities

Financial liabilities of the Group are classified and measured at fair value on initial recognition and subsequently at amortised cost net of directly attributable transaction costs, except for derivatives which are classified and subsequently recognised at fair value through profit or loss.

Fair value gains or losses for financial liabilities designated at fair value through profit or loss are accounted for in profit or loss except for the amount of change that is attributable to changes in the Group's own credit risk which is presented in other comprehensive income. The remaining amount of change in the fair value of the liability is presented in profit or loss. The Group's financial liabilities include trade and other payables and interest bearing loans and borrowings.

b)    Impairment of financial assets

Recognition of impairment provisions under IFRS 9 is based on the expected credit loss (ECL) model. The ECL model is applicable to financial assets classified at amortised cost and contract assets under IFRS 15: Revenue from Contracts with Customers. The measurement of ECL reflects an unbiased and probability-weighted amount that is determined by evaluating a range of possible outcomes, time value of money and reasonable and supportable information that is available without undue cost or effort at the reporting date, about past events, current conditions and forecasts of future economic conditions.

The Group applies the simplified approach or the three-stage general approach to determine impairment of receivables depending on their respective nature. The simplified approach is applied for trade receivables and contract assets while the general approach is applied to NPDC receivables, NAPIMS receivables, other receivables and cash and bank balances.

The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining the expected loss rates using a provision matrix that is based on the Group's historical default rates observed over the expected life of the receivable and adjusted forward-looking estimates. This is then applied to the gross carrying amount of the receivable to arrive at the loss allowance for the period.

The three-stage approach assesses impairment based on changes in credit risk since initial recognition using the past due criterion and other qualitative indicators such as increase in political concerns or other macroeconomic factors and the risk of legal action, sanction or other regulatory penalties that may impair future financial performance. Financial assets classified as stage 1 have their ECL measured as a proportion of their lifetime ECL that results from possible default events that can occur within one year, while assets in stage 2 or 3 have their ECL measured on a lifetime basis.

Under the three-stage approach, the ECL is determined by projecting the probability of default (PD), loss given default (LGD) and exposure at default (EAD) for each ageing bucket and for each individual exposure. The PD is based on default rates determined by external rating agencies for the counterparties. The LGD is determined based on management's estimate of expected cash recoveries after considering the historical pattern of the receivable, and it assesses the portion of the outstanding receivable that is deemed to be irrecoverable at the reporting period. The EAD is the total amount of outstanding receivable at the reporting period. These three components are multiplied together and adjusted for forward looking information, such as the gross domestic product (GDP) in Nigeria and crude oil prices, to arrive at an ECL which is then discounted back to the reporting date and summed. The discount rate used in the ECL calculation is the original effective interest rate or an approximation thereof.

Loss allowances for financial assets measured at amortised cost are deducted from the gross carrying amount of the related financial assets and the amount of the loss is recognised in profit or loss.

c)     Significant increase in credit risk and default definition

The Group assesses the credit risk of its financial assets based on the information obtained during periodic review of publicly available information, industry trends and payment records. Based on the analysis of the information provided, the Group identifies the assets that require close monitoring.

Furthermore, financial assets that have been identified to be more than 30 days past due on contractual payments are assessed to have experienced significant increase in credit risk. These assets are grouped as part of Stage 2 financial assets where the three-stage approach is applied.

In line with the Group's credit risk management practices, a financial asset is defined to be in default when contractual payments have not been received at least 90 days after the contractual payment period. Subsequent to default, the Group carries out active recovery strategies to recover all outstanding payments due on receivables. Where the Group determines that there are no realistic prospects of recovery, the financial asset and any related loss allowance is written off either partially or in full.

d)    Derecognition

Financial assets

The Group derecognises a financial asset when the contractual rights to the cash flows from the financial asset expire or when it transfers the financial asset and the transfer qualifies for derecognition. Gains or losses on derecognition of financial assets are recognised as finance income/cost.

Financial liabilities

The Group derecognises a financial liability when it is extinguished i.e. when the obligation specified in the contract is discharged or cancelled or expires. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised immediately in the statement of profit or loss.

e)    Modification 

When the contractual cash flows of a financial instrument are renegotiated or otherwise modified and the renegotiation or modification does not result in the derecognition of that financial instrument, the Group recalculates the gross carrying amount of the financial instrument and recognises a modification gain or loss immediately within finance income/(cost)-net at the date of the modification. The gross carrying amount of the financial instrument is recalculated as the present value of the renegotiated or modified contractual cash flows that are discounted at the financial instrument's original effective interest rate.

f)     Offsetting of financial assets and financial liabilities

Financial assets and liabilities are offset and the net amount is reported in the statement of financial position. Offsetting can be applied when there is a legally enforceable right to offset the recognised amounts, and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously.

The legally enforceable right is not contingent on future events and is enforceable in the normal course of business, and in the event of default, insolvency or bankruptcy of the Company or the counterparty.

g)     Derivatives

The Group uses derivative financial instruments such as forward exchange contracts to hedge its foreign exchange, risks as well as put options to hedge against its oil price risk. However, such contracts are not accounted for as designated hedges. Derivatives are initially recognised at fair value on the date a derivative contract is entered into and subsequently remeasured to their fair value at the end of each reporting period. Any gains or losses arising from changes in the fair value of derivatives are recognised within operating profit in profit or loss for the period. An analysis of the fair value of derivatives is provided in Note 5, Financial risk Management.

The Group accounts for financial assets with embedded derivatives (hybrid instruments) in their entirety on the basis of its contractual cash flow features and the business model within which they are held, thereby eliminating the complexity of bifurcation for financial assets. For financial liabilities, hybrid instruments are bifurcated into hosts and embedded features. In these cases, the Group measures the host contract at amortised cost and the embedded features is measured at fair value through profit or loss.

For the purpose of the maturity analysis, embedded derivatives included in hybrid financial instruments are not separated. The hybrid instrument, in its entirety, is included in the maturity analysis for non-derivative financial liabilities.

h)    Fair value of financial instruments

The Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When available, the Group measures the fair value of an instrument using quoted prices in an active market for that instrument. A market is regarded as active if quoted prices are readily available and represent actual and regularly occurring market transactions on an arm's length basis.

If a market for a financial instrument is not active, the Group establishes fair value using valuation techniques. Valuation techniques include using recent arm's length transactions between knowledgeable, willing parties (if available), reference to the current fair value of other instruments that are substantially the same, and discounted cash flow analysis. The chosen valuation technique makes maximum use of market inputs, relies as little as possible on estimates specific to the Group, incorporates all factors that market participants would consider in setting a price, and is consistent with accepted economic methodologies for pricing financial instruments.

Inputs to valuation techniques reasonably represent market expectations and measure the risk-return factors inherent in the financial instrument. The Group calibrates valuation techniques and tests them for validity using prices from observable current market transactions in the same instrument or based on other available observable market data.

The best evidence of the fair value of a financial instrument at initial recognition is the transaction price - i.e. the fair value of the consideration given or received. However, in some cases, the fair value of a financial instrument on initial recognition may be different to its transaction price. If such fair value is evidenced by comparison with other observable current market transactions in the same instrument (without modification or repackaging) or based on a valuation technique whose variables include only data from observable markets, then the difference is recognised in the income statement on initial recognition of the instrument. In other cases, the difference is not recognised in the income statement immediately but is recognised over the life of the instrument on an appropriate basis or when the instrument is redeemed, transferred or sold, or the fair value becomes observable.

3.15.2 Financial instruments (policy prior to 1 January 2018)

a)  Financial assets

i)   Financial assets initial recognition and measurement 

The Group determines the classification of its financial assets at initial recognition.

All financial assets are recognised initially at fair value plus transaction costs, except in the case of financial assets recorded at fair value through profit or loss which do not include transaction costs. The Group's financial assets include cash and short-term deposits, trade and other receivables, favourable derivatives and other receivables.

ii)   Subsequent measurement 

 

The subsequent measurement of financial assets depends on their classification, as follows:

Trade and other receivables

 

Trade and other receivables, which are non-derivative financial assets that have fixed or determinable payments that are not quoted in an active market, are classified as loans and receivables. They are included in the current assets, except for maturities greater than 12 months after the reporting date. The Group's receivables comprised of trade and other receivables in the consolidated historical financial information.

Loans and receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest rate method net of any impairment.A provision for impairment of trade receivables is established when there is objective evidence that the Group will not be able to collect all the amounts due according to the original terms of the receivable.

Significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganisation and default or delinquency in payments are considered as indicators that the trade receivable is impaired. The amount of the provision is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate.

The carrying amount of the asset is reduced through the use of an allowance account, and the amount of the loss is recognised in profit or loss. When a trade is uncollectable, it is written off against the allowance account for trade receivables.

iii)   Impairment of financial assets 

The Group assesses at each reporting date whether there is objective evidence that a financial asset or a group of financial assets is impaired. A financial asset or a group of financial assets is deemed to be impaired if there is objective evidence of impairment as a result of one or more events that has occurred since the initial recognition of the asset (an incurred loss event) and that loss event has an impact on the estimated future cash flows of the financial asset or the Group of financial assets that can be reliably estimated. Evidence of impairment may include indications that the debtor or a group of debtors is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganisation and observable data indicating that there is a measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults.

iv)   Derecognition of financial assets 

A financial asset is derecognised when the contractual rights to the cash flows from the financial asset expire. When an existing financial assets is transferred, the transfer qualifies for derecognition if the Group transfers the contractual rights to receive the cash flows of the financial asset or retains the contractual rights to receive the cash flows of the financial asset, but assumes a contractual obligation to pay the cash flows to one or more recipients in an arrangement.

b) Financial liabilities

Financial liabilities in the scope of IAS 39 are classified as financial liabilities at fair value through profit or loss, and financial liabilities at amortised cost as appropriate. The Group determines the classification of its financial liabilities at initial recognition.

 

i)      Financial liabilities initial recognition and measurement 

All financial liabilities are recognised initially at fair value and, in the case of loans and borrowings, net of directly attributable transaction costs.

The Group's financial liabilities include trade and other payables, and interest bearing loans and borrowings.

ii)   Subsequent measurement

The measurement of financial liabilities depends on their classification as described below:

Trade payables

Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Trade payables are classified as current liabilities if payment is due within one year or less. If not, they are presented as non-current liabilities.

Trade payables are recognised initially at fair value and subsequently measured at amortised cost using effective interest method.

Interest bearing loans and borrowings

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently carried at amortised cost while any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the statement of profit or loss over the period of borrowings using the effective interest method.

Fees paid on establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw down occurs. To the extent that there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a pre-payment for liquidity services and amortised over the period of the facility to which it relates.

iii)   Derecognition of financial liabilities 

A financial liability is derecognised when the associated obligation is discharged or cancelled or expired. When an existing financial liability is replaced by another from the same lender on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised in the statement of profit or loss.

c)  Derivative financial instruments

The Group uses derivative financial instruments, such as forward exchange contracts, to hedge its foreign exchange risks as well as put options to hedge against its oil price risk. However, such contracts are not accounted for as designated hedges. Derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently re-measured at fair value. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Any gains or losses arising from changes in the fair value of derivatives are taken directly to profit or loss and presented within operating profit.

Commodity contracts that were entered into and continue to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the Group's expected purchase, sale or usage requirements fall within the exemption from IAS 32 and IAS 39, which is known as the 'normal purchase or sale exemption'. For these contracts and the host part of the contracts containing embedded derivatives, they are accounted for as executory contracts. The Group recognises such contracts in its statement of financial position only when one of the parties meets its obligation under the contract to deliver either cash or a non-financial asset. An analysis of fair values of financial instruments and further details as to how they are measured are provided in Note 5 financial risk management.

d)  Fair value of financial instruments

The Group measures all financial instruments at initial recognition at fair value and financial instruments carried at fair value through profit and loss such as derivatives at fair value at each reporting date. From time to time, the fair values of non-financial assets and liabilities are required to be determined, e.g., when the entity acquires a business, or where an entity measures the recoverable amount of an asset or cash-generating unit ('CGU') at FVLCD.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.

A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use.

The Group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximising the use of relevant observable inputs and minimising the use of unobservable inputs. From time to time external valuers are used to assess FVLCD of the Group's non-financial assets. Involvement of external valuers is decided upon by the valuation committee after discussion with and approval by the Group's Audit Committee. Selection criteria include market knowledge, reputation, independence and whether professional standards are maintained. Valuers are normally rotated every three years. The valuation committee decides, after discussions with the Group's external valuers, which valuation techniques and inputs to use for each case.

Changes in estimates and assumptions about these inputs could affect the reported fair value. The fair value of financial instruments that are traded in active markets at each reporting date is determined by reference to quoted market prices or dealer price quotations (bid price for long positions and ask price for short positions), without any deduction for transaction costs.

3.16 Share capital

On issue of ordinary shares, any consideration received net of any directly attributable transaction costs is included in equity. Shares held by the Group are disclosed as treasury shares and deducted from equity. Issued share capital has been translated at the exchange rate prevailing at the date of the transaction and is not retranslated subsequent to initial recognition.

3.17 Earnings and dividends per share

Basic EPS

Basic earnings per share is calculated on the Group's profit or loss after taxation attributable to the parent entity and on the basis of weighted average of issued and fully paid ordinary shares at the end of the year.

Diluted EPS

Diluted EPS is calculated by dividing the profit or loss after taxation attributable to the parent entity by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares (after adjusting for outstanding share options arising from the share based payment scheme) into ordinary shares.

Dividends

Dividends on ordinary shares are recognised as a liability in the period in which they are approved.

3.18 Post-employment benefits

Defined contribution scheme

The Group contributes to a defined contribution scheme for its employees in compliance with the provisions of the Pension Reform Act 2014. The scheme is fully funded and is managed by licensed Pension Fund Administrators. Membership of the scheme is automatic upon commencement of duties at the Group. The Group's contributions to the defined contribution scheme are charged to the profit and loss account in the year to which they relate.

Employee benefits are all forms of consideration given by an entity in exchange for service rendered by employees or for the termination of employment. The Group operates a defined contribution plan and it is accounted for based on IAS 19 Employee benefits.

Defined contribution plans are post-employment benefit plans under which an entity pays fixed contributions into a separate entity (a fund) and will have no legal or constructive obligation to pay further contributions if the fund does not hold sufficient assets to pay all employee benefits relating to employee service in the current and prior periods. Under defined contribution plans the entity's legal or constructive obligation is limited to the amount that it agrees to contribute to the fund.

Thus, the amount of the post-employment benefits received by the employee is determined by the amount of contributions paid by an entity (and perhaps also the employee) to a post-employment benefit plan or to an insurance company, together with investment returns arising from the contributions. In consequence, actuarial risk (that benefits will be less than expected) and investment risk (that assets invested will be insufficient to meet expected benefits) fall, in substance, on the employee.

Defined benefit scheme

The Group operates a defined benefit gratuity plan, which requires contributions to be made to a separately administered fund. The Group also provides certain additional post-employment benefits to employees. These benefits are unfunded.

The cost of providing benefits under the defined benefit plan is determined using the projected unit credit method and calculated annually by independent actuaries. The liability or asset recognised in the balance sheet in respect of the defined benefit plan is the present value of the defined benefit obligation at the end of the reporting period less the fair value of plan assets (if any). The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using government bonds.

Remeasurements gains and losses, arising from changes in financial and demographic assumptions and experience adjustments, are recognised immediately in the statement of financial position with a corresponding debit or credit to retained earnings through OCI in the period in which they occur. Remeasurements are not reclassified to profit or loss in subsequent periods.

Past service costs are recognised in profit or loss on the earlier of:

   The date of the plan amendment or curtailment; and

   The date that the Group recognises related restructuring costs.

 

Net interest is calculated by applying the discount rate to the net defined benefit obligation and the fair value of the plan assets.

The Group recognises the following changes in the net defined benefit obligation under employee benefit expenses in general and administrative expenses:

   Service costs comprises current service costs, past-service costs, gains and losses on curtailments and non-routine settlements.

   Net interest cost

 

3.19 Provisions

Provisions are recognised when (i) the Group has a present legal or constructive obligation as a result of past events; (ii) it is probable that an outflow of economic resources will be required to settle the obligation as a whole; and (iii) the amount can be reliably estimated. Provisions are not recognised for future operating losses.

In measuring the provision:

risks and uncertainties are taken into account;

the provisions are discounted (where the effects of the time value of money is considered to be material) using a pretax rate that is reflective of current market assessments of the time value of money and the risk specific to the liability;

when discounting is used, the increase of the provision over time is recognised as interest expense;

future events such as changes in law and technology, are taken into account where there is subjective audit evidence that they will occur; and

gains from expected disposal of assets are not taken into account, even if the expected disposal is closely linked to the event giving rise to the provision.

Decommissioning

 

Liabilities for decommissioning costs are recognised as a result of the constructive obligation of past practice in the oil and gas industry, when it is probable that an outflow of economic resources will be required to settle the liability and a reliable estimate can be made. The estimated costs, based on current requirements, technology and price levels, prevailing at the reporting date, are computed based on the latest assumptions as to the scope and method of abandonment.

Provisions are measured at the present value of management's best estimates of the expenditure required to settle the present obligation at the end of the reporting period. The discount rate used to determine the present value is a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. The increase in the provision due to the passage of time is recognised as a finance cost. The corresponding amount is capitalised as part of the oil and gas properties and is amortised on a unit-of-production basis as part of the depreciation, depletion and amortisation charge. Any adjustment arising from the estimated cost of the restoration and abandonment cost is capitalised, while the charge arising from the accretion of the discount applied to the expected expenditure is treated as a component of finance costs.

If the change in estimate results in an increase in the decommissioning provision and, therefore, an addition to the carrying value of the asset, the Group considers whether this is an indication of impairment of the asset as a whole, and if so, tests for impairment in accordance with IAS 36. If, for mature fields, the revised oil and gas assets net of decommissioning provisions exceed the recoverable value, that portion of the increase is charged directly to expense.

3.20 Contingencies

A contingent asset or contingent liability is a possible asset or obligation that arises from past events and whose existence will be confirmed by the occurrence or non-occurrence of uncertain future events. The assessment of the existence of the contingencies will involve management judgement regarding the outcome of future events.

3.21.1 Contingent consideration

A contingent consideration to be transferred by the acquirer is recognised at fair value through profit or loss at the acquisition date by the Group. Contingent consideration classified as an asset or liability is measured at fair value in accordance with IFRS 13: Fair value Measurement with the changes in fair value recognised in the statement of profit or loss.

Financial liabilities at fair value through profit or loss are recorded in the statement of financial position at fair value. Changes in fair value are recorded in profit and loss with the exception of movements in fair value of liabilities designated at fair value through profit or loss due to changes in the Group's own credit risk. Such changes in fair value are recorded in the own credit reserve through other comprehensive income and are not get recycled to the profit or loss.

3.21 Income taxation

i) Current income tax

The tax expense for the period comprises current and deferred tax. Tax is recognised in the statement of profit or loss and other comprehensive income, except to the extent that it relates to items recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or directly in equity.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the balance sheet date in the country where Group operates and generates taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulations are subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities.

Taxation on crude oil activities is provided in accordance with the Petroleum Profits Tax Act ('PPTA') CAP. P13 Vol. 13 LFN 2004 and on gas operations in accordance with the Companies Income Tax Act ('CITA') CAP. C21 Vol. 3 LFN 2004. Education tax is assessed at 2% of the assessable profits.

ii) Deferred tax

Deferred tax is recognised, using the liability method, on temporary differences arising between the carrying amounts of assets and liabilities in the consolidated historical financial information and the corresponding tax bases used in the computation of taxable profit.

A deferred income tax charge is determined using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

Deferred tax liabilities are generally recognised for all taxable temporary differences. Deferred tax assets are generally recognised for all deductible temporary differences to the extent that it is probable that taxable profits will be available against which those deductible temporary differences can be utilised. Such deferred tax assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit. 

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.

iii) New Tax Regime

During the year 2013, applications were made by Seplat for the tax incentives available under the provisions of the Industrial Development (Income Tax Relief) Act. In February 2014, Seplat was granted the incentives in respect of the tax treatment of OMLs 4, 38 and 41. Under these incentives, the Company's profits were subject to a tax rate of 0% with effect from 1 January 2013 to 31 December 2015 in the first instance and then for an additional two years if certain conditions included in the Nigerian Investment Promotion Commission (NIPC) pioneer status award document were met. After the expiration of the initial three years, the company considered the extension and concluded that it would be of no benefit to the Company.

In May 2015, in line with Sections of the Companies Income Tax Act which provides incentives to companies that deliver gas utilisation projects, Seplat was granted a tax holiday for three years with a possible extension of two years. In 2018, on review of the performance of the business, the Company provided a notification to the Federal Inland Revenue Service (FIRS) for the extension of claim for the additional two years tax holiday.

Tax incentives do not apply to Seplat East Onshore Limited (OML 53) and Seplat East Swamp Company Limited (OML 55).Leases

 

The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at the inception date. The arrangement is assessed for whether fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use the asset or assets, even if that right is not explicitly specified in an arrangement.

Leases in which a significant portion of the risks and rewards of ownership are not transferred to the Group as lessee are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are charged to profit or loss on a straight-line basis over the period of the lease.

3.22 Share based payments

Employees (including senior executives) of the Group receive remuneration in the form of share-based payments, whereby employees render services as consideration for equity instruments (equity-settled transactions).

i)       Equity-settled transactions

The cost of equity-settled transactions is determined by the fair value at the date when the grant is made using an appropriate valuation model.

That cost is recognised in employee benefits expense together with a corresponding increase in equity (share based payment reserve), over the period in which the service and, where applicable, the performance conditions are fulfilled (the vesting period). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The expense or credit in profit or loss for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

Service and non-market performance conditions are not taken into account when determining the grant date and for fair value of awards, but the likelihood of the conditions being met is assessed as part of the Group's best estimate of the number of equity instruments that will ultimately vest. Market performance conditions are reflected within the grant date fair value. Any other conditions attached to an award, but without an associated service requirement, are considered to be non-vesting conditions. Non-vesting conditions are reflected in the fair value of an award and lead to an immediate expensing of an award unless there are also service and/or performance conditions.

No expense is recognised for awards that do not ultimately vest because non-market performance and/or service conditions have not been met. Where awards include a market or non-vesting condition, the transactions are treated as vested irrespective of whether the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied. When the terms of an equity-settled award are modified, the minimum expense recognised is the grant date fair value of the unmodified award, provided the original terms of the award are met. An additional expense, measured as at the date of modification, is recognised for any modification that increases the total fair value of the share-based payment transaction, or is otherwise beneficial to the employee. Where an award is cancelled by the entity or by the counterparty, any remaining element of the fair value of the award is expensed immediately through profit or loss. The dilutive effect of outstanding awards is reflected as additional share dilution in the computation of diluted earnings per share.

4.    Significant accounting judgements, estimates and assumptions

The preparation of the Group's consolidated historical financial information requires management to make judgements, estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities, and the accompanying disclosures, and the disclosure of contingent liabilities. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of assets or liabilities affected in future periods.

4.1 Judgements

In the process of applying the Group's accounting policies, management has made the following judgements, which have the most significant effect on the amounts recognised in the consolidated historical financial information:

i)     OMLs 4, 38 and 41

OMLs 4, 38, 41 are grouped together as a cash generating unit for the purpose of impairment testing. These three OMLs are grouped together because they each cannot independently generate cash flows. They currently operate as a single block sharing resources for the purpose of generating cash flows. Crude oil and gas sold to third parties from these OMLs are invoiced when the Group has an unconditional right to receive payment. 

ii)  New tax regime

Effective 1 January 2013, the Company was granted the inter tax status incentive by the Nigerian Investment Promotion Commission for an initial three-year period and a further two-year period on approval. For the period the incentive applies, the Company was exempted from paying petroleum profits tax on crude oil profits (at 85%), corporate income tax on natural gas profits (currently taxed at 30%) and education tax of 2%. After the expiration of the initial three years, the company considered the extension and concluded that it would be of no benefit to the business.

In May 2015, in line with Sections of the Companies Income Tax Act which provides incentives to companies that deliver gas utilisation projects, Seplat was granted a tax holiday for three years with a possible extension of two years. In 2018, on review of the performance of the business, the Company provided a notification to the Federal Inland Revenue Service (FIRS) for the extension of claim for the additional two years tax holiday.

The impact of the tax holiday has been considered in calculating the current income tax and deferred tax asset recognised in the financial statements.

Tax incentives do not apply to Seplat East Swamp Company Limited (OML 55) and Seplat East Onshore Limited (OML 53), as  they have no activities to which they would be entitled to tax incentives.

 

iii)  Deferred tax asset

Deferred tax assets are recognised for tax losses carried forward to the extent that the realisation of the related tax benefit through future taxable profits is probable. See further details in note 15.

iv)  Foreign currency translation reserve

The Group has used the CBN rule to translate its Dollar currency to its Naira presentation currency. Management has determined that this rate is available for immediate delivery. If the rate used was 10% higher or lower, revenue in Naira would have increased/decreased by 22.8 billion, 2017: 13.8 billion. See note 47 for the applicable translation rates.

v)  Revenue recognition

Definition of contracts

The Group has entered into a non-contractual promise with PanOcean where it allows Panocean to pass crude oil through its pipelines from a field just above Seplat's to the terminal for loading. Management has determined that the non-existence of an enforceable contract with Panocean means that it may not be viewed as a valid contract with a customer. As a result, income from this activity is recognised as other income when earned.

Performance obligations

The judgments applied in determining what constitutes a performance obligation will impact when control is likely to pass and therefore when revenue is recognised i.e. over time or at a point in time. The Group has determined that only one performance obligation exists in oil contracts which is the delivery of crude oil to specified ports. Revenue is therefore recognised at a point in time.

For gas contracts, the performance obligation is satisfied through the delivery of a series of distinct goods. Revenue is recognised over time in this situation as the customer simultaneously receives and consumes the benefits provided by the Group's performance. The Group has elected to apply the 'right to invoice' practical expedient in determining revenue from its gas contracts. The right to invoice is a measure of progress that allows the Group to recognise revenue based on amounts invoiced to the customer. Judgement has been applied in evaluating that the Group's right to consideration corresponds directly with the value transferred to the customer and is therefore eligible to apply this practical expedient.

Significant financing component

The Group has entered into an advance payment contract with Mercuria for future crude oil to be delivered. The Group has considered whether the contract contains a financing component and whether that financing component is significant to the contract, including both of the following;

(a) The difference, if any, between the amount of promised consideration and cash selling price and;

(b) The combined effect of both the following:

The expected length of time between when the Group transfers the crude to Mecuria and when payment for the crude is received and;

The prevailing interest rate in the relevant market.

 

The advance period is greater than 12 months. In addition, the interest expense accrued on the advance is based on a comparable market rate. Interest expense has therefore been included as part of finance cost.

Transactions with Joint Operating arrangement (JOA) partners

The treatment of underlift and overlift transactions is judgmental and requires a consideration of all the facts and circumstances including the purpose of the arrangement and transaction. The transaction between the Group and its JOA partners involves sharing in the production of crude oil, and for which the settlement of the transaction is non-monetary. The JOA partners have been assessed to be partners not customers. Therefore, shortfalls or excesses below or above the Group's share of production are recognised in other income/ (expenses) - net.

Barging costs

The Group refunds to Mercuria barging costs incurred on crude oil barrels delivered. The Group does not enjoy a separate service which it could have paid another party for. The barging costs is therefore determined to be a consideration payable to customer as there is no distinct goods or service being enjoyed by the Group. Since no distinct good or service is transferred, barging costs is accounted for as a direct deduction from revenue i.e. revenue is recognised net of barging costs.

 

vi)  Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker.

The Board of directors has appointed a steering committee which assesses the financial performance and position of the Group, and makes strategic decisions. The steering committee, which has been identified as being the chief operating decision maker, consists of the chief financial officer, the general manager (Finance), the general manager (Gas) and the financial reporting manager. See further details in note 6.

4.2 Estimates and assumptions

The key assumptions concerning the future and other key sources of estimation uncertainty at the reporting date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are described below. The Group based its assumptions and estimates on parameters available when the consolidated financial statements were prepared. Existing circumstances and assumptions about future developments may change due to market changes or circumstances arising that are beyond the control of the Group. Such changes are reflected in the assumptions when they occur.

vii)          Other asset

Seplat has recorded its rights to receive the discharge sum of 75.5 billion, 2017: 89.9 billion ($246 million, 2017: $294 million) from the crude oil reserves of OML 55 as other asset. The fair value is determined using the income approach in line with IFRS 13 (Discounted cashflow). The fair value of the other asset is disclosed in Note 18.

viii)         Contingent consideration

During the year the Group continued to recognise the contingent consideration of 5.7 billion, 2017: 5.6 billion ($18.5 million, 2017: $18.5 million) for OML 53 at the fair value of 5.7 billion, 2017: 4.2 billion ($18.5 million, 2017: $13.9 million). It is contingent on oil price rising above $90 ( 27,630)/bbl over a one year period and expiring on 31 January 2020. See details of the assumptions used in estimating the contigent consideration in note 5.2.

ix)            Defined benefit plans (pension benefits)

The cost of the defined benefit retirement plan and the present value of the retirement obligation are determined using actuarial valuations. An actuarial valuation involves making various assumptions that may differ from actual developments in the future. These include the determination of the discount rate, future salary increases, mortality rates and changes in inflation rates.

Due to the complexities involved in the valuation and its long-term nature, a defined benefit obligation is highly sensitive to changes in these assumptions. The parameter most subject to change is the discount rate. In determining the appropriate discount rate, management considers market yield on federal government bonds in currencies consistent with the currencies of the post-employment benefit obligation and extrapolated as needed along the yield curve to correspond with the expected term of the defined benefit obligation.

The rates of mortality assumed for employees are the rates published in 67/70 ultimate tables, published jointly by the Institute and Faculty of Actuaries in the UK.

x)             Oil and gas reserves

Proved oil and gas reserves are used in the units of production calculation for depletion as well as the determination of the timing of well closure for estimating decommissioning liabilities and impairment analysis. There are numerous uncertainties inherent in estimating oil and gas reserves. Assumptions that are valid at the time of estimation may change significantly when new information becomes available. Changes in the forecast prices of commodities, exchange rates, production costs or recovery rates may change the economic status of reserves and may ultimately result in the reserves being restated.

xi)            Share-based payment reserve

Estimating fair value for share-based payment transactions requires determination of the most appropriate valuation model, which depends on the terms and conditions of the grant. This estimate also requires determination of the most appropriate inputs to the valuation model including the expected life of the share award or appreciation right, volatility and dividend yield and making assumptions about them. The Group measures the fair value of equity-settled transactions with employees at the grant date. The assumptions and models used for estimating fair value for share-based payment transactions are disclosed in Note 27.

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. Such estimates and assumptions are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

xii)          Provision for decommissioning obligations

Provisions for environmental clean-up and remediation costs associated with the Group's drilling operations are based on current constructions, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.

xiii)         Property, plant and equipment

The Group assesses its property, plant and equipment, including exploration and evaluation assets, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable, or at least at every reporting date.

If there are low oil prices or natural gas prices during an extended period the Group may need to recognise significant impairment charges. The assessment for impairment entails comparing the carrying value of the cash-generating unit with its recoverable amount, that is, value in use. Value in use is usually determined on the basis of discounted estimated future net cash flows. Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and the outlook for regional market supply-and-demand conditions for crude oil and natural gas.

During the year, the Group carried out an impairment assessment on OML 4, 38 and 48, OML 56 and OML 53. The Group used the value in use in determining the recoverable amount of the cash-generating unit. In determining the value, the Group used a forecast of the annual net cash flows over the life of proved plus probable reserves, production rates, oil and gas prices, future costs and other relevant assumptions based on the 2018 year end CPR report. The pre-tax future cash flows were adjusted for risks specific to the forecast and discounted using a pre-tax discount rate of 10% which reflects both current market assessment of the time value of money and risks specific to the asset. The impairment test did not result in an impairment charge for both 2018 and 2017 reporting periods.

Management has considered whether a reasonable possible change in one of the main assumptions will cause an impairment and believes otherwise.

xiv)          Useful life of other property, plant and equipment

The Group recognises depreciation on other property, plant and equipment on a straight line basis in order to write-off the cost of the asset over its expected useful life. The economic life of an asset is determined based on existing wear and tear, economic and technical ageing, legal and other limits on the use of the asset, and obsolescence. If some of these factors were to deteriorate materially, impairing the ability of the asset to generate future cash flow, the Group may accelerate depreciation charges to reflect the remaining useful life of the asset or record an impairment loss.

xv)           Contingencies

By their nature, contingencies will only be resolved when one or more uncertain future events occur or fail to occur. The assessment of the existence, and potential quantum, of contingencies inherently involves the exercise of significant judgement and the use of estimates regarding the outcome of future events. See Note 39 for further details.

xvi)          Income taxes

The Group is subject to income taxes by the Nigerian tax authority, which does not require significant judgement in terms of provision for income taxes, but a certain level of judgement is required for recognition of deferred tax assets. Management is required to assess the ability of the Group to generate future taxable economic earnings that will be used to recover all deferred tax assets. Assumptions about the generation of future taxable profits depend on management's estimates of future cash flows. The estimates are based on the future cash flow from operations taking into consideration the oil and gas prices, volumes produced, operational and capital expenditure.

xvii)  Impairment of financial assets

The loss allowances for financial assets are based on assumptions about risk of default, expected loss rates and maximum contractual period. The Group uses judgement in making these assumptions and selecting the inputs to the impairment calculation, based on the Group's past history, existing market conditions as well as forward looking estimates at the end of each reporting period. Details of the key assumptions and inputs used are disclosed note 41.2.

5.    Financial risk management

5.1 Financial risk factors

The Group's activities expose it to a variety of financial risks such as market risk (including foreign exchange risk, interest rate risk and commodity price risk), credit risk and liquidity risk. The Group's risk management programme focuses on the unpredictability of financial markets and seeks to minimise potential adverse effects on the Group's financial performance.

Risk management is carried out by the treasury department under policies approved by the Board of Directors. The Board provides written principles for overall risk management, as well as written policies covering specific areas, such as foreign exchange risk, interest rate risk, credit risk and investment of excess liquidity.

Risk

Exposure arising from

Measurement

Management

Market risk - foreign exchange

Future commercial transactions

Recognised financial assets and liabilities not denominated in US dollars.

Cash flow forecasting

Sensitivity analysis

Match and settle foreign denominated cash inflows with foreign denominated cash outflows.

Market risk - interest rate

Interest bearing loans and borrowings at variable rate

Sensitivity analysis

Review refinancing opportunities

Market risk - commodity  prices

Future sales transactions

 

Sensitivity analysis

Oil price hedges

Credit risk

Cash and bank balances, trade and other receivables, contract assets and derivative financial instruments.

Aging analysis

Credit ratings

Diversification of bank deposits.

Liquidity risk

Borrowings and other liabilities

Rolling cash flow forecasts

Availability of committed credit lines and borrowing facilities

 

5.1.1 Market Risk

Market risk is the risk of loss that may arise from changes in market factors such as commodity prices, interest rates and foreign exchange rates.

j)      Commodity price risk

The Group is exposed to the risk of fluctuations on crude oil prices. The uncertainty around the rate at which oil prices increase or decline led to the Group's decision to enter into an option contract to insure the Group's revenue against adverse oil price movements.

On 17 December 2018, the Group entered economic crude oil hedge contracts with a strike price of 15,350 ($50/bbl) to N16,885 ($55/bbl) for 4 million barrels at an average premium price of 399 ($1.3/bbl) on 19 December 2018. These contracts, which will commence in 1 January 2019, are expected to reduce the volatility attributable to price fluctuations of oil. The Group has pre-paid a premium of N1.6 billion, 2017: nil ($5.2 million; 2017: nil) and has recognised an unrealised fair value gain of N2.7