Seplat Energy Regulatory News (SEPL)

Seplat Petroleum Development Company Plc

Unaudited results for the three months ended 31 March 2020

Lagos and London, 29 April 2020: Seplat Petroleum Development Company Plc ("Seplat" or the "Company"), a leading Nigerian independent oil and gas company listed on both the Nigerian Stock Exchange and the London Stock Exchange, today announces its unaudited results for the three months ended 31 March 2020.

Highlights

Operational

· Low unit cost of production at US$7.7/boe, with cost cutting initiatives now in force

· Working interest production within guidance at 48,491 boepd

· Liquids production of 33,368 bopd

· Gas production of 88 MMscfd

COVID-19 impact and mitigating actions

· Business continuity plan working successfully

· Oil field operations now working 28-day rotations (previously 14 days), with regular health checks

· Substantial support for local communities, donations of medical and protective equipment and food

Financial

· Cash at bank US$336 million, net debt of $458m

· Revenue of US$130 million, down 18.2% due to a stock build at the terminal (underlift) of $47m and lower oil prices.

· Non-current asset impairment provision of US$146 million in line with IAS 36 COVID-19 impact assessment

· Impairment provision reverses a profit for Q1 2020 of $39 million into a loss for the period of $107m.

· Impairment provision reduces non-current assets from $2.34 billion to $2.20 billion.

· Total capital expenditure of US$46 million

· Cash flow from operations US$65 million

Outlook

· Expected production of 47-57 kboepd (inc. Eland 6-10kbopd) for full year, subject to market conditions

· 1.5MMbbls/quarter hedged at $45/bbl from Q1 to Q3 2020

· Significant cash balance available

· Low cost of production enables profitability at levels below current oil price

· 2020 capex revised upwards to $120 million from $100 million, with two additional gas wells and related infrastructure.

Austin Avuru, Chief Executive Officer, said:

"Against the twin crises of significantly reduced oil demand and the price war, Seplat continues to demonstrate its resilience because of its ongoing philosophy of prudent financial management, the careful mitigation of risk and a keen focus on managing factors of the business that are within our control.

We have the benefit of long-term contracted gas revenues that are insulated from oil market volatility. We are achieving substantial cost reductions from our suppliers and managing our own costs even more carefully in this unprecedented and challenging period. We are in constant dialogue with partners on monies owed and are pleased to report that our cash flow remains robust and we have significant cash in reserve. This, coupled with the majority of our debt repayment obligations extending beyond 2021, gives us confidence that we can continue to operate comfortably within the covenants on all lines of debt.

To assist with the COVID-19 pandemic, we have provided medical and food donations as part of our ongoing commitment to our local and state communities and we will continue to do whatever we can to support those upon whom we depend for our business.

The challenges before us remain significant, but through our extensive scenario planning, we are confident that the resilience and discipline of our business will help us through this unprecedented time and strengthen our position as Nigeria's leading independent oil and gas producer."

Summary of performance

Outlook for 2020

The emergence of the COVID-19 pandemic in the first quarter of 2020, as well as pressure on oil prices in March, have placed a premium on solid financial management that focuses upon low-cost production, robust cash management, a strong balance sheet and focused investment in high-return projects for sustainable future growth.

The business is hedged against low oil prices and a significant proportion of our revenues now come from gas, which offers further protection from oil price volatility. The Company has low production costs and can remain profitable even at lower oil prices. We have significant cash resources available and will continue to manage our finances prudently in 2020, expecting now to invest $120 million of capital expenditure across the year, including two new gas wells and associated infrastructure. The completion of the ANOH project remains a major priority and we recently launched a financing package with responses expected from lenders in the coming weeks.

At present we are targeting 2020 production of between 47-57 kboepd, including Eland production of 6-10 kbopd, subject to continuous evacuation being possible.

Seplat has been tested in previous adverse conditions and we are confident that the stronger and more diverse business we operate today will be even more resilient against these unprecedented market events.

Enquiries:

Notes to editors

Seplat Petroleum Development Company Plc is Nigeria's leading indigenous oil and gas exploration and production company. It is listed on the Nigerian Stock Exchange (NSE: SEPLAT) and the Main Market of the London Stock Exchange (LSE: SEPL).

Seplat is pursuing a Nigeria-focused growth strategy and is well positioned to participate in future asset divestments by international oil companies, 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 unaudited and 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.

Operating review

Working interest production for the three months ended 31 March 2020

1. Liquid production volumes as measured at the LACT unit for OMLs 4, 38 and 41, OML40 and OPL 283 flow station. Volumes stated are subject to reconciliation and will differ from sales volumes within the period.

Average working interest production for the first quarter of 2020 was within guidance at 48,491 boepd, which represents an overall increase of 4.1% year-on-year. Within this, liquids production was up 52.5% to 33,368 bopd year-on-year whilst gas production was down 38.5% to 88 MMscfd year-on-year.

Production uptime stood at 78%, whilst the overall reconciliation losses arising from use of third-party infrastructure were around 12% for the period.

Oil business performance

Seplat's oil operations produced an average 33,368 bopd on a working interest basis in Q1 2020. This 52.5% increase reflects a contribution of 10,056 bopd from the recently acquired Eland's OML 40 production and higher production from OML 53.

During the period, three new development wells (Sap-35, Oben-48 and Ovh-06) were completed and the wells are expected to flow at a combined initial gross rate of approximately 4,200 bopd. The drilling of Ovhor-20 commenced and expected to be completed in the second quarter of 2020 with an expected initial flow rate of 2,500 bopd.

The average price realised per barrel in the first quarter of 2020 was US$49.85 (2019: US$69.73). The sharp dip in the oil price is attributed to the outbreak of the COVID-19 (coronavirus) which led to a significant decline in demand, at the same time as the activities of Saudi Arabia and Russia war were creating a supply glut with an inevitable collapse in global oil prices.

Integration of Eland Oil & Gas PLC

The integration process is being implemented over the course of the year and is led by an expert team that consists of technical, finance and operations personnel. The integration is proceeding well, achieving synergies, pooling of resources, increased efficiency of operations and streamlining of procedures.

Update on export route

The Amukpe to Escravos pipeline is set to provide a third export option for liquids production from OMLs 4, 38 and 41. While completion work on the 160kbopd pipeline has been slower than anticipated due to delays in the contractor delivery schedule, final activities have been delayed due to the COVID-19 pandemic lock down order. However, we expect that the pipeline will be commissioned during the first half of 2020 and become fully operational to the initial permitted volume for the Seplat / NPDC joint venture of 40 kbopd.

Gas business performance

Seplat's working interest production for the first quarter of 2020 was 88 MMscfd at an average selling price of US$2.89/Mscf. The currency adjustment by the CBN in the period from N306/$1 to N360/$1 was reflected in the month of March. This adjustment will have no impact on our gas revenues because they are priced in Dollars. We continue to receive payments for our gas from NGC and Azura.

Oben Gas Plant

The Company successfully completed a 15-day turnaround maintenance for the gas plant in March. Gas production was affected during the maintenance period and this impact was exacerbated by third-party infrastructure (TFP) downtime of 22%.

The Oben-48 well, drilled in late 2019, came onstream in the first quarter of 2020. A further two gas wells are planned for the year.

Sapele Gas Plant

Decommissioning works of the existing gas plant reached 80% completion in the period with complete decommissioning due to be completed in the second quarter of 2020. Schedule slippages are expected due to the COVID-19 pandemic and the project completion date is expected to be second half 2021 and will see an increase in processing capacity from 60 MMscfd to 75 MMscfd, and attain West African Gas Pipeline (WAGP) specifications.

ANOH gas plant development

The ANOH gas plant development at OML 53 will comprise a Phase One 300 MMscfd midstream gas processing plant.

The contractors (Zerock Construction Nigeria Ltd and Kenno-Mena Ltd) for the civil foundation works, plant roads and drainages have mobilised to site with work commenced. Having reviewed the construction schedule and progress on the OB3 gas pipeline, the project completion date has been revised from Q1 2021 to Q4 2021.The Company has assessed the effect of COVID-19 in equipment delivery and at present will not impact the revised first gas date of Q4 2021.

The total project cost is budgeted at US$700 million. As at the end of 2019, NGC and Seplat had each made an equity investment of US$150 million (US$300 million combined) and the final equity injection from Seplat and NGC of a further US$60 million (US$120 million total) is expected in Q2. An accompanying debt funding round of US$320 million was launched to potential lenders in April, with responses expected by the end of June.

COVID-19 response

As we monitor developments on the Coronavirus (COVID-19) pandemic in Nigeria and around the world, the health and safety of our employees, communities, partners and other stakeholders remain our top priority. In line with our strong HSE culture, we have implemented preventative measures across all Seplat sites designed to protect our stakeholders whilst ensuring we can continue to provide the energy and fuels that Nigeria needs. The measures set out below comply with the current recommendations provided by the Nigerian Government and World Health Organisation (WHO) and promote safe and secure engagements with our stakeholders: 

1. To do our part in mitigating the spread of the virus, we took the decision to temporarily close our offices and run our field operations with reduced operations personnel for two weeks from 23rd March to 5th April 2020. However, following a recent directive by the Federal Government to stop all movements in Lagos and the Federal Capital Territory, this directive has been extended and will remain under review until such time as the Federal Government deems it safe to allow travel throughout the city.

2. Consistent with our business continuity plan, our employees are working from home and are supported by our robust technology platforms, enabling all staff to interact with our internal and external stakeholders. Our IT platforms, including Company-issued laptop computers for home use, comply with world-class standard data protection and confidentiality protocols. 

3. During this period, our field operations personnel have been reduced to essential-only staffing and we continue to produce oil and gas at our sites across Nigeria, based upon 28-day rotations of workers instead of the usual 14-day rotations. All field staff have access to regular health checks.

4. We have deferred our physical participation in external meetings, both local and international, as well as workshops and similar gatherings. 

5. Before closing our offices, we instituted a ban on all travel. Additionally, all employees who returned to the country in that period were placed on a self-quarantine for 14 days. We also directed our staff to adopt preventive practices and substitute physical stakeholder engagements in and out of office premises with interactions through a variety of IT platforms, such as video conferencing. To support our communities, we recently committed funds to purchase medical equipment and essential consumables that we distributed to states in which we have oil and gas operations, to support those local state governments fight against the virus.

At a national-level, Seplat is also one of the 33 partners that contributed to an industry intervention initiative in recognition of the impact of the COVID-19 pandemic on the Nigerian population and economy. The country's oil and gas industry, under the leadership of the Nigerian National Petroleum Corporation (NNPC) Group Managing Director, Mele Kyari, embarked on an industry-wide collaborative intervention initiative to combat the pandemic and its potential impacts.

The NNPC, along with the 33 industry partners, donated US$30 million to support the Federal Government's efforts at curbing the spread of the pandemic. The safety measures and donations of Seplat will contribute to the ongoing national efforts to contain the COVID-19 pandemic, without compromising the wellbeing of our people and communities and to ensure Nigeria has access to the fuels it needs during this time. 

In addition, Seplat provided food assistance, medical and protective equipment worth ₦50 million to help local State authorities.

We will continue to monitor the rapidly changing dynamics and the impact of COVID-19 to comply with all State and Federal Government directives to help protect the health and safety of our stakeholders.

Seplat's business philosophy of prudent financial management and a strong focus on cash generation helped it navigate the twin shocks of the oil price crisis and the 16-month shutdown caused by force majeure at the Forcados terminal in 2016/17. Thanks to its sound financial management and increasing investments in gas, today, Seplat is even more robust. Our hearts go out to those in Nigeria and across the world that have been impacted by COVID-19 and we hope for a speedy resolution to the pandemic.

Update on Annual General Meeting

In view of the current COVID-19 pandemic, SEPLAT obtained approval from the Nigeria Corporate Affairs Commission to hold its AGM on 28th May 2020 by proxy ONLY, which is in accordance with the new Guidelines on Holding of Annual General Meetings (AGM) of Public Companies taking advantage of Section 230 of the Companies and Allied Matters Act (CAMA) using proxies.

It is clarified that a proxy need not be a member of the Company. However, members are required to appoint a proxy of their choice from the following proposed proxies to represent them at the meeting: (a) Dr. A. B. C. Orjiako; (b) Mr. O. A. Avuru; (c) Mrs. E. Onwuchekwa; (d) Sir Sunny Nwosu; (e) Dr. Faruk Umar; (f) Mr. Boniface Okezie; and (g) Mr. Matthew Akinlade.

For the appointment to be valid for the purposes of the Meeting, the Company has made arrangements at its cost for the stamping of the duly completed proxy form(s), which must be deposited at the office of the Registrar, DataMax Registrars Limited, 2C Gbagada Express Way, by Beko Ransom Kuti Park, Gbagada, Lagos or at the head office of the Company, marked for the attention of the "Company Secretary" or by email to proxy@seplatpetroleum.com, not less than 48 hours before the time fixed for the meeting.

Further details are available in the Company's 2019 Annual Report, posted on its website www.seplatpetroleum.com.

Financial review

Revenue, production and commodity prices

Brent oil price averaged US$50.90/bbl in the first quarter of 2020 (Q1 2019: US$63.59/bbl).

Total revenue for the period stood at US$130.5 million, down 18.2% from the US$159.5 million achieved in 2019. Crude oil revenue was US$107.4 million (Q1 2019: US$117.8 million) an 8.8% reduction compared to 2019, reflecting lower realised oil prices.

Average working-interest liquids production was 33,368 bopd, up 52.5% from 21,885 bopd in 2019, whilst the total volume of crude lifted in the period was 2.1 MMbbls compared to 1.9 MMbbls in 2019. The higher production was due to a 10,056 bopd contribution from OML 40 (Eland) and higher production from OML 53.

Gas revenue decreased by 44.6% to US$23.1 million (Q1 2019: US$41.7 million), due to lower realised prices and lower gas sales volumes. The average realised gas price was lower at US$2.89/Mscf (2019: US$3.24/Mscf), with total gas volumes sold of 88 Bscf (2019: 143 Bscf). The lower gas sales volumes reflect higher downtime at the third-party infrastructure and a planned 15-day week shut down of the gas plant for the turnaround maintenance executed in March.

Gas sales contributed 17.7% of total Group revenue in the period (Q1 2019: 26.2%).

Gross profit

Gross profit decreased to US$33.1 million (Q1 2019: US$81.4 million) as a result of US$29 million lower revenues, higher crude handling fees and non-production costs primarily consisting of royalties and DD&A, which were US$59.8 million compared to US$49.7 million in the prior year. These increased costs reflect the additional production volumes from OML 40 and resultant increase in royalties and crude handling fees. On a cost-per-barrel basis, production opex was higher at US$7.7/boe (Q1 2019: US$6.2/boe).

The 56.4% increase in general and administrative expenses, which stood at US$32.0 million (Q1 2019: US$20.4 million), related to one-off termination payments of US$2.3 million made to the Directors of Eland following its acquisition, as well as the inclusion of Eland staff and office costs.

IAS 36 Impairments

The Group, under IAS 36 identified the need to revalue its assets due to the significant economic uncertainty of the COVID-19 crisis. Following a reassessment of the business models and assumptions to establish its reasonableness and practicality particularly in the oil price environment principally driven by the pandemic, the Group decided to raise a provision at this stage and the result is an aggregate impact of US$145.5 million across all assets.

Operating loss

The operating loss of US$77.0 million (Q1 2019: US$32.5 million operating profit) resulted primarily from the US$145.5 million IAS 36 impairment charge, detailed above. This was partially offset by adjustment for a US$46.8 million underlift position (shortfalls of crude lifted below the share of production, which is priced at date of lifting and recognised as other income) and the US$19.2 million fair value gain in relation to the Company's oil price hedges.

Tax

The Group's tax expense for the first quarter of 2020 was US$10.8 million, compared to a tax credit of US$13.3 million for the same period in 2019. The tax expense is made up of a deferred tax charge of US$10 million and current tax charge of US$0.8 million. 

Net result

The loss before tax adjustments was US$95.7 million (Q1 2019: US$19.4 million). The net finance charge was US$20 million, compared to US$13 million in 2019. The net loss for 2019 was US$106.6 million (Q1 2019: US$32.7 million net profit).

The resultant basic loss per share was US$0.19 in 2019, compared to an EPS of US$0.06 in 2019.

Cash flows from operating activities

Net cash flows from operating activities after movements in working capital were US$64.5 million (Q1 2019: US$79.5 million). In Q1 2020, Seplat received a total of US$40 million towards the settlement of outstanding dollar denominated cash calls and US$43 million (Naira equivalent) to offset Naira cash calls.

The NPDC receivable balance now stands at US$207.3 million. Seplat has continued discussions with the NPDC to ensure that receivables are settled promptly. The Group continues to receive the proceeds of gas sales from NPDC in lieu of Naira cash calls for ongoing operations.

Cash flows from investing activities

Capital expenditures were US$45.9 million in the period and included drilling costs in relation to the completion of three development wells, pre-drill and ongoing drilling operations costs for two development wells and associated facilities development and engineering costs. Gas project costs included the Sapele Gas Plant upgrade project.

After adjusting for interest receipts of US$1 million, the net cash outflow from investing activities for the period was US$44.8 million compared to a net cash outflow in 2019 of US$2.9 million, reflecting the higher capex spend.

Cash flows from financing activities

Net cash outflows from financing activities were US$15.9 million (Q1 2019: US$18.7 million). This reflects a further US$10.0 million drawn from the Westport RBL facility in the period; and interest and other financing charges totalling US$25.8 million.

Overall, Seplat's aggregate indebtedness at 31 March 2020 stood at US$794 million, with cash at bank of US$336 million, leaving net debt at US$458 million.

Hedging

Seplat's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. The 2020 hedging programme consists of up-front premium put options at a strike price of US$45.0/bbl protecting a volume of 4.5 MMbbls (in aggregate) for the first three quarters of 2020. Following the oil price crash at the end of Q1 2020 and in line with IFRS, these hedges were fair valued leading to a Market to Market gain (MTM) of US$19.2 million.

The Board and management team 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.

Interim Condensed Consolidated Financial Statements (Unaudited)

For the period ended 31 March 2020

(Expressed in Nigerian Naira and US Dollars)

Interim condensed consolidated statement of profit or loss and other comprehensive income

For the first quarter ended 31 March 2020

The above interim condensed consolidated statement of profit or loss and other comprehensive income should be read in conjunction with the accompanying notes.

Interim condensed consolidated statement of financial position

As at 31 March 2020

The above interim condensed consolidated statement of financial position should be read in conjunction with the accompanying notes.

The Group financial statements of Seplat Petroleum Development Company Plc and its subsidiaries (The Group) for three months ended 31 March 2020 were authorised for issue in accordance with a resolution of the Directors on 29 April 2020 and were signed on its behalf by

Interim condensed consolidated statement of changes in equity

For the first quarter ended 31 March 2020

The above interim condensed consolidated statement of changes in equity should be read in conjunction with the accompanying notes.

The above interim condensed consolidated statement of changes in equity should be read in conjunction with the accompanying notes.

Interim condensed consolidated statement of cash flows

For the first quarter ended 31 March 2020

For the purposes of the cash flow statements, the restricted cash balance of $6.7m (N2.1billion) has been excluded from the cash and cash equivalents at the end of the period. These amounts are subject to legal restrictions and are therefore not available for general use by the Group.

The above interim condensed consolidated statement of cashflows should be read in conjunction with the accompanying notes.

Notes to the interim condensed 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: 16a Temple Road (Olu Holloway), 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 ₦104 billion ($340 million) paid at the completion of the acquisition on 31 July 2010 and a contingent payment of ₦10 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 ₦24,560 ($80) per barrel. ₦110 billion ($358.6 million) was allocated to the producing assets including ₦5.7 billion ($18.6 million) as the fair value of the contingent consideration as calculated on acquisition date. The contingent consideration of ₦10 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 Limited. 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 ₦79.6 billion ($259.4 million).

On 16 January 2018, the Group incorporated a subsidiary, Seplat West Limited ('Seplat West'). Seplat West was incorporated to manage the producing assets of Seplat Plc.

On 31 December 2019 Seplat Petroleum Development Company acquired 100% of Eland Oil and Gas Plc's issued and yet to be issued ordinary shares. Eland is an independent oil and gas company that holds interest in subsidiaries and joint ventures that are into production, development and exploration in West Africa, particularly the Niger Delta region of Nigeria.

On acquisition of Eland Oil and Gas Plc (Eland), the Group acquired indirect interest in existing subsidiaries of Eland.

Eland Oil & Gas (Nigeria) Limited, is a subsidiary acquired through the purchase of Eland and is into exploration and production of oil and gas.

Westport Oil Limited, which was also acquired through purchase of Eland is a financing company.

Elcrest Exploration and Production Company Limited (Elcrest) who became an indirect subsidiary of the Group purchased a 45 percent interest in OML 40 in 2012. Elcrest Exploration and Production Nigeria is a Joint Venture between Eland Oil and Gas (45%) and Starcrest Nigeria Energy Limited (55%). It has been consolidated because Eland is deemed to have power over the relevant activities of Elcrest to affect variable returns from Elcrest at the date of acquisition by the Group. (See details in Note 4.1.iv) The principal activity of Elcrest is exploration and production of oil and gas.

Wester Ord Oil & Gas (Nigeria) Limited, who also became an indirect subsidiary of the Group acquired a 40% stake in a licence, Ubima, in 2014 via a joint operations agreement. The principal activity of Wester Ord Oil & Gas (Nigeria) Limited is exploration and production of oil and gas.

Other entities acquired through the purchase of Eland are Tarland Oil Holdings Limited (a holding company), Brineland Petroleum Limited (dormant company) and Destination Natural Resources Limited (dormant company).

The Company together with its subsidiaries as shown below are collectively referred to as the Group.

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

In order to fund the development of the ANOH gas processing plant, on 13 August 2018, the Group entered into a shareholder's agreement with Nigerian Gas Processing and Transportation Company (NGPTC). Funding is to be provided by both parties in equal proportion representing their ownership share and will be used to subscribe for the ordinary shares in ANOH. The agreement was effective on 18 April 2019, which was the date the Corporate

Affairs Commission (CAC) approval was received. Given the change in ownership structure, the Group no longer exercises control and has now deconsolidated ANOH in the consolidated financial statements. However, its retained interest qualifies as a joint arrangement and has been recognised accordingly as investment in joint venture.

2. Significant changes in the current reporting period

The following significant changes occurred during the reporting period ended 31 March 2020:

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 interim condensed consolidated financial statements. These accounting policies have been applied to all the periods presented, unless otherwise stated. The interim financial statements are for the Group consisting of Seplat and its subsidiaries.

3.2 Basis of preparation

The interim condensed consolidated financial statements of the Group for the first quarter ended 31 March 2020 have been prepared in accordance with the accounting standard IAS 34 Interim financial reporting. This interim condensed consolidated financial statement does not include all the notes normally included in an annual financial statement of the Group. Accordingly, this report is to be read in conjunction with the annual report for the year ended 31 December 2019 and any public announcements made by the Group during the interim reporting period.

The financial statements have been prepared under the going concern assumption and historical cost convention, except for contingent liability and consideration, and financial instruments measured at fair value on initial recognition, defined benefit plans - plan assets measured at fair value and assets and liabilities acquired on business combination. 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.

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.

The accounting policies adopted are consistent with those of the previous financial year end corresponding interim reporting period, except for the adoption of new and amended standard which is set out below.

3.3 New and amended standards adopted by the Group

The accounting policies adopted in the preparation of the interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group's annual consolidated financial statements for the year ended 31 December 2019, except for the adoption of new standards effective as of 1 January 2020. The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.

Several amendments and interpretations apply for the first time in 2020, but do not have an impact on the interim condensed consolidated financial statements of the Group.

a) Amendments to IFRS 3: Definition of a Business

The amendment to IFRS 3 clarifies that to be considered a business, an integrated set of activities and assets must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output. Furthermore, it clarified that a business can exist without including all of the inputs and processes needed to create outputs. These amendments had no impact on the consolidated financial statements of the Group, but may impact future periods should the Group enter into any business combinations

b) Amendments to IFRS 7, IFRS 9 and IAS 39: Interest Rate Benchmark Reform

These amendments to IFRS 9 and IAS 39 Financial Instruments: Recognition and Measurement provide a number of reliefs, which apply to all hedging relationships that are directly affected by interest rate benchmark reform. A hedging relation is affected if the reform gives rise to uncertainties about the timing and of amount of benchmark-based cash flows of the hedged item or the hedging instrument. These amendments had no impact on the consolidated financial statements of the Group as it does not have any interest rate hedge relationships.

c) Amendments to IAS 1 and IAS 8: Definition of Material

The amendments provide a new definition of material that states, "information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general-purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity."

The amendments clarify that materiality will depend on the nature or magnitude of information, either individually or in combination with other information, in the context of the financial statements. A misstatement of information is material if it could reasonably be expected to influence decisions made by the primary users. These amendments had no impact on the consolidated financial statements of, nor is there expected to be any future impact to the Group.

d) Sale or Contribution of Assets between an investor and its Associate or Joint Venture-Amendments to IFRS 10 and IAS 28

The amendments address the conflict between IFRS 10 Consolidated Financial Statements and IAS 28 In IAS 28 Investments in Associates and Joint Ventures in dealing with the loss of control of a subsidiary that is sold or contributed to an associate or joint venture.

The amendments clarify that a full gain or loss is recognised when a transfer to an associate or joint venture involves a business as defined in IFRS 3. Any gain or loss resulting from the sale or contribution of assets that does not constitute a business, however, is recognised only to the extent of unrelated investors' interests in the associate or joint venture.

These amendments had no impact on the consolidated financial statements of the Group.

e) Conceptual Framework for Financial Reporting issued on 29 March 2018

The Conceptual Framework is not a standard, and none of the concepts contained therein override the concepts or requirements in any standard. The purpose of the Conceptual Framework is to assist the IASB in developing standards, to help preparers develop consistent accounting policies where there is no applicable standard in place and to assist all parties to understand and interpret the standards.

The revised Conceptual Framework includes some new concepts, provides updated definitions and recognition criteria for assets and liabilities and clarifies some important concepts.

These amendments had no impact on the consolidated financial statements of the Group.

3.4 Basis of consolidation

The consolidated financial statements comprise the financial statements of the Company and its subsidiaries as at 31 March 2020.

This basis of consolidation is the same adopted for the last audited financial statements as at 31 December 2019.

3.5 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 Great Britain Pound. The interim condensed 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. They are deferred in equity if attributable to net investment in foreign operations.

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 at the date of the reporting date.

· 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 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. Goodwill and fair value adjustments arising on the acquisition of a foreign operation are treated as assets and liabilities of the foreign operation and translated at the closing rate.

4. Significant accounting judgements estimates and assumptions

4.1 Judgements

Management judgements at the end of the first quarter are consistent with those disclosed in the 2019 Annual financial statements. The following are some of the judgements which have the most significant effect on the amounts recognised in this interim consolidated financial statement.

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 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. Deferred tax asset

Deferred income 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.

iii. Foreign currency translation reserve

The Group has used the CBN rate 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 ₦4.2 billion, 2019: ₦4.9 billion.

iv. Consolidation of Elcrest

On acquisition of 100% shares of Eland Oil and Gas Plc, the Group acquired indirect holdings in Elcrest Exploration and Production (Nigeria) Limited. Although the Group has an indirect holding of 45% in Elcrest, Elcrest has been consolidated as a subsidiary for the following basis:

· Eland Oil and Gas Plc has power over Elcrest through due representation of Eland in the board of Elcrest, and clauses contained in the Share Charge agreement and loan agreement which gives Eland the right to control 100% of the voting rights of shareholders.

· Eland Oil and Gas Plc is exposed to variable returns from the activities of Elcrest through dividends and interests.

· Eland Oil and Gas Plc has the power to affect the amount of returns from Elcrest through its right to direct the activities of Elcrest and its exposure to returns.

v. Contingent liability

A contingent liability of $7.2 million was recognised on the acquisition of Eland Group for a pending investigation into the UK's Controlled Foreign Company (CFC) tax regime. This amount is the present value of estimated probability of exposure from the pending case. On 25 April 2019, the European Commission released its decision in relation to the Group/Company finance exemption in the UK's CFC rules finding that the exemption constitutes unlawful state aid if the exempted profits arise in connection with UK activity. It is expected that that HM Revenue and Customs will have reached a decision on this case within the next 12 months. The potential undiscounted amount of all future payments that the group could be required to make, if there was an adverse decision related to the investigation, it is estimated at $45.4 million. As at 31 March 2020, there has been no change in the probability of the outcome of the lawsuit.

vi. Defined benefit plan

The Group has placed reliance on the actuarial valuations carried out at the previous year and reporting period as it does not expect material differences in the assumptions used for that period and the current period assumptions. All assumptions are reviewed annually.

vii. 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 gas customers 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 Mercuria 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.

Exploration and evaluation assets

The accounting for exploration and evaluation ('E&E') assets require management to make certain judgements and assumptions, including whether exploratory wells have discovered economically recoverable quantities of reserves. Designations are sometimes revised as new information becomes available. If an exploratory well encounters hydrocarbon, but further appraisal activity is required in order to conclude whether the hydrocarbons are economically recoverable, the well costs remain capitalised as long as sufficient progress is being made in assessing the economic and operating viability of the well. Criteria used in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected additional development activities, commercial evaluation and regulatory matters. The concept of 'sufficient progress' is an area of judgement, and it is possible to have exploratory costs remain capitalised for several years while additional drilling is performed or the Group seeks government, regulatory or partner approval of development plans.

4.2. Estimates and assumptions

The key assumptions concerning the future and the other key source of estimation uncertainty that have a significant risk of causing a material adjustment to the carrying amount of assets and liabilities are disclosed in the most recent 2019 annual financial statements.

The following are some of the estimates and assumptions made.

i. 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.

ii. Contingent consideration

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.

iii. 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.

iv. 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.

v. 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 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.

vi. 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.

vii. 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.

viii. 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.

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.

5.1.1 Credit risk

Credit risk refers to the risk of a counterparty defaulting on its contractual obligations resulting in financial loss to the Group. Credit risk arises from cash and cash equivalents, favourable derivative financial instruments, deposits with banks and financial institutions as well as credit exposures to customers and Joint venture partners, i.e. NPDC receivables and NGC receivables.

a) Risk management

The Group is exposed to credit risk from its sale of crude oil to Mecuria. The off-take agreement with Mercuria runs for five years until 31 July 2020 with a 30 day payment term. The Group is exposed to further credit risk from outstanding cash calls from Nigerian Petroleum Development Company (NPDC) and National Petroleum Investment Management Services (NAPIMS).

In addition, the Group is exposed to credit risk in relation to its sale of gas to Nigerian Gas Marketing Company (NGMC) Limited, a subsidiary of NNPC, its sole gas customer during the quarter.The credit risk on cash is limited because the majority of deposits are with banks that have an acceptable credit rating assigned by an international credit agency. The Group's maximum exposure to credit risk due to default of the counterparty is equal to the carrying value of its financial assets. 

5.1.2 Liquidity risk

Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The Group manages liquidity risk by ensuring that sufficient funds are available to meet its commitments as they fall due.

The Group uses both long-term and short-term cash flow projections to monitor funding requirements for activities and to ensure there are sufficient cash resources to meet operational needs. Cash flow projections take into consideration the Group's debt financing plans and covenant compliance. Surplus cash held is transferred to the treasury department which invests in deposit bearing current accounts, time deposits and money market deposits.

The following table details the Group's remaining contractual maturity for its non-derivative financial liabilities with agreed maturity periods. The table has been drawn based on the undiscounted cash flows of the financial liabilities based on the earliest date on which the Group can be required to pay.

** Trade and other payables (exclude non-financial liabilities such as provisions, taxes, pension and other non-contractual payables).

5.1.3 Fair value measurements

Set out below is a comparison by category of carrying amounts and fair value of all financial instruments:

* Trade and other receivables exclude NGMC VAT receivables, cash advances and advance payments.

Trade and other payables (exclude non-financial liabilities such as provisions, taxes, pension and other non-contractual payables), trade and other receivables (excluding prepayments), contract assets and cash and bank balances are financial instruments whose carrying amounts as per the financial statements approximate their fair values. This is mainly due to their short-term nature.

5.1.4 Fair Value Hierarchy

As at the reporting period, the Group had classified its financial instruments into the three levels prescribed under the accounting standards. There are recurring fair value measurements and non-recurring fair value measurements resulting from the acquisition of Eland. There were no transfers of financial instruments between fair value hierarchy levels during the year.

· Level 1 - Quoted (unadjusted) market prices in active markets for identical assets or liabilities.

· Level 2 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable.

· Level 3 - Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.

The fair value of the financial instruments is included at 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 the Group's derivative financial instruments has been determined using a proprietary pricing model that uses marked to market valuation. The valuation represents the mid-market value and the actual close-out costs of trades involved. The market inputs to the model are derived from observable sources. Other inputs are unobservable but are estimated based on the market inputs or by using other pricing models.

The fair value of the Group's interest-bearing loans and borrowings is determined by using discounted cash flow models that use market interest rates as at the end of the period. The interest-bearing loans and borrowings are in level 2.

The fair value of the Group's contingent consideration is determined using the discounted cash flow model. The cash flows were determined based on probable future oil prices. The estimated future cash flow was discounted to present value using a discount rate.

The valuation process

The finance & planning team of the Group performs the valuations of financial and non-financial assets required for financial reporting purposes. This team reports directly to the General Manager (GM) Commercial who reports to the Chief Financial Officer (CFO) and the Audit Committee (AC). Discussions of valuation processes and results are held between the GM and the valuation team at least once every quarter, in line with the Group's quarterly reporting periods.

6. Segment reporting

Business segments are based on the Group's internal organisation and management reporting structure. The Group's business segments are the two core businesses: Oil and Gas. The Oil segment deals with the exploration, development and production of crude oil while the Gas segment deals with the production and processing of gas. These two reportable segments make up the total operations of the Group.

For the period ended 31 March 2020, revenue from the gas segment of the business constituted 18% of the Group's revenue. Management believes that the gas segment of the business will continue to generate higher profits in the foreseeable future. It also decided that more investments will be made toward building the gas arm of the business. This investment will be used in establishing more offices, creating a separate operational management and procuring the required infrastructure for this segment of the business. The gas business is positioned separately within the Group and reports directly to the ('chief operating decision maker'). As this business segment's revenues and results, and its cash flows, will be largely independent of other business units within the Group, it is regarded as a separate segment.

The result is two reporting segments, Oil and Gas. There were no intersegment sales during the reporting periods under consideration, therefore all revenue was from external customers.

Amounts relating to the gas segment are determined using the gas cost centres, with the exception of depreciation. Depreciation relating to the gas segment is determined by applying a percentage which reflects the proportion of the Net Book Value of oil and gas properties that relates to gas investment costs (i.e. cost for the gas processing facilities).

The Group accounting policies are also applied in the segment reports.

6.1 Segment profit disclosure

Oil

Gas