Seplat Announces Unaudited Results for 3M Ended 31 March 2021

Source: 4/29/2021, Location: Africa

Seplat Petroleum Development Company Plc, a leading Nigerian independent energy 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 2021.

Operational highlights
- Working-interest oil and production within guidance at 48,239 boepd
- Average daily volumes of nearly 54,000 boepd achieved in first 21 days of April
- Liquids production of 28,541 bopd in Q1 2021
- Gas production of 114 MMscfd (19,698 boepd)
- Low unit cost of production of $8.70/boe
- Oben-50 gas well now producing, Oben-51 drilled and completed with gas expected to flow in May
- Safety record extended to more than 17 million hours without LTI on Seplat-operated assets

Financial highlights
- Board adopts quarterly dividend policy; declares Q1 2021 dividend of US2.5 cents per share
- Revenue up 16.8% to $152.4 million
- EBITDA of $77.8 million
- Cash at bank $236.3 million, net debt of $458.1 million
- Successful issue of $650 million 7.75% senior notes to redeem existing $350 million 9.25% senior notes and repay $250 million drawn on $350 million RCF
- Refinanced $100 million Westport RBL facility
- Total capital expenditure of $32.6 million

Corporate updates
- Seeking shareholder approval at the AGM on 20 May 2021 to change name to Seplat Energy PLC to reflect evolving strategy
- ANOH project now fully funded following successful $260 million debt issue
- Plan to host Capital Markets Day on 29 July 2021

- Expected production unchanged at 48-55 kboepd for full year, subject to market conditions
- Capex guidance unchanged, expected to be $150 million for the full year
- 5.0MMbbls hedged at $35-$45/bbl from Q2 to Q4 2021

Roger Brown, Chief Executive Officer, said:
"We have made a progressive start to the year, delivering oil and gas production volumes of 48,239 boepd, within our guidance range. With the Gbetiokun field at OML40 now back in production, we are currently achieving average daily volumes of nearly 54 kboepd so far in April and we will build on this as we add additional oil and gas wells this year.

Our flagship ANOH gas project is proceeding as planned and was fully funded in February when our joint venture company, AGPC successfully raised $260 million of debt financing. In addition, the success of our $650 million Eurobond issuance in March demonstrates investor confidence in our prudent financial management and the exciting future ahead for the Company and its stakeholders.

As we drive forward our strategy of being a low-cost energy provider delivering reliable, affordable and sustainable energy to the young, fast-growing population of Nigeria, energy transition - which delivers on Nigeria's social development goals in tandem with the climate agenda - is essential. This is the backbone of Seplat's strategy and we will be communicating how we plan to achieve this over the coming months. To that end, the Board took the decision to change our name to Seplat Energy PLC, which more adequately reflects our ambitions of providing a broader energy mix. We will present the name change to our shareholders for approval at the AGM on 20 May 2021."

Outlook for 2021
For 2021 we expect to produce an average of 48,000 - 55,000 boepd, taking into account the impact of OPEC+ quotas. We continue to hedge against oil price volatility and expect a higher proportion of revenues to come from long-term gas contracts at stable prices.

We have significant cash resources and will continue to manage our finances prudently in 2021, expecting to invest $150 million of capital expenditure across the full year, with nearly $33 million already invested. We remain confident that our ongoing cost-cutting initiatives and prudent management of cash will enable further reductions in debt, whilst supporting dividend payments and investment for growth.

Following its successful funding, the completion of the ANOH project remains a major priority. Although we expect some COVID-19 related delays to push completion into early 2022, following a cost optimisation programme we now expect the project to cost no more than $650 million, substantially below the $700 million budget previously stated at Final Investment Decision.

Proposal to change name to Seplat Energy PLC
We are seeking shareholder approval to change our name to Seplat Energy PLC to reflect the future direction of the Company. The change of name will be accompanied by a new corporate brand identity that we plan to unveil at the Seplat Energy Summit in September. Before that, we intend to host a Capital Markets Day on 29 July 2021 to outline the Company's strategic direction and its plans to develop its New Energy business.

Adoption of quarterly dividend
On 28 April 2021 the Board approved the payment of quarterly dividends, commencing with an interim dividend of US2.5 cents, in a change to Seplat's previous policy of declaring dividends twice a year in the Q3 results and the full-year results. The change in policy is intended to provide more frequent returns to shareholders. Operating review

Group reserves
Total working-interest 2P reserves, as assessed independently by Ryder Scott Company, L.P., at 1 January 2021, stood at 499.4 MMboe, comprising 240.5 MMbbls of oil and condensate and 1,501.3 Bscf of natural gas. The change represents an organic decrease in overall 2P reserves of 1.9% year-on-year, due to production of 12.3 MMbbls but mitigated by upward revisions of previous estimates. Working-interest 2C resources stood at 94.8 MMboe, comprising 59.7 MMbbls of oil and condensate and 203.3 Bscf of natural gas.

Consequently, the Group's working-interest 2P reserves and 2C resources stood at 594.1 MMboe at 1 January 2021, comprising 300.2 MMbbls oil and condensate and 1,704.7 Bscf of natural gas.

Drilling programme
During the first quarter of 2021 we completed the Oben-50 gas well, which is now producing as expected. We also drilled and completed Oben-51 and expect gas to be flowing in May. We plan workover activity at Oben-44 and Oben-46 as an alternative to new drilling. We also plan a development well and an appraisal well at our Eastern Asset in the second half of the year, as well as three wells at Gbetiokun and an exploration well at Sibiri (formerly called Amobe). Shell, the unitised operator, has commenced drilling the gas wells at ANOH, with a total of four wells being planned for this year.

HSE performance
Staff and contractors worked a total of 1.9 million hours with no fatalities, lost-time injuries or minor injuries. The Company has achieved more than 17 million hours without LTI on Seplat-operated assets. There were 23 HSE incidents in total, compared to 26 in Q1 2020, including four spills and four gas leaks, all of which were remediated with limited environmental impact. By the end of March we had conducted 4,471 COVID-19 tests, with a positivity rate of 2%. We continue to enforce all infection control protocols at our field operations and offices.

Working-interest production for the three months ended 31 March 2021
Average working-interest production for the first quarter of 2021 was within guidance at 48,239 boepd, which represents an overall increase of 0.5% year-on-year. Within this, liquids production was down 13.2% to 28,541 bopd because of delays in siting a new storage vessel at OML 40 to replace the MT Harcourt, which was damaged in November 2020. There was 84% uptime for the Trans Forcados Pipeline during the period and the produced liquid volumes from OMLs 4, 38 and 41 were subject to 12.6% reconciliation losses.

Working-interest gas production increased by nearly 30% to 114 MMscfd, compared to Q1 2020 in which maintenance was undertaken at the Oben Gas Processing plant.

Oil business performance
Seplat's oil operations produced an average 28,541 bopd on a working-interest basis in Q1 2021. Although output increased at OMLs 4,38, 41, OML 53 and OPL 283, the delays at OML 40 noted above resulted in significantly lower volumes in the first quarter. Production at the Gbetiokun field on OML 40 resumed in March and we expect volumes to normalise in the second quarter. Similarly, the Extended Well Test at Ubima has been completed and the production phase commenced in March.

The average price realised per barrel in the first quarter of 2021 was $60.76 (2020: $49.85), following the recovery of Brent prices on the receding threat from the Covid-19 pandemic and a return to previous levels of economic activity.

In accordance with the revised OML 55 commercial arrangement that was agreed in July 2016, which provides for a discharge sum of $330 million to be paid to Seplat over a six-year period through allocation of crude oil volumes produced from OML 55, Seplat received payments amounting to $4.9 million in Q1 2021.

Update on export route
The minor completion works on the 160,000 bopd Amukpe-Escravos Pipeline are not within Seplat's control and have been slower than anticipated due to a combination of challenges associated with access to the Escravos terminal owing to COVID-19 and issues relating to ownership of the pipeline. Our partner, the NPDC, now owns a direct stake in the pipeline and we understand they are working with the other pipeline owner and their banks to enable the completion of the project. We have consequently adjusted our plan and budgets to expect commencement of export of the initial permitted volume of 40,000 bopd through the Escravos terminal in the second half of 2021. Once completed, we believe it will significantly improve the assets' production uptime (84% in Q1 2021) and reduce losses from crude theft and reconciliation (12.6% in Q1 2021).

Gas business performance
Seplat's working interest production for the first quarter of 2021 was 114 MMscfd (19,698 boepd) at an average selling price of $2.76/Mscf. Gas volumes were higher than Q1 2020 (88 MMscfd), during which period we undertook turnaround maintenance at the Oben Gas Plant. Gas contributed 40.8% of Group volumes on a boepd basis, and 18.6% of Group revenues.

Sapele Gas Plant
Work continues on the new Sapele Gas Plant with modules now being fabricated overseas and foundation work being conducted at the site. The project is expected to be completed in the second half of 2022, with Sapele's processing capacity increasing from 60 MMscfd to 75MMscfd. The upgraded facility will produce gas that meets export specifications, and the LPG processing unit module will enhance the economics of the plant, as well as ensuring that any gas flaring is eliminated. We are currently accelerating the installation of AG Booster Compressors at Sapele which will reduce the gas flare at the site. This is expected to be completed and operational in Q4 this year.

ANOH gas plant development
The ANOH Gas Processing Plant development at OML 53 (and adjacent OML 21 with which the upstream project is unitised) will drive the next phase of growth for Seplat's expanding gas business. The project will comprise a Phase One 300 MMscfd midstream gas processing plant.

The ANOH plant, is being built by AGPC, which is an IJV owned equally between Seplat and the Nigerian Gas Company ("NGC"), a wholly owned subsidiary of Nigerian National Petroleum Corporation ("NNPC"). In February 2021, AGPC successfully raised $260 million in debt to fund completion of the ANOH project. The project is now fully funded following completion of equity investments of $210 million by each partner ($420 million combined).

ANOH is one of Nigeria's most strategic gas projects. It will help Nigeria to accelerate its transition away from small-scale diesel generators to cleaner, less expensive fuels such as natural gas for power generation.

The upstream development, including the drilling of six production wells, will be delivered by the upstream unit operator Shell Petroleum Development Company (SPDC), with four wells expected to be completed in 2021. We have made excellent progress on the project despite the COVID-19 challenges, and we expect the major gas processing units to arrive in Nigeria in Q3 2021. We hope to commence installation before the end of the year, with mechanical completion and pre-commissioning in Q1 2022, and have first gas flowing to customers by the end of H1 2022. The initial total project cost was budgeted at $700 million. Following a cost optimisation programme, the AGPC construction cost is now expected to be no more than $650 million, inclusive of financing costs and taxes, significantly lower than the original projected cost at FID.

Financial review

Revenue, production and commodity prices
On an average daily basis, Brent crude oil traded between $51.1/bbl and $69.6/bbl in the first quarter of 2021, ending the period at around $63.5/bbl. Brent prices averaged $61.3/bbl for the quarter, 20.5% higher compared to $50.9/bbl in Q1 2020, which was affected by the pandemic.

Total revenue for the period was $152.4 million, up 16.8% from the $130.5 million achieved in 2020. Crude oil revenue was $124.1 million (Q1 2020: $107.4 million) a 15.5% increase compared to 2020, reflecting higher realised oil prices. The average oil price realised in the first quarter of 2021 was $60.8/bbl (Q1 2020: $49.9/bbl).

Average working-interest liquids production was 28,541 bopd, down 13.2% from 32,863 bopd in 2020, whilst the total volume of crude lifted in the period was 2.0 MMbbls compared to 2.1 MMbbls in 2020. The lower oil production in OML 40 was caused by a shut-in of production from Gbetiokun in January and February, after the MV Harcourt was damaged in November 2020, and there were delays in siting the replacement storage vessel for evacuating oil produced from the field.

Gas sales revenue increased by 22.8% to $28.4 million (Q1 2020: $23.1 million), due to higher gas sales volumes achieved of 10.3Bcf (Q1 2020: 7.9Bcf) reflective of the new gas wells brought onstream during the period. The average realised gas price was lower at $2.76/Mscf (Q1 2020: $2.89/Mscf).

Gas sales contributed 18.6% of total Group revenue in the period (Q1 2020: 17.7%).

Gross profit
Gross profit increased by 59.5% to $52.8 million (Q1 2020: $33.1 million) as a result of higher revenues. Cost of sales in the period totaling $99.7 million was comparable with $97.4 million in the same period last year. The higher production opex of $37.6 million includes maintenance costs to support asset integrity works carried out in the period, offset by lower crude handling charges as the Liquid Heater Treater became operational with minimal water volumes being evacuated through TFP. Consequently, production opex for the period was $8.7/boe (Q1 2020: $7.7/boe). Non-production costs primarily consisting of royalties and DDA, which were $59.3 million comparable to $59.8 million in the prior year reflect the lower production volumes from OML 40.

The 43.1% reduction in general and administrative (G&A) expenses resulted from a combination of the effect of cost reduction initiatives (such as office maintenance, telecommunication, travel and logistics) across the business, one-off payments made for emoluments to former Eland directors in prior period and G&A costs correctly classified in Q3 2020.

Operating profit
The operating profit was $44.4 million after recognising other income from tariffs (fee from use of Group's pipeline to the Warri refinery) of $6.6 million and underlift (shortfalls of crude lifted below the share of production, which is priced at date of lifting) of $8.1 million. This compared to a $77.0 million operating loss in Q1 2020, which was impacted primarily by a $145.5 million IAS 36 impairment charge in the period. We achieved an EBITDA of $77.8 million in the period, when adjusted for non-cash items.

The Group's tax expense for the first quarter of 2021 was $3.2 million, compared to a tax expense of $10.8 million for the same period in 2020. The tax expense is made up of a deferred tax credit of $4.7 million and current tax charge of $7.9 million. The effective tax rate for the period was 11.3%.

Net profit
The profit before tax adjustments was $28.0 million (Q1 2020: $95.7 million loss). The net finance charge was $16.8 million, compared to $20 million in 2020. The net profit for Q1 2021 was $24.9 million (Q1 2020: $106.6 million net loss).

The resultant basic EPS was $0.06 in Q1 2021, compared to a loss per share of $0.19 in Q1 2020.

Seplat's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. The 2021 hedging programme consists of up-front premium put options as follows: for Q1, 1.0MMbbls at a strike price of $30/bbl and 1.0MMbbls at a strike price of $35/bbl; for Q2, 2.0MMbbls at a strike price of $35/bbl; for Q3, 1.0MMbbls at a strike price of $35/bbl and 1.0MMbbls at a strike price of $40/bbl; and for Q4, 1.0MMbls at a strike price of $45/bbl. 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.

Cash flows from operating activities
Operating cash flow before movements in working capital was $84.1 million (Q1 2020: $81.0 million). For the purposes of cash flow statements, restricted cash of $54.5 million has been excluded from the cash balance at the end of the period. Cash generated in the period was also affected by timing differences in the lifting dates that were scheduled towards the end of the quarter and resultant settlement dates that included $36.8 million for sale of crude oil in trade receivables. Consequently, net cash flows from operating activities, after movements in working capital, were $5.3 million (Q1 2020: $64.5 million).

Seplat received a total of $16.4 million towards the settlement of outstanding dollar-denominated cash calls and $51.0 million (Naira equivalent) to offset Naira cash calls, totalling $67.4 million in Q1 2021. The major JV receivable balance now stands at $97.2 million, down from $107.0 million in December 2020. Seplat has continued discussions with major partners to ensure that receivables are settled promptly.

Cash flows from investing activities
Capital expenditures were $32.6 million in the period and included drilling costs of $18.7 million in relation to the completion of two gas development wells, pre-drill and ongoing batch drilling operations costs for two ANOH upstream gas wells at OML 53. Other expenditure included $8.7 million for costs associated with the Sapele Gas Plant upgrade and $5.2 million for other oil and gas facilities and engineering costs.

The Group received total proceeds of $4.9 million from partner BelemaOil under the revised commercial arrangement at OML 55, for the monetisation of 94.2 kbbls of crude oil during the period.

After adjusting for interest receipts, the net cash outflow from investing activities for the period was $27.7 million (Q1 2020: $44.8 million).

Cash flows from financing activities
Net cash outflows from financing activities were $20.4 million (Q1 2020: $15.9 million). This reflects lower interest paid on loans of $20.4 million, compared to the previous year, after $100 million was paid down on the RCF.

Reserve-Based Loan (RBL) Refinancing
Eland's existing RBL was consolidated into the Group's balance sheet in 2020. The initial RBL was entered into in November 2018, via the Group's subsidiary Westport, and was a five-year loan agreement with interest payable semi-annually. The RBL is secured against the Group's producing assets in OML 40 via the Group's shares in Elcrest, and by way of a debenture that creates a charge over certain assets of the Group, including its bank accounts. The available facility is capped at the lower of the available commitments and the borrowing base.

On 17th March 2021, Westport signed an amendment and restatement agreement regarding the RBL. As part of the new agreement, the debt utilised and interest rate remain unchanged at $100 million and 8% + LIBOR respectively, however, the maturity date was extended by either five years after the effective date of the loan (March 2026) or by the reserves tail date (expected to be March 2025).

Events after the reporting period
During the period, the Group offered 7.75% senior notes with an aggregate principal of $650 million due in April 2026. The notes, which were priced on 25 March and closed on 1 April 2021, were issued by the Group in March 2021 and guaranteed by certain of its subsidiaries. The gross proceeds of the Notes were used to redeem the existing $350 million 9.25% senior notes due in 2023, to repay in full drawings of $250 million under the existing $350 million RCF for general corporate purposes, and to pay transaction fees and expenses. The RCF remains available for drawing if required.

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