SEPL Seplat Energy Plc

"Please see the Full Audited Results in attached PDF"

http://www.rns-pdf.londonstockexchange.com/rns/9678J_1-2024-10-29.pdf

Unaudited results for the nine months ended 30 September 2024

29 October 2024

Lagos and London, 29 October 2024: Seplat Energy Plc ("Seplat Energy" or "the Company"), a leading Nigerian independent energy company listed on the Nigerian Exchange Limited and the London Stock Exchange, announces its unaudited results for the nine months ended 30 September 2024.

Summary

3Q24 highlights included Abiala first oil, successful turnaround maintenance at Oben gas plant and the first lifting at Bonny terminal since 2022, continuing the strong operational performance delivered in 2024. Robust cash generation further improved the balance sheet, with period end net debt down to $270m (0.5x Net Debt/EBITDA). Given the strong underlying performance of the business the Board has approved a 20% increase in the quarterly dividend to US3.6 cents per share from 3Q 2024.

Operational highlights  

• Working interest production averaged 47,525 boepd (9M 2023: 48,152 boepd), around the midpoint of guidance. Daily average liquids production increased 6% and gas production decreased by 11% versus 9M 2023. Annual guidance narrowed to 46,000 - 50,000 boepd (previously 44,000 - 52,000 boepd).

• Oben gas plant turnaround maintenance activity successfully completed, expect higher gas production in 4Q 2024.

• Abiala first oil achieved in September. Exports to commence during Q4 2024, targeting gross production level of c.5,000 bopd in Q1 2025.

• Trans Niger Pipeline ('TNP') availability improving, supporting higher OML 53 production, 3Q 2024 production of 2,097 bopd +85% compared to 3Q 2023, and enabling a resumption of OML 53 crude lifting at Bonny Terminal in September.

• Drilling activity increased. Completed nine wells year to date. Seven from the 2024 program, which is on track.

• ANOH Gas project saw completion of the 23km spur line, but the OB3 pipeline experienced further delays due to the technical challenges associated with the project. NGIC completion date has now moved to end of 2024. Factoring in a further contingency, in line with our previously stated approach, first gas is now expected during 2Q 2025.

• Carbon intensity of 32.7 kgCO2e/boe (9M 2023: 26.0 kgCO2e/boe) for operated assets. High 3Q 2024 emissions due to increased flaring during planned maintenance at Oben and following the resumption of operations at Ohaji, OML53. The anticipated impact of the End of Routine Flaring projects, starting in the second half of 2025, is expected to materially reduce absolute emissions by up to 70%.

• Safety culture maintained, achieved 8.2-million-man hours without LTI at Seplat operated assets year to date.

Financial highlights

• Revenues of $715.3 million, down 11.7% vs. 9M 2023 ($810.4 million), largely due to overlift reported at 9M 2023. Adjusting for overlift/underlift 9M 2024 revenue $724 million, +6% compared to 9M 2023 of $683 million

• Average price realisations. Oil: $82.89/bbl (9M 2023: $82.76/bbl); Gas: $3.18/Mscf (9M 2023: $2.87/Mscf). 

• Adjusted EBITDA $383.0 million, up 25% from $306.4 million in 9M 2023, driven by higher revenue (adjusted) and lower costs.

• Cash generated from operations of $423.3 million, up 17% from $362.3 million in 9M 2023.

• Capex of $157.0 million (9M 2023: $125.4 million), reflecting higher drilling activity. 

• Balance sheet cash at 9M 2024, $433.9 million (9M 2023: $391.0 million). Net debt at end September, $270 million, down from $366 million at end June 2024. $38.5 million of Reserve-Based Lending (RBL) borrowings repaid year to date. Period end Net Debt to EBITDA was 0.5x.

Corporate updates

• Received Ministerial Consent for acquisition of entire issued share capital of Mobil Producing Nigeria Unlimited ('MPNU'). 

• Strong underlying business performance supports increase to core dividend. 3Q 24 dividend raised by 20% to US3.6 cents. Total core dividend declared to date in 2024 $9.6 cents per share.

• 2024 production guidance narrowed to 46,000 - 50,000 boepd (previously 44,000 - 52,000 boepd). Capex now expected at the top end of the guidance range ($170 million - $200 million).

Roger Brown, Chief Executive Officer, said:

"The first nine months of 2024 has seen Seplat Energy deliver a strong operational performance. Production has been consistent, drilling has improved and our main maintenance activities have been executed successfully. We have brought two new fields on stream, most recently Abiala, and are approaching completion of the Sapele gas plant. Further delays to the start up at ANOH are frustrating, but we have been pleased to see the commitment of our government partner in tackling the technically challenging river crossing. Based on the latest estimates received, and maintaining a cautious stance on any risk of further delays, we update our guidance for first gas to Q2 2025.

Commodity prices remained supportive, combined with operational uptime and timely cash calls from our joint venture partner, helped cash generation improve year over year, enhancing our balance sheet position. As a result, we are pleased to announce a 20% increase in the core quarterly dividend and note that this is reflective of the strength of the underlying business. The increase does not factor in the organic (ANOH) and inorganic (MPNU) growth opportunities that the company is currently pursuing. 

We were delighted in recent days to receive Ministerial consent for the acquisition of MPNU. The transaction will be transformational for Seplat Energy, and every effort is now on completing the transaction.

Summary of performance

* Adjusted for impairment, fair value loss, unrealised FX gain, profit from JV and decommissioning

**9M 2024 includes underlift of $8.2 million, 9M 2023 includes overlift of $127.8 million

Responsibility for publication

The Board member responsible for arranging the release of this announcement on behalf of Seplat Energy is  Eleanor Adaralegbe, CFO Seplat Energy Plc.

Signed:

Eleanor Adaralegbe

Chief Financial Officer  

Enquiries:

About Seplat Energy

Seplat Energy Plc (Seplat) is Nigeria's leading indigenous energy company. Listed on the Nigerian Exchange Limited (NGX: SEPLAT) and the Main Market of the London Stock Exchange (LSE: SEPL), we are pursuing a Nigeria-focused growth strategy in oil and gas, as well as developing a Power & New Energy business to lead Nigeria's energy transition.

Seplat's energy portfolio consists of seven upstream oil and gas blocks in the prolific Niger Delta region of Nigeria, which we operate with partners including the Nigerian Government and other oil producers. We also have a revenue interest in OML 55. In Gas Midstream, we operate a 465MMscfd gas processing plant at Oben, in OML4, and are constructing the 300MMscfd ANOH Gas Processing Plant in OML53 and a new 85MMscfd gas processing plant at Sapele in OML41, to augment our position as a leading supplier of gas to the domestic power generation market.

For further information please refer to our website, https://www.seplatenergy.com/

Operating review

Group production performance

Working interest production for the nine months ended 30 September 2024

Liquid production volumes as measured at the LACT (Lease Automatic Custody Transfer) unit for OMLs 4, 38 and 41; OML 40 and OPL 283 flow station.

Gas conversion factor of 5.8 boe per scf.

Volumes stated are subject to reconciliation and may differ from sales volumes within the period.

During the first nine months of 2024, the Company reported total working interest production of 47,525 boped, a 1.3% decline in 9M 2024 (9M 2023: 48,152 boepd)), but around the mid-point of initial 2024 guidance (44,000 - 52,000 boepd).

The oil & gas mix was 62% and 38% respectively. Within this, daily average working interest oil production increased by 6% while working interest gas production fell 11%. Gas production was lower due to a combination of gas well availability and the two-week shutdown of the Oben gas plant which successfully carried out planned maintenance activities.

Total production deferment in the period was 24% (9M 2023: 31%), a significant improvement on the prior year performance driven by improved asset availability.

Working interest production by quarter

                                                                   Q1 2024                                        Q2 2024                                      Q3 2024

Liquid production volumes as measured at the LACT (Lease Automatic Custody Transfer) unit for OMLs 4, 38 and 41; OML 40 and OPL 283 flow station.

Gas conversion factor of 5.8 boe per scf.

Volumes stated are subject to reconciliation and may differ from sales volumes within the period

Upstream business performance

Total liquids production increased by 6% to 8.13 MMbbls in 9M 2024, compared to 7.66 MMbbls in 9M 2023.

Summary of the contribution from each asset is highlighted below:

Western Assets

In OMLs 4, 38, & 41, working interest liquids production was stable at 15,067 bopd (9M 2023: 15,206 bopd). Delivery of our 2024 drilling program is on track and will support production in subsequent quarters.

We continue to benefit from the availability of multiple export routes for our Western Assets. In the third quarter we experienced some downtime on our main export routes. In August the Amukpe Escravos pipeline ('AEP') experienced 14 days of downtime, while in September the Trans Forcados pipeline ('TFP') experienced 13 days of downtime. However, on both occasions the alternative evacuation route was available, ensuring minimal disruption to operations.

Elcrest

Our operations in OML 40 continued to record strong growth during the period. Average daily working interest production rose 12.8% to 11,468 bopd (9M 2023: 10,169 bopd). The solid growth in production has being supported by timely delivery of new wells, and improved export route availability experienced in the year to date.

Abiala marginal field

Abiala is a marginal field located in the OML 40 area, in which Elcrest (45% owned by Seplat Energy) owns a 95% equity farm-in and is the operator. It represents one of the growth projects expected to be brought online in 2024. The progress so far is in line with our plan to focus on low-cost development with early monetisation opportunities that leverage existing contractual positions to accelerate the field's development.

We are pleased to report first oil, via an extended well test ('EWT'), from Abiala-01 was achieved on 15th September. The second producing well, Abiala-02 well has been completed with well clean-up currently in progress. Evacuation of the crude for sale is expected to commence at the end of October 2024, and the Company expects the field to reach a gross production rate of c.5,000 bopd by Q1 2025.

Eastern Assets

On OML 53, following the resumption of pipeline operations, daily working interest production rose 31.4% to 1,516 bopd in 9M 2024 (9M 2023: 1,154 bopd), while 3Q24 production was up 85% on the equivalent period in 2023, highlighting the benefit of TNP availability. At Ohaji, evacuation has primarily been to the nearby Waltersmith Refinery in the year to date, though the split has been balanced between the TNP and Waltersmith in 3Q24. TNP has been available since April 2024, and the Company lifted its first shipment, of 200,000 barrels, from bonny terminal for the first time in 32 months in September.

We continue to see limited production from our Jisike field, with a daily working interest production of 332 bopd in 9M 2024 (9M 2023: nil).

In OPL 283, daily working interest production rose 4.7% to 1,613 bopd in 9M 2024, from 1,540 bopd in 9M 2023. 

Trans Niger Pipeline ('TNP') Update

Ongoing operational improvements and enhanced security measures have been implemented to stabilise the TNP, which has previously encountered challenges due to oil theft and vandalism. As a result, operations are currently restricted to daylight hours. The line operator, Shell Petroleum Development Company (SPDC) continues to execute workstreams needed to resume 24-hour operations on Zone-6 of the line. These workstreams are expected to be completed in Q4 2024 which would allow us resume 24-hour injection into the line.

The following wells- Ohaji-7, Ohaji-8 and Ohaji-9, in OML 53 which were shut in when evacuation was constrained have been cleaned up and are ready to commence production once stability has been achieved on the TNP.

TNP is also the primary export route for condensate production for ANOH Gas Processing Company (AGPC), which will evacuate condensate into the TNP from the ANOH gas plant.

Drilling

For 2024, the Company's drilling program is expected to deliver 13 new wells (11 oil wells and 2 gas wells). The 2024 drilling program continues to address normal production decline and, along with the completion of maintenance activities, support long-term production levels from the assets.

In our 6M 2024 results, we reported completion of four wells (Ovhor-21, Ovhor-22, Abiala-1 W/O and Sapele-38) from our 2024 drilling program and two wells (Okporhuru-9 and Sapele-37) from our 2023 drilling program. We also stated that Ovhor-21 was onstream and producing at a gross rate of 2,300 bopd. We can now report that Ovhor-22 is onstream and producing at a gross rate of 1,250 bopd while well testing is ongoing at Abiala-1 W/O. 

In the third quarter, we completed the drilling of three additional wells from our 2024 drilling plan. The wells that were completed include Oben-55, Oben-54, and Abiala-2. The completed wells are expected to come onstream in October, with expected combined gross oil & gas production of 4,500 bopd and 23 MMscfd respectively. Two wells (Ovhor-23 & Ovhor-24) billed for completion in Q3 2024 will now be moved Q4 2024. Drilling has commenced in Ovhor-23 using the Imperial rig, with the rig scheduled to move to Ovhor-24 following completion of drilling in Ovhor-23.

In the final quarter of the year, we plan to drill six wells (including two wells from Q3) to complete our 2024 drilling program. The wells to be drilled include Ovhor-23 (ongoing), Ovhor-24, Oben-56 (ongoing), Oben-57, GB-12 (ongoing), and GB-13. Drilling is the major contributing factor in our 2024 capex plans. A high rate of drilling activity alongside management of some well complexity are the principal drivers for group capex now being anticipated at the top of the original guidance range.

Midstream Gas business performance

During the period, the average working interest gas production volume fell 11.1% to 103.6 MMscfd in 9M 2024, from 116.5 MMscfd in 9M 2023. The decline in gas production year to date has been driven by a combination of gas well availability at the start of 2024 and in 3Q by the planned two-week shutdown of the Oben gas plant for mandatory maintenance[1].

Total gas sales for the period were 28.4 Bcf (9M 2023: 31.8 Bcf), contributing 38% of the Company's produced volumes and 13% of total revenue. 

The business continues to pursue growth opportunities to maximise the utilisation of the Oben gas plant. New customers are being brought onboard to high grade the GSA customer base and improve revenue generation. 

Oben Gas Plant

The turnaround maintenance (TAM) activities of the Oben gas plant were successfully carried out during August. The TAM was completed ahead of schedule with the gas plant restarted on August 28th, one day ahead of plan. Alongside mandatory activities, a number of additional activities were delivered concurrently, such as; debottlenecking of condensate separators, conversion of in-let valves to support lower pressure production, tie-ins for western assets flares out projects, an upgrade of the gas metering system and a power upgrade for a new 1.2MVA gas Gen Set, one of our diesel displacement initiatives.

Following completion of the TAM activities, gas production has stabilised around 260 MMscfd gross (c.117 MMscf/d net working interest).

ANOH Gas Processing Plant  

In Q3 2024, AGPC achieved 13.6 million man-hours without Lost Time Injury. We continued to make progress on the gas plant construction, pre-commissioning works and operational readiness towards first gas.

The upstream wells and facilities achieved ready for start-up in early 3Q 2024, which confirmed readiness to deliver wet gas to the ANOH Gas plant.

During October, our partner, NGIC, achieved pipeline commissioning of the 23.3 km Spur line, following completion of all pre-commissioning activities including pipeline cleaning, debris removal, defect testing, hydrotesting, dewatering and drying. The line is now ready to transport processed lean gas into the OB3 pipeline.

In our 6M 2024 results, we reported that tunnelling operations on the OB3 pipeline had reached 1.12km of the 1.85km river crossing. Subsequently, OB3 pipeline experienced further technical and mechanical challenges. The setbacks required import of additional equipment, to reinforce the hardware required for micro tunnelling and horizontal directional drilling (HDD), which have been delivered onsite. Our partner, NGIC, also identified new subsurface complexities which required more grouting works to be completed. Tunnelling works are expected to resume shortly.

Based on the latest guidance from NGIC, the expected OB3 completion date is now end of 2024.  As we have done previously, we have a built in a contingency of up to six months and have now updated our guidance on first gas to Q2 2025.

Sapele Gas Plant

The Sapele Gas Plant is an 85 MMscfd plant, capable of processing both Non-Associated Gas (NAG) and Associated Gas (AG) which meets export specifications and LPG processing module which would supply LPG to the domestic market. The project will also contribute significantly to Seplat's target to end routine flaring by the end of 2025.

Work at the new Sapele Gas Plant has continued through the year. Recent activity includes commissioning work associated with the initial 30 MMscfd MRU train. The project is now near completion, as such, we retain guidance for first gas from the first 30 MMscfd module during Q4 2024. Subsequent modules will be commissioned in 2025 to enable the plant to ramp up to full capacity.

New Energy business

In line with our strategy to support the country's energy transition, we continue to assess various midstream gas, power, and renewable investment opportunities that are focused on increasing energy supply and reliability, lowering costs, and reducing the carbon intensity of Nigeria's electricity consumption. 

In the past quarter, we continued to assess viable and scalable opportunities predominantly in the domestic power sector.

HSE performance

In 9M 2024, the Company achieved a total of 8.2 million manhours without any Lost Time Injury (LTI) in its operated assets, which reflects the Company's strong focus on safety and the dedication of its workforce to maintaining a secure work environment. This brings aggregate LTI free manhours to 18.8 million with over 717 days since last LTI was recorded (13 October 2022). In addition, the Total Recordable Incident Rate (TRIR) was 0.487 with three Medical Treatment Case (MTC) reported during this period. Furthermore, no Tier 2 Process Safety Loss of Primary Containment (LOPC) incident was recorded during the period. 

Ending routine flaring

The carbon intensity recorded for the period was 32.7 kg CO2/boe, higher than the 26.0 kg CO2/boe recorded in 9M 2023. The significant increase in carbon intensity was primarily driven by increased production from our Eastern assets following reinstatement of TNP Zone 6. Wells in our Eastern asset are gas-rich which leads to emission of associated gas as production increases. The shutdown of the Oben Gas Plant during the TAM activities carried out in August led to higher emissions during the two-week period, also contributing to higher carbon intensity compared to last year.

The Company continues to progress efforts to secure evacuation options for unprocessed associated gas from the Sapele Flow Station. Alongside this, work continues on the construction of the Sapele Integrated Gas Plant (SIGP), which is scheduled to be fully complete in 1H 2025 (details in earlier sections). Once operational, SIGP offtake has the potential to materially reduce Group Scope 1 emissions. Other ongoing key flare-out projects, including the Western Asset Flares Out (installation of VRU compressors), Sapele LPG Storage & Offloading Facility, Oben LPG Project and Ohaji Flares Out Project. The Company is on track to end routine flaring of gas in 2H 2025.

Proposed acquisition of MPNU

On 22 October 2024, we reported that we had received confirmation from the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) that Ministerial consent has been granted by the Honourable Minister of Petroleum Resources in Nigeria, President Bola Ahmed Tinubu GCFR, to proceed with the acquisition of the entire issued share capital of Mobil Producing Nigeria Unlimited (MPNU).

Following receipt of Ministerial consent the Company is now working to complete the transaction. This includes four main work streams, which are all at an advanced stage of completion. 1) Nigerian regulatory process: Work is ongoing to finalise the transaction documentation in order to complete the transfer of MPNU to the Seplat Group, 2) UK Prospectus: Given the transaction is classed as a reverse takeover ('RTO') under UK listing rules, the company is required to publish a full prospectus. The prospectus process is underway with the UK Financial Conduct Authority ('FCA'). 3) Operational Readiness: Seplat Energy has various teams engaged to ensure a smooth transition of MPNU into the Seplat Group. 4) Financing the transaction: Seplat Energy plans to fund the transaction via equity cash, our undrawn RCF and a new debt facility. 

Outlook

Following robust performance year to date, and after adjusting for the revised start-up of the ANOH gas project, we narrow our production guidance to 46,000-50,000 boepd (previously 44,000-52,000 boepd). The mid-point of guidance is unchanged. 

Year to date, drilling activity and cost has been towards the upper end of original expectations. Our 2024 drilling program is on track to deliver the wells which will support production in the quarters ahead. As such, we now expect full year capex to be at the top end of previous guidance range ($170 million - $200 million). 

Over the coming months, the Company is looking to deliver a number of key milestones including; completion of the MPNU acquisition, first gas at ANOH and Sapele Gas Plant, crude evacuation from Abiala, completion of a number of End of Routine Flaring projects and unrestricted 24-hour operations on the TNP pipeline.

Financial review

Revenue

Oil

In the first nine months of 2024, Brent crude oil benchmark price averaged $81.79/bbl, down 2% on the average in the first six months of 2024, after weaker pricing in 3Q 2024, but flat on 9M 2023's average of $81.96/bbl. A confluence of continued management of crude oil output by OPEC+ member nations, elevated geopolitical tensions and mixed macroeconomic developments have all contributed to keeping average prices around similar levels to last year.

The Company continues to benefit from oil price realisations at a modest premium to Brent, realising $82.89/bbl, an average premium to Brent of $1.10/bbl. Our realised price was relatively flat compared to the equivalent figure in 9M 2023 ($82.76/bbl). 

Total crude revenues declined 12.7% to $625.2 million in 9M 2024, from $716.4 million in 9M 2023. The decline is largely attributed to lower liftings in the period, with total crude lifted in 9M 2024 13% lower at 7.54 MMbbl vs. the 8.66 MMbbl lifted in 9M 2023.

9M 2024 crude revenue excludes an underlift of 7 kbbl (valued at $0.5 million), while 9M 2023 includes an overlift volume of 1.28 MMbbl (valued at $127.8 million).

After adjusting for underlift at 9M 2024, crude oil revenue was $633.4 million, which is 7.6% higher than the adjusted 9M 2023 crude oil revenue of $588.5 million, this reflects slightly higher oil production and realised pricing in the period.

Gas

Gas revenue fell by 4.0% to $90.2 million in 9M 2024 (compared to $94.0 million in 9M 2023). The reduction in gas revenue was due to lower production, partially offset by higher gas price realisations.

Production in 9M 2024 fell 10.7% to 28.4 Bscf, from 31.8 Bscf in 9M 2023. This was partially offset by the average realised gas price, which rose by 10.8% to $3.18/Mscf in 9M 2024, from $2.87/Mscf in 9M 2023. The average realised gas price improvement reflects the impact of price escalations on a gas contract which took effect in the period. In addition, higher prices for DGDO gas contracts (increased from $2.18/MMBtu to $2.42/MMBtu in April 2024) contributed to the realised gas price during the period.

Total Oil & Gas Sales

Revenue from combined oil and gas sales in 9M 2024 was $715.3 million, an 11.7% decrease from the $810.4 million achieved in 9M 2023.

Gross profit

Gross profit fell 14.7% to $355.0 million in 9M 2024, from the $416.3 million recorded in 9M 2023. The decline was largely driven by the lower reported revenue in the period (due to overlifts in 9M 2023), an increase in direct operating costs, due to higher gas flaring penalty (9M 2024: $19.2 million vs 9M 2023: $4.4 million), net off by reduction in Royalty charges. The reduced royalty charge follows an agreement with JV partners to share liftings via Walter smith refinery ("WSR"). In the period from 2022 to the agreement in 2024, only Seplat was lifting crude via WSR. We remain focused on delivering our routine flare reduction projects, slated to come online in H2 2025. Upon completion, these projects will substantially minimise gas flares penalties and concurrently support revenue growth. Adjusting for Gas flare penalty fees driven by higher government tariffs from mid-2023, production costs are 8.4% lower year on year.

Adjusting gross profit for underlift/overlift, we recorded a 25.9% growth to $363.3 million in 9M 2024 (9M 2023: $288.4 million), primarily driven by lower cost of sales in the period. This translates to an adjusted gross margin of 51% in 9M 2024 (9M 2023: 36%).

Direct operating costs include expenses related to crude-handling charges (CHC), barging/trucking, operations and maintenance, amounted to $131.8 million in 9M 2024, marking a 3.7% increase from the $127.1 million incurred in 9M 2023.

Considering the cost per barrel equivalent basis, production operating expenses (opex) rose to $10.1/boe in 9M 2024, compared to $9.7/boe in 9M 2023.

Non-production costs which primarily includes $107.6 million in royalties and $114.1 million in depreciation, depletion, and amortisation (DD&A), declined from the $141.2 million in royalties and $116.9 million in DD&A reported in 9M 2023. 

Operating profit

Operating profit increased by 77.5% to $274.8 million in 9M 2024, from $154.8 million achieved in 9M 2023. In addition to the contribution from higher adjusted oil revenue, other reasons for increases in operating profit was attributed to the items below. 

Firstly, and under non-cash items is a reversal in the impact of foreign exchange on the income statement as the Company reports a $17.1 million accounting adjusted FX gain in 9M 2024 (9M 2023: $27.8 million FX loss). In mid 2023 the Naira began to materially depreciate versus the US Dollar. This depreciation led to the Company recording an FX loss in 9M 2023 following revaluation of the Naira financial asset balances on our books. Conversely, in the second quarter, we received approvals from our JV partner on OML 53, NUIMS to net off outstanding cash calls with the overlift volumes on the asset. The subsequent redenomination of overlift liabilities in Naira led to an accounting adjusted FX gain of $17.1 million in 9M 2024. Partly net off from this increase is an impairment of $7.4 million on the Turnkey rigs after the successful sale of the rigs were consummated in Q3, 2024. (See section on cash flow from investing activities below)

In addition, the Company reported a decline in General and Administrative (G&A) expenses. G&A expenses amounted to $95.9 million, 8.3% lower than the $104.5 million incurred in 9M 2023. The decrease in G&A costs was mainly due to lower spending on Professional and Consulting fees, reflecting lower litigation costs compared to 9M 2023 when the company had to manage an unprecedented and intense period of minority shareholder actions through the courts. Seplat remains committed to minimising G&A expenses and continues to implement measures to manage all costs. 

After adjusting for non-cash items such as impairment, fair value losses, and exchange gains, the Company reports adjusted EBITDA for 9M 2024 of $383.0 million, up 25% on the prior period (9M 2023: $306.4 million). This results in an adjusted EBITDA margin of 53.5% (9M 2023: 37.8%). The increase in adjusted EBITDA reflects the impact of lower non-production costs, such as royalties during the period.

Taxation

The income tax expense of $209.7 million includes a current tax charge of $65.7 million (9M 2023: $54.3 million) and a deferred tax charge of $144.0 million (9M 2023: deferred tax credit of $27.3 million). The higher current tax this year resulted from higher taxable profit due to lower costs for the period.

The deferred tax charge in 9M 2024 was driven by the FX gains and underlift for the period which are excluded from petroleum profit tax (PPT) calculations, giving rise to the creation of a deferred tax liability. This contrasts with 9M 2023's deferred tax credit which arose due to creation of deferred tax assets from the overlift and FX loss recorded in the period.  The effective tax rate for the period was 86% (9M 2023: 25%).

Net result

Profit before tax increased by 129.9%, amounting to $245.0 million, compared to $106.5 million in 9M 2023. However, primarily due to the significant increase in taxation in 9M 2024 (as explained above), net profit declined 55.7% to $35.3 million in 9M 2024, from $79.5 million in 9M 2023. 

The profit attributable to equity holders of the parent company, representing shareholders, was $38.7 million in 9M 2024, which resulted in basic earnings per share of $0.07/share for the period (9M 2023: $0.07/share). 

Cash flows from operating activities

During the period, the Company generated $423.3 million in cash from its operations, a 16.8% increase from the $362.3 million generated in 9M 2023, driven by improved receivables collection. During the quarter, we continued to receive cash call payments from our JV partners. On our NEPL/Seplat JV and NEPL/Elcrest JV balance, we received an aggregate cash call amount of $341.4 million, lowering the aggregate receivables balance at period end to $47.5 million. At the end of 9M 2024, we had no receivables outstanding from our JV partner on OML 53.

Net cash flow from operating activities amounted to $361.8 million in 9M 2024, compared to $296.3 million in 9M 2023. Cash tax payments of $64.0 million (9M 2023: $60.5 million) and hedge premiums paid of $4.1 million (9M 2023: $3.9 million) during the current period, were broadly stable on the prior period.

Cash flows from investing activities

The total net cash outflow from investing activities was $126.8 million, which increased from the $110.4 million recorded in 9M 2023, the increase was due to increased capex, partially offset by receipts from disposal of assets. We received $5.4 million in respect of the divestment from Ubima and $10.9 million from our financial interest in OML 55. The $6.1 million proceeds from disposal of other PPE represents the initial cash payment agreed for the sale of Turnkey rigs (formerly known as Cardinal drilling rigs). We made the strategic decision to sell the Turnkey drilling rigs in order to concentrate on our core strengths and long-term objectives. The Turnkey rigs were sold for $12.3 million, with final payments expected by April 2025.

The capital expenditure on oil & gas assets during the period was $153.6 million, including $114.2 million invested in drilling activities and $39.4 million invested in engineering & gas projects. Total capex (including other fixed assets) was $157.0 million.

Cash flows from financing activities

Net cash outflows from financing activities were $198.8 million, which increased from the $168.6 million recorded in 9M 2023. The increase was driven largely by principal repayments on loans of $38.5 million (9M 2023: $22.0 million) related to the Eland Senior RBL facility and share purchases for the Company's LTIP of $19.3 million (9M 2023: $nil).

Elsewhere, $62.5 million for interest on loans and borrowings, reflecting the cost of servicing the Company's debt obligations, were modestly higher versus the prior period, while commitment fee and associated transaction costs of $6.9 million were modestly lower.

The Company paid $70.6 million in dividends to investors during the period, down from $76.1 million in the prior period due to the magnitude of the special dividend paid for 2023 (FY 2022 special dividend paid in 2023 was US$5.0 cents while FY 2023 special dividend paid in 2024 was US$3.0 cents).

Liquidity

* including amortised interest

The balance sheet remains healthy with a solid liquidity position. Seplat Energy ended the year with gross debt of $703.8 million (with maturities in 2026 and 2027) and cash at bank of $433.9 million, leaving net debt at $270.0 million. We also ended 9M 2024 with a restricted cash balance of $24.4 million including $2.4 million and $21.0 million set aside in the stamping reserve and debt service reserve accounts for the revolving credit facility. 

As the Company continuously reviews its funding and maturity profile, it continues to monitor the market in ensuring that it is well positioned for any refinancing and or buyback opportunities for the current debt facilities - including potentially the $650 million 7.75% 144A/Reg S bond maturing in 2026.

Post reporting period, Fitch Ratings published its rating action commentary on Seplat Energy, revising the outlook on our Long-Term Issuer Default Rating (IDR) to Positive from Stable and affirmed the IDR at 'B-'. Fitch also affirmed that the upgrade to a positive outlook reflects that an upgrade of Nigeria's Long-Term IDR could result in an upward revision of the country ceiling, which would no longer constrain Seplat's Long-Term IDR at the current level.

Dividend

Following board consideration and approval, we are pleased to announce a 20% increase in our quarterly core dividend payment to US3.6 cents per share from 3Q 24, this level has been committed for 4Q 24 as well, as such the total core dividend to be declared in respect of 2024 will be US 13.2 cents per share, a 10% increase on 2023. The dividend increase is due to the strength of the underlying business and does not factor in the potential enhancement in the shareholder returns policy that may be supported by the organic (ANOH) and inorganic (MPNU) growth opportunities that the Company is currently pursuing.

In line with the company's quarterly dividend policy, the board has approved a Q3 2024 dividend of US3.6 cents per share (subject to appropriate WHT) which will be paid to shareholders whose name appear in the register of members as at the close of business 12 November 2024. This brings total dividends announced for the 2024 financial reporting cycle to US9.6 cents per share.  

Hedging

Seplat's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. Total volumes hedged for 2024 amount to 6.0 MMbbls with the average cost to hedge these volumes for 2024 being $0.81/bbl.  In line with our policy to target hedging two quarters in advance, we have hedged additional 1.5 MMbbls at a strike price of $55 for Q1 2025. The Board and management team 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.