Seplat Energy Announces Its Results for the Full Year Ended 31 December 2021

Source: www.gulfoilandgas.com 2/28/2022, Location: Africa

Seplat Energy Plc, a leading Nigerian independent energy company listed on both the Nigerian Exchange Limited and the London Stock Exchange, announces its audited results for the full year ended 31 December 2021.

Operational highlights
? Strong safety record extended, 28 million hours without LTI from Seplat Energy operated assets
? Delivered robust performance against challenging year for Nigerian oil & gas industry
? Working interest production averaged 47,693 boepd, impacted by August and December FOT shut ins
? Completed nine wells: five oil and four gas wells
? Eland’s OML 40: four wells drilled at a total gross cost of US$60million, now delivering 15.5 kbopd (gross)
? Sibiri exploration on OML40 drilled to TD in February with initial indications it has encountered eight oil bearing reservoirs with 353 ft of gross hydrocarbon pay, net pay of 229 ft; further data acquisition and analysis are underway

Financial highlights
? Revenues up 38% to $733 million ($747 million including $14 million underlift)
? Adjusted EBITDA up 40% to $372 million,
? Strong cash generation of $394 million against capex of $137 million (excluding cost of rig acquisitions)
? Strong balance sheet with $341 million cash at bank, net debt of $426 million and
? Q4 dividend of US2.5 cents per share recommended

Corporate updates
? Name changed to Seplat Energy to reflect evolving strategy
? Proposed $1.28 billion MPNU acquisition adds transformational shallow water portfolio with dedicated export routes
? AEP mechanically completed in January, hydrocarbons introduced into line as part of commissioning process, commercial agreements to enable production into terminal being finalised; injection expected in March
? ANOH project mechanical completion expected H2 2022 (84% complete at present, all materials in country), however delays to third-party spur line likely to delay first gas to H1 2023
? Related party transactions eliminated from 1 January 2022

Outlook for 2022 (excluding MPNU)
? Production guidance of 50-60 kboepd, capex expected to be $160 million
? MPNU next steps: focus on government approvals and transition planning, completion expected H2

Roger Brown, Chief Executive Officer, said:
“Seplat Energy announced a major acquisition last week and despite a challenging year for Nigerian oil and gas, the robust results delivered today clearly show how our increasing financial strength has made such an acquisition possible, without the need to dilute shareholders, by giving international financial partners the confidence to invest in our vision.

The addition of MPNU nearly trebles our production and doubles our reserves on a pro forma 2020 basis, reinforcing our leadership of Nigeria’s indigenous energy sector and enabling us to generate strong future cash flows that will underpin our investment in Nigeria’s energy transition and improve our overall stakeholder returns.

Our 2021 performance was affected by outages at Forcados Terminal that will no longer have such an impact when we switch to the new Amukpe-Escravos Pipeline, which we expect to launch in March. This is part of our strategy to diversify and derisk routes to market, assuring higher revenues from significantly better uptime and lower reconciliation losses. Furthermore, once we have completed our acquisition of MPNU, we will add significant production from offshore assets with dedicated export terminals that also have higher availability and lower reconciliation losses.

The addition of MPNU offers a significant undeveloped gas resource base which, alongside our ANOH gas project development, will underpin Nigeria’s energy transition and drive domestic and export revenues when developed.

Our financial strength is matched by the skills and ambitions of our staff and we look forward to welcoming more than a thousand highly trained colleagues from MPNU and working with them to ensure their smooth onboarding into Seplat Energy. Together we will build a sustainable, world-class company that generates attractive returns for stakeholders and delivers energy transition for one of the world’s largest and most rapidly growing populations.”

Operating review

HSE performance
Safe and responsible operations are critical to the delivery of Seplat Energy’s strategy. Staff and contractors worked a total of 8.0 million man-hours with no fatalities, lost-time injuries, or major injuries in the period.

The Company has achieved 28 million hours without LTI on its operated assets. There were 88 HSE incidents in total, compared to 107 in 2020, including two reportable spills and six gas leaks, all of which were remediated with limited environmental impact. The Group established appropriate processes and safeguards for its people and operations against Covid-19.

By the end of December, we had conducted 14,319 Covid-19 tests, with a positivity rate of 3.3%. We have a vaccination policy for Covid-19 management and continue to enforce all Covid-19 control protocols at our field operations and offices, with no major Covid-19 related incidents.

Reserves
Seplat Energy’s portfolio comprises direct interests in seven oil and gas blocks and a revenue interest in one other block. This portfolio provides us with a robust platform of oil and gas reserves and production capacity, as well as material upside opportunities to add reserves through future development.

At 31 December 2021, total working interest 2P reserves, as assessed independently by Ryder Scott Company, L.P., stood at 457.1 MMboe, comprising 219.2 MMbbls of oil and condensate and 1,379.4 Bscf of natural gas (237.8 MMboe). The change represents an organic decrease in overall 2P reserves of 8.4% year-on-year, due to production of 10.6 MMbbls of liquids and 39.3 Bscf of gas, and reclassification and revisions of previous estimates.

Working interest 2C resources stood at 74.9 MMboe, comprising 40.9 MMbbls of oil and condensate and 197.1 Bscf of natural gas compared to 94.8 MMboe in 2020. The 21.1% decrease is mostly due to the inability to prove producibility in Mosogar following the unsuccessful Drill Stem Test (DST). Consequently, the Group’s working interest 2P reserves and 2C resources stood at 531.9 MMboe at 31 December 2021, comprising 260.1 MMbbls oil and condensate and 1,576.5 Bscf of natural gas (197 MMboe).

Production
Our oil and gas assets are in the onshore land and swamp areas of the prolific Niger Delta in Nigeria. Principal areas of production are Edo, Delta, Imo and Rivers States with evacuation for export through the Forcados, Bonny and Brass oil terminals. Seplat Energy has significant opportunities within its reserves base to grow production and extend field life through infill drilling, well intervention programmes, and innovation through technology deployment.

Full-year total working interest production for 2021 averaged 47,693 boepd. Within this, liquids production was down 13.7% year-on-year. Delays in replacing the MT Harcourt storage vessel on OML40 reduced exports from the asset in the first quarter of 2021. In addition, volumes were impacted by decreased production from the Western Assets owing to the disruption caused by the suspension of exports at the Forcados Oil Terminal (FOT) for significant periods in the year. The impact of unplanned downtime in the second half of the year amounted to a deferment of working interest production of c.1.0 MMbbls of oil from OMLs 40, 4, 38 and 41. There was a 75% production uptime for the Trans Forcados System during the year. The impact of future FOT outages will be alleviated by our use of the new Amukpe-Escravos Pipeline, the launch of which is imminent following mechanical completion and introduction of hydrocarbons, with only commercial agreements pending.

Gas volumes were up 6.9% year-on-year to 107.9 MMscfd.

Drilling activities
During the period, we drilled and completed eight wells, with an additional well completed early January 2022. In OML 4 we completed the Oben-50 and Oben-51 gas wells, which are now producing at a combined gross rate of c. 60 MMscfd of gas and 4,000 bpd of condensates. We also completed the workover of Oben-44 and 46 gas wells in the fourth quarter with combined gross production rate of 70 MMscfd and 1,200 bpd.

In OPL 283, the Umuseti-07 well was successfully completed in August and is producing ca.2,000 bopd gross.

The three-well Gbetiokun drilling campaign was completed ahead of schedule with cost savings of 25%, achieved through efficient execution, underpinned by the optimisation of drilling parameters and logistics. The wells were drilled in tandem and batch drilled. The Gbetiokun-06, 07 and 08 wells have commenced production, with gross production of approximately 12,000 bopd combined. An additional well, Gbetiokun-09, was drilled in December 2021, hooked up in January 2022 and is producing approximately 3,500 bopd gross. Given the strong production of the new Gbetiokun wells, we deployed a larger evacuation vessel, MT Hampden, in November to improve evacuation of crude.

Project activities associated with preparation for drilling the high-impact, near-field Sibiri (formerly Amobe) exploration well in OML 40 were completed in 2021 and the well was drilled in Q1 2022. The well has been drilled to TD, with initial indications it has encountered eight oil-bearing reservoirs with 353 ft of gross hydrocarbon pay, net pay of 229 ft. Further data acquisition and analysis on the well is underway.

Despite persistent adverse weather, we progressed preparation of the Owu appraisal well in OML 53. However, the two wells (OHS KBAM1 and Owu appraisal) planned for OML 53 in 2021 were deferred to 2022 due to partner recommendation and rig contracting challenges.

We continue to exercise discretion over drilling investments and selectively consider opportunities in our existing portfolio with a view to capturing the highest cash return investment opportunities, whilst diligently preserving a liquidity buffer.

Focus on asset integrity
At the core of Seplat Energy’s operations is a focus on asset integrity, process safety and maintenance culture, to ensure and improve the safety, reliability, and availability of our facilities. This also promotes higher revenue assurance. We are making progress towards an ISO 55001 Certification with full implementation of the ISO standards by 2023. As defined in our July 2021 Capital Markets Day (CMD), and as part of our commitment to continuous improvement, Seplat Energy’s goal through various initiatives is to reduce deferment by c.120kbbl annually, which will increase revenue assurance and profitability.

Other capital projects
As indicated in our CMD, we initiated projects targeting cost reduction that are also expected to increase production in the long term.

At OML 4, 38 and 41, we decommissioned the leased pumps at Amukpe and started the installation of seven NOV pumps. The pump replacements will reduce deferment of crude oil and improve produced water disposal. We undertook a delivery line re-routing project for the Sapele-Amukpe pipeline to reduce the risk of pipeline failure on the heavily encroached right of way and extended the life span of the pipeline. We completed and secured 5.1 km of the re-routed section and are reviewing tie-in options.

The optimisation of the Jisike Flow Station Debottlenecking and Gaslift Compressor Station commenced in the period to provide lift gas for secondary recovery of crude oil from existing weak wells. This includes an upgrade of the capacity of the flowstation from 10 kbpd to 15 kbpd to handle future increased production from the asset and a 6 MMscfd associated gas (AG) compressor station to optimise gas lifting of oil wells and reduce flaring.

Oil business performance
Seplat Energy’s liquids (oil and condensate) operations produced 10.6 MMbbls on a working interest basis in 2021 (2020: 12.3 MMbbls). The average realised price per barrel in the period was $70.54 (2020: $39.95), following a recovery of Brent prices on the receding threat from the Covid-19 pandemic and the resultant return of global economic activity.

The lower-than-expected oil production for the year was primarily due to the curtailment of production and suspension of export operations from OMLs 4, 38, 41 and 40, after Shell Petroleum Development Company Limited (SPDC) declared a month-long force majeure at the Forcados Oil Terminal (FOT) on 13 August because of a failure of the loading buoy at the FOT. This was exacerbated by a 12-day shut in of the flow stations due to technical fault at the FOT in December.

Previously, delays in siting a new storage vessel at OML 40 to replace the MT Harcourt, which was damaged in November 2020, resulted in significantly lower volumes in the first quarter.

In December 2020, Seplat Energy signed a Crude Purchase Agreement (CPA) with Waltersmith Petroman Oil Limited (Waltersmith) for the supply of between 2,000 and 4,000 bopd from existing working interest production from the Ohaji South Field within OML 53, for Waltersmith's 5,000 bopd modular refinery at Ibigwe, in Imo State. We commenced the supply of 2,000 bopd to the Waltersmith Refinery in October with 172 kbbls supplied during 2021 and no pipeline losses recorded.

OPEC+ quotas
During the period, Nigeria’s quota stood at 1.6 million barrels per day, excluding condensates. However, the country’s production has trended below allocated production, largely because of downtime on major pipelines, crude oil theft and several operational challenges leading to production capacity constraints in the assets. Seplat’s OPEC quota is currently 68,554 bopd for the Western Assets and 13,007 bopd for the Eastern Assets. Seplat has lifted below the OPEC quota for the past 6 months due to the reasons highlighted above. Following its July meeting, OPEC+ agreed an increased oil output of 1.8 million bopd for Nigeria, which restores all the production cuts imposed when the Covid-19 pandemic started in 2020. The new quota, which excludes condensates, will take effect in 2022.

Amukpe-Escravos pipeline commissioning
Following the introduction of hydrocarbons into the pipeline in December 2021 as part of the start-up and testing process, mechanical completion has now been achieved and we are finalising crude handling and offtake agreements to enable flowing of oil into the Escravos terminal, expected in March. Oil Lifting from the terminal will be undertaken by the terminal operator - Chevron, expected in Q2.

The 67km, mostly underground pipeline, provides a reliable and secure export route for liquids from Seplat Energy’s major assets OML 4, 38 and 41, connecting them with the Chevron-operated Escravos Terminal. Until now, we have relied on the Trans Forcados System, which has experienced numerous disruptions due to maintenance and vandalism. The Amukpe-Escravos pipeline has a capacity of 160,000 bpd, into which the Seplat Energy / NPDC joint venture is entitled to inject 40,000 bpd.

Including the Warri Refinery, Seplat Energy now has access to three independent export routes for production from OMLs 4, 38 and 41. It is our intention to utilise all three to ensure there is adequate redundancy in evacuation routes, reducing downtime that has adversely affected revenues over a number of years, and significantly de-risking the distribution of products to market.

Gas business performance
Alongside the oil business, we have also prioritised the development and commercialisation of the substantial gas reserves identified in our assets, to pursue new market opportunities. Today, Seplat Energy is a leading supplier of processed natural gas to the Nigerian domestic market, which is independent of global oil and gas market dynamics. With 100% of volumes dedicated to supplying key demand centres within the domestic market, our customers include power generation companies and the National Gas Marketing and Distribution Company, which serves the power generation, industrial and agricultural sectors. Seplat Energy is therefore strategically important to the security of Nigeria’s current and future gas supply.

Seplat Energy maintained a reliable and increased gas supply to customers during the year. Working interest gas production for the period was 107.9 MMscfd at an average selling price of $2.85/Mscf (2020: 101 MMscfd, $2.87/Mscf). The Gas business contributed 41.2% of the Group’s volumes on a boepd basis.

Gas pricing
The price of gas for power generation (Domestic Supply Obligation), which accounts for about 30% of our gas volumes, was reduced from $2.50/Mscf to $2.18/Mscf in July 2021 (implemented in August 2021) following a review of the gas pricing framework by the Federal Government (FGN). As part of the process to stabilise the sector, the Government has taken various measures to address challenges with domestic gas utilisation as well as pricing and fiscal policy issues limiting adoption. It is expected that the lower gas price will translate to a reduced electricity tariff for the end consumer and will improve collection for the entire value chain, as well as stimulate growth in demand.

The regulated Domestic Supply Obligation (DSO) gas-to-power price of $2.18/Mscf is expected to remain until a transition to a ‘willing buyer/willing seller’ regime in 2023 (latest 2025) for a fully deregulated market. We have assessed the business and economic impact of the price reduction on Seplat Energy’s gas portfolio and this price review will result in a temporary reduction of the average weighted gas price to around $2.7/Mscf in 2022. With the FGN’s “Decade of Gas” programme promoting gas as Nigeria’s transition fuel towards Net Zero, we are confident of the growth of gas demand and a corresponding adjustment in the pricing regime.

Oben Gas Plant
Despite the impact on oil volumes following the force majeure at the Forcados Oil Terminal in the third quarter, disruption to gas volumes was minimal because the associated condensate volumes were stored in the Amukpe buffer tanks, ensuring continuity of gas production. However, our Associated Gas (AG) station units were put on standby due to FOT outage.

To ensure the delivery of on-specification gas to our customers, we completed the installation of heat exchanger trains 1 and 2; piping installation works on heat exchangers 3, 4 and 5 are ongoing with commissioning expected in the first quarter of 2022.

Additional third-party volumes
Seplat Energy is focused on developing third-party gas processing opportunities that can utilise the remaining processing capacity at Oben. Securing additional volumes from counterparties will secure long-term supplies of raw natural gas from which we can optimise the plant’s utilisation and generate tolling revenues. We progressed discussions with targeted thirdparty gas producers during the year and expect to conclude terms shortly.

Sapele Gas Plant
Work continues on the new Sapele Gas Plant with project progress at 45%. Upon completion, the processing capacity will be 85 MMscfd. 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 ensure that gas flaring is eliminated.

ANOH Gas Processing Plant
We have made good progress on the ANOH plant but have seen some delays in shipments and releasing equipment from the ports. To date, we have achieved 84% overall project completion at the gas plant site. Our government partner, the Nigerian Gas Company, (NGC) is delivering the pipelines that will take the gas from ANOH to Oben, namely the 23km spur line and the Obiafu-Obrikom-Oben (OB3) pipeline.

The OB3 pipeline project has seen a number of failed attempts to complete the 1.85km river crossing, which is needed to complete the pipeline. However, the latest contractor is making progress and the HDD drilling stands at 20% complete. We do not anticipate the OB3 pipeline to delay the completion of the overall ANOH project.

The Spur Line project has seen significant delays due to contracting issues and payments. We have been informed that the milling of the line pipes, which is being undertaken in China, will now commence in Q2 and therefore will not arrive Nigeria until later this year. The latest schedule provided by NGC shows completion in Q4 2022 / Q1 2023.

We had earlier communicated a first gas date by mid-year 2022, but based on our current risking, we now expect further delays of between 9-12 months to the original timeline, with the spur line expected to be the last piece of infrastructure delivered.

The upstream development, including the drilling of six production wells, will be delivered by the upstream unit operator SPDC. We expect that the two wells on which drilling commenced in 2021 will be completed this year.

Located at OML 53 (in a unitised field between Seplat JV’s OML 53 and SPDC JV’s OML 21), the ANOH Gas Processing Plant development will drive the next phase of growth for Seplat Energy’s core Midstream Gas business. The 300 MMscfd midstream gas processing plant is the most advanced of the FGN’s seven critical gas projects and is central to the National Gas Master Plan to develop and expand the indigenous domestic gas market for additional power and industrial projects.

The ANOH plant is being built by AGPC, which is an Incorporated Joint Venture (IJV) owned equally between Seplat Energy and the NGC, a wholly owned subsidiary of the Nigerian National Petroleum Corporation ("NNPC"). In February 2021, AGPC successfully raised $260 million in debt to fund the 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). The plant construction cost is expected to be no more than $650 million, inclusive of financing costs and taxes, which is significantly lower than the original projected cost at Final Investment Decision (FID) of $700 million.

Net Zero by 2050
Seplat Energy supports the goals of the Paris Agreement and is in step with society’s objective to get the world to net zero carbon emissions by 2050, if not before. Around 90% of the Company’s Scope 1 and 2 emissions come from flaring of associated gas. Through investments in decarbonisation projects over the next two years, we plan to focus on maximising gas-to-grid options, which will capture and monetise gas for productive use, drive LPG production and put the Group on track to end routine flaring by 2024.

Aside from ending routine flares, we are investing in other ways to decarbonise our operations such as replacing diesel with LPG or LNG and onsite solar energy generation. Longer-term, as part of Nigeria's energy transition, we will selectively target opportunities in solar energy projects, which alongside our gas-to-power developments, will be critical to providing an alternative to Nigeria’s expensive and extensive diesel generated electricity.

Outlook and plans for 2022
Full-year production guidance for 2022 is set at 50,000 to 60,000 boepd on a working interest basis, comprising 30,000 to 35,000 bopd liquids and 116 to 150 MMscfd (20,000 to 25,000 boepd) gas production. This guidance does not include any contribution from MPNU and the ANOH Gas Plant.

We expect production uptime of 75% for evacuation through the TFS and 90% for evacuation via the AEP, the latter being our preferred export route from OMLs 4, 38, & 41.

Capital expenditure for 2022 is expected to be around $160 million. We expect to drill a minimum of ten wells, including the Sibiri exploration well and one appraisal well, complete ongoing projects, invest in maintenance capex to secure the existing assets and continue investments in gas. The 2022 drilling programme is designed to address production decline and along with completion of maintenance activities, will support long-term production levels from the assets. With the recovery in oil prices, rig-based and other project activities activity will ramp-up in 2022.

Facilities and engineering projects will focus on delivery of an upgraded integrated gas processing facility at Sapele and further upgrades to the liquid treatment facility to enable increased deliveries of dry crude. Towards our goal to end routine flaring by 2024, we will focus on Oben, Amukpe, Sapele & Jisike end of routine flaring projects, which will capture and monetise gas for productive use.

In OML 53, in addition to drilling, we plan to complete the Jisike flow station debottlenecking and gaslift compressor station and installation of the Ohaji South Lease Automatic Custody Transfer (LACT) Unit.

For the non-operated assets, in OML 40, in additional to the drilling plans, facilities and engineering work will focus on the Gbetiokun facilities upgrade to optimise the Gbetiokun barging operations; whilst we complete all front-end activities for the Gbetiokun to Adagbasa pipeline which will replace the barging of the produced crude. In OPL 283, we have planned one gas well re-entry for production testing and the Igbuku gas plant design (FEED). The delivery of the 2022 workplan will be underpinned by a strong commitment to safety, asset integrity, GHG emissions reduction and operational excellence.

Outlook and plans for 2022
Full-year production guidance for 2022 is set at 50,000 to 60,000 boepd on a working interest basis, comprising 30,000 to 35,000 bopd liquids and 116 to 150 MMscfd (20,000 to 25,000 boepd) gas production. This guidance does not include any contribution from MPNU and the ANOH Gas Plant.

We expect production uptime of 75% for evacuation through the TFS and 90% for evacuation via the AEP, the latter being our preferred export route from OMLs 4, 38, & 41.

Capital expenditure for 2022 is expected to be around $160 million. We expect to drill a minimum of ten wells, including the Sibiri exploration well and one appraisal well, complete ongoing projects, invest in maintenance capex to secure the existing assets and continue investments in gas. The 2022 drilling programme is designed to address production decline and along with completion of maintenance activities, will support long-term production levels from the assets. With the recovery in oil prices, rig-based and other project activities activity will ramp-up in 2022.

Facilities and engineering projects will focus on delivery of an upgraded integrated gas processing facility at Sapele and further upgrades to the liquid treatment facility to enable increased deliveries of dry crude. Towards our goal to end routine flaring by 2024, we will focus on Oben, Amukpe, Sapele & Jisike end of routine flaring projects, which will capture and monetise gas for productive use.

In OML 53, in addition to drilling, we plan to complete the Jisike flow station debottlenecking and gaslift compressor station and installation of the Ohaji South Lease Automatic Custody Transfer (LACT) Unit.

For the non-operated assets, in OML 40, in additional to the drilling plans, facilities and engineering work will focus on the Gbetiokun facilities upgrade to optimise the Gbetiokun barging operations; whilst we complete all front-end activities for the Gbetiokun to Adagbasa pipeline which will replace the barging of the produced crude. In OPL 283, we have planned one gas well re-entry for production testing and the Igbuku gas plant design (FEED). The delivery of the 2022 workplan will be underpinned by a strong commitment to safety, asset integrity, GHG emissions reduction and operational excellence.

Financial review

Revenue and other income
Revenue from oil and gas sales in 2021 was $733.2 million, a 38.2% increase from the $530.5 million achieved in 2020. Crude oil revenue was $618.4 million (2020: $417.9 million), 48.0% higher than 2020, largely reflecting higher average realised oil prices of $70.54/bbl for the period (2020: $39.95/bbl). The total volume of crude lifted in the year was 8.8 MMbbls, lower than the 10.5 MMbbls lifted in 2020, due to the decrease in production following the suspension of exports at the FOT. In addition, the Group’s 2021 produced liquid volumes were subject to reconciliation losses of 14.5%, compared to less than 10% in the corresponding period in 2020. We expect these to improve significantly when we evacuate the bulk of our crude through the Amukpe-Escravos underground pipeline.

Gas sales revenue increased by 2.0% to $114.8 million (2020: $112.5 million), due to higher gas sales volumes of 39.4 Bscf compared to 37.1 Bscf in 2020, which reflects new gas wells coming onstream during the period. The average realised gas price was slightly lower, at $2.85/Mscf (2020: $2.87/Mscf) and reflects the reduction applied to the DSO gas-to-power volumes from August 2021.

Other income of $20.1 million includes an underlift $13.9 million (shortfalls of crude lifted below Seplat’s share of production, which is priced at the date of lifting and recognised as other income) representing 152 kbbls and $5.2 million tariff income generated from the use of the Company’s pipeline. In addition, there was a $5.4 million reversal of decommissioning obligation no longer required for Eland operations in the period.

Gross profit
Gross profit increased by 128.9% to $285.2 million (2020: $124.6 million). The non-production costs primarily consisting of royalties and DD&A totalled $270.9 million, compared to $228.9 million in the prior year. The higher royalties were the result of higher oil prices, and the DD&A charge for oil and gas assets increased to $141.1 million (2020: $127.5 million), because of a higher depletion rate applied following a reclassification and revision of previous 2P estimates compared to the prior year.

Direct operating costs, which include crude-handling fees, rig-related costs and operations and maintenance costs amounted to $172.1 million in 2021, 2.6% higher than $167.7 million in 2020. The increase was primarily because of the higher operational and maintenance costs of $107.9 million that include unaccrued late charges of $13.8 million related to the OML 40 asset operated by NPDC. On a cost-per-barrel equivalent basis, production opex was higher at $9.9/boe (2020: $8.9/boe) due to the additional costs detailed above and the average working interest production reducing in 2021 compared to 2020. However, a continuous cost reduction drive for production evacuation from the Gbetiokun and Ubima fields resulted in a 26.4% reduction in barging and trucking costs, to $11.7 million (2020: $15.9 million).

IAS impairments reversal
As previously reported, under IAS 36 the Company identified the need to revalue its assets due to the significant economic uncertainty of the Covid-19 crisis in 2020 and booked a non-cash provision of $114.4 million across non-financial assets in the period. Following a reassessment of the business models and assumptions at the end of 2021, a reversal of $74.7 million was recognised to reflect the current and expected higher oil price environment.

Operating profit
The operating profit for the year was $250.7 million, compared to an operating loss of $31.7 million in 2020 (which resulted mainly from the $160.9 million impairment charges).

During the year, the Group recognised impairment losses totalling $38.1 million, which include financial asset charges of $22.6 million for outstanding receivables and non-financial asset charges of $15.2 million for the rigs. This was offset by the $74.7 million impairment reversal described above.

General and administrative expenses increased by 5.4% to $80.1 million (2020: $76.0 million) and reflect the increase in administrative activities across the business compared to the previous year, which was more heavily impacted by the Covid-19 pandemic and its associated reduction in activities.

An EBITDA of $371.8 million adjusts for non-cash items which include impairment, abandonment, and exchange losses, equating to a margin of 50.7% for the year (2020: $265.8 million; 50.1%).

Taxation
The income tax expense of $60.2 million reflects a higher assessable profit driven by higher accounting profit compared to the prior year, and represents an effective tax rate of 34% (2020: $5.1 million; 6%). The tax charge comprises a deferred tax charge of $22.6 million and a current tax charge of $37.6 million. The deferred tax charge is mainly driven by the unwinding of previously unutilised capital allowances.

Net result
The profit before tax was $177.3 million (2020: $80.2 million loss before tax) and profit for the year was $117.2 million (2020: $85.3 million net loss). The resultant basic earnings per share was $0.24 in 2021, compared to $0.13 basic loss per share in 2020.

Cash flows from operating activities
Cash generated from operations in 2021 was $394.3 million (2020: $329.4 million). Net cash flows from operating activities were $369.8 million (2020: $308.7 million), after accounting for tax payments of $12.9 million (2020: $10.4 million) and a hedge premium of $9.0 million ($8.4 million). Free cash flow for the period amounted to $200 million (2020: $163.9 million).

The Group received $235 million from the major JV partner towards the settlement of cash calls. The major JV receivable balance now stands at $83.9 million, down from $107.1 million at the end of 2020.

Cash flows from investing activities
Net capital expenditure of $136.4 million consisted of $37.7 million towards completing five development oil wells (Umuseti 07, GB-06, 07, 08, 09) and $26.3 million for completing two new gas wells (Oben 50, 51) and two workover wells (Oben 44, 46). Associated facilities and engineering costs amounted to $72.4 million. We realised significant cost savings from drilling in the period because of the relatively lower cost workover operations compared to new drills carried out for two Oben gas wells in addition the optimisation of drilling parameters and logistics applied in the execution of the Gbetiokun wells.

Payments for non-oil and gas assets amounting to $33.5 million relates to the net effect of consideration for the four Cardinal rigs at $36 million purchased in October 2021 and $3.5 million for spares classified as inventory. The rigs were funded out of already restricted funds (excluded from previous cash flow statements) held at Access Bank and the Federal High Court of Nigeria, as previously disclosed.

Seplat Energy received $4.9 million in the period through the allocation of 94.2 kbbls of crude oil from OML 55. Recovery in the period is below expectations and impacted by significant sabotage along the NCTL and TNP pipelines, with a theft factor of up to 60% recorded. The next lifting due to Seplat Energy is scheduled for March 2022 (previously December 2021 but delayed because of evacuation challenges) and we continue to work with BelemaOil to optimise production and sustain recovery of the remaining discharge amount. Out of $330 million to be paid to Seplat Energy, $129.9 million has been recovered with $200.1m outstanding.

Cash flows from financing activities
Net cash outflows from financing activities were $100.8 million (2020: $217.4 million). Proceeds from loans and borrowings of $671.0 million reflects the debt restructuring where the Group offered senior notes of $650 million. The gross proceeds of the notes were used to redeem the existing $350 million senior notes and to repay in full drawings of the $250 million RCF. It also reflects a further $10.0 million drawn from the Westport RBL facility and $11.0 million drawn on the $50 million off-take facility to support drilling operations at Elcrest. Payments for other financing charges, which include $20.4 million transaction costs on the debt facilities and interest paid on loans, totalled $89.6 million (2020: $65 million). The dividend payment for the period totalled $73.4 million (2020: $58.3 million), net of withholding taxes is $15.1 million higher because of timing of quarterly dividend distribution introduced in 2021.

A charge of $4.9 million relates to the share buy-back programme for Seplat Energy’s Long-Term Incentive Plan. The programme commenced on 1 March 2021 and shares are held by the Trustees under the Trust for the benefit of Seplat Energy employee beneficiaries covered under the Trust.

Liquidity
The balance sheet continues to remain healthy with a solid liquidity position.

Seplat Energy ended the year with gross debt of $766.6 million (with maturities in 2026 and 2027) and cash at bank of $340.5 million, leaving net debt at $426.1 million. Liquidity, which includes the $350 million RCF available for drawing, a $39 million undrawn offtake facility plus the cash balance, was more than $700 million at the end of the period.

Dividend
In line with the quarterly dividend policy announced in 2021, Seplat distributed four dividend payments in 2021 and paid out $73.4 million. The Board has recommended a final dividend of US2.5 cents per share for the financial year 2021, which will bring the total dividend declared for 2021 to $0.10 per share (2020: $0.10 per share).

Subject to approval of shareholders, the recommended dividend will be paid shortly after the Annual General Meeting, which will be held in Lagos, Nigeria, on 18 May 2022.

Hedging
Seplat’s hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. For 2021, the Group had in place dated Brent put options as follows: (i) for Q1, 1.0 MMbbls at a strike price of $30/bbl and 1.0 MMbbls at a strike price of $35/bbl; (ii) for Q2, 2.0 MMbbls at a strike price of $35/bbl; and (iii) for Q3, 1.0 MMbbls at a strike price of $35/bbl and 1.0 MMbbls at a strike price of $40/bbl. The $11.1 million hedging costs were recognised as fair value charges in the period.

This hedging programme has been continued in 2022 with put options for 5.0 MMbbls through Q3 2022 at an average premium of $1.41/bbl as follows: (i) for Q1, 1.0 MMbbls at a strike price of $50/bbl and 1.0 MMbbls at a strike price of $55/bbl; (ii) for Q2, 2.0 MMbbls at a strike price of $55/bbl; and (iii) for Q3, 1.0 MMbbls at a strike price of $55/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.

Credit ratings
Seplat maintains corporate credit ratings with Moody's Investor Services (Moody’s), Standard & Poor's (S&P) Rating Services and Fitch. The current corporate ratings are as follows: (i) Moody’s B2 (stable); (ii) S&P B (stable) and (ii) Fitch B (stable).

Elimination of related-party transactions
In our continuous efforts to promote world-class governance, all related-party transactions (RPT) were eliminated from 1 January 2022.

Petroleum Industry Act 2021
Nigeria’s Petroleum Industry Bill was signed into law on 16 August 2021, shortly after the bill received legislative approval from both the Senate and the House of Representatives. The assent by the Executive enacts the Petroleum Industry Act, 2021 (PIA 2021) as the superseding policy to provide legal, governance, regulatory and fiscal frameworks for the Nigerian petroleum industry, the development of host communities, and related matters. The PIA 2021 also repeals existing Acts and makes transitional and savings provisions to accommodate instances of licensees that may choose not to convert until their current license expires.

We have reviewed the fiscal provisions of the Act, and a multi-disciplinary project team has been commissioned to review the impact of Seplat Energy business entering the new PIA regime, versus the benefits of remaining in the current fiscal regime until the expiry of our licenses. The analyses will be based on the life-cycle data of all the assets and the result of the review will inform management’s decision on whether Seplat Energy converts to the PIA regime or remains in the current tax regime.

Climate change and financial disclosures
Seplat Energy Plc recognises that climate change and the decarbonisation of the global economy, within the context of the energy transition, present significant risks and opportunities to the company’s strategy, operations, and financial planning, and to the delivery of long-term shareholder value. Accordingly, Seplat Energy will, in the near future:
1. Adopt climate change as a Principal Risk within the company’s risk management framework; and
2. Carry out an assessment of the impact of climate change on the company’s financial statements using scenario analysis as recommended by the Taskforce on Climate-related Financial Disclosures (TCFD). Seplat Energy aims to publish an inaugural TCFD-aligned report in mid-2022.


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