Seplat Energy Plc, a leading Nigerian independent energy company listed on both the Nigerian Exchange Limited and the London Stock Exchange, announces its unaudited results for the nine months ended 30 September 2021.
- YTD working-interest production of 47,280 boepd down 6.7% year on year largely as a result of the shut-in
of the Forcados Oil Terminal (FOT) in August (Q3: 40,381 boepd)
- Liquids production down 16.6% year on year at 27,804 bopd, recovering to 33kbopd liquids in October
- Gas production up 13% to 113 MMscfd, despite FOT impact on associated gas
- Completed two gas wells and three oil wells in the period, new Gbetiokun wells performing strongly
Financial highlights (9M 2021)
- Revenue after adjusting for an underlift was $535 million
- EBITDA of $266.4 million
- Cash generated from operations $163.8 million
- Cash at bank $273.9 million, net debt of $479.8 million
- Total capital expenditure of $83.9 million
- Interim dividend of 2.5 cents ($0.025)
- Name changed to Seplat Energy Plc to reflect new strategic vision outlined in July; new branding launched in October
- Acquisition of Cardinal Drilling rigs for $36 million and cessation of legal proceedings by Access Bank
Outlook for 2021
- Expected production narrowed to 48-50 kboepd for full year, subject to market conditions
- Amukpe-Escravos Pipeline (AEP) commissioning has commenced, oil flow expected in December 2021
- Capex now expected to be $167 million for the full year
- ANOH project remains on track for first gas in H1 2022
Roger Brown, Chief Executive Officer, said:
"Production has recovered strongly since the outage at Forcados Oil Terminal (FOT) and we have been averaging nearly 33kbopd liquids throughout October. Now that production has normalised, we expect production to be in the range 48-50 kboepd for the year, provided uptime on the Forcados Pipeline and FOT remains above the budgeted 80%. I'm pleased to report that our new wells at Gbetiokun are performing strongly, and we will soon commence drilling the exciting Sibiri prospect on OML40.
We have taken the difficult, but practical decision to bring an end to the uncertainty of the Access Bank legal dispute regarding Cardinal Drilling Services, which completes the Board-mandated removal of Related Party Transactions. Although we maintain our previously stated position that legal action against the Company was wholly without merit, the risk of significant disruption to our operations and other opportunities from a long, drawn-out legal case brought us to a negotiated settlement with Access Bank. We have therefore acquired the four Cardinal rigs and we are now focusing on fast tracking their deployment in future drilling campaigns. `
Our business model is robust, despite setbacks in the third quarter, thanks to the prudent and flexible approach we have taken to managing the business. With an increased focus on efficiency in our operations, improving uptime by opening up the Amukpe to Escravos Pipeline and driving further cost reduction across our portfolio, this will provide the bedrock allowing us to operate effectively in fluctuating commodity prices and generate returns for shareholders. I am optimistic that the coming year will be much stronger, with many of the problems of the past put behind us.
After we set out our future strategy in July's Capital Markets Day and launched our new corporate name of Seplat Energy plc, complete with its new branding, we are now focusing on building out and executing the energy transition that is right for Nigeria. A strong step forward will be when we bring on stream the ANOH project next year delivering more transition gas to an energy poor market, over reliant on expensive, high carbon-emitting electricity generated from small-scale diesel and PMS generators. Our three-pillar strategy is designed to ensure we balance carbon emission reduction with the essential social agenda for undeniably the most under-electrified, youngest and fastest growing population on earth.
Seplat Energy's focus is clear: "Reliable energy, limitless potential".
Outlook for 2021
Liquids production has recovered strongly following the outage and force majeure at Forcados and after averaging approximately 33 kbopd liquids in October, we expect the Group's full-year liquids and gas production to be in the range 48-50 kboepd, assuming 80% uptime.
We expect to introduce liquids into the Amukpe-Escravos Pipeline in December, which will provide a secure and reliable alternative export route and reduce our reliance on the TFP, which has caused significant problems in the past.
Following its successful funding, the completion of the ANOH project remains a major priority and we expect first gas to be achieved in H1 2022, at lower cost than originally estimated at FID.
Staff and contractors worked a total of 5.6 million man-hours with no fatalities, lost-time injuries or major injuries in the period. The Company has achieved 26 million hours without LTI on assets operated by Seplat Energy. There were 64 HSE incidents in total, compared to 66 in 9M 2020, including two reportable spills and six gas leaks, all of which were remediated with limited environmental impact. By the end of September, we had conducted 9,348 Covid-19 tests, with a positivity rate of 2.2%. We continue to enforce all Covid-19 control protocols at our field operations and offices, with no major Covid-19 related incidents.
Working-interest production for the nine months ended 30 September 2021
Average working-interest production for the first nine months of 2021 was 47,280 boepd (12.9 MMboe), down 6.7% on the same period in 2020. Within this, liquids production was down 16.6% to 27,804 bopd, impacted by decreased production from the Western Assets owing to the disruption caused by the suspension of exports at the Forcados Oil Terminal (FOT), as well as previously reported delays in replacing the MT Harcourt storage vessel on OML40, which reduced exports from the asset in Q1 2021. However, gas production increased by 13% to 113 MMscfd for the nine-month period (9M 2020: 100 MMscfd).
The impact of an unplanned 40% downtime for one full month in the third quarter of the FOT (as against budgeted downtime of 20%) amounted to a loss of c.885 kbbls of oil in the third quarter from OMLs 40, 4, 38 and 41. Consequently, there was 74% uptime for the Trans Forcados Pipeline during the nine-month period and the produced liquid volumes from OMLs 4, 38 and 41 were subject to reconciliation losses of 11.3%.
Oil business performance
Seplat Energy's oil operations produced 7.6 MMbbls on a working-interest basis in 9M 2021 (9M 2020: 9.1 MMbbls).
Oil production in the third quarter was affected by 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 force majeure at the Forcados Oil Terminal on 13 August because of a failure of the loading buoy around the terminal export pipeline. Production uptime recorded for the third quarter was 60% as repairs took longer than planned, with the resumption of normal operations and exports commencing 14 September. 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.
The average price realised per barrel in the period was $67.43 (9M 2020: $38.60), following the recovery of Brent prices on the receding threat from the Covid-19 pandemic and the resultant return of global economic activity.
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 due to downtime on major pipelines, crude oil theft and several operational challenges leading to production capacity constraints in the assets.
Following the July meeting, OPEC+ agreed an increased oil output of 1.8 million barrels 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 from 2022.
Update on Amukpe-Escravos export route
The production shut-in at FOT in the third quarter has heightened the urgency to access the Escravos export terminal. The construction of the entire pipeline system, including its metering facilities, is effectively complete and we have commenced the commissioning process. This process involves functional testing of key components and operating systems integration with the receiving terminal facilities. After we have flushed and removed the water from the pipeline, we expect to introduce hydrocarbons into the line in December 2021 and lift our crude via the Escravos terminal upon completion of the crude handling agreements (CHA) with Chevron. The availability of this more secure underground pipeline will significantly improve our assets' production uptime compared with the TFP (74% in 9M 2021) and reduce losses from crude theft and reconciliation (11.3% in 9M 2021).
Gas business performance
Seplat Energy's working-interest gas production for the period was 113 MMscfd at an average selling price of $2.86/Mscf (9M 2020: 100 MMscfd, $2.88/Mscf). The Gas business contributed 41.2% of Group volumes on a boepd basis, and 19.7% of the Group's revenue. The impact of the disruption in production on gas volumes in the third quarter was minimal when a force majeure was declared by SPDC at the Forcados Oil Terminal (FOT). However, the Associated Gas (AG) station units were put on standby due to FOT outage.
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 exercise of the gas pricing framework in Nigeria between the Federal Government and the organised labour unions including the OPTS, NGA and other stakeholders. As part of the process to stabilize the sector, the Government has taken various measures to address challenges with domestic gas utilization 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 stimulating growth in demand.
The regulated Domestic Supply Obligation (DSO) price of $2.18/Mscf is expected to remain until a transition to a 'willing buyer/willing seller' regime in 2023 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 may result in a reduction of the average weighted gas price to around $2.67/Mscf in 2022. With some 20GW -25GW of power being generated from imported diesel and PMS at 4-5 times the cost of on-grid gas generated power (currently 4GW - 5GW), we are confident that this will be a temporary position as the regime changes in 2023 to a willing buyer/willing seller model.
ANOH Gas Processing Plant
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 Energy's expanding gas business. The project comprises a phase one 300 MMscfd midstream gas processing plant.
The ANOH plant is being built by AGPC, which is an Incorporated Joint Venture (IJV) owned equally between Seplat Energy and the Nigerian Gas Company ("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).
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 and LPG for cooking instead of biomass.
The upstream development, including the drilling of six production wells, will be delivered by the upstream unit operator SPDC. SPDC commenced drilling two wells as part of the four wells planned to be drilled in 2021 to supply the two midstream plants. We expect that the two wells initially drilled will be completed this year and the other two pushed back to 2022.
We are closely monitoring the completion of the 23km spur line and OB3 pipeline, developed by our partner NGC, to ensure that global supply constraints and construction challenges do not lead to delays in first gas by H1 2022. We have been reassured by our partner that both projects will be delivered on a timeline that ensures first gas is delivered on schedule.
We plan to commence installation of equipment in the fourth quarter, 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 but following a cost optimization programme, the AGPC construction cost is now expected to be no more than $650 million, inclusive of financing costs and taxes and is significantly lower than the original projected cost at FID.
Sapele Gas Plant
Work continues on the new Sapele Gas Plant, which is now expected to be completed in the first half of 2023, with Sapele's processing capacity increasing from 60 MMscfd to 75 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 ensuring that gas flaring is eliminated. We are currently accelerating the installation of the AG compressors at Sapele, which will reduce the gas flares at the site.
During the period, 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. The Umuseti-07 well was successfully completed in August and is producing c.2,000 bopd gross.
The three-well Gbetiokun drilling programme is ongoing. The Gbetiokun-06 well commenced production in August with additional production of c. 4,000 bopd, taking Gbetiokun to a peak gross production of approximately 12,000 bopd. Gbetiokun-07 was completed and the hook-up is in progress. The third well Gbetiokun-08 will be spudded in October and gross production from the three wells upon completion is expected to be around 10,500 bopd. Given the strong production of the Gbetiokun wells, we are examining evacuation options to accommodate 16,000 - 20,000 bopd from OML 40 when these new wells start producing and are looking to increase our storage capacity from the current 24 kbbls on the vessel currently stationed there.
Despite persistent adverse weather we have progressed preparation of the Owu appraisal well in OML 53 and have completed project activities associated with preparation for drilling the Sibiri (formerly called Amobe) exploration well in OML40.
We also plan to complete gas wells on Oben-44 and 46 in the fourth quarter; upon completion they are expected to produce 60 MMscfd and 2,400 bpd gross combined.
The direct impact of Covid-19 has been less severe in Nigeria than in many other countries. We continue to monitor developments, the health and safety of our employees, contractors, communities, partners and other stakeholders remain top priority. We have implemented preventative measures across all Seplat Energy sites, designed to protect our stakeholders whilst ensuring we can continue to provide the energy and fuels that Nigeria needs. The measures have been very successful to date since the pandemic struck early last year with no major incident recorded.
We will continue to monitor the rapidly changing dynamics and the impact of Covid-19 to comply with all State and Federal Government directives to help protect the health and safety of our stakeholders across all Seplat Energy locations. Employees are encouraged to take advantage of the vaccination schedule as was organised by the OPTS medical subcommittee in collaboration with the Lagos State Government.
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 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.
Acquisition of Cardinal Drilling rigs and conclusion of legal proceedings with Access Bank
On 3 December 2020, Seplat Energy reported that the ongoing debt recovery action by Access Bank against Cardinal Drilling Services Ltd ("Cardinal Drilling"), a related party of Seplat Energy, had led to the closure of its headquarters in Lagos (RNS 5019H). At that time, Seplat Energy stated there was no basis to have made it a party to the litigation as it was neither a shareholder in Cardinal Drilling nor had any outstanding loan obligations or guarantees to Access Bank. It did not at any time make any commitments or guarantees in respect of Cardinal Drilling's loan obligations to Access Bank. That position remains unchanged.
Access Bank commenced action against Seplat Energy in November 2020 through an ex parte injunction at the Federal High Court because it has certain shareholders in common with Cardinal Drilling. As a result, on 2 December 2020, access to Seplat Energy's corporate headquarters in Lagos and some of Seplat Energy's bank accounts were disrupted in connection with an injunctive order in relation to the court case by Access Bank in respect of the indebtedness of Cardinal Drilling, in which Access Bank was seeking to recover $85 million plus costs.
Although the Lagos Division of the Court of Appeal suspended the injunctive order on 22 January 2021, restoring access to its office and bank accounts, Access Bank appealed to the Supreme Court, where the matter awaits a hearing date.
In a worst-case scenario, were the Supreme Court to rule in favour of Access Bank, Seplat Energy will have no further recourse until the substantive case is heard in the Federal High Court. During this time, Seplat Energy could face significant disruption to its day-to-day operations including closure of its headquarters and bank accounts until the underlying case is resolved.
To avoid significant disruption to its business and to bring a period of uncertainty to an end, Seplat Energy has agreed to acquire four drilling rigs from the receiver/manager appointed by Access Bank over the assets of Cardinal Drilling Services Limited. The acquisition of these rigs, when deployed, should help to optimise drilling costs for Seplat Energy.
Consequently, the parties have agreed to end all legal actions regarding the outstanding loan owed by Cardinal Drilling to Access Bank, which could have persisted as an ongoing distraction for Seplat Energy, with the potential to disrupt its financial and commercial operations.
While we reiterate that the underlying action was without merit and against the principles of corporate veil, an unfavourable outcome in Nigeria's court system may result in a significantly higher settlement when the underlying case is heard.
The negotiated $36 million consideration for the rigs will be funded out of already restricted funds (excluded from previous cash flow statements) held at Access Bank and the Federal High Court of Nigeria, as disclosed in previous quarterly results.
Seplat Energy remains committed to the highest standards of corporate governance. In March we announced that the Board had decided to adopt Nigeria's strict definition of 'Related Parties' and eliminate all related-party transactions (RPT) as defined by the end of 2021.
We have taken legal advice to ensure that no other related-party matters pose any legal threat to the Company's financial or commercial operations.
Q3 2021 interim dividend
The Board has approved a Q3 2021 interim dividend of US2.5 cents per share (subject to appropriate WHT) to be paid to shareholders whose names appear in the Register of Members as at the close of business on 15 November 2021.
Dr. Emma FitzGerald was appointed as an Independent Non-Executive Director of the Company, joining the Seplat Board with effect from 1st August 2021.
Dr. FitzGerald brings vast knowledge in important areas such as the energy sector, renewables and sustainability, with hands-on experience in transformation through her many years of working at Shell, ranging from building its lubricants business in China to running its Global Retail network. From 2007-2010, she was accountable for Shell's Downstream strategy and played a key role in reshaping Shell's renewables strategy including the creation of Raizen, a biofuels JV with Cosan. From 2013 to 2018 she ran gas distribution and water & waste networks for National Grid and Severn Trent where she successfully positioned them as sustainability thought leaders in their industries.
Most recently Dr. FitzGerald served as CEO of Puma Energy International, a global energy company owned by Trafigura and Sonangol, which is focused on high potential developing markets in Africa, Asia and Central America. In 2020 she set up Puma's Future Energies division to play a critical role in helping customers and communities find the right energy solutions to support the energy transition. Over the last 10 years she has served on various Boards in executive and non-executive capacities and currently sits on the board of UPM Kymmene, an international paper & biomaterials business focused on innovating for a future beyond fossil fuels.
Revenue and production
Total revenue for the period, was $460.4 million, up 18.7% from the $387.8 million achieved in 2020. Crude oil revenue was $369.5 million (9M 2020: $305.6 million) a 20.9% increase compared to 2020, reflecting higher realised oil prices of $67.4/bbl for the period (9M 2020: $38.6/bbl) despite lower production. A $74.7 million oil underlift, representing 919 kbbls, was recorded under other income in the period, compared to $39.1 million in 9M 2020. Consequently, total revenue for the period after adjusting for an underlift was $535.1 million.
Total working-interest oil production volume for the period was 7.6 MMbbls (9M 2020: 9.1 MMbbls) with the total volume of crude lifted in the period being 5.5 MMbbls. The lower volume resulted from the disruption caused by the suspension of exports at the Forcados terminal. The Company experienced TFP reconciliation losses of 11.3% for the nine-month period, but we expect the effects of losses and downtime to fall when the delayed Amukpe-Escravos underground pipeline comes onstream.
Gas sales revenue increased by 10.6% to $90.9 million (9M 2020: $82.2 million), due to higher gas sales volumes of 30.8 Bscf compared to 27.5 Bscf in 9M 2020, which is reflective of the new gas wells brought onstream during the period and the full operations of the Oben gas plant, which underwent a turnaround maintenance in Q1 2020. Gas sales contributed 19.7% of total Group revenue in the period (9M 2020: 21.2%) and the average realised gas price was $2.86/Mscf (9M 2020: $2.88/Mscf).
Gross profit increased to $146.5 million (9M 2020: $90.6 million) due to higher revenues. Cost of sales in the period was $313.9 million (H1 2020: $297.2 million). Production evacuation from the Gbetiokun fields resulted in barging costs of $7.5 million; the higher operational and maintenance costs of $79.1 million include unaccrued late charges of $13m related to the OML 40 asset operated by NPDC. On a cost-per-barrel equivalent basis, production opex was higher at $9.7/boe (9M 2020: $8.7/boe), due to the additional costs noted above and the TFP downtime experienced in the third quarter. Non-production costs, primarily consisting of royalties and DD&A, were $183.5 million compared to $172.7 million in the prior year and reflect the higher oil prices during the period.
General and administrative expenses of $53.9 million (9M 2020: $52.4 million) were comparable to the previous year when administrative activities dropped due to the Covid-19 pandemic, and also reflect the effect of cost-reduction initiatives (such as office maintenance, telecommunication, travel and logistics) across the business.
The operating profit was $157.8 million (9M 2020: $79.3 million operating loss resulting mainly from the $160.9 million impairment charges) after recognising other income of $1.5 million (the fee from use of Group's pipeline to the Warri refinery) and underlift of $74.7 million (shortfalls of crude lifted below the share of production, which is priced at date of lifting).
There was a $5.5 million reversal of decommissioning obligation no longer required for Eland in the period. We achieved an EBITDA of $266.4 million in the period, adjusted for non-cash items (9M 2020: $205.6 million).
The net finance charge was $61.1 million and included one-off transaction fees of $16.4 million associated with the debt restructuring carried out in the period.
The profit before tax was $97.4 million (9M 2020: $130.1 million loss before tax). The Company's tax expense for the period was $62.3 million, compared to a tax credit of $33.8 million for the same period in 2020. The tax expense is made up of a deferred tax expense of $39.9 million and a current tax charge of $22.4 million.
The net profit for 9M 2021 was $35.0 million (9M 2020: $96.3 million net loss).
The resultant basic EPS was $0.11 in 9M 2021, compared to $0.10 basic loss per share in 9M 2020.
Cash flows from operating activities
Net cash flows from operating activities, after movements in working capital, were $144.5 million, lower than $187.4 million in 9M 2020 partly due to an increase in restricted cash at the end of the period related to a $20 million bank guarantee filed by Seplat Energy in line with an order from the Court of Appeal in January 2021. An income tax payment of $12.4 million was made in the period.
Seplat Energy received $160 million from its JV partner NPDC towards the settlement of its Naira and USD cash calls. We have continued engagements with NPDC to ensure their cash call obligations are met as due. The NPDC receivable was $70 million at the end of September 2021 (December 2020: $107 million).
Cash flows from investing activities
Capital expenditures in the period were $83.9 million, comprising $41.9 million drilling costs in relation to the completion of two Oben gas wells, two Gbetiokun oil wells, pre-drill and ongoing drilling operations costs and associated facilities development, and engineering costs of $40.7 million. Gas project costs included the Sapele Gas Plant upgrade project.
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 Energy over a six-year period through allocation of crude oil volumes produced from OML 55, Seplat Energy received payments amounting to $4.9 million in the period. 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 in September. The next lifting due to Seplat Energy is scheduled for December 2021 and we continue to work with BelemaOil to optimise production and sustain recovery of the remaining discharge amount. Out of $330m, $129.9 million has been recovered with $200.1m outstanding.
After adjusting for interest receipts, the net cash outflow from investing activities for the period was $79.1 million, compared to a net cash outflow in 2020 of $131.8 million, when there was a joint venture payment of $30.0 million for additional equity contribution towards the ANOH Gas Processing Plant project.
Cash flows from financing activities
Net cash outflows from financing activities were $70.6 million (9M 2020: $180.5 million). This 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 $250 million RCF. In the third quarter, $11 million was drawn on the $50 million off-take facility to support drilling operations at Elcrest. Payments of other financing charges and interest totalled $82.3 million and the dividend payment for the period totalled $58.4 million, net of withholding taxes.
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.
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).
On 24 May 2021 Westport drew down a further $10 million increasing the debt utilised under the RBL from $100 million to $110 million. The amortised cost for this as at the reporting period is $108.9 million (Dec 2020: $98.6 million), although the principal is $110 million.
On July 19, 2021, the Group announced that its wholly owned subsidiary, Westport Oil Limited, had successfully raised a $50 million offtake linked reserved based lending facility due April 2027 (the "Offtake Facility"). The Offtake Facility is subordinated to the $110 million senior reserve-based lending facility (the "RBL"). The Offtake Facility carries initial interest of Libor + 10.5% payable semi-annually and is scheduled to commence repayment from March 2023.
Seplat's hedging policy aims to guarantee appropriate levels of cash flow assurance in times of oil price weakness and volatility. The hedging programme consists of up-front and deferred premium put options as follows: for Q4 2021, 1.0 MMbbls at a strike price of $45/bbl and 1.0 MMbbls at a strike price of $50/bbl and for Q1 2022, 1.0mmmbls are protected at $50/bbl and 1.0mmbbls are protected at $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.