Financial and Operational Update Year to Date with
22% Increase in Average Gross Daily Production
Savannah Energy PLC, the British independent energy company focused around the delivery of Projects that Matter in Africa is pleased to provide a financial and operational update for the year to date.
Andrew Knott, CEO of Savannah Energy, said:
“We are pleased to be updating our 2022 financial guidance this morning, driven by the significant year-on-year increase in production volumes that has been delivered in Nigeria – the fourth year in a row. Looking forward to 2023 we are excited by the opportunities available to the business in all the four countries in which we operate in across Africa in both the hydrocarbon and renewable energy sectors and look forward to updating investors further next year.”
YTD Unaudited Financial Highlights
· Total Revenues1 up 27% y-o-y to US$256.7m for the 11 months ended 30 November 2022 (year to date period ended 30 November 2021: US$201.4m);
· Group cash balance of US$193.1m2 and net debt of US$310.1m3 (as at 30 November 2021: US$149.5m and US$370.2m respectively);
· We update our FY 2022 guidance4 as follows:
o Total Revenues1 of greater than US$270m (increased from US$215m);
o Group Operating expenses plus administrative expenses5 unchanged of up to US$75m;
o Group Depreciation, Depletion and Amortisation unchanged of US$21m fixed for infrastructure assets plus US$2.3/boe; and
o FY 2022 capital expenditure of up to US$35m (reduced from up to US$85m).
YTD Operational Highlights
· Average gross daily Nigeria production in the year-to-date period ended 30 November 2022 was 27.1 Kboepd, a 22% increase from the average gross daily production of 22.2 Kboepd in the same period last year;
· Of the total average gross daily production of 27.1 Kboepd in the year-to-date period, 90% was gas, including a 25% increase in production from the Uquo gas field compared to the same period last year, from 117.4 MMscfpd (19.6 Kboepd) to 147.3 MMscfpd (24.6 Kboepd);
· Following Savannah’s completion of the acquisition of ExxonMobil’s upstream and midstream asset portfolio in Chad and Cameroon and assumption of the operatorship of the upstream assets on 9 December 2022, production in Chad has continued uninterrupted at an average gross daily rate of approximately 28 Kbopd; and
· In 2022, we have expanded our customer base, signing additional gas sales agreements with three new customers, including the Central Horizon Gas Company, TransAfam Power Limited and Notore Chemical Industries, as well as agreeing a contract extension with First Independent Power Limited to supply three of its power plants, FIPL Afam, Eleme and Trans Amadi. As a result, Savannah now supplies gas to 24% of Nigeria’s thermal power generation capacity.
Nigeria Average Gross Daily Production
Uquo Gas (MMscfpd)
Uquo Condensate (Kbopd)
Stubb Creek Oil (Kbopd)
1 January – 30 November 2022
% of total production
1 January – 30 November 2021
% of total production
N.B. – Percentages in this table are calculated from exact numbers, the figures above are rounded.
Note that Nigeria production levels are largely driven by customer nomination levels, while cash collections are largely driven by contractual maintenance adjusted take-or-pay provisions.
1. Total Revenues are defined as the total amount of invoiced sales during the period. This number is seen by management as more accurately reflecting the underlying cash generation capacity of the business in comparison to Revenue recognised in the Consolidated Statement of Comprehensive Income.
2. Within cash balance of US$193.1m, are amounts which are held for debt service purposes and US$1.6m is restricted cash which includes cash collateral and stamp duty escrow balances.
3. Net debt (defined as ‘Total long and short term debt exclusive of lease liabilities less Cash at bank and other escrow monies) includes a Senior Secured Note with a call option, which is subject to final review. Any change in this option value will impact the reported net debt.
4. 2022 guidance relates only to the Nigerian and Nigerien assets (and does not include the impact of completion of the Chad and Cameroon acquisition in December 2022).
5. Operating expenses plus administrative expenses are defined as total cost of sales, administrative and other operating expenses excluding transaction costs, royalty and depletion, depreciation and amortisation.
Heads of Terms for the Sale of Cory Moruga; future EOR collaboration and
settlement agreement with Predator Oil & Gas Holdings Plc
Challenger has announced that it has entered into a binding heads of terms (the “Term Sheet”) with Predator Oil & Gas Holdings Plc and relevant subsidiary entities (“Predator”), providing for (i) the conditional sale of the Company’s interest in the non-producing Cory Moruga licence in Trinidad, (ii) a framework for future CO2 collaboration between the Company and Predator, and (iii) a mutually agreed settlement in relation to all matters relating to the Inniss-Trinity CO2 enhanced oil recovery (“EOR”) pilot project previously carried out by Predator at the Company’s Inniss-Trinity block (in aggregate, the “Transaction”).
· Binding heads of terms signed for the conditional sale of CEG’s 83.8% interest in the non-producing Cory Moruga licence in Trinidad, including the Snowcap oil field, to Predator, by way of sale of 100% of the issued share capital of T-Rex Resources (Trinidad) Limited, with retention of 25% future back-in right based on future drilling / EOR activity and associated future production
· Up to US$9m aggregate value proposition for Challenger Energy, comprising US$2m in staged cash consideration, US$1m in contingent cash consideration, removal of all liabilities and potential exposures associated with the Cory Moruga licence, retention of residual back-in rights, and a full settlement with Predator in respect of all matters relating to the Inniss-Trinity CO2 EOR pilot project
About Cory Moruga and Transaction Background
· The Cory Moruga licence is a direct licence from the Trinidadian Ministry of Energy and Energy Industries (“MEEI”) in which the Company’s wholly-owned subsidiary T-Rex Resources (Trinidad) Limited (“T-Rex”) holds an 83.8% operating interest, alongside its partner Touchstone Exploration Inc. which has a non-operating 16.2% interest.
· The Cory Moruga licence includes the Snowcap oil discovery, with oil previously having been produced on test from the Snowcap-1 and Snowcap-2ST wells. On the basis of the production tests, a development plan was submitted in 2018, prior to the Company taking control of the asset, however, the block has not been further developed since that time.
· Subsequent to the acquisition of Columbus Energy Resources PLC in 2020, the Company undertook a detailed technical review of its Trinidad portfolio and assessed that Cory Moruga field required further appraisal before a commercial development decision could be made. There is currently no production from the Cory Moruga licence.
· As a consequence of the lack of current production and the need for further appraisal, the Company considers the Cory Moruga licence to be non-core to its cash flow generative production-focused business in Trinidad, and therefore no further work has been planned for the Cory Moruga field in the near-term. In contrast, Predator considers the Cory Moruga field to represent an ideal candidate for a CO2 EOR project.
· The Company’s wholly owned Trinidadian subsidiary, CEG Inniss-Trinity Trinidad Limited, was a party to a Well Participation Agreement (and subsequent amendments) (“WPA”) with Predator and its subsidiaries, pursuant to which Predator agreed to carry out a CO2 EOR pilot project in a restricted part of the Company’s Inniss-Trinity field in Trinidad. The pilot project was carried out in 2020 and 2021, with the WPA terminated by the Company in August 2021.
· Following mutual discussions, the Company and Predator consider that a broader collaboration in relation to CO2 EOR projects in the Company’s existing portfolio of mature oil fields across Trinidad could provide a mutually beneficial outcome for both parties, leveraging shared past experiences utilising CO2 EOR techniques and methodologies.
· The Company and Predator have therefore entered into the binding Term Sheet, summary details of which are set out in this announcement, to reflect the parties’ strategic intent and the agreed commercial terms between the parties in respect of the Transaction.
Key terms of the Transaction
· Predator will acquire 100% of the issued share capital of T-Rex, an indirectly wholly-owned subsidiary of the Company that holds the Company’s 83.8% interest in, and is the operator of, the Cory Moruga licence.
· The Company will retain a “back-in right” which will afford the Company the option in the future to repurchase 25% of Predator’s share in T-Rex (and thus representing a 20.95% interest in the underlying Cory Moruga asset).
· CEG and Predator have also agreed to establish a collaboration in relation to CO2 EOR activities and projects in other areas in Trinidad, including but not limited to potential application of CO2 EOR techniques across the Company’s other fields.
· As part of the overall Transaction, the Company (and its relevant subsidiaries) and Predator (and its relevant subsidiaries), without admission of fault and liability on either party’s part, have agreed to a mutual settlement and discharge of all disputes and claims in relation to the Inniss-Trinity CO2 EOR pilot project previously undertaken by Predator, including the repayment of all loans and debts owed or claimed to be owed by either party to the other in respect of the Inniss-Trinity CO2 EOR pilot project.
· The Transaction represents a gross potential value proposition to Challenger Energy of up to US$9 million (as estimated by the parties to the Transaction), comprising:
o US$2.0 million payable to the Company by Predator in cash, in instalments as follows: (i) US$1 million upon completion of the transaction (the “Completion Date”), and (ii) a further US$1 million on the date that is six months after the Completion Date;
o a further US$1 million conditional cash payment, payable once the Cory Moruga field production first reaches 100 barrels of oil per day;
o the option-value embedded in the retained back-in right;
o the removal of all ongoing T-Rex financial obligations, and the elimination of all T-Rex associated liabilities from the Challenger Energy balance sheet, as well as the elimination of all contingent and potential liabilities associated with the Cory Moruga licence, whether crystalised or not;
o the settlement of any outstanding loan amounts in respect of the Inniss-Trinity CO2 EOR pilot project (recognising that absent a settlement between the parties, such amounts would be recoverable only from incremental production from the Inniss-Trinity CO2 EOR pilot project area); and
o a full and final mutual settlement in respect of all disputes and claims between the parties in relation to the Inniss-Trinity CO2 EOR pilot.
· In relation to the back-in right, it may be exercised at the Company’s sole election at any time in the period commencing three years after the Completion Date or first commercial production from Cory Moruga field (whichever is earlier) and ending six years after the Completion Date. Consideration payable if the Company elects to exercise the back-in right is a fixed cash amount of US$2.25 million, plus a variable percentage of the costs incurred by Predator on the Cory Moruga field subsequent to the Completion Date, the percentage dependent on the P50 Resource attributable to the Cory Moruga field at that time, as follows: (i) 50% of costs incurred if the P50 Resource is less than 5 million barrels of oil (MMbbls), (ii) 75% of costs incurred if the P50 Resource is more than 5 MMbbls but less than 10 MMbbls, and (iii) 100% of costs incurred if the P50 resource exceeds 10 MMbbls.
· Predator will have until 31 January 2023 to complete confirmatory due diligence, prior to which time the parties will also work in good faith to enter into long-form transaction documentation in respect of the Transaction. However, the Term Sheet is expressed to be legally binding, and will remain as the operative legal document in respect of the Transaction until long-form transaction documentation is entered into.
· Thereafter, completion of the Transaction will be conditional on consent of the Trinidadian Ministry of Energy and Energy Industries (“MEEI”) to a revised work programme for the Cory Moruga licence proposed by Predator (to include technical work, CO2 EOR activity, and new well drilling), as well as agreement of MEEI to a revision of future fees for the Cory Moruga licence and a settlement / cancellation of past claimed dues and other amounts pertaining to the Cory Moruga licence. Completion of the Transaction will occur 7 days after satisfaction of this condition and any other relevant conditions precedent that may be stipulated in the long-form transaction documentation. The parties have agreed to work together to secure the required consents and agreements with MEEI and thus achieve completion of the Transaction as soon as reasonably practicable on or before 30 May 2023, with a long stop date of 31 August 2023.
· For the year to 31 December 2021 T-Rex made a loss of approximately TT$4.5 million (or approximately US$674,000), largely reflective of the annual licence fees and dues in respect of the Cory Moruga licence. As at 31 December 2021, T-Rex had net liabilities of approximately TT$48.0 million (or approximately US$7.1 million) of which approximately TT$31.7 million (or approximately US$4.7 million) is intra-group and will be written-off as at the Completion Date. Cash received in relation to the Transaction will be used for general working capital in the Company’s operations.
Eytan Uliel, Chief Executive Officer of Challenger Energy, said:
“I am pleased to advise of today’s commercial agreement, to sell our interest in the Cory Moruga block to Predator. Subject to Ministry consent and agreement, Predator intend to aggressively take the block forward to production, through a combination of new technical studies, CO2 enhanced oil recovery activities, and new well drilling. In the event Predator are successful, we retain a future ability to come back in to a 25% interest, and we have put in place a new framework to work with Predator on considering the application of CO2 EOR techniques on our other Trinidadian assets.
In financial terms, subject to completion, the transaction will result in cash receipts of US$2 million through 2023, and a further US$1 million in the event of commercial production being achieved at the Cory Moruga field. In addition, we will see tangible realisation of value in the form of the embedded option value of the back-in right retained, all liabilities and potential liabilities associated with the Cory Moruga entity being removed, and a resolution of all outstanding matters between us and Predator being achieved in an amicable manner.
It is worth noting though that whilst Cory Moruga may currently be non-producing and thus non-core to our existing business in Trinidad, the block does have future production potential, albeit new wells and the application of innovative, environmentally-friendly EOR techniques will be required to unlock that potential. We will thus be working with Predator in the coming months to seek the consents and agreements necessary from the Ministry to enable the future work program intended by Predator to proceed. This will not only be to the benefit of our Company and Predator, but will meet the Trinidadian Government’s objective of seeing EOR deployment in Trinidadian onshore fields, with a view to establishing the basis for new oil production in the future. Further updates will be provided as appropriate.”
Predator Oil & Gas Holdings Plc
Conditional acquisition of Cory Moruga; CO2 EOR collaboration and settlement with Challenger Energy Group Plc
· Settlement reached with Challenger Energy Group PLC
· Progressing acquisition of Cory Moruga oil field in Trinidad
· US$9 million Gross Consideration
· Net payment of US$3 million cash, in staged payments with US$6 million of potential liabilities and other value items offset against Gross Consideration
· Cory Moruga under-developed and very well suited to application of CO2 EOR
Predator Oil & Gas Holdings Plc (LSE: PRD), the Jersey based Oil and Gas Company with near-term gas operations focussed on Morocco, is pleased to announce that it has today entered into a binding Term Sheet (the “Term Sheet”) with Challenger Energy Group PLC (“Challenger Energy”), providing for:
(i) the acquisition of Challenger Energy’s 83.8% interest in the Cory Moruga asset; and
(ii) a mutually agreed final settlement in relation to the Well Participation Agreement under which a CO2 enhanced oil recovery project (“CO2 EOR”) was carried out by Predator Oil & Gas Trinidad in CEG Inniss-Trinity Trinidad Limited’s (formerly FRAM Exploration Trinidad Limited) Inniss-Trinity field in Trinidad –
Key terms of the Transaction
· Predator will acquire 100% of the issued shares of T-Rex Resources (Trinidad) Limited (“T-Rex”), an indirectly wholly owned subsidiary of Challenger Energy that holds its 83.8% interest in, and is the operator of, the Cory Moruga licence.
· Gross consideration is US$9.0 million.
o US$3.0 million is payable to Challenger Energy by Predator in cash, in instalments as follows:
(i) US$1 million upon completion;
(ii) a further US$1 million 6 months after completion; and
(iii) a further US$1 million payable once Cory Moruga field production first reaches 100 barrels of oil per day.
o An agreed amount of US$6 million will be offset against the Gross Consideration to reflect the aggregate agreed value of:;
(i) T-Rex’s liabilities (including all contingent and potential liabilities, whether crystallised or not); and
(ii) The option value embedded in Challenger Energy’s back-in right (“Back-in Right”);
(iii) the repayment of all loans and debts owed or claimed to be owed by either party to the other in respect of the Inniss-Trinity CO2 EOR pilot project (recognising that absent a settlement between the parties, such amounts would be recoverable only from incremental production from the Inniss-Trinity CO2 EOR pilot project area), and
(iv) the mutual final settlement agreed between the parties in respect of all disputes and claims in relation to the Inniss-Trinity CO2 EOR pilot project.
Engagement Letter with Optiva Securities Limited (“Optiva”)
An Engagement Letter with Optiva has been executed by the Company regarding any potential M & A transaction with, or an investment by parties directly into, Predator Oil & Gas Trinidad Limited (“POGT”), a wholly owned subsidiary of the company, to gain specific exposure to CO2 EOR activities. Any such external investment specifically into POGT would allow this project to progress simultaneously with Predator’s other projects, while not diluting the value of those other projects.
Back-in Right for 25% Equity of Predator’s share of Cory Moruga
In relation to the Back-in Right, it may be exercised at Challenger Energy’s election:
o at any time in the period commencing three years after the completion date or first commercial production from Cory Moruga field (whichever is earlier) and ending six years after the completion date;
o If the Back-in Right is exercised, Challenger Energy will pay to Predator a fixed cash amount of US$2.25 million:
(i) plus a variable percentage of the costs incurred by Predator on the Cory Moruga field subsequent to the completion date;
(ii) the percentage dependent on the P50 Resource attributable to the Cory Moruga field at that time being:
a) 50% of costs incurred if the P50 Resource is less than 5 million barrels of oil (MMbbls);
b) 75% of costs incurred if the P50 Resource is more than 5 MMbbls but less than 10 MMbbls; and
c) 100% of costs incurred if the P50 resource exceeds 10 MMbbls.
Framework for CO2 EOR collaboration
· Predator and Challenger Energy have agreed to establish a collaboration in relation to CO2 EOR activities and projects in other areas in Trinidad, including but not limited to potential application of CO2 EOR techniques across Challenger Energy’s other fields;
· Leveraging Predator’s expertise in CO2 EOR techniques and methodologies.
· Predator has until 31 January 2023 to complete confirmatory due diligence, prior to which time the parties will also work in good faith to enter into long-form transaction documentation in respect of the Transaction.
· Thereafter, completion of the Transaction will be conditional on consent to the Transaction being received from the Trinidadian Ministry of Energy and Energy Industries (“MEEI”), including agreement from MEEI to a revised work programme proposed by Predator:
(i) work programme to include technical work, CO2 EOR activity, and new well drilling in 2024;
(ii) a waiver by MEEI of past dues and claims in respect of Cory Moruga field, and a revision by MEEI of the basis of future licence fees applicable to the Cory Moruga licence.
The parties have agreed to work together to secure the required consents and approvals and achieve completion of the Transaction as soon as reasonably practicable on or before 30 May 2023, with a long stop date of 31 August 2023 after which either party may elect to terminate the agreement or they can mutually agree to an extension.
Independent Competent Persons Report (“CPR”)
The Company will commission a CPR on Cory Moruga in the coming weeks which is expected to be published before Completion.
The Cory Moruga field in Trinidad was first identified by Predator as a prime candidate for CO2 EOR in 2017. An option to acquire Cory Moruga was outlined in the Company’s Prospectus published in 2018 at the time of admission to the Main Market but was later dropped when the Company elected to focus on the Guercif Licence in Morocco.
The Inniss-Trinity pilot CO2 EOR Project allowed the Company to develop valuable CO2 EOR operational expertise and for it to establish exclusivity in respect of using the surplus liquid CO2 supply in Trinidad for CO2 EOR operations with Massy Gas Products Limited (“Massy”).
The Cory Moruga field is under-developed as a result of which higher reservoir pressures have been maintained. This makes it relatively unique in Trinidad as it creates the possibility to execute a miscible CO2 EOR project to generate the potential to significantly increase the oil recovery factor.
Cory Moruga is covered by 3D seismic which shows less fault compartmentalisation relative to many other mature fields onshore Trinidad. It has never been water-flooded. This assists the development of a CO2 injection strategy to potentially maximise the effectiveness of the CO2 sweep through the reservoirs.
A small part of the Moruga West field extends into Cory Moruga. The ex-BP field continues to produce from the same Herrera reservoirs as have been encountered in Cory Moruga drilling to date. In 2017 the Company unsuccessfully bid for the Moruga West field, which was then owned by Massy. The geological understanding of the development and extent of the Herrera reservoirs in Moruga West has been invaluable in the Company’s assessment of the growth potential of the Cory Moruga asset.
Paul Griffiths, Executive Chairman of Predator Oil & Gas Holdings Plc commented:
“We are delighted to have negotiated an amicable settlement with Challenger Energy – which gives a positive footing for both companies to move forward – and gives Predator access to the under-developed Cory Moruga field. Cory Moruga has always been recognised by the Company as a candidate for miscible CO2 EOR. Since 2017, when the Company first had an option to acquire it, WTI spot oil price has increased by 46% to improve CO2 EOR project economics.
It is important for our shareholders that the Company is seen to be leveraging its expertise in CO2 EOR techniques and methodologies developed as a consequence of executing the Inniss-Trinity CO2 EOR Project. This allows us to capture value for the Inniss-Trinity CO2 EOR Project that would otherwise have been unrealised. Cory Moruga creates another exciting growth opportunity for 2023 which the Company can operate entirely itself and can exercise direct control over the receipt of potential future production revenues.”
Serica has announced that it has entered into an agreement to acquire the entire issued share capital of Tailwind Energy Investments Ltd (“Tailwind”) from Tailwind Energy Holdings LLP (the “Seller”) (the “Transaction”). The consideration for the acquisition comprises:
· The issue of up to 111,048,124 new ordinary shares in Serica (the “Consideration Shares”). Following the issue of the Consideration Shares, they will represent up to 28.9 per cent of Serica’s enlarged issued share capital
· A cash payment on Completion of £58.7 million (the “Cash Consideration”)
On the basis of the Serica closing price as of 19 December 2022 of 278 pence per share this would be equivalent to £367 million. Serica will also be taking on Tailwind’s net debt, which as at 30 November 2022 was c.£277 million. As part of the Transaction, Mercuria, the largest ultimate shareholder of Tailwind, will become a strategic investor in Serica with a 25.2 per cent holding and will enter into a Relationship Agreement with Serica as further described below.
Significant increase in Serica’s scale, portfolio diversity and organic investment opportunities
· Estimated proforma combined production in 2023 will rise significantly to between 40,000 boe/d and 45,000 boe/d putting Serica in the top 10 UKCS producers and top 3 UKCS listed independent producers
· Acquiring fully developed 2P reserves of 42 million boe to create a combined portfolio with 2P reserves of 104 million boe
· Will create a balanced spread of production from two main hubs – Bruce and Triton – which have separate transportation infrastructure
· Number of producing fields will increase from 5 to 11 with substantial upside and organic growth opportunities
· Enlarged group will operate more than 80 per cent of its net production
· Adding predominantly oil reserves reduces concentration of commodity price risk whilst gas remains more than 50% of production
· The carbon intensity of the enlarged group’s producing assets is projected to remain below the UKCS average
Introduces Mercuria as a strategic investor with a 25.2 per cent shareholding in Serica
· Serica will benefit from the availability of Mercuria’s financing and hedging capacity combined with its wide geographic reach
· Relationship Agreement between Serica and Mercuria will govern ongoing relationship
· Two Mercuria nominated non-executive directors joining the Serica board on completion
Reinforces Serica’s financial strength
· Highly cash generative portfolio and expected to have a significant net cash position on completion
· Existing Tailwind reserves-based lending (“RBL”) and junior facility expected to be rolled over on completion with subsequent refinancing to take advantage of the increased strength of the enlarged group during 2023
· Markedly lower decommissioning liabilities compared to North Sea peers
· Dividend policy to be maintained
· Tailwind holds significant ring fence tax losses carried forward for future use
Combines the two companies’ complementary leadership, technical and commercial expertise
· Tony Craven Walker and Mitch Flegg remaining as Non-Executive Chairman and CEO respectively
· Steve Edwards and Jacques Tohme will be joining the senior management team
· Serica’s North Sea operating capability combining with Tailwind’s sub-surface expertise
· All current Tailwind employees to be offered positions in the enlarged group
Creates an enlarged platform from which to consider future investments in the UK, overseas and in the wider energy sector
· Greater financial capability of the enlarged group
· Enhanced and complementary skill sets
· Strategic shareholder with a wide geographic reach and extensive activities in the broader energy sector
Mitch Flegg, CEO of Serica, commented:
“I am excited by the announcement of this transaction and by the possibilities it brings for Serica in terms of a new phase of growth. The transaction achieves our strategic objective of materially increasing the scale and diversity of our UKCS portfolio of assets. The Tailwind portfolio also brings multiple organic investment opportunities for further material near-term growth in reserves and production. Following this Transaction, Serica will retain its competitive strengths of a strong balance sheet, positive cash flow and low decommissioning cost obligations. Moreover, through the introduction of Mercuria as a new strategic investor, we will be differentially positioned to take advantage of the opportunities we expect to arise through industry consolidation, the North Sea Transition Deal and potentially overseas. I look forward to working with my new Tailwind management colleagues, Steve and Jacques joining our leadership team, as well as the Tailwind employees and contractors joining Serica on completion. Their skills and experience, which have been central to the success of Tailwind since its formation, are highly complementary to those already existing in Serica’s organisation.”
Tony Craven Walker, Chairman of Serica, commented:
“Serica has been able to grow its business by several times over the past five years without recourse to any external fund raising. We are proud of that achievement and are now a major North Sea operator with proven capabilities, a strong balance sheet and significant ongoing cash flow. The transaction with Tailwind reinforces these strengths, materially enhancing our asset base as we continue responsibly to provide much needed domestic energy at a time of energy crisis and seek to grow and diversify our portfolio of assets further.
The transaction with Tailwind provides a new strategic relationship, bringing in Mercuria, one of the world’s largest energy traders, as a major new shareholder of the enlarged group. The Board believes this relationship will provide competitive advantages as the Company seeks out further value accretive transactions. On completion, Mercuria will hold just over 25 per cent of Serica and will nominate two new non-Executive directors to serve on the Board. I and my Board colleagues are delighted to welcome them, the Tailwind executives and the Tailwind employees to the Company. We look forward to working together on the next phase of Serica’s growth.”
Steve Edwards, CEO of Tailwind, commented:
“Since inception in 2016, Tailwind has been driven by creating value for its stakeholders; acquiring and exploiting high quality production and development opportunities on the UKCS. Our value growth and delivery over that period have been exceptional, resulting from smart M&A and consistent delivery of high value organic projects. We have achieved this through the combination of a committed strategy, excellent people and enjoying the constant support of Mercuria. My colleagues and I are excited about this next step with Serica, with the combined assets, increased production and financial strength creating a platform to grow even further. We look forward to working closely with our Serica colleagues to deliver on the exciting opportunities for the enlarged group.”
San Leon Energy
San Leon has provided the following update in relation to the Company’s proposed refinancing discussions, its US$50 million loan facility and its working capital position. The Company also announces the proposed sale of its non-core investments relating to the Oza oil field.
As disclosed in the AIM Admission Document that was published on 8 July 2022 (the “Admission Document”), a loan facility of US$50 million has been made available to the Company by MM Capital Holding Limited (“MM Capital“) for the purposes of funding the Company’s working capital requirements and financing the Further ELI Investments (the “MM Capital Facility“). Whilst the MM Capital Facility is a legally binding facility agreement in place between the Company and MM Capital, the Board of San Leon has delayed utilising the facility as it believes that additional or alternative financing might be available on terms that may be better aligned with the Company’s overall strategic and financing objectives. Specifically, a prospective alternative lender has also indicated that it may have an interest in taking an equity position in San Leon by acquiring existing ordinary shares from certain shareholders. As the Company seeks to diversify its shareholder base and build long term support ahead of the planned expansion of its activities in Nigeria, the Board considers that financing on this basis represents a substantial improvement over the MM Capital Facility.
As previously announced, San Leon is in discussions with a prospective alternative lender in this regard. It is the Board’s view that these two financing sources are mutually exclusive and, noting what it believes to be considerable advantages with the alternative counter party, the Board does not consider it to be in the Company’s or shareholders’ best interests to draw down the MM Capital Facility at this time.
On 1 December 2022, the Company announced that discussions on the alternative financing were expected to be concluded by mid-December 2022. However, given its more extensive terms, this process has since been proved to be more complex than anticipated, and the timetable has become more protracted, especially against the backdrop of the current macroeconomic environment. Conversations remain very positive but, with the holiday period fast approaching, the Board now expects this alternative facility to be finalised and available for draw down early in the New Year and a further announcement will be made at that time by the Company, as appropriate.
As a further source of near-term funding, the Board is also currently in advanced negotiations in respect of the proposed sale of the Company’s non-core investments relating to the Oza oil field in Nigeria (the “Proposed Non-core Investments Sale“), which had a book value of US$5.6 million in San Leon’s unaudited interim results for the six months ended 30 June 2022, to generate working capital. All terms for the Proposed Non-core Investments Sale are in agreed form, however, San Leon expects the transaction to formally be entered into once the purchaser has finalised its own financing arrangements. It is San Leon’s understanding that this could be imminent and the Company is in daily contact with the prospective buyer in this regard. A further announcement will be made at that time by the Company, as appropriate.
Since the publication of the Admission Document, the Company has not received any material cash inflows but, during that period, the Company has taken steps to manage its overheads whilst it explores these alternative refinancing options. In addition, pending securing funding from one or both of these sources, the Company has not yet been able to progress the Further ELI Investments and several of the Company’s trade creditors, predominantly related to adviser and other fees incurred in relation to the proposed Midwestern Reorganisation and the Proposed Further ELI Investments, remain outstanding. San Leon is in regular dialogue with both its creditors and ELI in respect of timing for settling these payments.
It is important to note that, notwithstanding this short term cashflow delay, San Leon’s balance sheet is robust with, in particular, US$112.6 million owed to it by Midwestern Leon Petroleum Limited (the “MLPL Loan“) and US$23.0 million owed to it by ELI. The MLPL Loan will be extinguished following the proposed Midwestern Reorganisation but, for the time being, remains a valid obligation and therefore a significant asset of the Company’s. Aside from Oza, the Company also holds non-core assets in other countries which may have a meaningful value, such as the 4.5% net profit interest in the Barryroe Field, which lies in shallow water of about 100m some 50km off the south coast of Ireland.
For the time being the Board is satisfied that its alternative refinancing options are progressing satisfactorily, even if slower than initially hoped, and furthermore that conversations with those creditors who are due outstanding payments are not producing any undue pressure on San Leon. Nevertheless, the Board continues to keep these matters under review and will take actions to protect the interests of both shareholders and creditors as appropriate. As set out in the Admission Document, the Further ELI Investments are contingent on San Leon securing further funding, whether from the MM Capital Facility or otherwise, and the Board are focused on finalising this.
- Continued strong performance in Asset Solutions and IES offset by challenges in E&C
- Expect a full year EBIT loss in E&C of approximately US$190 million for 2022, yielding a total Group EBIT loss of approximately US$100 million
- Reflecting adverse commercial settlements, further unrecovered cost overruns in the legacy portfolio and cost increases on the Thai Oil Clean Fuel joint venture contract
- We will seek, working closely with our Thai Oil joint venture partners, to mitigate those increases over the remainder of that contract in addition to seeking to realise other portfolio upsides
- Six legacy E&C lump-sum contracts were completed or substantially completed (1) in the second half
- Asset Solutions on track to deliver full year EBIT margin of 5-6%
- Robust IES performance driven by high production, operational performance and oil prices
- Positive outlook for the recovery in E&C and continued growth in Asset Solutions, with a healthy total Group pipeline of US$68 billion scheduled for award in the next 18 months
- Pipeline includes bids submitted of US$5.5 billion, and a further US$1.5 billion where we are at preferred bidder stage
- Net debt was US$396 million (2) at 15 December 2022, with cash management partly offsetting the delays in E&C contract awards and the unrecovered cost overruns in the E&C legacy portfolio during the second half
Sami Iskander, Petrofac’s Group Chief Executive, commented:
“We have maintained strong momentum in Asset Solutions and IES, however Group performance for 2022 has been impacted by further cost recovery challenges in E&C. Good progress has been made in the second half where we have completed or substantially completed (1) six lump-sum contracts, with five of the remaining eight active lump-sum contracts scheduled to complete in 2023. This will largely close-out the mature E&C portfolio that was heavily impacted by pandemic delays. On the Thai Oil Clean Fuel contract, we are working closely with our joint venture partners to pursue the recovery of costs over the remaining course of the contract.
“Looking forward, whilst E&C awards were slower than expected in 2022, the market outlook remains positive and we are well positioned on a number of near-term prospects, with US$1.5 billion of E&C opportunities where we are at preferred bidder stage, and a further US$3.5 billion of bids submitted in E&C. We expect these opportunities to provide backlog growth in 2023 and lay the foundations for a return to profitability, positive free cash flow and continued recovery thereafter.
“In 2023, we will continue to close out the legacy E&C portfolio and associated commercial settlements. We retain our focus on cost discipline, unwinding working capital and ensuring Petrofac has sufficient liquidity to support our growth ambitions.”
The Group’s performance in 2022 will reflect continued strong performance in Asset Solutions and IES, offset by the challenges in the E&C portfolio. Management expects to report Group revenue of approximately US$2.5 billion and a full-year business performance EBIT loss of approximately US$100 million for 2022.
Engineering & Construction (E&C)
Second half performance in E&C was further adversely impacted by the mature, Covid-affected legacy contracts. The additional costs incurred on these contracts due to extended schedules have not been fully recovered from our customers, resulting in net cost overruns. Six of the active lump-sum contracts were completed or substantially completed (1) in the second half and five of the remaining eight are scheduled to complete in 2023.
In addition, we have recognised cost increases on the Thai Oil Clean Fuel contract – where the partners are jointly liable for the performance of the contract – driven by a reassessment, with the partners, of the forecast costs to complete this highly complex project. This is a loss-making contract and the expected full-life loss has therefore been recognised immediately. There is no cash outflow associated with these cost increases in 2022, as the cash impact will be spread over the remaining life of the contract. Petrofac will continue to work closely with its partners to pursue the recovery of costs over the course of the contract and, in addition, seek to realise other portfolio upsides.
Full year revenues in 2022 are expected to be around US$1.3 billion reflecting the lower levels of activity compared with the prior year. The combined impact of the cost overruns described above mean that E&C is expected to report a full year EBIT loss of approximately US$190 million.
Year to date, E&C has secured new order intake (3) of US$0.5 billion and signed a collaboration with Hitachi to provide joint grid integration and associated infrastructure to support the rapidly growing offshore wind market. The addressable pipeline for E&C remains healthy, although clients have been slower to award contracts in the second half than expected. These awards are now expected to be made in 2023, and this is reflected in the healthy E&C pipeline of US$54 billion scheduled for award in the next 18 months. This includes bids submitted of approximately US$3.5 billion and a further US$1.5 billion where we are at preferred bidder stage. As a result, the business remains well placed to deliver a sustained period of growth in backlog in the near and medium term.
Asset Solutions (AS)
Asset Solutions has continued to deliver robust performance, with strong order intake in the year to date and a healthy margin.
Full year revenue is expected to be approximately US$1.1 billion, and EBIT margins are expected to be between 5% and 6%, in line with guidance. This includes the impact of lower margins in the second half due to the roll-off of certain historic high-margin contracts, as noted at the half-year.
Year to date order intake (3), comprising new contract awards and extensions, is US$1.4 billion, including material awards in Well Engineering and Decommissioning in Australia and the Gulf of Mexico. Asset Operations and Asset Developments secured awards across the UK, MENA and India.
In New Energy Services, the momentum gained over the last two years continues. The market remains active and we have secured a series of early-stage awards and strategic alliances with technology providers. This leaves us well positioned over the medium-term to secure EPC and other execution phase project work, as projects reach final investment decision.
Integrated Energy Services (IES)
IES’ financial performance during the year has been robust, with a significant increase in production and the benefit of high oil prices. Net production is expected to be between 3.0-3.5 kbbl/d for the year, reflecting a full year’s production from the East Cendor development, which commenced in June 2021, and the reinstatement of the main Cendor field production.
The average realised oil price (net of royalties) (4) for the year to date is expected to be approximately US$110/bbl (2021: US$75/bbl), including the impact of hedging, with the full year EBITDA expected to marginally exceed the guided range of US$90 million to US$100 million.
The Group’s backlog (5) is expected to be approximately US$3.3 billion at 31 December 2022 (30 June 2022: US$3.7 billion), reflecting industry delays to awards, partially offset by continued new order intake success in AS in the second half.
|Expected Backlog||31 December 2022||30 June 2022|
|US$ billion||US$ billion|
|Engineering & Construction||1.4||1.8|
CASH FLOW, NET DEBT AND LIQUIDITY
Net debt (2) was US$396 million at 15 December 2022 (30 June 2022: US$341 million). Liquidity (6) was US$451 million on the same date (30 June 2022: US$511 million). This reflects a delay in the expected receipt of certain 2022 settlements and milestone collections to early 2023, the delay in new awards and the unrecovered cost overruns in the E&C legacy portfolio, partly mitigated through active cash flow management.
We have engaged with our lenders to extend the revolving credit facility and a bilateral loan – totalling US$230 million – which are scheduled to mature in October 2023.
OUTLOOK FOR 2023
The outlook for new awards in E&C remains robust, supported by high energy demand and increased focus on energy security and energy transition. E&C is well positioned on a number of near-term prospects, with US$1.5 billion of opportunities where we are at preferred bidder stage, and a further US$3.5 billion of bids submitted. Bidding activity remains high, with an 18-month pipeline, including bids submitted, of approximately US$54 billion, of which US$33 billion is scheduled for award in 2023.
E&C has secured revenue of US$0.9 billion for 2023, approximately a third of which from contracts with no future margin contribution. Coupled with the adverse operating leverage due to the small portfolio of active contracts, we expect a small EBIT loss in E&C in 2023. Our healthy pipeline and projected order intake in 2023 mean that we remain confident of delivering a return to profitability and positive cash flow in 2024 and significant growth in the E&C business over the medium term.
Asset Solutions has US$2 billion of bids submitted as part of a US$14 billion 18-month pipeline of opportunities, with US$11 billion scheduled for award in 2023.
Asset Solutions has secured revenue of US$0.8 billion for 2023. The business is expected to continue to perform well, with revenue growth driven by focused geographic expansion and new order intake in Well Engineering & Decommissioning in 2022. We expect EBIT in 2023 to be lower than 2022 reflecting the roll-off of certain high-margin contracts in the first half of 2022 and a larger portion of pass-through revenue in Well Engineering & Decommissioning contracts.
IES is expected to deliver another robust production performance in 2023, in line with 2022. At US$85/bbl oil price, EBITDA is expected to be in the range US$70 million to US$80 million, taking into account hedging.
At Group level, we expect broadly neutral cash flow in 2023 as a result of new awards and the partial unwinding of working capital balances, offset by capex of US$25-35 million, tax payments of US$70-80 million (relating to the closure of prior periods’ assessments) and interest costs of US$80 million.