WTI (June) $74.30 -$2.77, Brent (June) $77.69 -$3.08, Diff -$3.39 -31c
USNG (May) $2.12 -18c, UKNG (May) 90.32p -3.68p, TTF (May) €38.35 -€0.62

Oil price

Oil fell sharply with the US recession getting closer and closer, even decent inventory stats couldnt stop the wheels coming off.

Sound Energy

Sound has provided a financing update, including in relation to the Company’s Tendrara Production Concession, onshore Morocco.

The Company announced on 23 June 2022 that it had entered into an Arrangement and Mandate letter with Attijariwafa bank, a Moroccan multinational bank and one of the leading banks in Morocco, under which the Company mandated the Arranger in relation to the arrangement of project debt financing for the Phase 2 development of Sound Energy’s Tendrara Production Concession.

Under the Agreement, as amended and extended, the Arranger was mandated, and provided with exclusivity by the Company until 1 June 2023, to arrange a long-term project senior debt facility with a term of no more than 12 years of up to 2.250 billion Moroccan dirhams (approximately US$223 million using current exchange rates) for the partial financing of the currently estimated approximately US$330 million total Phase 2 development cost (including development wells post-first gas) of the Tendrara Production Concession (the “Financing”), with the parties seeking to negotiate binding terms for the Financing by 28 April 2023.

Whilst the Company has been advised by the Arranger that it has now concluded its due diligence in respect of the Financing, Arranger Credit Committee consideration of the Financing has been delayed due to local Eid celebrations and is not expected to be held prior to 28 April 2023. With Arranger Credit Committee consideration of the Financing rescheduled, the parties continue to work in good faith in advancing the Financing and further announcements will be made, as appropriate in due course.

On the 8 June 2022 the Company announced a £4 million placing of new ordinary shares at 2.0 pence per ordinary share (the “Placing”). At the time the Company envisaged the net proceeds of the Placing would be sufficient to continue to advance the Company’s projects and meet the Company’s working capital obligations through to April 2023. Over the subsequent 10 months the Company has scheduled its work accordingly and managed its corporate cost base such that its remaining cash resources are now expected to be sufficient to meet the Company’s present working capital requirements through to July 2023.    

Commenting, Graham Lyon (Executive Chairman) said:
“The Phase 2 senior debt process has completed its due diligence phase with recommendations to Attijariwafa’ s credit committee prepared by the Arranger. We now await the conditioned financing offer which we expect shortly from the bank’s committee. We look forward to providing further updates as the process moves forward.”

I see this as further good news from Sound, Attijariwafa completing their DD is a good sign and as is often the  way with big banks the approval process is quite rigid. The moveable feast of Eid seems to have got in the way of a scheduled meeting but I can’t imagine that with exclusivity good for another month that anything but an offer will come. This is too big a prize for the state Bank to lose out to a competitor as lead arranger. 

The management continue to deliver and this is another key yardstick, progress has been solid and there are many who wouldnt have expected so much by now. With the shares having doubled since the start of the year and looking to go past the significant 2p milestone I think Sound should very much be on people’s radar  screens. 

Petrofac

• Challenges in E&C partially offset by strong performance in Asset Solutions and IES
• Business performance EBIT loss of US$(205) million(1)
• Reported net loss of US$(310) million(2) inclusive of separately disclosed items
• Healthy total Group pipeline of US$51 billion scheduled for award in the period to June 2024
• Net debt of US$349 million(3) and liquidity of US$506 million (4) at 31 December 2022
• Bank facilities extended to October 2024
• Backlog of US$3.4 billion at 31 December 2022
• Share of €13 billion TenneT framework agreement and first contract award secured in Q1 2023

Tareq Kawash, Petrofac’s Group Chief Executive since 1 April 2023, commented:
“Petrofac’s performance for 2022 was severely impacted by the challenges in the Group’s legacy E&C portfolio, which continues to feel the direct and indirect effects of pandemic delays. We are working resolutely to put these challenges behind us, and to rebuild our backlog – such as the recent multi-year, multi-platform Framework Agreement in support of TenneT’s 2GW offshore wind programme. Meanwhile, IES is performing well and Asset Solutions continues to provide us with attractive growth opportunities.

“I joined Petrofac because I see the business is a trusted project delivery partner, with significant opportunity for growth and value creation. I have known the business for many years and believe strongly in the business model and Petrofac’s differentiated competitive position. We have an exceptional Engineering, Procurement, Construction and Operations capability that is well positioned to deliver and support critical energy infrastructure. In an increasingly active market, we must be selective and disciplined as we grow our order book over the coming years. I am impressed by the people at Petrofac and I’m excited to work together to deliver the Group’s potential.”

I said a few days ago that I really thought I knew Petrofac having followed them for many years, last week’s profit warning suggested that ‘Petrofac now expects to report a full year Group EBIT loss of approximately US$150 million to US$170 million for 2022’. Today, that figure is $205m the ultimate kitchen sinking by a new CEO, no wonder they needed an extra two days to put the results out…

If it wasn’t for the Wind farm contract and the banking facilities being renegotiated in recent weeks one could get really bearish about PFC but the backlog is substantial and in their favoured MENA region they appear to be stacking up the business. Accordingly I guess that we are going to have to give the new chief a bit of rope, for old times sake… 

DIVISIONAL HIGHLIGHTS

Engineering & Construction (E&C)
2022 was another challenging year for E&C as we progressed with the completion of many of the legacy Covid-19 affected projects in the portfolio and new industry awards were further delayed. As a result, financial performance was adversely affected by unrecovered cost overruns and delays to the realisation of working capital balances.

Cost overruns related principally to two areas: the Thai Oil Clean Fuels contract and other legacy contracts completed or substantially completed in the year (6).

On the Thai Oil Clean Fuels contract, due to the scale and complexity of this project and the schedule delays suffered during the pandemic, the additional work required to complete the project and recover lost time led to additional costs. Going forward, we expect to recover a portion of these additional costs, however, in the meantime, we remain focussed on working with our client and partners to safely and successfully deliver this unique project.

In addition, in a challenging commercial environment, we have in some cases suffered adverse outcomes on commercial settlements in the remaining portfolio of contracts to release working capital.

Following the impact of these challenges, E&C reports the following financial results for the 12 months ended 31 December 2022 (1)

• Revenue down 33% to US$1.3 billion (2021 restated(5): US$2.0 billion)
• EBIT loss of US$299 million (2021 restated(5): US$62 million)
• EBIT margin down to (22.8)% (2021 restated(5): (3.2)%)

Industry awards were lower than expected again in 2022, and, as a result, E&C’s new order intake for the year was lower than prior years at US$0.5 billion (2021: US$1.2 billion), comprising an EPC contract in Algeria and net variation orders.

In June 2022, Petrofac and Hitachi Energy entered into a collaboration to provide joint grid integration and associated infrastructure to support the rapidly growing offshore wind market. This collaboration led, subsequent to the year end, to the award of our largest ever Framework Agreement with TenneT, in support of its 2GW offshore wind programme. Worth approximately €13 billion to the partnership, the multi-year Framework Agreement was accompanied by the first platform contract award which was added to backlog in Q1 2023.

The market outlook for the remainder of 2023 and beyond remains positive. Following a decade of underinvestment, a renewed focus in the sector on secure, affordable, sustainable energy provides a backdrop for awards in the short and medium-term. E&C’s addressable pipeline remains healthy, with a potential US$40 billion in customer opportunities scheduled for award in the period to June 2024. This includes bids in the proposal process of approximately US$12 billion and a further US$1.5 billion where we remain at preferred bidder stage.

Asset Solutions
Asset Solutions delivered another robust performance in 2022, in line with guidance, with a strong book-to-bill ratio of 1.2x for the year, with each of the service lines (Asset Operations, Asset Development and Well Engineering & Decommissioning) delivering growth. We maintained our core 40% market share in the UK and renewal rate of 80% for operations and maintenance contracts. Internationally, we have expanded our operations within new and existing geographies, with awards across each service line. In particular, 2022 saw great success in driving forward our late-life asset management and decommissioning service offerings, with significant awards in Australia and the Gulf of Mexico.

Operational performance has continued to remain robust, with healthy margins, albeit reduced compared with the prior year due to the roll-off of certain historic high-margin contracts and the impact of an increased proportion of pass-through revenue.

Asset Solutions reports the following financial results for the 12 months ended 31 December 2022(1)

• Revenue up 4% to US$1.2 billion
• EBIT of US$60 million (2021: US$74 million)
• EBIT margin of 5.2% (2021: 6.7%)
• US$1.4 billion of awards (2021: US$1.0 billion), representing a book-to-bill of 1.2x

The strong momentum we have gained over the last two years in new energies continued in 2022, with a series of early-stage awards and strategic alliances with technology providers. This leaves us well positioned over the medium-term to secure engineering, procurement and construction scopes and other execution phase project work, as projects reach final investment decision.

Integrated Energy Services (IES)
IES delivered strong financial performance in the year, reflecting the increased production and higher oil prices realised. Net production reflected a full year’s production from the East Cendor development, which commenced in June 2021, the reinstatement of the main Cendor field production and other well workovers. IES generated positive free cash flow in the year as a result of Block PM304 performance, as well as receiving US$98 million of consideration from the divestments of the Greater Stella Area and the Mexico operations

IES reports the following financial results for the 12 months ended 31 December 2022(1)

• Revenue up 174% to US$137 million
  • Average realised oil price up 49% to US$112/boe
  • Net production up 97% to 1,261kboe
• EBITDA up US$88 million to US$109 million

SEPARATELY DISCLOSED ITEMS (7)
The reported net loss of US$310 million (2021 restated(5): US$245 million) includes a net charge of US$26 million (2021: US$248 million). This predominantly related to:

• US$(5) million impairment reversal (net) primarily resulting from a review of the carrying amount of the investment in Block PM304 in Malaysia
• US$(10) million of positive fair value re-measurements (net), primarily resulting from the improved final settlement relating to the divestment of the Group’s operations in Mexico
• US$18 million financing related fair value loss associated with the embedded derivative in respect of the Revolving Credit Facility
• US$10 million of cloud ERP software implementation costs
• Other net separately disclosed items of US$13 million including: restructuring and redundancy costs, a loss on the sale of the deferred consideration in relation to the divestment of the Greater Stella Area operations, and professional service fees in the Corporate reporting segment

CASH FLOW, NET DEBT AND LIQUIDITY
Free cash outflow for the year of US$188 million principally reflected the net cash outflow used in operating activities – which included the payment of the US$104 million SFO court penalty – and higher interest payments, partially offset by higher divestment proceeds.

Net debt, excluding net finance leases, increased to US$349 million at 31 December 2022 (2021: US$144 million), driven by the free cash outflow in the year.

The Group had US$506 million of liquidity(4) available at 31 December 2022 (2021: US$705 million).

In the short term, the Group is reliant on a small number of relatively high value collections in respect of the conclusion of historical contracts, settlements and new awards. Based on the recent progress made, the Directors are confident that the expected timing and realisation of these collections are reasonable and reflect their assessment of the most likely outcome. However, as the resolution of these matters is not wholly within Petrofac’s control, there remains a level of uncertainty which is disclosed within note 2.5 to the consolidated financial statements.

EXTENSION OF DEBT FACILITIES
Following the capital raise and the refinancing completed in 2021, the Group extended its banking facilities in April 2023. The Group therefore now has facilities consisting of US$600 million of senior secured notes (due 2026), a US$162 million revolving credit facility and two bilateral loan facilities totalling US$90 million all of which mature in October 2024

DIVIDEND
The Board recognises the importance of dividends to shareholders and aims to reinstate them in due course, once the Company’s performance has improved.

ORDER BACKLOG
The Group’s backlog decreased 15% to US$3.4 billion at 31 December 2022 (2021 restated(5): US$4.0 billion), reflecting low new order intake in E&C due to industry delays to awards, partially offset by strong order intake in Asset Solutions.

OUTLOOK
The outlook for new awards in E&C remains robust, supported by high energy demand and increased focus on energy security and the energy transition. E&C is well positioned on a number of other near-term prospects as evidenced by the recent multi-year, multi-platform Framework Agreement award in support of TenneT’s 2GW offshore wind programme. It has US$1.5 billion of opportunities at preferred bidder stage, and a further US$3 billion of bids submitted. Bidding activity remains high, with a total pipeline scheduled for award by June 2024 of approximately US$40 billion, of which US$23 billion is scheduled for award in 2023.

E&C has secured revenue of US$0.9 billion for 2023. Approximately half of this revenue comes from contracts with no future margin contribution. Furthermore, new awards secured in 2023 are not expected to contribute to margins until next year. 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 E&C over the medium term.

Asset Solutions has US$2.5 billion of bids submitted as part of a US$11 billion pipeline of opportunities scheduled for award by June 2024, with US$8 billion scheduled for award in 2023.

Asset Solutions has secured revenue of US$1.2 billion for 2023. The business is expected to continue to grow, with revenue growth driven by focused geographic expansion and new order intake in Well Engineering & Decommissioning in 2022. We expect a healthy EBIT in 2023 albeit lower than 2022, reflecting the further roll-off of certain high-margin contracts and a higher proportion of pass-through revenue.

IES is expected to deliver another robust production performance in 2023, with production marginally lower than 2022. At US$85/bbl oil price, EBITDA is expected to be in the range US$65 million to US$75 million, taking into account hedging.

At Group level, we expect cash flow to be broadly neutral in 2023, with upside potential depending on the progress made in unwinding working capital balances. Included in the underlying cash flows are capex of US$25-35 million, tax payments of US$70-80 million (relating to prior periods) and interest costs of US$80 million.

The near-term objectives for the Group are clear: to leverage our healthy pipeline of opportunities to increase backlog; and to release existing working capital to support liquidity. Good progress has been made in the year to date with the TenneT award, an extension of bank debt facilities and efforts to release working capital.

BOARD CHANGES
Further to the announcement made on 22 November 2022, the Company welcomed Tareq Kawash as Group Chief Executive and Executive Director, succeeding Sami Iskander, with effect from 1 April 2023.

United Oil & Gas

United Oil & Gas has announced its audited results for the year ended 31 December 2022.  

Brian Larkin, CEO, commented:
“2022 was filled with extensive corporate and operational activity across our portfolio, all completed with zero LTI’s, TRIR’s and environmental incidents. In Egypt it was a challenging year for United, with five wells drilled and completed in addition to a number of workovers, delivering mixed results following an exceptional 100% drilling success rate during 2020 and 2021. Abu Sennan remains integral to our portfolio and going forward activity on the licence will focus on maintaining and extending long-term production rates to generate operational cashflows for many years to come. In Jamaica, the farm-out efforts of this high impact exploration licence continued with the addition of a new advisor to support the process. In the UK post year-end, an agreement was signed for the conditional sale of the Maria discovery, which is in line with our strategy to actively manage our portfolio.

“Our work programme in Egypt in the first half has started strongly, with a focus on development drilling and workovers. We were delighted with the result of the ASH-8 well which is producing at stable rates and look forward to the results of the ASD-3 well which spud in March. For the remainder of the year, newsflow will centre around the results from our ongoing Egyptian drilling programme, the expected completion of the sale of Maria and further progress on the Jamaica farm-out. 

“We remain committed to our growth ambitions with a focus for new ventures in the Greater Mediterranean and North and West African regions, where the Board and management’s experience and relationships can be leveraged.  As such, United is well placed to execute our growth strategy, with a continued focus on disciplined capital allocation to generate the best returns for shareholders.“

UOG is moving along, with Egypt barring the odd hiccup doing OK, but there is more, Maria looks like it really has been sold and Jamaica does appear to be at long last about to reveal something. When all that is done we will have a better idea of what to expect from this active management team.  

Operational summary

• Group full-year 2022 production averaged 1,312 boepd net (1,137 bopd oil and 175 boepd gas) in line with revised 2022 guidance of 1,300-1,325 boepd
• 2022 Egypt work programme completed, consisting of three development wells, two exploration wells, and eight workovers
• Safety and the environment: Zero lost time incident frequency rate. No environmental spills, restricted work incidents or medical treatment incidents
• In Jamaica, the completion of additional technical studies that were agreed as part of the licence extension have provided additional positive support to the farm-out process
• 2023 Egypt work programme has commenced positively, with the ASH-8 development coming onstream in March ahead of schedule and above expectations (post period)
• The second well in the 2023 drilling campaign, the ASD-3 development well, spud at the beginning of April 2023 (post period)

Financial summary

• Group revenue for full year 2022 was $15.8m (1) (2021 : $19.2m)
• The average realised oil price per barrel from Egypt achieved was $96.1/bbl ( 2021 : $68.9/bbl)
• Gross Profit of $12.9m (2021 : $12.3m)
• Profit After Tax $2.3m (2021 : $3.6m)
• Cash Collections of $16.9m (2021: $17.3m)
• Group Cash balances as at 31 December 2022 were $1.4m with Net Debt of $1.5m (FY 2021: Cash balances $0.4m, Net Debt $3.9m)
• BP Acquisition facility to be fully repaid in 2023
• Capital expenditure for the year was $8.6m (FY 2021 : $6.9m)
• Egyptian receivables of $4.4m (FY 2021 : $5.1m)

(1) 22% working interest net of Government Take

Corporate summary

• Appointment of Peter Dunne, as Chief Financial Officer, effective from 5 May 2022
• Amounts due from Anasuria Hibiscus UK Ltd for Crown disposal fully satisfied in the year ($2.5m)
• Completion and receipt of proceeds in relation to the sale of UOG Italia Srl to Prospex Energy for €2.2m plus €0.1m working capital adjustment
• Directors’ purchases increase total directors’ shareholding to 5.64% of issued share capital as at year-end
• Tom Hickey, non-executive director stepped down from the Board on 23 September 2022
• A binding Asset Purchase Agreement signed for the conditional sale of UK Central North Sea Licence P2519 containing the Maria discovery for a total consideration of up to £5.7 million (post period)
• United intends to seek the requisite shareholder approvals at this year’s Annual General Meeting to approve a limited share buyback programme, which will be subject to completion of the Maria sale and market conditions (post period)
• The Company initiated a full review of its G&A expenditure in Q4 2022 and has commenced a programme to reduce these costs by up to 15% in 2023 compared to 2022 (post period)

Outlook

• Q1 2023 oil production averaged 841 bopd net, with an exit rate for the quarter of 1,275 bopd net
• The first well in the 2023 campaign, the ASH-8 development well, came onstream in March at rates above expectations and six weeks ahead of the anticipated start-up
• The ASH-8 result, coupled with the continuing development drilling in the first half of the year has the potential to have a positive impact on production levels for 2023, and actual quarterly production information will be provided in H2
• 2023 Egypt work programme consists of two firm wells, and at least eight workovers, with the potential to add additional wells and workover activity to the programme later in the year:
• ASH-8 Development well: Onstream in March 2023
• ASD-3 Development well: Commenced drilling on 1 April
• AJ14 workover: well drilled in 2022 is now onstream
• The potential for additional drilling in 2023 will be finalised with JV partners once the results of the ASD-3 well are available
• Farm-out campaign for the Walton Morant licence, Jamaica, continues to be a focus with the appointment of Energy Advisors Group (“EAG”), a Houston-based M&A advisory group, targeting US companies and investment funds. Process is ongoing with indicative offers due Q2 2023
• Group cash capital expenditure for the full year is forecasted to be approx. $5m, funded from existing operations, with circa $4.5m to be invested in Egypt and up to $0.5m across the other assets in the portfolio
• ESG focus on evaluating emissions baseline in Egypt with operator and contributions to social investment programmes
• Continued evaluation of new opportunities in the Greater Mediterranean area and North and West Africa regions to grow the business in line with the strategy

Tower Resources

Tower has provide an update on its activities in respect of its Thali Production Sharing Contract (“PSC”), in the Rio Del Rey sedimentary basin offshore Cameroon.

Highlights:

• Applied for a one-year extension of the initial exploration period of the PSC, following positive discussions with the Minister of Mines, Industry and Technological Development and (“MINMIDT”) and the Prime Minister of the Republic of Cameroon.
• Discussions continue with rig owners and operators with the aim to secure rig availability in the third and fourth quarter of this year to drill at NJOM-3.
• Discussion for a term loan of approximately $7 million with BGFI Bank Group (“BGFI”) is ongoing and the Company is also actively discussing asset-level financing with several parties.
• Updated resource estimates and risks for the reservoirs connected to the NJOM-1 and the NJOM-2 discovery wells, substantially lowering risk attributed to PS9 Sup and PS3 HW reservoirs, and increasing total risked pMean prospective resources to 35.4 million bbls.
• Deployment of Paradise® software to conduct detailed attribute analysis of the reprocessed 3D seismic data to identify the oil and gas elements of the reservoirs in the Njonji-1 and Njonji-2 fault blocks, resulting in a clearer picture of the pay zones in both fault blocks.

Jeremy Asher, Tower’s Chairman and CEO, commented:
“We are very pleased with the progress that we are making on the Thali PSC and the NJOM-3 well, and we believe that we are close to having a final schedule for this well, which will be transformational for the Company.

“We are finally able to see viable rig slots appearing, and we are now working on the assumption that we will be able to get the NJOM-3 well spudded over the next nine months.

“Every additional piece of subsurface work also increases our confidence in the size and value of the resource that we are targeting, both in terms of the volumes connected to the existing discovery wells and the substantial upside in additional reservoirs.

“We also have a number of different financing options, which we expect to combine to obtain the funds needed for the well.

“We are as excited as ever about the Thali PSC, and very grateful to MINMIDT and the Republic of Cameroon for their continued support.”

If you didn’t know any better you could believe that nothing had changed for Tower, trying to get an extension, needing to raise more money and expecting to drill the now infamous well before Christmas. But it actually looks to me that the light is actually appearing at the end of the tunnel for Jeremy Asher and team. 

In an area that is still very much flavour of the month Tower may just be able to say that they are going to drill in Cameroon this year and that hasn’t always been the case…

Extension of the initial exploration period of the PSC
The Company has formally applied to MINMIDT, with copy to the Societe Nationale de Hydrocarbures, for a further one-year extension of the initial exploration period of the PSC (which currently runs to 11 May 2023) following meetings with the Minister of MINMIDT and the Prime Minister of the Republic of Cameroon. During those meetings, in which the Company explained the status of current rig discussions, both Ministers indicated that they would support the further extension.

Rig availability and NJOM-3 well timing
The Company has continued to maintain discussions with rig owners and operators throughout the past year. As previously announced, rig owners are reluctant to commit rigs to a single well except when gaps appear in other operators’ schedules, this is due to balancing the risk of losing long term contracts for a single well contract. At present, the Company is looking closely at two possible rig availabilities, with different rigs and owners, one in the third quarter of 2023 and one in the fourth quarter. In order to take advantage of either, when available, the Company will need to have put sufficient financing in place to cover a significant level of prepayments. The expected cost of the well is discussed in more detail below. At this stage there is no certainty on availability of the rigs; however, as soon as this changes the Company will update the market.

Cameroon financing
As announced on 29 June 2022, the Company has been discussing a term loan of approximately $7 million with BGFI Bank Group, the largest bank group in Central Africa, which is supported by the Cameroon bank but is now subject to a review by the bank’s group credit committee. The Company understands that this review is linked to a broader review of the capital available to the Cameroon bank for writing new business in the year ahead, which has impacted the time taken, and therefore the outcome remains uncertain. However, the Company has been assured that the process is still ongoing, and that the Cameroon bank continues to support the Company’s plan.

Tower has also continued to pursue possible financing at the asset level, whether in the form of a farm-out or a financial investment in the Company’s operating subsidiary, Tower Resources Cameroon SA (“TRCSA”), to achieve a similar economic result without the need for a formal approval process. Discussions are taking place with multiple credible groups, who have all executed NDAs and are all currently working within the virtual data room.

The Company’s objective remains to raise up to $15 million through a combination of asset financing in the form of debt or equity, with asset-level financing preferred to issuing corporate level equity. Tower will update the market as, and when, any agreements are reached.

Cameroon updated internal resource estimates
Since the Company’s updated internal resource estimates last year, Tower has continued to undertake further G&G work with two objectives: first, to further refine the Company’s understanding of the additional reservoir potential that was identified, and second, to refine the choice of well location for the NJOM-3 well.

In particular, the Company has conducted a more detailed attribute analysis of the reprocessed 3D seismic data which Tower obtained in 2018, using the AI-driven Paradise® workbench software from Geophysical Insights, to identify more clearly the location of the oil and gas elements of the reservoirs in the Njonji-1 and Njonji-2 fault blocks which were connected to the original NJOM-1 and NJOM-2 wells drilled by Total.

The Paradise AI workbench analysis has resulted in higher resolution of the PS9 (Sup) and PS3 pay zones in the Njonji-1 fault block which has both confirmed the additional volumes identified in Tower’s previous estimates and also substantially de-risked them. The analysis also provides better resolution of the PS9-R1 reservoir in the Njonji-2 fault block, including identifying an additional potential oil leg below the gas encountered in the NJOM-2 well, which was not included in the contingent resource estimates as only its gas cap was connected to the well.

The Company has therefore prepared updated internal resource estimates and risk estimates for the reservoirs connected to the NJOM-1 and the NJOM-2 discovery wells, and has also reviewed the risking of the PS9 Sup 1 and 2 reservoirs which appear to be present in the Njonji-1 fault block but were not connected to the NJOM-1 well. These updated internal resource estimates are set out in detail in the linked presentation, and also in the Notes section of this announcement. While the underlying volumetrics are unchanged, the improved risking has led to an increase in the risked pMean recoverable resources compared with the estimates of prospective resources published in June 2022, which were themselves a little higher than those contained in the OIL Reserves/Resources Report dated 12 March 2020.

The latest company estimate of risked pMean recoverable resources is now 35.4 million barrels. The changes from previous internal company estimates can be summarised as follows:

• Risked pMean recoverable resources in fault block 1 increased from 10.5 to 12.9 million bbls
• Risked pMean recoverable resources in fault block 2 increased from 4.1 to 4.9 million bbls
• Risked pMean recoverable resources in South fault block unchanged at 17.6 million bbls

The Company will update its CPR to SPE/PRMS standards in due course.

NJOM-3 well budget
One outcome of the better imaging of the PS9-R1 and PS-3 reservoirs afforded by the attribute analysis has been a review of the optimal point of intersection for the NJOM-3 well. Based on Tower’s latest prognosis, the Company believes that the NJOM-3 well can intersect as much as 75 metres of net pay in the PS9-R1 and PS3-R1 sands alone, with substantial further pay zones expected to be encountered in the PS9 Sup 1 & 2 and the PS3-HW reservoirs. However, this will require either moving the well somewhat to the northwest or deviating the well to achieve the same result.

The Company has had to take account of additional factors that may increase the expected cost to drill the well, including: higher costs associated with the well planning (including the survey costs and change of location or deviation); and higher rig rates and service company and vessel costs. On the other hand, these may be somewhat mitigated by lower fuel costs (since the peak level of oil prices) and Tower also expects lower mobilisation/demobilisation costs with the rigs it is currently considering. Furthermore, the Company is now working on the assumption that it may no longer be practical to undertake a full DST (flow test to surface) immediately, given the long lead times on test equipment, especially if the Company is to drill in the third quarter or early in the fourth quarter of this year, but the Company is working on an alternative method to achieve a shorter period flow test which will also reduce costs.

The Company’s current cost estimate to complete the NJOM-3 well is approximately $15.5 million.

Trinity Exploration & Production

Trinity has provided an update on operations for the three-month period ended 31 March 2023 (“Q1 2023” or “the Period”).  The information contained herein has not been audited and may be subject to further review and amendment.

Jeremy Bridglalsingh, Chief Executive Officer of Trinity, commented:
“Trinity is at an inflection point as we prepare to drill the Jacobin well, testing the first of our nine Hummingbird deeper prospects. The rig has mobilised and the well will spud in the coming days. The well is designed to test the extensive deeper onshore play and collect data to calibrate and define future activity across Trinity’s existing onshore acreage and the Buenos Ayres block, should the Company be successful in the ongoing licence round.

The ABM-151 well was successfully returned to production in March and, since this time, has performed consistently above expectations.  The well is currently producing at a managed stabilised rate of around 140 bopd, whilst producing encouraging well performance data.

As reported, we suffered from two setbacks recently: the cyber incident in December and then, in April, a generator fire on the Trintes Bravo platform. I’m pleased to say that we avoided a lengthy disruption from either event and the team responded in a calm and professional manner. Trintes returned to production the day following the fire and Bravo itself within eight days. We are grateful for the help of the Ministry of Energy and Energy Industries, with whom our excellent working relationship proved invaluable, and I am also thankful for the team’s rapid and level-headed response. We see this focus and commitment in other operational delivery such as the successful performance of ABM-151 and look forward to updating shareholders on our further progress at a very busy and exciting time for Trinity.”

The Jacobin well is of significant importance as any growth elsewhere in Trinity is hard to find, Q1 production is just down on this time last year. 

Q1 2023 Operational Highlights 

• The Company maintained solid production performance over the quarter with Q1 2023 sales volumes averaging 2,899 bopd (Q4 2022: 2,961 bopd; Q1 2022: 2,929 bopd).  This sales performance, which is broadly in line with the prior period, comes as a result of ongoing well optimisation, drilling, workovers and recompletion activities.

During Q1 2023:

• 2 recompletions (“RCPs”) (Q4 2022: 1; Q1 2022: 5) were completed.
• 39 workovers (Q4 2022: 27; Q1 2022: 24) were completed.
• swabbing operations continued across onshore and West Coast assets.

The ABM-151 well in the Brighton Marine block, offshore the West Coast of Trinidad, was returned to production on 21 March 2023 following an extensive refurbishment of surface facilities and the installation of remote surveillance technology.  Between restart and the end of the Period the well flowed at an average rate of 175 bopd. The well is currently producing at a managed rate of 140 bopd and Trinity continues to monitor the well closely.

Q4 2022 Financial Highlights

Average realisation of US$ 67.9/bbl for Q1 2023 (Q4 2022: US$ 75.4/bbl, Q1 2022: US$ 83.1/bbl) reflects lower prevailing oil prices in the Period.

• EBITDA, pre-hedging1, in Q1 2023 of US$ 5.3 million (unaudited) (Q4 2022 US$ 7.9 million (unaudited); Q1 2022 US$ 7.9 million).
• Operating break-even2, pre-hedging1, Q1 2023 of US$ 35.4/bbl (Q4 2022 US$ 31.4/bbl; Q1 2022 US$ 31.1/bbl).

1. The Company has no hedging in place in 2023.
2. Operating break-even is the realised price/bbl where the adjusted EBITDA/bbl for the Group is equal to zero.

• Cash balance of US$ 11.4 million (unaudited) as at 31 March 2023 versus US$ 12.1 million (unaudited) as at 31 December 2022 and US$ 17.5 million as at 31 March 2022.
• The Group had drawn borrowings (overdraft) of US$ 2.3 million as at 31 March 2023 (US$ 2.7 million as at 31 December 2022 and US$ 2.7 million as at 31 March 2022).
• The Company continued to repurchase its Ordinary Shares in accordance with the second buyback programme announced on 24 October 2022 and, during the Period, repurchased an additional 312,000 shares (0.8% of the Company’s shares in issue).

The second buyback programme concluded on 26 April 2023 with a further 48,000 shares repurchased during April 2023 bringing the total number of shares held in treasury at 26 April 2023 to 1,432,000 (3.6 % of the Company’s shares in issue).

The Board will consider a further share buyback programme.

Outlook

Jacobin Update
Preparation of the site for the upcoming Jacobin well to test the deep Miocene play fairway in Licence PS-4 is complete.  Well Services’ Rig 60 mobilisation is underway currently with the first elements of the rig arriving on site and are being assembled.  The well is expected to spud in the coming days.

2022 Onshore and Nearshore Competitive Bid Round
On 9 January 2023, Trinity submitted a bid for the Buenos Ayres block in the 2022 Onshore and Nearshore Competitive Bid Round conducted by the Government of Trinidad and Tobago Ministry of Energy and Energy Industries.

Buenos Ayres is located immediately to the west of Trinity’s existing Palo Seco area interests comprising Blocks WD-5/6, WD-2 and PS-4 and, at its closest, is only around 500 metres from the Company’s existing sub-licences.

If awarded, Trinity would seek to take advantage of its unique understanding of the stratigraphy in this area onshore Trinidad, where there are strong analogues to the Company’s existing acreage, and quickly progress from the drilling phase to production.

Award of licences from the Bid Round is now anticipated in May.

Cyber Incident
Following the sophisticated cyber incident in December 2022, Trinity’s IT team and its external advisers have successfully returned its administrative systems to full capacity incorporating learnings from the incident and embedding more resilient IT infrastructure, cyber security systems and procedures.

This work to high-grade IT and associated security systems has delayed the normal year-end financial close process.  However, the external financial audit is underway and the Company still expects to issue its audited 2022 financial statements before 30 June 2023, in line with its legal and regulatory requirements.

Trintes Field Incident
On the evening of 10 April 2023, a fire occurred in one of the two generators on the Trintes Bravo platform.  Production across the field was halted and the fire was contained.  Production restarted from Alpha and Delta platforms on 11 April 2023.

Four operators, all Trinity staff, were on Bravo at the time of the incident and, having suffered some burns and from smoke inhalation, all are now recovering well and expect to resume work imminently.

Following approval from the Ministry of Energy and Energy Industries, received on 17 April 2023, the Company successfully restored oil production from all previously producing wells on the Bravo platform on 18 April 2023.

Production from the field is in-line with pre-incident levels at approximately 1,010 bopd.

Gulf Keystone Petroleum 

Gulf Keystone is today providing an update on operational and corporate activity and 2023 guidance following the shut-in of the Iraq-Turkey pipeline on 25 March 2023.

Jon Harris, Gulf Keystone’s Chief Executive Officer, said:
“Gulf Keystone was on track to deliver another year of strong profitable production growth and robust cash flow generation until the Iraq-Turkey pipeline arbitration award resulted in the suspension of pipeline exports. March production prior to the pipeline suspension averaged c.53,700 bopd with plans to bring on SH-18 in Q2 2023 and ongoing facilities expansion activities.

The lack of crude oil exports for a month has further exacerbated delays in KRG payments to international oil companies with uncertainty on when consistent monthly payments will resume and when the current overdue amount of $102 million net to GKP will be paid.

While we continue to believe that the pipeline shut-in is temporary and the KRG will resume more normalised payments, we are prudently taking action to preserve liquidity by targeting a reduction of costs across the business. We are closely monitoring the situation and will take further appropriate action as required.”

With the pipeline suspension really beginning to cut into the finances at GKP it is inevitable that a serious cost cutting process was inevitable, however temporary the closure is going to be. Even the dividend is likely to be part of the cost reduction programme. We all thought that its in no one’s interest for this to happen but in this game there is no blinking yet…

Operational

• Up to the Iraq-Turkey pipeline shut-in on 25 March 2023, gross average production in 2023 of c.49,200 bopd and in March 2023 of c.53,700 bopd, including five days in excess of 55,000 bopd
• Following the suspension of exports, GKP produced at reduced rates into storage facilities prior to shutting in production at PF-1 on 31 March 2023 and at PF-2 on 13 April 2023
• The suspension has resulted in a gross production deferment to date of around 1.6 million barrels, or approximately 4,400 bopd on a full-year basis
• The Company continues to believe that the suspension of exports will be temporary and is ready to resume production immediately, although no official timeline to restart pipeline operations has been publicly announced by the Kurdistan Regional Government (“KRG”)
  • The Company understands that discussions between the KRG and the Iraqi Ministry of Oil are ongoing to implement the framework agreement announced on 4 April 2023
• Upon the resumption of exports, production will be gradually ramped up with the objective of safely returning to full export capacity
  • The drilling of SH-18 was recently completed and the well is now being hooked-up. We expect the well to be available for start-up in Q2 2023, in line with prior guidance

Financial

• The Company continues to engage with the KRG regarding the delays to oil sales payments
  • While the Company has received $66 million net from the KRG in 2023 for August and September 2022 oil sales, overdue receivables for the months of October 2022 to January 2023 total $102 million net on the basis of the KBT pricing mechanism
• Net capital expenditures to the end of April 2023 are estimated at $45 million net, including completion of SH-17 and SH-18, well workovers, well pad preparation, long lead items and expansion of production facilities
• Cash balance of $99 million at 26 April 2023

Outlook

• Given the ongoing suspension of exports and continued delays to KRG payments, the Company is focussed on preserving liquidity and is targeting a reduction of costs across the business, while maintaining a strong focus on safety and long-term asset reliability
• Consequently, the Company is significantly reducing planned net capital expenditures to focus on only safety critical and unavoidable contractual commitments
  • While our review is ongoing, we currently expect May to December 2023 net capital expenditures of $35-40 million
  • Full year 2023 net capital of expenditures are currently estimated at $80-85 million (prior guidance: $160-$175 million)
• The Company is implementing initiatives to reduce Opex and G&A. However, until pipeline operations resume and the overall production impact from the export suspension is known, the Board is suspending production and gross Opex per barrel guidance
• As part of its ongoing review, the Board is considering the previously declared final 2022 ordinary annual dividend of $25 million
• The Board continues to review the implications of the current situation and is considering necessary operational, financial and legal measures to protect the Company’s interests during this period

 KeyFacts Energy Industry Directory: Malcy's Blog