GENL Genel Energy Plc

26 March 2024

Genel Energy plc

Audited results for the year ended 31 December 2023

 

Genel Energy plc (‘Genel’ or ‘the Company’) announces its audited results for the year ended 31 December 2023.

 

Paul Weir, Chief Executive of Genel, said:

“We have continued the journey that we commenced in 2022 to, firstly, refocus the business on areas where it can be profitable and deliver shareholder value and, secondly, optimise the organisation to create a reshaped and resilient business with the potential for transformational value accretion through several catalysts.

 

We are a leaner, simplified company that retains clear objectives – generating resilient and sustainable cash flows, diversifying our income through the addition of new assets, and maintaining a strong balance sheet.

 

We have reduced our workforce and cut costs significantly, exited the Sarta and Qara Dagh licences, worked with our operating partner to develop a new income stream from local sales, and spent considerable time defending our contractual rights under the Bina Bawi and Miran PSCs, where we invested over $1.4 billion before their termination in December 2021.

 

These actions mean that we are now well positioned in 2024, with a reshaped and resilient business and a strong balance sheet. In the absence of value accretive M&A, we expect to maintain net cash of more than $100 million even if the suspension of exports continues to the end of the year.

 

Genel has established a sound platform from which to spring forward. The re-opening of the pipeline has the potential to more than double cash generation. We expect to recover the $107 million of overdue receivables, and we have the capacity and intent to acquire new assets. On the Miran and Bina Bawi oil and gas assets arbitration, having now completed the evidential hearing, our views on the merits of our case are unchanged since the arbitration was launched in December 2021.”

 

Results summary ($ million unless stated)

	2023	2022
Average Brent oil price ($/bbl)	82	101
Production (bopd, working interest)	12,410	30,150
Revenue	84.8	401.9
EBITDAX1	32.8	349.1
Depreciation and amortisation	(44.0)	(134.3)
Exploration expense	(0.1)	(1.0)
Net write-off / impairment of oil and gas assets	1.2	(75.8)
Net (expected credit loss (‘ECL’)) / reversal of ECL of receivables	(9.1)	8.6
Operating (loss) / profit	(19.2)	146.6
Cash flow from operating activities	55.1	412.4
Capital expenditure	68.0	143.1
Free cash flow2	(71.0)	234.8
Cash	363.4	494.6
Total debt	248.0	274.0
Net cash3	119.7	228.0
Dividends declared during financial year (¢ per share)	12	18

 

1. EBITDAX is operating profit / (loss) adjusted for the add back of depreciation and amortisation, net write-off/impairment of oil and gas assets and net ECL/reversal of ECL receivables
2. Free cash flow is reconciled on page 11
3. Reported cash less IFRS debt (page 11)

Highlights

• The Iraq-Türkiye pipeline (‘ITP’) has been suspended since March 2023, with talks ongoing but no clear timing on when exports will restart
• Reshaped business resilient and well positioned to maximise upside
  • Local sales consistent since end of January, with the Tawke PSC currently generating sufficient funding to cover organisational spend
  • Increase to Tawke PSC 2P reserves replacing production in 2023 and retaining 2P reserves of 79 MMbbls net to Genel at the licence
  • Organisational spend outside the cash generative Tawke PSC reduced by 40% to around $3 million per month
  • Reduced workforce by 70% and cut costs significantly across all areas of the business
  • Sarta and Qara Dagh exited, resulting in a write off relating to Sarta of $19 million
  • Somaliland licence extended until 2026
• Strong balance sheet provides opportunity to acquire and develop new assets
  • Net cash of $120 million at 31 December 2023 ($228 million at 31 December 2022)
  • Total debt of $248 million reduced by $26 million through repurchase of bonds at below 95 cents ($274 million at 31 December 2022)
  • Genel expects to maintain net cash well above $100 million throughout 2024
• Ongoing focus on being a socially responsible contributor to the global energy mix
  • Zero lost time incidents in 2023, with over four million hours now worked since the last incident
  • Carbon intensity of 14 kgCO2e/bbl for Scope 1 and 2 emissions in 2023 (2022: 17.6 kgCO2e/bbl), below the global oil and gas industry average of 19 kgCO2e/boe
  • Genel continues to invest in the host communities in which we operate, aiming to invest in those areas in which we can make a material difference to society
• The London-seated international arbitration two-week hearing which included Genel’s claim for substantial compensation from the Kurdistan Regional Government (‘KRG’) following the termination of the Miran and Bina Bawi PSCs finished as scheduled. Parties will make written closing submissions in April, subsequent to which written reply submissions will be made in May. The timing of the result is uncertain, but continues to be expected by the end of 2024

 

Potential catalysts for significant shareholder value creation in 2024

• Reopening of the ITP has the potential to materially increase cash generation
• $107 million overdue from the KRG for oil sales from October 2022 to March 2023 inclusive
• The Company continues to seek to acquire new assets to increase and diversify our income streams

 

Enquiries:

 

Genel Energy Andrew Benbow, Head of Communications	+44 20 7659 5100
Vigo Consulting Patrick d’Ancona	+44 20 7390 0230

 

Genel will host a live presentation on the Investor Meet Company platform on Tuesday 26 March at 1000 GMT. The presentation is open to all existing and potential shareholders. Questions can be submitted at any time during the live presentation. Investors can sign up to Investor Meet Company for free and add to meet Genel Energy PLC via:

https://www.investormeetcompany.com/genel-energy-plc/register-investor. 

 

This announcement includes inside information.

 

 

Disclaimer

This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company’s control or within the Company’s control where, for example, the Company decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements.

 

 

 

CEO STATEMENT

It is difficult to look at 2023 without it being dominated by the closure of the Iraq-Türkiye pipeline. The suspension of our route to export resulted in a material reduction in production and cash flow. In a year in which we were buffeted by factors beyond our control, it was a reminder of the inherent resilience of our business model, a resilience that means we retain a strong position from which we view the future with confidence.

 

Going in to 2023, one of our key aims was to continue the simplification of the business, focusing on optimisation and cost control and investment in business improvement. With the ITP suspended, we accelerated this journey, significantly changing the size and shape of the organisation, materially reducing our cost base. We are now in a position where our income from strong local sales in January and February 2024 has covered our outflows, we have over $100 million in net cash, and significant opportunities lie ahead.  

 

A reshaped business

The closure of the pipeline prompted us to move quickly to reduce our capital expenditure, with $50 million cut from our original budget. We have more than halved our workforce, and we have shed non-profitable assets. We allowed the Qara Dagh licence to lapse, and Sarta has been terminated. We are a significantly leaner vehicle than we were even six months ago, having efficiently closed out our activity at Sarta and having minimised our footprint and cost base in Kurdistan. And we are getting leaner still, encouraging a constant state of awareness in the business about how we can drive further cost efficiencies.

 

As we have cut costs we have ensured that we have kept the right personnel to grow the business in the better times that certainly lie ahead. It is important that a reshaped business does not mean a business that lacks skills, and we must ensure that we have the correct balance between being right sized in the current environment and having the right people to drive Genel forward and take advantage of upcoming opportunities.

 

All of the changes that we have made to the business have been done with our shareholders in mind, protecting shareholder funds and ensuring that we remain resilient with a robust balance sheet, with a business that is set up to maximise shareholder value going forward.

 

Robustly positioned

Our focus on resilience is bolstered by income from the Tawke licence, which remains the engine room of the business. Working with the operator, DNO, a great job has been done to build a new income stream from local sales, while cutting operational costs by 65%. Production ramped up through the second half of the year, and local sales have been material and robust so far this year.

 

Going forward we expect cash generation from these local sales to match our total business expenditure, should income remain at levels seen in Q1 2024. Should the ITP reopen, our cash generation has the potential to more than double overnight. Along with our industry peers, we continue to work hard to facilitate the resumption of exports with appropriate commercial terms. Positive comments are regularly being made by politicians from both the Federal Government of Iraq and the KRG, although these are not being supported by movement on key issues so far. The timing of export resumption is therefore not something that we can suggest with any certainty.

 

Opportunities ahead

The reopening of the export route, with a stable and predictable payment environment, is one of the numerous catalysts that we can see ahead in 2024. We are reviewing all options relating to the $107 million that is still owed for past exports, the repayment of which would help to further strengthen our balance sheet and boost cash generation.

 

As we work to unlock the significant value from Kurdistan, we continue our search to add new income streams elsewhere. Our criteria for new assets have not changed – we are focused on cash generation, seeking a value accretive deal in a stable jurisdiction. We remain laser focused and disciplined as we seek the right deal for our shareholders, and are comfortable looking beyond the MENA region to get a deal that ticks all of our boxes. As we reshaped our business in 2023, we have continued our search for the right opportunity to integrate within Genel. There remain opportunities out there that fit our criteria, and we are confident that we will find the correct deal.

 

Miran and Bina Bawi arbitration progressing

The Company has committed significant senior management time to the arbitration relating to the Miran and Bina Bawi PSCs. As a reminder, our position is that the KRG’s termination of the Bina Bawi and Miran licences in December 2021 was repudiatory and caused us significant losses. By way of reference, we have spent over $1.4 billion acquiring and attempting development of these assets, both as operator and non-operator up to the termination of both PSCs in December 2021.

 

The two-week hearing (including factual and expert evidence) was held in London as scheduled and ended on 1 March 2024. The timing of the result is uncertain, but is expected by the end of 2024 following the Parties making closing written submissions in April 2024 and reply written submissions in May 2024. Our views on the merits of the case are unchanged since the dispute process under the PSCs was commenced in Q3 2021.

 

Outlook

Genel retains a robust cash position, a resilient business model, and a focus on taking advantage of the material catalysts ahead.

 

 

OPERATING REVIEW

Reserves and resources development

Genel's proven plus probable (2P) net working interest reserves totalled 89 MMbbls (31 December 2022: 92 MMbbls) at the end of 2023. A positive 4 MMbbls revision of 2P reserves at the Tawke PSC offset the removal of 2.7 MMbbls of 2P reserves from the terminated Sarta PSC, with 4.5 MMbbls of production in 2023. 

 

	Remaining reserves (MMbbls)				Resources (MMboe)
					Contingent				Prospective
	1P		2P		1C		2C		Best
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
31 December 2022	267	69	349	92	37	11	129	36	4,722	3,006
Production	(18)	(5)	(18)	(4)	-	-	-	-	-	-
Acquisitions and disposals	-	-	(9)	(3)	(28)	(8)	(85)	(25)	(142)	(43)
Extensions and discoveries	-	-	-	-	-	-	-	-	-	-
New developments	-	-	-	-	-	-	-	-	-	-
Revision of previous estimates	(4)	(1)	16	4	4	1	(5)	(1)	-	-
31 December 2023	245	63	338	89	13	3	39	10	4,580	2,964

 

Production

Net production in 2023 averaged 12,410 bopd, significantly down on the prior year (2022: 30,150 bopd) due to the suspension of the ITP. This caused there to be minimal sales in the second quarter of the year, before the local sales market was established in Q3 and production was then ramped up in Q4.  Production was dominated by the Tawke PSC, which produced 11,570 bopd.

 

All Genel production in H2 2023 came from the Tawke PSC. Gross production from the Tawke licence increased to 65,780 bopd in Q4 2023, up from 25,980 bopd in Q3, with the field partners selling their entitlement share into the local market.

 

 

PRODUCING ASSETS

Tawke PSC (25% working interest)

Gross production from the Tawke licence averaged 46,280 bopd in 2023, impacted by the closure of the ITP. Following the start of local sales in H2, production increased to 65,780 bopd in Q4 2023.

 

At the end of 2023, gross production from the Tawke licence was averaging 80,000 bopd, with entitlement barrels sold at prices in the low-to-mid $30s per barrel. The operator, DNO, expects gross production at the licence to continue to average 80,000 bopd. That figure could change depending on the outcome of ongoing discussions related to recovery of arrears for past deliveries to the KRG and payment terms and conditions for any future oil exports, which in turn will drive investments in wells.

 

With operational spend having been reduced by 65%, the Tawke PSC is currently generating over $3 million a month in net cash flow for Genel from strong local sales, which if retained at current levels is able to cover total organisational spend away from the licence.

 

Taq Taq (44% working interest, joint operator)

Prior to the closure of the ITP, field partners were planning a resumption of drilling at Taq Taq. In line with Genel’s focus on reducing costs, and lack of clarity regarding the resumption of exports and payments, this plan was dropped. Costs were reduced to below $1 million per month at the start of 2024, and further cuts are expected to reduce this to around half a million dollars per month. Given the lack of meaningful cash flows expected to come from Taq Taq going forward, its place in the Genel portfolio is under review.

 

Sarta (30% working interest, operator)

Genel’s focus at the start of 2023 was on making ongoing production from Sarta profitable, and capital investment was contingent on both licence profitability and the extent to which there could be confidence that such investment would add cash generative production. Given the investment required, and the lack of certainty over a resumption of payments, Genel and its joint venture partner, Chevron, informed the Ministry of Natural Resources of its intention to surrender the asset and thereby terminate the Sarta PSC on 1 December 2023.

 

Remediation work was completed in Q1 2024, at a net cost of $1 million, and there will be no further material expenditure at Sarta going forward.

 

PRE-PRODUCTION ASSETS

Somaliland

Work continued in 2023 on readiness towards the potential drilling of a well at the Toosan-1 well site on the SL10B13 block (51% working interest and operator). The Environmental, Social and Health Impact Assessment was finished, and required civil work at the well site at this stage of the project is now complete.

 

Genel continues to believe that there is a tremendous opportunity in Somaliland, and is assessing the timing of further investment. There is no significant expenditure expected in 2024, and a licence extension has been granted which allows for drilling to be undertaken in due course.

 

Morocco (Lagzira block - 75% working interest and operator)

The farm-out programme on the Lagzira block is ongoing.

 

 

 

FINANCIAL REVIEW

(all figures $ million)	FY 2023	FY 2022
Brent average oil price	$82/bbl	$101/bbl
Revenue	84.8	401.9
Production costs	(21.3)	(34.3)
Cost recovered production asset capex	(55.2)	(85.9)
Production business net income after cost recovered capex	8.3	281.7
Other operating costs	(3.6)	-
G&A (excl. non-cash)	(25.5)	(17.7)
Net cash interest1	(4.2)	(19.2)
Working capital	4.7	47.2
Free cash flow before investment in growth	(20.3)	292.0
Non cost recovered capex	(12.8)	(57.2)
Net (expense) / income from discontinued operations	(11.6)	12.5
Working capital and other	(26.3)	(12.5)
Free cash flow	(71.0)	234.8
Dividend paid	(33.5)	(47.9)
Purchases of own shares	(1.8)	-
Purchases of own bonds	(24.9)	(6.0)
Net change in cash	(131.2)	180.9
Cash	363.4	494.6

 

1 Net cash interest is bond interest payable less bank interest income (see note 5)

 

2023 financial priorities

With the export pipeline suspended from March, 2023 did not generate the financial performance that we had planned for, but we have taken decisions that mean we have ended the year in a resilient position, with an outlook where we can see a clear route to delivery of material shareholder value. While the closure of the ITP accelerated and deepened some of our planned cost cutting, we were already well on the way to reshaping the business and ensuring that it has the financial strength to endure challenges and maintain our exposure to the significantly value accretive potential events that we hope to see materialise in 2024. 

 

The table below summarises our progress against the 2023 financial priorities of the Company as set out in our 2022 results.

 

2023 financial priorities	Progress
Maintain business resilience and balance sheet strength	On suspension of exports, completed work efficiently, significantly cut capital and operating expenditure, suspended the dividend programme Developed a new income stream through domestic sales Cash of $363 million at end of 2023
Put our significant cash balance to work, earning appropriate returns to deliver value to shareholders primarily through our dividend programme and diversify our cash generation	Final dividend of 12¢ per share paid On the Tawke licence, new wells were completed in the first half, and 2P reserves increased to offset production in the year Bond debt reduced by $26 million at an average price below 95 cents in the dollar Continued to actively screen and work up opportunities to acquire new production assets, with the ultimate aim of resuming dividend returns to shareholders
Deliver the 2023 work programme on time and on budget, and continue simplification of the business with a focus on optimisation and cost control and investment in business improvement	Work programme reduced due to external conditions Remaining activities completed on time and below budget Simplification of the business was accelerated and deepened, with a two thirds reduction to our total workforce

 

Outlook and financial priorities for 2024

The key principles of our financial focus remain largely unchanged. We have a resilient business model that will continue to mitigate negative events and maximise potential upside, all with a firm focus on maximising cash generation. Ultimately, successful strategic delivery will lead to a resumption of shareholder returns, through delivering robust, resilient, diverse, and predictable cash flows.

 

Maintain business resilience and balance sheet strength

Running a resilient business with a strong balance sheet is a key component of our business model. It is particularly relevant at the current time, with the lack of access to export prices and volumes and the delayed receipt of amounts owed. While the ITP remains closed, we protect the balance sheet and resilience of the business by balancing the sources and uses of our cash flows. Actions taken to reduce costs and restructure the organisation in 2023 have prepared us well for this, with monthly organisation spend excluding the cash-generative Tawke PSC reduced to under $3 million per month at the time of writing.

 

Local market sales since November 2023 have seen relatively consistent volumes, which has required constant attention from the operator. We believe the Tawke PSC is well positioned to continue to deliver stable and meaningful cash flows that will be sufficient to cover our costs, and as a consequence we expect to retain a net cash position of over $100 million in 2024. Should the pipeline open, which we expect, then the subsequent establishment of regular payments would materially boost our cash generation, with the receipt of our outstanding receivable of $107 million offering further significant upside.

 

Ensure capital availability for funding of key strategic objectives

Our capital allocation priorities remain maintenance of a strong balance sheet and funding of the Company’s strategic objectives in order to generate long-term value for shareholders.

 

We are currently retaining a significant cash balance in excess of the cash required to fund the organic business in order to fund the acquisition of new assets, as we seek to diversify our income streams. This balance is partly funded by our bond debt of $248 million, which matures in October 2025. We retain strict discipline as we seek new opportunities, with appropriate economic analysis and downside planning key considerations.

 

With a coupon that is low relative to prevailing market rates, the net cost of retaining this optionality is low.

 

Ensure appropriate capital allocation

In pursuit of our strategic objectives, robust assessment of the expected benefit to be obtained from invested capital underpins our processes to ensure appropriate allocation of capital, making sure that each dollar spent is done so in the knowledge that we are custodians of shareholder funds.

 

In 2023, as well as cutting our capital allocation appropriately in the face of the ongoing ITP closure, with Tawke drilling suspended, we ensured that any investment was necessary and effective towards improving the profitability of our business and achieving our objectives.

 

At the start of the year, we took the decision to exit the Qara Dagh licence, due to the extent of certainty that redrilling on the licence would have a positive outcome. For similar reasons, it was decided not to pursue other drilling opportunities at Sarta, and to reduce costs appropriately at Taq Taq. This focus has meant that our future activity at that licence is under review. Finally, we agreed with the government and our partner to extend the exploration period on the Toosan-1 well in Somaliland. There is the opportunity for significant value creation in Somaliland, where we remain excited about the potential of the subsurface.

 

In addition, we invested in the Miran and Bina Bawi arbitration process, where we are seeking to protect our contractual position under the PSCs which are governed by English law. We have invested over $1.4 billion in the acquisition and attempted development of these assets, and we will continue to ensure that funds are available to pursue collection in the event of an Award in Genel’s favour.

 

Finally, we reduced our debt by nominal $26 million of our debt at a cost of below 95 cents in the dollar, which provided an attractive level of return without significantly impacting our capital availability for other strategic objectives.

 

Financial results for the year

Income statement

 

(all figures $ million)	FY 2023	FY 2022
Brent average oil price	$82/bbl	$101/bbl
Production (bopd, working interest)	12,410	30,150
Profit oil	25.4	143.4
Cost oil	58.6	116.1
Override royalty	0.8	142.4
Revenue	84.8	401.9
Production costs	(21.3)	(34.3)
Other operating costs	(3.6)	-
G&A (excl. depreciation and amortisation)	(27.1)	(18.5)
EBITDAX	32.8	349.1
Depreciation and amortisation	(44.0)	(134.3)
Exploration expense	(0.1)	(1.0)
Net write-off / impairment of oil and gas assets	1.2	(75.8)
Net (ECL) / reversal of ECL of receivables	(9.1)	8.6
Net finance expense	(9.1)	(24.5)
Income tax expense	(0.2)	(0.2)
Loss from discontinued operations	(32.8)	(129.2)
Loss	(61.3)	(7.3)

 

Production of 12,410 bopd was significantly lower than last year (2022: 30,150 bopd) as a result of the suspension of exports through the ITP. This resulted in very limited production between April and July, with production from Tawke only restarting from July at lower levels, selling into the domestic market. This decrease in production, together with the significantly lower realised price per barrel for local sales, resulted in a reduction in revenue from $402 million to $85 million, with $38 million generated from local sales in H2 2023 and the remainder of $47 million generated from export sales between January and March inclusive.

 

Production costs of $21 million decreased from the prior year (2022: $34 million), with cost per barrel $4.8/bbl in 2023 (2022: $3.3/bbl), with the higher cost per barrel being the result of a combination of lower production and some fixed costs.

 

Other operating costs of $4 million were related to Taq Taq which were incurred after production cease.

 

Corporate cash costs were $12 million (2022: $14 million).

 

The decrease in revenue resulted in a similar decrease to EBITDAX, which was $33 million (2022: $349 million). EBITDAX is presented in order to illustrate the cash operating profitability of the Company and excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation, impairments and write-offs.

 

Depreciation of $40 million (2022: $95 million) and Tawke intangibles amortisation of $4 million (2022: $39 million) decreased due to lower production and pipeline closure.

 

While Genel expects to recover its overdue receivables of $107 million in full, given there is currently no repayment plan, a net expense of $10 million has been recognised relating to the expected credit loss on overdue receivables. Further explanation is provided in note 1 to the financial statements.

 

Interest income of $21 million (2022: $7 million) has significantly increased as a result of the increase in interest rates, in turn reducing our net cost of debt. Bond interest expense of $25 million (2022: $26 million) was in line with the previous year. Other finance expense of $5 million (2022: $5 million) related to non-cash discount unwinding on provisions and bond which is partly offset by gain on buyback of bonds in the year.

 

In relation to taxation, under the terms of KRI production sharing contracts, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. Tax presented in the income statement was related to taxation of the service companies (2023: $0.2 million, 2022: $0.2 million).

 

Following the termination of Sarta PSC in the year, income statement figures of Sarta PSC have been disclosed as discontinued operation. Further details are provided in note 7 to the financial statements.

 

Capital expenditure

Capital expenditure was reduced to $68 million (2023: $143 million), a reduction of around $50 million reduced from our initial guidance. Spend on production assets was $59 million, and pre-production assets $9 million, with $20 million spent in H2 as expenditure cuts were made following the ITP closure.

 

(all figures $ million)	FY 2023	FY 2022
Cost recovered production capex	55.1	85.9
Non cost recovered production capex	3.8	47.5
Other exploration and appraisal capex	9.1	9.7
Capital expenditure	68.0	143.1

 

Cash flow, cash, net cash and debt

Gross proceeds received totalled $102 million (2022: $473 million).

 

 

(all figures $ million)	FY 2023	FY 2022
Brent average oil price	$82/bbl	$101/bbl
EBITDAX	32.8	349.1
Working capital	22.3	63.3
Operating cash flow	55.1	412.4
Producing asset cost recovered capex	(66.6)	(77.8)
Development capex	(22.2)	(50.4)
Exploration and appraisal capex	(9.7)	(20.0)
Interest and other	(27.6)	(29.4)
Free cash flow	(71.0)	234.8

 

Free cash flow is presented in order to illustrate the free cash generated for equity. Free cash outflow was $71 million (2022: $235 million inflow) with an overall decrease due to pipeline closure and delay in proceeds.

 

(all figures $ million)	FY 2023	FY 2022
Free cash flow	(71.0)	234.8
Dividend paid	(33.5)	(47.9)
Purchase of shares	(1.8)	-
Bond repayment	(24.9)	(6.0)
Net change in cash	(131.2)	180.9
Opening cash	494.6	313.7
Closing cash	363.4	494.6
Debt reported under IFRS	(243.7)	(266.6)
Net cash	119.7	228.0

 

The bonds maturing in 2025 have two financial covenant maintenance tests:

Financial covenant	Test	YE 2023
Equity ratio (Total equity/Total assets)	> 40%	55%
Minimum liquidity	> $30m	$363m

 

Net assets

Net assets at 31 December 2023 were $434 million (31 December 2022: $528 million) and consist primarily of oil and gas assets of $331 million (31 December 2022: $327 million), net trade receivables of $93 million (31 December 2022: $117 million) and net cash of $120 million (31 December 2022: $228 million).

 

Liquidity / cash counterparty risk management

The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills, time deposits or liquidity funds with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating.

 

Going concern

The Directors have assessed that the Company’s forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the annual report for the year ended 31 December 2023 and consequently that the Company is considered a going concern. Further explanation is provided in note 1 to the financial statements.

 

The Company is in a net cash position with no near-term maturity of liabilities.

 

Consolidated statement of comprehensive income

For the year ended 31 December 2023

 

		2023	Restated 2022
	Note	$m	$m
Revenue	2	84.8	401.9
Production costs	3	(21.3)	(34.3)
Depreciation and amortisation of oil assets	3	(43.9)	(134.2)
Gross profit		19.6	233.4
Exploration expense	3	(0.1)	(1.0)
Other operating costs	3	(3.6)	-
Net write-off of intangible assets	3	1.2	(75.8)
Net (expected credit loss (‘ECL’)) / reversal of ECL of receivables	3	(9.1)	8.6
General and administrative costs	3	(27.2)	(18.6)
Operating (loss) / profit		(19.2)	146.6
Operating (loss) / profit is comprised of:
EBITDAX		32.8	349.1
Depreciation and amortisation	3	(44.0)	(134.3)
Exploration expense	3	(0.1)	(1.0)
Net write-off of intangible assets	3	1.2	(75.8)
Net (ECL) / reversal of ECL of receivables	3	(9.1)	8.6
Finance income	5	20.6	6.7
Bond interest expense	5	(24.8)	(25.9)
Net other finance expense	5	(4.9)	(5.3)
(Loss) / profit before income tax		(28.3)	122.1
Income tax expense	6	(0.2)	(0.2)
(Loss) / profit and total comprehensive (expense) / income from continuing operations		(28.5)	121.9
Loss from discontinued operations	7	(32.8)	(129.2)
Loss and total comprehensive expense		(61.3)	(7.3)
Attributable to:
Owners of the parent		(61.3)	(7.3)
		(61.3)	(7.3)
(Loss) / Earnings per ordinary share		¢	¢
From continuing operations:
Basic	8	(10.2)	43.7
Diluted	8	(10.2)	43.7
From continuing and discontinued operations:
Basic	8	(22.0)	(2.6)
Diluted	8	(22.0)	(2.6)
Basic (LPS) / EPS excluding impairments1	8	(11.9)	66.7

1Basic (LPS) / EPS excluding impairment is loss and total comprehensive expense adjusted for the add back of net impairment/write-off of oil and gas assets and net ECL/reversal of ECL of receivables divided by weighted average number of ordinary shares

 

Previous year’s figures have been restated for discontinued operation disclosure in relation to Sarta PSC (see note 7).

Consolidated balance sheet

At 31 December 2023

 

		2023	2022
	Note	$m	$m
Assets
Non-current assets
Intangible assets	9	84.7	79.1
Property, plant and equipment	10,20	246.5	248.1
Trade and other receivables	11	66.5	-
		397.7	327.2
Current assets
Trade and other receivables	11	34.0	121.7
Cash and cash equivalents	12	363.4	494.6
		397.4	616.3
Total assets		795.1	943.5
Liabilities
Non-current liabilities
Trade and other payables	13,20	(0.5)	(1.2)
Deferred income	14	(8.2)	(6.5)
Provisions	15	(45.2)	(52.2)
Interest bearing loans	16	(243.7)	(266.6)
		(297.6)	(326.5)
Current liabilities
Trade and other payables	13,20	(57.6)	(82.4)
Deferred income	14	(6.0)	(6.8)
		(63.6)	(89.2)
Total liabilities		(361.2)	(415.7)
Net assets		433.9	527.8
Owners of the parent
Share capital	18	43.8	43.8
Share premium		3,863.9	3,897.4
Accumulated losses		(3,473.8)	(3,413.4)
Total equity		433.9	527.8

 

 

 

Consolidated statement of changes in equity

For the year ended 31 December 2023

 

 

	Note	Share capital $m	Share premium $m	Accumulated losses $m	Total equity $m
At 1 January 2022		43.8	3,947.5	(3,410.2)	581.1
Loss and total comprehensive expense		-	-	(7.3)	(7.3)
Contributions by and distributions to owners
Share-based payments	21	-	-	4.1	4.1
Dividends provided for or paid1	19	-	(50.1)	-	(50.1)
At 31 December 2022 and 1 January 2023		43.8	3,897.4	(3,413.4)	527.8
Loss and total comprehensive expense		-	-	(61.3)	(61.3)
Contributions by and distributions to owners
Share-based payments	21	-	-	2.7	2.7
Purchase of own shares for employee share plan		-	-	(1.8)	(1.8)
Dividends provided for or paid1	19	-	(33.5)	-	(33.5)
At 31 December 2023		43.8	3,863.9	(3,473.8)	433.9

 

 

1 The Companies (Jersey) Law 1991 does not define the expression “dividend” but refers instead to “distributions”. Distributions may be debited to any account or reserve of the Company (including share premium account)

 

 

 

 

Consolidated cash flow statement

For the year ended 31 December 2023

 

	Note	2023	2022
		$m	$m
Cash flows from operating activities
Loss for the year		(61.3)	(7.3)
Adjustments for:
Net finance expense	5,7	9.4	25.4
Taxation	6	0.2	0.2
Depreciation and amortisation	3,7	46.7	152.0
Exploration expense	3	0.1	1.0
Net impairments, write-offs	3,7	28.1	193.1
Other non-cash items (royalty income and share-based payment cost)		0.8	(7.4)
Changes in working capital:
Decrease in trade and other receivables		14.4	47.2
(Decrease) / Increase in trade and other payables		(3.7)	1.7
Cash generated from operations		34.7	405.9
Interest received	5	20.6	6.7
Taxation paid		(0.2)	(0.2)
Net cash generated from operating activities		55.1	412.4
Cash flows from investing activities
Payments of intangible assets		(9.7)	(20.0)
Payments of property, plant and equipment		(88.8)	(128.2)
Net cash used in investing activities		(98.5)	(148.2)
Cash flows from financing activities
Dividends paid to company’s shareholders	19	(33.5)	(47.9)
Purchase of own shares		(1.8)	-
Bond repayment	16	(24.9)	(6.0)
Lease payments		(2.8)	(3.8)
Interest paid		(24.8)	(25.6)
Net cash used in financing activities		(87.8)	(83.3)
Net (decrease) / increase in cash and cash equivalents		(131.2)	180.9
Cash and cash equivalents at 1 January	12	494.6	313.7
Cash and cash equivalents at 31 December	12	363.4	494.6

 

 

Notes to the consolidated financial statements

 

1. Summary of material accounting policies

 

1.     Basis of preparation

Genel Energy Plc – registration number: 107897 (the Company), is a public limited company incorporated and domiciled in Jersey with a listing on the London Stock Exchange. The address of its registered office is 26 New Street, St Helier, Jersey, JE2 3RA.

 

The consolidated financial statements of the Company have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union and interpretations issued by the IFRS Interpretations Committee (together ’IFRS’); are prepared under the historical cost convention except as where stated; and comply with Company (Jersey) Law 1991. The significant accounting policies are set out below and have been applied consistently throughout the period.

 

The Company prepares its financial statements on a historical cost basis, unless accounting standards require an alternate measurement basis. Where there are assets and liabilities calculated on a different basis, this fact is disclosed either in the relevant accounting policy or in the notes to the financial statements.

 

Items included in the financial information of each of the Company's entities are measured using the currency of the primary economic environment in which the entity operates (the functional currency). The consolidated financial statements are presented in US dollars to the nearest million ($ million) rounded to one decimal place, except where otherwise indicated.

 

For explanation of the key judgements and estimates made by the Company in applying the Company’s accounting policies, refer to significant accounting judgements and estimates on pages 17 to 19.

 

Going concern

The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combinations of oil price, discount rates, production volumes, payments, capital and operational spend scenarios.

 

The Company has reported cash of $363 million, with its debt of $248 million maturing in the second half of 2025 and significant headroom on both the equity ratio and minimum liquidity financial covenants.

 

The Federal Iraq Supreme Court majority decision in February 2022 regarding the Kurdistan Oil and Gas Law (2007) and the subsequent actions taken by the Federal Minister of Oil in Baghdad Commercial Court did not have a significant impact on the Company’s cash generation. However, since then, the International Chamber of Commerce in Paris ruling in favour of Iraq in the long running arbitration case against Türkiye concerning the Iraqi-Turkish pipeline agreement signed in 1973, resulted in exports through the pipeline being suspended from 25 March 2023.

 

The Company is currently selling in the domestic market at lower prices and lower volumes than are available from exports, with significantly reduced cash generation.

 

The Company forecasts that, even with continued suspension of exports, it will have a significant net cash balance for the foreseeable future.

 

As a result, the Directors have assessed that the Company’s forecast liquidity provides adequate headroom over its forecast expenditure for the 12 months following the signing of the annual report for the period ended 31 December 2023 and consequently that the Company is considered a going concern.

 

Consolidation

The consolidated financial statements consolidate the Company and its subsidiaries. These accounting policies have been adopted by all companies.

 

Subsidiaries

Subsidiaries are all entities over which the Company has control. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are deconsolidated from the date that control ceases. Transactions, balances and unrealised gains on transactions between companies are eliminated.

 

Joint arrangements and associates

Arrangements under which the Company has contractually agreed to share control with another party, or parties, are joint ventures where the parties have rights to the net assets of the arrangement, or joint operations where the parties have rights to the assets and obligations for the liabilities relating to the arrangement. Investments in entities over which the Company has the right to exercise significant influence but has neither control nor joint control are classified as associates and accounted for under the equity method.

 

The Company recognises its assets, liabilities, income and expenses relating to its interests in joint operations, including its share of assets and income held jointly and liabilities and expenses incurred jointly with other partners.

 

Farm-in/farm-out

Farm-in/farm-out transactions undertaken in the exploration phase of an oil and gas asset are accounted for on a no gain/no loss basis due to inherent uncertainties in the exploration phase and associated difficulties in determining fair values reliably prior to the determination of commercially recoverable proved reserves. The resulting exploration and evaluation asset is then assessed for impairment indicators under IFRS 6. Any cash payment or proceeds are presented as an increase or reduction to additions respectively.

 

2.     Significant accounting judgements and estimates

The preparation of the financial statements in accordance with IFRS requires the Company to make judgements and estimates that affect the reported results, assets and liabilities. Where judgements and estimates are made, there is a risk that the actual outcome could differ from the judgement or estimate made.

 

Significant judgements

The following are the significant judgements that the directors have made in the process of applying the Group and Company’s accounting policies and that have the most significant effect on the amounts recognised in the financial statements.

 

Sarta PSC (note 10 and 7)

At 31 December 2022, the Company’s assessment on the recoverable value of the Sarta PSC had resulted with an impairment expense of $125.5 million following the disappointing results of the two appraisal wells and pilot production.

 

In 2023, the Company has informed the KRG of its intention to exit the Sarta licence and the remaining recoverable value of the Sarta PSC have been reduced to nil and a write-off expense of $18.7 million has been booked. Following the termination of the PSC on 1 December 2023, decommissioning provisions have been derecognised.

 

Significant estimates

The following are the critical estimates that the directors have made in the process of applying the Group and Company’s accounting policies and that have the most significant effect on the amounts recognised in the financial statements.

 

Estimation of hydrocarbon reserves and resources and associated production profiles and costs

Estimates of hydrocarbon reserves and resources are inherently imprecise and are subject to future revision. The Company’s estimation of the quantum of oil and gas reserves and resources and the timing of its production, cost and monetisation impact the Company’s financial statements in a number of ways, including: testing recoverable values for impairment; the calculation of depreciation, amortisation and assessing the cost and likely timing of decommissioning activity and associated costs. This estimation also impacts the assessment of going concern and the viability statement.

 

Proved and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company’s assets. The Company estimates its reserves using standard recognised evaluation techniques which are based on Petroleum Resources Management System 2018. Assets assessed as having proven and probable reserves are generally classified as property, plant and equipment as development or producing assets and depreciated using the units of production methodology. The Company considers its best estimate for future production and quantity of oil within an asset based on a combination of internal and external evaluations and uses this as the basis of calculating depreciation and amortisation of oil and gas assets and testing for impairment under IAS 36.

 

Hydrocarbons that are not assessed as reserves are considered to be resources and the related assets are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted and are likely to contain estimates and judgements with a wide range of possibilities. These assets are considered for impairment under IFRS 6.

 

Once a field commences production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions.

 

Assessment of reserves and resources are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves.

 

Where the Company has updated its estimated reserves and resources any required disclosure of the impact on the financial statements is provided in the following sections.

 

Estimation of oil and gas asset values (note 9 and 10)

Estimation of the asset value of oil and gas assets is calculated from a number of inputs that require varying degrees of estimation. Principally oil and gas assets are valued by estimating the future cash flows based on a combination of reserves and resources, costs of appraisal, development and production, production profile, climate-related risks, pipeline reopening and future sales price and discounting those cash flows at an appropriate discount rate.

 

Future costs of appraisal, development and production are estimated taking into account the level of development required to produce those reserves and are based on past costs, experience and data from similar assets in the region, future petroleum prices and the planned development of the asset. However, actual costs may be different from those estimated.

 

Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. A post tax nominal discount rate of 14% (2022: 14%) derived from the Company’s weighted average cost of capital (WACC) is used when assessing the impairment testing of the Company’s oil assets at year-end. Risking factors are also used alongside the discount rate when the Company is assessing exploration and appraisal assets.

 

Estimation of future oil price and netback price

The estimation of future oil price has a significant impact throughout the financial statements, primarily in relation to the estimation of the recoverable value of property, plant and equipment and intangible assets. It is also relevant to the assessment of ECL, going concern and the viability statement.

 

The Company’s estimate of average Brent oil price for future years is based on a range of publicly available market estimates and is summarised in the table below.

 

$/bbl	2023	2024	2025	2026	2027	2028
Actual / Estimate	82	80	76	74	71	70
HY2023 estimate	82	78	74	70	70	70
Prior year estimate	82	78	74	70	70	70

 

The netback price is used to value the Company’s revenue, trade receivables and its forecast cash flows used for impairment testing and viability. It is the aggregation of reference oil price average less transportation costs, handling costs and quality adjustments.

 

Effective from 1 September 2022, sales have been priced by the MNR under a new pricing formula based on the realised sales price for Kurdistan blend crude (‘KBT’) during the delivery month, rather than on dated Brent. The Company has not agreed on this new pricing formula and continued to invoice on Brent. The Company does not have direct visibility on the components of the netback price realised for its oil because sales are managed by the KRG, but the latest payments were based on the netback price provided by the KRG. Therefore, the export revenue from 1 September 2022 was recognised in accordance with IFRS15 using KBT pricing, resulting in the recognition of $13 million less of revenue.

 

The export pipeline closure in March 2023 has resulted in volumes sold in the local market starting in June 2023 on a cash and carry basis at lower realised oil prices than previously achieved through export.

 

A sensitivity analysis of netback price on producing asset values has been provided in note 10.

 

The Company has also taken the change into account in its assessment of impairment reversal and considered it appropriate not to reverse any previous impairments.

 

Estimation of the recoverable value of deferred receivables and trade receivables (note 11)

As of 31 December 2023, the Company is owed six months of payments. Management has compared the carrying value of trade receivables with the present value of the estimated future cash flows based on the prevailing discount rate at the time sales made (14%) and a number of collection scenarios. The ECL is the weighted average of these scenarios and is recognised in the income statement. The weighting is applied based on expected repayment timing by considering the recovery of previous deferred receivables. The result of this assessment is an ECL provision of $14.5 million. Each 1% increase in discount rate would increase the ECL by $0.9 million. Sensitivity of the calculation to different scenarios has been provided in note 11.

 

Other estimates

The following are the other estimates that the directors have made in the process of applying the Group and Company’s accounting policies and that have effect on the amounts recognised in the financial statements.

 

Decommissioning provision (note 15)

Decommissioning provisions are calculated from a number of inputs such as costs to be incurred in removing production facilities and site restoration at the end of the producing life of each field which is considered as the mid-point of a range of cost estimation. These inputs are based on the Company’s best estimate of the expenditure required to settle the present obligation at the end of the period inflated at 2% (2022: 2%) and discounted at 4% (2022: 4%). 10% increase in cost estimates would increase the existing provision by c.$4 million and 1% increase in discount rate would decrease the existing provision by c.$3 million, the combined impact would be c.$1 million. The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2028 and 2036.

 

Taxation

Under the terms of KRI PSC's, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. It is not known at what rate tax is paid, but it is estimated that the current tax rate would be between 15% and 40%. If this was known it would result in a gross up of revenue with a corresponding debit entry to taxation expense with no net impact on the income statement or on cash. In addition, it would be necessary to assess whether any deferred tax asset or liability was required to be recognised.

 

3.     Accounting policies

The accounting policies adopted in preparation of these financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2022, adjusted for transitional requirements where necessary, further explained under revenue and changes in accounting policies headings.

 

Revenue

Revenue from contracts with customers is earned based on the entitlement mechanism under the terms of the relevant PSC and, overriding royalty income (‘ORRI’), which was earned on 4.5% of gross field revenue from the Tawke licence up until July 2022.

 

Under IFRS 15, entitlement revenue and ORRI is recognised when the control of the product is deemed to have passed to the customer, in exchange for the consideration amount determined by the terms of the contract. For exports the control passes to the customer when the oil enters the export pipe. For local sales, the control passes to the customer when the oil is delivered to the trucks.

 

Entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred on an asset, and profit oil, which is the mechanism through which profits are shared between the Company, its partners and the KRG. The Company pays capacity building payments on profit oil entitlement earned on the Sarta and Taq Taq licences, which become due for payment once the Company has received the relevant proceeds. Profit oil revenue is always reported net of any capacity building payments that will become due.

 

The Company’s export oil sales made to the KRG are valued at a netback price which is explained further in significant accounting estimates and judgements. The Company’s local sales are valued at the price agreed with the local buyers.

 

The Company is not able to measure the tax that has been paid on its behalf and consequently has not been able to assess where revenue should be reported gross of implied income tax paid.

 

The Company’s revenue from other sources includes a non-cash royalty income which is recognised in the statement of comprehensive income in a manner consistent with entitlement mechanism.

 

Intangible assets

Exploration and evaluation assets

Oil and gas assets classified as exploration and evaluation assets are explained under Oil and Gas assets below.

 

Tawke RSA

Intangible assets include the Receivable Settlement Agreement (‘RSA’) effective from 1 August 2017, which was entered into in exchange for trade receivables due from KRG for Taq Taq and Tawke past sales. The RSA was recognised at cost and is amortised on a units of production basis in line with the economic lives of the rights acquired.

 

Property, plant and equipment

Producing and Development assets

Oil and gas assets classified as producing and development assets are explained under Oil and Gas assets below.

 

Oil and gas assets

Costs incurred prior to obtaining legal rights to explore are expensed to the statement of comprehensive income.

Exploration, appraisal and development expenditure is accounted for under the successful efforts method. Under the successful efforts method only costs that relate directly to the discovery and development of specific oil and gas reserves are capitalised as exploration and evaluation assets within intangible assets so long as the activity is assessed to be de-risking the asset and the Company expects continued activity on the asset into the foreseeable future. Costs of activity that do not identify oil and gas reserves are expensed.

 

All licence acquisition costs, geological and geophysical costs, inventories and other direct costs of exploration, evaluation and development are capitalised as intangible assets or property, plant and equipment according to their nature. Intangible assets comprise costs relating to the exploration and evaluation of properties which the directors consider to be unevaluated until assessed as being 2P reserves and commercially viable.

 

Once assessed as being 2P reserves they are tested for impairment and transferred to property, plant and equipment as development assets. Where properties are appraised to have no commercial value, the associated costs are expensed as an impairment loss in the period in which the determination is made. Development assets are classified under producing assets following the commercial production commencement. 

 

Development expenditure is accounted for in accordance with IAS 16 – Property, plant and equipment. Producing assets are depreciated once they are available for use and are depleted on a field-by-field basis using the unit of production method. The sum of carrying value and the estimated future development costs are divided by total barrels to provide a $/barrel unit depreciation cost. Changes to depreciation rates as a result of changes in forecast production and estimates of future development expenditure are reflected prospectively.

 

The estimated useful lives of property, plant and equipment and their residual values are reviewed on an annual basis and changes in useful lives are accounted for prospectively. The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in the statement of comprehensive income for the relevant period.

 

Where exploration licences are relinquished or exited for no consideration or costs incurred are neither de-risking nor adding value to the asset, the associated costs are expensed to the income statement.

 

Impairment testing of oil and gas assets is considered in the context of each cash generating unit. A cash generating unit is generally a licence, with the discounted value of the future cash flows of the CGU compared to the book value of the relevant assets and liabilities.

 

Subsequent costs

The cost of replacing part of an item of property and equipment is recognised in the carrying amount of the item if it is probable that the future economic benefits embodied within the part will flow to the Company, and its cost can be measured reliably. The net book value of the replaced part is expensed. The costs of the day-to-day servicing and maintenance of property, plant and equipment are recognised in the statement of comprehensive income.

 

Discontinued operations

A part of the Company’s operations is classified as a discontinued operation if the component has either been disposed of or is classified as held for sale and represents a separate major line of business or geographic area of operations, is part of a single coordinated plan to dispose of a separate major line of business or geographic area of operations, or is a subsidiary acquired exclusively with a view to resale. Discontinued operations are excluded from the net income/loss from continuing operations and are presented as a single amount as gain/loss from discontinued operations, in the consolidated statement of comprehensive income. When an operation is classified as a discontinued operation, the comparative consolidated statement of comprehensive income is restated and presented as if the operation had been classified as such from the start of the comparative year.

 

Right of use (RoU) assets / Lease liabilities

The Company recognises a right to use asset and lease liability, depreciate the associated asset, re-measure and reduce the liability through lease payments unless the underlying leased asset is of low value and/or short term in nature. The Company uses the following judgements permitted by the standard: applying a single discount rate to a portfolio of leases with reasonably similar characteristics, exemption from recognition of right of use assets with a lease term of less than 12 months at the inception and using hindsight in determining the lease term where the contract contains options to extend or terminate the lease. Right-of-use assets are depreciated over the lifetime of the related lease contract. Lease liabilities were measured at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate and included within trade and other payables.

 

Drill rig contracts are service contracts where contractors provide the rig together with the services and the contracted personnel on a day-rate basis for the purpose of drilling exploration or development wells. The Company has no right of use of the rigs. The aggregate payments under drilling contracts are determined by the number of days required to drill each well and are capitalised as exploration or development assets as appropriate.

 

Financial assets and liabilities

Classification

The Company assesses the classification of its financial assets on initial recognition at amortised cost, fair value through other comprehensive income or fair value through profit and loss. The Company assesses the classification of its financial liabilities on initial recognition at either fair value through profit and loss or amortised cost.

 

Recognition and measurement

Regular purchases and sales of financial assets are recognised at fair value on the trade-date – the date on which the Company commits to purchase or sell the asset. Trade and other receivables, trade and other payables, borrowings and deferred contingent consideration are subsequently carried at amortised cost using the effective interest method.

 

Trade and other receivables

Trade receivables are amounts due from crude oil sales, sales of gas or services performed in the ordinary course of business. If payment is expected within one year or less, trade receivables are classified as current assets otherwise they are presented as non-current assets. Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for expected credit loss.

 

The Company’s assessment of expected credit loss model is explained below under financial assets.

 

Cash and cash equivalents

In the consolidated balance sheet and consolidated statement of cash flows, cash and cash equivalents includes cash in hand, deposits held on call with banks, other short-term highly liquid investments which are assessed as cash and cash equivalents under IAS 7 and includes the Company’s share of cash held in joint operations.

 

Interest-bearing borrowings

Borrowings are recognised initially at fair value, net of any discount in issuance and transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the statement of comprehensive income over the period of the borrowings using the effective interest method.

 

Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan.

 

Borrowings are presented as long or short-term based on the maturity of the respective borrowings in accordance with the loan or other agreement. Borrowings with maturities of less than twelve months are classified as short-term. Amounts are classified as long-term where maturity is greater than twelve months. Where no objective evidence of maturity exists, related amounts are classified as short-term.

 

Trade and other payables

Trade and other payables are recognised initially at fair value. Subsequent to initial recognition they are measured at amortised cost using the effective interest method.

 

Offsetting

Financial assets and liabilities are offset and the net amount reported in the balance sheet when there is a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously.

 

Provisions

Provisions are recognised when the Company has a present obligation as a result of a past event, and it is probable that the Company will be required to settle that obligation. Provisions are measured at the Company’s best estimate of the expenditure required to settle the obligation at the balance sheet date and are discounted to present value where the effect is material. The unwinding of any discount is recognised as finance costs in the statement of comprehensive income.

 

Decommissioning

Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field. A corresponding cost is capitalised to property, plant and equipment and subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision and capitalised as part of the cost of the assets.

 

Impairment

Exploration and evaluation assets

Spend on exploration and evaluation assets is capitalised in accordance with IFRS 6. The carrying amounts of the Company’s exploration and evaluation assets are reviewed at each reporting date to determine whether there is any indication of impairment under IFRS 6. Impairment assessment of exploration and evaluation assets is considered in the context of each cash generating unit, which is generally represented by relevant the licence.

 

Producing and Development assets

The carrying amounts of the Company’s producing and development assets are reviewed at each reporting date to determine whether there is any indication of impairment or reversal of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. The recoverable amount of an asset or cash generating unit is the greater of its value in use and its fair value less costs of disposal. For value in use, the estimated future cash flows arising from the Company’s future plans for the asset are discounted to their present value using a nominal post tax discount rate that reflects market assessments of the time value of money and the risks specific to the asset. For fair value less costs of disposal, an estimation is made of the fair value of consideration that would be received to sell an asset less associated selling costs (which are assumed to be immaterial). Assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (cash generating unit).

 

The estimated recoverable amount is then compared to the carrying value of the asset. Where the estimated recoverable amount is materially lower than the carrying value of the asset an impairment loss is recognised. Non-financial assets that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.

 

Property, plant and equipment and intangible assets

Impairment testing of oil and gas assets is explained above. When impairment indicators exist for other non-financial assets, impairment testing is performed based on the higher of value in use and fair value less costs of disposal. The Company assets' recoverable amount is determined by fair value less costs of disposal.

 

Financial assets

Impairment of financial assets is assessed under IFRS 9 with a forward-looking expected credit loss (‘ECL’) model. The standard requires the Company to book an allowance for ECL for its financial assets. The Company has assessed its trade receivables as at 31 December 2023 for ECL. Further explanation is provided in significant accounting judgements and estimates.

 

Equity

Share capital

Amounts subscribed for share capital at nominal value. Ordinary shares are classified as equity.

 

When share capital recognised as equity is repurchased, the amount of the consideration paid, which includes directly attributable costs, is net of any tax effects and is recognised as a deduction in equity. Repurchased shares are classified as treasury shares and are presented as a deduction from total equity. When treasury shares are subsequently sold or reissued, the amount received is recognised as an increase in equity and the resulting surplus or deficit of the transaction is transferred to/from retained earnings.

 

Share premium

Amounts subscribed for share capital in excess of nominal value.

 

Accumulated loss

Cumulative net losses recognised in the statement of comprehensive income net of amounts recognised directly in equity.

 

Dividend

Liability to pay a dividend is recognised based on the declared timetable. A corresponding amount is recognised directly in equity.

 

Employee benefits

Short-term benefits

Short-term employee benefit obligations are expensed to the statement of comprehensive income as the related service is provided. A liability is recognised for the amount expected to be paid under short-term cash bonus or profit-sharing plans if the Company has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee and the obligation can be estimated reliably.

 

Share-based payments

The Company operates equity-settled share-based compensation plans. The expense required in accordance with IFRS 2 is recognised in the statement of comprehensive income over the vesting period of the award and partially capitalised as oil and gas assets in line with the hours incurred by the employees. The expense is determined by reference to option pricing models, principally Monte Carlo and adjusted Black-Scholes models.

 

At each balance sheet date, the Company revises its estimate of the number of options that are expected to become exercisable. Any revision to the original estimates is reflected in the statement of comprehensive income with a corresponding adjustment to equity immediately to the extent it relates to past service and the remainder over the rest of the vesting period.

 

Finance income and finance costs

Finance income comprises interest income on cash invested, foreign currency gains and the unwind of discount on any assets held at amortised cost. Interest income is recognised as it accrues, using the effective interest method.

 

Finance expense comprises interest expense on borrowings, foreign currency losses and discount unwind on any liabilities held at amortised cost. Borrowing costs directly attributable to the acquisition of a qualifying asset as part of the cost of that asset are capitalised over the respective assets.

 

Taxation

Under the terms of the KRI PSCs, the Company is not required to pay any cash corporate income taxes as explained in significant accounting judgements and estimates. Current tax expense is incurred on profits of service companies.

 

Segmental reporting

IFRS 8 requires the Company to disclose information about its business segments and the geographic areas in which it operates. It requires identification of business segments on the basis of internal reports that are regularly reviewed by the CEO, the chief operating decision maker, in order to allocate resources to the segment and assess its performance.

 

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the party in making financial or operational decisions. Parties are also related if they are subject to common control. Transactions between related parties are transfers of resources, services or obligations, regardless of whether a price is charged and are disclosed separately within the notes to the consolidated financial information.

 

New standards

The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2023. Amendments to IAS 12 Income taxes: International Tax Reform – Pillar Two Model Rules (issued on 23 May 2023), Amendments to IFRS 17 Insurance contracts: Initial Application of IFRS 17 and IFRS 9 – Comparative Information (issued on 9 December 2021), Amendments to IAS 12 Income Taxes: Deferred Tax related to Assets and Liabilities arising from a Single Transaction (issued on 7 May 2021), Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice Statement 2: Disclosure of Accounting policies (issued on 12 February 2021), Amendments to IAS 8 Accounting policies, Changes in Accounting Estimates and Errors: Definition of Accounting Estimates (issued on 12 February 2021), IFRS 17 Insurance Contracts (issued on 18 May 2017). These standards did not have a material impact on the Company’s results or financial statements disclosures in the current reporting period except Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice Statement 2: Disclosure of Accounting policies (issued on 12 February 2021). The Company has adopted the amendments to IAS 1 for the first time in the current year as to disclose material accounting policies.

 

The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and/or have not yet been endorsed by the EU: Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability (issued on 15 August 2023), Amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures: Supplier Finance Arrangements (issued on 25 May 2023), Amendments to IAS 1 Presentation of Financial Statements: Classification of Liabilities as Current or Noncurrent (issued on 23 January 2020); Classification of Liabilities as Current or Noncurrent - Deferral of Effective Date (issued on 15 July 2020); and Non-current Liabilities with Covenants (issued on 31 October 2022), Amendments to IFRS 16 Leases: Lease Liability in a Sale and Leaseback (issued on 22 September 2022). Nothing has been early adopted, and these standards are not expected to have a material impact on the Company’s results or financials statement disclosures in the periods they become effective.

 

2. Segmental information

 

The Company has two reportable business segments: Production and Pre-production. Capital allocation decisions for the production segment are considered in the context of the cash flows expected from the production and sale of crude oil. The production segment is comprised of the producing fields on the Tawke PSC (Tawke and Peshkabir fields) and the Taq Taq PSC which are located in the KRI and make export sales to the KRG and local sales to the local buyers. The pre-production segment is comprised of exploration activity, principally located in Somaliland and Morocco. ‘Other’ includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

 

 

For the year ended 31 December 2023

	Production	Pre-production	Other	Total
	$m	$m	$m	$m
Revenue from contracts with customers (export)	45.8	-	-	45.8
Revenue from contracts with customers (local)	38.2	-	-	38.2
Revenue from other sources	0.8	-	-	0.8
Cost of sales	(65.2)	-	-	(65.2)
Gross profit	19.6	-	-	19.6
Exploration expense	-	(0.1)	-	(0.1)
Other operating costs	(3.6)	-	-	(3.6)
Reversal of decommissioning provision	1.2	-	-	1.2
Reversal of ECL of trade receivables	4.2	-	-	4.2
ECL of trade receivables	(13.3)	-	-	(13.3)
General and administrative costs	-	-	(27.2)	(27.2)
Operating profit / (loss)	8.1	(0.1)	(27.2)	(19.2)
Operating profit / (loss) is comprised of
EBITDAX	59.9	-	(27.1)	32.8
Depreciation and amortisation	(43.9)	-	(0.1)	(44.0)
Exploration expense	-	(0.1)	-	(0.1)
Reversal of decommissioning provision	1.2	-	-	1.2
Reversal of ECL of receivables	4.2	-	-	4.2
ECL of receivables	(13.3)	-	-	(13.3)
Finance income	-	-	20.6	20.6
Bond interest expense	-	-	(24.8)	(24.8)
Net other finance expense	(3.2)	(0.1)	(1.6)	(4.9)
Profit / (Loss) before income tax from continuing operations	4.9	(0.2)	(33.0)	(28.3)
Loss from discontinued operations	(32.8)	-	-	(32.8)
Profit / (Loss) before income tax	(27.9)	(0.2)	(33.0)	(61.1)
Capital expenditure	58.9	9.1	-	68.0
Total assets	412.1	26.8	356.2	795.1
Total liabilities	(91.0)	(12.0)	(258.2)	(361.2)

Sarta PSC figures have been disclosed as discontinued operation following the PSC termination in the year (see note 7).

 

Total assets and liabilities in the other segment are predominantly cash and debt balances.

 

 

 

 

 

For the year ended 31 December 2022

	Production	Pre-production	Other	Total
	$m	$m	$m	$m
Revenue from contracts with customers	388.7	-	-	388.7
Revenue from other sources	13.2	-	-	13.2
Cost of sales	(168.5)	-	-	(168.5)
Gross profit	233.4	-	-	233.4
Exploration expense	-	(1.0)	-	(1.0)
Net write-off of intangible asset	-	(75.8)	-	(75.8)
Reversal of ECL of receivables	10.8	-	2.0	12.8
ECL of receivables	(4.2)	-	-	(4.2)
General and administrative costs	-	-	(18.6)	(18.6)
Operating profit / (loss)	240.0	(76.8)	(16.6)	146.6
Operating profit / (loss) is comprised of
EBITDAX	367.6	-	(18.5)	349.1
Depreciation and amortisation	(134.2)	-	(0.1)	(134.3)
Exploration expense	-	(1.0)	-	(1.0)
Net write-off of intangible assets	-	(75.8)	-	(75.8)
Reversal of ECL of receivables	10.8	-	2.0	12.8
ECL of receivables	(4.2)	-	-	(4.2)
Finance income	-	-	6.7	6.7
Bond interest expense	-	-	(25.9)	(25.9)
Other finance expense	(2.4)	(0.4)	(2.5)	(5.3)
Profit / (Loss) before income tax from continuing operations	237.6	(77.2)	(38.3)	122.1
Loss from discontinued operations	(129.2)	-	-	(129.2)
Profit / (Loss) before income tax	108.4	(77.2)	(38.3)	(7.1)
Capital expenditure	133.4	9.7	-	143.1
Total assets	447.3	23.5	472.7	943.5
Total liabilities	(111.9)	(17.7)	(286.1)	(415.7)

Revenue from contracts with customers includes $94.5 million arising from the ORRI and $34.7 million in relation to the suspended ORRI.

 

Total assets and liabilities in the other segment are predominantly cash and debt balances.

3. Operating (loss) / profit

	2023	2022
	$m	$m
Production costs	(21.3)	(34.3)
Depreciation of oil and gas property, plant and equipment (excl. RoU assets)	(39.6)	(95.0)
Amortisation of oil and gas intangible assets	(4.3)	(39.2)
Cost of sales	(65.2)	(168.5)
Exploration expense	(0.1)	(1.0)
Other operating costs1	(3.6)	-
1 Other operating costs relate to Taq Taq costs which were incurred after production ceased in May 2023, following the pipeline closure.
Write-off of intangible assets (note 9)	-	(78.0)
Net reversal of accruals and provisions	1.2	2.2
Net write-off of intangible assets	1.2	(75.8)
Reversal of ECL of other receivables	-	2.0
Reversal of ECL of trade receivables (note 1,11)	4.2	10.8
ECL of trade receivables (note 1,11)	(13.3)	(4.2)
Net (ECL) / reversal of ECL of receivables	(9.1)	8.6
Corporate cash costs	(12.4)	(14.0)
Non-recurring costs	(13.1)	(3.7)
Corporate share-based payment expense	(1.6)	(0.8)
Depreciation and amortisation of corporate assets (excl. RoU assets)	(0.1)	(0.1)
General and administrative expenses	(27.2)	(18.6)
Auditor’s remuneration:       Audit of the Group’s consolidated financial statements (0.3) (0.3)   Audit of the Group’s subsidiaries pursuant to legislation (0.1) (0.1)   Total audit services (0.4) (0.4)   Interim review (0.1) (0.1)   Total audit related and non-audit services (0.5) (0.5)                 All fees paid to the auditor were charged to operating loss in both years.     4. Staff costs and headcount   2023 2022   $m $m Wages and salaries (19.3) (21.1) Contractors costs (13.8) (20.6) Social security costs (1.9) (4.3) Share based payments (3.7) (4.1)   (38.7) (50.1)
Average headcount was:	2023 number	2022 number
Türkiye	38	39
KRI	23	38
UK	30	34
Somaliland	27	18
Contractors	84	129
	202	258

 

 

 

5. Finance expense and income 

	2023	2022
	$m	$m
Bond interest	(24.8)	(25.9)
Other finance expense (non-cash)	(6.0)	(5.3)
Finance expense	(30.8)	(31.2)
Bank interest income	20.6	6.7
Gain on bond buyback	1.1	-
Finance income	21.7	6.7
Net finance expense	(9.1)	(24.5)

 

Bond interest payable is the cash interest cost of the Company’s bond debt. Other finance expense (non-cash) primarily relates to the discount unwind on the bond and the asset retirement obligation provision.

 

 

6. Income tax expense

 

Current tax expense is incurred on profits of service companies. Under the terms of the KRI PSCs, the Company is not required to pay any cash corporate income taxes as explained in note 1.

 

 

7. Discontinued operations

 

Sarta PSC was terminated on 1 December 2023. The results of the discontinued operations, which have been included in the loss for the year, were as follows:

 

	2023	2022
	$m	$m
Revenue	3.6	30.8
Production costs	(3.6)	(16.8)
Depreciation of oil and gas property, plant and equipment	(0.7)	(14.9)
Gross loss	(0.7)	(0.9)
Other operating costs1	(20.0)	-
Write-off / impairment of property, plant and equipment (note 1,10)	(18.7)	(125.5)
Reversal of provisions	8.2	-
Reversal of ECL of trade receivables	0.4	-
ECL of trade receivables	(1.2)	(0.4)
General and administrative costs	(0.5)	(1.5)
Operating loss	(32.5)	(128.3)
Other finance expense (non-cash)	(0.3)	(0.9)
Loss from discontinued operations	(32.8)	(129.2)

 

1 Other operating costs relate to costs incurred after production ceased in March 2023, following the pipeline closure and costs incurred in relation to exiting the PSC.

 

 

	2023	2022
Cash flows from discontinued operations	$m	$m
Net cash (used in) / generated from operating activities	(27.8)	18.5
Net cash used in investing activities	(3.8)	(53.7)
Net cash used in financing activities	(2.1)	(2.9)

 

 

 

 

 

 

8. (Loss) / Earnings per share

 

Basic

Basic loss per share is calculated by dividing the loss attributable to owners of the parent by the weighted average number of shares in issue during the year.

 

	2023	2022
(Loss) / Profit from continuing operations ($m)	(28.5)	121.9
Loss from discontinued operations ($m)	(32.8)	(129.2)
Loss attributable to owners of the parent ($m)	(61.3)	(7.3)
Weighted average number of ordinary shares – number 1	278,836,216	278,654,909
Basic (loss) / earnings per share – cents per share (from continuing operations)	(10.2)	43.7
Basic loss per share – cents per share	(22.0)	(2.6)

1 Excluding shares held as treasury shares

 

 

Diluted

The Company purchases shares in the market to satisfy share plan requirements so diluted earnings per share is adjusted for performance shares, restricted shares, share options and deferred bonus plans not included in the calculation of basic earnings per share. Because the Company reported a loss for the year ended 31 December 2023 and 31 December 2022, the performance shares, restricted shares and share options are anti-dilutive and therefore diluted LPS is the same as basic LPS:

 

	2023	2022
(Loss) / Profit from continuing operations ($m)	(28.5)	121.9
Loss from discontinued operations ($m)	(32.8)	(129.2)
Loss attributable to owners of the parent ($m)	(61.3)	(7.3)
Weighted average number of ordinary shares – number1	278,836,216	278,654,909
Adjustment for performance shares, restricted shares, share options and deferred bonus plans	-	-
Weighted average number of ordinary shares and potential ordinary shares	278,836,216	278,654,909
Basic (loss) / earnings per share – cents per share (from continuing operations)	(10.2)	43.7
Diluted loss per share – cents per share	(22.0)	(2.6)

1 Excluding shares held as treasury shares 

 

Basic (LPS) / EPS excluding impairments

Basic (LPS) / EPS excluding impairment is loss and total comprehensive expense adjusted for the add back of net impairment/write-off of oil and gas assets and net ECL/reversal of ECL of receivables divided by weighted average number of ordinary shares.

 

		2023	2022
Loss attributable to owners of the parent ($m)	(61.3)		(7.3)
Add back of net impairment/write-off of oil and gas assets	18.2		201.3
Add back of net ECL/reversal of ECL of receivables	9.9		(8.2)
(Loss) / profit attributable to owners of the parent ($m) - adjusted	(33.2)		185.8
Weighted average number of ordinary shares – number 1	278,836,216		278,654,909
Basic (loss) / earnings per share excluding impairments – cents per share	(11.9)		66.7

1 Excluding shares held as treasury shares 

 

 

9. Intangible assets

	Exploration and evaluation assets	Tawke RSA	Other assets	Total
	$m	$m	$m	$m
Cost
At 1 January 2022	81.4	425.1	7.5	514.0
Additions	9.7	-	-	9.7
Write-off in the year (note 1)	(78.0)	-	-	(78.0)
Other	(0.2)	-	-	(0.2)
At 31 December 2022 and 1 January 2023	12.9	425.1	7.5	445.5
Additions	9.1	-	-	9.1
Other	0.8	-	-	0.8
At 31 December 2023	22.8	425.1	7.5	455.4
Accumulated amortisation and impairment
At 1 January 2022	-	(319.7)	(7.5)	(327.2)
Amortisation charge for the period	-	(39.2)	-	(39.2)
At 31 December 2022 and 1 January 2023	-	(358.9)	(7.5)	(366.4)
Amortisation charge for the year	-	(4.3)	-	(4.3)
At 31 December 2023	-	(363.2)	(7.5)	(370.7)
Net book value
At 1 January 2022	81.4	105.4	-	186.8
At 31 December 2022	12.9	66.2	-	79.1
At 31 December 2023	22.8	61.9	-	84.7

 

 

		2023	2022
Book value		$m	$m
Somaliland PSC	Exploration	22.8	12.9
Exploration and evaluation assets		22.8	12.9
Tawke capacity building payment waiver		61.9	66.2
Tawke RSA assets		61.9	66.2

 

  

 

 

10. Property, plant and equipment

 

	Producing assets	Other assets	Total
	$m	$m	$m
Cost
At 1 January 2022	3,117.2	17.1	3,134.3
Net additions	129.1	0.9	130.0
Right-of-use assets (note 20)	-	(0.4)	(0.4)
Other1	5.9	-	5.9
At 31 December 2022 and 1 January 2023	3,252.2	17.6	3,269.8
Additions	58.9	-	58.9
Right-of-use assets (note 20)	-	(0.3)	(0.3)
Other1	2.1	-	2.1
At 31 December 2023	3,313.2	17.3	3,330.5
Accumulated depreciation and impairment
At 1 January 2022	(2,769.2)	(12.6)	(2,781.8)
Depreciation charge for the year	(112.8)	(1.6)	(114.4)
Impairment (note 1)	(125.5)	-	(125.5)
At 31 December 2022 and 1 January 2023	(3,007.5)	(14.2)	(3,021.7)
Depreciation charge for the year	(42.3)	(1.3)	(43.6)
Write-off (note 1)	(18.7)	-	(18.7)
At 31 December 2023	(3,068.5)	(15.5)	(3,084.0)
Net book value
At 1 January 2022	348.0	4.5	352.5
At 31 December 2022	244.7	3.4	248.1
At 31 December 2023	244.7	1.8	246.5

 

1 Other line includes non-cash asset retirement obligation provision and share-based payment costs.

 

		2023	2022
Book value		$m	$m
Tawke PSC	Oil production	210.0	199.1
Taq Taq PSC	Oil production	34.7	28.8
Sarta PSC	Oil production/development	-	16.8
Producing assets		244.7	244.7

 

Sarta PSC was terminated on 1 December 2023 and this resulted in a reduction in the carrying value to nil and write-off of assets of $18.7 million as of 31 December 2023. Further explanation is provided in note 1.

 

The sensitivities below provide an indicative impact on net asset value of a change in netback price, discount rate or production, assuming no change to any other inputs.

 

Sensitivities	Taq Taq CGU $m	Tawke CGU $m
Netback price +/- $5/bbl	+/- 2	+/- 30
Discount rate +/- 1%	+/- 0	+/- 8
Production +/- 10%	+/- 2	+/- 32
Local sales only for 1 year	+/- 0	- 19

 

 

 

 

 

 

11. Trade and other receivables

	2023	2022
	$m	$m
Trade receivables – non-current	66.5	-
Trade receivables – current	26.4	117.0
Other receivables and prepayments	7.6	4.7
	100.5	121.7

 

At 31 December 2023, the Company is owed six months of payments (31 December 2022: five months).

 

 

	Period when sale made
	Not due	Overdue 2023	Overdue 2022	Deferred 2020	Total nominal	ECL provision	Trade receivables
	$m	$m	$m	$m	$m	$m	$m
31 December 2023	-	49.3	58.1	-	107.4	(14.5)	92.9
31 December 2022	60.7	-	44.4	16.5	121.6	(4.6)	117.0

 

 

 

Movement on trade receivables in the year	2023 $m	2022 $m
Carrying value at 1 January	117.0	158.1
Revenue from contracts with customers	87.6	384.8
Revenue recognised for suspended ORRI	-	34.7
Cash for export sales	(61.2)	(473.3)
Cash for local sales	(41.0)	-
Offset of payables due to the KRG	-	(0.1)
Reversal of previous year’s expected credit loss (note 1)	4.6	10.8
Expected credit loss for current year (note 1)	(14.5)	(4.6)
Capacity building payments	0.2	5.2
Sarta processing fee payments	0.2	1.4
Carrying value at 31 December	92.9	117.0

 

 

Recovery of the carrying value of the receivable

All trade receivables relate to export sales as the local sales are on a cash and carry basis. As explained in note 1, the booked nominal receivable value of $107.4 million has been recognised based on KBT due to IFRS 15 requirements and it would be $13 million higher under Brent pricing mechanism. The Company expects to recover the full value of receivables owed from the KRG under Brent pricing mechanism, but the terms of recovery are not determined yet. An explanation of the assumptions and estimates in assessing the net present value of the deferred receivables are provided in note 1.

	Total $m
Booked nominal balance to be recovered	107.4
Estimated net present value of total cash flows	92.9

 

 

Sensitivities/Scenarios

The table below shows the sensitivity of the net present value of the overdue trade receivables to start and timing of repayment that the company has used during its ECL assessment. Each scenario has been weighted in accordance with the management’s expected outcome.

 

12. Cash and cash equivalents

	2023	2022
	$m	$m
Cash and cash equivalents	363.4	494.6
	363.4	494.6

 

Cash is primarily invested with major international financial institutions, in US Treasury bills or liquidity funds. $0.6 million (2022: $0.1 million) of cash is restricted.

 

 

13. Trade and other payables

	2023	2022
	$m	$m
Trade payables	23.0	25.3
Other payables	2.2	5.2
Accruals	32.9	53.1
	58.1	83.6
Non-current	0.5	1.2
Current	57.6	82.4
	58.1	83.6

Current payables are predominantly short-term in nature and there is minimal difference between contractual cash flows related to the financial liabilities and their carrying amount.  For non-current payables, liabilities are recognised at discounted fair value using the effective interest rate. Lease liabilities are included in other payables, further explanation is provided in note 20.

 

 

14. Deferred income

	2023	2022
	$m	$m
Balance at 1 January	13.3	20.5
Interest (non-cash)	1.7	1.0
Royalty income (non-cash)	(0.8)	(8.2)
Balance at 31 December	14.2	13.3

 

Non-current (within 1-2 years)	8.2	6.5
Current	6.0	6.8
	14.2	13.3

15. Provisions

	2023	2022
	$m	$m
Balance at 1 January	52.2	42.6
Interest unwind	1.8	2.6
Additions	0.7	7.0
Reversals	(9.5)	-
Balance at 31 December	45.2	52.2

Provisions cover expected decommissioning, abandonment and exit costs arising from the Company’s assets which are further explained in note 1. Reversals are related to Sarta and Qara Dagh licences as a result of the termination of the PSCs.

 

 

 

 

16. Interest bearing loans and net cash

 

	1 Jan 2023	Discount unwind	Repurchase of bond	Dividend paid	Net other changes1	31 Dec 2023
	$m	$m	$m	$m	$m	$m
2025 Bond 9.25% (non-current)	(266.6)	(2.7)	25.6	-	-	(243.7)
Cash	494.6	-	(24.9)	(33.5)	(72.8)	363.4
Net cash	228.0	(2.7)	0.7	(33.5)	(72.8)	119.7

 

1 Net other changes are free cash flow plus purchase of own shares

 

At 31 December 2023, the fair value of the $248 million (2022: $274 million) of bonds held by third parties is $236.5 million (2022: $257.6 million).

 

The Company repurchased $26 million of its existing $274 million senior unsecured bond at a price equal to 93.5% of the nominal amount.

 

The bonds maturing in 2025 have two financial covenant maintenance tests:

 

Financial covenant	Test	YE 2023	YE 2022
Equity ratio (Total equity/Total assets)	> 40%	55%	56%
Minimum liquidity	> $30m	$363.4m	$494.6m

	1 Jan 2022	Discount unwind	Repurchase of bond	Dividend paid	Net other changes1	31 Dec 2022
	$m	$m	$m	$m	$m	$m
2025 Bond 9.25% (non-current)	(269.8)	(2.5)	5.7	-	-	(266.6)
Cash	313.7	-	(6.0)	(47.9)	234.8	494.6
Net cash	43.9	(2.5)	(0.3)	(47.9)	234.8	228.0

 

 

17. Financial Risk Management

 

Credit risk

Credit risk arises from cash and cash equivalents, trade and other receivables and other assets. The carrying amount of financial assets represents the maximum credit exposure. The maximum credit exposure to credit risk at 31 December was:

	2023 $m	2022 $m
Trade and other receivables	97.4	119.1
Cash and cash equivalents	363.4	494.6
	460.8	613.7

 

All trade receivables are owed by the KRG. Cash is deposited with major international financial institutions and the US treasury that are assessed as appropriate based on, among other things, sovereign risk, CDS pricing and credit rating.

 

Liquidity risk

The Company is committed to ensuring it has sufficient liquidity to meet its payables as they fall due. At 31 December 2023 the Company had cash and cash equivalents of $363.4 million (2022: $494.6 million).

 

Oil price risk

The Company’s export revenues are calculated from netback price and local sales revenues are from a price established on an arms length basis as further explained in note 1, and a $5/bbl change in average price across local and export sales would result in a (loss) / profit before tax change of circa $10 million.

 

Currency risk

Other than head office costs, substantially all of the Company’s transactions are denominated and/or reported in US dollars. The exposure to currency risk is therefore immaterial and accordingly no sensitivity analysis has been presented.

 

Interest rate risk

The Company reported borrowings of $243.7 million (2022: $266.6 million) in the form of a bond maturing in October 2025, with fixed coupon interest payable of 9.25% on the nominal value of $248.0 million (2022: $274 million). Although interest is fixed on existing debts, whenever the Company wishes to borrow new debt or refinance existing debt, it will be exposed to interest rate risk. A 1% increase in interest rate payable on a balance similar to the existing debts of the Company would result in an additional cost of circa $2.5 million per annum.

 

Capital management

The Company manages its capital to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. The Company’s short-term funding needs are met principally from the cash flows generated from its operations and available cash of $363.4 million (2022: $494.6 million).

 

Financial instruments

All financial assets and liabilities are measured at amortised cost. Due to their short-term nature except interest bearing loans and non-current portion of trade receivables, the carrying value of these financial instruments approximates their fair value. Their carrying values are as follows:

 

Financial assets	2023 $m	2022 $m
Trade and other receivables	97.4	119.1
Cash and cash equivalents	363.4	494.6
	460.8	613.7
Financial liabilities
Trade and other payables	55.9	78.4
Interest bearing loans	243.7	266.6
	299.6	345.0

 

 

18. Share capital

	Total  Ordinary Shares
At 1 January 2022 – fully paid1	280,248,198
At 31 December 2022, 1 January 2023 and 31 December 2023 – fully paid1	280,248,198

1 Ordinary shares include 845,335 (2022: 845,335) treasury shares. Share capital includes 2,224,090 (2022: 629,769) of trust shares.

 

There have been no changes to the authorised share capital since it was determined to be 10,000,000,000 ordinary shares of £0.10 per share.

 

 

19. Dividends

	2023	2022
	$m	$m
Ordinary shares
Final dividend (2023: 12¢ per share, 2022: 12¢ per share)	33.5	33.4
Interim dividend (2023: nil, 2022: 6¢ per share)	-	16.7
Total dividends provided for or paid	33.5	50.1
Paid in cash	33.5	47.9
Foreign exchange on dividend paid	-	2.2
Total dividends provided for or paid	33.5	50.1

 

 

 

 

 

 

20. Right-of-use assets / Lease liabilities

 

The Company’s right-of-use assets are related to the offices and included within property, plant and equipment.

 

	Right-of-use assets $m
Cost
At 1 January 2022	13.2
Disposals due to terminations	(0.4)
At 31 December 2022 and 1 January 2023	12.8
Disposals due to terminations	(0.3)
At 31 December 2023	12.5
Accumulated depreciation
At 1 January 2022	(5.1)
Depreciation charge for the period	(3.7)
At 31 December 2022 and 1 January 2023	(8.8)
Depreciation charge for the period	(2.6)
At 31 December 2023	(11.4)
Net book value
At 1 January 2022	8.1
At 31 December 2022	4.0
At 31 December 2023	1.1

 

 

		2023	2022
Book value		$m	$m
Offices		1.1	1.8
Cars		-	0.2
Production facility		-	2.0
Right-of-use assets		1.1	4.0

 

 

The weighted average lessee’s incremental borrowing rate applied to the lease liabilities. The lease terms vary from one to five years.

 

Lease liabilities	2023 $m	2022 $m
At 1 January	(4.1)	(8.3)
Additions	-	-
Disposals due to terminations	0.3	0.5
Payments of lease liabilities	2.8	3.8
Interest expense on lease liabilities	(0.1)	(0.1)
At 31 December (note 13)	(1.1)	(4.1)

Included within lease liabilities of $1.1 million (2022: $4.1 million) are non-current lease liabilities of $0.5 million (2022: $1.2 million). The identified leases have no significant impact on the Company`s financing, bond covenants or dividend policy. The Company does not have any residual value guarantees. The contractual maturities of the Company’s lease liabilities are as follows:

 

	Less than 1 year $m	Between 1 - 2 years $m	Between 2 - 5 years $m	Total contractual cash flow $m	Carrying Amount $m
31 December 2023	(0.7)	(0.3)	(0.2)	(1.2)	(1.1)
31 December 2022	(3.0)	(0.7)	(0.5)	(4.2)	(4.1)

 

 

 

21. Share based payments

 

The Company has five share-based payment plans under which awards are currently outstanding: performance share plan (2011), performance share plan (2021), restricted share plan (2011), share option plan (2011), and deferred bonus plan (2021). The main features of these share plans are set out below.

 

Key features	PSP (2011)	PSP (2021)	DBP (2021)	RSP (2011)	SOP (2011)
Form of awards	Performance shares. The intention is to deliver the full value of vested shares at no cost to the participant (as conditional shares or nil-cost options).	Either Performance shares or restricted shares. The intention is to deliver the full value of vested shares at no cost to the participant (as conditional shares or nil-cost options).	Deferred bonus shares. The intention is to deliver the full value of shares at no cost to the participant (as conditional shares or nil-cost options).	Restricted shares. The intention is to deliver the full value of shares at no cost to the participant (as conditional shares or nil-cost options).	Market value options. Exercise price is set equal to the average share price over a period of up to 30 days to grant.
Performance conditions	Performance conditions will apply. Awards granted from 2017 are measured against relative and absolute total shareholder return (‘TSR’) measured against a group of industry peers over a three-year period.	Performance conditions may or may not apply. Awards granted with performance conditions are measured against relative and absolute TSR measured against a group of industry peers over a three-year period.	Performance conditions may or may not apply. For awards granted to date, there are no performance conditions.	Performance conditions may or may not apply. For awards granted to date, there are no performance conditions.	Performance conditions may or may not apply. For awards granted to date, there are no performance conditions.
Vesting period	Awards will vest when the Remuneration Committee determines whether the performance conditions have been met at the end of the performance period.	For awards subject to performance conditions, they will vest when the Remuneration Committee determines whether the performance conditions have been met at the end of the performance period. For awards that are not subject to performance conditions, awards typically vest in tranches over three years.	Awards typically vest after two years.	Awards typically vest in tranches over three years.	Awards typically vest after three years.
Dividend equivalents	Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply.	Provision of additional cash/shares to reflect dividends over the vesting period and the period where the options have vested and have not yet been exercised (where applicable) may or may not apply.	Provision of additional cash/shares to reflect dividends over the vesting period and the period where the options have vested and have not yet been exercised (where applicable) may or may not apply.	Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply.	Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply.

 

 

In 2023, awards were made under the performance share plan only. The numbers of outstanding shares as at 31 December 2023 are set out below:

	Share awards with performance conditions	Share awards without performance conditions		Share options	Weighted avg. exercise price of share options
Outstanding at 1 January 2022	9,508,167	1,415,816		85,232	817p
Granted during the year	2,549,151	505,645		-	-
Dividend equivalents	710,605	115,753		-	-
Forfeited during the year	(2,248,542)	-		-	-
Lapsed during the year	(2,555,194)	(125,326)		(33,967)	753p
Exercised during the year	(11,647)	(883,603)		-	-
Outstanding at 31 Dec 2022 and 1 Jan 2023	7,952,540	1,028,285		51,265	858p
Granted during the year	2,961,900	540,834		-	-
Dividend equivalents	607,589	91,973		-	-
Forfeited during the year	(3,805,594)	-		-	-
Lapsed during the year	(191,374)	(191,768)		(26,443)	767p
Exercised during the year	(64,085)	(366,082)		(6,370)	742p
Outstanding at 31 December 2023	7,460,976	1,103,242		18,452	1,046p

The exercise price for share options outstanding at the end of the period is 1,046.00p.

 

Fair value of awards granted during the year has been measured by use of the Monte-Carlo pricing model. The model takes into account assumptions regarding expected volatility, expected dividends and expected time to exercise. Expected volatility was also analysed with the historical volatility of FTSE-listed oil and gas producers over the three years prior to the date of grant. The expected dividend assumption was set at 0%. The risk-free interest rate incorporated into the model is based on the term structure of UK Government zero coupon bonds. The inputs into the fair value calculation for PSP awards granted in 2023 and fair values per share using the model were as follows:

		PSP (without condition) 06/04/2023	PSP 06/04/2023	PSP (without condition) 12/09/2023	PSP 12/09/2023
Share price at grant date		124p	124p	82p	82p
Fair value on measurement date		124p	80p	82p	43p
Expected life (years)		1-3	1-3	1-3	1-3
Expected dividends		-	-	-	-
Risk-free interest rate		3.25%	3.25%	4.73%	4.73%
Expected volatility		47.21%	47.21%	42.21%	42.21%
Share price at balance sheet date		71p	71p	71p	71p
Change in share price between grant date and 31 December 2023		-43%	-43%	-13%	-13%

 

The weighted average fair value for PSP awards (without condition) granted in 2023 is 121p and for PSP awards granted in 2023 is 80p.

 

The inputs into the fair value calculation for PSP awards granted in 2022 and fair values per share using the model were as follows:

		PSP (without condition) 04/04/2022	PSP 04/04/2022	PSP (without condition) 08/09/2022	PSP 08/09/2022
Share price at grant date		186p	186p	137p	137p
Fair value on measurement date		186p	127p	137p	82p
Expected life (years)		1-3	1-3	1-3	1-3
Expected dividends		-	-	-	-
Risk-free interest rate		1.41%	1.41%	3.04%	3.04%
Expected volatility		39.76%	39.76%	41.42%	41.42%
Share price at balance sheet date		125p	125p	125p	125p
Change in share price between grant date and 31 December 2022		-33%	-33%	-9%	-9%

 

The weighted average fair value for PSP awards (without condition) granted in 2022 is 164p and for PSP awards granted in 2022 is 124p.

 

Total share-based payment charge for the year was $3.7 million (2022: $4.1 million).

22. Capital commitments

 

Under the terms of its production sharing contracts (‘PSC’s) and joint operating agreements (‘JOA’s), the Company has certain commitments that are generally defined by activity rather than spend. The Company’s capital programme for the next few years is explained in the operating review and is in excess of the activity required by its PSCs and JOAs. 

 

23. Related parties

 

The directors have identified related parties of the Company under IAS 24 as being: the shareholders; members of the Board; and members of the executive committee, together with the families and companies, associates, investments and associates controlled by or affiliated with each of them. The compensation of key management personnel including the directors of the Company is as follows:

		2023 $m	2022 $m
Board remuneration		0.7	0.8
Key management emoluments and short-term benefits		4.1	6.0
Share-related awards		2.7	1.0
		7.5	7.8

 

There have been no changes in related parties since last year and no related party transactions that had a material effect on financial position or performance in the year.

 

24. Events occurring after the reporting period

 

The London-seated international arbitration hearing (factual and expert evidence) which includes Genel’s claim for substantial compensation from the KRG following the termination of the Miran and Bina Bawi PSCs ended on 1 March 2024. The timing of the result is uncertain but is expected by the end of 2024 following the Parties making closing written submissions in April 2024 and reply written submissions in May 2024.

 

25. Subsidiaries and joint arrangements

 

The Company has four joint arrangements in relation to its producing assets Taq Taq, Tawke, Sarta and pre-production asset Qara Dagh PSC. The Company holds 44% working interest in Taq Taq PSC and owns 55% of Taq Taq Operating Company Limited. The Company holds 25% working interest in Tawke PSC which is operated by DNO ASA.

 

For the period ended 31 December 2023 the principal subsidiaries of the Company were the following:

 

Entity name		Country of Incorporation		Ownership % (ordinary shares)
Barrus Petroleum Cote D'Ivoire Sarl1		Cote d'Ivoire		100
Barrus Petroleum Limited2		Isle of Man		100
Genel Energy Africa Exploration Limited3		UK		100
Genel Energy Finance 4 plc3		UK		100
Genel Energy Gas Company Limited4		Jersey		100
Genel Energy Holding Company Limited4		Jersey		100
Genel Energy International Limited5		Anguilla		100
Genel Energy Miran Bina Bawi Limited3		UK		100
Genel Energy Morocco Limited3		UK		100
Genel Energy No. 6 Limited3		UK		100
Genel Energy Petroleum Services Limited3		UK		100
Genel Energy Qara Dagh Limited3		UK		100
Genel Energy Sarta Limited3		UK		100
Genel Energy Somaliland Limited3		UK		100
Genel Energy UK Services Limited3		UK		100
Genel Energy Yӧnetim Hizmetleri A.Ş.6		Turkey		100
Taq Taq Drilling Company Limited7		BVI		55
Taq Taq Operating Company Limited7		BVI		55

 

1 Registered office is 7 Boulevard Latrille Cocody, 25 B.P. 945 Abidjan 25, Cote d'Ivoire

2 Registered office is 6 Hope Street, Castletown, IM9 1AS, Isle of Man

3 Registered office is Fifth Floor, 36 Broadway, Victoria, London, SW1H 0BH, United Kingdom

4 Registered office is 26 New Street, St Helier, JE2 3RA, Jersey

5 Registered office is PO Box 1338, Maico Building, The Valley, Anguilla

6 Registered office is Vadi Istanbul 1 B Block, Ayazaga Mahallesi, Azerbaycan Caddesi, No:3 Floor: 18, 34396, Sariyer, Istanbul, Turkey

7 Registered office is Kingston Chambers, P.O. Box 173, Road Town, Tortola, VG1110, British Virgin Islands

 

 

26. Annual report

 

Copies of the 2023 annual report will be despatched to shareholders in April 2024 and will also be available from the Company’s registered office at 26 New Street, St Helier, Jersey, JE2 3RA and at the Company’s website – www.genelenergy.com.

 

27. Statutory financial statements

 

The financial information for the year ended 31 December 2023 contained in this preliminary announcement has been audited and was approved by the Board on 25 March 2024. The financial information in this statement does not constitute the Company's statutory financial statements for the years ended 31 December 2023 or 2022. The financial information for 2023 and 2022 is derived from the statutory financial statements for 2022, which have been delivered to the Registrar of Companies, and 2023, which will be delivered to the Registrar of Companies and issued to shareholders in April 2024. The auditors have reported on the 2023 and 2022 financial statements; their report was unqualified and did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying their report. The statutory financial statements for 2023 are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted for use in the European Union. The accounting policies (that comply with IFRS) used by Genel Energy plc are consistent with those set out in the 2022 annual report.