23 March 2023

 

 

Gulf Keystone Petroleum Ltd. (LSE: GKP)

("Gulf Keystone", "GKP", "the Group" or "the Company")

 

2022 Full Year Results Announcement and Competent Person's Report Update

 

Strong 2023 production, recently exceeding 55,000 bopd

2022 CPR confirms 817 MMstb of gross 2P reserves + 2C resources, with 100% replacement of production

Record 2022 free cash flow and profitability drove sector leading dividend yield

 

Gulf Keystone, a leading independent operator and producer in the Kurdistan Region of Iraq, today announces its results for the full year ended 31 December 2022 and the 2022 Competent Person's Report.

 

Jon Harris, Gulf Keystone's Chief Executive Officer, said:

"We delivered strong operational and financial performance in 2022 in line with our clear strategy of balancing investment in profitable production growth with sustainable shareholder returns, while maintaining a robust balance sheet and prudent liquidity levels. Higher oil prices and production, combined with continued capital discipline and cost control, enabled us to generate record profitability and cash flow, funding increased investment in future production growth, record dividends of $215 million and the repayment of our $100 million bond resulting in a debt-free balance sheet.  

The benefits of our 2022 investment programme and progress on executing the Jurassic scope of the Shaikan Field Development Plan contributed to a material increase in gross average production to around 53,500 bopd in March 2023, hitting a new record of over 55,000 bopd in the last few days, an important milestone for GKP. In addition, we are pleased that the 2022 CPR has confirmed the Shaikan Field's significant growth potential and gross 2P + 2C reserves and resources of 817 MMstb, with 100% reserves replacement since the 2020 CPR.

Looking ahead we are reviewing our forward capital programme in light of continued delays to KRG payments to ensure that we maintain a prudent financial position as we continue to develop the Jurassic reservoir and advance towards approval of the FDP. As ever, we remain committed to balancing growth with shareholder returns and financial strength, confirmed by our declaration today of a final 2022 ordinary annual dividend of $25 million, increasing total dividends declared in 2023 to $50 million."

Highlights to 31 December 2022 and post reporting period

 

Operational

 

·      Zero Lost Time Incidents ("LTIs") in 2022, despite significant increase in operational activity

o  Following an LTI in January 2023 during drilling operations, remedial actions have been implemented

·      Gross average production for 2022 of 44,202 bopd (2021: 43,440 bopd), in line with annual guidance

·      Executing the Jurassic scope of the Field Development Plan ("FDP") with the agreement of the Ministry of Natural Resources ("MNR"), with 2022 activity laying the foundation for higher future production

o  Drilled and brought online SH-15 and SH-16, the first two Jurassic wells in the FDP sequence, on schedule and on budget, and partially drilled SH-17

o  Prepared well pads and flowlines to enable a continuous drilling programme

o  Completed initial engineering and construction works and procurement of long lead items for production facility expansion and installation of water handling

·      Realising benefits of 2022 investments with recent material increase in production to record highs

o  2023 year to date gross average production of c.48,900 bopd, with gross average production in March to date of c.53,500 bopd and production of c.55,000 bopd in the last few days

o  Production growth driven by continued ramp up of SH-16 following start-up in December 2022, start-up of SH-17 in February 2023, and our well workover programme

o  Minor impact from temporary suspension of pipeline exports in February 2023 following the tragic earthquakes in Turkey and Syria

·      Continuous drilling programme delivering improvements in drilling performance

o  SH-17 drilled, completed and brought onstream in February 2023, under budget and ahead of schedule

o  Drilling of SH-18 progressing well with expected start up in Q2 2023, in line with prior guidance

 

Financial

 

·      Record profitability and cash generation in 2022, driven by a strong increase in the oil price, higher production and our continued focus on cost control

o  Adjusted EBITDA increased by 61% to $358.5 million (2021: $222.7 million)

o  Profit after tax increased 62% to $266.1 million (2021: $164.6 million)

o  Gross Opex per barrel of $3.2/bbl (2021: $2.7/bbl), in line with the Company's 2022 guidance range of $2.9-$3.3/bbl and reflecting higher operational activity

o  Realised price per barrel increased by 49% to $74.1/bbl (2021: $49.7/bbl)

o  While the Company has not accepted the MNR's proposed change to the pricing mechanism for Shaikan oil sales, changing the reference price from Dated Brent to the Kurdistan Blend ("KBT") effective 1 September 2022, revenue from September 2022 to December 2022 has been recognised on this basis, resulting in an average reduction in the realised sales price versus the previous pricing mechanism over the period of approximately $12/bbl or $23.4 million

o  The KBT discount to Dated Brent has tightened since November 2022, with the impact on Shaikan realised prices versus the previous pricing mechanism decreasing to $6/bbl in February 2023

·      Increased investment in the Shaikan Field while maintaining capital discipline to drive future profitable production growth

o  Net capital expenditure of $114.9 million (2021: $46.2 million), in line with final 2022 guidance of $110-$120 million

§ $63.4 million: Drilling of SH-15, SH-16 and partial drilling of SH-17 that was completed in early 2023

§ $35.8 million: Early work for the expansion of the production facilities with water handling capacity, as well as future well pad preparation including flowlines

§ $15.7 million: Well workover and interventions to optimise production

·      Strong free cash flow generation funded continued delivery of our strategy to balance growth with shareholder returns while maintaining a robust balance sheet and prudent liquidity levels

o  Free cash flow generation of $266.5 million, more than double the prior year (2021: $122.2 million)

o  Record dividends of $215 million, representing a sector-leading dividend yield of 41% based on the closing share price on 31 December 2022. Since the beginning of 2023, GKP has paid an additional interim dividend of $25 million

o  Redeemed $100 million outstanding bond in August 2022, leaving the Company debt free with significant financial flexibility

o  Cash balance of $118.8 million at 22 March 2023

·      Revenue receipts of $450.4 million net to GKP received from the Kurdistan Regional Government ("KRG") in 2022 for crude oil sales and repayment of historical revenue arrears

o  While the Company has received $65.7 million net from the KRG in 2023 for August and September 2022 oil sales, overdue receivables for the months of October to December 2022 total $76.0 million net on the basis of the KBT pricing mechanism

 

2022 Competent Person's Report

 

·      GKP announces today the 2022 Competent Person's Report ("2022 CPR"), an updated independent third-party evaluation of the Shaikan Field's reserves and resources prepared by ERC Equipoise ("ERCE")

·      2022 CPR incorporates significant incremental information, including an updated field development plan, new wells, production data and further technical analysis, since the previous 2020 CPR also prepared by ERCE

·      Gross 2P+2C reserves and resources of 817 MMstb as at 31 December 2022, 52 MMstb higher than the previous 2020 CPR after adjusting for production in 2021 and 2022

o  Gross 2P reserves of 506 MMstb increased 34 MMstb or 7% relative to 2020 CPR volumes adjusted for production, resulting in 100% reserves replacement over the two-year period

o  Increase driven by higher plateau rate of 85,000 bopd from the Jurassic reservoir

o  Gross 1P reserves of 199 MMstb decreased 8 MMstb or 4% relative to 2020 CPR volumes adjusted for production due to prudent management of production rates to avoid traces of water ahead of water handling installation

o  Gross 2C resources of 311 MMstb increased 18 MMstb or 6% relative to 2020 CPR volumes due to higher planned production processing capacity

·      2022 CPR highlights the significant growth potential of the Shaikan Field, with a gross 2P reserves-to-production ratio of 31 years based on 2022 gross average production, and reaffirms our deep understanding and prudent management of the reservoir, which has produced over 117 MMstb to date

 

Gross reserves and resources⁽¹⁾ based on the 2022 CPR compared to the 2020 CPR are as follows:

 

	Reserves		Resources
Formation (MMstb)	1P	2P	2C(2)	2P+2C(2,3)
31 December 2022
Jurassic	199	506	101	607
Triassic	-	-	157	157
Cretaceous	-	-	53	53
Total (gross)	199	506	311	817
31 December 2020
Jurassic	240	505	80	585
Triassic	-	-	157	157
Cretaceous	-	-	56	56
Total (gross)	240	505	293	798

 

The reconciliation of changes in reserves and resources between the 2020 CPR and the 2022 CPR is as follows:

	Reserves		Resources
Gross (MMstb)	1P	2P	2C(2)	2P+2C(2,3)
31 December 2020	240	505	293	798
2021 & 2022 production	(33)	(33)	-	(33)
31 December 2020 (adjusted for production)	207	472	293	765
Revisions	(8)	34	18	52
31 December 2022	199	506	311	817

 

GKP's 80% net working interest ("WI")⁽⁴⁾ share of reserves and resources at 31 December 2022 are:

 

	Reserves		Resources
Formation (80% WI) (MMstb)	1P	2P	2C(2)	2P+2C(2,3)
Jurassic	159	405	81	486
Triassic	-	-	126	126
Cretaceous	-	-	42	42
Total (net WI)	159	405	249	654

 

(1)   Reserves and resources have been calculated in accordance with the June 2018 SPE/WPC/AAPG/ SPEE/SEG/SPWLA/EAGE Petroleum Resources Management System).

(2)   Contingent resources volumes are classified as such because there is technical and commercial risk involved with their extraction. In particular, there may be a chance that accumulations containing contingent resources will not achieve commercial maturity. The 2C (best estimate) contingent resources presented are not risked for chance of development. All Contingent resource volumes quoted in this document are volumes which could be extracted prior to license expiry.

(3)   Aggregated 2P+2C estimates should be used with caution as 2C contingent resources are commercially less mature than the 2P reserves.

(4)   Net working interest reserves and resources do not represent the net entitlement resources under the terms of the Production Sharing Contract ("PSC").

 

 

Outlook

 

·      Given continued delays to KRG payments, we are currently reviewing our forward capital programme and 2023 net capital expenditure guidance of $160-$175 million

o  With further clarity around KRG payments, we would consider continued drilling following SH-18

o  With continued payment delays, we would review reductions to our capital programme

·      Looking ahead, subject to timely KRG payments and oil prices, we are focused on transitioning towards capitalising on the significant growth potential of the Shaikan Field, as confirmed by the 2022 CPR, and attractive returns on capital from the accelerated payback of investment as we recover our historic costs

o  Targeting step up in production levels through execution of the Jurassic scope of the FDP, drilling additional Jurassic wells and expanding the production facilities

o  While timing of FDP approval remains uncertain, we continue to advance towards key project sanction milestones, including the conclusion of the Gas Management Plan ("GMP") tendering process and, as appropriate, financing arrangements

·      We are committed to balancing profitable production growth, shareholder returns and a robust balance sheet according to our disciplined financial framework, in line with our historic track record

o  Following payment of $25 million interim dividend in March, we are pleased to announce declaration of a final 2022 ordinary annual dividend of $25 million, in line with the Company's dividend policy

o  Subject to approval at the AGM on 16 June 2023, we expect to pay final dividend on 21 July 2023, based on a record date of 7 July 2023 and ex-dividend date of 6 July 2023

o  Total dividends declared in 2023 of $50 million, equating to an 11% yield for year to date 2023, based on the closing share price on 22 March 2023

o  The Board remains committed to distributing excess cash to shareholders via dividends and/or share buybacks and will continue to review distributions based on our disciplined financial framework, as outlined in our 30 January 2023 trading update, which includes regular assessment of the Company's expected liquidity, cash flow generation and investment needs

·      Continue to monitor discussions between the Federal Iraqi Government and the KRG on the management of oil and gas assets in Kurdistan following the Iraqi Federal Supreme Court ruling in February 2022. GKP's operations currently remain directly unaffected

 

2023 guidance

 

·      2023 guidance remains dependent on timely KRG payments and oil prices. The Company will consider adjustments to the capital programme based on how the business environment evolves

·      We remain focused on delivering 2023 gross average production of 46,000-52,000 bopd, representing a 11% increase from 2022 at the mid-point

o  Reflects anticipated contributions from SH-17 and SH-18, as well as the benefits of well workovers

o  Continue to manage natural field declines, well production rates ahead of water handling installation and higher gas production from one of our wells near the gas cap, in line with our reservoir modelling

·      Current 2023 net capital expenditure guidance of $160-$175 million:

o  $30-$35 million: Completion of SH-17, drilling and completion of SH-18 and well workover programme to optimise production

o  $45-$50 million: Long lead items and preparing well pads to enable continuous drilling

o  $85-$90 million: Continued expansion of production facilities, targeting by H2 2024 an increase in total field capacity from c.60,000 bopd currently to 85,000 bopd and installation of water handling capacity, potentially enabling the increase in production rates from constrained wells

·      2023 gross Opex guidance of $3.0-$3.4/bbl unchanged, underpinned by the Company's continued focus on strict cost control

 

Investor & analyst presentation

 

GKP's management team will be hosting a presentation for analysts and investors at 10:00am (GMT) today via live audio webcast:

 

https://brrmedia.news/GKP_FY2022   

 

Management will also be hosting an additional webcast presentation focused on retail investors via the Investor Meet Company ("IMC") platform at 12:00pm (GMT) today. The presentation is open to all existing and potential shareholders and participants will be able to submit questions at any time during the event.

 

https://www.investormeetcompany.com/gulf-keystone-petroleum-ltd/register-investor

 

This announcement contains inside information for the purposes of the UK Market Abuse Regime.

 

Enquiries:

 

Gulf Keystone:	+44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations	[email protected]
FTI Consulting	+44 (0) 20 3727 1000
Ben Brewerton Nick Hennis	[email protected]

 

 

or visit: www.gulfkeystone.com

 

Notes to Editors:

 

Gulf Keystone Petroleum Ltd. (LSE: GKP) is a leading independent operator and producer in the Kurdistan Region of Iraq. Further information on Gulf Keystone is available on its website www.gulfkeystone.com 

 

Disclaimer

 

This announcement contains certain forward-looking statements that are subject to the risks and uncertainties associated with the oil & gas exploration and production business.  These statements are made by the Company and its Directors in good faith based on the information available to them up to the time of their approval of this announcement but such statements should be treated with caution due to inherent risks and uncertainties, including both economic and business factors and/or 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.  This announcement has been prepared solely to provide additional information to shareholders to assess the Group's strategies and the potential for those strategies to succeed.  This announcement should not be relied on by any other party or for any other purpose.

 

 

 

Chairman's statement

 

Gulf Keystone benefitted from strong oil prices in 2022, with Dated Brent averaging $101/bbl in the year, up $30/bbl from 2021. However, volatility was high, with peaks of around $130/bbl in the first half of the year declining in the second half to around $80/bbl in December, as concerns around energy security and supply deficits, driven primarily by the tragic conflict in Ukraine and recovery in global economic demand, transitioned to market fears of inflationary pressures, fiscal tightening and recession.

 

From an operational perspective, working patterns in the Shaikan Field and our offices returned to normal following the disruption caused by the COVID-19 pandemic. Safety was a major focus for the team as activity ramped up, and the Board and I are pleased with the Company's performance in 2022. The Company is continuing to manage tightness in regional and global supply chains, with ongoing pressure on equipment lead times and cost pressures.

 

Looking at the geopolitical environment, while security in Kurdistan was relatively stable in the year, the Iraqi Federal Supreme Court ruling in February 2022 led to heightened tensions in the longstanding dispute between Federal Iraq and the KRG regarding oil and gas assets in Kurdistan. The situation has improved since the formation of a new Federal Iraqi government in October 2022, with an active dialogue taking place between both sides. Nonetheless, it remains difficult to predict outcomes and the Board continues to monitor the situation closely. We also continue to closely monitor and engage with the KRG regarding the delays to recent oil sales payments and the negotiation of a new lifting agreement. While historically payments have been made, the recent delays have been disappointing. We are experienced operating in Kurdistan and look to maintain a prudent level of liquidity and flexible capital programme to manage through periods of uncertainty.

 

Against this backdrop, GKP delivered strong operational and financial results in 2022 and continued execution of its strategy of balancing investment in growth with sustainable shareholder returns, while maintaining a robust balance sheet and prudent liquidity levels.

 

From an operational perspective, the Company achieved its 2022 production guidance and completed a significant work programme, paving the way for expected future increases in production. The Company also advanced towards approval of the Shaikan Field Development Plan ("FDP"). From a financial perspective, strong oil prices and continued cost control and capital discipline supported significant cash flow generation, enabling the Company to fund its investment programme, pay record dividends to shareholders of $215 million and strengthen its balance sheet through the early redemption of the outstanding $100 million bond. The Company delivered top quartile total shareholder returns of 57% in the year, assuming dividends reinvested.

 

The Company has seen a material increase in production in 2023, with production recently exceeding 55,000 bopd. The achievement of this important milestone has been supported by the Company's 2022 investments and decision to proceed with the execution of the FDP's Jurassic scope.

 

Looking ahead to 2023, the Company is currently reviewing its forward capital programme in light of continued delays to KRG payments. Subject to timely payments and oil prices, the Company will continue to transition to increased investment in profitable production growth while advancing towards key project sanction milestones of the full FDP, which the Board expects to maximise long-term value for shareholders and Kurdistan. The Board and I are pleased the 2022 Competent Person's Report reaffirms the significant growth potential of the Shaikan Field, with 817 MMstb 2P reserves and 2C resources, 100% reserves replacement since the 2020 CPR and a 2P reserves-to-production ratio of 31 years.

 

As the Company progresses, the Board will manage the balance between investment in growth, shareholder returns and balance sheet strength according to a disciplined financial framework.

 

The Board is committed to paying an ordinary dividend of at least $25 million per annum and distributing excess cash to shareholders by way of dividends and/or share buybacks. In determining the level of distributions, the Board regularly reviews the Company's expected liquidity, cash flow generation and investment needs. We are pleased to have declared total dividends in 2023 date of $50 million, including the declaration of a $25 million 2022 ordinary annual dividend for shareholder approval at the Company's AGM on 16 June 2023.

 

Sustainability continues to be a strategic priority for GKP and the Board has direct oversight and responsibility for the Company's strategy. The strategy has a number of objectives, of which addressing climate-related risks and opportunities is key. For fiscal year 2022, the Company's disclosures are fully consistent with all of the Taskforce on Climate-related Financial Disclosures ("TCFD") recommendations, reflecting how a focus on climate-related risks and opportunities is embedded into the Company's strategy and governance, including risk management. The Company also continued to make significant progress in the year in supporting the development of its workforce, increasing gender diversity, generating material economic and social value for Kurdistan and the Company's local communities, as well as continuing to maintain strong corporate governance, ethical business conduct and compliance.

 

The Board continued to engage with the Company's shareholders in 2022 and welcomes ongoing interaction and feedback with all investors. We encourage GKP shareholders to participate in our Annual General Meetings, which are accessible virtually to all investors. While we saw voting turnout improve at the 2022 AGM, it remained low relative to prior years and we continue to look at ways to improve shareholder participation and voting at future general meetings.

 

We were delighted in July 2022 to welcome Wanda Mwaura to the Board as a new Non-Executive Director and member of the Audit and Risk Committee. Wanda brings over 25 years of expertise and experience in accounting, external and internal audit, consulting, regulatory and corporate governance to GKP. She is highly respected and complements the Board with her extensive skill set.

 

GKP's 2022 Full Year Results and Annual Report will be my last as Non-Executive Chairman, as I prepare to hand over the role following the 2023 AGM. It has been a distinct privilege to serve as Chairman of GKP and I am proud of the significant achievements and progress the Company has made during my tenure to create value for its shareholders, Kurdistan and broader stakeholder base.

 

Since my appointment in 2018, GKP has increased gross average production from an average of 31,563 bopd in 2018 to over 55,000 bopd recently. In the same period, GKP has distributed $440 million in dividends and share buybacks to shareholders, generated more than $1.8 billion in gross revenues for the KRG from the Shaikan Field and maintained a strong balance sheet throughout, against a backdrop of commodity price volatility and the COVID-19 pandemic. This performance has been underpinned by a rigorous focus on safety and sustainability and strong leadership from the Board, with regular Director visits to the Company's operations in Kurdistan.

 

I am delighted to be succeeded by Martin Angle, my esteemed fellow Director and current Deputy Chairman and Senior Independent Director ("SID"), and that Martin's Deputy Chair and SID roles will be taken on by Kimberley Wood, currently independent Non-Executive Director. I have worked with both Martin and Kimberley since 2018 and they have both made an enormous contribution to the Company and to the Board. Their experience and expertise will be invaluable to GKP's future success.

 

On behalf of the Board, I would like to thank GKP's leadership team and all of the Company's employees for their continued commitment to safety, delivery of the Company's strategy and relentless focus on creating value for GKP's shareholders and stakeholder base. We are excited about the future and the year of significant activity ahead.

 

Jaap Huijskes

Non-Executive Chairman

 

22 March 2023

 

 

CEO review

 

In 2022, we delivered strong operational and financial performance as we continued to execute our clear strategy of balancing investment in profitable growth with shareholder returns while maintaining a robust balance sheet.

 

We commenced the execution of the Phase 1 Shaikan Field Development Plan ("FDP") Jurassic scope with the agreement of the MNR, comprising additional wells (with SH-15 and SH-16 completed in 2022 and SH-17 and SH-18 completed or currently underway in 2023) and early works related to the expansion of our production facilities. We also delivered another year of record production and made good progress towards key FDP sanction milestones.

 

We generated record Adjusted EBITDA in 2022, driven by higher production, strong oil prices and a continued focus on cost management and efficiency, resulting in a more than doubling of free cash flow to $266 million. Strong cash flow generation enabled us to fund our capital programme and pay sector leading dividends to our shareholders of $215 million, bringing total shareholder distributions to $415 million since 2019, while at the same time strengthening our balance sheet through the redemption of our $100 million bond. We are now debt free.

 

Our performance, as always, was underpinned by a rigorous focus on safety, with zero Lost Time Incidents ("LTI") in the year and only one recordable incident.

 

Gross average production in 2022 was 44,202 bopd, within our annual guidance range. Despite the small increase versus 2021, our 2022 work programme has laid the foundations for a material increase in future production. Our drilling performance is improving and we are delivering wells on or below budget. The latest well, SH-18, is progressing well and we expect start up in Q2 2023, in line with our previous guidance. Continuous drilling has been facilitated by our investment in well pad preparation, flowlines and long lead items. In addition, completion of early work for the production facility expansion in 2022 has positioned us to increase total field processing capacity to 85,000 bopd and install water handling capacity in H2 2024.

 

As we enter 2023, it is clear that our investments in 2022 and decision to progress the Jurassic scope of the FDP are beginning to pay off. Gross average production in 2023 year to date has been c.48,900 bopd, while gross average production in March to date has been c.53,500 bopd, including the achievement of a new production record of over 55,000 bopd in the last few days, an important milestone for the Company.

 

We continue to see significant growth potential from the Shaikan Field, with the 2022 Competent Person's Report confirming gross 2P reserves and 2C resources of 817 MMstb, 52 MMstb higher than the previous CPR from 2020 after adjusting for production. The 2022 CPR shows 100% reserves replacement, driven by a higher plateau rate of 85,000 bopd from the Jurassic reservoir and accelerating post license production.

 

In addition, we see an excellent opportunity to create value for our shareholders. Returns on capital from incremental investment in the Shaikan Field are attractive, as the payback of investment under the Shaikan Production Sharing Contract accelerates as we recover our historic costs. By increasing profitable production, we also expect to enhance the sustainability and longevity of the Company's capacity for shareholder distributions.

 

Looking ahead, our intention is to continue our transition towards increased investment in profitable production growth, expanding the Jurassic reservoir while advancing towards key project sanction milestones of the FDP. However, given continued delays to KRG payments, we are currently reviewing our forward capital programme and 2023 net capital expenditure guidance of $160-$175 million. With further clarity around KRG payments, we would consider continued drilling following SH-18. However, we will also review potential reductions to our capital programme should payment delays continue.

 

As we increase investment in profitable production growth through a flexible capital programme, we remain focused on delivering against our strategy of balancing growth with sustainable shareholder returns, while maintaining a robust balance sheet and prudent liquidity levels. We are pleased to declare a final 2022 ordinary annual dividend of $25 million subject to shareholder approval at the AGM on 16 June 2023, increasing total dividends declared in 2023 to $50 million and equating to an 11% yield for 2023, based on the closing share price on 22 March 2023. The Board remains committed to distributing excess cash to shareholders by way of dividends and/or share buybacks and will continue to review distribution decisions based on a disciplined financial framework.

 

We have an exciting year ahead of us at Gulf Keystone and a number of opportunities to create significant value for our shareholders and broader stakeholder base. I want to provide my heartfelt thanks to GKP's teams in Kurdistan and the UK, whose continued hard work and innovation are enabling the Company to deliver against its strategy. I would also like to thank Jaap Huijskes, who will be stepping down following the 2023 AGM, for all his help and stewardship in my first two years as CEO. I wish him well for the future.

 

Jon Harris

Chief Executive Officer

 

22 March 2023

 

 

Operational review

 

We delivered strong operational performance in 2022, safely achieving higher production while investing in future growth and further advancing towards approval of the Shaikan Field Development Plan ("FDP"). We also continued to execute our sustainability strategy with progress in several areas.

 

Throughout the year, the health and safety of our workforce and local communities remained our priority. We were pleased to record zero Lost Time Incidents ("LTIs") in 2022, despite a more than 50% increase in working hours to 2.2 million hours. Unfortunately, we experienced an LTI in January 2023 during drilling operations and we are implementing remedial actions. As at 22 March 2023, we have been operating for over 60 days without an LTI.

 

We achieved gross average production of 44,202 bopd in 2022, a 2% increase versus 2021 and in line with our revised annual guidance range of 44,000-47,000 bopd. Production was supported by incremental volumes from SH-13 and SH-14, brought on-stream in December 2021, and from SH-15 and SH-16, which started up in April and December 2022 respectively. Increases were mostly offset by the continued prudent management of well production rates to avoid trace amounts of water production ahead of installation of water handling capacity, including the shut-in of SH-12 for most of H1 2022, as well as the temporary shut-in of one well during Q4 2022 due to an isolated Electrical Submersible Pump ("ESP") electrical failure.

 

We delivered a significant work programme in 2022 as we commenced execution of the FDP Jurassic scope that positions us to drive profitable future production growth. Drilling activities in 2022 included the start-up of SH-15 and SH-16 and spud of SH-17 which was completed in early 2023 and started producing in February 2023. We have seen the benefit of a continuous drilling programme with a general decline in drilling costs and times, while investments in the year in well pad preparation, flowline installation and long lead items have enabled us to maintain momentum.

 

In addition, we advanced the expansion of the production facilities in the year, carrying out early engineering and construction work and progressing the procurement of long lead items, despite ongoing equipment lead time and cost pressures, positioning us to increase total field processing capacity to 85,000 bopd and install water handling capacity in H2 2024. Water handling capacity will potentially enable us to increase production rates from constrained wells which we are currently prudently managing to avoid traces of water.

 

Shaikan Field Development Plan

 

We are continuing to progress towards approval of the FDP. Since the initial draft was submitted in November 2021, we have engaged extensively with the MNR and have substantially finalised the technical scope and future work programme. We continue to progress key project milestones, including optimising the work programme to phase activity and facilitate accelerated cost recovery, negotiating commercial terms including a potential update to the Shaikan Production Sharing Contract ("PSC") with the target of ensuring changes are at least value neutral, and concluding the Gas Management Plan tendering process and, as appropriate, financing arrangements.

 

As we progress, we have agreed with the MNR to execute the Jurassic scope of the FDP before approval, to date drilling or in the process of drilling a total of four FDP wells - SH-15, SH-16, SH-17 and SH-18 - and advancing the expansion of the production facilities. We remain focused on testing the Triassic reservoir, targeting initial pilot production of up to 10,000 bopd, and implementing the Gas Management Plan, which, depending on timely sanction and implementation, will enable us to eliminate almost all routine flaring, a requirement of the PSC, and more than halve our Scope 1 emissions intensity by 2025 versus the original 2020 baseline.

 

2022 Competent Person's Report

 

We are pleased to announce the 2022 Competent Person's Report, an updated independent third-party evaluation of the Company's reserves and resources prepared by ERC Equipoise. The 2022 CPR incorporates significant incremental information, including an updated field development plan, new wells, production data and further technical analysis, since the previous CPR dated 31 December 2020 also prepared by ERCE.

 

The 2022 CPR confirms the Shaikan Field's significant gross 2P reserves and 2C resources of 817 MMstb, 52 MMstb higher than the previous 2020 CPR after adjusting for production during the period. It underlines the significant growth potential of the asset, with a gross 2P reserves-to-production ratio of 31 years, based on 2022 gross production. It also reaffirms our deep understanding of the reservoir, which has produced over 117 MMstb to date.

 

Gross 2P reserves have increased 7% to 506 MMstb relative to 2020 CPR volumes adjusted for production, with 100% reserves replacement during the period. The increase is driven by the higher plateau rate of 85,000 bopd from the Jurassic reservoir, bringing more reserves volumes into the license period. Gross 1P reserves of 199 MMstb are 4% lower relative to 2020 CPR volumes adjusted for production due to prudent management of production rates to avoid traces of water ahead of water handling installation.

 

Gross 2C resources of 311 MMstb have increased 6% relative to 2020 CPR volumes due to higher planned production processing capacity.

 

Current operational activity and 2023 outlook

 

We have seen a step-up in production in 2023, with gross average year to date production of c.48,900 bopd and gross average production in March to date of c.53,500 bopd. In the last few days, we are delighted that production has exceeded 55,000 bopd.

 

Production growth has been supported by the continued ramp up of SH-16, production from SH-17, which we are gradually ramping up, and our well workover programme. Production increases have more than offset the minor impact of the temporary suspension of pipeline exports in February following the tragic earthquakes in Turkey and Syria.

 

Looking ahead to the rest of the year, we are currently reviewing our forward capital programme and 2023 net capital expenditure guidance of $160-$175 million, given continued delays to KRG payments. Our current guidance includes the completion of SH-17 and the drilling and completion of SH-18, further investment in well pad preparation and long lead items for continuous drilling and the continued progression of the production facility expansion. With further clarity around KRG payments, we would consider continued drilling following SH-18. However, we will also moderate investment levels should payment delays continue.

 

We remain focused on delivering our production guidance of 46,000-52,000 bopd, representing 11% growth at the mid-point versus 2022, as we continue to target start-up of SH-18 in Q2 2023. While we have seen strong recent production, we continue to manage well production rates ahead of water handling installation and are optimising production from a single well near the gas cap due to higher gas production, in line with our reservoir modelling. Estimated base natural declines of 6-10% per annum across the Shaikan Field remain low relative to the industry and are in line with our expectations and development plan, even following production of over 117 million barrels to date.

 

Sustainability strategy

 

We continued to deliver against our sustainability strategy in 2022, which is critical to the creation of long-term value for all our stakeholders and our licence to operate. Our strategic priorities include working safely, minimising our impact on the environment, addressing climate change, enhancing diversity & inclusion, generating local economic value and strong governance and compliance.

 

There were a number of highlights to note, which we will publish as part of our 2022 Annual Report and Sustainability Report, but I am particularly pleased that this year our disclosures are fully consistent with all of the TCFD recommendations as the Company continues to address climate-related risks and opportunities, in particular through progression of the Gas Management Plan tendering process and development of a number of other decarbonisation opportunities.

 

As we progress, we expect to see increases in our emissions principally due to higher oil production and higher gas production from a single well near the gas cap. Subject to timely sanction and implementation, the Gas Management Plan will enable us to eliminate almost all our routine flaring and more than halve our Scope 1 emissions intensity by 2025. We are also targeting further emissions reductions through other decarbonisation projects and are proceeding in the near term to eliminate methane venting from our production facility storage tanks, which we expect to complete in 2024.

 

We also continued to make a significant contribution to Kurdistan and our local communities, generating $515 million net from the Shaikan Field for the KRG, employing almost 350 Kurdistan nationals, representing three-quarters of our workforce in country, increasing our purchasing and contracting with local suppliers by 31% to $64 million and spending over $1 million gross on impactful projects for our local communities focused on agriculture, education and infrastructure. In addition, we remain focused on investing in the development of our people and improving the diversity of our teams. The proportion of women in our workforce increased to 14% in 2022 from 9% in 2021, a figure which we hope to build momentum on into 2023 and beyond.

 

John Hulme

Chief Operating Officer

 

22 March 2023

 

 

Financial review

 

		Year ended	Year ended
		31 December 2022	31 December 2021
Gross average production(1)	bopd	44,202	43,440
Dated Brent(2)	$/bbl	101.4	70.8
Realised price(1)	$/bbl	74.1	49.7
Discount to Dated Brent	$/bbl	27.2	21.1
Revenue	$m	460.1	301.4
Operating costs	$m	41.9	34.4
Gross operating costs per barrel(1)	$/bbl	3.2	2.7
Other general and administrative expenses	$m	12.2	13.6
Incurred in relation to Shaikan Field	$m	5.2	4.1
Corporate G&A	$m	7.0	9.5
Share option expense	$m	13.8	8.5
Adjusted EBITDA(1)	$m	358.5	222.7
Profit after tax	$m	266.1	164.6
Basic earnings/(loss) per share	cents	123.5	77.14
Revenue and arrears receipts(1)	$m	450.4	221.7
Net capital expenditure(1)(3)	$m	114.9	46.2
Free cash flow(1)	$m	266.5	122.2
Dividends	$m	215	100
Cash and cash equivalents	$m	119.5	169.9
Face amount of the Notes	$m	0.0	100.0
Net cash(1)	$m	119.5	69.9

 

(1)   Gross average production, realised price, gross operating costs per barrel, Adjusted EBITDA, revenue and arrears receipts, net capital expenditure, free cash flow and net cash are either non‑financial or non-IFRS measures and, where necessary, are explained in the summary of non-IFRS measures.

(2)   Weighted average GKP sales volume price.

(3)   2021 restated as the definition of net capital expenditure was amended to no longer exclude the increase/decrease of drilling and other equipment.

 

Record profitability and cash flow generation in 2022 were driven by an increase in the oil price, higher production and a continued focus on cost control. The Company increased net capital expenditure while maintaining capital discipline to drive future production growth and paid oil and gas sector leading dividends, while maintaining a robust balance sheet and prudent liquidity levels to manage potential risks, including KRG payment delays.

 

Adjusted EBITDA

 

Adjusted EBITDA increased by 61% in 2022 to $358.5 million (2021: $222.7 million), driven by a strong increase in the oil price and higher production, partly offset by higher operating costs, share option expense and capacity building payments.

 

Gross average production was 44,202 bopd in 2022, up 2% from 43,440 bopd in 2021 and within the Company's 2022 guidance range. Revenue increased by 53% to $460.1 million (2021: $301.4 million), driven by our leverage to the 43% increase in Dated Brent price from an average of $70.8/bbl in 2021 to $101.4/bbl in 2022. The increase was partially offset by a corresponding $11.4 million increase in capacity building payments to $34.9 million (2021: $23.5 million), which is a component of the KRG's entitlement from the Shaikan Field.

 

The average realised price per barrel increased by 49% in the year to $74.1/bbl (2021: $49.7/bbl), including the impact of an increase in the discount to Dated Brent to $27.2/bbl (2021: $21.1/bbl). The increase in the discount reflected a new pricing mechanism proposed by the KRG for Shaikan oil sales changing the reference price from Dated Brent to KBT, effective 1 September 2022, and increased pipeline tariffs.

 

While the Company has not accepted the proposed pricing mechanism, revenue from September 2022 to December 2022 has been recognised on this basis, resulting in an average reduction in the realised sales price versus the previous pricing mechanism over the four-month period of approximately $12/bbl or $23.4 million.

 

If the new pricing mechanism had been in place throughout 2022, the reduction in monthly Shaikan realised prices would have ranged from $4/bbl to $13/bbl versus the previous pricing mechanism, assuming KBT crude specs during Q3 2022 were representative of those during H1 2022. While it is difficult to predict how pricing will evolve going forward given the historic fluctuation of KBT prices, the KBT discount to Dated Brent has tightened since November 2022, with the impact on Shaikan realised prices versus the previous pricing mechanism decreasing to $6/bbl in February 2023.

 

Gulf Keystone continues to maintain a rigorous focus on cost control. Gross operating costs per barrel increased to $3.2/bbl in 2022 (2021: $2.7/bbl), in line with the Company's 2022 guidance range of $2.9-$3.3/bbl. The increase in operating costs in 2022 to $41.9 million (2021: $34.4 million) was primarily driven by an increase in staff costs reflecting increased activity, as well as incremental maintenance activity.

 

Other general and administrative expenses ("G&A"), comprising Shaikan Field and corporate G&A, were 10% lower in 2022 at $12.2 million (2021: $13.6 million), reflecting increased capitalisation due to accelerating capital activity resulting in a more than doubling of net capital expenditure. Share option expense in the period increased by $5.3 million to $13.8 million (2021: $8.5 million), principally due to the final contractual exercise of share option entitlements by former Directors under the 2016 Value Creation Plan ("VCP").

 

Profit after tax

 

Profit after tax increased to $266.1 million (2021: $164.6 million) driven by the increase in Adjusted EBITDA, partly offset by higher depreciation, depletion and amortisation ("DD&A") expense of $80.2 million (2021: $54.1 million) due to increased production, accelerated cost recovery as result of recent high oil prices, and updated future capital cost estimates.

 

Cash flows

 

The Company more than doubled cash from operating activities to $374.3 million (2021: $178.5 million) primarily due to the increase in Adjusted EBITDA.

 

In 2022, Gulf Keystone received revenue receipts from the KRG of $450.4 million net to GKP for crude oil sales related to the September 2021 to July 2022 invoices and repayment of arrears outstanding from November 2019 to February 2020 invoices, which were fully recovered with payment of the March 2022 invoice.

 

Since the beginning of 2023, the Company has received a further $65.7 million net to GKP for crude oil sales related to the August and September 2022 invoices. Discussions are ongoing with the KRG regarding payments for October to December 2022 crude oil sales, which are overdue and amount to $76.0 million net on the basis of the KBT pricing mechanism.

 

During the year, the Company invested net capital expenditure of $114.9 million (2021 restated: $46.2 million), in line with final 2022 guidance of $110-$120 million, to drive future profitable production growth. $63.4 million was spent on the drilling of SH-15, SH-16 and SH-17 that was completed in early 2023. $35.8 million was invested in early work for the expansion of the production facilities with water handling capacity, as well as future well pad preparation costs. $15.7 million was invested in well workover and interventions to optimise production.

 

Free cash flow generation was $266.5 million in 2022, more than double the prior year (2021: $122.2 million), enabling the Company to continue to deliver against its strategic commitment of balancing investment in growth with returns to shareholders, while maintaining a robust balance sheet.

 

In 2022, GKP paid record dividends of $215 million, representing a sector-leading dividend yield of 41% based on the closing share price on 31 December 2022.

 

In early August 2022, the Company redeemed the $100 million of notes outstanding leaving the Company debt free with significant financial capacity. Net cash increased from $69.9 million at 31 December 2021 to $119.5 million at 31 December 2022. The Company continues to maintain a robust balance sheet with cash and cash equivalents of $118.8 million at 22 March 2023.

 

As at 31 December 2022, there were $213 million gross of unrecovered costs, subject to potential cost audit by the KRG. The R-factor, calculated as cumulative gross revenue receipts of $2,078 million divided by cumulative gross costs of $1,760 million, was 1.18. The unrecovered cost pool and R-factor are used to calculate monthly cost oil and profit oil entitlements, respectively, owed to the Company from crude oil sales.

 

The Group performed a cash flow and liquidity analysis, including the impact on the Group's working capital position due to delays in revenue receipts from the KRG and the proposed revision to the lifting agreement, based on which the Directors have a reasonable expectation that the Group has adequate resources to continue to operate for the foreseeable future. Therefore, the going concern basis of accounting is used to prepare the financial statements.

 

Outlook

 

Given continued delays to KRG payments, we are currently reviewing our forward capital programme and 2023 net capital expenditure guidance of $160-$175 million. Our guidance includes $30-$35 million related to drilling costs and well workovers, $45-$50 million related to long lead items and well pad preparation and $85-$90 million related to the expansion of the production facilities and installation of water handling. With further clarity around KRG payments, we would consider continued drilling following SH-18. However, with continued payment delays we would review reductions to our capital programme.

 

We remain focused on delivering 2023 gross average production of 46,000-52,000 bopd, representing an 11% increase from 2022 at the mid-point. We also continue to target gross Opex of $3.0-$3.4/bbl in 2023, implying no change from 2022 gross Opex per barrel at the mid-point of guidance.

 

Financial framework & shareholder distributions

 

As we continue to transition towards increased investment in profitable production growth from the Jurassic reservoir through a flexible capital programme, we remain focused on balancing investment in growth with sustainable shareholder returns, while looking to maintain a robust balance sheet and prudent liquidity levels.

 

Given our oil price outlook and flexible capital programme, we currently have no hedging programme in place. We consider hedging on an ongoing basis, taking into account macro-economic and corporate considerations.

 

In line with the Company's dividend policy and financial framework, we paid an interim dividend of $25 million to shareholders on 3 March 2023 and we are pleased to declare a $25 million final 2022 ordinary dividend for shareholder approval at the Company's AGM on 16 June 2023. Total dividends declared in 2023 of $50 million equate to an 11% yield based on the closing share price on 22 March 2023.

 

The Board remains committed to distributing excess cash to shareholders by way of dividends and/or share buybacks and will continue to review further distributions based on a rigorous framework that includes an assessment of the outlook for oil prices, timeliness of payments from the KRG, expected liquidity, cash flow generation and future PSC and capital commitments.

 

Ian Weatherdon

Chief Financial Officer

 

22 March 2023

 

 

Non-IFRS measures

 

The Group uses certain measures to assess the financial performance of its business. Some of these measures are termed "non-IFRS measures" because they exclude amounts that are included in, or include amounts that are excluded from, the most directly comparable measure calculated and presented in accordance with IFRS, or are calculated using financial measures that are not calculated in accordance with IFRS. These non‑IFRS measures include financial measures such as operating costs and non-financial measures such as gross average production.

 

The Group uses such measures to measure and monitor operating performance and liquidity, in presentations to the Board and as a basis for strategic planning and forecasting. The Directors believe that these and similar measures are used widely by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity.

 

The non-IFRS measures may not be comparable to other similarly titled measures used by other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of the Group's operating results as reported under IFRS. An explanation of the relevance of each of the non-IFRS measures and a description of how they are calculated is set out below. Additionally, a reconciliation of the non-IFRS measures to the most directly comparable measures calculated and presented in accordance with IFRS and a discussion of their limitations is set out below, where applicable. The Group does not regard these non-IFRS measures as a substitute for, or superior to, the equivalent measures calculated and presented in accordance with IFRS or those calculated using financial measures that are calculated in accordance with IFRS.

 

Gross operating costs per barrel

Gross operating costs are divided by gross production to arrive at operating costs per barrel.

 

	2022	2021
Gross production (MMstb)	16.1	15.9
Gross operating costs ($ million)(1)	52.3	43.0
Gross operating costs per barrel ($ per bbl)	3.2	2.7

 

(1)   Gross operating costs equate to operating costs (see note 3) adjusted for the Group's 80% working interest in the Shaikan Field.

 

Adjusted EBITDA

Adjusted EBITDA is a useful indicator of the Group's profitability, which excludes the impact of costs attributable to tax (expense)/credit, finance costs, finance revenue, depreciation, amortisation and impairment of receivables.

 

	2022 $ million	2021 $ million
Profit after tax	266.1	164.6
Finance costs	9.7	11.4
Finance revenue	(0.6)	(0.4)
Tax credit	(0.3)	(0.9)
Depreciation of oil and gas assets	80.2	54.1
Depreciation of other PPE assets and amortisation of intangibles	1.4	1.0
Impairment of receivables	2.0	(7.1)
Adjusted EBITDA	358.5	222.7

 

Net capital expenditure

Net capital expenditure is the value of the Group's additions to oil and gas assets excluding the change in value of the decommissioning asset or any asset impairment.

 

	2022 $ million	2021 Restated(1) $ million
Net capital expenditure (note 11)	114.9	46.2

 

(1)   The definition of net capital expenditure has been amended to no longer exclude the increase/decrease of drilling and other equipment.

 

Net cash

Net cash is a useful indicator of the Group's indebtedness and financial flexibility because it indicates the level of cash and cash equivalents less cash borrowings within the Group's business. Net cash is defined as cash and cash equivalents, less current and non-current borrowings and non-cash adjustments. Non-cash adjustments include unamortised arrangement fees and other adjustments.

 

	2022 $ million	2021 $ million
Outstanding Notes	-	(99.1)
Unamortised issue costs (note 16)	-	(0.9)
Cash and cash equivalents	119.5	169.9
Net cash	119.5	69.9

 

Free cash flow

Free cash flow represents the Group's cash flows, before any dividends, share buybacks and notes redemption, including related fees.

 

	2022 $ million	2021 $ million
Net cash generated from operating activities	374.3	178.6
Net cash used in investing activities	(107.4)	(55.7)
Payment of leases	(0.4)	(0.7)
Free cash flow	266.5	122.2

 

 

 

Consolidated income statement

For the year ended 31 December 2022

 

	Notes	2022	2021
		$'000	$'000
Revenue	2	460,113	301,389
Cost of sales	3	(158,651)	(111,721)
(Increase)/decrease of impairment provision on trade receivables	14	(1,960)	7,065
Gross profit		299,502	196,733
Other general and administrative expenses	4	(12,202)	(13,643)
Share option related expenses	5	(13,756)	(8,490)
Profit from operations		273,544	174,600
Finance revenue	7	648	419
Finance costs	7	(9,655)	(11,353)
Foreign exchange gains		1,232	57
Profit before tax		265,769	163,723
Tax credit	8	325	874
Profit after tax for the year		266,094	164,597
Profit per share (cents)
Basic	9	123.52	77.14
Diluted	9	118.62	73.04

 

 

Consolidated statement of comprehensive income

For the year ended 31 December 2022

 

		2022	2021
		$'000	$'000
Profit after tax for the year		266,094	164,597
Items that may be reclassified to the income statement in subsequent periods:
Fair value losses arising in the period		-	(2,021)
Cumulative losses arising on hedging instruments reclassified to revenue		-	3,753
Exchange differences on translation of foreign operations		(1,950)	(254)
Total comprehensive income for the year		264,144	166,075

 

 

Consolidated balance sheet

 

	Notes	31 December 2022	31 December 2021
		$'000	$'000
Non-current assets
Intangible assets	10	4,307	3,583
Property, plant and equipment	11	436,443	404,205
Deferred tax asset	18	1,576	1,385
		442,326	409,173
Current assets
Inventories	13	6,372	6,018
Trade and other receivables	14	176,203	179,200
Cash and cash equivalents		119,456	169,866
		302,031	355,084
Total assets		744,357	764,257
Current liabilities
Trade and other payables	15	(128,561)	(98,800)
Non-current liabilities
Trade and other payables	15	(325)	(789)
Borrowings	16	-	(99,123)
Provisions	17	(42,546)	(43,841)
		(42,871)	(143,753)
Total liabilities		(171,432)	(242,553)
Net assets		572,925	521,704
Equity
Share capital	20	216,247	213,731
Share premium	20	528,125	742,914
Exchange translation reserve		(4,718)	(2,768)
Accumulated losses		(166,729)	(432,173)
Total equity		572,925	521,704

 

 

The financial statements were approved by the Board of Directors and authorised for issue on 22 March 2023 and signed on its behalf by:

 

Jon Harris

Chief Executive Officer

 

Ian Weatherdon

Chief Financial Officer

Consolidated statement of changes in equity

For the year ended 31 December 2022

 

		Attributable to equity holders of the Company
Notes		Share capital	Share premium	Treasury shares	Cost of hedging reserve	Exchange translation reserve	Accumulated losses	Total equity
		$'000	$'000	$'000	$'000	$'000	$'000	$'000
Balance at 1 January 2021		211,371	842,914	(2,592)	(1,732)	(2,514)	(593,422)	454,025
Profit after tax for the year		-	-	-	-	-	164,597	164,597
Cash flow hedge - fair value movements		-	-	-	1,732	-	-	1,732
Exchange difference on translation of foreign operations		-	-	-	-	(254)	-	(254)
Total comprehensive income/(expense) for the year		-	-	-	1,732	(254)	164,597	166,075
Dividends paid	25	-	(100,000)	-	-	-	-	(100,000)
Employee share schemes	24	-	-	-	-	-	1,604	1,604
Share options exercised		-	-	2,592	-	-	(2,592)	-
Share issues	20	2,360	-	-	-	-	(2,360)	-
Balance at 31 December 2021		213,731	742,914	-	-	(2,768)	(432,173)	521,704
Profit after tax for the year		-	-	-	-	-	266,094	266,094
Exchange difference on translation of foreign operations		-	-	-	-	(1,950)	-	(1,950)
Total comprehensive income for the year		-	-	-	-	(1,950)	266,094	264,144
Dividends paid	25	-	(214,789)	-	-	-	-	(214,789)
Employee share schemes	24	-	-	-	-	-	1,866	1,866
Share issues	20	2,516	-	-	-	-	(2,516)	-
Balance at 31 December 2022		216,247	528,125	-	-	(4,718)	(166,729)	572,925

 

 

 

 

Consolidated cash flow statement

For the year ended 31 December 2022

 

	Notes	2022 $'000	2021 $'000
Operating activities
Cash generated from operations	21	383,846	189,155
Interest received	7	648	419
Interest paid	16	(10,194)	(10,000)
Payment of put option premium		-	(1,043)
Net cash generated from operating activities		374,300	178,531
Investing activities
Purchase of intangible assets	10	(2,074)	(2,725)
Purchase of property, plant and equipment	21	(105,291)	(52,959)
Net cash used in investing activities		(107,365)	(55,684)
Financing activities
Payment of dividends	25	(214,789)	(100,000)
Payment of leases	22	(458)	(688)
Notes redemption	16	(100,000)	-
Notes repayment fee	16	(2,000)	-
Net cash used in financing activities		(317,247)	(100,688)
Net (decrease)/increase in cash and cash equivalents		(50,312)	22,159
Cash and cash equivalents at beginning of year		169,866	147,826
Effect of foreign exchange rate changes		(98)	(119)
Cash and cash equivalents at end of the year being bank balances and cash on hand		119,456	169,866

 

 

Summary of significant accounting policies

 

General information

Gulf Keystone Petroleum Limited (the "Company") is domiciled and incorporated in Bermuda (registered address: Cedar House, 3rd Floor, 41 Cedar Avenue, Hamilton, HM12, Bermuda); together with its subsidiaries it forms the "Group". On 25 March 2014, the Company's common shares were admitted, with a standard listing, to the Official List of the United Kingdom Listing Authority ("UKLA") and to trading on the London Stock Exchange's Main Market for listed securities. Previously, the Company was quoted on Alternative Investment Market, a market operated by the London Stock Exchange. In 2008, the Company established a Level 1 American Depositary Receipt programme in conjunction with the Bank of New York Mellon, which has been appointed as the depositary bank. The Company serves as the holding company for the Group, which is engaged in oil and gas exploration, development and production, operating in the Kurdistan Region of Iraq.

 

The financial information set out in this Results Announcement does not constitute the Company's annual report and accounts for the years ended 31 December 2021 or 2022 but is derived from those accounts. The auditors have reported on those accounts; their reports were unqualified and did not draw attention to any matters by way of emphasis without qualifying their report.

 

Amendments to International Financial Reporting Standards ("IFRS") that are mandatorily effective for the current year

In the current year, the Group has applied a number of amendments to IFRSs issued by the International Accounting Standards Board (IASB) that are mandatorily effective for an accounting period that begins on or after 1 January 2022.

 

The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2022: Reference to the Conceptual Framework (Amendments to IFRS 3), Property, Plant and Equipment - Proceeds before Intended Use (Amendments to IAS 16), Onerous Contracts - Cost of Fulfilling a Contract (Amendments to IAS 37), and Annual Improvements to IFRS Standards 2018-2020. These standards do not and are not expected to have a material impact on the Company's results or financials statement disclosures in the current or future reporting periods.

 

New and revised IFRSs issued but not yet effective

 

At the date of approval of these financial statements, the Group has not applied the following new and revised IFRSs that have been issued but are not yet effective by United Kingdom adopted International Accounting Standards:

 

IFRS 17	Insurance Contracts
Amendments to IFRS 4	Applying IFRS 9 'Financial Instruments' with IFRS 4 'Insurance Contracts'; Extension of the Temporary Exemption from Applying IFRS 9
Amendments to IAS 1	Classification of Liabilities as Current or Non-current; Classification of Liabilities as Current or Non-current - Deferral of Effective Date; Non-current Liabilities with Covenants
Amendments to IFRS 16	Lease Liability in a Sale and Leaseback
Amendments to IFRS 17	Initial Application of IFRS 17 and IFRS 9 - Comparative Information; Amends IFRS 17 to address concerns and implementation challenges that were identified after IFRS 17 Insurance Contracts was published in 2017
Amendments to IAS 1 and IFRS Practice Statement 2	Disclosure of Accounting Policies
Amendments to IAS 8	Definition of Accounting Estimates
Amendments to IAS 12	Deferred Tax related to Assets and Liabilities arising from a Single Transaction

 

The directors do not expect that the adoption of the Standards listed above will have a material impact on the financial statements of the Group in future periods.

 

Statement of compliance

The financial statements have been prepared in accordance with United Kingdom adopted International Accounting Standards.

 

Basis of accounting

The financial statements have been prepared under the historical cost basis, except for the valuation of hydrocarbon inventory and the valuation of certain financial instruments, which have been measured at fair value, and on the going concern basis. Equity-settled share-based payments are recognised at fair value at the date of grant, and are not subsequently revalued. The principal accounting policies adopted are set out below.

 

Going concern

The Group's business activities, together with the factors likely to affect its future development, performance and position, are set out in the Chairman's statement, the Chief Executive Officer's review, the Operational review and the Management of principal risks and uncertainties. The financial position of the Group at the year end and its cash flows and liquidity position are included in the Financial review.

 

As at 22 March 2023, the Group had $118.8 million of cash and no debt. The Group continues to closely monitor and manage its liquidity. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, change in commodity prices, different production rates from the Shaikan block, cost contingencies, disruptions and delays to revenue receipts, impact of climate change and geopolitical risks on the Group's operations, including the Iraqi Supreme Court ruling on 15 February 2022, as further described in key sources of uncertainty below.

 

In the current year, further consideration has been given to the impact on the Group's working capital position due to delays in revenue receipts from the KRG and the proposed revision to the lifting agreement: 

·      Revenue receipts - The timing of revenue receipts over the last 12 months has increased from an average of 20-30 days past due to 100 days for the most recent September production month payment. At the date of this report, $76.0 million is overdue for October to December 2022 oil sales; and

·      Lifting agreement: There has been no lifting agreement in place since 1 September 2022 and negotiations are ongoing around the pricing mechanism of oil sales. Instead of a Dated Brent based pricing mechanism, the KRG has proposed a Kurdistan Blend (KBT) based pricing mechanism to recognise the value they receive for oil sales, as further described in note 2.

 

The Directors believe an agreement will ultimately be reached on the terms of a revised lifting agreement, and we reasonably expect that overdue balances will be paid and payments will return to a more regular basis. However, a deferral of revenue receipts from the KRG for an extended period of time could result in liquidity pressures within the twelve month going concern period.

 

The Directors have considered sensitivities to assess the impact on the Group's liquidity position if revenue receipts from the KRG are deferred for an extended period of time. While the payment of such amounts are outside of management's control, the Directors believe sufficient mitigating actions are available to withstand potential further delays in revenue receipts until such receipts return to more routine payment terms. Mitigating actions include deferring planned capital expenditures, reducing operating and general and administrative expenses and managing supplier payment timing.

 

Overall, the Group's forecasts, taking into account the applicable risks, stress test scenarios and potential mitigating actions, show that it has sufficient financial resources for the twelve months from the date of approval of the 2022 annual report and accounts.

 

Based on the analysis performed, the Directors have a reasonable expectation that the Group has adequate resources to continue to operate for the foreseeable future. Thus the going concern basis of accounting is used to prepare the annual consolidated financial statements.

 

Basis of consolidation

The consolidated financial statements incorporate the financial statements of the Company and enterprises controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity, so as to obtain benefits from its activities.

 

Joint arrangements

The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified as joint operations in accordance with IFRS 11. The Group accounts for its share of the results and net assets of these joint operations. Where the Group acts as Operator of the joint operation, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint operation are included in the Group's balance sheet.

 

Sales revenue

The recognition of revenue is considered to be a key accounting judgement.

 

Revenue is earned based on the entitlement mechanism under the terms of the Shaikan Production Sharing Contract ("PSC"). Entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred, and profit oil, which is the mechanism through which profits are shared between the Company, its partner and the Kurdistan Regional Government ("KRG"). The Company is liable for capacity building payments calculated as a proportion of profit oil entitlement. Entitlement from cost oil and profit oil are reported as revenue, and capacity building payments are included in cost of sales.

 

All oil is sold by the Shaikan Contractor (the Company and Kalegran BV, a subsidiary of MOL Hungarian Oil & Gas Plc, ("MOL")) to the KRG, who in turn resell the oil. The selling price is determined in accordance with the principles of the crude oil lifting agreement.

 

Under IFRS 15: Revenue from contracts with customers, GKP considers that control of crude oil is transferred from the Shaikan Contractor to the KRG at the delivery point as defined in the lifting agreement, this being the export pipeline; at this point the Shaikan Contractor is due economic benefits which can be reliably measured and are probable to be received. The consideration is variable and is dependent upon the monthly average oil market price with deductions for quality and transportation fees, with other fees and royalties due as determined by commercial agreements; revenue is reported net of these deductions.

 

Effective September 1, 2022, the KRG proposed a new pricing mechanism for crude oil sales. Under the new pricing mechanism, the realised sales price for a month is based on the average market price realised by the KRG for the Kurdistan blend (KBT) sold at Ceyhan, Turkey, as advised by the KRG. The change in the benchmark market price from Brent to KBT has not yet been agreed and no lifting agreement has been in place since 1 September 2022. Nonetheless, the Shaikan Contractor continued to produce and the KRG continued to accept delivery of oil at the delivery points. GKP continues to consider that control of crude oil was transferred at the delivery points despite no commercial agreement being in place and as such has recognised revenue based on the proposed new pricing terms. A summary of the currently estimated financial impact of the proposed change in pricing mechanism is detailed in note 2.

 

During past PSC negotiations with the Ministry of Natural Resources ("MNR"), it was tentatively agreed that the Shaikan Contractor would provide the KRG a 20% carried working interest in the PSC. This would result in a reduction of GKP's working interest from 80% to 61.5%. To compensate for such decrease, capacity building payments expense would be reduced to 20% of profit petroleum. While the PSC has not been formally amended, it was agreed that GKP would invoice the KRG for oil sales based on the proposed revised terms from October 2017. The financial statements reflect the proposed revised working interest of 61.5%. Relative to the PSC terms, the proposed revised invoicing terms result in a decrease in both revenue and cost of sales and on a net basis are slightly positive for the Company.

 

As part of earlier PSC negotiations, on 16 March 2016, GKP signed a bilateral agreement with the MNR (the "Bilateral Agreement"). The Bilateral Agreement included a reduction in the Group's capacity building payment from 40% to 30% of profit petroleum. Subsequent to signing the Bilateral Agreement, further negotiations resulted in the capacity building payment rate being reduced from 30% to 20%, which has formed the basis for all oil sales invoices to date as noted above. Since PSC negotiations have not been finalised, GKP has included a non-cash payable for the difference between the capacity building rate of 20% and 30%, which is recognised in cost of sales and other payables.

 

The Company is in dialogue with the MNR to confirm whether to proceed with a formal amendment to the PSC to reflect current invoice terms.

 

Income tax arising from the Company's activities under its PSC is settled by the KRG on behalf of the Company. Since the Company is not able to measure the amount of income tax that has been paid on its behalf the notional income tax amounts have not been included in revenue or in the tax charge.

Finance revenue

Interest revenue is accrued on a time basis, by reference to the principal outstanding and at the effective rate of interest applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount on initial recognition.

 

Intangible assets

Intangible assets include computer software and are measured at cost and amortised over their expected useful economic lives of three years.

 

Property, plant and equipment ("PPE")

 

Oil and gas assets

Development and production assets

Development and production assets are accumulated on a field-by-field basis and represent the costs of acquisition and developing the commercial reserves discovered and bringing them into production, together with the exploration and evaluation expenditure incurred in finding commercial reserves, directly attributable overheads and costs for future restoration and decommissioning. These costs are capitalised as part of PPE and depreciated based on the Group's depreciation of oil and gas assets policy.

 

The net book values of producing assets are depreciated generally on a field-by-field basis using the unit of production ("UOP") basis which uses the ratio of oil and gas production in the period to the remaining commercial reserves plus the production in the period. Costs used in the calculation comprise the net book value of the field, and estimated future development expenditures required to produce those reserves.

 

Commercial reserves are proven and probable ("2P") reserves which are estimated using standard recognised evaluation techniques. The reserves estimate used in 2022 are based on the June 2022 draft FDP submitted to the MNR. The previous independent reserves report at 31 December 2020 did not reflect various known updates since completion of the report. A new Competent Person's Report reserves report has been completed by ERC Equipoise at 31 December 2022 and will be applied prospectively in the depreciation, depletion and amortisation ("DD&A") calculation from 1 January 2023.

 

Other property, plant and equipment

Other property, plant and equipment are principally equipment used in the field which are separately identifiable to development and production assets, and typically have a shorter useful economic life. Assets are carried at cost, less any accumulated depreciation and accumulated impairment losses. Costs include purchase price, construction and installation costs.

 

These assets are expensed on a straight-line basis over their estimated useful lives of 3 years from the date they are put in use.

Fixtures and equipment

Fixtures and equipment assets are stated at cost less accumulated depreciation and any accumulated impairment losses. These assets are expensed on a straight-line basis over their estimated useful lives of 5 years from the date they are available for use.

Impairment of PPE and intangible non-current assets

At each balance sheet date, the Group reviews the carrying amounts of its tangible and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset, or group of assets, is estimated in order to determine the extent of the impairment loss (if any).

 

For assets which do not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.

 

Recoverable amount is the higher of fair value less costs to sell ("FVLCTS") and value in use. In assessing FVLCTS and value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.

 

Any impairment identified is immediately recognised as an expense. Conversely, any reversal of an impairment is immediately recognised as income.

 

Borrowing costs

Borrowing costs directly relating to the acquisition or construction of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are capitalised and added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

 

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.

 

All other borrowing costs are recognised in the income statement in the period in which they are incurred.

 

Taxation

Tax expense or credit represents the sum of tax currently payable or recoverable and deferred tax.

 

Tax currently payable or recoverable is based on taxable profit or loss for the year. Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities, based on tax rates and laws that are enacted or substantively enacted by the balance sheet date.

 

As described in the revenue accounting policy section above, it is not possible to calculate the amount of notional tax in relation to any tax liabilities settled on behalf of the Group by the KRG.

 

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from the initial recognition of goodwill or from the initial recognition of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

 

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient future taxable profits will be available to allow all or part assets to be recovered.

 

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised based on tax laws and rates that have been enacted or substantively enacted by the balance sheet date. Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also recognised in equity.

 

Foreign currencies

The individual financial statements of each company are presented in the currency of the primary economic environment in which it operates (its functional currency). For the purpose of the consolidated financial statements, the results and the financial position of the Group are expressed in US dollars, which is the presentation currency for the consolidated financial statements.

In preparing the financial statements of the individual companies, transactions in currencies other than the entity's functional currency are recorded at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing on the balance sheet date. Non-monetary assets and liabilities carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Gains and losses arising on retranslation are included in the income statement for the year.

 

On consolidation, the assets and liabilities of the Group's foreign operations which use functional currencies other than US dollars are translated at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average exchange rates for the period. Exchange differences arising, if any, are recognised in other comprehensive income and accumulated in equity in the Group's translation reserve. On the disposal of a foreign operation, such translation differences are reclassified to profit or loss.

 

Inventories

Inventories, except for hydrocarbon inventories, are stated at the lower of cost and net realisable value. Cost comprises direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. Cost is calculated using the weighted average cost method. Hydrocarbon inventories are recorded at net realisable value with changes in the value of hydrocarbon inventories being adjusted through cost of sales.

 

Financial instruments

Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group has become a party to the contractual provisions of the instrument.

 

Trade receivables

Trade receivables are measured at amortised cost using the effective interest method less any impairment.

 

Cash and cash equivalents

Cash and cash equivalents comprise cash on hand and demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insignificant risk of changes in value.

 

Financial assets at fair value through profit and loss

Financial assets are held at fair value through profit and loss ("FVTPL") when the financial asset is either held for trading or it is designated as FVTPL. Financial assets at FVTPL are stated at fair value, with any gains or losses arising on re-measurement recognised in profit or loss. The net gain or loss recognised in profit or loss incorporates any dividend or interest earned on the financial asset and is included in the other gains and losses line in the income statement.

 

Derivative financial instruments

The Group may utilise derivative financial instruments to manage its exposure to oil price, foreign exchange or interest rate risk.

 

Derivatives are initially recognised at fair value at the date a derivative contract is entered into and are subsequently re-measured to their fair value at each balance sheet date. The resulting gain or loss is recognised in the profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship.

 

A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a liability. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than twelve months and it is not expected to be realised or settled within twelve months. Other derivatives are presented as current assets or current liabilities.

 

Hedge accounting

The Group uses hedge accounting for certain derivative instruments. The Group uses cash flow hedge accounting when hedging the exposure to variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability or a highly probable forecast transaction or the foreign currency risk in an unrecognised firm commitment.

 

At the inception of the hedge relationship, the Group formally designates and documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking the hedge transaction. Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is highly effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk, which is when the hedging relationship meets all of the following hedge effectiveness requirements:

 

-     there is an economic relationship between the hedged item and the hedging instrument;

-     the effect of credit risk does not dominate the value changes that result from the economic relationship; and

-     the hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group uses to hedge that quantity of hedged item.

 

If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets the qualifying criteria again.

 

The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option. The changes in the fair value of the time value of the option are recognised in other comprehensive income and accumulated in the cost of hedging reserve. If the hedged item is transaction-related, the time value is reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time-period related, then the amount accumulated in the cost of hedging reserve is reclassified to profit or loss on a rational basis - the Group applies straight-line amortisation. Those reclassified amounts are recognised in profit or loss. If the hedged item is a non-financial item, then the amount accumulated in the cost of hedging reserve is removed directly from equity and included in the initial carrying amount of the recognised non-financial item. Furthermore, if the Group expects that some or all of the profit or loss accumulated in cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.

 

Cash flow hedge

The effective portion of changes in the fair value of derivatives and other qualifying hedging instruments that are designated and qualify as cash flow hedges is recognised in other comprehensive income and accumulated under the heading of cash flow hedging reserve, limited to the cumulative change in fair value of the hedged item from inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss and is included in the revenue line item.

 

The Group discontinues hedge accounting only when the hedging relationship (or a part thereof) ceases to meet the qualifying criteria (after rebalancing, if applicable). This includes instances when the hedging instrument expires or is sold, terminated or exercised. The discontinuation is accounted for prospectively. Any gain or loss recognised in other comprehensive income and accumulated in cash flow hedge reserve at that time remains in equity and is reclassified to profit or loss when the forecast transaction occurs. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in the cash flow hedge reserve is reclassified immediately to profit or loss.

 

Impairment of financial assets

The Group recognises a loss allowance for expected credit losses ("ECL") on trade receivables and contract assets, as well as on financial guarantee contracts. The amount of expected credit losses is updated at each reporting date to reflect changes in credit risk since initial recognition of the respective financial instrument.

 

The Group always recognises lifetime expected credit losses for trade receivables, contract assets and lease receivables. The expected credit losses on these financial assets are estimated based on observed market data and convention, existing market conditions and forward-looking estimates at the end of each reporting period, including time value of money where appropriate.

 

For all other financial instruments, the Group recognises lifetime ECL when there has been a significant increase in credit risk since initial recognition. However, if the credit risk on the financial instrument has not increased significantly since initial recognition, the Group measures the loss allowance for that financial instrument at an amount equal to 12-month ECL.

 

Lifetime ECL represents the expected credit losses that will result from all possible default events over the expected life of a financial instrument. In contrast, 12-month ECL represents the portion of lifetime ECL that is expected to result from default events on a financial instrument that are possible within 12 months after the reporting date.

 

Financial liabilities and equity

Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities.

 

Equity instruments

Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs, which are charged to share premium.

 

Borrowings

Interest-bearing loans and overdrafts are recorded at the fair value of proceeds received, net of transaction costs. Finance charges, including premiums payable on settlement or redemption, are accounted for on an accrual basis and are added to the carrying amount of the instrument to the extent that they are not settled in the year in which they arise. The liability is carried at amortised cost using the effective interest rate method until maturity.

 

Trade payables

Trade payables are stated at amortised cost. The average maturity for trade and other payables is one to three months.

 

Provisions

Provisions are recognised when the Group has a present obligation as a result of a past event which it is probable will result in an outflow of economic benefits that can be reliably estimated.

 

Decommissioning provision

Provision for decommissioning is recognised in full when there is an obligation to restore the site to its original condition. The amount recognised is the present value of the estimated future expenditure for restoring the sites of drilled wells and related facilities to their original status. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related oil and gas asset. The amount recognised is reassessed each year in accordance with local conditions and requirements. Any change in the present value of the estimated expenditure is dealt with prospectively. The unwinding of the discount is included as a finance cost.

 

Share-based payments

Equity-settled share-based payments to employees and others providing similar services are measured at the fair value of the instruments at the grant date. Details regarding the determination of the fair value of equity-settled share-based transactions are set out in note 24. The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Group's estimate of equity instruments that will eventually vest. At each balance sheet date, the Group revises its estimate of the number of equity instruments expected to vest as a result of the effect of non-market based vesting conditions. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to equity reserve.

 

For cash-settled share-based payments, a liability is recognised for the goods or services acquired, measured initially at the fair value of the liability. At each balance sheet date until the liability is settled, and at the date of settlement, the fair value of the liability is re-measured, with any changes in fair value recognised in profit or loss for the period. Details regarding the determination of the fair value of cash-settled share-based transactions are set out in note 24.

 

Leases

The Group assesses whether a contract contains a lease at inception of the contract. The Group recognises a right-of-use asset and corresponding lease liability in the consolidated balance sheet for all lease arrangements longer than twelve months, where it is the lessee and has control of the asset. For all other leases, the Group recognises the lease payments as an operating expense on a straight-line basis over the term of the lease.

 

The lease liability is initially measured at the present value of the future lease payments from the commencement date of the lease. The lease payments are discounted using the interest rate implicit in the lease or, if not readily determinable, the company specific incremental borrowing rate.

 

The lease liability is subsequently measured by increasing the carrying amount to reflect interest on the lease liability (using the effective interest method) and by reducing the carrying amount to reflect the lease payments made. The lease liability is recognised in creditors as current or non current liabilities depending on underlying lease terms.

 

The right-of-use assets are initially recognised on the balance sheet at cost, which comprises the amount of the initial measurement of the corresponding lease liability, adjusted for any lease payments made at or prior to the commencement date of the lease and any lease incentive received.

 

For short-term leases (periods less than 12 months) and leases of low value, the Group has opted to recognise lease expense on a straight line basis.

 

Critical accounting judgements and key sources of estimation uncertainty

In the application of the accounting policies described above, the Group is required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

 

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of revision and future periods if the revision affects both current and future periods.

 

Critical judgements in applying the Group's accounting policies

The following are the critical judgements, apart from those involving estimations (which are presented separately below), that the directors have made in the process of applying the Group's accounting policies and that have the most significant effect on the amounts recognised in financial statements.

 

Revenue

The recognition of revenue, particularly the recognition of revenue from exports, is considered to be a key accounting judgement. The Group began commercial production from the Shaikan Field in July 2013 and historically made sales to both the domestic and export markets. The Group considers that revenue can be reliably measured as it passes the delivery point into the export pipeline. The critical accounting judgement applied in preparing the 2022 financial statements is that it is appropriate to recognise revenue for deliveries from 1 September 2022 based on the proposed new pricing mechanism, notwithstanding that there is no signed lifting agreement for that period and the pricing mechanism has not yet been agreed. Further details of this judgement are provided in the sales revenue accounting policy above. In making this judgement, consideration was given to the fact that, subsequent to the year end, the Group received payment for September 2022 deliveries at an amount that was consistent with the proposed new pricing terms.

 

A summary of the currently estimated financial impact of the proposed change in pricing mechanism is detailed in Note 2.

 

Any future agreements between the Company and the KRG might change the amounts of revenue recognised.

Key sources of estimation uncertainty

The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.

 

Carrying value of producing assets

In line with the Group's accounting policy on impairment, management performs an impairment review of the Group's oil and gas assets at least annually with reference to indicators as set out in IAS 36. The Group assesses its group of assets, called a cash-generating unit ("CGU"), for impairment, if events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Where indicators are present, management calculates the recoverable amount using key estimates such as future oil prices, estimated production volumes, the cost of development and production, potential climate change transition risk impacts, pre-tax discount rates that reflect the current market assessment of the time value of money and risks specific to the asset, commercial reserves and inflation. The key assumptions are subject to change based on market trends and economic conditions. Where the CGU's recoverable amount is lower than the carrying amount, the CGU is considered impaired and is written down to its recoverable amount.

 

The Group's sole CGU at 31 December 2022 was the Shaikan Field with a carrying value of $391.0 million (2021: $358.3 million). The Group performed an impairment trigger assessment and concluded that the Iraqi Supreme Court ruling in February 2022 and the change in the proposed basis of calculating the realised oil price from September 2022 were potential impairment triggers. Accordingly a full impairment evaluation was completed and it was concluded that no impairment write-down was required.

 

The key areas of estimation in the impairment assessment are as follows:

 

-     Commodity prices for the current year were based on the forward curve as at December 2022 for the period 2023 to 2028 with inflation of 2% per annum thereafter. Prices at 31 December 2021 were determined based on the latest internal estimates, benchmarked with external sources of information;

-     All prices below are nominal and no impairment arose under either the base or stress case.

 

Scenario ($/bbl - nominal)	2022	2023	2024	2025	2026	2027	2028
31 December 2022 - base case	n/a	83.4	78.2	74.5	71.7	69.6	68.1
31 December 2022 - stress case	n/a	75.1	70.4	67.1	64.5	62.6	61.3
31 December 2021 - base case	81	56.1	57.2	58.4	59.5	60.7	61.9
31 December 2021 - stress case	80	51.0	52.0	53.1	54.1	55.2	56.3

 

-     The Group continues to develop its assessment of the potential impacts of climate change and the associated risks, the transition to a low-carbon future and our ambition to reduce scope one per barrel CO₂ emissions by at least 50% by 2025 versus the original 2020 baseline of 38 kgCO2e per barrel dependent on the timely sanction and implementation of the Gas Management Plan. The International Energy Agency's ("IEA") Announced Pledges Scenario ("APS") and Net Zero Emissions ("NZE") climate scenario oil prices and carbon taxes were used to evaluate the potential impact of the principal climate change transition risks. The APS being that governments will meet, in full and on time, all of the climate‐related commitments that they have announced, including longer term net zero emissions targets and pledges in Nationally Determined Contributions ("NDCs") to reduce national emissions and adapt to the impacts of climate change leading to a global temperature rise of 1.7⁰C in 2100.The NZE being the normative scenario pathway to the stabilisation of global average temperatures at 1.5 °C above pre‐industrial levels. Neither adoption of the APS price scenario nor NZE price scenario, both with and without the addition of an incremental carbon tax, resulted in an impairment arising.

-     Discount rates that are adjusted to reflect risks specific to the Shaikan Field and the Kurdistan Region of Iraq ("KRI"). The impairment analysis was based on a pre-tax nominal 15% discount rate (2021: 15%). The impact of an increase in the discount rate to 20% was considered to reflect potential increased geopolitical risks and no impairment was identified;

-     Operating costs and capital expenditure that are based on financial budgets and internal management forecasts. Costs assumptions incorporate management experience and expectations, including the impact of forecast short term inflationary pressures, as well as the nature and location of the operation and the risks associated therewith. Base case costs assumptions used in the assessment reflect the latest cost estimates for the FDP, which includes the estimated cost of implementing a Gas Management Plan, as part of our ambition to reduce scope one emissions as outlined above;

-     Commercial reserves and production profiles used in the assessment are consistent with the latest draft FDP and materially consistent with the figures shown in the new independent reserves report recently completed by ERC Equipoise at 31 December 2022; and

-     Timing of revenue receipts.

 

In February 2022, the Iraqi Federal Supreme Court ("FSC") had ruled that the Kurdistan Oil and Gas Law ("KROGL") was unconstitutional and subsequently the Iraqi Ministry of Oil commenced proceedings in the Baghdad Commercial Court against International Oil Companies ("IOCs"), including Gulf Keystone, operating in the KRI seeking to nullify the PSCs issued under the KROGL. The Company understands that the Baghdad Commercial Court has issued adverse judgements against many of the IOCs, including Gulf Keystone, in absentia. The KRG continues to affirm that KROGL is validly constituted and the PSCs issued are valid and in full force and effect. The Company's operations in the Shaikan Field are currently unaffected. However, the matter continues to be closely monitored, including any potential impact on the restrictions placed on the export of crude oil, service contractors or any other parties by the Iraqi Ministry of Oil.

Notes to the consolidated financial statements

 

1 Geographical information

 

The Group's non-current assets, excluding deferred tax assets and other financial assets, by geographical location are detailed below:

 

	2022 $'000	2021 $'000
Kurdistan	436,213	402,787
United Kingdom	4,537	5,001
	440,750	407,788

 

The Chief Operating Decision Maker, as per the definition in IFRS 8, is considered to be the Board of Directors. The Group operates in a single segment, that of oil and gas exploration, development and production, in a single geographical location, the Kurdistan Region of Iraq. As a result, the financial information of the single segment is the same as set out in the consolidated statement of comprehensive income, the consolidated balance sheet, the consolidated statement of changes in equity, the consolidated cash flow statement and the related notes.

 

2 Revenue

 

	2022 $'000	2021 $'000
Oil sales	460,113	305,142
Hedging losses reclassified to revenue	-	(3,753)
	460,113	301,389

 

The Group accounting policy for revenue recognition is set out in the 'Summary of significant accounting policies', with revenue recognised upon crude oil passing the delivery points into the export pipeline.

 

From 1 January 2022 to 31 August 2022 the realised sales price was based on the weighted monthly average Dated Brent price, which was $107.3/bbl during the period (2021: $70.8/bbl) less a weighted monthly average discount of $23.3 (2021: $21.2) per barrel for quality and pipeline tariff costs. Since 1 September 2022 there has been no lifting agreement in place between the Shaikan Contractor and the KRG; production and export has continued whilst negotiations are ongoing. The KRG proposal is for a new pricing mechanism based upon the average monthly Kurdistan blend ("KBT") sales price realised by the KRG at Ceyhan, as advised by the KRG. The Company has not accepted the proposal and continues to invoice the KRG for oil sales based on the pre-1 September 2022 pricing formula.

 

Oil sales during 2022 were impacted by $2.4 million of backdated pipeline tariff increases related to 2021 (2021: nil).

 

Considering the uncertainty in respect of the pricing mechanism, the Company has concluded that it is appropriate to recognise revenue based on the proposed mechanism from September to December 2022. The revenue impact of the proposed pricing mechanism for the period is estimated to be a reduction of $23.4m. Taking into account the associated reduction in capacity building payments results in a total reduction of profit after tax for the year of $21.7 million. Any difference between the proposed and final pricing mechanism will be reflected in future periods.

 

Information about major customers

All oil sales revenue relates to sales to the KRG.

 

3 Cost of sales

 

	2022 $'000	2021 $'000
Operating costs	41,835	34,372
Capacity building payments	34,927	23,529
Change in oil inventory value	555	(348)
Depreciation of oil and gas assets and operational assets	80,225	54,168
Impairment of surplus drilling stock	1,109	-
	158,651	111,721

 

Capacity building payments have been recorded in line with the proposed pricing mechanism (see note 2); any difference between the proposed and final pricing mechanism will be reflected in future periods.

 

Further details on the depreciation of oil and gas assets and operational assets, as well as the recognition of capacity building payments, are set out in the Summary of significant accounting policies section.

 

The Company updated the depreciation calculation based on the June 2022 draft FDP submitted to the MNR including an internal reserves and cost update. This resulted in a higher DD&A per barrel rate. The new DD&A rate constitutes a change in accounting estimate and is reflected in the financial statements effective 1 January 2022.

 

The impairment of surplus drilling stocks includes the carrying value of items not anticipated to be used in future drilling operations.

 

4 Other general and administrative expenses

 

	2022 $'000	2021 $'000
Depreciation and amortisation	1,563	940
Auditor's remuneration (see below)	703	583
Other general and administrative costs	9,936	12,120
	12,202	13,643

 

Of the $12.2 million of general and administrative expenses, $5.2 million (2021: $4.1 million) were incurred in relation to the Shaikan Field.

 

	2022 $'000	2021 $'000
Fees payable to the Company's auditor for the audit of the Company's annual accounts	430	318
Fees payable to the Company's auditor for other services to the Group
- audit of the Company's subsidiaries pursuant to legislation	26	28
Total audit fees	456	346
Advisory services	112	107
Other assurance services (including a half year review)	135	130
Total fees	703	583

 

5 Share option related expense

	2022 $'000	2021 $'000
Share-based payment expense	3,266	2,255
Payments related to share options exercised	8,690	4,142
Share-based payment related provision for taxes	1,800	2,093
	13,756	8,490

 

On the final exercise of the legacy Value Creation Plan ("VCP") share options by former Directors, the Company elected to make required tax withholding settlements in cash instead of issuing and selling additional shares. This together with payment of dividends accumulated during the vesting period are the main components of the payments related to share options exercised.

 

The legacy VCP scheme totalled $9.5 million of the $13.8 million expense (2021: $3.4 million). There are no further VCP share options outstanding and the plan has been terminated.

 

6 Staff costs

 

The average number of employees and contractors (including Executive directors) employed by the Group was 460 (2021: 349); the number of full-time equivalents of these workers was 317 (2021: 237).

 

	Average number of employees			Average number of full-time equivalents
	2022	2021	2022		2021
Kurdistan	421	317	280		205
United Kingdom	39	32	37		32
Total	460	349	317		237

 

 

Staff costs were as follows:
	2022 $'000	2021 $'000
Wages and salaries	46,879	36,835
Social security costs	2,503	1,880
Share-based payment (see note 24)	4,260	3,009
	53,642	41,724

Staff costs include costs relating to contractors who are long-term workers in key positions, and are included in PPE additions, cost of sales and other general and administrative expenditure depending on the nature of such costs. Staff costs are shown gross before amounts recharged to joint operations.

7 Finance costs and finance revenue

 

	2022 $'000	2021 $'000
Notes interest expense (see note 16)	(5,833)	(10,000)
Unwinding of finance and arrangement fees (see note 16)	(879)	(489)
Notes repayment fee (see note 16)	(2,000)	-
Finance lease interest	(77)	(123)
Unwinding of discount on provisions (see note 17)	(866)	(741)
Total finance costs	(9,655)	(11,353)
Finance revenue	648	419
Net finance costs	(9,007)	(10,934)

 

On 2 August 2022 the Group redeemed the $100m notes and paid an early repayment fee (see note 16).

 

8 Income tax

 

	2022 $'000	2021 $'000
Current year credit	216	75
Prior year adjustment	-	28
Deferred UK corporation tax credit (see note 18)	109	771
Tax credit attributable to the Company and its subsidiaries	325	874

 

The Group is not required to pay taxes in Bermuda on either income or capital gains. The Group has received an undertaking from the Minister of Finance in Bermuda exempting it from any such taxes at least until the year 2035.

 

In the Kurdistan Region of Iraq, the Group is subject to corporate income tax on its income from petroleum operations under the Kurdistan PSC. Under the Shaikan PSC, any corporate income tax arising from petroleum operations will be paid from the KRG's share of petroleum profits. Due to the uncertainty over the payment mechanism for oil sales in Kurdistan, it has not been possible to measure reliably the taxation due that has been paid on behalf of the Group by the KRG and therefore the notional tax amounts have not been included in revenue or in the tax charge. This is an accounting presentational issue and there is no taxation to be paid.

 

The annual UK corporation tax rate for the year ended 31 December 2022 was 19.0% (2021: 19.0%).

 

On 3 March 2021, the UK Government announced that the corporation tax rate in the UK will increase to 25% for companies with taxable profits above £250,000 with effect from 1 April 2023, as well as announcing a number of other changes to allowances and treatment of losses. These changes were substantively enacted as at 31 December 2021.

Deferred tax is provided for due to the temporary differences, which give rise to such a balance in jurisdictions subject to income tax. All deferred tax arises in the UK.

 

9 Profit per share

 

The calculation of the basic and diluted profit per share is based on the following data:

	2022	2021
Profit after tax for basic and diluted per share calculations ($'000)	266,094	164,597
Number of shares ('000s):
Basic weighted average number of ordinary shares	215,420	213,384
Basic EPS (cents)	123.52	77.14

The Group followed the steps specified by IAS 33 in determining whether potential common shares are dilutive or anti-dilutive.

 

Reconciliation of dilutive shares:

Number of shares ('000s)	2022	2021
Basic weighted average number of ordinary shares outstanding	215,420	213,384
Effect of potential dilutive share options	8,909	11,962
Diluted number of ordinary shares outstanding	224,329	225,346
Diluted EPS (cents)	118.62	73.04

 

The weighted average number of ordinary shares in issue excludes shares held by Employee Benefit Trustee ("EBT").

 

The diluted number of ordinary shares outstanding is calculated on the assumption of the exercise of all potentially dilutive share options.

 

10 Intangible assets

 

	Computer software $'000
Year ended 31 December 2021
Opening net book value	933
Additions	2,742
Amortisation charge	(25)
Foreign currency translation differences	(67)
Closing net book value	3,583
At 31 December 2021
Cost	4,722
Accumulated amortisation	(1,139)
Net book value	3,583

 

Year ended 31 December 2022
Opening net book value	3,583
Additions	2,074
Amortisation charge	(859)
Foreign currency translation differences	(491)
Closing net book value	4,307
At 31 December 2022
Cost	6,305
Accumulated amortisation	(1,998)
Net book value	4,307

 

The amortisation charge of $859,000 (2021: $25,000) for computer software has been included in other general and administrative expenses (see note 4).

 

11 Property, plant and equipment

 

	Oil and gas assets $'000	Fixtures and equipment $'000	Right of use assets $'000	Total     $'000
Year ended 31 December 2021
Opening net book value	402,620	1,187	1,662	405,469
Additions	46,165	203	76	46,444
Disposals	-	-	(1,432)	(1,432)
Revision to decommissioning asset	7,429	-	-	7,429
Depreciation charge	(54,120)	(351)	(612)	(55,083)
Accumulated depreciation eliminated on disposal	-	-	1,405	1,405
Foreign currency translation differences	(1)	(6)	(21)	(28)
Closing net book value	402,094	1,033	1,078	404,205
At 31 December 2021
Cost	831,924	7,363	2,246	841,533
Accumulated depreciation	(429,830)	(6,330)	(1,168)	(437,328)
Net book value	402,094	1,033	1,078	404,205
Year ended 31 December 2022
Opening net book value	402,094	1,033	1,078	404,205
Additions	114,909	1,595	-	116,504
Impairment of surplus drilling stocks	(1,109)	-	-	(1,109)
Revision to decommissioning asset	(2,161)	-	-	(2,161)
Depreciation charge	(80,177)	(359)	(347)	(80,883)
Foreign currency translation differences	-	(12)	(101)	(113)
Closing net book value	433,556	2,257	630	436,443
At 31 December 2022
Cost	943,563	8,946	2,145	954,654
Accumulated depreciation	(510,007)	(6,689)	(1,515)	(518,211)
Net book value	433,556	2,257	630	436,443

 

The net book value of oil and gas assets at 31 December 2022 is comprised of property, plant and equipment relating to the Shaikan block with a carrying value of $433.6 million (2021: $402.1 million).

 

The additions to the Shaikan asset during the year include costs relating to the drilling and completion of SH-15 and SH-16, and SH-17 that was completed early 2023, well pad preparation, PF-1 and PF-2 expansion and water handling activities, and subsurface studies.

 

The decrease in the decommissioning asset represents the change in accounting estimates as detailed in note 17 partially offset by additional decommissioning activities arising from capital projects completed during the year and revisions to decommissioning cost estimates.

 

The DD&A charge of $80.2 million (2021: $54.1 million) on oil and gas assets has been included within cost of sales (note 3). The depreciation charge of $0.4 million (2021: $0.4 million) on fixtures and equipment and $0.3 million (2021: $0.6 million) on right of use assets has been included in general and administrative expenses (note 4).

 

Right of use assets at 31 December 2022 of $0.6 million (2021: $1.1 million) consisted principally of buildings.

 

For details of the key assumptions and judgements underlying the impairment assessment, refer to the "Critical accounting estimates and judgements" section of the Summary of significant accounting policies.

 

12 Group companies

 

Details of the Company's subsidiaries and joint operations at 31 December 2022 is as follows:

 

Name of subsidiary	Place of incorporation	Proportion of ownership interest	Principal activity
Gulf Keystone Petroleum (UK) Limited 6th floor New Fetter Place 8-10 New Fetter Lane London EC4A 1AZ	United Kingdom	100%	Management, support, geological, geophysical and engineering services
Gulf Keystone Petroleum International Limited Cedar House, 3rd Floor 41 Cedar Avenue Hamilton HM12 Bermuda	Bermuda	100%	Exploration, evaluation, development and production activities in Kurdistan

 

Name of joint operation	Location	Proportion of ownership interest	Principal activity
Shaikan	Kurdistan	80%	Production and development activities

 

 

 

 

 

 

13 Inventories

 

	2022 $'000	2021 $'000
Warehouse stocks and materials	6,074	5,318
Crude oil	298	700
	6,372	6,018

 

14 Trade and other receivables

 

Current receivables

	2022 $'000	2021 $'000
Trade receivables	158,032	174,634
Other receivables	16,828	3,622
Prepayments and accrued income	1,343	944
	176,203	179,200

 

Reconciliation of Trade Receivables

		2022 $'000		2021 $'000
Gross carrying amount	161,112				175,754
Less: Impairment allowance	(3,080)				(1,120)
Carrying value at 31 December	158,032				174,634

 

Gross trade receivables of $161.1 million (2021: $175.8 million) are comprised of invoiced amounts due from the KRG for crude oil sales totalling $148.9 million (2021: $163.6 million) related to August - December 2022 and a share of Shaikan amounts due from the KRG that the Group purchased from MOL amounting to $12.2 million (2021: $12.2 million).

 

As detailed in the Summary of significant accounting policies, sales revenue for September - December 2022 production and Note 2, the revenue and corresponding receivable have been recognised based on a proposed pricing mechanism. On 8 March 2023 GKP received payment for crude oil sales relating to September 2022 in line with the proposed pricing mechanism; this does not indicate that GKP has accepted the terms of this proposed pricing mechanism.

 

At 31 December 2022, overdue trade receivables relating to oil sales for August to October 2022 aggregated $99.1 million (2021: $60.4 million). Since year end, $69.0 million has been received; $40.8 million relating to August oil sales and $28.2 million relating to September oil sales, which reflects the proposed pricing mechanism based upon discounted KBT. While the Group expects to recover the full value of the outstanding invoices and purchased revenue arrears, the ECL on the overdue receivable balance of $3.1 million (2021: $1.1 million) was provided against the receivables balance in line with the requirements of IFRS 9. During the year, a $2.0 million charge was recognised due to the increase in the ECL provision (2021: credit of $7.1 million); driven by an estimated increase in the probability of counterparty default as well as an extension to the expected date of receipt of outstanding receivables.

 

The Group received the final payments in relation to the arrears outstanding at 31 December 2021 in relation to November 2019 to February 2020 invoices totaling $41.0 million during 2022. This was settled in line with the KRG's proposal to pay 50% of the difference between the monthly average dated Brent price and $50/bbl multiplied by the gross Shaikan crude oil volumes sold in the month.

 

ECL sensitivities

 

The Group's profit before tax was not materially sensitive to movements of +/-10% in production level, Brent price, loss given default or probability of default.

Other receivables

 

Other receivables includes an amount relating to advances to suppliers of $11.5 million (2021: $0.4 million) related to property, plant and equipment that are included within investing activities in the consolidated cash flow statement.

 

Included within Other receivables is an amount of $0.4 million (2021: $0.4 million) being the deposits for leased assets which are receivable after more than one year. There are no receivables from related parties as at 31 December 2022 (2021: nil). No impairments of other receivables have been recognised during the year (2021: nil).

 

15 Trade and other payables

 

Trade and other payables principally comprise amounts outstanding for trade purchases and ongoing costs.

 

The directors consider that the carrying amount of trade payables approximates their fair value.

 

Current liabilities

	2022 $'000	2021 $'000
Trade payables	3,499	6,494
Accrued expenditures	40,642	25,961
Other payables	84,035	65,927
Current lease liabilities (see note 22)	385	419
	128,561	98,800

 

Other payables include $70.7 million (2021: $56.4 million) of amounts payable to the KRG that are not expected to be paid in cash, but rather offset against historic revenue due from the KRG, which have not yet been recognised in the financial statements. Within this amount, $34.2 million (2021: $22.6 million) relates to a non-cash payable for the difference between the capacity building rate of 20% and 30% (see Summary of significant accounting policies, Sales revenue).

 

Non-current liabilities

	2022 $'000	2021 $'000
Non-current lease liability (see note 22)	325	789

 

16 Long term borrowings

	2022 $'000	2021 $'000
Liability component at 1 January	103,482	102,993
Interest expense, including unwinding of finance & arrangement fees, and notes early repayment fee	8,712	10,489
Interest paid during the year	(10,194)	(10,000)
Principal repaid in year	(100,000)	-
Settlement of notes early repayment fee	(2,000)	-
Liability component at 31 December	-	103,482

 

Liability component reported in:

 

	2022 $'000	2021 $'000
Current liabilities (see note 15)	-	4,359
Non-current liabilities	-	99,123
	-	103,482

 

In July 2018, the Group completed the private placement of a 5-year senior unsecured $100 million bond issue (the "Notes"). The unsecured Notes were guaranteed by Gulf Keystone Petroleum International Limited and Gulf Keystone Petroleum (UK) Limited, two of the Company's subsidiaries, and the key terms are summarised as follows:

 

-      maturity date was 25 July 2023;

-      the Notes were redeemable in full with a prepayment penalty; and

-      the interest rate was 10% per annum with semi-annual payment dates.

 

During the year, the Group was not in breach of any terms of the Notes.

 

On 2 August 2022 the Group redeemed the $100m bond and paid a 2% early repayment fee.

 

The Notes were traded on the Norwegian Stock Exchange and the fair value at the prevailing market price as at the balance sheet date was:

 

 

		2022 $'000	2021 $'000
Notes		-	103,750

 

As at year end, the Group's remaining contractual liability comprising principal and interest based on undiscounted cash flows is as follows:

 

	2022 $'000	2021 $'000
Within one year	-	10,000
Within two years	-	105,639
	-	115,639

 

17 Provisions

 

 

Decommissioning provision	2022 $'000	2021 $'000
At 1 January	43,841	35,671
New provisions and changes in estimates	(2,161)	7,429
Unwinding of discount	866	741
At 31 December	42,546	43,841

 

The $2.2m decrease in new provisions and changes in estimates comprises an increase relating to new drilling and facilities work of $7.6 million (2021: $10.5 million), offset by a reduction of $9.8 million (2021: $3.1 million) due to changes in inflation and discount rates. The provision for decommissioning is based on the net present value of the Group's estimated share of expenditure, inflated in line with the table below and discounted at 3.8% (2021: 2.0%), which may be incurred for the removal and decommissioning of the wells and facilities currently in place and restoration of the sites to their original state. Most expenditures are expected to take place towards the end of the PSC term in 2043.

 

	Annual Inflation Assumption (%)
	2022	2021
2022	-	2.00%
2023	5.00%	2.00%
2024	3.00%	2.00%
2025 - 2043	2.75%	2.00%

 

18 Deferred tax asset

 

The following are the major deferred tax liabilities and assets recognised by the Group and movements thereon during the current and prior reporting periods. The deferred tax assets arise in the United Kingdom.

 

	Accelerated tax depreciation $'000	Share-based payments   $'000	Tax losses carried forward $'000	Total     $'000
At 1 January 2021	(115)	732	-	617
(Charge)/credit to income statement	(381)	321	831	771
Exchange differences	1	(4)	-	(3)
At 31 December 2021	(495)	1,049	831	1,385
(Charge)/credit to income statement	(139)	241	223	325
Exchange differences	62	(109)	(87)	(134)
At 31 December 2022	(572)	1,181	967	1,576

 

 

19 Financial instruments

	2022 $'000	2021 $'000
Financial assets
Cash and cash equivalents	119,456	169,866
Receivables	162,990	178,258
	282,446	348,124
Financial liabilities
Trade and other payables	128,886	99,589
Borrowings	-	99,123
	128,886	198,712

 

All financial liabilities, except for non-current lease liabilities (see note 15), are due to be settled within one year and are classified as current liabilities. All financial liabilities are recognised at amortised cost.

 

Fair values of financial assets and liabilities

With the exception of the Notes, and the receivables from the KRG which the Group expects to recover in full (see note 14), the Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. On 2 August 2022 the company redeemed the Notes, therefore no amount remained outstanding at 31 December 2022 (2021: fair value as determined using market values of $103.8 million; carrying value of $99.1 million).

 

In making the above assessment, consideration has been given to the fair value hierarchy set out in IFRS 13. Fair value hierarchy levels 1 to 3 are based on the degree to which the fair value is observable:

·      Level 1 fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities;

·      Level 2 fair value measurements are those derived from inputs other than quoted prices included with Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices); and

·      Level 3 fair value measurements are those derived from valuation techniques that include inputs for the asset or liability that are not based on observable market date (unobservable inputs).

The fair value of the Notes disclosed above is based on Level 1 in the hierarchy.

 

The financial assets balance includes a $3.1 million provision against trade receivables (2021: $1.1 million) (see note 14). All financial assets, except derivatives designated as a hedge, are measured at amortised cost.

 

Capital Risk Management

The Group manages its capital to ensure that the entities within the Group will be able to continue as going concerns while maximising the return to stakeholders through the optimisation of the debt and equity structure. The capital structure of the Group consists of cash, cash equivalents, Notes (in prior year) and equity attributable to equity holders of the parent. Equity comprises issued capital, reserves and accumulated losses as disclosed in note 20 and the Consolidated statement of changes in equity.

 

Capital Structure

The Company's Board of Directors reviews the capital structure on a regular basis and will make adjustments in light of changes in economic conditions. As part of this review, the Board considers the cost of capital and the risks associated with each class of capital.

 

Significant Accounting Policies

Details of the significant accounting policies and methods adopted, including the criteria for recognition, the basis of measurement and the basis on which income and expenses are recognised, in respect of each class of financial asset, financial liability and equity instrument are disclosed in the Summary of significant accounting policies.

 

Financial Risk Management Objectives

The Group's management monitors and manages the financial risks relating to the operations of the Group. These financial risks include market risk (including commodity price, currency and fair value interest rate risk), credit risk, liquidity risk and cash flow interest rate risk.

 

As at year end, the Group did not hold any derivative assets to hedge against commodity price declines or any other financial risks. The Group does not use derivative financial instruments for speculative purposes.

 

The risks are closely reviewed by the Board on a regular basis and, where appropriate, steps are taken to ensure these risks are minimised.

 

Market risk

The Group's activities expose it primarily to the financial risks of changes in oil prices, foreign currency exchange rates and changes in interest rates in relation to the Group's cash balances.

 

There have been no changes to the Group's exposure to other market risks. The risks are monitored by the Board on a regular basis.

 

The Group conducts and manages its business predominantly in US dollars, the operating currency of the industry in which it operates. The Group also purchases the operating currencies of the countries in which it operates routinely on the spot market. Cash balances are held in other currencies to meet immediate operating and administrative expenses or to comply with local currency regulations.

 

At 31 December 2022, a 10% weakening or strengthening of the US dollar against the other currencies in which the Group's monetary assets and monetary liabilities are denominated would not have a material effect on the Group's net assets or profit.

 

Interest rate risk management

The Group's policy on interest rate management is agreed at the Board level and is reviewed on an ongoing basis. The current policy is to maintain a certain amount of funds in the form of cash for short-term liabilities and have the rest on relatively short-term deposits, usually between one and three months, to maximise returns and accessibility. Prior to redeeming the Notes in August 2022, the Company paid interest on its Notes semi-annually in cash at 10% per annum.

 

Based on the exposure to interest rates for cash and cash equivalents at the balance sheet date, a 0.5% increase or decrease in interest rates would not have a material impact on the Group's profit. A rate of 0.5% is used as it represents management's assessment of a reasonable change in interest rates.

 

Credit risk management

Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. As at 31 December 2022, the maximum exposure to credit risk from a trade receivable outstanding from one customer is $161.1 million (2021: $175.8 million). Although the Group is confident in the recovery of the trade receivables balance, a provision of $3.1 million (2021: $1.1 million) was recognised against the trade receivables balance.

 

The credit risk on liquid funds is limited because the counterparties for a significant portion of the cash and cash equivalents at the balance sheet date are banks with investment grade credit ratings assigned by international credit-rating agencies.

 

Liquidity risk management

Ultimate responsibility for liquidity risk management rests with the Board of Directors. It is the Group's policy to finance its business by means of internally generated funds, external share capital and debt. The Group seeks to raise further funding as and when required.

20 Share capital

 

	2022 $'000	2021 $'000
Authorised
Common shares of $1 each (2021: $1 each)	231,605	231,605
Non-voting shares of $0.01 each	500	500
Preferred shares of $1,000 each	20,000	20,000
Series A Preferred shares of $1,000 each	40,000	40,000
	292,105	292,105

 

	Common shares
	No. of shares	Share capital	Share premium	Total amount
	'000	$'000	$'000	$'000
Balance 1 January 2021	211,371	211,371	842,914	1,054,285
Dividends paid	-	-	(100,000)	(100,000)
Shares issued	2,360	2,360	-	2,360
Balance 31 December 2021	213,731	213,731	742,914	956,645
Dividends paid	-	-	(214,789)	(214,789)
Shares issued	2,516	2,516	-	2,516
Balance 31 December 2022	216,247	216,247	528,125	744,372

 

At 31 December 2022, a total of 0.4 million common shares at $1 each were held by the EBT (2021: 0.1 million at $1 each). These common shares were included within reserves.

 

Rights attached to share capital

The holders of the common shares have the following rights (subject to the other provisions of the Byelaws):

 

(i)	entitled to one vote per common share;
(ii)	entitled to receive notice of, and attend and vote at, general meetings of the Company;
(iii)	entitled to dividends or other distributions; and
(iv)	in the event of a winding-up or dissolution of the Company, whether voluntary or involuntary or for a reorganisation or otherwise or upon a distribution of capital, entitled to receive the amount of capital paid up on their common shares and to participate further in the surplus assets of the Company only after payment of the Series A Liquidation Value (as defined in the Byelaws) on the Series A Preferred Shares.

21 Cash flow reconciliation

 

	Notes	2022	2021
		$'000	$'000
Cash flows from operating activities
Profit from operations		273,544	174,600
Adjustments for:
Depreciation, depletion and amortisation of property, plant and equipment (including the right of use assets)		80,883	55,111
Amortisation of intangible assets		859	25
Increase/(Decrease) of provision for impairment of trade receivables	14	1,960	(7,065)
Put option hedging losses reclassified to revenue		-	3,752
Share-based payment expense	24	1,866	1,197
Impairment of PPE items		1,109	-
Operating cash flows before movements in working capital		360,221	227,620
Increase in inventories		(354)	(258)
Decrease/(Increase) in trade and other receivables		11,640	(75,259)
Increase in trade and other payables		12,339	36,977
Income taxes received		-	75
Cash generated from operations		383,846	189,155

 

Reconciliation of property, plant and equipment additions to cash flows from purchase of property, plant and equipment:

	2022 $'000	2021 $'000
Associated cash flows
Additions to property, plant and equipment	116,617	46,417
Movement in working capital	(11,214)	6,927
Non-cash movements
Capitalised share option charges	-	(409)
Foreign exchange differences	(112)	24
Purchase of property, plant and equipment	105,291	52,959

 

Movement in financing related liabilities

The Group's financing related liabilities are comprised of borrowings and lease liabilities. The movements in borrowings are shown in note 16 and the movements in lease liabilities in the year were primarily cash payments of $0.7 million (2021: $0.7 million).

22 Lease Liabilities

 

During 2022, the total cash outflows relating to leased assets was $0.5 million (2021: $0.7 million); this amount is the total of capital repayments, interest charges and foreign exchange impact.

	2022 $'000	2021 $'000
Analysed as:
Current liabilities (note 15)	385	419
Non-current liabilities (note 15)	325	789
	710	1,208
Lease liability maturity analysis
Year 1	385	419
Year 2	325	789
Amounts payable under leases
Within one year	436	509
In the second to fifth year inclusive	339	868
	775	1,377
Less future interest charges	(65)	(169)
Net present value of lease obligations	710	1,208

 

23 Commitments

 

Exploration and development commitments

 

Additions to property, plant and equipment are generally funded with the cash flow generated from the Shaikan Field. As at 31 December 2022, gross capital commitments in relation to the Shaikan Field were estimated to be $41.9 million (2021: $20.6 million).

 

24 Share-based payments

	2022 $'000	2021 $'000
Total share options charge	3,266	2,664
Capitalised share options charge	-	(409)
Share options charge in Income Statement	3,266	2,255

 

Value Creation Plan ("VCP")

 

The VCP was approved by shareholders in December 2016. As at 31 December 2022, nil (2021: 3.5 million) nil-cost share options were outstanding under the VCP. There will be no further awards under the plan.

 

During the year, the awards that were outstanding at 31 December 2021 vested, with the Company achieving a Total Shareholder Return ("TSR") of at least 8% compound annual growth, in accordance with the VCP rules.

 

	2022 Number of share options '000	2021 Number of share options '000
Outstanding at 1 January	3,508	7,017
Exercised during the year	(3,508)	(3,509)
Outstanding at 31 December	-	3,508
Exercisable at 31 December	-	3,508

 

No VCP options remained outstanding at 31 December 2022 with all remaining awards at 2021 year end fully exercised in 2022.

 

Staff Retention Plan

 

At the 2016 Annual General Meeting ("AGM"), shareholders approved the adoption of the Gulf Keystone Petroleum 2016 Staff Retention Plan ("SRP"), which is designed to reward members of staff through the grant of share options at a zero exercise price.

 

The exercise of the nil-cost awarded options is not subject to any performance conditions and can be exercised at any time after the three year vesting period but within ten years after the date of grant. If options are not exercised within ten years, the options will lapse and will not be exercisable. If an employee leaves the company during the three years from the date of grant, the options will lapse on the date notice to leave is given to the company. Should an employee be regarded as a good leaver as defined in the scheme rules, the options may be exercised at any time within a period of six months from departure date.

 

	2022 Number of share options '000	2021 Number of share options '000
Outstanding at 1 January	65	973
Exercised during the year	(55)	(908)
Outstanding at 31 December	10	65
Exercisable at 31 December	10	65

 

 

The weighted average share price at the date of exercise for share options exercised during the year was £2.56 (2021: £1.70).

 

During the year no options (2021: nil) were granted to employees under the Group's SRP.

 

A charge of nil (2021: nil) in relation to the SRP is included in the total share options charge.

 

Share options outstanding at the end of the year have the exercise price of nil and the following expiry dates:

 

Expiry date	Options ('000)
	2022	2021
11 December 2026	9	12
30 June 2027	1	53
	10	65

 

The options outstanding at 31 December 2022 had a weighted average remaining contractual life of 4 years.

 

Long Term Incentive Plan

 

The Gulf Keystone Petroleum 2014 Long Term Incentive Plan ("LTIP") is designed to reward members of staff through the grant of share options at a zero exercise price, that vest three years after grant, subject to the fulfilment of specified performance conditions. These performance conditions are 50% TSR over the vesting period and 50% the Group's TSR relative to a bespoke group of comparators.

 

	2022 Number of share options '000	2021 Number of share options '000
Outstanding at 1 January	8,275	7,254
Granted during the year	2,278	2,747
Exercised during the year	(586)	(1,014)
Forfeited during the year	(1,182)	(712)
Outstanding at 31 December	8,785	8,275
Exercisable at 31 December	-	-

 

The weighted average share price at the date of exercise for share options exercised during the year was £2.44 (2021: £1.69).

 

The inputs into the calculation of fair values of the shares granted during the year are as follows:

 

	2022	2021
Weighted average share price	£2.44	£2.26
Weighted average exercise price	Nil	Nil
Expected volatility	57.7%	58.7%
Expected life	3 years	3 years
Risk-free rate	0.14%	0.14%
Expected dividend yield (on the basis dividends equivalents received)	Nil	Nil

 

The options outstanding at 31 December 2022 had a weighted average remaining contractual life of 2 years.

 

The aggregate of the estimated fair value of options granted in 2022 is $5.0 million (2021 $4.3 million).

 

A charge of $3.1 million (2021: $2.5 million) in relation to the LTIP is included in the total share options charge.

25 Dividends

 

During 2022 a total of $215 million (2021: $100 million) of dividends were paid to shareholders including an ordinary dividend of $25 million (11.561 US cents per Common Share), a special dividend of $50 million (23.12 US cents per Common Share) and interim dividends totalling $140 million (65.27 US cents per Common Share).

 

To date in 2023 an interim dividend of $25 million has been paid. An ordinary dividend of $25million is subject to approval at the AGM on 16 June 2023.

 

26 Related party transactions

 

The Company has a related party relationship with its subsidiaries and in the ordinary course of business, enters into various sales, purchase and service transactions with joint operations in which the Company has a material interest. These transactions are under terms that are no less favourable to the Group than those arranged with third parties.

 

Remuneration of Directors and Officers

 

The remuneration of the Directors and Officers who are considered to be key management personnel is set out below in aggregate for each of the categories specified in IAS 24 Related Party Disclosures. The Directors and Officers who served during the year ended 31 December 2022 were as follows:

 

J Huijskes - Non-Executive Chairman

M Angle - Deputy Chairman

G Soden - Non-Executive Director

D Thomas - Non-Executive Director

K Wood - Non-Executive Director

W Mwaura - Non-Executive Director (appointed July 2022)

J Harris - Chief Executive Officer

I Weatherdon - Chief Financial Officer

G Papineau-Legris - Chief Commercial Officer

C Kinahan - Chief Human Resources Officer

A Robinson - Chief Legal Officer and Company Secretary

S Catterall - Chief Operating Officer (resigned February 2022)

J Hulme - Chief Operating Officer (appointed April 2022)

 

The values below are calculated in accordance with IAS 19 and IFRS 2.

	2022 $'000	2021 $'000
Short-term employee benefits	4,725	5,809
Share-based payment - options	1,499	1,012
	6,224	6,821

 

Further information about the remuneration of individual Directors is provided in the Directors' Emoluments section of the Remuneration Committee Report.

 

27 Contingent Liabilities

 

The Group has a contingent liability of $27.3 million (2021: $27.3 million) in relation to the proceeds from the sale of test production in the period prior to the approval of the original Shaikan Field Development Plan ("FDP") in June 2013. The Shaikan PSC does not appear to address expressly any party's rights to this pre-FDP petroleum. The sales were made based on sales contracts with domestic offtakers which were approved by the KRG. The Group believes that the receipts from these sales of pre-FDP petroleum are for the account of the Contractor, rather than the KRG and accordingly recorded them as test revenue in prior years. However, the KRG has requested a repayment of these amounts and the Group is currently involved in negotiations to resolve this matter. The Group has received external legal advice and continues to maintain that pre-FDP petroleum receipts are for the account of the Contractor. This contingent liability forms part of the ongoing Shaikan PSC amendment negotiations and it is likely that it will be settled as part of those negotiations.