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Gulf Keystone Petrol (GKP)

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Thursday 28 March, 2019

Gulf Keystone Petrol

2018 Full Year Results

RNS Number : 2525U
Gulf Keystone Petroleum Ltd.
28 March 2019
 

 

 

28 March 2019

Gulf Keystone Petroleum Ltd. (LSE: GKP)

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

 

2018 Full Year Results Announcement

Record profit after tax and declaration of first dividend on strong financial performance

On track for 55,000 bopd in Q1 2020 as next milestone in phased production uplift

 

 

Gulf Keystone Petroleum, a leading independent operator and producer in the Kurdistan Region of Iraq ("Kurdistan" or "Kurdistan Region") announces its results for the full year ended 31 December 2018.

 

Highlights to 31 December 2018 and post reporting period

 

Financial

 

·      Record revenue of $250.6 million (FY 2017: $172.4 million)

·      EBITDA of $149.3 million (FY 2017: $104.3 million)

·      Profit after tax of $79.9 million (FY 2017: $14.1 million)

·      Net capital investment in Shaikan of $35.7 million (FY 2017: $8.1 million)

·      Cash balance of $295.6 million at year end (2017: $160.5 million)

·      The Company anticipates being fully funded for all phases of the Shaikan expansion
programme under its current set of assumptions

·      $100 million bond refinancing in July 2018

 

Dividend

 

·      The Board confirms a dividend policy to shareholders, which will comprise an annual dividend on the ordinary shares of the Company of no less than $25 million per financial year

·      The Company is therefore pleased to announce its intention to pay an ordinary dividend on the ordinary shares of $25 million in 2019 and, given its current financial strength, the Board is also proposing to complement the ordinary dividend in 2019 with a $25 million supplemental dividend to shareholders on the ordinary shares

·      The total dividend of $50 million will be subject to approval at the next AGM in June 2019.  One third of the total dividend will be paid following approval at the Company's AGM, with the balance payable following release of the Company's half-year results

 

Operational

 

·      Full year gross average production of 31,563 bopd (2017: 35,298), at the upper end of guidance

·      GKP and its partner MOL reached agreement with the MNR in June 2018 to recommence investment into Shaikan, towards an initial production target of 55,000 bopd by Q1 2020

·      Common vision for a phased development that will grow gross Shaikan production to 110,000 bopd

·      The development vision described by the revised Field Development Plan ("FDP") was submitted in October 2018. This revision has not been accepted by the MNR, specifically due to a request for additional assurances on the timing and commitment to eliminate gas flaring. As the parties aim to progress this matter and reach an agreement, investment on the ground continues as per the initial phases of this plan

·      On target to achieve plant de-bottlenecking by year-end and tie-in of the pipeline from PF-1 to the export system mid-year

·      GKP internal review indicates an upgrade in Proven (1P) reserves and no material changes to Probable reserves (2P). A revised Competent Person's Report to be released following FDP approval

·      Robust HSSE performance with one LTI in 2018, the first in three years

 

Corporate

 

·      Signature of Crude Oil Sales Agreement in January 2018 normalised payments in line with oil prices and production.  Renewed in February 2019 through to 2020 providing certainty over payments for the foreseeable future

·      Further strengthening of the Board in 2018 with Jaap Huijskes appointed as Non-Executive Chairman, Martin Angle as Senior Independent Non-Executive Director and Kimberley Wood as Non-Executive Director

 

Outlook

 

·      On track for material uplift in production to 55,000 bopd in Q1 2020

·      In 2019, gross Capex associated with 55,000 bopd phase of between $130 million and $150 million, in addition to $20 million to $45 million associated with the subsequent development phase

·      Dividend distribution from 2019 onwards

·      Gross production guidance for 2019 unchanged at 32,000 - 38,000 bopd

 

Jón Ferrier, Gulf Keystone's Chief Executive Officer, said:

 

"Throughout 2018, our focus was on laying the foundations for the delivery of the Company's phased growth plans, which envisages a step change in production profile.  The Company is on track to achieve its near-term production target of 55,000 bopd in Q1 2020, and with our partner MOL continues to work towards delivering the staged investment programme. The remarkable Shaikan reservoir presents a straightforward, low-cost onshore development opportunity with unrivalled near-term upside.

 

The new dividend policy represents another major milestone for the Company. It crystallises returns to shareholders while we preserve the ability to fully fund the Shaikan development and maintain a strong balance sheet; our platform for growth."

 

Capital Markets Event

 

Gulf Keystone will host a Capital Markets Event for analysts and institutional investors.  This will be webcast live today at 10am on the Company's website www.gulfkeystone.com

 

Enquiries:

 

Celicourt Communications:

+44(0) 20 7520 9266

Mark Antelme

Jimmy Lea

 

 

or visit: www.gulfkeystone.com

 

The information communicated in this announcement is inside information for the purposes of Article 7 of Regulation 596/2014.

 

 

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

 

I am pleased to report that 2018 was a pivotal year for Gulf Keystone when following an extensive period of negotiations, the Company recommenced investment into the Shaikan oil field.  This could not have happened without the diligent work of the Company and the continued support from the Kurdistan Regional Government ("KRG") and the Ministry of Natural Resources of the KRG ("MNR").  Following our agreement with the KRG and our partner MOL Hungarian Oil & Gas plc ("MOL"), Gulf Keystone will ramp up gross production capacity to 55,000 barrels of oil per day ("bopd") at Shaikan, which we expect to achieve in Q1 2020.

 

As with other oil and gas companies across the globe, the strong oil price in 2018 was a favourable macro factor for Gulf Keystone.  Whilst prices eased towards the end of the period, the increase in value from a low of $55 a barrel for Brent crude in Q4 2017 to a high of $86 a barrel in 2018 meant the Company was able to announce a record profit after tax for the year of $79.9 million.  The combination of stable production and exports, regular payments from the KRG since September 2015 and a new bond, secured in July 2018, has enabled Gulf Keystone to build a robust balance sheet, leaving the Company well financed for the future development of Shaikan.

 

Kurdistan remained largely stable during the reporting period and we were able to significantly advance our development plans for Shaikan whilst enjoying safe and secure operating conditions.  The revised Field Development Plan ("FDP") submitted to the MNR in October 2018, has not been accepted.  However, both GKP and MOL are aligned on a vision for the development of Shaikan and continue to make considerable operational headway with the necessary construction and drilling works that will enable the Company to meet its production target of 55,000 bopd in Q1 2020 - an important milestone on the way to full development of the field.

 

Strong corporate governance continued to be a priority for the Company, with the composition of the Board changing considerably during the year.  After many years of distinguished service, Philip Dimmock stood down as Senior Independent Director in July 2018 and was replaced by Martin Angle, who brings substantial financial, commercial and boardroom experience to the Company. Kimberley Wood also joined the Board in 2018, as a Non-Executive Director.  Kimberley adds significant legal expertise to the Board with over 18 years in the oil and gas sector, advising a wide range of oil and gas companies during this time.  In line with industry best practice we remain committed to maintaining a strong, independent Board.  We also continue to strive to achieve greater diversity throughout all levels of the business and see the further development of our extensive local employee workforce as being pivotal to the success of the Company.

 

Following a period of significant commercial and operational achievements in Kurdistan, the Board has decided to establish a dividend policy to ordinary shareholders, which comprises an annual dividend on the ordinary shares of the Company of no less than a total of $25 million per financial year, payable semi-annually and split between an interim and final payment (1/3:2/3).

 

The Company is therefore pleased to announce its intention to pay an ongoing ordinary dividend on the ordinary shares of $25 million in 2019 and, given its current financial strength, the Board is also proposing to complement this ordinary dividend in 2019 by a $25 million supplemental dividend to shareholders on the ordinary shares.  The total dividend of $50 million for 2019 will be subject to approval at the next AGM in June 2019.  It is the Board's current intention that one third of the total dividend will be paid following approval at the Company's AGM, with the balance payable following release of the Company's half-year results on dates to be determined in due course.

 

In future periods of strong cash flow generation, the Board will also look to complement the annual ordinary dividend with further supplemental dividends to shareholders while preserving its ability to grow the business.  

 

When setting the appropriate ordinary, and any supplemental, dividend levels in future periods, the Board of Directors will look at a range of factors including; inter alia, the macro environment including the oil price, the commercial environment, the balance sheet of the Company, and all current and future investment plans. The payment of any dividend will be subject at all times to appropriate Board and shareholder approvals and compliance with Bermuda law.

 

I have relished my first year as Chairman of Gulf Keystone and believe the Company has made considerable positive progress during 2018.  I would like to thank our shareholders for their continued support during what has been a busy time for the business.  On a final note, I would like to express my gratitude to all of the Company's employees, whose hard work and dedication over the last year has enabled the business to recommence investment into Shaikan, which has the potential to deliver significant value to all stakeholders for the foreseeable future.

 

 

EXECUTIVE REVIEW

 

Throughout 2018, our focus was on laying the foundations for the delivery of the Company's phased growth plans, which entail an unrivalled step change in production profile.  In this regard, 2018 was another successful year for Gulf Keystone.  The Company is on track to achieve its near-term production target of 55,000 bopd in Q1 2020, and with our partner MOL, continues to work towards delivering the staged investment programme, which is expected to lead ultimately to a gross production of up to 110,000 bopd. 

 

We are pleased to report that the Shaikan Field maintained its track record of consistent performance, allowing the Company to announce full year gross average production of 31,563 bopd, at the upper end of the guidance range of 27,000 - 32,000 bopd.  There have been no signs of water or gas breakthrough and quality of the crude produced at Shaikan has remained consistent.

 

2018 began favourably with the Company announcing its first Crude Oil Sales Agreement, ensuring that payments were normalised in line with oil prices and actual production from Shaikan.  Importantly, this paved the way for the Company to once again invest in Shaikan.  In February 2019, the Company renewed the Crude Oil Sales Agreement through to 2020, giving Gulf Keystone greater certainty over oil sales payments for the foreseeable future. 

 

After a detailed planning phase, GKP began an extensive work programme in the second half of 2018, which is now fully underway.  GKP has gone to considerable lengths to mitigate risks where it can with its Shaikan expansion plans.  Given the project is onshore and the reservoir is well understood, the Company believes that the project carries relatively low execution risk.

 

The development vision of the Shaikan Field is described by the revised FDP which was submitted in October 2018.  This revision was not accepted by the MNR, in particular due to a request for additional assurances on the timing and commitment to eliminate gas flaring - the single most complex and expensive component of the field's development.  We are hopeful that GKP along with MOL will reach an agreement with the MNR for the benefit of all parties.  As the parties progress this matter, investment on the ground continues as per the initial phases of the plan.

 

The Company is in a robust financial position, and a disciplined approach to capital management remains central to everything we do.  In 2018, the Company continued to receive regular oil payments from the KRG, with cash receipts in the year totalling $225 million net to GKP.  At the time of this report, the cash balance stands at $296 million.  It is also important to stress that the Company has immaterial outstanding revenue arrears.  Under our current market assumptions and predicted field performance, the Company is now fully funded for all phases of the Shaikan expansion programme, up to 110,000 bopd.  The gross capital expenditure guidance for the 55,000 bopd phase of the uplift in production remains unchanged between $200 million to $230 million gross.  With imminent growth in production, the Company expects to accelerate recovery of the ca.$500 million outstanding petroleum cost pool (gross). As a result of this robust financial position, the Board was pleased to confirm a dividend policy effective this year, subject to approval by the shareholders at the next AGM.

 

The Company has spoken in the past of discussions with the MNR and MOL which could potentially lead to an amendment to the existing Shaikan Production Sharing Contract ("PSC") where the MNR is seeking a carried interest that is common in many other PSCs in the Kurdistan Region of Iraq.  Should a new PSC amendment be concluded, the Company is confident that the revised fiscal terms are expected to be at least value neutral to GKP.  This matter has no reason to impede development progress, investment and increasing production from Shaikan, as evidenced by our considerable activity in 2018 which continues apace in 2019.  

 

The Company has received final clearance from Sonatrach in relation to the Ferkane Permit (Block 126).  This officially marks Gulf Keystone's exit from its Algerian operations.  This positive development has allowed the Company to release $10 million of past liabilities, with no further costs to be incurred. 

 

Ensuring the safety of our people remains our number one priority and we are pleased to have maintained a strong track HSSE record throughout 2018.  As the operational tempo increases, so do risks in the workplace; there can be no complacency with our HSSE performance.

 

2019 is set to be another significant year for the Company as we continue to create value for all of our stakeholders, in particular our shareholders and the Kurdistan Region of Iraq.

 

 

 

Key Financial Highlights 

 

 

 

Year Ended

Year Ended

31 December 2018

$'000

31 December 2017

$'000

 

 

 

Gross average production (bopd)

31,563

35,298

 

 

 

Realised price ($/bbl)

49.0

34.6

 

 

 

Revenue

250.6

172.4

 

 

 

Operating costs ($m)1

(30.7)

(28.8)

 

 

 

Operating costs per bbl ($/bbl)1

(3.2)

(2.7)

 

 

 

General and administrative expenses ($m)

(17.8)

(21.3)

 

 

 

Profit from operations ($m)

78.2

24.1

 

 

 

Profit after tax ($m)

79.9

14.1

 

 

 

Basic earnings per share (cents)

34.84

6.16

 

 

 

EBITDA ($m)1

149.3

104.3

 

 

 

Capital investment ($m) 1

35.7

8.1

 

 

 

Net cash ($m) 1

191.2

58.5

 

 

 

Net increase in cash ($m)

135.2

67.0

 

 

 

Revenue receipts ($m)

224.7

132.0

 

1 Operating costs, operating costs per barrel, EBITDA, capital investment and net cash are either non-financial or non-IFRS measures and are explained in the summary of significant accounting policies.

Revenues

 

The Group has delivered a year of strong financial results. 2018 revenue stands at $250.6 million (2017: $172.4 million), the highest recorded level since the Group started selling its Shaikan crude oil.  This is the result of a higher Brent price and the signing of a Crude Oil Sales agreement in January 2018 which allowed the Group to receive revenues based on its entitlement rather than the capped amount of $12 million (net) received for the first nine months of 2017.  Revenue recognised includes $16.2 million MNR liability offset (2017: $14.9 million).

 

The Group continues to recognise revenues on a cash receipt assured basis, leaving past revenue arrears off balance sheet.  The Group's current assessment is that the possible range of revenue arrears is not material.

 

Operating costs, depreciation, other cost of sales and administrative expenses

 

The Group's operating costs increased to $30.7 million (2017: $28.8 million) as the Group undertook certain one-off maintenance projects during the year and started incurring costs associated with the preparation for the future production ramp up, mostly in relation to hiring additional resource.

 

Other cost of sales components include depletion and amortisation of oil and gas assets, capacity building charge, production bonuses, and certain other cost of sales such as the cost of trucking oil to Fishkhabour and oil inventory movements.  Cost of sales increased to $154.5 million (2017: 127.0 million), which was mostly driven by the production bonus of $16.0 million (2017: $nil) and transportation costs of $14.3 million (2017: $2.4 million).  With the completion of the export pipeline from PF-1 to the main export pipeline expected to become operational mid-year, trucking costs will be eliminated.

 

General and administrative expenses ("G&A") have come down from $21.3 million in 2017 to $17.8 million in 2018, with the Kurdistan office contributing $7.8 million (2017: $5.4 million) of this amount.  The reduction in G&A is the result of prudent resource management which is a core part of the corporate culture and an important element of the Group's KPIs.  The G&A amount includes $1.8 million of share-based payments (2017: $2.7 million) and $0.4 million (2017: $0.4 million) of depreciation costs.

 

The movement in these three components has allowed the Group to record an EBITDA of $149.3 million a 43% increase in comparison to the previous year (2017: $104.3 million).

 

Net finance costs and other gains

 

The Group incurred net finance costs of $9.4 million (2017: $10.3 million).  This includes $2.9 million of accelerated amortisation of the refinanced Notes' issue costs (2017: $nil).

 

The Company has received final clearance from Sonatrach in relation to the Ferkane Permit (Block 126). This officially marks Gulf Keystone's exit from its Algerian operations.  This resulted in a $10.2m release of past liabilities recognised in other gains.

 

A solid financial foundation underpinning the Group's strategy

 

Strong free cash flow generation

 

In 2018, the Group received revenue payments of $224.7 million (2017: $132.0 million).  This, combined with strong capital discipline and low-cost operations, allowed us to generate a net cash increase of $135.2 million (2017: $67.0 million).

 

The cash balance at the end of 2018 stood at $295.6 million (2017: $160.5 million), serving as a solid base for the Shaikan investment programme. 

 

In July 2018, the Group redeemed the $100 million Reinstated Notes due in 2021 at a price equal to 100% of the principal, plus accrued and unpaid interest.  The Group also successfully completed the private placement of a 5-year senior unsecured $100 million bond issue (the "New Notes") carrying a 10% fixed semi-annual coupon.  The bond placement was oversubscribed receiving strong investor demand, both from existing and new investors across international markets.  The New Notes give the Group the flexibility to raise up to $200m of additional borrowing.

 

Capital investment

 

In 2018, capital investment in Shaikan amounted to $35.7million.  This investment covered the work on the export pipeline from the production facilities to the main export pipeline, the SH-1 workover, work in preparation to the upcoming drilling campaign, production facilities improvement, various studies and reservoir engineering.

 

Capital investment in Shaikan will continue this year with the Group's work programme aimed at achieving the near-term production target of 55,000 bopd.  In 2019, the gross capital expenditure associated with this project is expected to total $130-150 million. In addition, the Company has initiated certain workstreams in relation to the subsequent phase of the development which includes expansion to 75,000 bopd and the gas re-injection project, although the investment decision has not been finalised.  In 2019, the gross capital expenditure associated with this workstream, which includes installation of additional electrical submersible pumps, certain long lead items, well pads civil works and engineering and design work on the gas re-injection project, is expected to be in the range of $20-45 million, depending on the timing of the project investment decision and achievement of key milestones.

 

OPERATIONAL REVIEW

 

2018 was a year of operational delivery from the Shaikan Field, with the Company focused on laying the foundations to increase gross production from the field to 55,000 bopd and beyond.


The Company delivered strong operational performance in 2018, following a similarly good year in 2017.

 

Gulf Keystone attained gross average production of 31,563 bopd during the period, at the upper end of our 27,000 - 32,000 bopd guidance for the year.  The production figures were achieved by maintaining safe and reliable operations underpinned by predictable performance from the Shaikan Jurassic reservoir, which continues to produce in line with expectations.  Plant uptime remained very high throughout the year at 99%. 

 

The year marked the beginning of direct pipeline exports from Shaikan with the commissioning in July of the spur line from PF-2 to the Kurdish export pipeline.  During 2018, the reduction in trucking operations to Fishkhabour a reduced the risk of road traffic accidents, and today, following the installation of temporary unloading facilities at PF-2, only ca.3,000 bopd are exported by trucks via Fishkhabour.  Trucking will be eliminated in the summer 2019 when the tie-in from PF-1 to the main export line is finalised.

 

The Company continues to focus on cost discipline at Shaikan.  Operating costs have increased in comparison to 2017, due to various maintenance projects undertaken during the year and other investments in preparation for the increase in production.  This, together with the lower average production for the year, has resulted in an increase in Opex per barrel from $2.7/bbl in 2017 to $3.2/bbl in 2018.

 

Over the last year, the Company has conducted an internal in-depth assessment of reserves.  This used as a foundation: new petrophysical and geological interpretations, a comprehensive fracture network modelling study, updated well and facilities performance data, production history to the end of 2018 and dynamic reservoir simulation modelling incorporating all of these data. On this basis, GKP's internal review of reserves indicates an upgrade in Proven (1P) reserves and no material changes to Probable reserves (2P) compared to previous work.  The lack of any significant change in the mid-case is reassuring, but more importantly the increase in 1P reserves is indicative of the reduced uncertainty and risk as production and reservoir performance becomes better understood.

 

However, GKP continues to report reserves based on the 2016 ERCE Competent Person's Report ("CPR"), the last audited assessment of reserves. Using the gross 1P and 2P reserves of Shaikan are estimated at 207 MMstb ("Million Stock Tank Barrels") and 591 MMstb respectively at the end of 2018, accounting for production in 2017 and 2018.  A revised CPR is expected to be released following FDP approval.

 

At the end of 2018, Gulf Keystone had produced over 56 MMstb from Shaikan, representing 9% of Shaikan's Gross 2P reserves.  This knowledge proved instrumental when designing the phased investment programme at Shaikan and gives the Company comfort when setting out its future investment plans for the field.

 

Next stage of growth - 55,000 bopd project in the next 12 months

 

In June 2018, Gulf Keystone with its partner MOL, reached agreement with the MNR to recommence investment into Shaikan; a landmark event for the business.  Since this time, a number of workstreams have commenced which will enable the Company to reach the target of 55,000 bopd in Q1 2020. The target of the investment in this phase is the continued exploitation of the high quality Jurassic reservoir, which benefits from an unusually high oil column of up to 950 metres and an east-west closure mapped of ca.25 kilometres. The scale of the reservoir affords several infill well locations.

 

The Company signed an agreement with Independent Oil Tools ("IOT") to use 'Rig 1' for its planned workover programme.  The rig has now successfully completed a workover on the SH-1 well, resulting in an increase in production from the well by ca.90%, to over 7,000 bopd.  The IOT rig used will complete a workover for another operator in the region before returning to Shaikan for the remaining workovers in the 55,000 bopd expansion programme.  This will include the SH-3 tubing change-out along with installation of Electric Submersible Pumps ("ESPs") in wells SH-5, SH-10 and SH-11.

 

A drilling campaign using 'Rig 40' (owned by DQE) is planned to commence shortly, with the first four wells (needed for the 55,000 bopd target) expected to be completed in Q1 2020.  The four wells will target infill locations between existing wells to exploit the Jurassic Sargelu, Alan, Mus and Butmah formations, the source of all Shaikan production to date. Well pad construction for the first two wells of the campaign is complete.

 

Progress with the debottlenecking work at PF-1 and PF-2, remains on track for completion late 2019.  After incurring minor operational delays, largely from the late delivery of drilling and well completion equipment, the 55,000 bopd production target is now expected in Q1 2020.  The Company has made significant progress since construction commenced and remains on track to achieve this milestone.  Gulf Keystone expects gross capital expenditure for the 55,000 bopd development phase to remain unchanged in the range of $200 million to $230 million, including a 25% contingency.

 

Gross production this year up to 26 March 2019 averaged 27,845 bopd; somewhat lower than the forecast range due to an unplanned export pipeline shutdown and the SH-1 workover.  Nevertheless, average gross production guidance for 2019 remains in the range of 32,000 - 38,000 bopd as previously communicated. 

 

Staged production growth over next five years

 

Looking beyond the 55,000 bopd project initiated in June 2018, Gulf Keystone and its partner MOL have formulated a phased investment programme, which envisages gross field production increase in stages to 75,000 bopd, then up to 85,000 bopd (collectively "Phase 1"), and eventually 110,000 bopd ("Phase 2") once the Triassic reservoir is fully on-stream.  Compared to the previous development plan, this revised plan has been de-risked and optimised on phasing, timeline and expenditures.  A revised Field Development Plan reflecting the strategy was submitted to the MNR in Q4 2018.  This revision has not been accepted by the MNR, specifically due to a request for additional assurances on the timing and commitment to eliminate gas flaring.  As the parties aim to progress this matter and reach an agreement for the benefit of all parties, investment on the ground continues as per the initial phases of this plan.   

 

Whilst the FDP has not been accepted, the Company has commenced with various workstreams (including planning and procurement of certain long lead items) to prepare for the increase in output to 75,000 bopd.  This project includes a new train plus utilities to be constructed at PF-1 and PF-2, which would increase total processing capacity at the field to 75,000 bopd.  The expansion beyond 55,000 bopd to 75,000 bopd includes a gas re-injection facility which is expected to eliminate flaring, help maintain reservoir pressure, mitigate HSSE risks and lay the foundation for the development of the Triassic reservoir by enabling the handling of the higher gas-oil ratio expected from lighter Triassic oil. Gulf Keystone currently estimates the gross costs associated with the gas re-injection project, and the step up to 75,000 bopd, to be in the range of $400 million and $450 million, including a 25% contingency, but this remains subject to a final review and sanction. The gross Capex of the expansion to 75,000 bopd is estimated between $150 million and $175 million with an estimated project duration of 18 to 24 months, while the Capex for the gas re-injection is estimated between $225 million and $300 million with an estimated project duration of 24 to 30 months. 

 

The 85,000 bopd phase requires production from Shaikan's Triassic reservoir, which is yet to be exploited.  Installation of oil processing facilities at a new site, adjacent to the Jurassic gas reinjection facility and the drilling of two new Triassic production wells, plus a possible third contingent well, would also need to be carried out to achieve the initial phase of production of ca.10,000 bopd from the Triassic.  In this initial, or pilot phase, the Company plans to use dynamic data from the first six to twelve months of production to better understand the reservoir's behaviour.  Once this has been quantified, a final investment decision on the planned expansion work will be made.  Further details on the costs of this Triassic pilot phase will be disclosed in due course, but initial estimates suggest gross Capex for this stage in the region of $135 million to $165 million, including a 25% contingency, over a duration between 18 to 24 months.

 

It is currently envisaged that a final investment decision on Phase 2 (which includes expansion of the Triassic and a Cretaceous pilot) will be made before moving ahead with the ordering of compression and facility equipment in addition to the drilling of a further five wells required to increase output at Shaikan to the 110,000 bopd target level. The timing of Shaikan's Phase 2 development decision will be dependent on the outcome of the Phase 1 project. Further details on the costs of the subsequent 110,000 bopd phase will be disclosed in due course, but initial estimates suggest gross Capex for these stages in the region of $450 million to $550 million, including a 25% contingency, over a duration between 24 to 30 months.

  

The Company has been thorough in designing this staged investment scheme and believes that the blueprint laid out represents prudent reservoir management and is in the best interests of all stakeholders.  Realising the full potential from Shaikan and maximising its value for shareholders, remains a priority for the Company and we believe our approach to be the optimal method of achieving this.

 

HSSE & CSR

 

Gulf Keystone strives to be at the forefront of HSSE performance in Kurdistan and monitors and continually improves its safety practices accordingly.  HSSE performance was robust during the period with one Lost Time Incident ("LTI") recorded, the first for three years.

 

Connecting PF-2 to the export pipeline in July 2018 significantly reduced the need to truck crude and the installation of a temporary unloading facility at PF-2 has allowed PF-1 trucks to materially reduce the distance they need to travel and has resulted in decreased HSSE exposure.  The connection of PF-1 to the main export pipeline in mid-2019 is expected to eliminate the need for trucking at Shaikan entirely.

 

Gulf Keystone remains committed to having a high proportion of the Company's workforce made up of local personnel. During 2018 ca.80% of in-country staff were local employees, 35% of which live in the nearby villages surrounding Shaikan.  Last year, a total of 25 promotions for local personnel took place; awarded on the basis of successful development and performance.  A number of companies from the Shaikan area have been successful in our tendering processes and this, as well as providing excellent service, enables a higher proportion of local communities and personnel to share in the success of the Shaikan development.

 

We remain focussed on assuring our environmental impact is minimised and in 2018 a number of drilling sites, where storage pits had been left in place, were remediated and landscaped.  The programme was carried out in close collaboration with the MNR, who have agreed that it met all requirements.  The programme continues in 2019, but by the end of this year we hope to have completed the remediation of all those sites.  We were also very pleased to receive approval from the MNR for our Environmental and Social Impact Studies (ESIA) in relation to the drilling programme and the pipeline installation. 

 

In 2018, the Company was pleased to agree a long term corporate social responsibility ("CSR") strategy with local and government stakeholders.  The aim of the strategy is to ensure community investment is built into the framework of Gulf Keystone's business actions. We have started a number of projects - in particular two relating to improvement to agricultural practice - and have identified a number of others which we are in the process of evaluating. We actively work with NGOs in the region using their expertise in the implementation of these projects.

 

 

 

Consolidated Income Statement

For the year ended 31 December 2018

 

 

 

Notes

2018

2017

 

 

$'000

$'000

 

 

 

 

 

 

 

 

Continuing operations

 

 

 

Revenue

2

250,554

172,372

Cost of sales

3

(154,534)

(126,996)

Gross profit

 

96,020

45,376

 

 

 

 

General and administrative expenses

4

(17,813)

(21,304)

Profit from operations

 

78,207

24,072

 

 

 

 

Finance revenue

7

4,441

702

Finance costs

7

(13,873)

(11,023)

Other gains and losses

6

10,925

314

Profit before tax

 

79,700

14,065

 

 

 

 

Tax credit

8

189

61

Profit after tax for the year

 

79,889

14,126

 

Profit per share (cents)

 

 

 

Basic

9

34.84

6.16

Diluted

9

33.87

6.12

 

 

 

 

 

 

 

 

 

 

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2018

 

 

 

2018

2017

 

 

$'000

$'000

 

 

 

 

 

 

 

 

Profit after tax for the year

 

79,889

14,126

 

Items that may subsequently be reclassified to profit or loss:

 

 

 

 

 

 

 

Exchange differences on translation of foreign operations

 

(800)

1,281

 

 

 

 

Total comprehensive profit for the year

 

79,089

15,407

 

 

 

Consolidated Balance Sheet

As at 31 December 2018

 

 

Notes

2018

2017

 

 

$'000

$'000

 

 

 

 

Non-current assets

 

 

 

Intangible assets

10

84

63

Property, plant and equipment

11

380,537

417,473

Deferred tax asset

18

559

403

 

 

381,180

417,939

 

 

 

 

Current assets

 

 

 

Inventories

13

14,190

17,190

Trade and other receivables

14

67,909

61,710

Cash and cash equivalents

 

295,566

160,456

 

 

377,665

239,356

Total assets

 

758,845

657,295

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

Trade and other payables

15

(81,478)

(57,038)

Provisions

17

(4,155)

(7,197)

 

 

(85,633)

(64,235)

 

 

 

 

Non-current liabilities

 

 

 

Borrowings

16

(97,795)

(97,067)

Provisions

17

(22,600)

(24,107)

 

 

(120,395)

(121,174)

Total liabilities

 

(206,028)

(185,409)

Net assets

 

552,817

471,886

 

 

 

 

Equity

 

 

 

Share capital

19

229,430

229,430

Share premium

19

920,728

920,728

Exchange translation reserve

 

(3,818)

(3,018)

Accumulated losses

 

(593,523)

(675,254)

Total equity

 

552,817

471,886

 

The financial statements were approved by the Board of Directors and authorised for issue on 27 March 2019 and signed on its behalf by:

 

 

 

 

Jón Ferrier

Chief Executive Officer

 

 

 

Sami Zouari

Chief Financial Officer

 

Consolidated Statement of Changes in Equity

For the year ended 31 December 2018

 

 

 

 

Attributable to equity holders of the Company

 

 

Notes

 

Share

capital

Share

premium

Exchange translation reserve

Accumulated losses

Total

equity

 

$'000

$'000

$'000

$'000

$'000

 

 

 

 

 

 

 

 

 

 

Balance at 1 January 2017

 

229,430

920,728

(4,299)

(692,090)

453,769

 

 

 

 

 

 

 

Net profit for the year

 

-

-

-

14,126

14,126

Other comprehensive loss for the year

 

-

-

1,281

-

1,281

Total comprehensive loss for the year

 

-

-

1,281

14,126

15,407

Share-based payment expense

22

-

-

-

2,710

2,710

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at 31 December 2017

 

229,430

920,728

(3,018)

(675,254)

471,886

 

 

 

 

 

 

 

Net profit for the year

 

-

-

-

79,889

79,889

Other comprehensive profit for the year

 

-

-

(800)

-

(800)

Total comprehensive profit for the year

 

-

-

(800)

79,889

79,089

Share-based payment expense

22

-

-

-

1,842

1,842

 

 

 

 

 

 

 

Balance at 31 December 2018

 

229,430

920,728

(3,818)

(593,523)

   552,817

               

 

 

 

Consolidated Cash Flow Statement

For the year ended 31 December 2018

 

 

Notes

    2018

2017

 

 

$'000

$'000

 

 

 

 

Operating activities

 

 

 

Cash generated from operations

20

161,483

85,300

Interest received

  7

4,441

702

Interest paid on Reinstated Notes

16

(7,713)

(10,111)

Net cash generated from operating activities

 

158,211

75,891

 

 

 

 

Investing activities

 

 

 

Purchase of intangible assets

 

(66)

-

Purchase of property, plant and equipment

 

(20,589)

(8,856)

Net cash used in investing activities

 

(20,655)

(8,856)

 

 

 

 

Financing activities

 

 

 

Issue costs of new notes

 

(2,366)

-

Net cash from financing activities

 

(2,366)

-

 

 

 

 

Net increase in cash and cash equivalents

 

135,190

67,035

Cash and cash equivalents at beginning of year

 

160,456

92,870

Effect of foreign exchange rate changes

 

(80)

551

 

 

 

 

Cash and cash equivalents at end of the year being bank balances and cash on hand

 

295,566

160,456

 

 .

Summary of Significant Accounting Policies

 

General information

 

The Company is incorporated in Bermuda (registered address: Cumberland House, 9th Floor, 1 Victoria Street, Hamilton, Bermuda). 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 ("AIM"), 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 and production, operating in the Kurdistan Region of Iraq. During 2018 the company was still operating in Algeria, however it formally exited the country in January 2019.

 

Adoption of new and revised Standards

 

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 2018. Their adoption has not had any material impact on the disclosures or on the amounts reported in these financial statements.

 

IFRS 9 Financial instruments

The Group has adopted the IFRS 9 for the first time in the current year. The standard requires an entity to address the classification, measurement and recognition of financial assets and liabilities. The impact of this adoption has not had a material impact on the Group's financial statements. In applying IFRS 9 on trade receivables the expected credit loss is not determined to be

material.  

IFRS 15 Revenue from contracts

The Group has adopted IFRS 15 for the first time in the current year. The Group's accounting policy under IFRS 15 is that revenue is recognised when the Group satisfies a performance obligation by transferring oil to our customer and completing transportation services on their behalf. The application of IFRS 15 is not determined to be material.

New and revised IFRSs in issue but not yet effective

 

At the date of authorisation of these financial statements, The Group has not applied the following new and revised IFRSs that have been issued but are not yet effective and in some cases had not yet been adopted by the EU:

IFRS 16

Leases

IFRS 17

Insurance Contracts

IFRS 9

IAS 28 (amendments)

Prepayment Features with Negative Compensation

Long-term interests in Associates and Joint Ventures

Annual Improvements

Standards 2015-17

Amendments to IFRS 3 Business combinations, IFRS 11 Joint Arrangements

Cycle IAS 12 Income taxes and IAS 23 Borrowing costs

IAS 19 (amendments)

Employee benefits, plan amendments, curtail or settlement.

IFRS 10 and IAS 28 (amendments)

Sale or Contribution of Assets between an Investor and its Associate or Joint Venture

Annual Improvements to IFRSs 2014-2016 Cycle

Amendments to IFRS 1 First-time Adoption of International Financial     Reporting Standards and IFRS 28 Investments in Associates and Joint Ventures

IFRIC 23

Uncertainty over Income Tax Treatments

 

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, except as noted below:

 

 

 

 

IFRS 16 Leases

 

IFRS 16 introduces a comprehensive model for the identification of lease arrangements and accounting treatments for both lessors and lessees. IFRS 16 will supersede the current lease guidance including IAS 17 Leases and the related interpretations when it becomes effective for accounting periods beginning on or after 1 January 2019. The date for the initial application of IFRS for the Group will be 1 January 2019.

 

IFRS 16 will change how the Group accounts for leases previously classified as operating leases under IAS 17, which were off balance sheet.

 

On initial application of IFRS 16 the Group will;-

 

a)    Recognise right-of-use assets and lease liabilities, initially measured at the present value of the future lease payments;

 

b)    Recognise depreciation of right-to-use assets and interest on lease liabilities in the consolidated statement of profit and loss;

 

c)     Separate the total amount of cash paid into a principal portion(presented within financing activities) and (interest presented within operating activities) in the consolidated cash flow statement.

 

 

Under the transition rules of IFRS16 the Group has chosen to adopt the cumulative catch-up approach. The Group will not restate any prior year figures and make any necessary adjustments between assets and liabilities through opening retained earnings.  The Group does not expect the implementation of IFRS 16 to have a material impact on the financial statements.

 

The impact of IFRS 16 on the Group has set out in the table below:

 

Date of assessment

Assets

Liabilities

Net Assets

Expenses

Retained Earnings

 

$'000

$'000

$'000

$'000

$'000

1 January 2019

979

(979)

-

-

-

Year Ended 31 December 2019

221

(14)

207

8

8

Year Ended 31 December 2020

234

(255)

(21)

(10)

(2)

Year Ended 31 December 2021

47

(54)

(7)

(14)

(16)

Year Ended 31 December 2022

-

-

-

7

(9)

 

Statement of compliance

 

The financial statements have been prepared in accordance with IFRS as adopted by the European Union.

 

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 initially recognised at fair value, but 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 Executive Review and the Operational Review. The financial position of the Group at the year end and its cash flows and liquidity position are included in the Financial Review. 

 

The Group continues to closely monitor and manage its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Shaikan block, costs contingencies, disruptions to revenue receipts, etc. The Group has taken appropriate action to reduce its cost base and has $196 million of net cash as at 27 March  2019. The Group's forecasts, taking into account the risks applicable, show that the Group has sufficient financial headroom for the 12 months from the date of approval of the 2018 Annual Report and Accounts.

 

Based on the analysis performed, the directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Thus, they continue to adopt the going concern basis of accounting in preparing the annual 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.

 

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.

 

Operating costs

 

Operating costs is a useful indicator of the Group's costs incurred to produce Shaikan oil. Operating costs, in comparison with cost of sales, exclude certain non-cash accounting adjustments, contractual PSC payments and transportation costs.   

 

 

 
 

Year Ended

31 December 2018

Year Ended

31 December 2017

 

$ million

$ million

 

 

 

Cost of sales

154.5

127.0

Depreciation of oil & gas assets

(70.7)

(79.8)

Production bonus

(16.0)

-

Capacity building payments

(17.0)

(17.2)

Transportation costs

(14.3)

(2.4)

Working capital movement

(5.8)

1.2

Operating costs

30.7

28.8

 

 

Gross operating costs per barrel (unaudited)

 

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

 

 
 

Year Ended

31 December 2018

Year Ended

31 December 2017

 

 

 

 

 

 

Gross production (MMbbls)

11.5

12.9

Gross operating costs ($ million)

36.8

35.4

Gross operating costs per barrel ($ per bbl)

3.2

2.7

 

 

 

EBITDA

 

EBITDA is a useful indicator of the Group's profitability, which excludes the impact of costs attributable to income tax (expense)/credit, finance costs, interest revenue, depreciation, depletion and amortisation and other gains and losses.

 

 
 

Year Ended

31 December 2018

Year Ended

31 December 2017

 

$ million

$ million

 

 

 

Profit from operations

78.2

24.1

Depreciation of oil & gas assets

70.7

79.8

Depreciation and amortisation

0.4

0.4

EBITDA

149.3

104.3

 

Capital Investment

 

Capital investment is the value of the Group's additions to oil and gas assets excluding any movements in decommissioning assets.

 
 

Year Ended

31 December 2018

Year Ended

31 December 2017

 

$ million

$ million

 

 

 

Additions to oil and gas assets

35.7

8.1

Capital Investment

35.7

8.1

 

Net Cash

 

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

 

 

 

Year Ended

31 December 2018

Year Ended

31 December 2017

 

$ million

$ million

 

 

 

Outstanding New Notes

(100.0)

(100.0)

Non-cash adjustments

(4.4)

(2.0)

Cash and cash equivalents

295.6

160.5

Net Cash

191.2

58.5

 

 

 

 

 

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, particularly the recognition of revenue from export sales of crude oil, is considered to be a key accounting judgement.

 

All oil is sold to the KRG, who in turn resell the oil either  export in the pipeline at PF-2, at Fishkhabour or by trucking it to domestic customers. The selling price is determined in accordance with the principles of the crude oil export sales agreement ("Crude Oil Sales Agreement"), based on the Brent crude price less a quality discount and transportation costs. The sales agreement also specifies the delivery point, KRG's contribution to transportation costs and payment terms relating to export sales of crude oil. The Crude Oil Sales Agreement has been governing Shaikan crude oil sales from 1 October 2017 onwards.

 

As the payment mechanism for sales is developing within the Kurdistan Region of Iraq, the Group currently considers that revenue can best be reliably measured when the cash receipt is assured. The assessment of whether cash receipt is reasonably assured is based on management's evaluation of the reliability of the KRG's payments to the international oil companies operating in the Kurdistan Region of Iraq.

 

The value of sales revenue is determined after taking account of the following:

 

·      For the crude oil sales via Fishkhabour route, the point of sale is the point that the crude oil is unloaded into the export pipeline at Fishkhabour;

·      For the crude oil sales via Atrush feeder line, the point of sale is the point that the crude oil in injected into the Atrush feeder line;

·      The point of sale for domestic sales is at the Shaikan facility;

·      GKP recognises revenue for its share of the revenue on a cash-assured basis and these amounts of recognised revenue may be lower than the Company's entitlement under the Shaikan PSC, giving rise to unrecognised revenue amounts;

·      From 15 November 2017 onwards, the Group has performed transportation services in respect of the KRG's share of export oil sales. It recharges all of these transportation costs at nil mark-up to the KRG and these recharged transportation costs are recognised as revenue; and

·      Under the Shaikan PSC and the bilateral agreement between GKPI and the MNR signed on 16 March 2016 ("Bilateral Agreement"), the Group is entitled to offset certain costs (including capacity building payments and production bonuses) against amounts owed by the KRG to GKPI. In these instances, the Group recognises revenue and a reduction in the liability to the KRG.

 

To the extent that revenue arises from test production during an evaluation programme, an amount is charged from exploration and evaluation costs to cost of sales so as to reflect a zero net margin.

 

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

 

Interest 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.

 

Property, plant and equipment other than oil and gas assets

 

Property, plant and equipment ("PPE") are stated at cost less accumulated depreciation and any accumulated impairment losses.  Depreciation is provided at rates calculated to write each asset down to its estimated residual value over its expected useful life as follows:

 

Fixtures and equipment

-

20% straight-line

 

Intangible assets other than oil and gas assets

 

Intangible assets, other than oil and gas assets, have finite useful lives and are measured at cost and amortised over their expected useful economic lives as follows:

 

Computer software

-

33% straight-line

 

Oil and gas assets

 

Pre-licence costs

Costs incurred prior to having obtained the legal rights to explore an area are expensed directly to the income statement as they are incurred.

 

Exploration and evaluation costs

The Group follows the successful efforts method of accounting for exploration and evaluations ("E&E") costs.  Expenditures directly associated with evaluation or appraisal activities are initially capitalised as intangible asset in cost pools by well, field or exploration area, as appropriate. Such costs include licence acquisition, technical services and studies, seismic acquisition, exploration and appraisal well drilling, payments to contractors, interest payable and directly attributable administration and overhead costs.    

 

These costs are then written off as exploration costs in the income statement unless the existence of economically recoverable reserves has been established and there are no indicators of impairment.

 

E&E costs are transferred to development and production assets within property, plant and equipment upon the approval of a development programme by the relevant authorities and the determination of commercial reserves existence. 

 

Development and production assets

Development and production assets are accumulated on a field-by-field basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above.

 

The cost of development and production assets includes the cost of acquisition and purchases of such assets, directly attributable overheads, and costs for future restoration and decommissioning. These costs are capitalised as part of the property, plant and equipment and depreciated based on the Group's depreciation of oil and gas assets policy.

 

Depreciation of oil and gas assets

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. Production associated with unrecognised export sales revenue is included in the DD&A calculation. Costs used in the calculation comprise the net book value of the field, and any further anticipated costs to develop such reserves.

 

Commercial reserves are proven and probable ("2P") reserves together with, where considered appropriate, a risked portion of 2C contingent resources, which are estimated using standard recognised evaluation techniques. The estimate is regularly reviewed by independent consultants.

 

 

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 and value in use.  In assessing 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.

 

 

Borrowing costs

 

Borrowing costs directly relating to the acquisition, construction or production 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

 

The tax expense represents the sum of the tax currently payable and deferred tax.

 

The tax currently payable is based on taxable profit 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 to be shown 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 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 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 functional currency of the Group, and 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 valued at the lower of cost and net realisable value. Hydrocarbon inventories are recorded at net realisable value with changes in 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.

 

Liquid investments

Liquid investments comprise short-term liquid investments with maturities of three to twelve months.

 

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 at 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 enter into derivative financial instruments including foreign exchange forward contracts to manage its exposure to foreign exchange 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.

 

Impairment of financial assets

Financial assets, other than those valued at FVTPL, are assessed for indicators of impairment at each balance sheet date.  Financial assets are impaired where there is objective evidence that, as a result of one or more events that occurred after the initial recognition of the financial asset, the estimated future cash flows of the investment have been impacted.

 

For certain categories of financial asset, such as trade receivables, assets that are assessed not to be impaired individually are subsequently assessed for impairment on a collective basis.  Objective evidence of impairment for a portfolio of receivables could include the Group's past experience of collecting payments, an increase in the number of delayed payments in the portfolio past the average credit period, as well as observable changes in local or national economic conditions that correlate with default on receivables.

 

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 damage is done to the site and an obligation to restore the site to its original condition exists. 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 entity instruments at the grant date. Details regarding the determination of the fair value of equity-settled share-based transactions are set out in Note 22. 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 22.

 

Leasing

 

Rentals payable under operating leases are charged to the income statement on a straight-line basis over the term of the relevant lease.

 

Critical accounting estimates and judgements

 

In the application of the Group's accounting policies, which are described above, the directors are 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.

 

Key estimates

 

 

Reserves estimates

Commercial reserves are determined using estimates of oil-in-place, recovery factors and future oil prices.  Future development costs are estimated using assumptions as to numbers of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital and operating costs.  Reserves estimates principally affect the depreciation, depletion and amortisation charges, as well as impairment assessments.

 

Carrying value of producing assets

 

Oil and gas assets within property, plant and equipment are held at historical cost value, less accumulated depreciation and impairments.

 

Producing assets are tested for impairment whenever indicators of impairment exist. Management assesses whether such indicators exist, with reference to the criteria specified in IAS 36 Impairment of Assets, at least annually. 

As at 31 December 2017, an internal valuation of the Shaikan field was performed, providing further support in relation to the conclusion that no indicators of impairment existed.

 

The assumptions and estimates in the valuation model include:

 

-       Commodity prices that are based on latest internal forecasts, benchmarked with external sources of information, to ensure they are within the range of available analyst forecasts and the long-term corporate economic assumptions thereafter;

 

-       Discount rates that are adjusted to reflect risks specific to individual assets and the region;

 

-       Commercial reserves and the related production and payment profiles; and

 

-       Timing of revenue receipts.

 

Operating costs and capital expenditure are based on financial budgets and internal management forecasts. Cost assumptions incorporate management experience and expectations, as well as the nature and location of the operation and the risks associated therewith. Underlying input cost assumptions are consistent with related output price assumptions.

 

In line with the Group's accounting policy on impairment, management performs an impairment review of the Group's oil and gas assets annually with reference to indicators as set out in IAS 36.  The Group assesses its group of assets called cash generating units (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 assumptions such as future oil and gas prices, estimated production volume, pre-tax discount rates that reflect the current market assessment of the time value of money and risks specific to the asset, commercial reserves, inflation and transportation fees. The key assumptions are subject to change based on the current market trends and economic conditions.  The CGU's recoverable amount is the higher of the fair value less cost of disposal and value in use. 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 2018 was Shaikan with a carrying value of $379.7 million.  No impairment indicator was identified as at 31 December 2018.

 

Reserves estimates

Commercial reserves are determined using estimates of oil-in-place, recovery factors and future oil prices.  Future development costs are estimated using assumptions as to numbers of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital and operating costs.  Reserves estimates principally affect the depreciation, depletion and amortisation charges, as well as impairment assessments.

 

 

Significant accounting judgement

 

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.  However, as the payment mechanism for sales to the export market continues to develop within the Kurdistan Region of Iraq, the Group considers that revenue can be only reliably measured when the cash receipt is assured. The assessment of whether cash receipts are reasonably assured is based on management's evaluation of the reliability of the MNR's payments to the international oil companies operating in the Kurdistan Region of Iraq.  The Group also recognised payables to the MNR that were offset against amounts receivable from the MNR for previously unrecognised revenue in line with the terms of the Shaikan PSC.

 

The judgement is not to recognise revenue in excess of the sum of the cash receipt that is assured and the amount of payables to the MNR that can be offset against amounts due for previously unrecognised revenue in line with the terms of the Shaikan PSC, despite the Group being entitled to additional revenue under the terms of the Shaikan PSC. Any future agreements between the Company and the KRG might change the amounts of revenue recognised.

 

Notes to the Consolidated Financial Statements

 

1.   Segment information

 

For the purposes of resource allocation and assessment of segment performance, the Group is organised into three regional business units - Algeria, Kurdistan and the Corporate. These geographical segments are the basis on which the Group reports its segmental information.  The chief operating decision maker is the Chief Executive Officer. He is assisted by the Chief Financial Officer and senior management team. 

 

The accounting policies of the reportable segments are consistent with the Group's accounting policies. 

 

Each segment is described in more detail below:

 

-       Kurdistan Region of Iraq: the Kurdistan segment consists of the Shaikan asset and the Erbil office, which provides support to the operations in Kurdistan;

 

-       Algeria:  the Algerian segment consists of the Algiers office and the Group's operations in Algeria. This activity has now been exited in January 2019.

 

-       Corporate: the corporate segment consists of the Group's UK and Bermuda offices. It represents all overhead and administration costs incurred that are of a corporate nature and elimination of intercompany income and charges which cannot be directly linked to one of the above segments.

 

 

 

 

31 December 2018

Algeria

Kurdistan

Corporate

Total

 

$'000

$'000

$'000

$'000

Revenue

 

 

 

 

Oil sales

-

243,711

-

243,711

Transportation revenue

-

6,843

-

6,843

Inter-segment sales

-

-

-

-

Total revenue

 

250,554

-

250,554

 

 

 

 

 

Cost of sales

 

 

 

 

Production costs

-

(69,479)

-

(69,479)

Oil and gas assets depreciation expense

-

(70,744)

-

(70,744)

Transportation costs

-

(14,311)

-

(14,311)

Gross profit

-

96,020

-

96,020

 

 

 

 

 

General and administrative expenses

 

 

 

 

Allocated general and administrative expenses

(153)

(7,776)

(9,500)

(17,429)

Depreciation and amortisation expense

-

(105)

(279)

(384)

 

 

 

 

 

Profit / (loss) from operations

(153)

88,139

(9,779)

78,207

 

 

 

 

 

Interest revenue

-

3,713

728

4,441

Finance costs

-

(723)

(13,150)

(13,873)

Other gains and losses

10,205

39

681

10,925

 

Profit / (loss) before tax

10,052

91,168

(21,520)

79,700

 

 

 

 

 

Tax benefit

-

-

189

189

 

 

 

 

 

Profit / (loss) after tax

10,052

91,168

(21,331)

79,889

 

 

 

 

 

Capital expenditure

-

36,316

109

36,425

Total assets

-

686,636

72,209

758,845

 

 

During 2018, the allocated general and administrative expenses of $17.4 million (2017: $20.6 million) included costs that are recoverable under the terms of the Shaikan PSC amounting to $7.3 million (2017: $5.4 million).

 

 

 

31 December 2017

Algeria

Kurdistan

Corporate

Total

 

$'000

$'000

$'000

$'000

Revenue

 

 

 

 

Oil sales

-

171,203

-

171,203

Transport revenue

-

1,169

-

1,169

Total revenue

 

172,372

-

172,372

 

 

 

 

 

Cost of sales

 

 

 

 

Production costs

-

(44,765)

-

(44,765)

 

 

 

 

 

Oil and gas assets depreciation

expense

-

(79,785)

-

(79,785)

 

Transportation costs

-

(2,446)

-

(2,446)

 

 

 

 

 

Gross profit

-

45,376

-

45,376

 

General and administrative expenses

 

 

 

 

Allocated general and administrative expenses

(63)

(5,387)

(15,157)

(20,607)

Depreciation and amortisation expense

-

(145)

(280)

(425)

 

 

 

 

 

Profit / (loss) from operations

(63)

39,844

(15,437)

24,344

 

 

 

 

 

Interest revenue

-

432

270

702

Finance income/ (costs)

-

(714)

(10,309)

(11,023)

Other gains

-

323

(281)

42

 

Profit / (loss) before tax

(63)

39,885

(25,757)

14,065

 

 

 

 

 

Tax expense

-

-

61

61

 

 

 

 

 

Profit / (Loss) after tax

(63)

39,885

(25,696)

14,126

 

 

 

 

 

Capital expenditure

-

43,578

-

43,578

Total assets

31

582,192

75,072

657,295

 

 

The 2017 segemental analysis has been restated to combine corporate activities under one heading

 

Geographical information

 

The Group's information about its segment assets (non-current assets excluding deferred tax assets and other financial assets) by geographical location is detailed below:

 

 

2018

$'000

2017

$'000

 

 

 

Kurdistan

380,339

417,024

United Kingdom

282

512

 

380,621

417,536

 

Information about major customers

 

Included in revenues arising from the Kurdistan segment are revenues of approximately $250.6 million which arose from sales to the Group's largest customer (2017: $172.4 million).

 

 2. Revenue

 

 

2018

$'000

2017

$'000

 

 

 

Oil sales

243,711

171,203

Transportation revenue

6,843

1,169

 

250,554

172,372

 

The Group accounting policy for revenue recognition is set out in the Summary of Significant Accounting Policies, with revenue recognised on a cash-assured basis.

 

During 2018, the cash-assured values recognised as oil sales were the invoiced revenue for the year amounting to $227.5 million (2017: $156.3 million). The MNR liability offset revenue recognised was $16.2 million (2017: $14.9 million). The oil sales price was calculated using the monthly Brent price less an average discount of $22.3 (2017: $20.3) per barrel for quality, pipeline tariff and transportation costs.

 

From 15 November 2017 onwards, the Group has performed transportation services in respect of the KRG's share of export oil sales. It recharges all of these transportation costs at nil mark-up to the KRG.

 

Interest revenue has been presented as part of net finance costs (note 7).

 

 

3.             Cost of Sales

 

 

2018

$'000

2017

$'000

 

 

 

Oil production costs

69,479

44,765

Depreciation of oil and gas assets

70,744

79,785

Transportation costs

14,311

2,446

 

154,534

126,996

 

Oil production costs represent the Group's share of gross production expenditure for the Shaikan field for the year and include capacity building charges of $17.0 million (2017: $17.2 million) and Shaikan PSC production bonus of $16.0 million (2017: nil).  All costs are included with no deferral of costs associated with unrecognised sales in accordance with the Group's revenue policy. Production and depreciation, depletion and amortisation ("DD&A") costs related to revenue arrears recognised in 2018 and 2017 have been charged to the income statement in prior periods when the oil was lifted.

 

A unit-of-production method has been used to calculate the DD&A charge for the year. This is based on full entitlement production, commercial reserves and costs for Shaikan. Commercial reserves are proven and probable ("2P") reserves, estimated using standard recognised evaluation techniques. Production and reserves entitlement associated with unrecognised sales in accordance with the Group's revenue policy have been included in the full year DD&A calculation.

 

The breakdown of the 2017 comparative has been restated by $1.3 million to accurately show the full transportation costs, as part of this had previously been shown in oil production costs.

 

4.             General and Administration costs

 

 

2018
$'000

2017

$'000

 

 

 

Depreciation and amortisation

383

425

Auditor's remuneration for audit fees (see below)

252

219

Operating lease rentals

2,044

2,924

Other general and admin costs (including staff costs)

15,134

17,736

 

17,813

21,304

 

 

 

 

2018

$'000

2017

$'000

 

 

 

Fees payable to the Company's auditor for the audit of the Company's annual accounts

224

192

 

Fees payable to the Company's auditor for other services to the Group

 

 

- audit of the Company's subsidiaries pursuant to legislation

28

27

Total audit fees

252

219

 

Corporate finance services

-

5

Other assurance services (half year review)

70

67

Total fees

322

291

 

 

5. Staff costs

 

The average number of employees and contractors (including Executive directors) employed by the Group was as follows:

 

 

2018

Number

2017

Number

 

 

 

Office and management

76

76

Technical and operational

295

277

 

371

353

 

 

 

Staff costs in respect of those employees were as follows:

 

 

 

2018

$'000

2017

$'000

 

 

 

Wages and salaries

25,582

22,444

Social security costs

2,263

1,672

Share-based payment (see note 22)

1,842

2,712

 

29,687

26,828

 

The Group have restated the staff costs note to include the costs relating to contractors. These staff members are long term workers in key positions and therefore this presentation is a more accurate statement of the Group's staff costs.

 

A proportion of these costs is allocated to operating costs and a proportion is capitalised as Oil and gas assets under the Group's accounting policy for Property, plant and equipment, with the remainder classified as an administrative overhead costs in the income statement. The net staff cost recognised in the income statement is $25.6m (2017: $23.1m)

 

 6. Other gains

 

 

2018

$'000

2017

$'000

 

 

 

Other gains

10,215

272

Exchange gains

710

42

 

10,925

314

 

The Company has received final clearance from Sonatrach in relation to the Ferkane Permit (Block 126). This officially marks Gulf Keystone's exit from its Algerian operations, which resulted in a $10.2 million release of past liabilities recognised in other gains in 2018.

 

In 2017, other gains consisted of the release of the decommissioning liability relating to the Ber Bahr block of $0.3 million.
 

 

7. Finance costs and finance revenue

 

 

2018

$'000

2017

$'000

 

 

 

Notes interest charged during the year (see note 16)

(13,150)

(10,309)

Unwinding of discount on provisions (see note 17)

(723)

(714)

Total finance costs

(13,873)

(11,023)

Finance revenue

4,441

702

Net finance costs

(9,432)

(10,321)

 

8. Tax

 

2017

$'000

 

 

 

Current year charged

-

-

Adjustment in respect of prior year

-

-

Deferred UK corporation tax credit (see note 18)

189

61

Tax credit attributable to the Company and its subsidiaries

189

61

 

Under current Bermudian laws, 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 PSCs. The rate of corporate income tax is currently 15% on total income. 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.

 

UK corporation tax is calculated at 19.00% (2017: 19.25%) of the estimated assessable profit for the year of the UK subsidiary. 

Deferred tax is provided for due to the temporary differences, which give rise to such a balance in jurisdictions subject to income tax.  During the current period no taxable profits were made in respect of the Group's Kurdistan PSC, nor were there any temporary differences on which deferred tax is required to be provided. As a result, no corporate income tax or deferred tax has been provided for Kurdistan in the period.

All deferred tax arises in the UK.

The income / (expense) for the year can be reconciled to the profit / (loss) per the income statement as follows:

 

2018

$'000

2017

$'000

 

 

 

 

 

 

Profit before tax

79,700

14,065

 

 

 

Tax at the Bermudian tax rate of 0% (2017:0%)

                   -

-

Effect of different tax rates of subsidiaries operating in other jurisdictions

                189

61

Tax credit for the year

  189

61

 

 

 

9. Profit  per share

 

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

 

2018

$'000

2017

$'000

 

 

 

Profit

 

 

Profit after tax for the purposes of basic and diluted profit per share

79,889

14,126

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2018

Number

(000s)

2017

Number

(000s)

 

 

 

 

 

Number of shares

 

 

 

Basic weighted average number of shares

229,317

229,317

 

           

 

 

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

 

Reconciliation of dilutive shares:

 
 

2018

Number

(000s)

2017

Number

(000's)

Number of shares

 

 

 

 

 

Basic number of ordinary shares outstanding

229,317

229,317

Effect of dilutive potential ordinary shares

6,528

1,595

Diluted number of ordinary shares outstanding

235,845

230,912

 

The average number of ordinary shares in issue excludes shares held by Employee Benefit Trustee ("EBT") and the Exit Event Trustee.

 

The diluted number of ordinary shares outstanding including share options is calculated on the assumption of conversion of all potentially dilutive ordinary shares. During the year ended 31 December 2018, there were 0.3 million (2017: 0.5m) share options that were excluded from the calculation of diluted earnings because they were anti-dilutive.

 

10. Intangible assets

 

 

Computer

software

$'000

Total

$'000

Year ended 31 December 2017

 

 

Opening net book value

99

99

Amortisation charge

(47)

(47)

Foreign currency translation differences

11

11

Closing net book value

63

63

 

 

 

At 31 December 2017

 

 

Cost

1,064

1,064

Accumulated amortisation

(1,001)

(1,001)

Net book value

63

63

 

Year ended 31 December 2018

 

 

Opening net book value

63

63

Additions

66

66

Disposals at cost

(29)

(29)

Amortisation charge

(46)

(46)

Amortisation of disposals

29

29

Foreign currency translation differences

1

1

Closing net book value

84

84

 

 

 

At 31 December 2018

 

 

Cost

1,102

1,102

Accumulated amortisation

(1,018)

(1,018)

Net book value

84

84

 

The amortisation charge of $46,000 (2017: $47,000) for computer software has been included in general and administrative expenses (note 4).

 

 

 

11. Property, plant and equipment

 

 

Oil and Gas

Assets

$'000

Fixtures and

Equipment

$'000

 

Total

$'000

Year ended 31 December 2017

 

 

 

Opening net book value

488,634

745

489,379

Additions

8,059

114

8,173

Depreciation charge

(79,785)

(378)

(80,163)

Foreign currency translation differences

-

84

84

Closing net book value

416,908

565

417,473

 

 

 

 

At 31 December 2017

 

 

 

Cost

693,146

5,941

699,087

Accumulated depreciation

(276,238)

(5,376)

(281,614)

Net book value

416,908

565

417,473

 

 

 

 

           

 

Year ended 31 December 2018

 

 

 

Opening net book value

416,908

565

417,473

Additions

35,715

644

36,359

Disposals at cost

(126,584)

(399)

(126,983)

Revision to decommissioning charge

(2,229)

-

(2,229)

Depreciation charge

(70,744)

(337)

(71,081)

Depreciation on disposals

126,584

399

126,983

Foreign currency translation differences

-

15

15

Closing net book value

379,650

887

380,537

 

 

 

 

At 31 December 2018

 

 

 

Cost

600,048

6,201

606,249

Accumulated depreciation

(220,398)

(5,314)

(225,712)

Net book value

379,650

887

380,537

 

The net book value of oil and gas assets at 31 December 2018 is comprised of property, plant and equipment relating to the Shaikan block and has a carrying value of $379.7 million (2017: $416.9 million).

 

The additions to the Shaikan asset during the year include costs for the work on the export pipelines from both production facilities to the main export pipeline, SH-1 workover, work in preparation to the upcoming drilling campaign, production facilities improvement work and various studies and reservoir engineering.

 

The DD&A charge of $70.7 million on oil and gas assets (2017: $79.8 million) has been included within cost of sales (note 3). The depreciation charge of $0.3 million on fixtures and equipment (2017: $0.4 million) has been included in general and administrative expenses (note 4).

 

Additions during the year include capitalised staff costs of $4.0m (2017: $1.6m).

 

For details of the key assumptions and judgements underlying the impairment assessment and the depreciation, depletion and amortisation charge, refer to the "Critical accounting estimates and judgments" section of the Summary of Significant Accounting Policies.

 

 

12. Group companies

 

Details of the Company's subsidiaries and joint operations at 31 December 2018 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 services, including geological, geophysical and engineering services

Gulf Keystone Petroleum International Limited

Cumberland House

9th floor, 1 Victoria Street

PO Box 1561

Hamilton HMFX

Bermuda

Bermuda

 

100%

 

Exploration and evaluation activities in Kurdistan

 

 

Name of joint operation

 

Place of incorporation

 

Proportion of ownership interest

Principal

activity

 

Shaikan

 

Kurdistan

 

80%(1)

 

Production and development activities

 

 

(1) 75% is held directly by Gulf Keystone Petroleum International Limited, with 5% held in trust for Texas Keystone, Inc. ("TKI") until formal transfer of the share is completed.

 

 

During the year the following subsidiaries were dissolved:

 

Gulf Keystone Petroleum Numidia Limited

Gulf Keystone Petroleum HBH Limited

Shaikan Petroleum Limited

 

13.          Inventories

 

2018

$'000

2017

$'000

 

 

 

Warehouse stocks and materials

13,534

14,569

Crude oil

656

2,621

 

14,190

17,190

 

Inventories at 31 December 2018 include write downs to net realisable value of $0.6 million (2017: $0.4 million).

 

 

14. Trade and other receivables

 

 

2018

$'000

2017

$'000

 

 

 

Trade receivables

61,251

57,887

Other receivables

5,405

3,260

Prepayments and accrued income

1,253

563

 

67,909

61,710

 

Trade receivables comprise invoiced amounts due from the MNR for crude oil sales totalling $53.2 million as at 31 December 2018 (2017: $57.9 million), which have all been received subsequent to the year end. This included past due trade receivables of $40.9 million (2017: $42.6 million). During 2018, the Group purchased a share of Shaikan revenue arrears from MOL amounting to $9.1 million. In line with the requirements of IFRS 9, the fair value of this receivable stood at $8.0 million as at 31 December 2018. The adjustment to the fair value is recognised in Cost of sales (note 3).

 

Included within Other receivables for 2018 is an amount of $0.4 million (2017: $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 2018 (2017: $nil) (see note 23). No impairments of other receivables have been recognised during the year (2017: $nil).

 

The directors consider that the carrying amount of trade and other receivables approximates to their fair value and no amounts are provided against them.

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.

 

 

2018

$'000

2017

$'000

Trade payables

11,857

2,687

Other payables

19,552

26,168

Accrued expenses

50,069

28,183

 

81,478

57,038

 

There is $4.4 million interest payable included in Accrued expenses as at 31 December 2018 (2017: $2.0m) (see note 16).

 

In 2018, Other payables included $10 million (2017: $10 million) in relation to the Sheikh Adi PSC bonus that was payable on the declaration of commerciality. It is likely that this liability will be offset against unrecognised Shaikan revenue arrears, in accordance with the principles agreed under the Bilateral Agreement between the Group and the MNR.  In 2017, the other payables balance also included $16.2 million of payments received in excess of the Group's revenue entitlements from the MNR under the Bilateral Agreement. In 2018, this amount was transferred to revenue as an offset of past revenue arrears.

 

 

16. Long term borrowings and warrants

 

 

 

2018

$'000

2017

$'000

 

 

 

Liability component at 1 January

99,084

98,886

 

 

 

Interest charged during the year

13,150

10,309

Interest paid during the year

(7,713)

(10,111)

Exchange or redemption of Reinstated Notes

(100,000)

-

Issue of New Notes at fair value

97,635

-

Liability component at 31 December

102,156

99,084

 

Liability component reported in:

 

 

2018

$'000

2017

$'000

 

 

 

Current liabilities: (see note 15)

4,361

2,017

Non-current liabilities

97,795

97,067

 

102,156

99,084

 

On 14 October 2016, the Company issued $100 million of guaranteed notes ("Reinstated Notes").  The unsecured Reinstated Notes were guaranteed by Gulf Keystone Petroleum International Limited, one of the Company's subsidiaries, and their key terms are summarised as follows:

 

-        maturity date was 18 October 2021. At any time prior to maturity, the Reinstated Notes were redeemable in part or full at par and could therefore be refinanced without any prepayment penalty;

-        the Company had the option to defer its interest payments until the maturity of the Reinstated Notes in payment in kind at 13% or pay in cash at 10% until 18 October 2018. From 19 October 2018, the Company would be mandatorily liable to pay interest in cash at 10%; and

-        the Company was permitted to raise up to $45 million of additional indebtedness at any time on market terms to fund capital and operating expenditure.

 

In July 2018, the Group redeemed all of the $100 million Reinstated Notes at a price equal to 100 per cent of the principal, plus accrued and unpaid interest on the Notes up to and including the Redemption Date. The Group also successfully completed the private placement of a 5-year senior unsecured $100 million bond issue (the "New Notes"). The unsecured New Notes are guaranteed by Gulf Keystone Petroleum International Limited and Gulf Keystone Petroleum (UK) Limited, two of the Company's subsidiaries, and their key terms are summarised as follows:

 

-        maturity date is 25 July 2023;

-        at any time prior to maturity, the New Notes are redeemable in part or full with a prepayment penalty;

-        the interest rate is 10% per annum with semi-annual payment dates; and

-        the Company is permitted to raise up to $200 million of additional indebtedness at any time on market terms to fund capital and operating expenditure.

 

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

 

 

Market price

2018

$'000

2017

$'000

 

 

 

 

New Notes

$102.75

102,750

-

Reinstated Notes

$0.98241

-

98,241

 

 

102,750

98,241

 

As of 31 December 2018, the Group's remaining contractual liability comprising principal and interest based on undiscounted cash flows at the maturity date of the New Notes is as follows:

 

 

 

 

2018

$'000

2017

$'000

 

 

 

Within one year

10,000

10,000

Within two to five years

135,639

130,000

 

145,639

140,000

 

 

17. Provisions

 

 

2018

$'000

2017

$'000

 

 

 

Current provisions

4,155

7,197

Non-current provisions

22,600

24,107

 

26,755

31,304

 

 

Current Provisions (Algeria)

Non-current Provisions (Kurdistan)

 

 

Total

Decommissioning provision

$'000

$'000

$'000

At 1 January 2018

7,197

24,107

31,304

New provisions and changes in estimates

-

(2,230)

(2,230)

Unwinding of discount

-

723

723

Release of provisions

(3,042)

-

(3,042)

At 31 December 2018

4,155

22,600

26,755

 

The provision for decommissioning is based on the net present value of the Group's share of expenditure which may be incurred in the removal and decommissioning of the wells and facilities currently in place and restoration of the sites to their original state. The expenditure on the Shaikan block in Kurdistan is expected to take place over the next 25 years.

 

In January 2019, the Group made a payment of $4.2 million in final settlement of all Algerian decommissioning liabilities.

 

 

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 2017

(82)

36

356

310

(Charge)/credit to income statement

21

92

(52)

61

Exchange differences

(7)

8

31

32

At 31 December 2017

(68)

136

335

403

(Charge)/credit to income statement

37

202

(50)

189

Exchange differences

1

(18)

(16)

(33)

At 31 December 2018

(30)

320

269

559

 

 

19. Share capital

 

 

2018

$'000

2017

$'000

Authorised

 

 

 

 

 

Common shares of $1 each (2017: $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

 

 

      Share

Share

 

No. of shares

Amount

            capital

premium

 

000

$'000

               $'000

$'000

Balance 31 December 2016

229,430

1,150,158

229,430

920,728

 

 

 

 

 

Balance 31 December 2017

229,430

1,150,158

229,430

920,728

 

 

 

 

 

Balance 31 December 2018

229,430

1,150,158

229,430

920,728

             

 

 

At 31 December 2018, a total of 0.1 million common shares at $1.0 each were held by the EBT (2017: 0.1 million at $1.0 each) and 0.1 million shares at $1.0 each were held by the Exit Event Trustee (2017: 0.1 million at $1.0 each). All 0.2 million common shares were included within reserves (2017: 0.2 million).

 

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.

 

 

20. Reconciliation of Profit from operations to Cash generated from operations

 

 

2018

$'000

2017

$'000

 

 

 

 

 

 

Profit from operations

78,207

24,072

 

 

 

Adjustments for:

 

 

 

 

 

Depreciation, depletion and amortisation of property, plant and equipment

              71,081

80,163

Amortisation of intangible assets

46

47

Other gains or losses

-

(11)

Share-based payment expense

1,785

2,710

(Increase)/ decrease in inventories

3,000

(1,219)

(Increase) in receivables

(4,330)

(20,125)

Increase/ (decrease) in payables

11,695

(337)

Cash generated from operations

161,483

85,300

 

 

The increase in receivable includes $8.0m relating to the purchase of a share of Shaikan revenue arrears from MOL

 

 

21. Commitments

 

Operating lease commitments - the Group as a lessee

 

2018

$'000

2017

$'000

 

 

 

Minimum lease payments under operating leases recognised as expense for the year

2,019

2,924

 

At the balance sheet date, the Group had outstanding total commitments under non-cancellable operating leases, which fall due as follows:

 

 

2018

$'000

2017

$'000

 

 

 

Within one year

2,264

1,144

Within two to five years

1,608

                 1,519

 

3,872

2,663

 

Operating lease payments represent rentals payable by the Group for certain of its office and residence properties, facilities and vehicle rentals in the United Kingdom and the Kurdistan Region of Iraq. The non-cancellable operating leases within Kurdistan are up to one year in duration.

 

Exploration and development commitments

 

Due to the nature of the Group's operations in exploring and evaluating areas of interest and development of assets, it is difficult to accurately forecast the nature or amount of future expenditure.

 

Expenditure commitments on current permits for the Group could be reduced by selective relinquishment of exploration tenure, by the sale of assets or by the renegotiation of expenditure commitments. Capital commitments of $29.9 million are expected in the year ending 31 December 2019 for the Group (2018: $nil).

 

 

22. Share-based payments

 

 

2018

$'000

2017

$'000

 

 

 

Share options charge

1,842

2,710

 

1,842

2,710

 

 

Value Creation Plan

 

The VCP was approved by shareholders in December 2016 and, as of 31 December 2018, one award of Performance Units has been made to the CEO and CFO.  No further awards of Performance Units are envisaged. Any outstanding awards under the VCP will be allowed to run-off and vest subject to the Company achieving the performance criteria of 8% compound annual growth in TSR on each of five annual Measurement Dates and the plan limits in place, in accordance with the VCP rules.  As such, it may be possible that additional conversions of the Performance Units into nil-cost options may occur in future (up to but not later than 2022).

 

 

Following the first measurement date on 15 May 2018, nil-cost options over 1,681,839 shares were granted to each of the CEO and CFO.  The Executive Directors are not eligible to participate in any other long-term incentive scheme until the VCP has ended

 

 

2018

2017

 

 

Number of

share options

'000

Weighted average

exercise price

(in pence)

 

Number of

share options

'000

Weighted

average

exercise price

(in pence)

 

 

 

 

 

Outstanding at 1 January

-

-

-

-

Granted during the year

                  3,364

-

-

-

Outstanding at 31 December

                  3,364

-

-

-

 

 

 

 

 

Exercisable at 31 December

-

-

-

-

 

Depending on the achievement of the performance criteria, the nil-cost options will vest as follows: 50% in May 2020, 25% in May 2021, and 25% in May 2022.

 

A charge of $0.6 million (2017: $1.1 million) in relation to the VCP is included in the total share options charge.

 

Staff Retention Plan

 

At the 2016 Annual General Meeting, 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 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, the options may be exercised at any time within a period of six months from departure date.

 

 

 

 

       2018

 

 

          2017

 

 

Number of

share options

'000

Weighted average

exercise price

(in pence)

 

Number of

share options

'000

Weighted

average

exercise price

(in pence)

 

 

 

 

 

Outstanding at 1 January

1,595

-

1,402

-

Granted during the year

-

-

611

-

Exercised during the year

-

-

(325)

-

Forfeited during the year

(155)

-

(93)

-

Outstanding at 31 December

                  1,440

-

1,595

-

 

 

 

 

 

Exercisable at 31 December

-

-

-

-

 

 

The options outstanding at 31 December 2018 had a weighted average remaining contractual life of 8 years.

 

During 2018 no options (2017: 611,000) were granted to employees under the Group's SRP.

 

The inputs into the stochastic (binomial) valuation model were as follows:

 

 

2018

2017

 

 

 

Weighted average opening share price on date of grant (in pence)

                    n/a 

119.47 

 

 

 

 

The expected volatility was calculated as 97.2% for the January 2017 awards, 94.0% for the early July 2017 awards, 94.1% for the July 2017 awards and has been based on the Company's share price volatility averaged for the three years prior to grant date.

 

The expected weighted average term of the SRP options is 3 years. The risk free rate for the options awarded was 0.26% for January 2017 awards, 0.43% for early July 2017 and 0.32% for late July 2017.

 

The weighted average fair value of the options granted in 2017 was £1.19.

 

The Company has not made a dividend payment to date and, as there was no expectation of making payments in the immediate future following grants of the SRP options in 2016 and 2017 the dividend yield variable has been set at zero for all grants.

 

A charge of $0.8 million (2017: $0.9 million) in relation to the SRP is included in the total share options charge.

 

Share options outstanding at the end of the year have the following expiry date and exercise prices:

 
Expiry date

 

 

Exercise price (pence)

 

Options ('000)

 

 

2018

2017

2018

2017

 

 

 

 

 

11 December 2026

-

-

939

994

09 January 2027

-

-

250

350

30 June 2027

-

-

206

206

30 July 2027

-

-

45

45

 

 

 

1,440

1,595

           

 

Long Term Incentive option plan

 

At the 2016 Annual General Meeting, shareholders approved the adoption of the Gulf Keystone Petroleum 2016 Long Term Incentive Plan ("LTIP"), which is designed to reward members of staff through the grant of share options at a zero exercise price, that vests three years after grant, subject to the fulfilment of specified performance conditions. These performance conditions attached to the 2018 LTIP grant are 50% Group's  Total Shareholder Return ("TSR") over the vesting period and 50% the Group's TSR relative to a bespoke group of comparators.

 

 

2018

2017

 

 

Number of

share options

'000

Weighted average

exercise price

(in pence)

 

Number of

share options

'000

Weighted

average

exercise price

(in pence)

 

 

 

 

 

Outstanding at 1 January

-

-

-

-

Granted during the year

1,786

-

-

-

Forfeited during the year

(172)

-

-

-

Outstanding at 31 December

                  1,614

-

-

-

 

 

 

 

 

Exercisable at 31 December

-

-

-

-

 

A charge of $0.5 million (2017: nil million) in relation to the LTIP is included in the total share options charge.

 

Equity-settled share option plan

 

The Group's share option plan provides for an exercise price at least equal to the closing market price of the Group shares on the date prior to grant.  Awards made under the Group's share option plan have a vesting period of at least three years except for awards made under the legacy Long Term Incentive Plan, which vest in equal tranches over a minimum of three years subsequent to the achievement of a number of operational and market-based performance conditions.  Options expire if they remain unexercised after a period of 10 years from the date of grant. The options granted in 2015 were made under the recruitment remuneration policy, vest in three equal tranches over two years, and expire if they remain unexercised after a period of 7 years from the date of grant. Options are forfeited if the employee leaves the Group before the options vest. The company has not made any awards during 2018 under this scheme.

 

 

 

2018

2017

 

 

Number of

share options

'000

Weighted average

exercise price

(in pence)

 

Number of

share options

'000

Weighted

average

exercise price

(in pence)

 

 

 

 

 

Outstanding at 1 January

360

10,149.7

360

10,190.0

Expired during the year

(34)

-

-

-

Outstanding at 31 December

326

11,492.6

360

10,149.7

 

 

 

 

 

Exercisable at 31 December

326

11,492.6

360

10,149.7

No options were exercised, granted or cancelled in 2018 (2017: nil).

 

The options outstanding at 31 December 2018 had a weighted average exercise price of £115 (2017: £102) and a weighted average remaining contractual life of 2 years (2017: 3 years).

 

A charge of nil (2017: $0.69 million) in relation to the equity-settled share option plan is included in the total share options charge.

 

Share options outstanding at the end of the year have the following expiry date and exercise prices:

 

 
Expiry date

 

 

Exercise price (pence)

 

Options ('000)

 

 

2018

2017

2018

2017

 

 

 

 

 

13 February 2018

3,000

3,000

-

11.0

24 September 2018

3,000

3,000

-

20.1

15 March 2019

3,000

3,000

15.9

15.9

30 July 2019

3,000

3,000

10.0

10.0

24 Jun 2020

7,500

7,500

156.3

156.3

22 September 2020

14,750

14,750

2.5

2.5

10 October 2020

17,500

17,500

-

2.5

6 February 2021

17,500

17,500

94.4

94.4

19 June 2021

14,625

14,625

5.5

5.5

7 July 2021

14,625

14,625

2.5

2.5

14 July 2021

14,625

14,625

2.5

2.5

21 July 2021

14,625

14,625

5.0

5.0

19 September 2021

15,250

15,250

2.5

2.5

26 October 2021

14,625

14,625

2.5

2.5

21 January 2022

5,500

5,500

15.0

15.0

20 March 2022

19,450

19,450

4.0

4.0

20 March 2022

25,000

25,000

2.5

2.5

8 July 2023

15,875

15,875

2.5

2.5

24 April 2024

9,975

9,975

2.5

2.5

 

 

 

326.1

359.7

 

 

Exit Event Awards

 

In March 2012, the Remuneration Committee recommended that the Company make cash settled awards to certain Executive Directors and employees conditional on the occurrence of an Exit Event (as defined below) up to a maximum amount equivalent to the value of 0.1 million common shares (adjusted for consolidation on 100:1 basis) at the time of an Exit Event. A trustee (the "Exit Event Trustee") was appointed to hold and, subject to the occurrence of an Exit Event, to sell sufficient common shares to satisfy the Exit Event Awards.

 

As at 31 December 2018, the Exit Event Trustee held 0.1 million common shares to satisfy any future Exit Event Awards to full-time employees of the Company and subsidiary companies, subject to the occurrence of an Exit Event, with such beneficiaries to be determined in due course. Any Exit Event awards previously made to the Directors and employees of the Group have expired.

 

An Exit Event envisages a sale of either the Company or a substantial proportion (i.e. more than 50%) of its assets.

 

23. Related party transactions

 

The Group has a related party relationship with its subsidiaries. The Company and its subsidiaries, in the ordinary course of business, enter into various sales, purchase and service transactions with joint operations in which the Group 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 key management personnel

 

The remuneration of the Directors and Officers, the key management personnel of the Group, is set out below in aggregate for each of the categories specified in IAS 24 Related Party Disclosures.  Those identified as key management personnel include the Directors of the Company and the following key personnel:

 

 

J Barker - HR Director

S Catterall - Chief Operations Officer

B Demont - Development Manager - Kurdistan Region of Iraq

N Kernoha - Head of Finance

W McAvock - Financial Controller

G Papineau-Legris - Commercial Director

A Robinson - Legal Director & Company Secretary

 

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

 

2018

$'000

2017

$'000

 

 

 

Short-term employee benefits              

5,444

6,514

Share-based payment - options

1,132

1,630

 

6,576

8,144

 

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

 

24.          Financial instruments

 

2018

$'000

2017

$'000

 

 

 

Financial assets

 

 

Cash and cash equivalents

295,566

160,456

Loans and receivables

66,656

61,148

 

362,222

221,604

 

 

 

Financial liabilities

 

 

Trade and other payables

81,478

57,038

Borrowings

97,795

97,067

 

179,273

154,105

 

All loans and payables, except for the New Notes, are due to be settled within one year and are classified as current liabilities.

 

The maturity profile and fair values of the New Notes are disclosed in note 16. The maturity profile of all other financial liabilities is indicated by their classification in the balance sheet as "Current" or "Non-current".  Further information relevant to the Group's liquidity position is disclosed in the Directors' Report under "Going Concern".

 

Fair values of financial assets and liabilities

 

With the exception of the New Notes, the Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The fair value of the New Notes, as determined using market values at 31 December 2018, was $102.8 million (2017: Reinstated Notes $98.2 million) compared to the carrying value of $97.8 million (2017: Reinstated Notes $97.1 million).

 

No material financial assets are impaired at the balance sheet date. All financial assets and liabilities, with the exception of derivatives, 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 balance. The capital structure of the Group consists of cash, cash equivalents, New Notes and equity attributable to equity holders of the parent. Equity comprises issued capital, reserves and accumulated losses as disclosed in Note 19, the Consolidated Statement of Comprehensive Income and the Consolidated Statement of Changes in Equity.

 

Capital Structure

 

The Group'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, as well as the impact of adoption of IFRS 9, 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.

 

The Group currently has no currency risk or other hedges against financial risks as the benefit of entering into such agreements is not considered to be significant enough to outweigh the significant cost and administrative burden associated with such hedging contracts. The Group does not use derivative financial instruments for speculative purposes.

 

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

 

Market risk

 

The Group's activities expose it primarily to the financial risks of changes in foreign currency exchange rates, oil prices 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 or any changes to the manner in which the Group manages and measures the risk.  The Group does not hedge against the effects of movement in oil prices or foreign currency rates. 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 2018, 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 current assets or profit before tax.

 

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. The Group must pay interest on its New Notes semi-annually in cash at 10%.

 

Based on the exposure to the 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 for the year or the previous year.  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 2018, the maximum exposure to credit risk from a trade receivable outstanding from one customer is $61 million (2017: $60 million). 

 

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 good 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.  In common with many exploration companies, the Group raises finance for its exploration and appraisal activities in discrete tranches to finance its activities for limited periods.  The Group seeks to raise further funding as and when required.

 

25. Contingent liabilities

 

The Group has a contingent liability of $27 million (2017: $27 million) in relation to the proceeds from the sale of test production in the period prior to the approval of the Shaikan Field Development Plan ("FDP") in July 2013. The Shaikan PSC does not appear to address expressly any party's rights to this pre-FDP petroleum. This suggests that there must have been some other agreement, understanding or arrangement between GKP and the KRG as to how this pre-FDP petroleum would be lifted and sold. 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 (GKP and MOL), 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 does not consider that a probable material payment is payable to the KRG.  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.

 

 

 


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