REG-Gulf Keystone Petroleum Ltd 2025 Half Year Results Announcement
Yesterday 07:02
============
Gulf Keystone Petroleum Ltd (GKP)
2025 Half Year Results Announcement
28-Aug-2025 / 07:00 GMT/BST
══════════════════════════════════════════════════════════════════════════
28 August 2025
Gulf Keystone Petroleum Ltd. (LSE: GKP)
(“Gulf Keystone”, “GKP”, “the Group” or “the Company”)
2025 Half Year Results Announcement
Gulf Keystone, a leading independent operator and producer in the
Kurdistan Region of Iraq, today announces its results for the half year
ended 30 June 2025.
Jon Harris, Gulf Keystone’s Chief Executive Officer, said:
“We delivered strong operational and financial performance in the first
half of 2025, with material free cash flow generated from increased
production and realised prices, capital discipline and cost control.
Following the temporary shut-in of the Shaikan Field in July related to
security concerns, production restarted earlier this month after
consultation with the Kurdistan Regional Government and has gradually
ramped back up towards full well capacity. Given the return to stable
sales and our robust cash balance, we are pleased to announce today the
declaration of a $25 million interim dividend, increasing total dividends
declared in 2025 to $50 million.
Looking ahead, we have tightened 2025 gross average production guidance to
40,000 - 42,000 bopd primarily reflecting the production losses from
recent temporary disruptions. We are excited to have sanctioned the
installation of water handling facilities at PF-2 which we expect, once
operational, to unlock incremental production above the anticipated field
baseline and reduce downside risk to reservoir recovery. We continue to
engage with government stakeholders regarding the restart of Kurdistan
crude exports, with increasing momentum towards a solution in recent
weeks.”
Highlights to 30 June 2025 and post reporting period
Operational
• Zero Lost Time Incidents for over 950 days with rigorous focus on
safety maintained
• Gross average production increased 12% to 44,100 bopd in H1 2025 (H1
2024: 39,252 bopd), reflecting consistently robust local market demand
and good reservoir performance
• Gross average production of c.40,600 bopd in 2025 year to date (as at
26 August 2025):
◦ Primarily reflects precautionary field shut-in in July following
drone attacks on certain other oil fields in Kurdistan
◦ Production has gradually returned towards full well capacity
after operations were restarted in August following a security
assessment and consultation with the Kurdistan Regional
Government (“KRG”)
◦ Realised prices have averaged around $27-$28/bbl in the post
reporting period
• Continued execution of disciplined work programme focused on safely
maintaining existing production capacity and reliability
• Investment decision taken on installation of water handling facilities
at PF-2:
◦ Commissioning expected at the beginning of 2027
◦ Once operational, the facilities are expected to unlock an
estimated 4,000 - 8,000 bopd of incremental gross production
above the anticipated field baseline while reducing reservoir
risk
◦ To minimise upfront capital expenditure and provide flexibility,
the facilities will be leased over multiple years following
commissioning, with limited incremental net capex expected in
2025
Financial
• Free cash flow generation of $24.6 million in H1 2025 (H1 2024: $26.6
million), enabled by increased production and realised prices, capital
discipline and cost control
• Adjusted EBITDA increased 13% to $41.1 million (H1 2024: $36.4
million) as higher production, stronger prices and lower other G&A
expenses offset the increase in operating costs and share option
expense:
◦ Revenue increased 17% to $83.1 million (H1 2024: $71.2m) as
strong production was bolstered by a 6% increase in the average
realised price during the period to $27.8/bbl (H1 2024:
$26.3/bbl)
◦ Gross operating costs per barrel of $4.2/bbl were flat (H1 2024:
$4.2/bbl), with the decrease from the 2024 average of $4.4/bbl
primarily reflecting higher production
• Net capital expenditure of $18.1 million (H1 2024: $7.8 million)
reflecting the Company’s focused work programme of safety critical
upgrades at PF-2 and production optimisation expenditures:
◦ Includes a non-cash charge of $5.4 million associated with the
capitalisation of drilling inventory previously classified as
held for sale
• Interim dividend of $25 million paid in H1 2025 (H1 2024 shareholder
distributions: $21 million)
• Cash balance of $99.0 million as at 30 June 2025 (31 December
2024: $102.3 million), with no outstanding debt; latest balance as
at 27 August 2025 of $105.7 million
Outlook
• 2025 gross average production expected to be between 40,000 – 42,000
bopd (previous guidance: 40,000 - 45,000 bopd), reflecting production
losses from the recent temporary disruptions:
◦ Guidance remains subject to local sales demand and a stable
security environment
• 2025 net capital expenditure expected to be $30-$35 million (previous
guidance: $25-$30 million):
◦ Unchanged expectation of c.$20 million net capex on PF-2 safety
upgrades and maintenance and $5-$10 million on production
optimisation initiatives
◦ Increase in guidance primarily reflects the incremental net capex
associated with the water handling project
• Unchanged guidance for operating costs of $50-$55 million and other
G&A expenses below $10 million
• The Company is pleased to declare a $25 million interim dividend,
equivalent to 11.52 US cents per Common Share based on the Company's
total issued share capital as at 27 August 2025:
◦ The dividend will be paid on 30 September 2025, based on a record
date of 12 September 2025 and ex-dividend date of 11 September
2025
◦ Shareholders will have the option of being paid the dividend in
either GBP or USD, with the default currency GBP
• The Company continues to engage with government stakeholders regarding
a solution to enable the restart of Kurdistan crude exports through
the Iraq-Türkiye Pipeline:
◦ The Company remains ready to resume oil exports provided
satisfactory agreements are reached on payment surety for future
oil exports, repayment of outstanding receivables and
preservation of current contract economics
Investor & analyst presentation
GKP’s management team will be hosting a presentation for investors and
analysts at 10:00am (BST) today via live audio webcast:
1 https://brrmedia.news/GKP_GY_25
Sell-side analysts are requested to join the meeting via the dial-in
details provided to them separately and ask questions verbally. Investors
are encouraged to pre-submit written questions via the webcast
registration page, with the opportunity to submit questions live during
the presentation.
A recording of the presentation will be made available on GKP’s website.
This announcement contains inside information for the purposes of the UK
Market Abuse Regime.
Enquiries:
Gulf Keystone: +44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations
& Corporate Communications 2 aclark@gulfkeystone.com
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton
3 GKP@fticonsulting.com
Nick Hennis
or visit: 4 www.gulfkeystone.com
Notes to Editors:
Gulf Keystone Petroleum Ltd. (LSE: GKP) is a leading independent operator
and producer in the Kurdistan Region of Iraq. Further information on Gulf
Keystone is available on its website: 5 www.gulfkeystone.com
Disclaimer
This announcement contains certain forward-looking statements that are
subject to the risks and uncertainties associated with the oil & gas
exploration and production business. These statements are made by the
Company and its Directors in good faith based on the information available
to them up to the time of their approval of this announcement but such
statements should be treated with caution due to inherent risks and
uncertainties, including both economic and business factors and/or factors
beyond the Company's control or within the Company's control where, for
example, the Company decides on a change of plan or strategy. This
announcement has been prepared solely to provide additional information to
shareholders to assess the Group's strategies and the potential for those
strategies to succeed. This announcement should not be relied on by any
other party or for any other purpose.
CEO review
The Company performed well in the first half of 2025, with consistently
robust local market demand and good reservoir performance enabling
increased production relative to the prior year period. Capital and cost
discipline continued to underpin free cash flow generation and shareholder
distributions. While temporary market disruption and security concerns
impacted sales in June and July respectively, production has gradually
returned towards full well capacity in August. We have also seen increased
momentum towards an exports restart solution in our engagement with
government stakeholders in recent weeks.
We have maintained a rigorous focus on safety in 2025 year to date,
extending our track record of days without a Lost Time Incident to over
950.
Gross average production in the first half of 2025 was 44,100 bopd, a 12%
increase relative to H1 2024. Local market demand for Shaikan Field crude
was consistently strong between January to May 2025, enabling monthly
gross average production above 45,000 bopd. Sales reduced in June because
of trucking shortages around the Eid Al-Adha holiday and some disruptions
during the conflict between Israel and Iran. Average realised prices in H1
2025 were relatively healthy at $27.8/bbl, 6% higher compared to the prior
year period. The Company’s ability to meet buyer demand was enabled by
good reservoir performance, with successful production optimisation
initiatives offsetting natural field declines and well maintenance.
Gross production has averaged c.40,600 bopd in the year to date as at 26
August 2025, with the reduction relative to the first half average
primarily reflecting the temporary shut-in of the Shaikan Field on 15 July
2025 following drone attacks on a number of oil fields close to our
operations and elsewhere in Kurdistan. The safety of Gulf Keystone’s staff
is always our top priority and we acted quickly to move employees and
contractors to safe locations. Earlier this month, the Company restarted
production operations following a security assessment and consultation
with the KRG. Following a gradual ramp up, production levels have returned
towards full well capacity.
The Company has continued to execute its disciplined work programme,
progressing safety upgrades at PF-2 and executing production optimisation
initiatives. As previously announced, the planned shut-in of PF-2 that had
been scheduled to take place in Q4 2025 to tie-in the safety upgrades was
deferred to 2026 to support production and provide greater work programme
flexibility.
Increased production, stronger prices and continued capital and cost
discipline enabled the Company to generate $24.6 million of free cash flow
in the first half of 2025. In line with our commitment to return excess
cash to shareholders, we paid a $25 million interim dividend in April.
The Company has recently sanctioned the installation of water handling
facilities at PF-2. Engineering design work has commenced and
commissioning is currently expected at the beginning of 2027.
Once operational, the facilities are expected to unlock an estimated 4,000
- 8,000 bopd of incremental gross production above the anticipated field
baseline from existing constrained wells and reduce downside risk to
reservoir recovery. The facilities will add additional wet oil processing
capacity of around 17,000 bopd to the Shaikan Field’s existing dry oil
processing capacity of around 60,000 bopd. While there are no indications
of a near term increase in water ingress following an extraordinary track
record of dry oil production to date of over 145 MMstb, we have long
viewed water handling as a critical component of the Shaikan Field’s
development and natural life cycle.
To reduce costs, we have sourced second hand facilities and are combining
them with an existing oil train at PF-2. To minimise upfront capital
expenditure and provide flexibility, the facilities will be leased over
multiple years following commissioning. Limited incremental net capital
expenditure is expected in 2025, with total costs during the construction
phase ahead of commissioning estimated at approximately $12 million net to
GKP. The facilities are expected to generate positive cash flow, even in a
local sales environment, with future operating costs associated with the
lease and water disposal expected to be more than covered by the
anticipated incremental production.
Looking ahead to the remainder of the year, we are expecting 2025 gross
average production to be between 40,000 - 42,000 bopd (previous guidance:
40,000 - 45,000 bopd), reflecting the impact of the temporary disruptions
experienced from June to August. We continue to progress our production
optimisation programme, with additional well workovers planned in the
second half of the year, while managing natural field declines and certain
wells constrained by water and gas. The guidance remains subject to local
sales demand and a stable security environment.
2025 net capital expenditure is expected to be $30-$35 million (previous
guidance: $25-$30 million), primarily reflecting the incremental capex
associated with water handling.
The Company, along with other international oil companies (“IOCs”)
operating in Kurdistan, has been continuing to engage with government
stakeholders and other relevant parties regarding the restart of Kurdistan
exports. The past few weeks have been characterised by increased levels of
activity as we focus on securing written agreements. We are hopeful of
reaching a solution soon and remain ready to restart exports quickly.
Jon Harris
Chief Executive Officer
27 August 2025
Financial review
Key financial highlights
Six months Six months
Year ended
ended ended
31 December
30 June 2025 30 June 2024
2024
Gross average production(1) bopd 44,100 39,252 40,689
Dated Brent(2) $/bbl 71.9 84.1 80.8
Realised price(1) $/bbl 27.8 26.3 26.8
Discount to Dated Brent $/bbl 44.1 57.8 53.9
Revenue $m 83.1 71.2 151.2
Operating costs $m 26.9 23.9 52.4
Gross operating costs per $/bbl 4.2 4.2 4.4
barrel(1)
Other general and administrative $m 4.6 5.4 11.4
expenses
Share option expense $m 4.4 2.1 4.4
Adjusted EBITDA(1) $m 41.1 36.4 76.1
(Loss)/profit after tax $m (7.2) 0.4 7.2
Basic (loss)/earnings per share cents (3.3) 0.2 3.3
Revenue receipts(1) $m 78.2 65.5 144.1
Net capital expenditure(1) $m 18.1 7.8 18.3
Free cash flow(1) $m 24.6 26.6 65.4
Shareholder distributions(3) $m 25 21 45
Cash and cash equivalents $m 99.0 102.3 102.3
1. Represents either a non-financial or non-IFRS measure which are
explained in the summary of non-IFRS measures where applicable.
2. Provided as a comparator for realised price. Realised prices for local
sales remain driven by supply and demand dynamics in the local market,
with no direct link to Dated Brent.
3. H1 2025: $25 million dividend; H1 2024: $15 million dividend and $6
million of the Company’s $10 million share buyback programme launched
on 13 May 2024 and completed on 23 July 2024; FY 2024: $35 million of
dividends and $10 million of completed share buybacks.
Gulf Keystone continued to generate material free cash flow in the first
half of 2025, supported by increased production and realised prices,
capital discipline and cost control. The strong financial performance
funded the payment of a $25 million interim dividend to shareholders while
maintaining the Company’s robust, debt-free balance sheet. With production
having returned towards full well capacity following the temporary July
shut-in and a robust cash balance, the Board has approved the declaration
of an additional $25 million interim dividend. Looking ahead, we remain
focused on maintaining capital and cost discipline to drive free cash flow
from local sales as we work towards the restart of exports.
Adjusted EBITDA
Adjusted EBITDA increased 13% to $41.1 million in H1 2025 (H1 2024: $36.4
million) as higher production, stronger realised prices and lower other
G&A expenses more than offset the increase in operating costs and share
option expense.
Gross average production increased 12% to 44,100 bopd in H1 2025 (H1 2024:
39,252 bopd) reflecting consistently robust demand from a more established
local sales market and good reservoir performance.
H1 2025 revenue increased 17% to $83.1 million (H1 2024: $71.2 million) as
strong production volumes were complemented by a 6% increase in the
average realised price during the period to $27.8/bbl (H1 2024:
$26.3/bbl). Realised prices have averaged around $27-$28/bbl since June.
The Company continued to carefully manage its cost base in the first half
of 2025 while safely maintaining the production capacity of the Shaikan
Field. Gross operating costs per barrel of $4.2/bbl were flat relative to
the prior period (H1 2024: $4.2/bbl), with the decrease from the 2024
average of $4.4/bbl primarily reflecting higher production. Operating
costs in the first half of 2025 increased by 13% to $26.9 million (H1
2024: $23.9 million), principally reflecting higher production and well
service costs to bring two wells back online.
Other G&A expenses decreased 15% to $4.6 million in H1 2025 (H1 2024: $5.4
million), primarily reflecting the absence of one-off retention awards
accrued for in 2024 and paid in Q1 2025.
Share option expense was $4.4 million in H1 2025 (H1 2024: $2.1 million),
reflecting the higher vesting in April 2025 of a greater number of awards
associated with the 2022 LTIP relative to the vesting of the 2021 LTIP
award in 2024.
(Loss)/profit after tax
The Company reported a loss after tax of $7.2 million in the first half of
2025 (H1 2024 profit after tax: $0.4 million), principally reflecting an
$8.9 million charge to the expected credit loss (“ECL”) provision
associated with the outstanding export sales receivables. The non-cash
charge reflects a revision of the previously modelled ITP reopening date
and updated commercial assumptions (see note 12 to the financial
statements for further detail).
Cash flows
Revenue receipts, which reflect cash received in the period for the
Company’s net entitlement of production sales, were $78.2 million, 19%
higher year-on-year (H1 2024: $65.5 million) primarily driven by higher
production and stronger realised prices.
Net capital expenditure in H1 2025 was $18.1 million (H1 2024: $7.8
million), as the Company progressed its disciplined work programme
comprised of safety-critical upgrades at PF-2 and production optimisation
expenditures. Net capex in the period included a non-cash charge of $5.4
million associated with the capitalisation of drilling inventory purchased
and paid for in 2022 and 2023 that had previously been classified as held
for sale following the wind down of the Company’s expansion programme in
2023 (see note 10 to the financial statements for further detail).
Free cash flow decreased 8% to $24.6 million in H1 2025 (H1 2024: $26.6
million), with the increase in production and realised prices offset by
higher cash capex and outflows related to working capital and other items.
The Company continued to engage with the KRG regarding outstanding
commercial matters including the payment mechanism of the overdue October
2022 to March 2023 invoices. The total owed to GKP amounts to $151.1
million (comprising of $120.4 million cost oil and $30.7 million profit
oil net to GKP after capacity building payment (“CBP”) deduction). The
combined total owed to GKP and Kalegran B.V. (a subsidiary of MOL Group,
“MOL”) (who form together the ”Shaikan Contractor” or the ”Contractor”)
amounts to $192.8 million (comprising $150.5 million cost oil and $42.3
million profit oil). The Company continues to expect to recover the
invoices in full.
Gulf Keystone was pleased to pay an interim dividend of $25 million in H1
2025 (H1 2024 shareholder distributions: $21 million), according to the
Company’s announced approach of semi-annual dividend reviews.
To satisfy the vesting of the 2022 LTIP award, purchases of the Company’s
shares were made by the Employee Benefit Trust (“EBT”) in the period,
amounting to $4.0 million. The vesting of LTIP awards in previous years
has been satisfied by the issuance of shares.
GKP’s cash balance was $99.0 million as at 30 June 2025 (31 December 2024:
$102.3 million) with no outstanding debt. The cash balance as at 27 August
2025 was $105.7 million.
The Group performed a cash flow and liquidity analysis, including
consideration of the current uncertainty over the timing of the pipeline
reopening and settlement of outstanding amounts due from the KRG, and the
fact that the outlook for local sales volumes and prices have fluctuated
in the past and may be difficult to predict. Based on this analysis, the
Directors have a reasonable expectation that the Group has adequate
resources to continue to operate for twelve months. Therefore, the going
concern basis of accounting is used to prepare the financial statements.
Net entitlement
The Company shares Shaikan Field revenues with its partner, MOL, and the
KRG, based on the terms of the Shaikan Production Sharing Contract
(“Shaikan PSC”). GKP and MOL’s revenue entitlement is described as
“Contractor entitlement” and GKP’s entitlement alone is described as
“net”. GKP’s net entitlement includes its share of the recovery of the
Company’s investment in the Shaikan Field, comprising capital expenditure
and operating costs, through cost oil and a share of the profits through
profit oil, less a CBP owed to the KRG.
The unrecovered cost oil balance (or ”Cost Pool”) and R-factor are used to
calculate monthly cost oil and profit oil entitlements, respectively, owed
to the Shaikan Contractor from crude oil sales. Unrecovered cost oil owed
to the Shaikan Contractor increases with the addition of incurred
expenditures deemed recoverable under the Shaikan PSC and is depleted on a
cash basis as crude sales are paid.
As at 30 June 2025, there was $140.0 million of unrecovered cost oil for
the Shaikan Contractor ($116.4 million net to GKP, including certain
expenditures funded 100% by the Company), subject to a potential cost
audit by the MNR. The R-factor, calculated as cumulative Contractor
revenue receipts of $2,523 million divided by cumulative Contractor costs
of $2,021 million, was 1.25, resulting in a share in the profit oil for
the Contractor of 26.3%.
GKP’s net entitlement of total Shaikan Field sales was 36% in the first
half of 2025. Looking ahead, the Company expects its net entitlement to
remain at this level in the second half of 2025. Should exports restart,
increases in realised price, cash receipt of payments for international
sales and the potential implementation by the KRG of a repayment mechanism
for past overdue invoices would accelerate the depletion of the Cost Pool
upon receipt of payment. This would shorten the period that the Company’s
net entitlement is expected to remain around 36% provided that investment
in the Shaikan Field does not increase.
The outlook for the Company’s net entitlement assumes effective receipt of
the cost oil portion of the outstanding October 2022 to March 2023
receivable balance due from the KRG to the Shaikan Contractor, which
totalled $150.5 million as at 30 June 2025 (or on a net basis to GKP
$120.4 million). Effective recovery of the receivable cost oil is expected
to occur with regular payment from either local or export sales. Recovery
is expected to effectively lead to a corresponding reduction in the net
receivable balance due from the KRG. $30.7 million of profit oil (net to
GKP after CBP deduction) is also expected to be fully repaid by the KRG as
part of a repayment mechanism.
The Company now expects the receivable cost oil to begin to be effectively
recovered through regular crude sales in the second half of 2025. This
reflects the differing accounting recognition criteria of the Cost Pool
and receivable balance, which under IFRS recognises revenue on an accrual
basis in contrast to the reporting of the PSC which is prepared on a cash
basis. It also reflects the Company’s ongoing negotiations with the MNR on
outstanding commercial matters, which include the timing and mechanism for
settling the outstanding receivables. See Note 12 to the financial
statements for further detail.
Outlook
2025 net capital expenditure is expected to be $30-$35 million (previous
guidance: $25-$30 million), primarily reflecting the incremental
investment associated with water handling. We continue to expect c.$20
million of net capital expenditure on the PF-2 safety upgrades and $5-$10
million related to the production optimisation programme. Guidance
excludes the H1 2025 non-cash charge of $5.4 million associated with the
reclassification of drilling inventory, as described above.
The Company continues to expect operating costs of $50-$55 million and
other G&A expenses below $10 million in 2025 as per previously
communicated guidance.
The Company is pleased to declare, alongside the 2025 half year results, a
$25 million interim dividend, increasing total dividends declared in 2025
to $50 million. The dividend is equivalent to 11.52 US cents per Common
Share based on the Company's total issued share capital as at 27 August
2025 and will be paid on 30 September 2025, based on a record date of 12
September 2025 and ex-dividend date of 11 September 2025. Shareholders
will have the option of being paid the dividend in either GBP or USD, with
the default currency GBP.
Gabriel Papineau-Legris
Chief Financial Officer
27 August 2025
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 International Financial Reporting Standards
(“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. 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 also set
out below, where applicable. The Group does not regard these non-IFRS
measures as a substitute for, or superior to, the equivalent measures
calculated and presented in accordance with IFRS or those calculated using
financial measures that are calculated in accordance with IFRS.
Gross operating costs per barrel
Gross operating costs are divided by gross production to arrive at
operating costs per barrel.
Six months Six months
ended ended Year ended 31
December 2024
30 June 2025 30 June 2024
Gross production (MMstb) 8.0 7.2 14.9
Gross operating costs ($ 33.6 29.9 65.5
million)(1)
Gross operating costs per barrel 4.2 4.2 4.4
($ per bbl)
1. Gross operating costs equate to operating costs (see note 5 to the
financial statements) adjusted for the Group’s 80% working interest in
the Shaikan Field.
Adjusted EBITDA
Adjusted EBITDA is a useful indicator of the Group’s profitability, which
excludes the impact of costs attributable to tax expense)/(credit),
finance costs, finance revenue, depreciation, amortisation, impairment of
receivables and provision against inventory held for resale.
Six months Six months
ended ended Year ended 31
December 2024
30 June 2025 30 June 2024
$ million
$ million $ million
(Loss)/profit after tax (7.2) 0.4 7.2
Finance costs 1.0 0.8 1.7
Finance income (1.1) (2.0) (4.1)
Tax (credit)/charge (0.2) 0.6 0.7
Depreciation of oil and gas assets 41.2 36.5 75.8
Depreciation of other PPE assets 1.2 1.7 3.0
and amortisation of intangibles
Increase/(decrease) of expected
credit loss provision on trade 8.9 (1.7) (8.2)
receivables
Reversal of provision against (2.6) - -
inventory held for resale
Adjusted EBITDA 41.1 36.4 76.1
Net cash
Net cash is a useful indicator of the Group’s indebtedness and financial
flexibility because it indicates the level of cash and cash equivalents
less cash borrowings within the Group’s business. Net cash is defined as
cash and cash equivalents, less current and non-current borrowings and
non-cash adjustments. Non-cash adjustments include unamortised arrangement
fees and other adjustments.
30 June 2025 30 June 2024 31 December 2024
$ million $ million $ million
Cash and cash equivalents 99.0 102.3 102.3
Borrowings - - -
Net cash 99.0 102.3 102.3
Net Capital expenditure
Net capital expenditure is the value of the Group’s additions to oil and
gas assets excluding the change in value of the decommissioning asset or
any asset impairment.
Six months Six months
ended ended Year ended 31
December 2024
30 June 2025 30 June 2024
$ million
$ million $ million
Net capital 18.1 7.8 18.3
expenditure
As detailed in Note 10 to the financial statements, the net capital
expenditure in the period ended 30 June 2025, includes $5.4 million of
items originally purchased and paid in 2022 and 2023, but were
subsequently classed as impaired inventory held for sale. Upon delisting
as held for sale these assets have been capitalised, as an oil and gas
asset, but are a non-cash item in the current period. 2025 full year capex
guidance of $30-$35 million excludes this non-cash item.
Free cash flow
Free cash flow represents the Group’s cash flows, before any dividends and
share buybacks including related fees.
Six months Six months
ended ended Year ended 31
December 2024
30 June 2025 30 June 2024
$ million
$ million $ million
Net cash generated from operating 38.3 42.8 93.5
activities
Net cash used in investing (13.5) (16.0) (27.6)
activities
Payment of leases (0.2) (0.2) (0.5)
Free cash flow 24.6 26.6 65.4
Principal risks & uncertainties
The Board determines and reviews the key risks for the Group on a regular
basis. The principal risks, and how the Group seeks to mitigate them, for
the second half of the year are largely consistent with those detailed in
the management of principal risks and uncertainties section of the 2024
Annual Report and Accounts. The principal risks are listed below:
Strategic Operational Financial
Health, safety and
Export route availability Commodity prices
environment (“HSE”)
risks
Political, social and economic Oil revenue payment
Gas flaring mechanism
instability
Liquidity and funding
Stakeholder misalignment Security
capability
Disputes regarding title or
Reserves
exploration and production
rights
Business conduct and
Field delivery risk
anti‑corruption
Risk of economic sanctions
impacting the Group
Climate change
Organisation and talent
Cyber security
Responsibility statement
The Directors confirm that to the best of their knowledge:
a. the condensed set of financial statements has been prepared in
accordance with UK-adopted IAS 34 (Interim Financial Reporting);
b. the interim management report includes a fair review of the
information required by DTR 4.2.7R (indication of important events and
their impact during the first six months and description of principal
risks and uncertainties for the remaining six months of the year); and
c. the interim management report includes a fair review of the
information required by DTR 4.2.8R (disclosure of related parties'
transactions and changes therein).
By order of the Board
Jon Harris
Chief Executive Officer
27 August 2025
INDEPENDENT REVIEW REPORT TO GULF KEYSTONE PETROLEUM LIMITED
Conclusion
Based on our review, nothing has come to our attention that causes us to
believe that the condensed set of financial statements in the half-yearly
financial report for the six months ended 30 June 2025 is not prepared, in
all material respects, in accordance with UK adopted International
Accounting Standard 34 and the Disclosure Guidance and Transparency Rules
of the United Kingdom’s Financial Conduct Authority.
We have been engaged by Gulf Keystone Petroleum Limited (the “company”)
and its subsidiaries (the “Group”) to review the condensed set of
financial statements in the half-yearly financial report for the six
months ended 30 June 2025 which comprises the condensed consolidated
income statement, the condensed consolidated statement of comprehensive
income, the condensed consolidated balance sheet, the condensed
consolidated statement of changes in equity, the condensed consolidated
cash flow statement and the related explanatory notes that have been
reviewed.
Basis for conclusion
We conducted our review in accordance with the International Standard on
Review Engagements (UK) 2410, “Review of Interim Financial Information
Performed by the Independent Auditor of the Entity” (“ISRE (UK) 2410”). A
review of interim financial information consists of making enquiries,
primarily of persons responsible for financial and accounting matters, and
applying analytical and other review procedures. A review is substantially
less in scope than an audit conducted in accordance with International
Standards on Auditing (UK) and consequently does not enable us to obtain
assurance that we would become aware of all significant matters that might
be identified in an audit. Accordingly, we do not express an audit
opinion.
As disclosed in Note 2, the annual financial statements of the Group are
prepared in accordance with UK adopted international accounting standards.
The condensed set of financial statements included in this half-yearly
financial report has been prepared in accordance with UK adopted
International Accounting Standard 34, “Interim Financial Reporting”.
Conclusions relating to going concern
Based on our review procedures, which are less extensive than those
performed in an audit as described in the Basis for conclusion section of
this report, nothing has come to our attention to suggest that the
directors have inappropriately adopted the going concern basis of
accounting or that the directors have identified material uncertainties
relating to going concern that are not appropriately disclosed.
This conclusion is based on the review procedures performed in accordance
with ISRE (UK) 2410, however future events or conditions may cause the
Group to cease to continue as a going concern.
Responsibilities of directors
The directors are responsible for preparing the half-yearly financial
report in accordance with the UK adopted International Accounting Standard
34 “Interim Financial Reporting”, the Bermuda Companies Act 1981 and
Disclosure Guidance and Transparency Rules of the United Kingdom’s
Financial Conduct Authority.
In preparing the half-yearly financial report, the directors are
responsible for assessing the Group’s ability to continue as a going
concern, disclosing, as applicable, matters related to going concern and
using the going concern basis of accounting unless the directors either
intend to liquidate the Group or to cease operations, or have no realistic
alternative but to do so.
Auditor’s responsibilities for the review of the financial information
In reviewing the half-yearly report, we are responsible for expressing to
the Company a conclusion on the condensed set of financial statement in
the half-yearly financial report. Our conclusion, including our
Conclusions Relating to Going Concern, are based on procedures that are
less extensive than audit procedures, as described in the Basis for
Conclusion paragraph of this report.
Use of our report
Our report has been prepared in accordance with the terms of our
engagement to assist the Company in meeting the requirements of the
Disclosure Guidance and Transparency Rules of the United Kingdom’s
Financial Conduct Authority and for no other purpose. No person is
entitled to rely on this report unless such a person is a person entitled
to rely upon this report by virtue of and for the purpose of our terms of
engagement or has been expressly authorised to do so by our prior written
consent. Save as above, we do not accept responsibility for this report to
any other person or for any other purpose and we hereby expressly disclaim
any and all such liability.
BDO LLP
Chartered Accountants
London, UK
27 August 2025
BDO LLP is a limited liability partnership registered in England and Wales
(with registered number OC305127).
Condensed consolidated income statement
For the six months ended 30 June 2025
Year
Six months Six months
ended ended ended 31
December
Notes 30 June 2025 30 June 2024 2024
Unaudited Unaudited
Audited
$’000 $’000
$’000
Revenue 4 83,144 71,186 151,208
Cost of sales 5 (71,172) (65,675) (138,866)
(Increase)/decrease of expected
credit loss provision on trade 12 (8,911) 1,676 8,191
receivables
Gross profit 3,061 7,187 20,533
Other general and administrative 6 (4,593) (5,392) (11,412)
expenses
Share option related expense 7 (4,435) (2,055) (4,419)
(Loss)/profit from operations (5,967) (260) 4,702
Finance income 1,124 2,008 4,116
Finance costs (970) (814) (1,676)
Foreign exchange (losses)/gains (1,651) 124 724
(Loss)/profit before tax (7,464) 1,058 7,866
Tax credit/(charge) 250 (616) (708)
(Loss)/profit after tax (7,214) 442 7,158
(Loss)/profit per share (cents)
Basic 8 (3.32) 0.20 3.26
Diluted 8 (3.32) 0.19 3.13
Condensed consolidated statement of comprehensive income
For the six months ended 30 June 2025
Six months Six months Year ended
ended ended 31 December
2024
30 June 2025 30 June 2024
Audited
Unaudited Unaudited
$’000 $’000 $’000
(Loss)/profit after tax for the (7,214) 442 7,158
period
Items that may be reclassified
subsequently to profit or loss:
Exchange differences on 2,289 (139) (517)
translation of foreign operations
Total comprehensive (loss)/income (4,925) 303 6,641
for the period
Condensed consolidated balance sheet
As at 30 June 2025
30 June
31 December 2024
2025
Notes Audited
Unaudited
$’000
$’000
Non-current assets
Property, plant and equipment 10 365,592 388,450
Intangible assets 607 1,255
Trade receivables 12 120,902 138,175
Deferred tax asset 1,159 825
488,260 528,705
Current assets
Inventories 11 7,777 9,852
Trade and other receivables 12 35,096 26,779
Cash and cash equivalents 99,041 102,346
141,914 138,977
Total assets 630,174 667,682
Current liabilities
Trade and other payables 13 (110,223) (117,277)
Deferred income 13 (800) (716)
(111,023) (117,993)
Non-current liabilities
Trade and other payables 13 (1,080) (1,112)
Provisions (37,594) (36,247)
(38,674) (37,359)
Total liabilities (149,697) (155,352)
Net assets 480,477 512,330
Equity
Share capital 14 217,005 217,005
Share premium account 14 439,105 463,985
Exchange translation reserve (1,994) (4,283)
Accumulated losses (173,639) (164,377)
Total equity 480,477 512,330
Condensed consolidated statement of changes in equity
For the six months ended 30 June 2025
Share Exchange
Share premium Accumulated Total
translation
capital account losses equity
reserve
$’000 $’000 $’000 $’000 $’000
Balance at 1 January 222,443 503,312 (3,766) (174,752) 547,237
2024 (audited)
Profit after tax for the - - - 442 442
period
Exchange difference of
translation of foreign - - (139) - (139)
operations
Total comprehensive
(loss)/income for the - - (139) 442 303
period
Dividends - (15,000) - - (15,000)
Share issues 255 - - (255) -
Repurchase of ordinary (3,359) (2,525) - - (5,884)
shares
Employee share schemes - - - 1,337 1,337
Balance at 30 June 2024 219,339 485,787 (3,905) (173,228) 527,993
(unaudited)
Profit after tax for the - - - 6,716 6,716
period
Exchange difference of
translation of foreign - - (378) - (378)
operations
Total comprehensive
(loss)/income for the - - (378) 6,716 6,338
period
Dividends - (19,933) - - (19,933)
Share issues - - - - -
Repurchase of ordinary (2,334) (1,869) - - (4,203)
shares
Employee share schemes - - - 2,135 2,135
Balance at 31 December 217,005 463,985 (4,283) (164,377) 512,330
2024 (audited)
Loss after tax for the - - - (7,214) (7,214)
period
Exchange difference of
translation of foreign - - 2,289 - 2,289
operations
Total comprehensive
income/(loss) for the - - 2,289 (7,214) (4,925)
period
Dividends - (24,880) - - (24,880)
Reissue of repurchased - - - (3,506) (3,506)
shares
Own shares repurchased
and held in Employee - - - (526) (526)
Benefit Trust
Employee share schemes - - - 1,984 1,984
Balance at 30 June 2025 217,005 439,105 (1,994) (173,639) 480,477
(unaudited)
Condensed consolidated cash flow statement
for the six months ended 30 June 2025
Six months Six months Year ended
ended ended 31 December
Notes 2024
30 June 2025 30 June 2024
Audited
Unaudited Unaudited
$’000 $’000 $’000
Operating activities
Cash generated in operations 9 37,171 40,788 89,427
Interest received 1,124 2,008 4,116
Net cash generated in 38,295 42,796 93,543
operating activities
Investing activities
Purchase of intangible assets (133) (32) (420)
Purchase of property, plant 10 (13,385) (15,973) (27,178)
and equipment
Net cash used in investing (13,518) (16,005) (27,598)
activities
Financing activities
Payment of dividends 14 (24,880) - (34,933)
Purchase of own shares - share - (5,884) (10,087)
buyback
Purchase of own shares - 14 (4,032) - -
employee share-based payments
Payment of leases (216) (238) (452)
Net cash used in financing (29,128) (6,122) (45,472)
activities
Net (decrease)/increase in (4,351) 20,669 20,473
cash and cash equivalents
Cash and cash equivalents at 102,346 81,709 81,709
beginning of period
Effect of foreign exchange 1,046 (46) 164
rate changes
Cash and cash equivalents at
end of the period being bank 99,041 102,332 102,346
balances and cash on hand
Notes to the consolidated financial statements
1. General information
Gulf Keystone Petroleum Limited (the “Company”) is domiciled and
incorporated in Bermuda (registered address: c/o Carey Olsen Services
Bermuda Limited, 5th Floor, Rosebank Centre, 11 Bermudiana Road, Pembroke,
HM08 Bermuda); together with its subsidiaries it forms the “Group”. On 25
March 2014, the Company’s common shares were admitted, with a standard
listing, to the Official List of the United Kingdom Listing Authority
(“UKLA”) and to trading on the London Stock Exchange’s Main Market for
listed securities. On 29 July 2024, new Listing Rules came into effect for
the London Stock Exchange. The former categories for Main Market listed
companies of Premium and Standard Listed were ceased (GKP being a Standard
Listed company up until this point). From that date, GKP moved to the
Equity Shares – Transition category. The Company serves as the parent
company for the Group, which is engaged in oil and gas exploration,
development and production, operating in the Kurdistan Region of Iraq.
2. Summary of material accounting policies
These interim financial statements should be read in conjunction with the
audited financial statements contained in the Annual Report and Accounts
for the year ended 31 December 2024. The Annual Report and Accounts of the
Group were prepared in accordance with United Kingdom adopted
International Accounting Standards (“IAS”). The condensed set of financial
statements included in this half yearly financial report have been
prepared in accordance with IAS 34 ‘Interim Financial Reporting’ and the
Disclosure and Transparency Rules (“DTR”) of the Financial Conduct
Authority (“FCA”) in the United Kingdom as applicable to interim financial
reporting.
The condensed set of financial statements included in this half yearly
financial report have been prepared on a going concern basis as the
Directors consider that the Group has adequate resources to continue
operating for the foreseeable future.
The accounting policies adopted in the 2025 half-yearly financial report
are the same as those adopted in the 2024 Annual Report and Accounts,
other than the implementation of new International Financial Reporting
Standards (“IFRS”) reporting standards.
The financial information included herein for the year ended 31 December
2024 does not constitute the Group’s financial statements for that year
but is derived from those Accounts. The auditor’s report on those Accounts
was unqualified and did not include a reference to any matters to which
the auditor drew attention by way of emphasis of matter.
Adoption of new and revised accounting standards
As of 1 January 2025, a number of accounting standard amendments and
interpretations became effective. The adoption of these amendments and
interpretations has not had a material impact on the financial statements
of the Group for the six months ended 30 June 2025.
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 Chief Executive Officer’s review and the Principal risks and
uncertainties. The financial position of the Group at the period end and
its cash flows and liquidity position are included in the Financial
review.
As at 27 August 2025 the Group had $105.7 million of cash and no debt. The
Group continues to closely monitor and manage its liquidity. Cash
forecasts are regularly produced and sensitivities are run for different
scenarios including, but not limited to, changes in sales volumes,
commodity price fluctuations, timing of export pipeline restart, delays to
revenue receipts and cost optimisations. The Group remains focused on
taking appropriate actions to preserve its liquidity position.
The Group’s liquidity position has remained stable up to the date of this
report. Although local sales were impacted by the precautionary shut-in of
the Shaikan field from mid-July due to drone attacks at a number of oil
fields in the vicinity of Shaikan operations, demand this year has been
consistently strong. This enabled production to remain within the 2025
guidance range. Following the re-start of operations earlier this month,
production has since returned to similar levels as before the shut-in. The
Group continues to execute a disciplined work programme, with careful
management of investment with a focus on production optimisation
initiatives and well maintenance to offset natural field decline.
Nonetheless, the Group is aware there could be a potential decline in
local sales, and potential delays in Kurdistan Regional Government (“KRG”)
revenue receipts once the Iraq-Türkiye pipeline (“ITP”) has been reopened.
The key uncertainties in the current environment are summarised below:
• Geopolitical events and regional instability: recent events such as
the recent conflict between Israel and Iran and drone attacks are
challenging to foresee;
• Local sales: the Group continues local sales with payments from buyers
required in advance following extensive due diligence. During H1 2025
the Group received over $78 million related to local sales. However,
production volumes (average 44,100 bopd in H1 2025) and prices have
fluctuated in the past and may be difficult to predict; and
• Export sales: The Group continues to engage with the KRG and Federal
Iraq on the resumption of Kurdistan's oil exports, although a number
of key details remain outstanding including payment surety for future
oil exports, the repayment of outstanding receivables and the
preservation of current contract economics which are a key step
towards the resumption of Kurdistan oil exports. As such, the timing
of the reopening of the ITP and payment mechanism remain uncertain.
The Directors believe an agreement will ultimately be reached to reopen
the ITP, and reasonably expect that overdue balances will be paid, and
that receipts from the KRG will return to a more regular basis. However, a
reduction in local sales or reopening of the pipeline with a deferral of
revenue receipts could result in liquidity pressures within the 12-month
going concern period.
The Directors have considered sensitivities, including local sales volumes
and potential delays in KRG revenue receipts once the ITP reopens, to
assess the impact on the Group’s liquidity position and believe sufficient
mitigating actions are available to withstand such impacts within the
12-month going concern period. Specifically, the Directors considered
stress tests that included no further local sales that could arise from
constrained local demand or a prolonged disruption to operations, delayed
KRG revenue receipts once the ITP reopens and confirmed that cost
reduction opportunities exist to ensure that the Group can continue to
discharge its liabilities for a period of at least 12 months.
As explained in note 13, although the Group has recognised current
liabilities of around $84 million payable to the KRG, it does not expect
these will be cash settled.
Overall, the Group’s forecasts which include the $25 million dividend
declared on 27 August 2025, and taking into account the applicable risks,
stress test scenarios and potential mitigating actions, show that it has
sufficient financial resources for the 12 months from the date of approval
of these interim financial statements.
Based on the analysis performed, the Directors have a reasonable
expectation that the Group has adequate resources to continue to operate
for the foreseeable future. Thus, the going concern basis of accounting is
used to prepare these interim financial statements.
Critical accounting judgements and key sources of estimation uncertainty
In the application of the accounting policies described above, the Group
is required to make judgements, estimates and assumptions about the
carrying amounts of assets and liabilities that are not readily apparent
from other sources. The estimates and associated assumptions are based on
historical experience and other factors that are considered to be
relevant. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognised in the period in which
the estimate is revised if the revision affects only that period or in the
period of revision and future periods if the revision affects both current
and future periods.
Critical judgements in applying the Group’s accounting policies
The following are the critical judgements, apart from those involving
estimations (which are presented separately below), that the Directors
have made in the process of applying the Group’s accounting policies and
that have the most significant effect on the amounts recognised in
financial statements
Production sharing contract entitlement: Revenue, trade receivables and
capacity building payments
The recognition of revenue, particularly the recognition of revenue from
pipeline exports, is considered to be a key accounting judgement. The
Group began commercial production from the Shaikan Field in July 2013 and
historically made sales to both the domestic and export markets. The Group
considers that revenue can be reliably measured as it passes the delivery
point into the export pipeline or truck, in the period all revenue was to
the local market via trucking. The critical accounting judgement applied
in preparing the financial statements is that it is appropriate to
continue to recognise trade receivables due from the KRG for deliveries
from 1 October 2022 to 25 March 2023 based on an alternative proposed
pricing mechanism, notwithstanding that there is no signed lifting
agreement for that period and the pricing mechanism has not yet been
agreed. In making this judgement, consideration was given to the fact that
the Group received payment for September 2022 deliveries at an amount that
was consistent with the proposed pricing terms; no further receipts for
the period of pipeline exports from 1 October 2022 to 25 March 2023 have
been received. No adjustments were made in the period in respect of the
above as revenue was earned via local sales, with no agreement yet reached
in respect of the export period mentioned above.
Any future agreements between the Group and the KRG might change the
amounts of revenue recognised.
During past production sharing contract (“PSC”) negotiations with the
Ministry of Natural Resources (“MNR”), it was tentatively agreed that the
Shaikan Contractor would provide the KRG a 20% carried working interest in
the PSC. This would result in a reduction of GKP’s working interest from
80% to 61.5%. To compensate for such decrease, capacity building payments
expense would be reduced to 20% of profit petroleum. While the PSC has not
been formally amended, it was agreed that GKP would invoice the KRG for
oil sales based on the proposed revised terms from October 2017. The
financial statements reflect the proposed revised working interest of
61.5%. Relative to the PSC terms, the proposed revised invoicing terms
result in a decrease in both revenue and cost of sales and on a net basis
are slightly positive for the Group.
As part of earlier PSC negotiations, on 16 March 2016, GKP signed a
bilateral agreement with the MNR (the “Bilateral Agreement”). The
Bilateral Agreement included a reduction in the Group’s capacity building
payment from 40% to 30% of profit petroleum. Subsequent to signing the
Bilateral Agreement, further negotiations resulted in the capacity
building payment rate being reduced from 30% to 20%, which has formed the
basis for all oil sales invoices to date as noted above. Since PSC
negotiations have not been finalised, GKP has included a non-cash payable
for the difference between the capacity building rate of 20% and 30%,
which is recognised in cost of sales and other payables. See note 13 for
further details.
The Group expects to confirm with the MNR whether to proceed with a formal
amendment to the PSC to reflect current invoice terms.
Material sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of
estimation uncertainty at the reporting period that may have a significant
risk of causing a material adjustment to the carrying amounts of assets
and liabilities within the next financial year, are discussed below.
Expected credit loss (“ECL”)
The recoverability of receivables is a key accounting judgement. The
difference between the nominal value of receivables and the expected value
of receivables after allowing for counterparty default risk is the basis
for the ECL. This ECL is offset against current and non-current receivable
amounts as appropriate within the balance sheet with the change in the
receivable balance during the period recognised in the income statement.
In making this judgement, a weighted average has been applied to modelled
receipt profiles, upon which a counterparty default allowance has been
applied to derive the ECL. When modelling receipt profiles management have
made a number of key estimates that are dependent upon uncertain future
events including: the KRG’s deemed credit rating, the export pipeline
reopening date, that the unrecovered cost pool is depleted on a cash basis
as invoices for crude sales are paid and can be recovered through local or
export sales, estimated timeline of cost oil and profit oil recoveries via
commercial terms which have not yet been agreed with the KRG, future oil
price including an estimate of both local and export prices, future oil
production, a potential commercial settlement with the KRG which may
include an agreement on the settlement mechanism of receivable balances on
terms not yet agreed, and the probabilities allocated to various scenarios
incorporating the aforementioned variables. Management has estimated the
KRG’s probability of default based on credit default swap ratings (“CDS”)
applicable to sovereign nations with similar characteristics to the KRG.
Material sensitivities of the ECL to discrete variables are summarised in
note 12.
Decommissioning provision
Decommissioning provisions are estimated based upon the obligations and
costs to be incurred in accordance with the PSC at the end of field life
in 2043. There is uncertainty in the decommissioning estimate due to
factors including potential changes to the cost of activities, potential
emergence of new techniques or changes to best practice. The basis for the
updated estimate of the current value of obligations and costs at 30 June
2025 was prepared internally. An independent third-party review of the
obligations and costs to decommission the asset was undertaken by ERC
Equipoise as at 31 December 2023, which closely aligned with the internal
estimate at the time; this estimate formed the basis of the updated
estimate of the current value of obligations and costs as at 30 June 2025.
Management have increased the decommissioning costs as at 30 June 2025, by
estimated compound interest rates to future value in 2043 and reduced to
present value by an estimated discount rate, there is also uncertainty
regarding the inflation and discount rates used.
Carrying value of producing assets
In line with the Group’s accounting policy on impairment, management
performs an impairment review of the Group’s oil and gas assets at least
annually with reference to indicators as set out in IAS 36 ‘Impairment of
Assets’. The Group assesses its group of assets, called a cash-generating
unit (“CGU”), for impairment, if events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable.
Where indicators are present, management calculates the recoverable amount
using key estimates such as future oil prices, estimated production
volumes, the cost of development and production, post-tax discount rates
that reflect the current market assessment of the time value of money and
risks specific to the asset, commercial reserves and inflation. The key
assumptions are subject to change based on market trends and economic
conditions. Where the CGU’s recoverable amount is lower than the carrying
amount, the CGU is considered impaired and is written down to its
recoverable amount.
The Group’s sole CGU at 30 June 2025 was the Shaikan Field with a carrying
value, being Oil and Gas assets less capitalised decommissioning
provision, of $324.9 million (31 December 2024: $348.9 million). The Group
performed an impairment indicator evaluation as at 30 June 2025 and
concluded that no impairment indicators arose. The key areas of estimation
in assessing the potential impairment indicators are as follows:
• While the date of the re-opening of the ITP remains uncertain,
management have assessed a re-opening date of August 2026 as being
reasonable. Although the estimated re-opening date is ten months later
than the base case assessment at 31 December 2024, management
previously performed sensitivities of up to two years with no
impairment, therefore this delay to the projected re-opening was not
assessed to be an impairment trigger;
• The Group’s netback oil price applied only to export pipeline sales
was based on the Brent forward curve and market participants’
consensus, including banks, analysts and independent reserves
evaluators, as at 30 June 2025 for the years 2025 to 2030 with
inflation of 2.5% per annum thereafter, less transportation costs and
quality adjustments. Brent consensus prices are as follows:
Scenario ($/bbl – nominal) 2025 2026 2027 2028 2029 2030
30 June 2025 – base case 66.0 65.0 70.0 71.0 70.0 80.0
30 June 2025 – stress case 59.4 58.5 63.0 63.9 63.0 72.0
31 December 2024 – base case 74.0 72.0 74.0 75.0 73.0 80.0
31 December 2024 – stress case 66.6 64.8 66.6 67.5 65.7 72.0
• Management have previously applied sensitivities including a 10%
reduction from base case pricing to derive a stress case price with no
impairment impact. The stress case pricing is noted above;
• Discount rates are adjusted to reflect risks specific to the Shaikan
Field and the Kurdistan Region of Iraq. Management assessed changes to
the key variables that could impact discount rate and concluded no
change was necessary. The post-tax nominal discount rate was estimated
to be 16%, unchanged from 31 December 2024;
• Operating costs and capital expenditure are based on financial budgets
and internal management forecasts. Costs assumptions incorporate
management experience and expectations, as well as the nature and
location of the operation and the risks associated therewith. There
were no indicators that costs will increase in comparison to 31
December 2024 impairment assessment;
• No adverse changes were noted for commercial reserves and production
profiles;
• No changes were noted in the operating environment such as local
market conditions in the period (although please see Going concern on
events that occurred after period end), tax or other legal or
regulatory changes. Following the judgment issued by the Iraqi Al
Kharkh (Commercial) Court on 18 December 2024 which declared that the
Shaikan PSC was valid and enforceable, the Company was subsequently
informed on 27 February 2025 that Iraqi Ministry of Oil had applied to
the Cassation (Appeal) Court for a procedure known as a ‘Correction’.
However, this application was denied by the Court and the decision is
considered final. Although this ruling by the Al Kharkh Court has
decreased the risk of challenge to the validity of the Shaikan PSC,
the Company has maintained its overall risk estimates in respect of
its operating environment, albeit the PSC validity risk has lowered.
There has been no change to the status of the Iraqi Federal Supreme
Court ruling from February 2022 which stated that the Kurdistan Oil
and Gas Law was unconstitutional; and
• The Group continues to develop its assessment of the potential impacts
of climate change and the associated risks of the transition to a
low‑carbon future. Our ambition to reduce Scope 1 per barrel CO2
emissions intensity by at least 50% versus the original 2020 baseline
of 38 kgCO2e per barrel is dependent on the timing of sanction and
implementation of the Gas Management Plan. The International Energy
Agency’s (“IEA”) most recent Announced Pledges Scenario (“APS”) and
Net Zero Emissions (“NZE”) climate scenario oil prices and carbon
taxes were used to evaluate the potential impact of the principal
climate change transition risks. The APS scenario assumes that
governments will meet, in full and on time, all of the climate‑related
commitments that they have announced, including longer term net zero
emissions targets and pledges in Nationally Determined Contributions
to reduce national emissions and adapt to the impacts of climate
change leading to a global temperature rise of 1.7°C in 2100. NZE
scenario portrays a pathway for the global energy sector to reach net
zero CO2 emissions by 2050 which is consistent with limiting long-term
global warming to 1.5 °C with limited overshoot. The assumed
re-opening date is August 2026, which is ten months later than the
base case assessment at 31 December 2024, which had a pipeline
reopening date of October 2025 whereby management previously performed
sensitivities of up to two years. There was no impairment under the
APS scenario, but a potential impairment under the NZE scenario. While
the IEA oil price assumptions incorporate carbon prices, the IEA has
not disclosed the assumed average carbon intensity per barrel of
production. Therefore, at 31 December 2024 the Group performed a
sensitivity to conservatively include IEA carbon pricing on all
production which results in no impairment under the APS scenario, but
a potential impairment under the NZE scenario.
3. Geographical information
The Chief Operating Decision Maker, as per the definition in IFRS 8
‘Operating Segments’, is considered to be the Board of Directors. The
Group operates in a single segment, that of oil and gas exploration,
development and production, in a single geographical location, the
Kurdistan Region of Iraq (“KRI”); 100% (31 December 2024: 100%) of the
group’s non-current assets, excluding deferred tax assets and other
financial assets, are located in the KRI. The financial information of the
single segment is materially the same as set out in the condensed
consolidated primary statements and the related notes.
4. Revenue
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
$’000 $’000 $’000
Oil sales via export pipeline - - -
Local oil sales 83,144 71,186 151,208
83,144 71,186 151,208
The Group accounting policy for revenue recognition is set out in its 2024
Annual Report, with revenue recognised upon crude oil passing the delivery
points, either being entry into pipeline or delivered into trucks.
Throughout the period, GKP sold oil to local buyers at negotiated prices.
The weighted average realised price achieved in the six-month period to 30
June 2025 was $27.8/bbl (H1 2024: $26.3/bbl; FY 2024: $26.8/bbl). Local
buyers are contracted to pay GKP in advance of receipt of oil; such
amounts are recognised as deferred income (see note 13) until a customer’s
receipt of oil at the delivery point.
Information about major customers
Customers making up greater than 10% of revenue are as follows:
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
$’000 $’000 $’000
Customer A 65% 86% 88%
Customer B 23% 14% <10%
Customer C 12% 0% <10%
5. Cost of Sales
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
$’000 $’000 $’000
Operating costs 26,893 23,917 52,435
Capacity building payments 5,885 5,131 10,818
Changes in oil inventory value (198) 98 (168)
Depreciation of oil and gas assets 41,219 36,529 75,781
and operational assets
Reversal of provision against (2,627) - -
inventory held for sale
71,172 65,675 138,866
Capacity building payments have been recorded in line with the MNR’s
proposed pricing mechanism (see 2024 Annual Report); any difference
between the proposed and final pricing mechanism will be reflected in
future periods.
The Group accounting policy for depreciation of oil and gas assets is set
out in its 2024 Annual Report. The increase in charge compared to the
corresponding period in 2024 is principally derived from higher production
in the six-month period ended 30 June 2025.
During the six-month period ended 30 June 2025, inventory formerly held
for sale was reassessed to no longer be held for sale. Whilst held for
sale this inventory was provided against, upon reassessment this provision
has been reversed resulting in a gain of $2.6m in the six-month period
ended 30 June 2025 (H1 2024: nil; FY 2024: nil). Following this reversal
in the six-month period ended 30 June 2025, these items were capitalised
as an addition to oil and gas assets (see note 10).
6. Other general and administrative expenses
Six months Year ended
ended Six months 31 December
ended
30 June 2025 30 June 2024 2024
Unaudited
Unaudited $’000 Audited
$’000 $’000
Depreciation and amortisation 1,233 1,690 3,033
Other general and administrative 3,360 3,702 8,379
costs
4,593 5,392 11,412
7. Share option related expense
Six months Year ended
ended Six months 31 December
ended
30 June 2025 30 June 2024 2024
Unaudited
Unaudited $’000 Audited
$’000 $’000
Share-based payment expense 1,984 1,337 3,472
Payments related to share options 2,058 741 704
exercised
Share-based payment/(credit) related 393 (23) 243
provision for taxes
4,435 2,055 4,419
During the six-month period ending 30 June 2025, share options exercised
relate to options vesting in the period under both the Deferred Bonus Plan
and the Long Term Incentive Plan. Further details relating to these plans
are set out in the 2024 Annual Report. The Company’s Employee Benefit
Trust settled employee share option exercises from shares purchased during
the period (see note 14).
8. Earnings per share
The calculation of the basic and diluted profit per share is based on the
following data:
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
(Loss)/profit after tax ($’000) (7,214) 442 7,158
Number of shares (‘000s):
Basic weighted average number of ordinary shares 217,500 222,188 219,562
Basic (loss)/earnings per share (cents) (3.32) 0.20 3.26
The Group followed the steps specified by IAS 33 ‘Earnings per share’ in
determining whether outstanding share options are dilutive or
anti-dilutive.
Reconciliation of dilutive shares:
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
Number of shares (‘000s):
Basic weighted average number of 217,500 222,188 219,562
ordinary shares
Effect of dilutive potential - 5,906 9,134
ordinary shares
Diluted number of ordinary shares 217,500 228,094 228,696
outstanding
Diluted (loss)/earnings per share (3.32) 0.19 3.13
(cents) (1)
1. As at 30 June 2025, the Group had 9,989k antidilutive (H1 2024: 5,906k
dilutive; FY 2024: 9,134 dilutive) ordinary shares relating to
outstanding share options. Earnings per share is calculated on the
assumption of conversion of all potentially dilutive ordinary shares;
however, during a period where a company makes a loss, anti-dilutive
shares are not included in the loss per share calculation as they
would reduce the reported loss per share.
The weighted average number of ordinary shares in issue excludes shares
held by Employee Benefit Trustee (“EBT”) of 0.2 million, (H1 2024: 0.2
million; FY 2024: 0.1 million) see note 14.
9. Reconciliation of loss from operations to net cash generated in
operating activities
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
$’000 $’000 $’000
(Loss)/profit from operations (5,967) (260) 4,702
Adjustments for:
Depreciation, depletion and
amortisation of property, plant and 41,651 37,008 76,752
equipment (including the right of
use assets)
Amortisation of intangible assets 801 1,211 1,980
Share-based payment expense 1,984 1,337 3,472
Increase/(decrease) of provision for 8,911 (1,676) (8,191)
impairment of trade receivables
(Reversal of provision)/provision (2,627) - 34
against inventory held for sale
Operating cash flows before 44,753 37,620 78,749
movements in working capital
Increase in inventories (714) (18) 49
(Increase)/decrease in trade and (27) 1,042 (1,290)
other receivables
(Decrease)/increase in trade and (6,841) 2,144 11,919
other payables
Cash generated from operations 37,171 40,788 89,427
10. Property, plant and equipment
Oil and Gas Fixtures and Right of use
Assets Equipment Assets Total
$’000 $’000 $’000 $’000
Year ended 31 December
2024
Opening net book value 443,393 2,066 383 445,842
Additions 18,252 284 1,559 20,095
Disposals’ costs - - (2,040) (2,040)
Revision to (693) - - (693)
decommissioning asset
Depreciation charge (75,781) (576) (394) (76,751)
Disposals’ depreciation - - 2,004 2,004
Foreign currency - (1) (6) (7)
translation differences
Closing net book value 385,171 1,773 1,506 388,450
Cost 1,010,429 9,687 1,701 1,021,817
Accumulated depreciation (625,258) (7,914) (195) (633,367)
Net book value at 31 385,171 1,773 1,506 388,450
December 2024
Period ended 30 June 2025
Opening net book value 385,171 1,773 1,506 388,450
Additions 18,055 143 - 18,198
Revision to 459 - - 459
decommissioning asset
Depreciation charge (41,219) (273) (159) (41,651)
Foreign currency - 6 130 136
translation differences
Closing net book value 362,466 1,649 1,477 365,592
At 30 June 2025
Cost 1,028,943 9,836 1,831 1,040,610
Accumulated depreciation (666,477) (8,187) (354) (675,018)
Net book value 362,466 1,649 1,477 365,592
The additions to the Shaikan asset, amounting to $18.1 million during the
six-month period ended 30 June 2025 (FY 2024: 18.3 million) included
safety critical upgrades, the purchase of jet pumps as well as items
purchased and paid for in 2022 and 2023 and subsequently classified as
impaired inventory held for sale (see note 5). Upon delisting as held for
sale, the items were capitalised as oil and gas assets at their unimpaired
value of $5.4 million (2024: not applicable).
The $0.5 million increase (2024: $0.7 million decrease) in decommissioning
asset value relates to a $0.1 million increase in changes to inflation and
discount rates (2024: $1.1 million decrease), in addition to an increase
of $0.4 million relating to facilities work (2024: $0.4 million).
11. Inventories
31 December
30 June 2025
2024
Unaudited
Audited
$’000
$’000
Warehouse stocks and materials 7,345 6,829
Inventory held for sale - 2,789
Crude oil 432 234
7,777 9,852
In the six-month period ended 30 June 2025, management determined that
inventory previously impaired and held for sale, was no longer being held
for sale. Impairments of $2.6 million recognised within Cost of sales in
prior periods were reversed in the six-month period ended 30 June 2025
(see note 5) and the unimpaired $5.4 million was included as an addition
within Oil and gas assets as at 30 June 2025 (see note 10).
12. Trade and other receivables
Non-current receivables
31 December
30 June 2025
2024
Unaudited
Audited
$’000
$’000
Trade receivables – non-current 120,902 138,175
Current receivables
31 December
30 June 2025
2024
Unaudited
Audited
$’000
$’000
Trade receivables - current 24,946 16,583
Underlift 436 -
Other receivables 7,172 7,291
Prepayments and accrued income 2,542 2,905
Total current receivables 35,096 26,779
Total receivables 155,998 164,954
Reconciliation of trade receivables
31 December
30 June 2025
2024
Unaudited
Audited
$’000
$’000
Gross carrying amount relating to export sales 171,026 171,026
Less: impairment allowance relating to export (25,178) (16,267)
sales
Carrying value relating to export sales at end of 145,848 154,759
period
Trade receivables relating to local oil sales 1,310 -
Total carrying value of trade receivables 147,158 154,759
Gross trade receivables relating to export sales of $171.0 million (2024:
$171.0 million) are comprised of invoiced amounts due, based upon
Kurdistan blend (“KBT”) pricing, from the KRG for crude oil sales
totalling $158.8 million (2024: $158.8 million) related to October 2022 –
March 2023 and a share of Shaikan amounts due from the KRG that GKP
purchased from Kalegran B.V. (a subsidiary of MOL Group) (“MOL”) amounting
to $12.2 million (2024: $12.2 million). Although no legal right of offset
exists, the net balance due from the KRG comprises $158.8 million (2024:
$158.8 million) included in trade receivables and $7.7 million (2024: $7.7
million) included within current liabilities (see note 13), resulting in a
net receivable balance due from the KRG relating to crude oil sales of
$151.1 million (2024: $151.1 million).
As detailed in the Summary of material accounting policies section within
the 2024 Annual Report, entitlement has two components: cost oil, which is
the mechanism by which the Company recovers its costs incurred, and profit
oil, which is the mechanism through which profits are shared between the
Company, its partner MOL and the KRG. The outstanding receivable balance
of $151.1 million above, comprises $120.4 million cost oil and $30.7
million profit oil (2024: $151.1 million, $120.4 million and $30.7 million
respectively) (net of Capacity Building Payment).
Impairment allowance relating to export sales (ECL)
While GKP expects to recover the full value of the outstanding invoices
and purchased revenue arrears, an ECL of $25.2 million (2024: $16.3
million) was provided against the trade receivables balance in accordance
with IFRS 9 ‘Financial Instruments’. During the six-month period to 30
June 2025, an $8.9 million charge was recognised due to the increase in
the ECL provision (H1 2024: $1.7 million credit; FY 2024: $8.2 million
credit) arising from the delayed estimated pipeline reopening date and
updated commercial assumptions applied compared to the prior year.
Negotiations are ongoing with the MNR on the wider commercial settlement,
including the timing and mechanism for settling outstanding receivables.
As a result of the ongoing discussions there is uncertainty on the balance
of the unrecovered cost pool and therefore when the Contractor expects to
start to recover the receivable balance which underpins the ECL estimate.
As reported in the 2024 Annual Report, the Company had expected to start
recovering cost oil balances within receivables in the first half of 2025,
however the Company now expects the Contractor to effectively begin
recovering the cost oil component of the trade receivables balance due
from the KRG in the second half of 2025 via the settlement of invoices due
from the point that the outstanding cost pool balance declines to a level
at or below the trade receivable balance. It is expected that upon
conclusion of commercial negotiations, cash received in line with current
entitlements would be offset against the overdue trade receivables
balance. This is incorporated into the ECL scenario modelling (see
Material sources of estimation uncertainty section included above).
Following the export pipeline reopening the remaining overdue trade
receivables are expected to be recovered from the KRG including both the
outstanding cost oil balance at that time and the full profit oil balance
referenced above.
The outstanding sales invoices from October 2022 – March 2023 receivable
have been recognised based on the MNR’s proposed pricing mechanism, which
GKP has not accepted (see Critical accounting judgements and key sources
of estimation uncertainty section included above)).
ECL sensitivities
Considering the variables listed within the Summary of material accounting
policies, the only variables with a significant impact upon the profit
before tax, when varied reasonably, are the estimation of the KRG's credit
rating for which no official market data exists, the estimated date of the
re-opening of the ITP and the probability of reaching a commercial
settlement.
For the purpose of GKP’s ECL calculation, the KRG's deemed CDS was
estimated to be 4.43%. An increase of the CDS of 2% would increase the ECL
provision by $7.4 million; conversely a decrease of the CDS by 2% would
decrease the ECL provision by $7.6 million. Doubling or halving the
probability of the modelled commercial settlement, in which the
receivables are recovered via future production would cause the ECL
provision to increase by $6.7 million or decrease by $3.2m respectively.
GKP estimates that re-opening of ITP will occur in August 2026, should
this be delayed by 12 months there would be a $6.3 million increase in the
ECL provision.
All other variables listed within the Summary of material accounting
policies, when individually reasonably varied do not have a material
impact upon ECL valuation.
13. Trade and other payables
Current liabilities
30 June 31 December
2025 2024
Unaudited Audited
$’000 $’000
Trade payables 2,304 1,746
Accrued expenditures 12,988 22,228
Amounts due to KRG not expected to be cash settled 83,722 80,905
Capacity building payment due to KRG on trade 7,687 7,687
receivables
Other payables 3,090 4,080
Finance lease obligations 432 395
Overlift - 236
Total current liabilities 110,223 117,277
Trade payables and accrued expenditures principally comprise amounts
outstanding for trade purchases and ongoing costs; the Directors consider
that carrying amounts approximate fair value. Accrued expenditures have
decreased due to payment of operational invoices and other expenditure
which became due in the six-month period ended 30 June 2025, having been
accrued at 2024 year end.
Amounts due to the KRG not expected to be cash settled of $83.7 million
(2024: $80.9 million) include:
• $40.9 million (2024: $40.1 million) expected to be offset against oil
sales to the KRG up to 2018, together with other amounts considered
due from the KRG, that have not been recognised in the financial
statements as management consider that the criteria for revenue
recognition have not been satisfied, and
• $42.8 million (2024: $40.8 million) related to an accrual for the
difference between the capacity building rate of 20%, as per the
invoicing basis in effect since October 2017, and 30% as per the 2016
Bilateral Agreement. The working interest under the 2016 bilateral
agreement is 80% whereas the invoicing basis is 61.5%. If the
commercial position were to revert to the full terms of the executed
amended PSC and the 2016 Bilateral Agreement, the Group would not
expect to cash settle this balance as a more than offsetting increase
in GKP’s net entitlement is expected to result in revenue being due to
GKP (see Critical accounting judgements and key sources of estimation
uncertainty section included above), the value of which is expected to
exceed the accrued $42.8 million.
Deferred income
At 30 June 2025, deferred income of $0.8 million (2024: $0.7 million)
relates to cash advances paid by local oil buyers in advance of lifting
oil (see note 4).
Non-current liabilities
30 June 31 December
2025 2024
Unaudited Audited
$’000 $’000
Non-current finance lease liability 1,080 1,112
14. Share capital
Common shares
No. of shares Share Share premium Amount
capital
000 $’000 $’000 $’000
Issued and fully paid
Balance 1 January 2025 217,005 217,005 463,985 680,990
(audited)
Dividends - - (24,880) (24,880)
Balance 30 June 2025 217,005 217,005 439,105 656,110
(unaudited)
During the six-month period ended 30 June 2025, the Company’s EBT
purchased 1.6 million shares of the Company for future satisfaction of
employee share options for a total consideration of $4.0 million that
originated from the Company. Subsequently 1.4 million of these shares,
with a value of $3.5 million, were used to satisfy exercised employee
share options. At period end 0.2 million shares, with a value of $0.5
million, were retained within the EBT.
15. Contingent liabilities
During the six-month period ended 30 June 2025, the Company has continued
negotiations with the MNR around a number of outstanding commercial
matters (including the sale of test production oil mentioned below), with
the aim of agreeing a formal amendment to the PSC to reflect current
invoicing terms.
The Group has a contingent liability of $27.3 million (31 December 2024:
$27.3 million) in relation to the proceeds from the sale of test
production oil prior to the approval of the Shaikan Field Development Plan
(“FDP”) in June 2013. If a cash outflow to the MNR were required in the
future, this would result in a corresponding increase to the unrecovered
cost pool as the test production revenue is recorded as a reduction of the
cost pool by $34 million gross to the Contractor ($27.3 million net to
GKP) in the Group’s cost Recovery submissions to the MNR.
The above negotiations may lead to a revision to the unrecovered cost pool
impacting future revenues, the settlement of previously unrecognised
assets and liabilities, netting of existing receivable and payable
balances, or require material adjustments to such balances as they are
currently recorded. Due to the uncertain and wide range of potential
financial outcomes that cannot presently be reliably estimated, no
provision for such asset or liability has been recognised within the
financial statements.
16. Subsequent Events
On 26 August 2025, the Group entered into a contractual agreement to
install water handling facilities at PF-2 which are expected to increase
future gross production over the anticipated field baseline. The costs
during construction phase are estimated at approximately $12 million net
to GKP in the period up to the anticipated commissioning at the beginning
of 2027. Once the water handling facilities have been commissioned, they
will be operated under a lease agreement and expected to generate positive
cash flows thereafter. The financial effect of this commitment will be
reflected in future periods. No adjustment has been made to the 30 June
2025 financial statements.
On 27 August 2025, the Company declared an interim dividend of $25
million.
GLOSSARY (See also the glossary in the 2024 Annual Report and Accounts)
H1 2024 First half of Financial Year 2024
H1 2025 First half of Financial Year 2025
APS Announced pledges scenario
bbl Barrel
bopd Barrels of oil per day
Capex Capital expenditure
CBP Capacity building payment
CDS Credit default swap
CGU Cash-generating unit
Company Gulf Keystone Petroleum Limited
Cost Pool Unrecovered cost oil balance
DTR Disclosure and Transparency Rules
EBITDA Earnings before interest, tax, depreciation and
amortisation
EBT Employee Benefit Trust
ECL Expected credit loss
FCA Financial Conduct Authority
FDP Field Development Plan
G&A General and administrative
FY Financial year
GKP Gulf Keystone Petroleum Limited
Group Gulf Keystone Petroleum Limited and its subsidiaries
HSE Health, safety and environment
IAS International Accounting Standards
IEA International Energy Agency
IFRS International Financial Reporting Standards
IOC International oil company
ITP Iraq-Türkiye pipeline
KBT Kurdistan blend
KRG Kurdistan Regional Government
KRI Kurdistan Region of Iraq
LTI Lost Time Incident
LTIP Long term incentive plan
MMstb Million stock tank barrels
MNR Ministry of Natural Resources of the Kurdistan Regional
Government
MOL Kalegran B.V. (a subsidiary of MOL Group)
NZE Net Zero Emissions
Opex Operating costs
PF-1 Production Facility 1
PF-2 Production Facility 2
PSC Production Sharing Contract
Shaikan Contractor GKP and MOL
Shaikan PSC Shaikan Production Sharing Contract
UKLA United Kingdom Listing Authority
$ US dollars
══════════════════════════════════════════════════════════════════════════
Dissemination of a Regulatory Announcement, transmitted by EQS Group.
The issuer is solely responsible for the content of this announcement.
══════════════════════════════════════════════════════════════════════════
ISIN: BMG4209G2077
Category Code: MSCM
TIDM: GKP
LEI Code: 213800QTAQOSSTNTPO15
Sequence No.: 400081
EQS News ID: 2189714
End of Announcement EQS News Service
══════════════════════════════════════════════════════════════════════════
References
Visible links
1. https://eqs-cockpit.com/cgi-bin/fncls.ssp?fn=redirect&url=c53cb18af3b51808c8220e13cc1dfbc9&application_id=2189714&site_id=refinitiv~~~456f380e-074c-434c-ab61-d8ca972fa0de&application_name=news
2. mailto:aclark@gulfkeystone.com
3. mailto:GKP@fticonsulting.com
4. https://eqs-cockpit.com/cgi-bin/fncls.ssp?fn=redirect&url=8d526d3701dabe9a2ff9507b71394df8&application_id=2189714&site_id=refinitiv~~~456f380e-074c-434c-ab61-d8ca972fa0de&application_name=news
5. https://eqs-cockpit.com/cgi-bin/fncls.ssp?fn=redirect&url=6965f2bb1ddcf50ad2dd09b21a93cfc7&application_id=2189714&site_id=refinitiv~~~456f380e-074c-434c-ab61-d8ca972fa0de&application_name=news
============Recent news on Gulf Keystone Petroleum
See all newsREG-Gulf Keystone Petroleum Ltd 2025 Half Year Results Announcement
AnnouncementREG - Gulf Keystone Petrol - Notice of HY25 Results & Operational Update
AnnouncementREG-Gulf Keystone Petroleum Ltd Update on Shaikan Field operations
AnnouncementREG-Gulf Keystone Petroleum Ltd Result of AGM
AnnouncementREG-Gulf Keystone Petroleum Ltd 2025 AGM Operational & Corporate Update
Announcement