REG - Ithaca Energy PLC Delek Group - DLEKG - First Half Results for Six Months to 30 June 2023
23/08/2023 07:15
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RNS Number : 1388K Ithaca Energy PLC 23 August 2023
23 August 2023
ITHACA ENERGY PLC
("Ithaca Energy", the "Company" or the "Group")
First Half Results for the Six Months to 30 June 2023
Strong H1 production performance, continued strategic and operational progress
Ithaca Energy, a leading UK independent exploration and production company,
today announced its unaudited financial results for the six months ended 30
June 2023.
Financial key performance indicators (KPIs)
H1 2023 H1 2022
Group adjusted EBITDAX(1) ($m) 979.7 907.4
Statutory net income ($m) 159.6 1,557.7
Adjusted net income(1) ($m) 253.2 233.4
Basic EPS (cents) 15.9 155.0
Net cash flow from operating activities ($m) 691.0 989.0
Available liquidity (1) ($m) 791.3 320.4
Unit operating expenditure(1) ($/boe) 19.8 19.5
Adjusted net debt (1) ($m) 698.7 1,414.6
Adjusted net debt/Group adjusted EBITDAX (1) 0.35x 0.91x
Other KPIs
Total production (boe/d) 75,755 66,685
Tier 1 / 2 process safety events 1 0
Serious injury and fatality frequency 0 0
(1) Non-GAAP measure as set out on pages 45 to 47.
H1 2023 Operational and strategic highlights
· Strong H1 production of 75.8 thousand barrels of oil equivalent per
day (kboe/d), supporting full year 2023 production guidance (H1 2022: 66.7
kboe/d)
- Production growth driven by the contribution of producing asset
additions from M&A transactions completed in the first half of 2022
- Production split 66% liquids and 34% gas
· Good progress made in H1 2023 against our BUY, BUILD and BOOST
strategy preserving optionality across our portfolio with the aim of
maximising value to shareholders
BUY
· Acquired the remaining 40% stake in the Fotla Discovery, together
with three exploration licences, providing Ithaca Energy with full control
over pre-final investment decision (FID) work and timing (subject to
completion)
· Entered into marketing agreement with Shell U.K. Limited in relation
to its interests in the Cambo field, representing a meaningful step towards
securing an aligned joint venture partnership that would enable the future
progression of the Cambo project towards FID, subject to regulatory and
licensing approval processes and market conditions
BUILD
· Pre-FID work continues across the Group's high-value greenfield and
brownfield development portfolio. Focus remains on finalising development
plans and financing for Rosebank
· Positive exploration drilling results at K2 prospect, with the
decision to proceed with an appraisal side-track (Ithaca Energy operated,
working interest 50%) highlighting Ithaca Energy's impressive exploration
track record
BOOST
· Production performance in H1 2023 driven by high production
efficiency across our operated assets in Q2 of 93%
· Material project scopes completed at Captain Enhanced Oil Recovery
(EOR) Phase II with four of the seven wells drilled. Critical EOR turnaround
scopes scheduled for H2 2023
· Front End Engineering Design (FEED) activity ongoing to explore the
potential for electrification of the Captain field, demonstrating our
continued focus on decarbonisation initiatives across our portfolio
H1 2023 Financial highlights
· Announced second interim 2023 dividend of $133 million payable in
September 2023, taking our total year to date interim 2023 dividend to $266
million, with targeted total dividend of $400 million reaffirmed for financial
year 2023
· Group adjusted EBITDAX up 8% to $979.7 million (H1 2022: $907.4
million), driven by higher production, despite lower average oil and gas
prices
· Realised oil and gas prices (respectively) of $85/boe and $82/boe
before hedging results and
$83/boe and $125/boe after hedging results (H1 2022: $107/boe and $144/boe
before hedging results and $93/boe and $105/boe after hedging results)
· Strong cost control, despite inflationary headwinds, delivering
operating costs of $272.1 million ($19.8/boe (H1 2022: $19.5/boe)), allowing
the Group to narrow its full year 2023 guidance range
· Adjusted net income of $253.2 million (H1 2022: $233.4 million)
· Statutory net income $159.6 million (H1 2022: $1,557.7 million)
reflecting a $73.7 million post-tax impairment of the Greater Stella Area due
to reduction in planned activity, as a direct result of the Energy Profits
Levy (EPL) and falling gas prices; H1 2022 includes $1,324.3 million gain on
bargain purchase which arose from the acquisitions of Marubeni UK and Siccar
Point Energy
· Net cash flow from operating activities of $691.0 million (H1 2022:
$989.0 million)
· Producing asset capex of $188 million, allowing the Group to reduce
its full year 2023 guidance range
· Strong cash flow generation supporting further deleveraging of the
balance sheet in the period. Adjusted net debt of $698.7 million at 30 June
2023 (31 December 2022: $971.2 million; 30 June 2022: $1,414.6 million)
· Group leverage position of 0.35x adjusted net debt to adjusted
EBITDAX (30 June 2022: 0.91x)
· Successful redetermination of Reserves Based Lending (RBL) facility
in June 2023
· Post period end, signed extension of bp offtake agreement and, in
parallel, entered into new five- year $100 million loan facility agreement
with bp (yet to be drawn)
Outlook
FY 2023 Management Guidance and Outlook
· Management provides the following updates to previously provided
guidance ranges and activities for full year 2023 (FY 2023):
- Production guidance reaffirmed for FY 2023 of 68-74 kboe/d;
- Operating cost guidance narrowed at the lower end of the range for
FY 2023 from $560-
$630 million to $560-$610 million; and
- Producing asset capital cost guidance for FY 2023 reduced from
$400-$460 million to $390-
$435 million
· Turnaround activity across operated and non-operated base scheduled
for Q3 2023
· Captain EOR Phase II project H2 2023 activities include the continued
drilling of Area E wells before moving to Area D to commence drilling
operations and turnaround activity in Q3 that will support polymer injection
into the subsea wells in 2024
· Continued focus on maturing high-value development projects and
preserving optionality across our portfolio while prioritising capital
allocation to maximise sustainable shareholder returns
· Management reaffirms its commitment to targeted total dividend of
$400 million for financial year 2023
Energy Profits Levy impact beyond 2023
· In June 2023, the UK government published terms of reference for the
oil and gas fiscal regime review and committed to engaging with industry
stakeholders. One of HM Treasury's stated objectives is to achieve a "simpler,
more predictable, and stabler regime" (HM Treasury)
· In the meantime, until the fiscal regime is improved, as a direct
result of the Energy Profits Levy, investment across our operated and
non-operated portfolio has and will reduce, including the deferral and
cancellation of certain 2023 and 2024 projects, impacting medium-term
production outlook, with production in 2024 expected to be lower than 2023
levels. As part of the Group's strategy, we continue to leverage our M&A
capabilities evaluating potential inorganic opportunities with the clear
intention to increase our production in the medium-term
· We are in the process of working through our medium-term outlook,
incorporating the full impact of EPL at an asset level and updating subsurface
models for the latest production history along with the potential positive
effect of new opportunities we are currently reviewing and we will share an
updated view of our medium-term production outlook later in the year
Gilad Myerson, Executive Chairman, commented: "Ithaca Energy's robust H1
performance demonstrates continued strong delivery across our BUY, BUILD and
BOOST strategy and our capital allocation policy in H1 2023. I am delighted to
announce today the second tranche of our 2023 interim dividend, taking our
total year to date dividend in 2023 to $266 million, in line with our
commitment to shareholders at IPO.
The Energy Profits Levy continues to have a direct impact on investment in the
UK North Sea and Ithaca Energy's own investment programme across its diverse
high-quality operated and non-operated asset base. We continue to
constructively engage with the UK government to highlight the impact of the
current fiscal regime to the industry's outlook and to the UK government's
stated energy security and Net Zero ambitions."
Alan Bruce, Chief Executive Officer, commented: "We are pleased to share a
strong set of results for the first half of 2023, with growing Adjusted
EBITDAX as a result of production of over 75 kboe/d in the period. Production
efficiency across our operated assets has been high demonstrating our strong
operational capabilities.
We continue to take a disciplined approach to capital investment including at
our Captain asset where we are progressing the EOR Phase II project
construction activities as well as evaluating emissions reduction options. We
reported successful exploration drilling at our K2 prospect in July which
further strengthens our high-quality development portfolio."
Ithaca Energy will host an in person and virtual presentation and Q&A session for investors and analysts at 09:00 (BST) today, 23 August 2023, accessible via our website: https://investors.ithacaenergy.com/
Half-year 2023 performance in review
Strong operational performance in H1 supports the Group's full year 2023 outlook
Continued focus on personal and process safety with one Tier 1/2 process
safety event recorded as a result of a marine gas oil leak in the Captain FPSO
power generation process. The Group's serious incident and fatality rate
remained at zero during the period.
Production in the first half of 2023 rose to an average of 75.8 kboe/d (H1
2022: 66.7 kboe/d), driven by the contribution of producing asset additions
from M&A transactions completed in the first half of 2022. Production in
the six-month period was split 66% oil and 34% gas.
The Group's operated assets accounted for 54% of total H1 2023 production (H1
2022: 63%) with strong production efficiency across the Group's operated
portfolio. In the second quarter production efficiency was 93% with the
Captain field recording its longest ever production run between field outages.
H1 2023 non-operated production was impacted by the delayed start-up and
curtailed production of the Pierce field and a number of unplanned outages at
Schiehallion that have now been resolved.
As we enter the second half of the year, the Group will embark on a series of
planned maintenance campaigns across its operated and non-operated asset base
including a scheduled ~25-day turnaround at Captain, in preparation for the
next stage of the EOR Phase II project.
With strong first half production performance; we reaffirm our 2023 production guidance of 68-74 kboe/d.
Operating costs in H1 2023 of $272.1 million (H1 2022: ($234.4 million),
representing a broadly flat net unit opex cost of $19.8/boe (H1 2022:
$19.5/boe).
During the first half of the year, the Group launched an internal cost
optimisation project focused on maintaining tight control on expenditure
across our operated and non-operated assets and corporate overhead costs.
In the medium-term, the Group has ambitions to materially reduce the average
operating cost per barrel by transitioning our portfolio to earlier-life
assets with lower operating costs.
Operating cost guidance narrowed at the lower end of the range for the year ended 31 December 2023 from $560-$630 million to $560-$610 million supported by stringent focus on ongoing cost control.
Total net producing asset capital expenditure (excluding decommissioning) in
H1 2023 of $188 million reflects the material work scopes completed at Captain
EOR Phase II during the first half of the year, with the Captain field
representing approximately 68% of producing asset capital expenditure in the
period.
Total capital spend in the year reflects lower scheduled activity across the
Group's operated and non- operated assets, with the deferral and cancellation
of capital project activities largely driven by EPL and the associated fiscal
uncertainty.
Producing asset capital cost guidance reduced for the year ended 31 December
2023 from $400-$460 million to $390-$435 million, reflecting a further
reduction to capital cost guidance in addition to the material reduction in
guidance provided earlier in the year.
Targeted investment across our strategic pillars: BUY, BUILD and BOOST
With expertise extending across the full life-cycle of E&P operations, the
Group has demonstrated its ability in the first half of 2023 to execute
operations successfully across exploration, development and production
activities.
During July, the Group announced successful exploration drilling at the K2
prospect together with the decision to proceed with follow on appraisal
drilling. Results from the appraisal side-track are expected during September
and will provide further data to determine a recoverable resource estimate and
future development activity. The K2 prospect is an excellent demonstration of
the Group's BUILD strategy targeting opportunities close to existing
infrastructure to maximise value.
Across our portfolio, we continue to seek to BOOST the value of our assets,
including infill drilling campaigns that provide short-cycle returns and
near-term cash flow generation. At Alba, preparations were underway in the
first half of the year to support an infill drilling campaign that will
commence in the second half of the year.
Material progress was made during the first half of the year on executing
Phase II of our pioneering polymer EOR project, that will maximise recovery
rates from Captain and deliver on our strategy to BOOST field performance. The
project reached a number of key milestones in H1 2023 including the successful
installation of polymer injection pumps, installation of the subsea umbilical
distribution structure and the commencement of Area E drilling operations. In
the second half of the year, activities include laying flowlines and
umbilicals, installation of piping cassettes and completion of Area E drilling
before moving to Area D.
Enhanced oil recovery from Captain EOR Phase I continues to perform well with
the first phase of polymer injection exceeding expectations with over 11
mmbbls recovered to date. We continue to refine the pioneering polymer
formulation and the development of 5th and 6th generation polymer designs,
which will continue to improve cost efficiency of the polymer flood by 10%.
With material work scopes completed, first injection of polymer to support EOR
Phase II is expected in summer 2024. History matching of the latest field
performance, together with reprocessed seismic, is currently being worked to
provide an updated subsurface model to refine the polymer response of EOR
Phase II. Initial results confirm no change to overall EOR Phase II reserve
recovery but shows indications of the possibility for a longer path to peak
response and plateau.
The Group continues to leverage our M&A capabilities (BUY) evaluating
potential inorganic opportunities both in the UK and internationally. During
the period, we entered into a marketing agreement with Shell
U.K. Limited, taking a meaningful step towards securing an aligned joint
venture partnership that would enable the future progression of the Cambo
project towards FID. Development options for Cambo continue to be evaluated to
support submission of a field development application ahead of the associated
licence milestone of 31 March 2024, subject to the outcome of the marketing
campaign. In July, the Group announced the acquisition of the remaining 40%
stake in the Fotla Discovery providing Ithaca Energy with full control over
pre-FID work and timing.
The pace of investment across our pre-FID projects has slowed as we continue
to engage with the UK government to highlight the impact of the Energy Profits
Levy and fiscal uncertainty on our ability to make critical decisions on large
scale capital investments. We remain committed to developing our pre-FID
projects and continue to engage in a constructive manner with the UK
government. During the first half of the year, the Group continued its work
towards supporting a final investment decision at Rosebank and in the
near-term, our focus remains on finalising development plans and financing
arrangements for thproject, and on prioritising capital across our strategic
pillars that will maximise shareholder returns in the current fiscal
environment.
Meaningful decarbonisation activity
Ithaca Energy is committed to its ambitions of developing one of the lowest
carbon emission portfolios in the UK North Sea by optimising our current
portfolio in the short-term, and fundamentally transitioning the portfolio in
the medium to long-term.
Significant progress has been made across our operated portfolio with
operational improvements at FPF-1 and Captain and an ongoing turbine
optimisation project at Alba. For the first six months of 2023, the GHG
emissions intensity (Scope 1 and 2), from our operated assets was 24.5
kgCO2e/boe.
FEED activity commenced in April 2023 to explore the potential for
electrification of the Group's flagship Captain field, following the
successful conclusion of a pre-FEED study in Q1 2023. With over 70% of
Captain's GHG emissions related to power generation, partial electrification
of the asset has the potential to substantially reduce emissions intensity.
The Captain electrification project is an important opportunity contributing
to Ithaca Energy meeting its target of a 50% reduction in Scope 1 and 2 CO2e
emissions by 2030. The delivery of the project is subject to accessing a
suitable grid connection or alternative power source in a timely manner.
Robust cash flow generation and continued strengthening of the balance sheet
During H1 2023, our diversified, high-quality asset base generated net cash
flow from operating activities of
$691.0 million. This strong cash flow generation supported the continued
deleveraging of our balance sheet in the first half of the year, with the
Group reporting adjusted net debt of $698.7 million, representing an adjusted
net debt to adjusted EBITDAX ratio of 0.35x at 30 June 2023.
The Group successfully completed the semi-annual redetermination of its
Reserves Based Lending facility (RBL) at the end of June securing borrowing
base availability of $865 million (31 December 2022: $925 million), excluding
RBL facilities utilised for letters of credits. The Group continues to be well
supported by a banking syndicate of nine financial institutions. The impact of
the recently announced price floor, that would trigger the early sunset of the
EPL based on oil prices dropping below $71.40 per barrel and gas prices below
54 pence per therm, was yet to be factored into borrowing base availability at
redetermination.
Post period end, the Group signed an extension to its Offtake agreement with
bp, and in parallel, entered into a new five-year $100 million term loan
facility agreement with bp at a commercial interest rate, which is yet to be
drawn. This new facility term provides capital out to 2028, supporting the
development of pre- FID fields.
The Group continues to have sufficient available capital to support our
capital allocation policy with a liquidity position at 30 June of $791.3
million (H1 2022: $320.4 million), prior to execution of the $100 million bp
loan facility agreement.
Net income recorded in H1 2023 of $159.6 million, was impacted by a pre-tax
impairment charge of $328.4 million (post tax $93.6 million), principally in
relation to the Greater Stella Area and other gains of $72.2 million in the
period. The impairment charge follows the decision not to proceed with further
infill drilling at Harrier, as a direct result of the Energy Profits Levy and
falling gas prices.
As we move into the second half of the year, we continue to take a disciplined
approach to hedging, recognising the importance of balancing upside exposure
to commodity prices while managing downside protection of our cash flows in
line with the PROTECT pillar of our capital allocation policy. At 30 June
2023, the Group has a hedged position of 9.9 million barrels of oil equivalent
(mmboe) (62% oil) from H2 2023 into 2025 at an average price floor of $73/bbl
for oil and 161p/therm for gas. Following the period end, we have been active
in placing further hedges on attractive terms and at 15 August our hedged
position has increased to 11.5 mmboe (66% oil) from H2 2023 into 2025 at an
average price floor of $73/bbl for oil and 159p/therm for gas.
In line with our capital allocation policy, we announced and paid the first
tranche of our 2023 dividend of $133 million in March 2023. We are pleased to
today declare the second tranche of our 2023 dividend of a further $133
million, payable in September this year, taking our total 2023 interim
dividend to $266 million. Ithaca Energy remains committed to its declared
dividend policy with a targeted 2023 total dividend of $400 million.
Outlook
Ithaca Energy remains committed to investing in its asset base in the UK North
Sea and continues to constructively engage with the UK government to highlight
the negative impact of the Energy Profits Levy to our investment programme and
the consequential medium and long-term impact to the UK government's energy
security and Net Zero ambitions.
New investment has been severely dampened across the UK North Sea in 2023,
with operators delaying or cancelling projects given the competition for
capital across global portfolios. While we maintain our 2023 production
guidance, due to our continued strong operational performance, it is clear
that we, like the rest of the industry, will feel the impact of lower
investment on our medium-term production outlook below previously guided
levels.
The Energy Profits Levy has already resulted in the deferral or cancellation
of investment across the Group's operated and non-operated assets, including
in the Greater Stella Area (impairment charges in Q2 2023), Montrose Arbroath
Area and Elgin Franklin Area. As capital investment plans are being drawn up
for 2024 and beyond, both Ithaca Energy and our diverse partner groups, are
reconsidering the attractiveness of capital deployment opportunities in the
context of an enduring Energy Profits Levy in what we would consider to be a
return to normal commodity prices. As an inevitable consequence of the current
fiscal environment, our medium-term production outlook will be impacted, such
that we now anticipate production in 2024 to fall below 2023 levels. For
example, the predominantly 100% Ithaca Energy owned Greater Stella Area is
expected to produce over 5,000 boe/d less in 2024, with Energy Profits Levy
related investment decisions driving the reduction. We are currently in the
process of reviewing inorganic opportunities with the clear intention to
increase our production in the medium-term.
Ithaca Energy is actively participating in the ongoing review of the Oil and
Gas Fiscal Regime in pursuit of a stable and supportive fiscal regime,
required to make critical investment decisions that will support the UK's
future energy security. We strongly believe that further amendments are
required to the Energy Profits Levy including the amendment, and legislation,
of an appropriate price floor that reflects the seasonal nature and structural
changes in gas markets.
In the period to June 2023, the Group incurred Energy Profits Levy charges of
$223 million.
As we navigate the continued impact of the Energy Profits Levy to our
operations, we remain value-focused and disciplined, investing only in
opportunities across our BUY, BUILD and BOOST strategy that we believe have
the potential to deliver growth and maximise shareholder value, including the
pursuit of value- accretive inorganic opportunities that strengthen short to
medium-term cash flows.
Enquiries
Ithaca Energy
Kathryn Reid - Head of Investor Relations, Corporate Affairs & kathryn.reid@ithacaenergy.com (mailto:kathryn.reid@ithacaenergy.com)
Communications
FTI Consulting (PR Advisers to Ithaca Energy) +44 (0)203 727 1000
Ben Brewerton / Nick Hennis ithaca@fticonsulting.com (mailto:ithaca@fticonsulting.com)
About Ithaca Energy plc
Ithaca Energy is a leading UK independent exploration and production company
focused on the UK North Sea with a strong track record of material value
creation. In recent years, the Company has been focused on growing its
portfolio of assets through both organic investment programmes and
acquisitions and has seen a period of significant M&A driven growth
centred upon two transformational acquisitions in recent years. Today, Ithaca
Energy is one of the largest independent oil and gas companies in the United
Kingdom Continental Shelf (the "UKCS"), ranking second by resources.
With stakes in six of the ten largest fields in the UKCS and two of UKCS's
largest pre-development fields, and with energy security currently being a key
focus of the UK Government, the Group believes it can utilise its significant
reserves and operational capabilities to play a key role in delivering
security of domestic energy supply from the UKCS.
Ithaca Energy serves today's needs for domestic energy through operating
sustainably. The Group achieves this by harnessing Ithaca Energy's deep
operational expertise and innovative minds to collectively challenge the norm,
continually seeking better ways to meet evolving demands.
Ithaca Energy's commitment to delivering attractive and sustainable returns is
supported by a well-defined emissions-reduction strategy with a target of
achieving net zero by 2040.
Ithaca Energy plc was admitted to trading on the London Stock Exchange (LON:
ITH) on 14 November 2022.
-ENDS-
Financial performance: revenue, costs and charges and adjusted EBITDAX
Statutory net income was $159.6 million (H1 2022: $1,557.5 million) reflecting
a $73.7 million post-tax impairment of the Greater Stella Area due to a
reduction in planned activity as a direct result of the EPL as well as falling
gas prices. H1 2022 included a $1,324.3 million gain on bargain purchase which
arose on the Marubeni ans Siccar Point Energy acquisitions.
Adjusted EBITDAX is a key measure of operational performance delivery in the
business and increased by 8.0% in H1 2023 to $979.7 million (H1 2022: $907.4
million) despite lower revenue in H1 2023 of $1,248.1 million (H1 2022:
$1,337.6 million). The reduction in revenue was principally due to changes in
overlift and underlift positions relative to H1 2022 and lower commodity
prices compared to H1 2022, partly offset by higher production in H1 2023
mainly due to acquisitions made during the first half of 2022. Increased
production was delivered from new field equity production from acquisitions
including from the MonArb area fields (from February 2022), and from the Jade,
Elgin Franklin, Mariner and Schiehallion fields (from July 2022).
Average realised oil prices for H1 2023 were $85/boe before hedging results
and $83/boe after hedging results (H1 2022: $107/boe before hedging results
and $93/boe after hedging results). Average realised gas prices for H1 2023
were $82/boe before hedging results and $125/boe after hedging results (H1
2022: $144/boe before hedging results and $105/boe after hedging results).
The focus on cost was maintained during the period with unit operating
expenditure increasing marginally to $19.8/boe (H1 2022: $19.5/boe) reflecting
our disciplined cost management approach across the portfolio.
Adjusted EBITDAX
analysis
H1 2023
H1 2022 FY
2022
Production kboe/d mmboe kboe/d mmboe kboe/d mmboe
Oil Gas NGL 47 8 40 8 43 16
25 5 24 4 24 9
3 1 3 0 4 1
Total production 76 14 67 12 71 26
Revenues(1) $/boe $m $/boe $m $/boe $m
Oil revenue 85 650 107 973 100 1,693
Gas revenue 82 380 144 605 149 1,348
NGL revenue 42 26 67 35 57 76
Oil and gas hedging gains/(losses) 13 172 (22) (269) (19) (501)
Total 90 1,228 111 1,344 100 2,615
Movement in oil and gas stocks 4 58 (16) (186) (5) (130)
Tanker costs (1) (12) (1) (11) - (18)
Stella royalties - (3) - (6) - (11)
Total value from production 93 1,271 94 1,141 94 2,457
Costs
Operating costs (20) (272) (19) (234) (19) (496)
Routine G&A (1) (15) - (6) (1) (28)
Forex gain/(loss) - (4) - 6 (1) (17)
Total operating cash costs (21) (291) (19) (234) (21) (540)
Adjusted EBITDAX(2) 71 980 75 907 73 1,916
1 Revenues in the above table exclude principally other income and put
premiums on oil and gas derivative instruments.
2 Non-GAAP measure.
OPERATIONAL AND FINANCIAL REVIEW CONTINUED
Revenue and EBITDAX
H1 2023 H1 2022
Production (boe/d) 75,755 66,685
$m $m
Oil sales 650.2 973.3
Gas sales 379.9 605.0
NGL sales 26.4 35.3
Other income 17.4 18.8
Realised losses on oil derivative contracts (12.5) (125.9)
Put premiums on oil derivative instruments (6.3) (7.2)
Realised gains/(losses) on gas derivative contracts 194.1 (144.3)
Put premiums on gas derivative instruments (1.1) (17.4)
Total revenue 1,248.1 1,337.6
Operating costs (300.7) (263.2)
Inventory movements and other items 32.3 (167.0)
Adjusted EBITDAX 979.7 907.4
Statutory net income was $159.6 million (H1 2022: $1,557.7 million) and
adjusted net income was $253.2 million (H1 2022: $233.4 million). A
reconciliation between statutory net income and adjusted net income is set out
on page 13.
Total costs and charges
Total costs and charges amounted to $999.4 million (H1 2022: credit of $403.8
million) and
comprised:
H1 2023$m H1 2022$m
Depletion, depreciation and amortisation (384.1) (297.4)
Operating costs (300.7) (263.2)
Movement in inventory 57.5 (186.1)
Royalties (3.2) (5.4)
Impairment (328.4) (7.6)
Exploration and evaluation (1.3) (9.5)
Other gains/(losses) 72.2 (27.5)
Administrative expenses (14.9) (26.7)
Gain on bargain purchase - 1,324.3
Net finance costs (96.5) (97.1)
Total costs and charges (999.4) 403.8
Depletion, depreciation and amortisation charges were $384.1 million (H1 2022:
$297.4 million). The year-on-year increase is principally due to the
acquisitions made during 2022. Depletion, depreciation and amortisation per
barrel was $28 (H1 2022: $25) with the increase driven mainly by the
acquisitions made during H1 2022.
Operating costs amounted to $300.7 million (H1 2022: $263.2 million) with the
increase driven mainly by higher production.
Movements in oil and gas inventories was a credit of $57.5 million (H1 2022:
charge of $186.1 million) representing movements in underlift/overlift
entitlement imbalances.
Impairment charges of $328.4 million (H1 2022: $7.6 million) principally
reflects an impairment of development and production assets relating to the
Greater Stella Area field as a result of lower future gas prices than
previously forecast and a reduction in planned activity as a direct result of
the EPL (see note 3 for further details).
Exploration and evaluation costs amounted to $1.3 million (H1 2022: $9.5
million) and principally relate to licence relinquishments during the period.
Other gains of $72.2million (H1 2022: losses of $27.5 million) comprise
principally gains on financial instruments and a historic claim relating to an
acquisition which was settled in Q1 2023. Administrative expenses were $14.9
million (H1 2022: $26.7 million) with the reduction principally due to
non-recurring transaction costs in H1 2022.
Gain on bargain purchase in H1 2022 arose on the Marubeni and Siccar Point
Energy acquisitions (see 2022 Annual Report and Accounts for further details).
Net finance costs were $96.5 million (H1 2022: $97.1 million) with the
reduction principally due to lower interest on related party loans which were
repaid during 2022 partly offset by higher bank interest and higher accretion
on decommissioning liabilities as a result of a higher discount rate.
OPERATIONAL AND FINANCIAL REVIEW CONTINUED
Financial performance: net income
H1 2023
$m
H1 2022
$m
Profit before tax 248.7 1,741.3
Tax (89.1) (183.6)
Net income after tax 159.6 1,557.7
Gain on bargain purchase - (1,324.3)
Impairment charges 328.4 -
Tax credit on impairment charges (234.8) -
Adjusted net income(1) 253.2 233.4
1 Non-GAAP measure.
Adjusted net income was broadly in line with H1 2022 despite the introduction
of the EPL which added an incremental current tax charge of $223.1 million for
the first half of 2023.
Financial position: assets/liabilities/equity
30 June 2023 $m 31 December 2022 $m
Total assets 6,365.4 6,759.6
Total liabilities (3,853.3) (4,302.1)
Net assets and shareholders' equity 2,512.1 2,457.5
Assets
At 30 June 2023, total assets amounted to $6,365.4 million (31 December 2022:
$6,759.6 million), of which current assets were $878.6 million (31 December
2022: $988.7 million) and non-currents assets were $5,486.8 million (31
December 2022: $5,770.9 million). The decrease in total assets during the
period was primarily due to a reduction in the carrying value of property,
plant and equipment as the depreciation charge and impairment charges during
the period were significantly higher than fixed asset additions, a $59.2m
increase in exploration and evaluation assets primarily due to additions
during the period as well as a $103.3m increase in deferred tax assets.
Liabilities
At 30 June 2023, total liabilities amounted to $3,853.3 million (31 December
2022: $4,302.1 million) including decommissioning provisions of $1,797.5
million (31 December 2022: $1,720.5 million) and borrowings of
$866.0 million (31 December 2022: $1,213.7 million). The decrease in total
liabilities during the period was primarily due to lower borrowings of $347.7
million (see cash flow on page 14), a reduction in trade and other payables of
$190.5 million due to a lower level of unfavourably hedged commodity
positions, lower overlift at 30 June 2023 and lower derivative financial
instruments partly offset by an increase in current tax payable of $156.0
million principally due to EPL.
Equity and reserves
At 30 June 2023, total equity and reserves amounted to $2,512.1 million (31
December 2022: $2,457.5 million) The increase in equity and reserves during
the period was primarily due to the retained profit for the period partly
offset by the interim dividend paid in March.
Financial position: cash
H1 2023
$m
H1 2022
$m
Opening cash 253.8 44.9
Operating cash flows 691.0 989.0
Investing cash flows (221.6) (1,203.6)
Financing cash flows (548.1) 332.7
Foreign exchange 1.2 (2.6)
Net cash flow (77.5) 115.5
Closing cash 176.3 160.4
Undrawn borrowing facilities/restricted cash 615.0 160.0
Available liquidity 791.3 320.4
Operating cash flows
Net cash from operating activities amounted to $691.0 million (H1 2022: $989.0
million) after accounting for adverse working capital movements of $184.2
million (H1 2022: favourable movements of $156.7 million) primarily due to
changes in the overlift/underlift position with the reduction principally due
to the working capital movement compared to H1 2022.
Investing cash flows
Cash flow used in investing activities amounted to $221.6 million (H1 2022:
$1,203.6 million) reflecting capital expenditure of $218.0 million (H1 2022:
$230.3 million) driven mainly by the Captain development project. H1 2022
included investing cash flows related to acquisitions (net of cash acquired)
of $957.5 million being primarily driven by the Siccar Point Energy ($926.7
million) acquisition.
Financing cash flows
Cash outflow from financing activities of $548.1 million (H1 2022: inflow of
$332.7 million) with interest costs and lease payments of $65.1 million (H1
2022: $67.5 million), a net repayment of principal debt of $350.0 million (H1
2022: increase of $400.0 million) and the payment of the first interim
dividend of $133.0 million (H1 2022: $nil).
Cash balances were $176.3 million (H1 2022: $160.4 million) at the end of the
period and available liquidity was $791.3 million (H1 2022: $320.4 million).
OPERATIONAL AND FINANCIAL REVIEW CONTINUED
Subsequent events
On 11 July 2023, the Group announced that it had signed a Sale and Purchase
Agreement to acquire the 40% stake in the Fotla Discovery that it doesn't
already own and three exploration licences from Spirit Energy Resources
Limited. The agreement, which is subject, amongst other things, to regulatory
approval, will bring the Group's working interest in Fotla to 100% providing
Ithaca Energy with full control over pre-final investment decision work and
timing. The total transaction consideration of up to $14.6 million, comprises
two capped contingent payments of which approximately two-thirds is payable on
final investment decision and one-third on first production.
On 26 July 2023, Ithaca Energy announced successful well test results at the
K2 prospect and as a result the Group, together with its joint venture
partner, have decided to perform an appraisal sidetrack following the positive
results in the main bore. The Group holds a 50% working interest in this
licence with the remaining 50% working interest held by Dana Petroleum.
On 31 July 2023, the Group completed a new 5-year $100m unsecured loan
agreement with bp at a commercial interest rate. Separately, a new offtake
agreement was also completed with bp on that date which runs concurrently with
the loan agreement.
Going concern
Based on their assessment of the Group's financial position over the period to
30 September 2024, the Directors believe that the Group will be able to
continue in operational existence for the foreseeable future. Accordingly,
they continue to adopt the going concern basis of accounting in preparing the
consolidated financial statements. Further details are set out in note 3.
Derivative financial instruments
Derivative financial instruments are utilised to manage commodity price risk
in a substantive financial hedging programme for future oil and gas production
volumes. As at 30 June 2023, the following hedges were in place:
H2 2023 2024 2025
Oil
Volume hedged (mmboe) 4.2 1.9 -
Weighted average floor hedged price ($/bbl) 71 78 -
Gas
Volume hedged (mmboe) 1.5 2.1 0.2
Weighted average floor hedged price (p/therm) 193 143 125
Principal risks and uncertainties
The Group faces various risks that could result in events or circumstances
that might threaten our business model, future performance, liquidity,
solvency or reputation. Not all of these risks are completely within the
control of the business and the Group may be affected by risks that have yet
to manifest themselves or are not reasonably foreseeable at the present time.
For those identified risks, the Group has mitigation strategies to minimise
the likelihood of the risk and reduce the impact as far as is practicable.
Depending on the nature of the risk, the Group may elect to take or tolerate
risk, treat risk with mitigating actions, transfer risk to third parties, or
eliminate risk by ceasing certain operations or activities.
The Directors have reviewed the principal risks and uncertainties facing the
Group and have concluded that those facing the Group for the remaining six
months of the current financial year are unchanged from the risks set out in
the 2022 Annual Report and Accounts. In reaching this conclusion, the
Directors considered changes in the internal and external environment during
the intervening period which could threaten the Group's business model, future
performance, liquidity, solvency or reputation.
The principal risks and uncertainties are as follows:
• Major HSE incident
• Cyber security breach
• Access to capital
• Capital project execution and delivery
• Commodity price exposure and volatility
• Production delivery issues
• Energy transition and Net Zero delivery
• Workforce recruitment and retention
• Supply chain capacity and capability
• Governmental regulatory, political policy and fiscal risk
• Major compliance breach
Details of these principal risks and how they are being managed are set out on
pages 64 to 68 of the 2022 Annual Report and Accounts.
STATEMENT OF DIRECTORS' RESPONSIBILITIES
The Directors confirm that, to the best of their knowledge:
• The condensed set of financial statements has been prepared in
accordance with IAS 34 Interim Financial Reporting as contained within UK
adopted IFRS;
• The half-yearly results statement includes a fair review of the
information required by DTR 4.2.7R (indication of important events during the
first six months and description of principal risks and uncertainties for the
remaining six months of the year); and
• The half-yearly results statement includes a fair review of the
information required by DTR 4.2.8R (disclosure of material related parties'
transactions and changes therein).
By order of the Board,
IAIN C S LEWIS
Director
22 August 2023
INDEPENDENT REVIEW REPORT TO ITHACA ENERGY PLC
Conclusion
We have been engaged by the company to review the condensed set of financial
statements in the half-yearly financial report for the six months ended 30
June 2023 which comprises:
• The condensed consolidated statement of profit or loss;
• The condensed consolidated statement of comprehensive income;
• The condensed consolidated statement of financial position;
• The condensed consolidated statement of changes in equity;
• The condensed consolidated statement of cash flows; and
• The related notes 1 to 19 to the condensed consolidated financial
statements.
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 2023 is not prepared, in all
material respects, in accordance with United Kingdom adopted International
Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of
the United Kingdom's Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with International Standard on Review
Engagements (UK) 2410 "Review of Interim Financial Information Performed by
the Independent Auditor of the Entity" issued by the Financial Reporting
Council for use in the United Kingdom (ISRE (UK) 2410). A review of interim
financial information consists of making inquiries, 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 United Kingdom adopted international accounting
standards. The condensed set of financial statements included in this half-
yearly financial report has been prepared in accordance with United Kingdom
adopted International Accounting Standard 34 Interim Financial Reporting.
Conclusion 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 entity to
cease to continue as a going concern.
Responsibilities of the directors
The directors are responsible for preparing the half-yearly financial report
in accordance with the 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 company'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
company 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 financial report, we are responsible for
expressing to the company a conclusion on the condensed set of financial
statements in the half-yearly financial report. Our Conclusion, including our
Conclusion 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
This report is made solely to the company in accordance with ISRE (UK) 2410.
Our work has been undertaken so that we might state to the company those
matters we are required to state to it in an independent review report and for
no other purpose. To the fullest extent permitted by law, we do not accept or
assume responsibility to anyone other than the company, for our review work,
for this report, or for the conclusions we have formed.
DELOITTE LLP
Statutory Auditor London, United Kingdom 22 August 2023
2023 2022 2023 2022
Note US$'000 US$'000 US$'000 US$'000
(Unaudited) (Unaudited) (Unaudited) (Audited)
Revenue 4 603,793 597,426 1,248,109 1,337,585
Cost of sales (327,480) (343,416) (630,391) (752,035)
5
Gross profit 276,313 254,010 617,718 585,550
Impairment charge 3 (328,426) (7,608) (328,426) (7,608)
Exploration and evaluation expenses - (7,945) (1,334) (9,550)
Administrative expenses (5,057) (13,192) (14,935) (26,746)
Other gains/(losses) 6 (18,752) (21,419) 72,239 (27,562)
Gain on bargain purchase - 723,405 - 1,324,342
Profit/(loss) from operations before tax and net finance costs (75,922) 927,251 345,262 1,838,426
Net finance costs 7 (46,939) (47,606) (96,521) (97,081)
Profit/(loss) before tax (122,861) 879,645 248,741 1,741,345
Income tax 12 124,006 (84,162) (89,155) (183,655)
Profit attributable to owners of the parent 1,145 795,483 159,586 1,557,690
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
Earnings per share for profit attributable to the ordinary equity holders of Note Cents Cents Cents Cents
the Company
Basic earnings per share 8 0.1 79.1 15.9 155.0
Diluted earnings per share 0.1 79.1 15.7 154.8
8
The results above are entirely derived from continuing operations.
The accompanying notes on pages 26 to 44 are an integral part of the financial
statements.
2023 2022 2023 2022
Note US$'000 US$'000 US$'000 US$'000
(Unaudited) (Unaudited) (Unaudited) (Audited)
Profit for the period 1,145 795,483 159,586 1,557,690
Items that may be reclassified to profit and loss
Fair value gain/(loss) on cash flow hedges and cost of hedging 16 (283) 189,916 83,178 (267,082)
Deferred tax (charge)/credit on cash flow hedges and cost of hedging 12 135 (75,966) (62,292) 106,833
Other comprehensive profit/(loss) (148) 113,950 20,886 (160,249)
Total comprehensive profit attributable to owners of the parent 997 909,433 180,472 1,397,441
The accompanying notes on pages 26 to 44 are an integral part of the financial
statements.
30 June 31 December
2023 2022
US$'000 US$'000
Note (Unaudited) (Audited)
Assets
Current assets
Cash and cash equivalents 176,324 253,822
Trade and other receivables 9 349,100 359,994
Decommissioning receivable 24,115 38,115
9
Prepaid expenses and decommissioning securities 7,748 9,055
Inventories 174,064 176,881
Derivative financial instruments 17 147,189 150,858
878,540 988,725
Non-current assets
Decommissioning receivable 9 171,551 162,710
Exploration and evaluation assets 834,969 775,773
10
Property, plant and equipment 3,191,071 3,634,896
11
Deferred tax assets 495,715 392,456
12
Derivative financial instruments 9,668 21,191
17
Goodwill 783,848 783,848
5,486,823 5,770,874
Total assets 6,365,363 6,759,599
Liabilities and equity
Current liabilities
Trade and other payables (520,930) (711,412)
Current tax payable (262,705) (106,678)
Decommissioning liabilities 14 (86,929) (146,829)
Lease liability (42,634) (41,637)
Contingent and deferred consideration 15 (38,406) (107,680)
Derivative financial instruments (23,283) (136,668)
17
(974,887) (1,250,904)
30 June 31 December
2023 2022
US$'000 US$'000
Note (Unaudited) (Audited)
Non-current liabilities
Borrowings 13 (865,984) (1,213,731)
Decommissioning liabilities (1,710,562) (1,573,711)
14
Lease liability - (17,221)
Contingent and deferred consideration 15 (291,759) (219,120)
Derivative financial instruments (10,071) (27,440)
17
(2,878,376) (3,051,223)
Total liabilities (3,853,263) (4,302,127)
Net assets 2,512,100 2,457,472
Shareholders' equity
Share capital 11,445 11,445
Share premium 293,712 293,712
Capital contribution reserve 181,945 181,945
Share-based payment reserve 12,081 4,920
Cash flow hedge reserve 36,938 16,710
Cost of hedging reserve 3,933 3,275
Retained earnings 1,972,046 1,945,465
Total equity 2,512,100 2,457,472
The accompanying notes on pages 26 to 44 are an integral part of the financial
statements.
Approved on behalf of the Board on 22 August 2023:
IAIN C S LEWIS,
Director
Retained
Share capital Share premium Capital contribution Share-based payment reserve Cash flow hedge reserve Cost of hedging reserve earnings/ (accumulated
reserve losses) Total
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
Balance at 1 January 2022 1 634,658 114,000 - (242,791) (4,862) 175,503 676,509
Total comprehensive income for the period:
Profit for the period - - - - - - 1,557,690 1,557,690
- - - (43,649) (116,600) - (160,249)
-
Other comprehensive expense
Total comprehensive income/(expense) for the period - - - - (43,649) (116,600) 1,557,690 1,397,441
Balance at 30 June 2022 (Audited) 1 634,658 114,000 - (286,440) (121,462) 1,733,193 2,073,950
Balance at 1 January 2023 11,445 293,712 181,945 4,920 16,710 3,275 1,945,465 2,457,472
- - - - - (133,005) (133,005)
-
Dividend
- - - - - - 7,161
7,161
Share-based payment charge
Total comprehensive income for the period:
Profit for the period - - - - - - 159,586 159,586
- - - 20,228 658 - 20,886
-
Other comprehensive income
Total comprehensive income for the period - - - - 20,228 658 159,586 180,472
Balance at 30 June 2023 11,445 293,712 181,945 12,081 36,938 3,933 1,972,046 2,512,100
The accompanying notes on pages 26 to 44 are an integral
part of the financial
statements.
Three months ended 30 June Six
months ended 30 June
Cash provided by/(used in) operating activities:
Note
2023
US$'000
(Unaudited)
2022
US$'000
(Unaudited)
2023
US$'000
(Unaudited)
2022
US$'000
(Audited)
Profit/(loss) before tax (122,861) 879,645 248,741 1,741,345
Adjustments for:
Depletion, depreciation and amortisation 11 195,386 152,387 384,120 297,417
Exploration and evaluation expenses - 7,945 1,334 9,550
Impairment charge 328,426 7,608 328,426 7,608
Increase in contingent/deferred consideration 26,103 14,449 1,725 14,449
Loan fee amortisation 1,103 1,127 2,254 2,282
Revaluation of financial instruments (16,990) 12,294 (38,660) 18,676
Prepaid put premiums 1,142 - 1,142 -
Gain on bargain purchase - (723,405) - (1,324,342)
Hedging resets(1) - (10,017) - (20,318)
Accretion 19,763 12,208 37,912 24,212
Bank interest and charges 26,072 49,366 56,355 52,920
Interest on related party loan - 17,924 - 17,924
Interest rate swaps - (4,782) - (257)
Unrealised foreign exchange on cash and cash equivalents (1,582) 2,585 (1,219) 2,585
Share-based payment expenses 4,304 - 8,562 -
Decommissioning expenditure (31,314) (7,894) (56,771) (11,689)
Operating cash flows before movements in working capital 429,552 411,440 973,921 832,362
Decrease in inventories 5,909 8,013 2,818 42,945
Decrease/(increase) in trade and other receivables 13,319 118,709 28,398 (58,228)
(Decrease)/increase in trade and other payables (109,161) 167,142 (215,466) 171,954
Corporation tax paid - - (98,719) -
Net cash from operating activities 339,619 705,304 690,952 989,033
FOR THE THREE MONTHS ENDED 31 MARCH
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
Note US$'000 US$'000 US$'000 US$'000
(Unaudited) (Unaudited) (Unaudited) (Audited)
Cash used in investing activities
Capital expenditure (120,322) (153,091) (218,002) (230,338)
Acquisition of subsidiaries net of cash acquired - (1,017,270) - (957,452)
Contingent/deferred consideration payment (1,220) (4,237) (3,568) (15,864)
Net cash used in investing activities (121,542) (1,174,598) (221,570) (1,203,654)
Cash provided by/(used in) financing activities
Dividends paid - - (133,005) -
Payments for lease liabilities (principal) (11,107) (9,621) (15,912) (13,018)
Loan repayment (third party) (100,000) 600,000 (350,000) 400,000
Bank interest and charges (7,634) (31,101) (49,182) (54,517)
Interest rate swaps - 257 - 257
Net cash used in financing activities (118,741) 559,535 (548,099) 332,722
Currency translation differences relating to cash 1,583 (1,736) 1,219 (2,582)
Increase/(reduction) in cash and cash equivalents 100,918 88,505 (77,498) 115,519
Cash and cash equivalents, beginning of period 75,406 71,863 253,822 44,849
Cash and cash equivalents, end of period 176,324 160,368 176,324 160,368
1. Hedging resets relate to the amortisation of the deferred reset gains which
have been recycled to the current year profit and loss.
The accompanying notes on pages 26 to 44 are an integral part of the financial
statements.
1. Nature of operations
Ithaca Energy plc (the Group or Ithaca Energy), is a Company limited by shares
incorporated and domiciled in the UK and is a Group involved in the
development and production of oil and gas in the North Sea. The Group's
registered office is 17 Hanover Square, London, United Kingdom, W1S 1BN.
2. Basis of preparation
The condensed consolidated financial statements are prepared in accordance
with United Kingdom adopted International Accounting Standard 34 Interim
Financial Reporting as contained within UK Adopted IFRS.
The condensed consolidated financial statements for the six months ended 30
June 2023 do not include all the information required for a full annual report
and do not constitute statutory accounts within the meaning of section 434(3)
of the Companies Act 2006. The condensed consolidated financial statements for
the six month period ended 30 June 2023 are not audited but have been reviewed
by the auditor whose review report is set out on page 18. The accounting
policies adopted in the preparation of the H1 2023 condensed consolidated
financial statements are consistent with those adopted and disclosed in the
Group's 2022 Annual Report and Accounts. Comparative information for the year
ended 31 December 2022 has been taken from the statutory accounts for that
year, a copy of which has been delivered to the Registrar of Companies. The
auditor's report on those accounts was not qualified, did not include a
reference to any matters to which the auditors drew attention by way of
emphasis and did not contain any statements under section 498(2) or (3) of the
Companies Act 2006. Comparative information
for the six months ended 30 June 2022 has been taken from the audited
Historical Financial Information included in the IPO Prospectus issued in
November 2022. A number of amendments to existing standards and
interpretations were effective from 1 January 2023, as was IFRS 17 Insurance
Contracts, but there was no impact on the H1 2023 condensed consolidated
financial statements. The Group has not early adopted any standard,
interpretation or amendment that has been issued but is not yet effective.
The condensed consolidated financial statements are presented in US dollars as
this is the functional currency of the business. All values are rounded to the
nearest thousand (US$'000), except when otherwise indicated.
In terms of segmental reporting, the Group currently operates a single class
of business being oil and gas exploration, development and production and
related activities in a single geographical area, being presently the North
Sea. The Group's segmental reporting structure remained in place for all
periods presented and is consistent with the way in which the Group's
activities are presented to the Board and to the Chief Decision Making
Officer. The Group's activities are considered to be an individual operating
segment due to the nature of the Group's operations being uniform, and such
operations existing in a single geographical area which is overseen by the
same management and covered by the same regulations.
These H1 2023 condensed consolidated financial statements are to be read in
conjunction with Ithaca Energy's Annual Report and Accounts for the year ended
31 December 2022, which contains additional accounting policy disclosure.
3. Accounting policies Basis of measurement
The condensed consolidated financial statements have been prepared on a going
concern basis using the historical cost convention, except for the revaluation
of certain financial assets and financial liabilities (under IFRS) to fair
value, including derivative instruments. Historical cost is generally based on
the fair value consideration given in exchange for the assets.
Going concern
Management closely monitors the funding position of the Group including
monitoring compliance with covenants and available facilities to ensure
sufficient headroom is maintained to fund operations. Management have
considered a number of risks applicable to the Group that may have an impact
on the Group's ability to continue as a going concern. Short-term and
long-term cash forecasts are prepared on a weekly and quarterly/annual basis
respectively along with any related sensitivity analysis. This allows
proactive management of any business risk including liquidity risk.
The Directors consider the preparation of the condensed financial statements
on a going concern basis to be appropriate. This is due to the following key
factors:
• Strong commodity markets and continuing robust commodity price
backdrop despite lower prices during H1 2023 and a well hedged portfolio over
the next 12 months;
• A new 5-year $100 million loan agreement with bp entered into
after the end of the period (see note 19);
• Reserves Based Lending (RBL) liquidity headroom of $615 million
($250 million drawn versus $865 million available), plus $176 million of cash
as at the end of June 2023; and
• Strong operational performance and well-diversified portfolio.
3. Accounting policies continued
Cash flow forecast - base case assumptions: H2 2023 2024
Average oil price $/bbl 84 82
Average gas price p/th 88 126
Average hedged oil price (including floor price for zero cost collars) $/bbl 72 77
Average hedged gas price (including floor price for zero cost collars) p/th 190 143
Owing to the on-going fluctuations in commodity demand and price volatility,
management prepared sensitivity analysis to the forecasts and applied a number
of plausible downside scenarios including decreases in production of 10%,
reduced sales prices of 20% and increases in operating and capital
expenditures of 10%. Management aggregated these scenarios to create a
reasonable combined worst-case scenario. The sensitivity analysis showed that
there was no reasonably possible scenario that would result in the business
being unable to meet its liabilities as they fell due. The Group would still
continue to comply with financial covenants and have sufficient liquidity
throughout the period to 30 September 2024 to continue trading. In addition,
mitigation strategies within the control of management include the reduction
in uncommitted capital expenditure, variable opex savings in the low
production scenario, the cancellation or deferral of future dividends and
further potential to refinance the Group's borrowing arrangements.
Based on their assessment of the Group's financial position in the period to
30 September 2024, the Directors believe that the Group will be able to
continue in operational existence for the foreseeable future. Accordingly,
they continue to adopt the going concern basis of accounting in preparing the
H1 2023 condensed consolidated financial statements.
Use of judgements and estimates
In preparing these H1 2023 condensed consolidated financial statements,
management has made judgements and estimates that affect the application of
accounting policies and the reported amounts of assets and liabilities and
income and expenses. Actual results may differ from these estimates.
The key sources of estimation uncertainty that may have a significant risk of
causing a material adjustment to the carrying amounts of assets and
liabilities within the next year are the same as those described on page 150
of the Group's 2022 Annual Report and Accounts with the below exception. The
only critical accounting judgement applied in the preparation of the H1 2023
condensed consolidated financial statements is whether there has been an
indication of impairment in respect of the Cambo field, as discussed further
below.
Estimates in impairment of oil and gas assets and goodwill
Determination of whether the Group's oil and gas assets (note 11) or goodwill
have suffered any impairment requires an estimation of the recoverable amount
of the cash generating unit (CGU) to which the oil and gas assets and goodwill
have been allocated. Projected future cash flows are used to determine a fair
value less cost to sell to establish the recoverable amount. Key assumptions
and estimates in the impairment models relate to commodity prices that are
based on an internal view of forward price curves that are considered to be a
best estimate of what a market participant would use, discount rate which
reflect management's best estimate of a market participant's post-tax weighted
average cost of capital, and oil and gas reserves and resources on a risked
basis as described in the 2022 Annual Report and Accounts. Management's best
estimates of a market participant's view of pricing and discount rates are
also supported by an independent consultant.
Following a quarterly review for indicators of impairment it was identified
that there were indicators of impairment relating to the Greater Stella Area
(GSA) CGU due to lower than previously forecast future gas prices as well as a
reduction in planned activity as a direct result of the EPL. It was determined
that the recoverable amount of the GSA CGU was $273.5 million compared to a
carrying value of $568.2 million resulting in a pre-tax impairment charge of
$294.7 million. Separately, a pre-tax impairment charge of $33.7 million arose
primarily on higher decommissioning costs on Fionn and Anglia which are both
fully depreciated and have ceased production. The total impairment charge in
the six months to 30 June 2023 was therefore $328.4 million (six months to 30
June 2022: $7.6 million).
The H1 2023 impairment projections for GSA used a post-tax discount rate of
10.5% and the following nominal commodity price assumptions:
H2 2023 2024 2025 2026 2027
Oil ($/bbl) 84 87 90 92 93
Gas (p/therm) 129 114 99 77 79
3. Accounting policies continued
Details of assumptions used for impairment testing for year ending 31 December
2022 and 31 December 2021 are set out on pages 165 and 166 of the 2022 Annual
Report and Accounts.
With all other assumptions held constant, a 20% decrease in forecast revenues,
illustrating lower commodity prices and/or production volumes, would result in
a further post-tax impairment of GSA property, plant and equipment (PP&E)
of $98 million. An increase of 1% in the discount rate assumption would not
have a material impact on the post-tax impairment.
Management has reviewed the carrying value of the Cambo field and has
concluded that due to ongoing initiatives, including those to address Shell's
exit and the 31 March 2024 licence expiry, there are currently no indicators
of impairment. Further details are provided in the Half Year 2023 Performance
in Review.
Judgements and estimates made in assessing the impact of climate change and
the energy transition have not materially changed for the H1 2023 consolidated
condensed financial statements. Details of these are set out on pages 141 and
142 of the 2022 Annual Report and Accounts.
4. Revenue
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Oil sales 336,821 474,968 650,176 973,326
Gas sales 152,735 199,261 379,883 604,996
NGL sales 12,837 20,338 26,434 35,297
Other income 7,821 7,337 17,388 18,782
Realised losses on oil derivative contracts (5,740) (73,043) (12,440) (125,908)
Put premiums on oil derivative instruments (2,730) (3,645) (6,330) (7,254)
Realised gains/(losses) on gas derivative contracts 103,191 (11,319) 194,140 (144,265)
Put premiums on gas derivative instruments (1,142) (16,471) (1,142) (17,389)
603,793 597,426 1,248,109 1,337,585
The majority of payment terms are on a specified monthly date, as detailed in
the initial contract. Otherwise, payment is due within 30 days of the invoice
date. No significant judgements have been made in determining the timing of
satisfaction of performance obligations, the transactions price and the
amounts allocated to performance obligations. Other income relates to tariff
income receivable in the year.
Revenue from two customers (30 June 2022: one customer) exceeds 10% of the
Group's consolidated revenue arising from hydrocarbon sales for the six months
ended 30 June 2023, representing $689.6 million and $216.1 million
respectively (six months ended 30 June 2022: $1,308.8 million).
Revenue from contracts with customers derives largely from customers within a
single geographical region, being the United Kingdom. Revenue from contracts
with customers out with the United Kingdom is immaterial and is therefore not
disclosed separately.
5. Cost of sales
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Movement in oil and gas inventory 18,709 (62,011) 57,546 (186,076)
(149,531) (126,211) (300,652) (263,180)
Operating costs
(1,273) (2,807) (3,165) (5,362)
Royalties
(10,534) (9,074) (20,953) (11,519)
Depreciation on right-of-use assets
(184,851) (143,313) (363,167) (285,898)
Depletion, depreciation and amortisation
(327,480) (343,416) (630,391) (752,035)
Royalty costs represent 3.34% of Stella and Harrier field revenue paid to the
original licence holders. Ithaca Energy holds a 100% interest in the Stella
and Harrier fields.
6. Other gains and losses
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Gain/(loss) on financial instruments 13,521 (12,295) 27,485 (19,131)
(26,103) (14,449) (1,725) (14,449)
Fair value losses on contingent consideration
(5,476) 5,325 (3,589) 6,018
Net foreign exchange
(694) - 50,068 -
Settlement of historic claim relating to an acquisition
(18,752) (21,419) 72,239 (27,562)
On 12 February 2023 the Group reached agreement on the settlement of a
historic claim relating to an acquisition. Under the terms of the agreement
Ithaca Energy received $50.1 million which was recognised in the condensed
consolidated financial statements in Q1 2023.
7. Net finance costs
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Bank interest and charges (12,165) (11,533) (28,964) (21,332)
Senior notes interest (14,024) (27,895) (27,894)
(14,024)
Loan fee amortisation (1,127) (2,254) (2,282)
(1,103)
Interest on lease liabilities (1,829) (1,635) (1,829)
(783)
Interest on related party loan (5,024) - (17,924)
-
Accretion (12,208) (37,912) (24,212)
(19,763)
Realised gains on interest derivative contracts 257 - 257
-
Interest income (253) 2,139 -
899
Other (1,865) - (1,865)
-
(46,939) (47,606) (96,521) (97,081)
There was no interest capitalised into qualifying assets in either the six
months to 30 June 2023 or the six months to 30 June 2022.
8. Earnings per share
The calculation of basic earnings per share is based on the profit after tax
and the weighted average number of ordinary shares in issue during the period.
Basic and diluted earnings per share are calculated as follows:
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Earnings for the period:
Earnings for the purpose of basic earnings per share 1,145 795,483 159,586 1,557,690
Effect of dilutive potential ordinary shares - - -
-
Earnings for the purpose of diluted earnings per share 1,145 795,483 159,586 1,557,690
Number of shares (million)
Weighted average number of ordinary shares for the purpose of basic earnings 1,006.6 1,005.2 1,006.6 1,005.2
per share
Dilutive potential ordinary shares 0.9 6.9 0.9
6.9
Weighted average number of ordinary shares for the purpose of diluted earnings 1,013.5 1,006.1 1,013.5 1,006.1
per share
Earnings per share (cents)
Basic 0.1 79.1 15.9 155.0
Diluted 79.1 15.7 154.8
0.1
9. Trade and other receivables
30 June 31 December
2023 2022
Current US$'000 US$'000
Trade receivables 41,350 31,906
Other receivables 47,901 14,210
Joint venture receivables 125,837 99,800
Accrued income 134,012 214,078
349,100 359,994
The Group regularly monitors all customer receivable balances outstanding in
excess of 90 days for expected credit losses (ECLs). The Group applies a
simplified approach in calculating ECLs as allowed under IFRS 9. Provision
rates are calculated based on estimates including the probability of default
by assessing counterparty credit ratings, the economic environment and the
Group's historical credit loss experience. Substantially all trade and other
receivables are current, being defined as less than 90 days, and as such no
ECLs have been recognised in the current or prior year as the ECL is
considered immaterial.
30 June 31 December
Non-current 2023 2022
US$'000 US$'000
Decommissioning reimbursement 171,551 162,710
30 June 31 December
2023 2022
Current US$'000 US$'000
Decommissioning reimbursement 24,115 38,115
The decommissioning reimbursement represents the equal and opposite of
decommissioning liabilities, net of tax, associated with the Heather and
Strathspey fields and relates to a contractual agreement as part of the CNSL
acquisition. As part of the terms of the CNSL acquisition, Chevron have the
obligation to provide the security and remain financially responsible for the
decommissioning obligations of CNSL in relation to these interests. As the
payment is virtually certain this has been accounted for under IAS 37 as a
reimbursement asset.
10. Exploration and evaluation assets
US$'000
At 1 January 2022 116,355
Additions 42,168
Acquisitions 706,558
Transfers to development and production assets (note 11) (75,005)
Write offs/relinquishments (14,303)
At 31 December 2022 and 1 January 2023 775,773
Additions 60,530
Write offs/relinquishments (1,334)
At 30 June 2023 834,969
10. Exploration and evaluation assets continued
Following completion of geotechnical evaluation activity, certain North Sea
licences were declared unsuccessful and certain prospects were declared
non-commercial. This resulted in the carrying value of these licences being
fully written off to nil with $1.3 million being expensed in the six months to
30 June 2023 (six months to 30 June 2022: $14.3 million).
The principal exploration and evaluation assets at 30 June 2023 and 31
December 2022 are Cambo and Rosebank, which formed part of the Siccar Point
Energy acquisition in 2022.
11. Property, plant and equipment
Right-of-use operating assets Development and production assets Other fixed assets
Total
US$'000 US$'000 US$'000 US$'000
Cost
At 1 January 2022 9,210 5,838,178 40,293 5,887,681
Additions 89,717 5,619 458,180
362,844
Acquisitions - - 1,115,023
1,115,023
Transfers from exploration and evaluation assets (note 10) - - 75,005
75,005
Change in decommissioning estimates - - (278,398)
(278,398)
At 31 December 2022 and 1 January 2023 98,927 7,112,652 45,912 7,257,491
Additions - 504 268,721
268,217
At 30 June 2023 98,927 7,380,869 46,416 7,526,212
Depletion, depreciation, amortisation and Impairment
At 1 January 2022 (5,429) (2,909,695) (13,824) (2,928,948)
Depletion, depreciation and amortisation charge for the year (37,438) (10,248) (662,947)
(615,261)
Impairment charge - - (30,700)
(30,700)
At 31 December 2022 and 1 January 2023 (42,867) (3,555,656) (24,072) (3,622,595)
Depletion, depreciation and amortisation charge for the period (20,953) (3,605) (384,120)
(359,562)
Impairment charge - - (328,426)
(328,426)
At 30 June 2023 (63,820) (4,243,644) (27,677) (4,335,141)
Net book value at 31 December 2022 56,060 3,556,996 21,840 3,634,896
Net book value at 30 June 2023 35,107 3,137,225 18,739 3,191,071
The transfers from exploration and evaluation assets to development and
production assets in the year to 31 December 2022 relates to the Abigail and
Jade South wells. At the point of transfer these assets were tested for
impairment and none was found.
Other fixed assets includes buildings, computer equipment, office equipment
and furniture and fittings.
As at 30 June 2023 the Group had capital commitments of $89.0 million (31
December 2022: $52.3 million). The key components at 30 June 2023 relate to
the Captain Enhanced Oil Recovery (EOR) project. At 31 December 2022, the
commitments related primarily to the Captain EOR project and drilling at the
Shaw field.
12. Taxation
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Current tax
Current corporation tax charge (21,382) - (31,695) -
Current EPL tax charge - (223,051)
(96,543)
Total current tax charge (117,925) - (254,746) -
Deferred tax
Adjustment in respect of prior period 371 - (16,357) (1)
Group tax credit/(charge) in consolidated statement of profit or loss (62,620) 183,123 (162,112)
242,735
Group tax (charge)/credit in consolidated statement of other comprehensive (75,966) (62,292) 106,833
income
135
Total deferred tax credit/(charge) 243,241 (138,586) 104,474 (55,280)
Deferred PRT charge in consolidated statement of profit or loss (21,542) (1,175) (21,542)
(1,175)
Total tax credit/(charge) through consolidated statement of profit or loss 124,006 (84,162) (89,155) (183,655)
The tax on the Group's profit before tax differs from the theoretical amount
that would arise using the 40% statutory rate of tax applicable for UK ring
fence oil and gas activities as follows:
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Accounting profit/(loss) before tax (122,861) 879,645 248,741 1,741,345
At tax rate of 40% (2022: 40%) 49,144 (351,858) (99,497) (696,538)
Non-deductible (expense)/income 259,885 (6,085) 484,888
(24,158)
Financing costs not allowed for Supplementary Charge (507) (530) (1,015)
(133)
Ring Fence Expenditure Supplement 17,490 53,076 34,888
25,727
Deferred tax effect of investment allowance 3,719 18,886 7,253
10,859
Prior year adjustment (1) (16,357) (1)
371
Deferred tax on EPL - 189,389 -
160,887
Current tax on EPL - (223,051) -
(96,543)
Net deferred tax PRT (12,926) (705) (12,926)
(705)
Share Schemes (1,059) - (1,059) -
Unrecognised tax losses (384) 36 (3,222) (204)
Total tax credit/(charge) recorded in the consolidated statement of profit or 124,006 (84,162) (89,155) (183,655)
loss
12. Taxation continued
The Company is UK tax resident. The effective rate of tax applicable for UK
ring fence oil and gas activities in 2023, was 40% (excluding the Energy
Profits Levy ("EPL") of 35%) (2022: 40% excluding EPL of 25%) consisting of a
Ring Fence Corporation Tax rate of 30% and the supplementary charge of 10%.
Items affecting the tax charge include a 10% uplift on ring fence losses, Ring
Fence Expenditure Supplement increasing the losses available to offset future
profits subject to Ring Fence Corporation Tax and Supplementary Charge. In
addition, investment allowance, a 62.5% uplift on capital expenditure, is
available reducing the profits subject to the supplementary charge only.
Petroleum Revenue Tax (PRT) is applied at 0% on certain oil and gas fields in
the UK, however adjustments to recognise deferred PRT assets are made to
reflect updated expectations of reversal against profits subject to the 0% PRT
rate. The EPL was enacted on 14 July 2022 with further changes announced on 17
November 2022 such that the Levy was increased to 35% from 1 January 2023
until 31 March 2028, increasing the effective UK ring fenced oil and gas tax
rate to 75%.
Deferred tax at 30 June 2023 and 31 December 2022 relates to the following:
30 June 31 December
2023 2022
US$'000 US$'000
Deferred corporation tax liability (1,958,159) (2,258,813)
Deferred corporation tax asset 2,433,327 2,629,548
Deferred PRT asset 20,547 21,721
Net deferred tax asset 495,715 392,456
Deferred tax assets primarily relate to decommissioning liabilities, brought
forward tax losses, and accumulated losses and profits related to derivative
contracts. Deferred tax liabilities primarily relate to accelerated capital
allowances on property, plant and equipment and accumulated losses and profits
related to derivative contracts.
The gross movement on the deferred tax account in the balance sheet is as
follows:
30 June 31 December
2023 2022
US$'000 US$'000
At 1 January 392,456 220,918
Profit or loss credit/(charge) 165,551 (1,024,889)
Other comprehensive income charge (62,292) (200,455)
Business combinations - 1,396,882
At end of period 495,715 392,456
12. Taxation continued
The net movement on the deferred tax account through the consolidated
statement of profit or loss and consolidated statement of comprehensive income
relates to the following:
6 months ended 6 months ended
30 June 30 June
2023 2022
US$'000 US$'000
Accelerated capital allowances 327,032 23,129
Tax losses (146,427) (212,316)
Abandonment provision 30,783 5,941
Deferred PRT 470 8,617
Hedging (86,672) 119,349
Share Schemes 3,374 -
Investment Allowances (24,086) -
Net movement in the period 104,474 (55,280)
Deferred corporation tax on
Accelerated tax
deferred PRT depreciation Total
Gross deferred corporation tax liabilities US$000 US$000 US$000
At 1 January 2022 (12,861) (675,279) (688,140)
Prior year adjustment - (4,347) (4,347)
Reclassification of decommissioning assets - (436,771) (436,771)
Business combinations - (647,743) (647,743)
Origination and reversal of temporary differences 4,173 (485,985) (481,812)
At 31 December 2022 (8,688) (2,250,125) (2,258,813)
Prior year adjustment - (7,307) (7,307)
Origination and reversal of temporary differences 470 307,493 307,963
At 30 June 2023 (8,218) (1,949,939) (1,958,157)
12. Taxation continued
Shares schemes Abandonment
provision Tax losses Hedges Total
Gross deferred corporation tax assets US$000 US$000 US$000 US$000 US$000
At 1 January 2022 - 197,666 500,282 178,956 876,904
Prior year adjustment - 3,706 - 3,706
-
Reclassification of decommissioning asset 436,772 - - 436,772
-
Business combinations 156,212 1,858,706 38,406 2,053,324
-
Origination and reversal of temporary differences (124,598) (390,520) (226,040) (741,158)
-
At 31 December 2022 - 666,052 1,972,174 (8,678) 2,629,548
Prior year adjustment - (12,141) 2,721 (9,243)
177
Origination and reversal of temporary differences 30,783 (134,286) (86,672) (186,977)
3,198
At 30 June 2023 3,375 696,835 1,825,747 (92,629) 2,433,328
Total
Deferred PRT asset $000
At 1 January 2022 32,154
Origination and reversal of temporary differences (10,433)
At 31 December 2022 21,721
Origination and reversal of temporary differences (1,175)
At 30 June 2023 20,546
The carrying value of the net deferred corporation tax asset at 30 June 2023
of $475 million (31 December 2022: $371 million) and the deferred PRT asset of
$21 million (31 December 2022: $21 million) are supported by estimates of the
Group's future taxable income, based on the same price and cost assumptions as
used for impairment testing.
An EPL or "the Levy" was enacted on 14 July 2022 applying a Levy of 25% to the
profits of oil and gas companies until 31 December 2025 or earlier if prices
return to normalised levels. On 17 November 2022, the Levy was increased to
35% and extended to 31 March 2028 regardless of prices. The Levy is charged
upon oil and gas profits calculated on the same basis as Ring Fence
Corporation Tax (RFCT), however excludes relief for decommissioning and
finance costs. RFCT losses and investment allowance are not available to
offset the EPL. On 9 June 2023 an Energy Security Investment Mechanism price
floor was announced which would remove the EPL if both average oil and gas
prices fall to, or below, $71.40 per barrel for oil and £0.54 per therm for
gas, for two consecutive quarters. It is not currently forecast that this
price floor will be met for both oil and gas prices and therefore there is no
impact on the tax values.
The Group's deferred tax assets are recognised to the extent that taxable
profits are expected to arise in the future against which tax losses and
allowances in the UK can be utilised, including as a result of Group
re-organisations and asset transfers. In accordance with IAS 12 Income Taxes,
the Group assesses the recoverability of its deferred tax assets at each
period end.
On 20 June 2023, Finance (No. 2) Act 2023 was substantially enacted in the UK,
introducing a global minimum effective tax rate of 15%. The legislation
implements a domestic top-up tax and a multinational top-up tax, effective for
accounting periods starting on or after 31 December 2023. The Group has
applied the exception under IAS 12 to recognising and disclosing information
about deferred tax assets and liabilities related to top-up income taxes,
therefore there is no impact on the tax values reported.
13. Borrowings
30 June 31 December
2023 2022
US$'000 US$'000
Non-current
RBL facility (250,000) (600,000)
Senior unsecured notes (625,000) (625,000)
Unamortised long-term bank fees 6,073 7,591
Unamortised long-term senior notes fees 2,943 3,678
Total debt (865,984) (1,213,731)
Accrued interest on borrowings is included within accruals.
Adjusted net debt, which does not include lease liabilities, is set out in
Non-GAAP measures on page 46.
Details of covenants under the RBL facility are set out in note 20 to the 2022
Annual Report and Accounts.
The Group was in compliance with all financial covenants of the RBL facility
in all periods presented.
14. Decommissioning liabilities
30 June 31 December
2023 2022
US$'000 US$'000
Balance at 1 January (1,720,540) (1,641,489)
Business combination additions - (390,530)
Accretion (36,485) (52,592)
Additions and revisions to estimates (97,238) 298,564
Decommissioning provision utilised 56,772 65,507
Balance, end of period (1,797,491) (1,720,540)
Current
Balance, beginning of period (146,829) (94,640)
Balance, end of period (86,929) (146,829)
Non-current
Balance, beginning of period (1,573,711) (1,546,849)
Balance, end of period (1,710,562) (1,573,711)
The total future decommissioning liability represents the estimated cost to
decommission, in situ or by removal, the Group's net ownership interest in all
wells, infrastructure and facilities, based upon forecast timing in future
periods. The Group uses a discount rate of 4.25% (31 December 2022: 4.25%) and
an inflation rate of 2.0% (31 December 2022: 2.0%) over the varying lives of
the assets to calculate the present value of the decommissioning liabilities.
Revisions to estimates in the six months ended 30 June 2023 were due to
changes in cost estimates and in the year ended 31 December 2022 were due to
changes in both cost estimates and discount rate assumptions. Further details
including a sensitivity on the impact of a change in the discount rate are set
out in the 2022 Annual Report and Accounts.
The estimated decommissioning spend in H2 2023 and H1 2024 of $87 million has
been treated as a current liability as at 30 June 2023 (31 December 2022:
estimated 2023 spend of $147 million). The Group currently expects to
incur decommissioning costs over the next 40 years.
15. Contingent and deferred consideration
30 June 31 December
2023 2022
Current US$'000 US$'000
Contingent consideration (32,220) (101,559)
Petrofac deferred consideration (6,186) (6,121)
(38,406) (107,680)
30 June 31 December
2023 2022
Non-current US$'000 US$'000
Contingent consideration (229,319) (157,337)
Deferred consideration (62,440) (61,783)
(291,759) (219,120)
Movement in contingent consideration and deferred consideration is as follows:
30 June 31 December
2023 2022
US$'000 US$'000
At beginning of period (326,800) (75,090)
Business combinations - (304,846)
Utilisation 3,568 66,132
Reversal - 1,100
Accretion (5,208) (9,801)
Changes in fair value (1,725) (4,295)
At end of period (330,165) (326,800)
Cash outflows in the six months to 30 June 2023 of $3.6 million are in respect
of MOGL deferred consideration and the cash outflows in the year to 31
December 2022 of $66.1 million are in relation to the consideration payable on
Petrofac GSA transaction and three quarterly payments in consideration to the
MOGL oil price trigger.
Details of movements in contingent and deferred consideration in the year to
31 December 2022 and sensitivities thereon are set out in note 25 of the
Group's 2022 Annual Report and Accounts.
16. Financial instruments
To estimate the fair value of financial instruments, the Group uses quoted
market prices when available, or industry accepted third-party models and
valuation methodologies that utilise observable market data. In addition to
market information, the Group incorporates transaction specific details that
market participants would utilise in a fair value measurement, including the
impact of non-performance risk. The Group characterises inputs used in
determining fair value using a hierarchy that prioritises inputs depending on
the degree to which they are observable. However, these fair value estimates
may not necessarily be indicative of the amounts that could be realised or
settled in a current market transaction. The three levels of the fair value
hierarchy are as follows:
• Level 1 - inputs represent quoted prices in active markets for
identical assets or liabilities (for example, exchange-traded commodity
derivatives). Active markets are those in which transactions occur in
sufficient frequency and volume to provide pricing information on an ongoing
basis.
• Level 2 - inputs other than quoted prices included within Level 1
that are observable, either directly or indirectly, as of the reporting date.
Level 2 valuations are based on inputs, including quoted forward prices for
commodities, market interest rates, and volatility factors, which can be
observed or corroborated in the marketplace. The Group obtains information
from sources such as the New York Mercantile Exchange and independent price
publications.
• Level 3 - inputs that are less observable, unavailable or where
the observable data does not support the majority of the instrument's fair
value.
In forming estimates, the Group utilises the most observable inputs available
for valuation purposes. If a fair value measurement reflects inputs of
different levels within the hierarchy, the measurement is categorised based
upon the lowest level of input that is significant to the fair value
measurement. The valuation of over-the-counter financial swaps and collars is
based on similar transactions observable in active markets or industry
standard models that primarily rely on market observable inputs. Substantially
all of the assumptions for industry standard models are observable in active
markets throughout the full term of the instrument. These are categorised as
Level 2.
Gains or losses on financial instruments, that are not hedge accounted for,
are recorded through the 'other gains and losses' line in the consolidated
statement of profit or loss. Valuation policies and procedures and
sensitivities on the fair values of financial instruments are set out in the
2022 Annual Report and Accounts.
All of the Group's assets are pledged as security against borrowings.
The accounting classification of each category of financial instruments and
their carrying amounts as at 30 June 2023 are set out below:
Mandatorily measured at fair value through Derivatives designated in hedge
Measured at Total carrying
amortised cost profit or loss relationships amount
$'000 $'000 $'000 $'000
Financial assets
Cash and cash equivalents 176,324 - - 176,324
Trade and other receivables 349,100 - - 349,100
Derivative financial instruments - 3,710 153,147 156,857
Financial liabilities
Borrowings (865,984) - - (865,984)
Trade and other payables (452,364) - - (452,364)
Lease liability (42,633) - - (42,633)
Contingent and deferred consideration (68,626) (261,539) - (330,165)
Derivative financial instruments - (20,382) (12,973) (33,355)
(1,042,220)
16. Financial instruments continued
The accounting classification of each category of financial instruments and
their carrying amounts as at 31 December 2022 are set out below:
Mandatorily measured at fair value through Derivatives designated in hedge
Measured at Total carrying
amortised cost profit or loss relationships amount
$'000 $'000 $'000 $'000
Financial assets
Cash and cash equivalents 253,822 - - 253,822
Trade and other receivables 359,994 - - 359,994
Derivative financial instruments - 7,125 164,924 172,049
Financial liabilities
Borrowings (1,213,731) - - (1,213,731)
Trade and other payables (618,460) - - (618,460)
Lease liability (58,858) - - (58,858)
Contingent and deferred consideration (67,904) (258,896) - (326,800)
Derivative financial instruments - (57,546) (106,563) (164,109)
(1,596,093)
The following table presents the Group's material financial instruments
measured at fair value for each hierarchy level as of 30 June 2023:
Level 1 US$'000 Level 2 US$'000 Level 3 US$'000 Total fair value
US$'000
Contingent consideration - (46,067) (215,472) (261,539)
Derivative financial instrument asset - 156,857 - 156,857
Derivative financial instrument liability - (33,354) - (33,354)
The following table presents the Group's material financial instruments
measured at fair value for each hierarchy level as of 31 December 2022:
Level 1 US$'000 Level 2 US$'000 Level 3 US$'000 Total fair value
US$'000
Contingent consideration - (35,650) (223,246) (258,896)
Derivative financial instrument asset - 172,049 - 172,049
Derivative financial instrument liability - (164,109) - (164,109)
16. Financial instruments continued
The table below presents the total gain/(loss) on financial instruments that
has been disclosed through the statement of profit or loss:
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
US$'000 US$'000 US$'000 US$'000
Revaluation of forex forward contracts 3,540 (14,862) 5,000 (19,131)
Revaluation of interest rate swaps (891) - (2,535) -
Revaluation of commodity hedges 14,341 2,110 36,195 -
16,990 (12,752) 38,660 (19,131)
Realised loss on forex contracts (885) - (2,967) -
Realised gain on interest rate swaps 2,324 - 3,850 -
Realised loss on commodity hedges (4,908) 457 (12,058) -
Total gain/(loss) on financial instruments 13,521 (12,295) 27,485 (19,131)
Hedging reserve
The table below presents the total gain/(loss) on financial instruments that
has been disclosed through the statement of comprehensive income:
Three months ended 30 June Six
months ended 30 June
2023 2022 2023 2022
Hedging reserve US$'000 US$'000 US$'000 US$'000
Revaluation gain/(loss) on derivative contracts 352 197,212 83,813 (249,485)
Realised gain/(loss) on derivative contracts 77,106 (111,517) 157,755 (312,156)
Amounts recycled to revenue (81,613) 84,362 (165,862) 270,173
Amounts recycled to revenue - oil put premiums 2,730 3,645 6,330 7,254
Amounts recycled to revenue - gas put premiums 1,142 16,471 1,142 17,389
Amounts recycled to finance costs - interest put premiums - (257) - (257)
Total gain/(loss) on financial instruments (283) 189,916 83,178 (267,082)
17. Derivative financial instruments
30 June 31 December
2023 2022
US$'000 US$'000
Oil swaps - cash flow hedge 7,396 (28,685)
Oil swaps - non-cash flow hedge (15,027)
(2,891)
Oil collars - cash flow hedge (21,983)
2,382
Gas swaps - cash flow hedge 19,797
36,590
Gas swaps - non-cash flow hedge (29,271)
(10,118)
Gas puts - cash flow hedge 9,746
8,974
Gas collars - cash flow hedge 79,489
84,832
Interest rate swaps - non-cash flow hedge 7,125
3,698
FX forwards - non-cash flow hedge (13,250)
(7,360)
123,503 7,941
30 June 31 December
Maturity analysis of derivative financial instruments 2023 2022
US$'000 US$'000
Non-current assets 9,668 21,191
Current assets 150,858
147,189
Non-current liabilities (27,440)
(10,071)
Current liabilities (136,668)
(23,283)
123,503 7,941
Judgements and estimates applied in the valuation of derivative instruments
can be found in note 3 to the 2022 Annual Report and Accounts.
Derivative financial instruments that are with counterparties included within
the RBL facility are subject to Master Netting Agreements.
18. Related party transactions
Gilad Myerson and Alan Bruce, who are Directors of Ithaca Energy plc, are
participants in the Company's Share Incentive Plan. On 6 June 2023 both Mr
Myerson and Mr Bruce purchased 202 ordinary shares of £0.01 each as a
deduction from their respective salaries, with the Company matching 101
ordinary shares of £0.01 each, to each participant at a market rate of
£1.48015 per share.
19. Subsequent events
On 11 July 2023, the Group announced that it had signed a Sale and Purchase
Agreement to acquire the 40% stake in the Fotla Discovery that it doesn't
already own and three exploration licences from Spirit Energy Resources
Limited. The agreement, which is subject, amongst other things, to regulatory
approval, will bring the Group's working interest in Fotla to 100% providing
Ithaca Energy with full control over pre-final investment decision work and
timing. The total transaction consideration of up to $14.6 million, comprises
two capped contingent payments of which approximately two-thirds is payable on
final investment decision and one-third on first production.
On 26 July 2023, Ithaca Energy announced successful well test results at the
K2 prospect and as a result the Group, together with its joint venture
partner, have decided to perform an appraisal sidetrack following the positive
results in the main bore. The Group holds a 50% working interest in this
licence with the remaining 50% working interest held by Dana Petroleum.
On 31 July 2023, the Group completed a new 5-year $100m unsecured loan
agreement with bp at a commercial interest rate. Separately, a new offtake
agreement was also completed with bp on that date which runs concurrently with
the loan agreement.
Non-GAAP measures
The Group uses certain performance metrics that are not specifically defined
under International Financial Reporting Standards or other generally accepted
accounting principles. These non-GAAP measures which are presented
in the H1 2023 condensed consolidated financial statements are defined below:
Adjusted EBITDAX: earnings before interest, tax, put premiums on oil and gas
derivative instruments, revaluation of forex forward contracts, revaluation of
commodity hedges, depletion depreciation and amortisation, impairment charges
or reversals, exploration and evaluation expenditure, fair value
gains/(losses) on contingent consideration, gain on bargain purchase and
transaction costs. This measure is considered as an indicator of underlying
financial performance as it excludes accounting (e.g. depreciation) and
financing deductions. It is also commonly used by stakeholders as a comparable
metric of core profitability. Adjusted EBITDAX is reconciled to profit after
tax as follows:
H1 2023 H1 2022
$m $m
Profit after tax 159.6 1,557.7
Taxation charge 89.2 183.7
Gain on bargain purchase - (1,324.3)
Depletion, depreciation and amortisation 384.1 297.4
Impairment charge 328.4 7.6
Net finance costs 96.5 97.1
Oil and gas put premiums 7.5 24.8
Revaluation of foreign exchange forward contracts (5.0) 18.7
Revaluation of commodity hedges (33.6) -
Exploration and evaluation expenses 1.3 9.5
Fair value loss on contingent consideration 1.8 14.4
Transaction costs - 20.8
Historic claim relating to an acquisition (50.1) -
Adjusted EBITDAX 979.7 907.4
Adjusted net income: Profit after tax excluding non-cash bargain purchase
credits, material impairment charges or reversals and the tax effect of these
items where applicable. Adjusted net income, which is presented as it
eliminates items which distort period-on-period comparisons, is reconciled to H1 2023 H1 2022
profit after tax as follows:
$m $m
Profit after tax 159.6 1,557.7
Gain on bargain purchase - (1,324.3)
Impairment charge 328.4 -
Tax credit on impairment charge (234.8) -
Adjusted net income 253.2 233.4
Adjusted EPS: Adjusted net income divided by the average number of shares for
the period of 1,006.6 million (H1 2022: 1,005.2
million):
H1 2023
$m
H1 2022
$m
Non-GAAP measures continued
Adjusted net debt: consists of amounts outstanding under RBL facility and
senior secured loan notes less cash and cash equivalents excluding lease
liabilities and intragroup debt arrangements or liabilities represented by
letters of credit and surety bonds. Adjusted net debt comprises:
30 June 30 June
2023 2022
$m $m
RBL drawn facility (250.0) (750.0)
Senior unsecured notes (625.0) (825.0)
Cash and cash equivalents 176.3 160.4
Adjusted net debt (698.7) (1,414.6)
Leverage ratio: adjusted net debt at the end of the period divided by adjusted
EBITDAX for the preceding 12 months. The calculations are as follows:
30 June 30 June
2023 2022
Net debt ($m) 698.7 1,414.6
Adjusted EBITDAX ($m) 1,988.4 1,562.7
Leverage ratio 0.35x 0.91x
Available liquidity: the sum of cash and cash equivalents on the balance sheet
and the undrawn amounts available to the Group using existing approved
third-party facilities less restricted cash. Available liquidity comprises:
30 June 30 June
2023 2022
$m $m
Cash and cash equivalents 176.3 160.4
Restricted cash - (15.0)
Undrawn borrowing facilities 615.0 175.0
Available liquidity 791.3 320.4
Non-GAAP measures continued
Group free cash flow: net cash flow from operating activities less cash used
in investing activities, adding back acquisition of subsidiaries net of cash
acquired, less bank interest and interest rate swaps. Group free cash flow
reconciles to net cash flow from operating activities as follows:
H1 2023 H1 2022
$m $m
Net cash flow from operating activities 691.0 989.0
Net cash used in investing activities (221.6) (1,203.7)
Add back acquisitions - 957.5
Bank interest and charges (49.2) (54.5)
Group free cash flow 420.2 688.3
Unit operating expenditure: operating costs (excluding over/underlift)
including tariff expense less tariff income and tanker costs divided by net
production for the period. Operating costs for this calculation reconcile to
note 5 as follows:
H1 2023 H1 2022
$m $m
Operating costs per note 5 300.7 263.2
Less Tanker costs (included within operating costs in note 5) (11.6) (10.2)
Less Tariff income (included within other income in note 4) (17.0) (18.6)
Operating costs used to calculate unit operating expenditure 272.1 234.4
DD&A rate per barrel: depletion, depreciation and amortisation charge for
the period divided by net production for the year.
Other key performance indicators
Total production: historic production boe/d include volumes from date of
acquisition of MOGL on 4 February 2022 and Siccar Point Energy and Summit on
30 June 2022.
Tier 1 process safety events: process safety incidents as defined by API 465
Process Safety-Recommended practise on Key Performance Indicators.
Serious injury and fatality frequency: the number of serious injuries
resulting in permanent impairment, as defined by IOGP, per million hours
worked.
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