REG - Tullow Oil PLC Tullow Oil PLC - FP Tullow Oil PLC - NP - Half Year Results
14/09/2022 07:00
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RNS Number : 3569Z Tullow Oil PLC 14 September 2022
Tullow oil PLC - 2022 Half Year Results
14 September 2022 - Tullow Oil (Tullow) announces its Half Year results for
the six months ended 30 June 2022. Tullow will host a webcast presentation at
9am this morning, details of which can be found on the last page of this
announcement and online at www.tullowoil.com (http://www.tullowoil.com)
Rahul Dhir, Chief Executive Officer, Tullow Oil plc, commented today:
"The turnaround of Tullow has gained momentum in the first half of 2022, with
solid production from our West African portfolio driving stronger financial
performance. We added material, unhedged production in Ghana through the
pre-emption of the Kosmos-Oxy deal and took over the Operations &
Maintenance (O&M) of the Jubilee FPSO to ensure that we can sustain the
good operating performance and deliver further operating cost improvements.
Our drilling programme has been very efficient and at current performance
levels we will be able to deliver our planned programme of wells through next
year with just one rig.
The Board of Tullow remains fully committed to the merger with Capricorn which
continues to be recommended by both the Tullow and Capricorn Boards on the
current terms. We firmly believe that the proposed merger has the potential
for material value creation by implementing a combined business plan which
accelerates investment in key projects and delivers very significant
synergies.
We have a high quality, opportunity rich portfolio, a clear and disciplined
growth strategy and an improving balance sheet. The Board looks to the future
with confidence, and I look forward to sharing further details at a capital
markets day."
2022 First half results summary
· Group working interest production for the first half of 2022 averaged
60.9 kboepd, in line with expectations.
· Ghanaian drilling programme ahead of schedule, having completed two
previously drilled wells and drilled and completed another three wells. A
further six wells are expected to be drilled and two of these completed by
year-end.
· Operational delivery: continued strong FPSO uptime (Jubilee c.95% and
TEN c.99%), gas export (averaging c.90 mmscfd) and water injection (Jubilee
c.170 kbwpd and TEN c.65 kbwpd).
· Reserves of 242 million barrels as of 30 June, valued at c.$4.7
billion after hedging (c.$5.3 billion before hedging) 1 (#_ftn1) .
· Revenue of $846 million with realised oil price of $87/bbl after
hedging; gross profit of $620 million; profit after tax of $264 million;
underlying operating cash flow of $165 million.
· First half free cash flow of $(205) million (negative), which
includes an arbitration payment of $76 million (outflow), Uganda FID payment
of $75 million (inflow) and Ghana pre-emption consideration of $126 million
(outflow), but excludes the benefit of over $200 million revenue relating to
two Ghana liftings, which took place in early June but for which cash was
received shortly after 30 June 2022, on 1 and 5 July respectively.
· Capital investment in the first half of 2022 was c.$156 million plus
decommissioning costs of c.$29 million.
· Net debt at 30 June 2022 of c.$2.3 billion; Gearing reduced to 1.9x
net debt/EBITDAX; liquidity headroom and free cash of $0.6 billion.
· Pre-emption of Deep Water Tano component of Kosmos Energy/Occidental
Petroleum Ghana transaction successfully completed.
· Announcement of recommended all-share combination of Tullow Oil plc
and Capricorn Energy plc.
1 Note: The NPV10 valuation is calculated in accordance with the terms of
the indenture for the issuance of 10.25% Senior Secured Notes due 2026 by
Tullow Oil plc ("Tullow") dated 17 May 2021 (the "Indenture"). Tullow has
agreed with the Takeover Panel that an independent valuation report prepared
in accordance with Rule 29 of the City Code on Takeovers and Mergers (the
"Takeover Code") will be included in the scheme document when published by
Capricorn Energy plc in connection with its recommended merger with Tullow
(the "Merger"). The publication of this independent reserves report in
connection with the Merger, or any other independent reserves report required
by the Takeover Code, should not be construed as a commitment to publish any
such report in the future.
Key financial results
1H 2022 1H 2021
Sales revenue ($m) 846 727
Gross profit ($m) 620 321
Underlying cash operating cost per barrel ($/bbl) 13.0 12.9
Profit after tax ($m) 264 93
Free cash flow(1) ($m) (205) 86
Net debt(1) ($m) 2,336 2,290
Gearing(1) (times) 1.9 2.6
(1) Excludes the benefit of over $200 million revenue relating to two Ghana
liftings which took place in early June but for which cash was received
shortly after 30 June 2022, on 1 and 5 July respectively.
2022 Guidance
· Group working interest production narrowed to 60-64 kboepd.
· Full year capital investment and decommissioning spend of c.$380
million and c.$100 million, respectively. Increase of $30 million associated
with additional equity following pre-emption in Ghana.
· Full year underlying operating cashflow expected to be c.$950
million, assuming an average oil price of $95/bbl. Post all costs, Tullow
forecasts full year free cash flow of c.$200 million and gearing of <1.5x
(net debt/EBITDAX) by year-end.
· Free cash flow guidance includes the c.$75 million contingent
consideration in relation to Tullow's sale of its assets in Uganda to
TotalEnergies, a payment of c.$76 million in relation to the arbitration award
in favour of HiTec Vision regarding the purchase of Spring Energy in 2013 and
a c.$126 million payment for the completion of the pre-emption related to the
sale of Occidental Petroleum's interests in the Jubilee and TEN fields in
Ghana to Kosmos Energy.
MERGER WITH CAPRICORN ENERGY
On 1 June 2022 Tullow announced that it had reached agreement with Capricorn
Energy on the terms of an all-share merger to create a leading African energy
company with a material and diversified asset base and a portfolio of
investment opportunities delivering visible production growth. This
recommended merger will enable the new company to develop and implement a new
business plan that accelerates the development of new, material opportunities,
realise meaningful cost synergies and deliver a combined group with robust
cash generation and a resilient balance sheet. The combined group will also
have a sustainable capital returns programme and a deep commitment to
environmental stewardship, social investment, development of local content and
its national workforces.
Tullow expects to host a Capital Markets Day for investors and issue a
circular and prospectus in connection with the recommended merger in the
fourth quarter, ahead of a shareholder vote, followed by completion of the
transaction before the end of the year.
ESG
Net Zero 2030
Tullow is committed to becoming a Net Zero Company by 2030 on its Scope 1 and
2 emissions. This will be achieved through a number of decarbonising
activities to eliminate flaring on its operated assets in Ghana, working
closely with our partners to eliminate flaring on our non-operated assets, and
pursuing a nature-based carbon removal programme to off-set hard to abate
emissions.
Over the next few years, Tullow has defined plans to reduce its carbon
emissions from its operations through an increase in the gas handling capacity
on Jubilee and process modifications on TEN. These investments are included in
the Group's Business Plan and will put the Group on track to eliminate routine
flaring in Ghana by 2025. Project Oil Kenya will align with Tullow's Net Zero
2030 target through limiting carbon emissions and offsetting any hard to abate
emissions. Through our Net Zero Task Force, Tullow also continues to track
progress on initiatives being delivered, and funded, by non-operating
partners.
To offset the residual hard-to-abate carbon emissions, progress continues to
be made in identifying nature-based carbon removal projects. A Feasibility
Study has been completed, identifying a significant scale opportunity covering
the Western Transitional Zone in Ghana. Tullow is in the process of finalising
a Letter of Intent with the Forestry Commission, detailing key activities and
information requirements to inform a Final Investment Decision (FID).
Operational UPDATE
Production
Group working interest production averaged 60.9 kboepd in the first half of
2022, in line with expectations. Full year production guidance for 2022 has
been narrowed from 59-65 kboepd to 60-64 kboepd.
Group average working interest production 1H 2022 actual (kboepd) FY 2022 guidance (kboepd)
Ghana 43.3 45
Jubilee 30.8 32
TEN 12.5 13
Non-operated portfolio 17.6 17
Total production 60.9 60-64
Ghana
The ongoing drilling programme that started in April 2021 has delivered eight
new wells, six at Jubilee and two at TEN, at an average cost of c.$50 million
per well (more than 10% below the average expected cost for these wells) and
ahead of schedule. In addition, two existing wells have been completed, one at
Jubilee (J12-WI) and one at TEN (En16-WI).
The first of the two strategic riser base wells (Nt10-P) was drilled to define
the extent of the Ntomme reservoir and found good quality reservoir sands, but
was water bearing. The second well (Nt11-P) is planned to target a different
objective later this year and will help define future drilling and
infrastructure plans for the TEN Enhancement Project. The rig is currently
drilling and completing a producer well on Enyenra (En21-P), before moving
across to Nt11-P.
The drill programme is ahead of schedule. If the current pace of drilling
continues, the next phase of drilling at Jubilee, which includes wells to be
tied into Jubilee South East infrastructure, is expected to be accelerated
into the fourth quarter of 2022. At current performance levels, we will be
able to deliver the planned programme of wells through next year with one rig.
Accordingly, the joint venture partners have agreed to defer a decision
regarding a second rig in Ghana.
Gross production from the Jubilee field averaged c.82.4 kbopd (net: c.30.8
kbopd) in the first half of the year, representing an increase of more than
15% compared to the first half of 2021. This is due to good well and
operational performance, which included the successful completion of the
planned, biennial maintenance shutdown of the Jubilee FPSO in May. Full year
net production guidance for Jubilee is 32kbopd. Gross production from the TEN
field averaged c.24.3 kbopd (net: c.12.5 kbopd) in the first half of the year,
in line with expectations. Full year net production guidance for TEN is
13kbopd, with the expectation of an increase in production rates when the
En21-P well comes onstream in the fourth quarter.
On the Jubilee FPSO, a handover of Operations & Maintenance (O&M) from
the O&M Contractor to Tullow was successfully completed at the end of
June. This transition will allow Tullow to deliver sustained FPSO safety and
reliability performance for the long term, as well as help deliver planned
reductions in the operating cost base and emissions.
Non-operated portfolio
Net production from the non-operated portfolio averaged c.17.6 kboepd in the
first half of 2022, in line with expectations. Full year net production
guidance for the non-operated portfolio is c.17 kboepd.
Production from Gabon averaged c.15.5 kbopd in the first half of 2022, with
Simba being the highest contributor. A long-term appraisal well test at the
Tchatamba field is underway and expected to see first oil in September 2022.
Infill drilling campaigns continue at the Ezanga Complex and Oba field.
Production from Côte d'Ivoire averaged c.2.1 kboepd in the first half of
2022. A 45 day shutdown of the Espoir FPSO is now planned from October 2022,
in which cargo tank maintenance and remediation work, which is required for
vessel class certification, will be carried out. Tullow continues to engage
with the operator, CNR International, to define the appropriate longer-term
course of action for the FPSO.
Decommissioning
The Group's operated and non-operated decommissioning programmes in the UK and
Mauritania are ongoing. The majority of operational work is expected to be
completed by the end of 2025, with environmental and monitoring surveys to
continue from 2026. The expected remaining UK and Mauritania decommissioning
exposure over 2022-26 is c.$145 million, with c.$100 million forecasted in
2022. The final exposure may vary depending on the final required scope and
work programmes agreed across the various projects.
Tullow expects to pay c.$30 million per annum for the decommissioning of
producing assets in Ghana and parts of the non-operated producing portfolio.
Kenya
A process to secure a strategic partner for the development project in Kenya
is ongoing and Tullow is confident that substantial progress will be made
before the end of the year. Following the recent elections, Tullow and its
joint venture partners will work with the new government to progress the
project which has the potential to make a significant contribution to the
Kenyan economy through taxation, revenue sharing, employment and local
content.
Exploration
All of the Group's exploration activity is guided by an overlay of rigorous
cost discipline. In Tullow's core area of West Africa, the exploration team is
focused on maturing near-field and infrastructure-led exploration (ILX)
opportunities around existing producing fields, to unlock additional value
from the Group's asset base.
In Côte d'Ivoire, Tullow, together with its JV Partner PetroCi, has elected
to proceed into the second exploration phase in Block CI-524. This block
presents a unique opportunity to realise operational synergies during the
exploration phase and in the event of discoveries due to Tullow's deep
understanding of the area and its proximity to the Group's producing fields.
In Gabon, focus is on strengthening the prospective resource base within the
Simba licence where several low-risk and compelling investment options
adjacent to infrastructure have been identified and will be considered for
future drilling programmes.
Tullow also continues to focus on unlocking value from its prospective
resource base in the emerging basins of Guyana and Argentina, while seeking to
mitigate capital exposure from historical work commitments in Argentina of
c.$25 million through farm-down. In Argentina a two year extension has been
granted in Block MLO-122.
Operational activity in the first half of 2022 included the drilling of the
Beebei-Potaro exploration well in the Repsol operated Kanuku Block offshore
Guyana. This commitment well encountered good quality reservoir in the primary
and secondary targets, but both targets were water bearing and the well has
been plugged and abandoned. Tullow is integrating the well results into its
regional subsurface models and is working with its joint venture partners
before deciding on next steps.
During the first half of 2022, the Group has written off exploration costs of
$87 million (1H 2021: $49 million) which are predominantly driven by
write-offs resulting from the Beebei Potaro well.
FINANCE REVIEW
Financial summary 1H 2022 1H 2021
Working interest production volume (boepd) 60,856 61,230
Sales volume (boepd) 53,500 65,800
Realised oil price ($/bbl) 86.5 60.8
Total revenue ($m) 846 727
Gross profit ($m) 620 321
Underlying cash operating costs per boe ($/boe)(1) 13.0 12.9
Exploration costs written off ($m) 87 49
Impairment of property, plant and equipment, net ($m) 7 8
Operating profit ($m) 696 370
Profit before tax ($m) 548 213
Profit after tax ($m) 264 93
Basic earnings per share (cents) 18.4 6.5
Capital investment ($m)(1) 156 101
Last 12 months adjusted EBITDAX ($m)(1) 1,263 885
Net debt ($m)(1) 2,336 2,290
Gearing (times)(1) 1.9 2.6
Free cash flow ($m)(1) (205) 86
Underlying operating cash flow ($m)(1) 165 218
Pre- Financing free cash flow ($m)(1) (75) 227
(1)Underlying cash operating costs per boe, capital investment, adjusted
EBITDAX, net debt, gearing, free cash flow, underlying operating cash flow and
pre-financing free cash flow are alternative performance measures (APM) and
are explained and reconciled on pages 39 to 42.
Production and commodity prices
Total Group working interest production averaged 60,856 boepd (1H 2021: 61,230
boepd). The marginal decrease in production primarily resulted from the 15 day
maintenance shutdown of the Jubilee facility, the natural decline in TEN and
the sale of Equatorial Guinea and the Dussafu asset in Gabon in 1H21, offset
by increased Jubilee production outside the maintenance shutdown period.
The realised oil price after hedging for the period was $86.5/bbl (1H 2021:
$60.8/bbl) and before hedging $106.9/bbl (1H 2021: $65.2/bbl). The higher
realised oil prices have been sustained during 2H21 and 1H22 offset by hedge
losses, decreasing total revenue by $189.6 million (1H 2021: decrease of $52.4
million).
1H 2022 1H 2021
Income Statement
Revenue ($m) 846 727
Underlift/(Overlift) and oil stock movements ($m) 120 (90)
Balance Sheet
Underlift ($m) 76 4
Overlift ($m) (94) (78)
The underlift in the income statement was mainly due to the increase in oil prices and stock positions in Gabon and Ghana as well as the delay in lifting due the Cap Lopez terminal spillage in Gabon.
Higher oil prices combined with oil entitlements have led to a 93% increase in gross profit for the period.
Operating costs, depreciation and expenses
Underlying cash operating costs amounted to $143 million; $13.0/boe (1H 2021:
$143 million; $12.9/boe). The cash unit operating costs has remained unchanged
against the comparative period. However this is due to disposal of Equatorial
Guinea and Dussafu asset in Gabon in 1H21 offset by the shutdown in Jubilee in
Ghana and the Simba expansion project costs in Gabon.
Normalised cash operating costs which exclude COVID-19 operating procedures,
shuttle tanker operations, CSV campaign and shutdown costs were $11.6/boe (1H
2021: $12.5/boe). Refer to page 41 for the reconciliation as an APM.
Higher equities in Jubilee and TEN following the pre-emption in 1H22 also
contributed to the increase in total operating costs.
DD&A charges before impairment on production and development assets
amounted to $177 million; $16.1 /boe (1H 2021: $170 million:$15.3/boe). This
increase in DD&A per barrel is mainly attributable to Ghana pre-emption
which was effective 1Q22, offset by 2021 impairments.
Administrative expenses of $23 million (1H 2021: $23 million) has remained
unchanged against the comparative period mainly due to an increase in
professional fees offset by a favourable GBP:USD FX variance in 2022 and a
decrease to the administrative assets' depreciation. Tullow delivered $238
million in net cash costs savings since mid-2020 to date.
Impairment of property, plant and equipment (PP&E) 1H 2022 1H 2021
Pre-tax impairment of PP&E, net ($m) 7 8
Associated deferred tax credit ($m) (1) (4)
Post-tax impairment of PP&E, net ($m) 6 4
The Group recognised a net impairment charge on PP&E of $7 million in
respect of first half 2022 (1H 2021: $8million) due to changes to estimates on
the cost of decommissioning for certain UK and Mauritania assets.
Exploration costs written off 1H 2022 1H 2021
Exploration cost written off ($m) 87 49
During the first half of 2022, the Group has written off exploration costs of
$87 million (1H 2021: $49 million) which are predominantly driven by
write-offs the Beebei Potaro commitment well in Guyana which has been plugged
and abandoned following the completion of the well.
Gain on bargain purchase
On 17 March 2022 the Group completed the pre-emption related to the sale of
Occidental Petroleum's interests in the Jubilee and TEN fields in Ghana to
Kosmos Energy. As a result of this acquisition, the Group's interest in the
TEN fields increased from 47.18% to 54.84%, and from 35.48% to 39.0% in the
Jubilee field. The difference between the fair value of net assets acquired
and consideration paid was recognised within the income statement as gain on
bargain purchase of $197 million. Refer to note 18. Business combination.
Derivative financial instruments
Tullow has a material hedge portfolio in place to protect against commodity
price volatility and to ensure the availability of cash flow for re-investment
in capital programmes that are driving business delivery.
At 30 June 2022, Tullow's hedge portfolio provides downside protection for 66%
of forecast production entitlements (after pre-emption) through to May 2023
and 41% for a further 12 months to May 2024 with $51/bbl floors and weighted
average sold calls of $78/bbl for the remainder of 2022, and $55/bbl floors
and weighted average sold calls of c.$75/bbl in 2023 and 2024.
At 30 June 2022, the Group's derivative instruments had a net negative fair
value of negative $573 million (30 June 2021: negative $148 million).
All financial instruments that are initially recognised and subsequently
measured at fair value have been classified in accordance with the hierarchy
described in IFRS 13 Fair Value Measurement. Fair value is the amount for
which the asset or liability could be exchanged in an arm's length transaction
at the relevant date. Where available, fair values are determined using quoted
prices in active markets. To the extent that market prices are not available,
fair values are estimated by reference to market-based transactions or using
standard valuation techniques for the applicable instruments and commodities
involved.
All of the Group's derivatives are Level 2 (1H 2021: Level 2). There were no
transfers between fair value levels during the year.
2H 2022 hedge position at 30 June 2022 Bopd Bought put (floor) Sold call
Collars 32,259 $54.73 $77.30
Zero cost collars 1,203 $55.00 $95.33
Straight puts 9,000 $38.84 -
Total/weighted average 42,462 $51.37 $77.95
Hedge position at 30 June 2022 2022 2023 2024
Hedged Volume (kbopd) 42,462 33,095 11,305
Weighted average bought put (floor) ($/bbl) $51/bbl $55/bbl $55/bbl
Weighted average sold call ($/bbl) $78/bbl $75/bbl $75/bbl
Borrowings
In May, the Group made a mandatory prepayment of $100 million of the Senior
Secured Notes due 2026, which reduced total debt to $2.5 billion. As at 30
June 2022 net debt was $2,336 million (30 June 2021: $2,290 million).
Management regularly reviews options for optimising the Group's capital
structure and may purchase outstanding debt securities or repay debt from time
to time in open-market purchases and/or privately negotiated transactions, and
upon such terms and at such prices as it may determine.
Net financing costs
Net financing costs for the period were $149 million (1H 2021: $157 million).
The decrease in financing costs is mainly due to $19 million fees incurred in
1H 2021 in relation to the refinancing of the RBL facility, a decrease of $5
million in interest on obligations under finance leases due to a decrease in
lease liability position, offset by a $14 million increase in interest on
borrowings.
Net financing costs include interest incurred on the Group's debt facilities,
foreign exchange gains/losses, the unwinding of discount on decommissioning
provisions, and the net financing costs associated with lease assets. These
costs are offset by interest earned on cash deposits. A reconciliation of net
financing costs is included in Note 9.
Taxation
The overall net tax expense of $284 million (1H 2021: $120 million) primarily
relates to expenses in respect of Ghana and West Africa non-operated assets
net of non-recurring deferred tax credits associated with exploration
write-offs, impairments and onerous lease provisions. The tax charge has been
calculated by applying the effective tax rate which is expected to apply to
each jurisdiction for the year ending 31 December 2022.
The Group's statutory effective tax rate is 51.8% (1H 2021: 56.4%). After
adjusting for the non-recurring amounts related to exploration write-offs,
impairments, restructuring costs, disposals and onerous lease provisions and
their associated tax benefit, the Group's underlying effective tax rate is
62.0% (1H 2021: (83.1%)). The change in effective tax rate from 1H21 to 1H22
is due primarily to there being no tax benefit from net interest and hedging
expenses, representing a smaller proportion of the Group's overall profits in
1H22 than in 1H21. Non-deductible expenditure in Ghana and a change to the mix
of taxable and non-taxable profits in Gabon are additional contributing
factors.
Analysis of effective tax rate ($'m) Profit/(loss) before tax Tax (expense)/credit Effective tax rate
Ghana - 1H 2022 543.8 (192.8) 35.5%
1H 2021 200.3 (72.6) 36.2%
Gabon - 1H 2022 190.6 (84.3) 44.2%
1H 2021 79.1 (38.1) 48.2%
Equatorial Guinea - 1H 2022 - - -
1H 2021 15.5 (5.4) 35.0%
Corporate - 1H 2022 (299.7) 0.2 0.1%
1H 2021 (157.9) (0.6) -0.4%
Other non-operated & exploration - 1H 2022 13.7 (1.1) 7.7%
1H 2021 4.6 (0.9) 20.4%
Total - 1H 2022 448.5 (278.0) 62.0%
1H 2021 141.7 (117.7) 83.1%
Profit after tax from continuing activities and earnings per share
The profit after tax for the period amounted to $264 million (1H 2021: $93
million). Basic earnings per share was 18.4 cents (1H 2021: basic earnings per
share of 6.5 cents).
Reconciliation of net debt $m
Year-end 2021 net debt 2,130.9
Sales revenue (845.7)
Operating costs 142.7
Other operating and administrative expenses 24.3
Operating cash flow before working capital movements (678.7)
Movement in working capital 326.4
Tax paid 143.7
Purchases of intangible exploration and evaluation assets and property, plant 134.8
and equipment
Purchase of additional interest in joint operation 126.8
Other investing activities (69.7)
Other financing activities 218.1
Foreign exchange loss on cash 3.6
1H 2022 net debt 2,336.0
Capital investment
Capital expenditure amounted to $156 million (1H 2021: $101 million) with $135
million invested in production and development activities and $21 million
invested in exploration and appraisal activities.
Capital investment will continue to be carefully controlled in the second half
of 2022 and total 2022 capital expenditure is expected to be c.$380 million.
The capital investment total is expected to comprise Ghana capex of c.$300
million, including an increase of $30 million associated with additional
equity following pre-emption in Ghana, West African non-operated capex of
c.$30 million, Kenya capex of c.$5 million and exploration spend of c.$45
million.
Going concern
The Directors consider the going concern assessment period to be up to 30
September 2023. The Group closely monitors and manages its liquidity headroom.
Cash forecasts are regularly produced, and sensitivities run for different
scenarios including, but not limited to, changes in commodity prices,
different production rates from the Group's producing assets and different
outcomes on ongoing disputes or litigation. For the assessment, management has
excluded the liquidity enhancing impact of the recommended merger with
Capricorn Energy PLC within its base case as it provides a more conservative
assessment.
Management has applied the following oil price assumptions for the going
concern assessment:
Base Case: $100/bbl for 2022, $90/bbl for 2023; and
Low Case: $80/bbl for 2022, $70/bbl for 2023.
The Low Case includes, amongst other downside assumptions, a 5 per cent
production decrease compared to the Base Case as well as increased outflows
associated with an ongoing dispute.
The Group had $0.6 billion liquidity headroom of unutilised debt capacity and
free cash as at 30 June 2022. The Group's forecasts show that the Group will
be able to operate within its current debt facilities and have sufficient
financial headroom for the going concern assessment period under its Base Case
and Low Case. Based on the analysis above, the Directors have a reasonable
expectation that the Group has adequate resources to continue in operational
existence for the foreseeable future. Thus, they have adopted the going
concern basis of accounting in preparing the half year results.
2022 principal risks and uncertainties
The Company risk profile has been closely monitored throughout the year, with
consideration given to the risks to delivering the revised Business Plan, as
well as whether external factors such as geo-political factors, global
pandemics and oil price volatility have resulted in any new risks or changes
to existing risks. The impact of these factors has been considered and managed
across all principal risks. The principal risks and uncertainties facing the
Group at half year remain unchanged from those disclosed in the 2021 Annual
Report as listed below.
1. Risk of failure to deliver production targets
2. Risk of a major EHS incident
3. Risk of failure to unlock value
4. Risk of failure to manage geopolitical risks
5. Risk of failure to manage climate change risks
6. Risk of insufficient liquidity and funding capacity
7. Risk of failure to develop, retain and attract capability
8. Risk of compliance or regulatory breach
9. Risk of major cyber attack
Events since 30 June 2022
Tullow Ghana Limited has awarded a 5-year contract to Petrofac Ghana
(Petrofac) to support Operations and Maintenance activities on the FPSO Kwame
Nkrumah (KNK) following the expiry of Tullow's contract with MODEC Production
Services Ghana JV Ltd (MODEC) which ended on 30 June 2022. Tullow and MODEC
worked on a smooth transition of O&M services and achieved a seamless
transition on 1 July 2022.
On 5 August 2022, it was announced that the Beebei Potaro well, offshore
Guyana has been plugged and abandoned after encountering good quality
reservoir in the primary and secondary targets, but both targets were water
bearing.
Responsibility statement (DTR 4.2 and the Transparency (Directive 2004/109/EC) Regulations (as amended))
The Directors confirm that to the best of their knowledge:
a. the condensed set of financial statements has been prepared in
accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK and
EU and IAS 34 'Interim Financial Reporting' as adopted by the EU, the
Disclosure Guidance and Transparency Rules of the United Kingdom's Financial
Conduct Authority (DTR) and the Transparency (Directive 2004/109/EC)
Regulations 2007 as amended
b. the interim management report includes a fair review of the information
required by DTR 4.2.7R and Regulation 8(2) (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
c. the interim management report includes a true and fair review of
the information required by DTR 4.2.8R and Regulation 8(3) (disclosure of
related parties' transactions and changes therein).
A list of the current Directors is maintained on the Tullow Oil plc website:
www.tullowoil.com.
By order of the Board,
Rahul Dhir
Chief Executive Officer
13 September 2022
Richard Miller
Interim Chief Financial Officer
13 September 2022
Disclaimer
This statement contains certain forward-looking statements that are subject to
the usual risk factors and uncertainties associated with the oil and gas
exploration and production business. Whilst the Group believes the
expectations reflected herein to be reasonable in light of the information
available to them at this time, the actual outcome may be materially different
owing to factors beyond the Group's control or within the Group's control
where, for example, the Group decides on a change of plan or strategy.
Accordingly, no reliance may be placed on the figures contained in such
forward-looking statements.
Independent review report to Tullow Oil 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 2022 which comprises Condensed consolidated income statement, Condensed consolidated statement of comprehensive income and expense, Condensed consolidated balance sheet, Condensed statement of changes in equity, Condensed consolidated cash flow statement and the related notes 1 to 25. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of 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 2022 is not prepared, in all material respects, in accordance with UK and EU 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 2410 (UK) "Review of Interim Financial Information Performed by
the Independent Auditor of the Entity" (ISRE) issued by the Financial
Reporting Council. A review of interim financial information consists of
making enquiries, primarily of persons responsible for financial and
accounting matters, and applying analytical and other review procedures. A
review is substantially less in scope than an audit conducted in accordance
with International Standards on Auditing (UK) and consequently does not enable
us to obtain assurance that we would become aware of all significant matters
that might be identified in an audit. Accordingly, we do not express an audit
opinion.
As disclosed in note 2, the annual financial statements of the group are
prepared in accordance with UK adopted international accounting standards and
International Financial Reporting Standards adopted pursuant to Regulation
(EC) No. 1606/2002 as it applies in the European Union. The condensed set of
financial statements included in this half-yearly financial report has been
prepared in accordance with UK adopted International Accounting Standard 34,
"Interim Financial Reporting".
Conclusions Relating to Going Concern
Based on our review procedures, which are less extensive than those performed
in an audit as described in the Basis of Conclusion section of this report,
nothing has come to our attention to suggest that management have
inappropriately adopted the going concern basis of accounting or that
management 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
this ISRE, 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 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 Conclusions
Relating to Going Concern, are based on procedures that are less extensive
than audit procedures, as described in the Basis for Conclusion paragraph of
this report.
Use of our report
This report is made solely to the company in accordance with guidance
contained in International Standard on Review Engagements 2410 (UK) "Review of
Interim Financial Information Performed by the Independent Auditor of the
Entity" issued by the Financial Reporting Council. To the fullest extent
permitted by law, we do not accept or assume responsibility to anyone other
than the company, for our work, for this report, or for the conclusions we
have formed.
Ernst & Young LLP
London
13 September 2022
Condensed consolidated income statement
Six months ended 30 June 2022
Notes Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited $m
Continuing activities
Revenue 6, 7 845.7 726.8 1,273.2
Cost of sales 8 (225.4) (405.7) (638.9)
Gross profit 620.3 321.1 634.3
Administrative expenses 8 (23.2) (23.1) (64.1)
Restructuring costs and other provisions 8 (4.6) 5.9 (61.8)
Gain on bargain purchase 18 196.8 - -
Gain on disposals 11 - 122.9 120.3
Exploration costs written off 12 (86.6) (49.3) (59.9)
Impairment of property, plant and equipment, net 13 (6.5) (8.0) (54.3)
Operating profit 696.2 369.5 514.5
Gain on hedging instruments - 0.2 -
Finance income 9 21.1 22.1 44.3
Finance costs 9 (169.7) (178.7) (356.1)
Profit from continuing activities before tax 547.6 213.1 202.7
Income tax expense 10 (283.7) (120.4) (283.4)
Profit/ (loss) for the year from continuing activities 263.9 92.7 (80.7)
Attributable to
Owners of the Company 263.9 92.7 (80.7)
Earnings/ (loss) per ordinary share from continuing activities ¢ ¢ ¢
Basic 3 18.4 6.5 (5.7)
Diluted 3 17.8 6.2 (5.7)
Condensed consolidated statement of comprehensive income and expense
Six months ended 30 June 2022
Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited $m
Profit/ (loss) for the period 263.9 92.7 (80.7)
Items that may be reclassified to the income statement in subsequent periods
Cash flow hedges
Loss arising in the period (577.2) (101.2) (159.3)
Gains/ (losses) arising in the period - time value 4.0 (108.2) (182.1)
Reclassification adjustments for items included in loss on realisation 174.4 30.8 112.3
Reclassification adjustments for items included in loss on realisation - time 12.0 21.6 40.7
value
Exchange differences on translation of foreign operations 8.6 (2.0) (1.4)
Other comprehensive expense (378.2) (159.0) (189.8)
Tax relating to components of other comprehensive expense - 2.8 2.7
Net other comprehensive expense for the period (378.2) (156.2) (187.1)
Total comprehensive expense for the period (114.3) (63.5) (267.8)
Attributable to
Owners of the Company (114.3) (63.5) (267.8)
Condensed consolidated balance sheet
As at 30 June 2022
Notes Six months ended Six months ended Year ended 31.12.21 Audited $m
30.06.22 Unaudited $m
30.06.21 Restated(1)
Unaudited
$m
Assets
Non-current asset
Intangible exploration and evaluation assets 12 288.6 346.3 354.6
Property, plant and equipment 13 3,413.3 3,144.1 2,914.6
Other non-current assets 15 317.3 514.9 489.1
Derivative financial instruments - 6.6 -
Deferred tax assets 343.5 490.4 354.4
4,362.7 4,502.3 4,112.7
Current assets
Inventories 16 333.3 141.3 134.8
Trade receivables 14 290.2 256.4 99.8
Other current assets 15 726.6 1,044.0 704.5
Current tax assets 29.9 41.4 19.7
Cash and cash equivalents 17 164.1 301.8 469.1
1,544.1 1,784.9 1,427.9
Total assets 5,906.8 6,287.2 5,540.6
Liabilities
Current liabilities
Trade and other payables 19 (828.8) (818.7) (751.1)
Borrowings 20 (100.0) (297.8) (100.0)
Provisions 21 (205.2) (255.3) (296.5)
Current tax liabilities (189.5) (95.1) (115.1)
Derivative financial instruments (378.5) (104.5) (80.9)
(1,702.0) (1,571.4) (1,343.6)
Non-current liabilities
Trade and other payables 19 (882.3) (1,082.2) (987.1)
Borrowings 20 (2,370.7) (2,565.5) (2,468.7)
Provisions 21 (443.7) (575.5) (431.0)
Deferred tax liabilities (889.9) (709.4) (677.3)
Derivative financial instruments (194.2) (50.2) (99.0)
(4,780.8) (4,982.8) (4,663.1)
Total liabilities (6,482.8) (6,554.2) (6,006.7)
Net liabilities (576.0) (267.0) (466.1)
Equity
Called-up share capital 214.9 213.8 214.2
Share premium 1,294.7 1,294.7 1,294.7
Equity component of convertible bonds - 48.4 -
Foreign currency translation reserve (240.2) (249.4) (248.8)
Hedge reserve (442.1) (62.6) (39.3)
Hedge reserve - time value (130.9) (92.1) (146.9)
Merger reserve 755.2 755.2 755.2
Retained earnings (2,027.6) (2,175.0) (2,295.2)
Equity attributable to equity holders of the Company (576.0) (267.0) (466.1)
Total equity (576.0) (267.0) (466.1)
(1)Refer to note 19 for details on prior period restatement.
Condensed statement of changes in equity
As at 30 June 2022
Share capital $m Share premium $m Equity component of convertible bonds $m Foreign currency translation reserve(1) $m Hedge reserve(2) $m Hedge reserve - Time value $m Merger reserve $m Retained earnings $m Total equity $m
At 1 January 2021 211.7 1,294.7 48.4 (247.4) 4.8 (5.4) 755.2 (2,272.0) (210.0)
Profit for the period - - - - - - - 92.7 92.7
Hedges, net of tax - - - - (67.4) (86.7) - - (154.1)
Currency translation adjustments - - - (2.0) - - - - (2.0)
Exercise of employee share options 2.1 - - - - - - (2.1) -
Share-based payment charges - - - - - - - 6.4 6.4
At 30 June 2021 213.8 1,294.7 48.4 (249.4) (62.6) (92.1) 755.2 (2,175.0) (267.0)
Loss for the period - - - - - - - (173.4) (173.4)
Hedges, net of tax - - - - 23.3 (54.8) - - (31.5)
Derecognition of the convertible bond(3) - - (48.4) - - - - 48.4 -
Currency translation adjustments - - - 0.6 - - - - 0.6
Exercise of employee share options 0.4 - - - - - - (0.4) -
Share-based payment charges - - - - - - - 5.2 5.2
At 1 January 2022 214.2 1,294.7 - (248.8) (39.3) (146.9) 755.2 (2,295.2) (466.1)
Profit for the period - - - - - - - 263.9 263.9
Hedges, net of tax - - - - (402.8) 16.0 - - (386.8)
Currency translation adjustments - - - 8.6 - - - - 8.6
Exercise of employee share options 0.7 - - - - - - (0.7) -
Share-based payment charges - - - - - - - 4.4 4.4
At 30 June 2022 214.9 1,294.7 - (240.2) (442.1) (130.9) 755.2 (2,027.6) (576.0)
(1) The foreign currency translation reserve represents exchange gains and
losses arising on translation of foreign currency subsidiaries, monetary items
receivable from or payable to a foreign operation for which settlement is
neither planned nor likely to occur, which form part of the net investment in
a foreign operation, and exchange gains or losses arising on long-term foreign
currency borrowings which are a hedge against the Group's overseas
investments.
(2) The hedge reserve represents gains and losses on derivatives classified as
effective cash flow hedges.
(3) On 12 July 2021 Tullow repaid the $300 million Convertible Bond due 2021
(note 20). As the conversion option was not exercised, the equity component of
$48.4 million has been transferred from the separate reserve to retained
earnings.
Condensed consolidated cash flow statement
Six months ended 30 June 2022
Notes Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited
$m
Cash flows from operating activities
Profit from continuing activities before tax 547.6 213.1 202.7
Adjustments for
Depreciation, depletion and amortisation 183.5 178.7 378.9
Gain on bargain purchase 18 (196.8) - -
Gain on disposals 11 - (122.9) (120.3)
Exploration costs written off 12 86.6 49.3 59.9
Impairment of property, plant and equipment, net 13 6.5 8.0 54.3
Restructuring costs and other provisions 21 4.6 (5.9) 61.8
Payments under restructuring costs and other provisions 21 (77.5) (8.9) (12.6)
Decommissioning expenditure (28.8) (27.7) (52.8)
Share-based payment charge 4.4 6.4 11.6
Gain on hedging instruments - (0.2) -
Finance income 9 (21.1) (22.1) (44.3)
Finance costs 9 169.7 178.7 356.1
Operating cash flow before working capital movements 678.7 446.5 895.3
Increase in trade and other receivables (118.0) (143.2) (17.9)
Increase in inventories (198.6) (50.2) (41.9)
Increase in trade payables (9.8) 42.3 7.5
Cash flows from operating activities 352.3 295.4 843.0
Income taxes paid (143.7) (37.3) (56.1)
Net cash from operating activities 208.6 258.1 786.9
Cash flows from investing activities
Proceeds from disposals 11 68.6 132.4 132.8
Purchase of additional interest in joint operation 18 (126.8) - -
Purchase of intangible exploration and evaluation assets (17.5) (55.8) (86.1)
Purchase of property, plant and equipment (117.3) (41.4) (150.4)
Interest received 1.1 1.7 2.0
Net cash (used in)/ from in investing activities (191.9) 36.9 (101.7)
Cash flows from financing activities
Debt arrangement fees - (57.8) (56.6)
Repayment of borrowings 25 (100.0) (2,080.0) (2,379.9)
Payment into trust for repayment of convertible bond(1) - (309.8) -
Drawdown of borrowings 25 - 1,800.0 1,800.0
Repayment of obligations under leases (91.9) (68.3) (155.9)
Finance costs paid (126.2) (86.9) (234.9)
Net cash used in financing activities (318.1) (802.8) (1,027.3)
Net decrease in cash and cash equivalents (301.4) (507.8) (342.1)
Cash and cash equivalents at beginning of period 469.1 805.4 805.4
Foreign exchange (loss)/ gain (3.6) 4.2 5.8
Cash and cash equivalents at end of period 17 164.1 301.8 469.1
(1) On 17 May 2021, as part of the refinancing transaction $309.8 million was
agreed to be put into a trustee account for settlement of principal and
accrued interest of the convertible loan notes on due date. On 12 July 2021
the convertible loan notes were settled by the trustees by utilising the
amount kept in the trust account. This this has been disclosed as a financing
activity within the cash flow statement.
Notes to the condensed financial statements
Six months ended 30 June 2022
1. General information
The condensed financial statements for the six-month period ended 30 June 2022
have been prepared in accordance with International Accounting Standard (IAS)
34 Interim Financial Reporting as adopted by UK and EU and the requirements of
the Disclosure and Transparency Rules (DTR) of the Financial Conduct Authority
(FCA) in the United Kingdom as applicable to interim financial reporting.
The Condensed financial statements represent a 'condensed set of financial
statements' as referred to in the DTR issued by the FCA. Accordingly, they do
not include all the information required for a full annual financial report
and are to be read in conjunction with the Group's financial statements for
the year ended 31 December 2021, which were prepared in accordance with
UK-adopted international accounting standards (IFRSs) and International
Financial Reporting Standards (IFRSs) adopted pursuant to Regulation (EC) No
1606/2002 as it applies in the European Union (EU). The Condensed financial
statements are unaudited and do not constitute statutory accounts as defined
in section 434 of the Companies Act 2006. The financial information for the
year ended 31 December 2021 does not constitute statutory accounts as defined
in section 434 of the Companies Act 2006. This information was derived from
the statutory accounts for the year ended 31 December 2021, a copy of which
has been delivered to the Registrar of Companies. The auditor's report on
these accounts was unqualified, did not include a reference to any matters to
which the auditor drew attention by way of an emphasis of matter and did not
contain a statement under sections 498 (2) or (3) of the Companies Act 2006.
2. Accounting policies
The annual financial statements of Tullow Oil plc will be prepared in
accordance with United Kingdom adopted international accounting standards ("UK
adopted IFRSs") and International Financial Reporting Standards adopted
pursuant to Regulation (EC) No. 1606/2002 as it applies in the European Union.
The condensed set of financial statements included in this half-yearly
financial report has been prepared in accordance with International Accounting
Standard (IAS) 34 Interim Financial Reporting as adopted by UK and EU , the
Disclosure and Transparency Rules of the Financial Conduct Authority and the
Transparency (Directive 2004/109/EC) Regulations 2007 as amended.
The accounting policies adopted in the 2022 half-yearly financial report are
the same as those adopted in the Group's Annual Report and Accounts as at 31
December 2021, except business combinations which is disclosed in Note 18.
There was no business combination in the previous year.
Going Concern
The Directors consider the going concern assessment period to be up to 30
September 2023. The Group closely monitors and manages its liquidity headroom.
Cash forecasts are regularly produced, and sensitivities run for different
scenarios including, but not limited to, changes in commodity prices,
different production rates from the Group's producing assets and different
outcomes on ongoing disputes or litigation. For the assessment, management has
excluded the liquidity enhancing impact of the recommended merger with
Capricorn Energy PLC within its base case as it provides a more conservative
assessment.
Management has applied the following oil price assumptions for the going
concern assessment:
Base Case: $100/bbl for 2022, $90/bbl for 2023; and
Low Case: $80/bbl for 2022, $70/bbl for 2023.
The Low Case includes, amongst other downside assumptions, a 5 per cent
production decrease compared to the Base Case as well as increased outflows
associated with an ongoing dispute.
The Group had $0.6 billion liquidity headroom of unutilised debt capacity and
free cash as at 30 June 2022. The Group's forecasts show that the Group will
be able to operate within its current debt facilities and have sufficient
financial headroom for the going concern assessment period under its Base Case
and Low Case. Based on the analysis above, the Directors have a reasonable
expectation that the Group has adequate resources to continue in operational
existence for the foreseeable future. Thus, they have adopted the going
concern basis of accounting in preparing the half year results.
3. Earnings per ordinary share
The calculation of basic earnings per share is based on the profit for the
period after taxation attributable to equity holders of the parent of $263.9
million (1H 2021: profit of $92.7 million) and a weighted average number of
shares in issue of 1,435.3 million (1H 2021: 1,421.3 million).
The calculation of diluted earnings per share is based on the profit for the
period after taxation as for basic earnings per share. The number of shares
outstanding, however, is adjusted to show the potential dilution if employee
share options are converted into ordinary shares. The weighted average number
of ordinary shares is increased by 45.7 million resulting in a diluted
weighted average number of shares of 1,481.0 million.
4. Dividends
The Directors intend to recommend that no 2022 interim dividend be paid.
5. Approval of accounts
These unaudited half year results were approved by the Board of Directors on
13 September 2022.
6. Segmental reporting
The information reported to the Group's Chief Executive Officer for the
purposes of resource allocation and assessment of segment performance is
focused on four Business Units - Ghana, Non-operated producing assets
including Uganda and decommissioning assets, Kenya and Exploration. Therefore,
the Group's reportable segments under IFRS 8 are Ghana, Non-operated, Kenya
and Exploration.
The following tables present revenue, profit and certain asset and liability
information regarding the Group's reportable business segments for the period
ended 30 June 2022, 30 June 2021 and 31 December 2021.
Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m
Six months ended 30 June 2022
Sales revenue by origin(1) 781.0 254.4 - - (189.7) 845.7
Segment result(2) 609.1 202.8 - (86.9) (197.8) 527.2
Other provisions(3) (4.1)
Gain on bargain purchase 196.8
Unallocated corporate expenses(4) (23.7)
Operating profit 692.6
Finance income 21.1
Finance costs (169.7)
Profit before tax 547.6
Income tax expense (283.7)
Profit after tax 263.9
Total assets 4,923.2 521.9 270.8 44.8 146.1 5,906.8
Total liabilities(5) (2,742.0) (494.4) (16.9) (11.6) (3,217.9) (6,482.8)
Other segment information
Capital expenditure:
Property, plant and equipment 135.5 20.5 - - 0.5 156.5
Intangible exploration and evaluation assets 0.3 (1.5) 2.6 19.2 - 20.6
Depletion, depreciation and amortisation (158.7) (18.6) (0.7) - (5.5) (183.5)
Impairment of property, plant and equipment, net - (6.5) - - - (6.5)
Exploration costs written off (0.3) 1.5 - (87.8) - (86.6)
(1)The basis of allocation of the loss on realisation of the cash flow hedges
presented in the "Sales revenue by origin" line was incorrectly classified
within Ghana and Non-Operated segment in the prior period. This has now been
allocated to the Corporate reportable segment. For the comparative periods,
the allocation for the year ended 31 December 2021 increased revenue for Ghana
and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the
hedging loss of $152.9 million was allocated to Corporate. For the six months
ended 30 June 2021, revenue for Ghana and Non-Operated increased by $33.8
million, and $18.6 million, respectively, with the hedging loss of $52.4
million allocated to Corporate.
(2)Segment result is a non-IFRS measure which includes gross profit,
exploration costs written off and impairment of property, plant and equipment.
See reconciliation below.
(3) This is included within the Restructuring costs and other provisions in
the Group Income Statement.
(4) Unallocated expenditure and net liabilities include amounts of a corporate
nature and not specifically attributable to a geographic area.
(5) Total liabilities - Corporate comprise of the Group's external debt,
derivative financial instruments and other non-attributable liabilities.
6. Segmental reporting continued
Reconciliation of segment result
Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited $m
Segment result 527.2 263.8 520.1
Add back
Exploration costs written off 86.6 49.3 59.9
Impairment of Property, Plant and Equipment 6.5 8.0 54.3
Gross profit 620.3 321.1 634.3
Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m
Six months ended 30 June 2021
Sales revenue by origin - restated(1) 501.6 277.6 - - (52.4) 726.8
Segment result - restated(1) 270.9 113.4 0.8 (63.3) (58.0) 263.8
Gain on disposal 122.9
Unallocated corporate expenses(2) (17.2)
Operating profit 369.5
Gain on hedging instruments 0.2
Finance income 22.1
Finance costs (178.7)
Profit before tax 213.1
Income tax expense (120.4)
Profit after tax 92.7
Total assets - restated(2) 4,813.9 546.5 283.4 125.9 517.5 6,287.2
Total liabilities - restated(2) (2,817.1) (495.8) (19.9) (20.5) (3,200.9) (6,554.2)
Other segment information
Capital expenditure:
Property, plant and equipment 95.7 9.7 - 0.3 0.7 106.4
Intangible exploration and evaluation assets(3) 0.8 (13.9) 4.4 36.1 - 27.4
Depletion, depreciation and amortisation (155.7) (15.3) (0.7) - (7.0) (178.7)
Impairment of property, plant and equipment, net - (8.0) - - - (8.0)
Exploration costs written off (0.9) 14.1 0.8 (63.3) - (49.3)
(1) Segment revenue and segment result allocation between the reportable
segments have been restated to correct a prior period error arising from
incorrect classification of loss on realisation of the cash flow hedges within
reportable segments. Total balances have remained unchanged.
The allocation for the six months ended 30 June 2021, revenue for Ghana and
Non-Operated increased by $33.8 million, and $18.6 million, respectively, with
the hedging loss of $52.4 million allocated to Corporate.
(2) Total assets and total liabilities allocation between the reportable
segments have been restated to correct a prior period error arising from
incorrect classification of tax assets and liabilities within reportable
segments. The above balances have been restated by:
Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m
Total assets - increase/ (decrease) (113.1) 7.1 (6.0) (22.0) 134.0 -
Total liabilities - (increase)/ decrease 45.3 (12.8) 6.0 24.0 (62.5) -
(3) Non-operated segment includes release of $15.3 million indirect tax
provision following settlement.
6. Segmental reporting continued
Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m
Year ended 31 December 2021
Sales revenue by origin - restated(1) 1,020.4 405.7 - - (152.9) 1,273.2
Segment result - restated(1) 469.8 286.5 - (70.5) (165.7) 520.1
Other provisions 6.6 - (13.2) - (52.1) (58.7)
Gain on disposal 120.3
Unallocated corporate expenses (67.2)
Operating profit 514.5
Finance income 44.3
Finance costs (356.1)
Profit before tax 202.7
Income tax expense (283.4)
Loss after tax (80.7)
Total assets - restated(2) 4,283.8 501.2 264.6 122.3 368.8 5,540.6
Total liabilities - restated(2) (2,529.3) (478.9) (18.0) (12.8) (2,967.7) (6,006.7)
Other segment information
Capital expenditure:
Property, plant and equipment 99.6 43.9 - - 4.6 148.1
Intangible exploration and evaluation assets(3) 1.2 (11.8) 8.2 48.8 - 46.4
Depletion, depreciation and amortization (334.5) (28.8) (1.4) (0.1) (14.1) (378.9)
Impairment of property, plant and equipment, net (119.1) 64.8 - - - (54.3)
Exploration costs written off(1) (1.2) 11.8 - (70.5) - (59.9)
(1) Segment revenue and segment result allocation between the reportable
segments have been restated to correct a prior period error arising from
incorrect classification of loss on realisation of the cash flow hedges within
reportable segments. Total balances have remained unchanged.
The allocation for the year ended 31 December 2021 increased revenue for Ghana
and Non-Operated by $109.8 million and $43.1 million, respectively, whilst the
hedging loss of $152.9 million was allocated to Corporate.
(2)Total assets and total liabilities allocation between the reportable segments have been restated to correct a prior period error arising from incorrect classification of tax assets and liabilities within reportable segments. The above balances have been restated by:
Ghana $m Non-Operated $m Kenya $m Exploration $m Corporate $m Total $m
Total assets - increase/ (decrease) (35.1) 5.4 (6.0) (22.0) 57.8 -
Total liabilities - (increase)/ decrease (32.0) (11.2) 6.0 24.0 13.2 -
(3) Non-operated segment includes release of $15.3 million indirect tax
provision following settlement.
( )
( )
( )
( )
6. Segmental reporting continued
Sales revenue six months ended 30.06.22(1) $m Sales revenue six months ended 30.06.21( ) Restated(1) Sales revenue Year ended 31.12.21 Restated(1) $m Non-current assets 30.06.22 (2) $m Non-current assets 30.06.21(2) $m Non-current assets 31.12.21(2) $m
$m
Ghana 781.0 501.6 1,020.4 3,473.9 3,477.5 3,131.3
Total Ghana 781.0 501.6 1,020.4 3,473.9 3,477.5 3,131.3
Kenya - - - 262.5 256.3 261.7
Total Kenya - - - 262.5 256.3 261.7
Argentina - - - 31.8 29.2 30.4
Guyana - - - - 64.9 69.1
Total Exploration - - - 31.8 94.1 99.5
Gabon 225.7 190.8 305.9 137.0 61.5 148.7
Côte d'Ivoire 28.7 27.7 40.7 86.6 75.4 81.4
Equatorial Guinea - 59.1 59.1 - - -
Total Non- Operated 254.4 277.6 405.7 223.6 136.9 230.1
Corporate (189.7) (52.4) (152.9) 27.4 40.5 35.6
Total 845.7 726.8 1,273.2 4,019.2 4,005.3 3,758.2
(1) Segment revenue allocation between the reportable segments has been
restated to correct a prior period error arising from incorrect classification
of loss on realisation of the cash flow hedges within reportable segments.
Total balances have remained unchanged.
For the comparative periods, the allocation for the year ended 31 December
2021 increased revenue for Ghana and Non-Operated by $109.8 million and $43.1
million, respectively, whilst the hedging loss of $152.9 million was allocated
to Corporate. For the six months ended 30 June 2021, revenue for Ghana and
Non-Operated increased by $33.8 million, and $18.6 million, respectively, with
the hedging loss of $52.4 million allocated to Corporate.
(2) Excludes derivative financial instruments and deferred tax assets.
( )
7. Total revenue
Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited $m
Revenue from contracts with customers
Revenue from crude oil sales 1,035.4 779.2 1,426.2
Total revenue from contracts with customers 1,035.4 779.2 1,426.2
Loss on realisation of cash flow hedges (189.7) (52.4) (153.0)
Total revenue 845.7 726.8 1,273.2
8. Operating profit
Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited $m
Operating profit is stated after charging/(deducting):
Operating costs 142.7 143.3 268.7
Depletion and amortisation of oil and gas and leased assets(1) 176.9 169.5 360.9
Underlift, overlift and oil stock movements(2) (119.9) 89.5 (20.0)
Share-based payment charge included in cost of sales 0.2 0.4 0.5
Other cost of sales 25.5 3.0 28.8
Total cost of sales 225.4 405.7 638.9
Administrative expenses
Share-based payment charge included in administrative expenses 4.2 6.0 11.1
Depreciation of other property, plant and equipment(1) 6.6 9.2 18.1
Other administrative costs 12.4 7.9 35.0
Total administrative expenses 23.2 23.1 64.1
Total restructuring costs and other provisions 4.6 (5.9) 61.8
(1) Depreciation expense on leased assets of $23.2 million as per note 13
includes a charge of $2.0 million on leased administrative assets, which is
presented within administrative expenses in the income statement. The
remaining balance of $21.2 million relates to other leased assets and is
included within cost of sales.
(2)Refer to page 6 of Finance Review and Note 19 for detailed explanations.
9. Net financing costs
Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited $m
Interest on bank overdrafts and borrowings 127.1 113.0 243.0
Interest on obligations for leases 37.8 43.1 83.4
Total borrowing costs 164.9 156.1 326.4
Finance and arrangement fees 0.1 18.7 19.1
Other interest expense 1.5 0.2 3.0
Unwinding of discount on decommissioning provisions 3.2 3.7 7.6
Total finance costs 169.7 178.7 356.1
Interest income on amounts due from Joint Venture partners for leases (15.7) (19.8) (38.8)
Other finance income (5.4) (2.3) (5.5)
Total finance income (21.1) (22.1) (44.3)
Net financing costs 148.6 156.6 311.8
10. Taxation on profit on ordinary activities
The overall net tax expense of $283.7 million (1H 2021: $120.4 million)
primarily relates to expenses in respect of Ghana and West Africa non-operated
assets net of non-recurring deferred tax credits associated with exploration
write-offs, impairments and onerous lease provisions. The tax charge has been
calculated by applying the effective tax rate which is expected to apply to
each jurisdiction for the year ending 31 December 2022.
The Group's statutory effective tax rate is 51.8% (1H 2021: 56.4%). After
adjusting for the non-recurring amounts related to exploration write-offs,
impairments, restructuring costs, disposals and onerous lease provisions and
their associated tax benefit, the Group's underlying effective tax rate is
62.0% (1H 2021: (83.1%)). The change in effective tax rate from 1H21 to 1H22
is primarily due to there being no UK tax benefit from net interest and
hedging expenses, which represents a smaller proportion of the Group's overall
profits in 1H22 than in 1H21. Non-deductible expenditure in Ghana and a change
to the mix of taxable and non-taxable profits in Gabon are additional
contributing factors.
Uncertain tax positions
The Group is subject to various material claims which arise in the ordinary
course of its business in various jurisdictions, including cost recovery
claims, claims from other regulatory bodies and both corporate income tax and
indirect tax claims. The Group is in formal dispute proceedings regarding a
number of these tax claims with significant updates described in more detail
below. The resolution of tax positions, through negotiation with the relevant
tax authorities or litigation, can take several years to complete. In
assessing whether these claims should be provided for in the Financial
Statements, Management has considered them in the context of the applicable
laws and relevant contracts for the countries concerned. Management has
applied judgement in assessing the likely outcome of the claims and has
estimated the financial impact based on external tax and legal advice and
prior experience of such claims.
Due to the uncertainty of such tax items, it is possible that on conclusion of
an open tax matter at a future date the outcome may differ significantly from
Management's estimate. If the Group was unsuccessful in defending itself from
all of these claims, the result would be additional unprovided liabilities of
$991.9 million (YE21: $1,025.5 million) which includes $33.0 million of
interest and penalties (YE21: $34.1m).
Provisions of $106.5 million (YE21: $127.9 million) are included in income tax
payable ($70.4 million (YE21: $34.1m)), deferred tax liability (nil (YE21:
$41.0 million)) and provisions ($36.2 million (YE21: $52.4m)). Where these
matters relate to expenditure which is capitalised within E&E and
PP&E, any difference between the amounts accrued and the amounts settled
is capitalised within the relevant asset balance, subject to applicable
impairment indicators. Where these matters relate to producing activities or
historical issues, any differences between the accrued and settled amounts are
taken to the group income statement.
The provisions and unprovided tax liabilities relating to these disputes have
decreased following the conclusion of tax authority challenges, but have
increased for the extrapolation of exposures, giving rise to an overall
decrease in provision of $21.4m and decrease in unprovided tax liabilities of
$33.6m.
Ghana tax assessments
In August 2018, Tullow Ghana Limited (TGL) received a direct tax assessment
from the Ghana Revenue Authority (GRA) for the financial years 2014 to 2016.
After discussions, a final assessment was issued in December 2019 for $407.3
million requesting that $397.7 million be paid by 13 January 2020. The GRA is
seeking to apply branch profits remittance tax under a law which the Group
considers is not applicable to TGL, since it falls outside the tax regime set
out in TGL's Petroleum Agreements and relevant double tax treaties. The GRA
has additionally assessed TGL for unpaid withholding taxes and corporate
income tax arising from the disallowance of loan interest. The Group considers
that these assessments also breach TGL's rights under its petroleum
agreements, applicable Ghanaian law and double taxation treaties, and, in some
cases, have arisen as the result of the errors in the GRA's calculations. In
January 2020, TGL issued a Notice of Dispute with the Ministry of Energy
(MoE), disputing the issues and suspending TGL's obligation to pay any taxes
until the disputed issues have been resolved. In April 2020, the GRA issued a
Demand Notice for $365.0 million ($337.6 million branch profits remittance tax
and withholding tax, and $27.4 million corporate income tax) which was put on
hold by the MoE. In September 2021 TGL received a revised final tax audit
report for $471.2 million ($325.0 million branch profits remittance tax and
withholding tax, and $146.1 million corporate income tax).
In October 2021 TGL filed a Request for Arbitration with the International
Chamber of Commerce (ICC) disputing the US$320 million branch profits
remittance tax assessment and an additional Notice of Dispute objecting
against the disallowance of certain expenditure in the revised tax audit
report. The Parties have agreed a procedural timetable for the arbitration
under which hearing will commence in October 2023. In December 2021, TGL paid
US$3 million on account in respect of a revised withholding tax assessment of
$3 million. TGL received a revised assessment in March 2022 assessing a tax
liability of $102 million together with a Demand Notice requiring full
settlement of the assessed tax liability within seven days. TGL disputes the
basis for the revised assessment and the payment obligation is suspended in
view of the Notices of Dispute previously issued. The March 2022 revised
assessment results in assessments totalling US$422 million including BPRT. The
Group disputes the validity of the assessments issued to date and the tax
liability arising from the March 2022 assessment and continues to engage with
the GRA to seek settlement of the issues raised (excluding BPRT) on a mutually
acceptable basis outside of the ongoing dispute process.
10. Taxation on profit on ordinary activities continued
Bangladesh litigation
The National Board of Revenue (NBR) is seeking to disallow $118 million of tax
relief in respect of development costs incurred by Tullow Bangladesh Limited
(TBL). In 2013, the High Court found in favour of Tullow such that the tax
relief should be reinstated. However, in March 2017, the NBR won its appeal to
the Supreme Court, which was not clear as to the position or liability of TBL.
A review application against this judgment was filed in April 2018. The
hearing took place in November 2019 and TBL was unsuccessful. The NBR
subsequently issued a payment demand to TBL in February 2020 for Taka 3,094m
(c$37 million) requesting payment by 15 March 2020. However, under the
Production Sharing Contract (PSC), the Government is required to indemnify TBL
against all taxes levied by any public authority, and the share of production
paid to Petrobangla (PB), Bangladesh's national oil company, is deemed to
include all taxes due which PB is then obliged to pay to the NBR. TBL sent the
payment demand to PB and the Government requesting the payment or discharge of
the payment demand under their respective PSC indemnities. TBL secured an
extension of the payment deadline to 15 June 2021 from the NBR to allow
discussions with PB and the Government to take place. Such discussions have
been delayed several times due to the COVID pandemic. On 14 June 2021 TBL
issued a formal notice of dispute under the PSC to the Government and PB. A
further request for payment was received from NBR on 28 October 2021 demanding
settlement by 15 November 2021. Arbitration proceedings were initiated under
the PSC on 29 December 2021 and subsequently, no further enforcement action
has been undertaken or threatened by NBR. The procedural hearing was held on
28 June 2022 which set the timetable for the process going forward. The first
submissions are being made in October 2022 with the hearing date in May 2024.
Timing of cash-flows
While it is not possible to estimate the timing of tax cash flows in relation
to possible outcomes with certainty. Management anticipate that there will not
be material cash taxes paid in excess of the amounts provided for uncertain
tax treatments in the next 12 months.
11. Disposals
There were no disposals in the six months ended 30 June 2022.
FID for the Tilenga Project in Uganda and the East African Crude Oil Pipeline
(EACOP) as reported by Total Energies Ltd on 1 February 2022 triggered a
contingent consideration of $75.0 million (offset by $7.1 million indemnity
relating to tax audits) in relation to Tullow's sale of its assets in Uganda
to Total in 2020 which was received on 16 February 2022.
Equatorial Guinea and Dussafu asset in Gabon
On 31 March 2021, the Group completed the sale of its assets in Equatorial
Guinea with a cash consideration received of $88.9 million. This transaction
included contingent future payments of up to $16.0 million which are linked to
asset performance and oil price. As per the SPA, a further $5.0 million of
additional consideration was also received on completion of Dussafu Marin
Permit in Gabon.
On 9 June 2021, the Group completed the asset sale of Dussafu Marin Permit in
Gabon with a cash consideration received of $39.0 million. This transaction
included contingent future payments of up to $24.0 million which are linked to
asset performance and oil price.
11. Disposals continued
Book value of assets disposed Equatorial Guinea Six months ended 30.06.21 Unaudited Dussafu Six months ended 30.06.21 Unaudited Total Six months ended 30.06.21 Unaudited
$m $m $m
Property, plant and equipment 72.9 52.0 124.9
Inventories 6.9 3.2 10.1
Other current assets 68.5 1.7 70.1
Total assets disposed 148.3 56.9 205.1
Trade and other payables (36.0) (18.5) (54.5)
Provisions (118.2) (4.7) (122.9)
Current tax liabilities (13.6) - (13.6)
Deferred tax liabilities (17.9) - (17.8)
Total liabilities disposed (185.7) (23.2) (208.8)
Net (liabilities)/ assets disposed (37.4) 33.7 (3.7)
Cash consideration 93.8 39.0 132.8
Transaction costs (8.4) (0.3) (8.7)
Gain on disposal(1) 122.8 5.0 127.8
Given Tullow no longer holds interest in the above assets, based on publicly
available information the Company has assessed that the asset performance
condition is not met. Accordingly, no contingent consideration has been
recognised as of 30 June 2022.
(1) In addition to $127.8 million gain on disposal recognised following the
Equatorial Guinea and Dussafu disposals, the Group recognised a loss of $5.0
million relating to its sale of Dutch assets to Hague and London Oil plc
(HALO) in 2017, and a gain of $0.1 million relating to other transactions
during the period (1H21: 122.9 million).
12. Intangible exploration and evaluation assets
Six months ended 30.06.22 Unaudited $m Six months ended 30.06.21 Unaudited $m Year ended 31.12.21 Audited $m
At 1 January 354.6 368.2 368.2
Additions 20.6 27.4 46.3
Exploration costs written off (86.6) (49.3) (59.9)
At 30 June/31 December 288.6 346.3 354.6
The below table provides a summary of the exploration costs written off on a
pre-tax basis by country.
Exploration costs written off Rationale for write-off six months ended 30.06.22 Write-off 30.06.22 Unaudited $m Remaining recoverable amount 30.06.22 Unaudited $m
Guyana a,d 84.2 -
Cote d'Ivoire b 2.0 -
Other a, b, c 0.4 -
Exploration costs written off 86.6 -
a. Licence relinquishments, expiry, planned exit or reduced activity
b. Current year expenditure on assets previously written off
c. New Ventures expenditure is written off as incurred
d. Unsuccessful well costs written off
In Kenya, the Group had received a 15-month licence extension from September
2020 to December 2021 which was contingent on certain conditions, including
submission of a technically and commercially compliant Field Development Plan
(FDP). On 10 December 2021 Tullow and its Joint Venture Partners submitted an
FDP to the Government of Kenya and fulfilled its licence obligations. The
Group expects a production licence to be granted once due Government process
has been completed. At 31 December 2021, in line with its accounting policy,
the Group has performed a VIU assessment of Kenya asset following
identification of triggers for impairment reversal. This resulted in an NPV
significantly in excess of the book value of $255.2 million. However, the
Group has identified the following uncertainties in respect to the Group's
ability to realise the estimated VIU; receiving and subsequently finalising an
acceptable offer from a strategic partner and securing governmental approvals
relating thereto, obtaining financing for the project and government
deliverables. These items require satisfactory resolution before the Group can
take FID.
Due to the binary nature of these uncertainties the Group was unable to either
adjust the cash flows or discount rate appropriately. It has therefore used
its judgement and assessed a probability of achieving FID and therefore the
recognition of commercial reserves. This probability was applied to the VIU to
determine a risk adjusted VIU and compared against the net book value of the
asset. Based on this there was no impairment or impairment reversal as at 31
December 2021.
Since 1 Jan 2022, there have been ongoing discussions with Government of Kenya
on the approval of FDP and securing government deliverables. The FDP is
currently under review with Government of Kenya with review period extended to
6 November 2022. In addition, Company continues to progress with the farm down
process with approvals being sought. However, as at 30 June 2022 the
uncertainties are largely unchanged and hence, no trigger for
impairment/impairment reversal was identified.
12. Intangible exploration and evaluation assets continued
Exploration costs written off Rationale for write-off six months ended 30.06.21 Write-off 30.06.21 Unaudited $m Remaining recoverable amount 30.06.21 Unaudited $m
Suriname b,c 56.9 -
Uganda d (15.3) -
Gabon c 1.7 -
Peru b 1.0 -
Cote d'Ivoire b 4.2 -
Other a,c 0.8 -
Exploration costs written off 49.3 -
a. Current year expenditure on assets previously written off
b. Licence relinquishments, expiry, planned exit or reduced activity
c. Unsuccessful well costs written off
d. Release of indirect tax provision following settlement
Exploration costs written off Rationale for write- Write-off 31.12.21 Unaudited $m Remaining recoverable amount 31.12.21 Unaudited $m
off year ended
31.12.21
Suriname b,d 58.9 -
Uganda c (15.3) -
Gabon d 2.2 -
Peru b 1.8 -
Cote d'Ivoire b 6.6 -
Other a 5.7 -
Total write-off 59.9
a. Current year expenditure on assets previously written off
b. Licence relinquishments, expiry, planned exit or reduced activity
c. Pre-licence exploration expenditure is written off as incurred
d. Unsuccessful well costs written off
e. Following VIU assessment as a result of reduction in long term oil price
assumption, using a pre-tax discount rate of 18%
f. Written down to the value of the transaction consideration.
13. Property, plant and equipment
Oil and gas assets Right of use Other property, plant and equipment Total six months Oil and gas assets Right of use Other property, plant and equipment Total Oil and gas assets Right of use Other property, plant and equipment Total
assets
six months
assets
six months
assets
six months
six months ended
six months
ended six months
six months
six months Year ended 31.12.21
Year ended
Year ended 31.12.21
ended
ended
ended
30.06.22 ended
30.06.22 ended ended
ended Audited ended
Audited
30.06.22
30.06.21
$m
31.12.21
$m
Unaudited 30.06.22
Unaudited 30.06.21 30.06.21
30.06.21 31.12.21
$m
Unaudited
$m
Unaudited
Audited
Unaudited
$m Unaudited Unaudited
$m Unaudited Audited
$m
$m
$m
$m
$m
$m
Cost
At 1 January 10,521.7 1,091.7 69.5 11,682.9 10,460.2 1,018.6 69.6 11,548.4 10,460.2 1,018.6 69.6 11,548.4
Additions 142.8 12.9 0.8 156.5 45.4 59.8 1.2 106.4 73.0 73.5 1.6 148.1
Acquisitions(1) 473.2 - - 473.2 - - - - - - - -
Transfer(2) - 86.6 - 86.6 - - - - - - - -
Disposals - - - - - - (0.8) (0.8) - - (1.4) (1.4)
Currency translation adjustments (113.5) (3.2) (3.7) (120.4) 15.4 0.4 0.5 16.3 (11.5) (0.4) (0.3) (12.2)
At 30 June/31 December 11,024.2 1,188.0 66.6 12,289.2 10,521.0 1,078.8 70.5 11,670.3 10,521.7 1,091.7 69.5 11,682.9
Depreciation, depletion and amortization and impairment
At 1 January (8,263.7) (450.8) (53.8) (8,768.3) (7,915.9) (352.3) (42.3) (8,310.5) (7,915.9) (352.3) (42.3) (8,310.5)
Charge for the year (155.7) (23.2) (4.6) (183.5) (145.4) (26.0) (7.3) (178.7) (304.9) (60.6) (13.4) (378.9)
Impairment loss (6.5) - - (6.5) (8.0) - - (8.0) (54.3) - - (54.3)
Capitalised depreciation - (23.4) - (23.4) - (14.2) - (14.2) - (38.0) - (38.0)
Disposal - - - - - - 0.8 0.8 - - 1.4 1.4
Currency translation adjustments 112.5 0.8 2.9 116.2 (15.4) - (0.2) (15.6) 11.4 0.1 0.5 12.0
At 30 June/31 December (8,313.4) (496.6) (55.5) (8,865.5) (8,084.7) (392.5) (49.0) (8,526.2) (8,263.7) (450.8) (53.8) (8,768.3)
Net book value at 30 June/31 December 2,710.8 691.4 11.1 3,413.3 2,436.3 686.3 21.5 3,144.1 2,258.0 640.9 15.7 2,914.6
(1)This relates to an acquisition through business combination discussed in
Note 18.
(2)As a result of Ghana pre-emption a proportionate amount has been
reclassified from receivables due from joint venture partners to right of use
assets relating to the Group's existing interest in lease contracts in the
joint operation.
The currency translation adjustments arose due to the movement against the
Group's presentation currency, USD, of the Group's UK assets which have
functional currencies of GBP.
Trigger for impairment/ (reversal) Impairment/ (reversal) 30.06.22 Remaining recoverable amount
six months ended 30.06.22 30.06.22 (unaudited)
(unaudited) $m
$m
Mauritania a 4.9 -
UK 'CGU' a, b 1.6 -
Impairment 6.5 -
a. Change to decommissioning estimate.
b. The fields in the UK are grouped into one CGU as all fields share critical
gas infrastructure.
13. Property, plant and equipment continued
Trigger for impairment six months ended 30.06.21 Impairment 30.06.21 Remaining recoverable amount
30.06.21 (unaudited)
(unaudited) $m
$m
Limande and Turnix CGU (Gabon) a (0.5) 6.7
UK 'CGU' a, b 8.5 -
Impairment 8.0 6.7
a. Change to decommissioning estimate.
b. The fields in the UK are grouped into one CGU as all fields share critical
gas infrastructure.
Trigger for impairment/ (reversal) year ended 31.12.21 Impairment/ (reversal) 31.12.21 Remaining recoverable amount
31.12.21 Pre-tax discount rate assumption (audited)
(audited) $m
$m
Limande and Turnix CGU (Gabon) a,c (40.8) 13% 50.8
Ezanga (Gabon) a,c (17.0) 15% 22.4
Oba and Middle Oba CGU (Gabon) a,c (3.2) 15% 10.5
Espoir (Cote d'Ivoire) a,c (8.7) 10% 81.4
TEN (Ghana) a,b,c 119.1 10% 1,171.4
Mauritania b 2.1 n/a -
UK 'CGU' b,d 2.8 n/a -
Impairment 54.3
a. Increase to short, medium and long-term oil price assumptions.
b. Change to decommissioning estimate.
c. Revision of value based on revision to reserves.
d. The fields in the UK are grouped into one CGU as all fields share critical
gas infrastructure.
e. The remaining recoverable amount of the asset is its value in use.
The Group applied the following nominal oil price assumption for impairment
assessments:
Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 onwards
FY 2021 $76/bbl $71/bbl $68/bbl $65/bbl $65/bbl $65/bbl inflated by 2%
14. Trade receivables
Trade receivables comprise amounts due for the sale of oil and gas. They are
generally due for settlement within 30-60 days and are therefore all
classified as current. The Group holds the trade receivable with the objective
of collecting the contractual cash flows and therefore measures them
subsequently at amortised cost using the effective interest method.
The balance of trade receivables as of 30 June 2022 of $290.2 million (1H
2021: $256.4 million; FY21: $99.8 million) mainly relates to June 2022 oil
liftings in Ghana, Gabon and Cote d'Ivoire which were settled in July 2022.
The increase is also due to increased oil prices as well as an additional
interest in Ghana following the pre-emption effective 17 March 2022.
15. Other assets
30.06.22 Unaudited $m 30.06.21 Unaudited $m 31.12.21 Audited $m
Non-current
Amounts due from joint venture partners(1) 314.4 514.9 486.0
VAT recoverable 2.9 - 3.1
317.3 514.9 489.1
Current
Amounts due from joint venture partners 584.0 586.3 554.7
Underlifts(2) 76.0 3.8 26.7
Prepayments 59.8 57.8 49.6
Other current assets(3) 6.8 396.1 73.5
726.6 1,044.0 704.5
1,043.9 1,558.9 1,193.6
(1) The decrease in non-current receivables from JV Partners compared to June
2021 and December 2021 mainly relate to reduction in time remaining on the TEN
FPSO lease, and to reduction in partner share following Ghana pre-emption.
(2) Underlifts of $76.0 million as at 30 June 2022 are due to the timing of
liftings and are mainly attributable to Jubilee field in Ghana.
(3) The decrease in other current assets compared to June 2021 and December
2021 is mainly due to a collection of the deferred consideration relating to
the Uganda disposal in March 2022 ($67.9 million net) and a release of $309.8
million of funds held in a trust to settle principal plus interest of the
Convertible Bond, which was subsequently repaid in July 2021.
16. Inventories
30.06.22 Unaudited $m 30.06.21 Unaudited $m 31.12.21 Audited $m
Warehouse stock and materials 53.7 71.5 55.5
Oil stock 279.6 69.8 79.3
333.3 141.3 134.8
The increase in oil stock is mainly associated with the timing of liftings in
Ghana ($86 million) as well as Gabon due to Cap Lopez spillage which delayed
lifting by a month ($112 million).
17. Cash and cash equivalents
30.06.22 Unaudited $m 30.06.21 Unaudited $m 31.12.21 Audited $m
Cash at bank 90.4 138.0 226.1
Short- term deposits and other cash equivalents 73.7 163.8 243.0
164.1 301.8 469.1
Cash and cash equivalents include an amount of $51.8 million (1H 2021: $72.0
million; FY21: $92.4 million) which the Group holds as operator in joint
venture bank accounts. Included within cash at bank is $3.8 million (1H 2021:
$67.4 million; FY21: $0.8 million) as the Group's share of security for the
Letters of Credit (LC) issued in relation to decommissioning activities.
18. Business combination
Accounting policy
The acquisition method of accounting is used to account for all business
combinations, regardless of whether equity instruments or other assets are
acquired. The consideration transferred for the acquisition comprises of:
· fair values of the assets transferred
· liabilities incurred to the former owners of the acquired
business
· equity interests issued by the group
· fair value of any asset or liability resulting from a contingent
consideration arrangement, and
· fair value of any pre-existing equity interest in the subsidiary.
The Group determines that it has acquired a business when the acquired set of
activities and assets include an input and a substantive process that together
significantly contribute to the ability to create outputs. The acquired
process is considered substantive if it is critical to the ability to continue
producing outputs, and the inputs acquired include an organised workforce with
the necessary skills, knowledge, or experience to perform that process or it
significantly contributes to the ability to continue producing outputs and is
considered unique or scarce or cannot be replaced without significant cost,
effort, or delay in the ability to continue producing outputs.
Identifiable assets acquired and liabilities and contingent liabilities
assumed when control is obtained over a business, and when an interest or an
additional interest is acquired in a joint operation which is a business are,
with limited exceptions, measured initially at their fair values at the
acquisition date.
Acquisition-related costs are expensed as incurred.
The excess of the consideration transferred, amount of any non-controlling
interest in the acquired entity, and acquisition-date fair value of any
previous equity interest in the acquired entity over the fair value of the net
identifiable assets acquired is recorded as goodwill. If those amounts are
less than the fair value of the net identifiable assets of the business
acquired, the difference is recognised directly in profit or loss as a bargain
purchase.
Summary of acquisition
On 17 March 2022 the Group completed the pre-emption related to the sale of Occidental Petroleum's ("Oxy") interests in the Jubilee and TEN fields in Ghana to Kosmos Energy. As a result of this acquisition, the Group's interest in the TEN fields increased from 47.18% to 54.84%, and from 35.48% to 39.0% in the Jubilee field. Tullow did not obtain control as a result of this transaction, as all joint venture partners retain joint control.
The total purchase consideration, which was funded from cash on the balance sheet, comprises of $118.2 million cash settled on completion, and $8.6 million subsequent post-completion adjustment paid in May 2022. There is no element of contingent consideration included in the purchase price.
18. Business combination continued
The fair values of the identifiable assets and liabilities acquired were:
Fair value recognised on acquisition Unaudited
$m
Property, plant and equipment 473.2
Inventories 12.1
Other current assets 31.4
Total assets acquired 516.7
Trade and other payables (10.5)
Provisions (61.6)
Deferred tax liabilities (143.6)
Total liabilities assumed (215.5)
Net identifiable assets acquired 301.0
Purchase consideration transferred (126.8)
Deemed settlement of provision 22.6
Gain on bargain purchase 196.8
There were no acquisitions in the six months ended 30 June 2021 and year ended
31 December 2021.
The property, plant and equipment acquired through the business combination
has been recognised at the fair value based on the net present value of the
discounted future cash flows. Significant inputs to the valuation include
short- and long-term commodity prices, reserve estimates, production volume
profiles, planned development expenditure, cost profiles and discount rates,
and are consistent with those applied by the management when testing assets
for impairments.
The fair value of acquired other receivables is nil. The gross contractual
amount for other receivables due is $0.9 million, with a loss allowance of
$0.9 million recognised on acquisition.
The deferred tax liability mainly comprises the tax effect of the accelerated
depreciation for tax purposes of tangible assets.
Contingent liabilities recognised in a business combination
A contingent liability recognised in a business combination is initially
measured at its fair value. Subsequently, it is measured at the higher of the
amount that would be recognised in accordance with the requirements for
provisions as per IAS 37 "Provisions, Contingent Liabilities and Contingent
Assets", or the amount initially recognised less (when appropriate) cumulative
amortisation recognised in accordance with the requirements for revenue
recognition.
As part of pre-emption Tullow has taken on pro-rated exposure relating to
Anadarko WCTP Company's ("Anadarko") BPRT and AOE disputed claims. In February
2018, Anadarko, whom Oxy acquired the interests from, received a provisional
assessment for AOE for US$346.6 million, including a penalty of $329.5
million, (the portion of this claim related to Tullow's acquired interests was
$67.2 million) covering financial years 2006 - 2016 and in November 2018 the
Ministry of Finance confirmed that the assessment was suspended pending the
Government reaching a final view on the basis for calculating AOE. Anadarko
continued to dispute the AOE assessment issued and considered no AOE was
payable for these periods. In September 2021, Anadarko received a revised tax
audit report from the Ghana Revenue Authority ("GRA") for the financial years
2014 to 2018 including a $228.3m branch profits remittance tax (BPRT)
assessment (including late payment interest of $52.1m) (the portion of this
claim related to Tullow's acquired interests was $67.1 million). The Anadarko
BPRT assessment is covered by a Notice of Dispute issued in June 2020.
A contingent liability at fair value of $36.8 million was recognised at the acquisition date for provisions resulting from certain contractual indemnities. There was no change in provision as at 30 June 2022.
18. Business combination continued
Revenue and net profit contribution
The acquired business contributed revenues of $nil and net profit of $15.8
million to the group for the period from 17 March 2022 to 30 June 2022. If the
acquisition had occurred on 1 January 2022, consolidated pro-forma revenues
would have been $nil and consolidated pro-forma profit for the period ended 30
June 2022 would have been $18.4 million.
These amounts have been calculated using the acquired interest's results and
adjusting them for the additional depreciation and amortisation that would
have been charged assuming the fair value adjustments to property, plant and
equipment had applied from 1 January 2022, together with the consequential tax
effects.
Acquisition-related costs
Acquisition-related costs of $0.6 million are included in administrative
expenses in the statement of profit or loss and in operating cash flows in the
statement of cash flows.
Recognition of gain on bargain purchase
The difference between the fair value of net assets acquired and consideration
paid was recognised within the income statement as gain on bargain purchase of
$196.8 million. This is mostly due to the change in the oil markets from 2021,
when the transaction between Occidental Petroleum and Kosmos Energy was
negotiated to March 2022, when the acquisition was completed by Tullow. The
consideration paid by Tullow for the acquired interest was based on the
proportionate consideration agreed between Occidental Peteroleum and Kosmos
Energy, subject to completion adjustments. Additionally, the original
transaction between the two parties was driven by the seller's intention to
leave the region and dispose of the non-core elements of portfolio which it
had acquired from Anadarko Petroleum in August 2019.
19. Trade and other payables
30.06.22 Unaudited $m 30.06.21 Unaudited Restated(1) $m 31.12.21 Audited $m
Non-current
Other non-current liabilities(2) 45.1 81.2 75.2
Non-current portion of leases 837.2 1,001.0 911.9
882.3 1,082.2 987.1
Current
Trade payables 54.8 53.4 60.2
Other payables 62.0 56.7 57.4
Overlift 93.9 77.7 0.7
Accruals(3) 403.2 388.0 381.3
Current portion of leases 214.9 242.9 251.5
828.8 818.7 751.1
(1) Non-current and current portion of leases amounts as at 30 June 2021 have
been restated to correct a balance sheet classification error. The non-current
portion of leases was understated, and current portion of leases was
overstated by $68.9 million, which equates to the present value of the current
finance costs.
(2) Other non-current liabilities include balances related to JV Partners.
(3) Accruals mainly relate to capital expenditure, interest expense on bonds
and loans and staff related expenses.
Trade and other payables are non-interest bearing except for leases.
Payables related to operated joint ventures (primarily related to Ghana and
Kenya) are recorded gross with the debit representing the partners' share
recognised in amounts due from joint venture partners (note 15). The change in
trade payables and in other payables predominantly represents timing
differences and levels of work activity.
The overlift position of $93.9 million as at 30 June 2022 are due to the
timing of liftings and are attributable to TEN ($37.7 million), and Gabon
($56.2 million). This is an increase of $93.2 million and $16.2 million from
December 2021 and June 2021, respectively.
19. Trade and other payables continued
On 2 April 2021 the Group contracted Maersk Venturer offshore drilling rig to
undertake the drilling work programme for Jubilee and TEN fields in Ghana. As
at 30 June 2022, Tullow carries a right of use assets of $9.8 million (1H 21:
$43.0 million; FY21: $25.8 million), and gross lease liability of $20.6
million (1H 21: $97.3 million; FY21: $59.9 million) as Tullow entered the
lease on behalf of the JV. A receivable from JV Partners of $10.2 million (1H
21: $53.5 million; FY21: $33.0 million has been recognised in other assets to
reflect the value of future payments that will be met by cash calls from JV
Partners (see note 15). The lease has been recognised for an 18-month term, in
line with the early termination option included in the contract and approvals
received by the JV Partners. In July 2022 the contract has been extended for a
12-month term ending September 2023. Refer to note 24. Events since 30 June
2022.
20. Borrowings
30.06.22 Unaudited $m 30.06.21 Unaudited $m 31.12.21 Audited $m
Current
Borrowings - within one year
6.625% Convertible Bonds due 2021 ($300 million) - 297.8 -
10.25% Senior Notes due 2026 ($1,800 million) 100.0 - 100.0
Carrying value of total current borrowings 100.0 297.8 100.0
Non-current
Borrowings - after one year but within five years
7.00% Senior Notes due 2025 ($800 million) 792.5 791.6 792.1
10.25% Senior Notes due 2026 ($1800 million) 1,578.2 1,773.9 1,676.6
Carrying value of total non-current borrowings 2,370.7 2,565.5 2,468.7
Carrying value of total borrowings 2,470.7 2,863.3 2,568.7
In May 2021, the Group completed a comprehensive refinancing of its debt with
the issuance of a five-year $1.8 billion Senior Secured Notes ("2026 Notes")
and $500 million Super Senior Revolving Credit Facility (SSRCF) which will
primarily be used for working capital purposes. The 2026 Notes, maturing in
May 2026, require an annual prepayment of $100 million, in May, of the
outstanding principal amount plus accrued and unpaid interest and payment of
$1.3 billion on 2026. On 13 May 2022, the Group made the mandatory prepayment
of $100 million of the 2026 Notes, which reduced total debt to $2.5 billion.
As at 30 June 2022, net debt was $2,336 million (1H21: $2,290 million).
Management regularly reviews options for optimising the Group's capital
structure and may purchase outstanding debt securities or repay debt from time
to time in open-market purchases and/or privately negotiated transactions,
upon such terms and at such prices as it may determine.
The Convertible Bonds due 2021 were settled on 12 July 2021.
The Senior Notes due 2025 are payable in a single payment in March 2025.
The SSRCF, maturing in December 2024, comprises of (i) a $500 million
revolving credit facility and (ii) a $100 million letter of credit facility.
The revolving credit facility remains undrawn as at 30 June 2022. Letters of
credit amounting to $50.4 million have been issued under the facility.
Unamortised debt arrangement fees for the 2026 Notes, the Senior Notes due
2025 and the SSRCF are $21.8 million, $7.5 million and $6.1 million
respectively.
The 2026 Notes and the SSRCF are senior secured obligations of Tullow Oil Plc
and are guaranteed by certain of the Group's subsidiaries.
Capital management
The Group defines capital as the total equity and net debt of the Group.
Capital is managed in order to provide returns for shareholders and benefits
to stakeholders and to safeguard the Group's ability to continue as a going
concern. Tullow is not subject to any externally imposed capital requirements.
To maintain or adjust the capital structure, the Group may put in place new
debt facilities, issue new shares for cash, repay debt, engage in active
portfolio management, adjust the dividend payment to shareholders, or
undertake other such restructuring activities as appropriate. No significant
changes were made to the capital management objectives, policies or processes
during the half year ended 30 June 2022. The Group monitors capital on the
basis of the gearing, being net debt divided by adjusted EBITDAX, and
maintains a target of less than 1x.
20. Borrowings continued
SSRCF covenants
The SSRCF does not have any financial maintenance covenants. Availability
under the $500 million cash tranche of the facility is determined on an annual
basis with reference to the Net Present Value of the 2P reserves of the Group
(2P NPV) at the end of the preceding calendar year. SSRCF debt capacity is
calculated as 2P NPV divided by 1.1x less senior secured debt outstanding.
Senior Notes covenants
The Senior Notes due 2025 and the 2026 Notes are subject to customary high
yield covenants including limitations on debt incurrence, asset sales and
restricted payments such as dividends. The key debt incurrence covenant is the
Fixed Charge Cover Ratio ("FCCR").
The FCCR is the ratio of the Consolidated Cash Flow to the Fixed Charges for
the previous twelve months. The 'Consolidated Cash flow' essentially
represents an Adjusted EBITDAX calculation. The Fixed Charges represent the
aggregate financial charges related to the Company's indebtedness i.e.
interest on all of the Group's borrowings and interests under capital leases
less any finance revenues. The Company may incur additional financial
indebtedness if the FCCR for the Company's most recently ended two full fiscal
half-years immediately preceding the date on which such additional
indebtedness is incurred would have been at least 2.25 to 1.0 on a proforma
basis. Drawdowns under the SSRCF are not subject to the FCCR covenant and are
always permitted subject to the availability calculation set out above. There
has been no debt incurrence event since the 2026 Notes have been issued.
21. Provisions
Decommissioning 30.06.22 Other provisions 30.06.22 Unaudited $m Total 30.06.22 Unaudited $m Decommissioning 30.06.21 Other provisions 30.06.21 Unaudited $m Total 30.06.21 Unaudited $m Decommissioning 31.12.21 Audited $m Other provisions 31.12.21 Audited $m Total 31.12.21 Audited $m
Unaudited $m Unaudited $m
At 1 January 498.7 228.8 727.5 696.1 154.6 850.7 696.1 154.6 850.7
New provisions, changes in estimates and reclassifications (2.4) (18.8) (21.2) (17.3) 36.5 19.2 (134.8) 90.0 (44.8)
Acquisitions(1) 24.8 36.8 61.6 - - - - - -
Payments (32.5) (77.5) (110.0) (36.6) (8.9) (45.5) (69.3) (15.7) (85.0)
Unwinding of discount 3.2 - 3.2 3.7 - 3.7 7.6 - 7.6
Currency translation adjustment (10.5) (1.7) (12.2) 2.3 0.4 2.6 (0.9) (0.1) (1.0)
At 30 June/31 December 481.3 167.6 648.9 648.2 182.6 830.8 498.7 228.8 727.5
Current provisions 106.1 99.1 205.2 116.9 138.4 255.3 101.2 195.3 296.5
Non-current provisions 375.2 68.5 443.7 531.3 44.2 575.5 397.5 33.5 431.0
(1)This relates to an acquisition through business combination discussed in
Note 18.
Other provisions include non-income tax provision and disputed cases and claims.
The decommissioning provision represents the present value of decommissioning
costs relating to the European and African oil and gas interests.
The Group has assumed cessation of production as the estimated timing for
outflow of expenditure. However, expenditure could be incurred prior to
cessation of production or after and actual timing will depend on a number of
factors including, underlying cost environment, availability of equipment and
services and allocation of capital.
In 2022, the Group has increased the decommissioning discount rate by 0.5%
from 31 December 2021 (2021: increase by 0.5% from 31 December 2020) due to
movement in the risk-free rate. This resulted in a decrease of the provision
by $8.7 million in Ghana (2021: 23.7 million), $4.2 million in Gabon (2021:
$4.3 million) and $3.6 million in Cote d'Ivoire (2021: $3.7 million).
Above includes provision relating to a potential claim arising out of
historical contractual agreement. Further information is not provided as it
will be seriously prejudicial to the Company's interest.
In January 2013, the Group acquired Spring Energy Norway AS (Spring) from
HitecVision V (Hitec), a Norwegian private equity company, and Spring employee
minority shareholders. In addition to the initial consideration payable under
the sale and purchase agreement for Spring, the Group undertook to make
contingent bonus payments to Hitec and the Spring employee minority
shareholders in the event of the discovery on or before 31 December 2016 of
commercially viable reserves from four identified drilling prospects
(including the Wisting prospect in licence PL537).
HiTec previously claimed that the conditions for a bonus payment under the
Spring SPA had been met in respect of the Wisting prospect in PL537 as at 31
December 2016. Tullow disputed this position. In 2016, the Group sold its
interest in PL537 to Equinor but remained responsible for this dispute. An
arbitration took place in Norway in Q4 2021 to resolve this issue.
On 15 February 2022, the arbitration panel delivered an award in favour of
HiTec. The Tribunal decided by way of split decision that conditions under the
Spring SPA in respect of the bonus payment had been met. The Tribunal ruled
that Tullow should pay $76 million to HiTec (an amount which includes
interest and costs) and a further amount of $0.7 million in respect of
Tribunal costs. This was settled in March 2022.
22. Called up share capital and share premium
As at 30 June 2022, the Group had in issue 1,438.3 million allotted and fully
paid ordinary shares of GBP 10 pence each (1H 21: 1,429.0 million, FY21:
1,432.1 million).
In the six months ended 30 June 2022, the Group issued 6.2 million shares in
respect of employee share options (1H 21: 14.9 million; FY21: 18.0 million new
shares in respect of employee share options).
23. Contingent Liabilities
30.06.22 Unaudited $m 30.06.21 Unaudited $m 31.12.21 Audited $m
Contingent liabilities
Performance guarantees 89.6 102.8 100.8
Other contingent liabilities 60.2 83.6 14.0
149.8 186.4 114.8
Performance guarantees are in respect of abandonment obligations, committed
work programmes and certain financial obligations.
Other contingent liabilities
This includes amounts for ongoing legal disputes with third parties where we consider the likelihood of cash outflow to be higher than remote but not probable. The timing of any economic outflow if it were to occur would likely range between one and five years.
24. Events since 30 June 2022
Adjusting events
On 5 August 2022, the Beebei-Potaro commitment well, offshore Guyana, has been
plugged and abandoned after encountering good quality reservoir in the primary
and secondary targets, but both targets were water bearing. This will be
treated as an adjusting post balance sheet event as it represents confirmation
of the subsurface position being tested by the well as at 30 June. As a
result, the well and residual costs have been written off on Kanuku ($62
million) and the Orinduik ($22 million) blocks.
Non-adjusting events
In July 2022 the Group extended the contract for Maersk Venturer offshore
drilling rig initially hired in April 2021 to undertake the drilling work
programme for Jubilee and TEN fields in Ghana. The extension has been
recognised for a 12-month term ending September 2023, in line with the
approvals received by the JV Partners. This resulted in a $80.2 million
increase to a gross lease liability, and a corresponding uplift to a lease
asset of $41.2 million. A receivable from JV Partners of $39.0 million has
been recognised in other assets to reflect the value of future payments that
will be met by cash calls from JV Partners.
25. Cash flow statement reconciliations
Movement in borrowings 1H 22 $m FY 21 $m 1H 21 $m FY 20 $m 1H22 Movement 1H21 Movement 2021 Movement
Borrowings 2,470.7 2,568.7 2,863.3 3,170.5 (98.0) (307.2) (601.8)
Associated cash flows
Debt arrangement fees - (57.8) (56.6)
Repayment of borrowings(1) (100.0) (2,080.0) (2,379.9)
Drawdown of borrowings - 1,800 1,800
Non-cash movements/presented in other cash flow lines
Amortisation of arrangement fees and accrued interest 2.0 30.6 34.7
(1)Refer to note 19 for the detailed explanation of the repayment of
borrowings in 2021 related to a comprehensive refinancing of the Group's debt.
Commercial Reserves and Contingent Resources summary working interest basis
Ghana Non-Operated Kenya Exploration Total
Oil mmbbl Gas bcf Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Oil mmbbl Gas Total
bcf
bcf
bcf
bcf mmboe
COMMERCIAL RESERVES(1)
1 January 2022 168.3 138.9 38.8 7.1 - - - - 207.1 145.9 231.4
Revisions(,3,4) - - 0.2 - - - - - 0.2 - 21.8
Acquisitions (2) 19.2 13.7 - - - - - - 19.2 13.7 21.6
Production (7.8) - (3.0) (0.9) - - - - (10.8) (0.9) (11.0)
30 June 2022 179.7 152.6 36.0 6.2 - - - - 215.7 158.8 242.2
CONTINGENT RESOURCES(1)
1 January 2022 212.1 585.2 29.7 0.9 231.4 - 54.5 - 527.7 586.1 625.4
Revisions(3) - - (0.2) - - - - - (0.2) - 42.9
Acquisitions (2) 29.0 84.2 - - - - - - 29.0 84.2
30 June 2022 241.1 669.4 29.5 0.9 231.4 - 54.5 - 556.5 670.3 668.2
TOTAL
30 June 2022 420.7 822.0 65.5 7.1 231.4 - 54.5 - 772.1 829.0 910.4
( )
(1)Proven and Probable Reserves & Contingent Resources above are as
audited and reported by independent third-party reserve auditors as of 31
December 2021 and adjusted for Working Interest changes in Ghana assets and
production to 30 June
2022.
(2)Reserves and resources acquisitions in Ghana relates to increase in
interest from successful pre-emption right in both Jubilee and TEN Assets on
17th March 2022.
(3)Reserves revision in Non-Operated (Gabon & CDI) relates to booking of
reserves in Etame which represents Tullow's share in future productions
following licence extension.
(4)No revision on Kenya and Guyana Resources.
The Group provides for depletion and amortisation of tangible fixed assets on
a net entitlement basis, which reflects the terms of the Production Sharing
Contracts related to each field. Total net entitlement reserves were 231.8
mmboe at 30 June 2022 (31 December 2021: 222.0 mmboe).
Contingent Resources relate to resources in respect of which development plans
are in the course of preparation or further evaluation is under way with a
view to future
development.
Alternative performance measures
The Group uses certain measures of performance which are not specifically
defined under IFRS or other generally accepted accounting principles. These
non-IFRS measures include capital investment, net debt, gearing, adjusted
EBITDAX, underlying cash operating costs, free cash flow, underlying operating
cash flow and pre-financing free cash flow.
Capital investment
Capital investment is defined as additions to property, plant and equipment
and intangible exploration and evaluation assets less decommissioning asset
additions, right-of-use asset additions, additions to administrative assets
and certain other adjustments. The Directors believe that capital investment
is a useful indicator of the Group's organic expenditure on exploration and
appraisal assets and oil and gas assets incurred during a period because it
eliminates certain accounting adjustments such as decommissioning asset
adjustments.
1H 2022 1H 2021
Additions to property, plant and equipment 156.5 106.4
Additions to intangible exploration and evaluation assets 20.6 27.4
Less
Decommissioning asset adjustments 22.4 (17.3)
Right-of-use asset additions 12.9 59.8
Lease payments related to capital activities (19.5) (8.7)
Additions to administrative assets 0.8 1.2
Other non-cash capital expenditure 4.5 (2.4)
Capital investment 156.0 101.2
Movement in working capital (22.0) (5.2)
Additions to administrative assets 0.8 1.2
Cash capital expenditure per the cash flow statement 134.8 97.2
Net debt
Net debt is a useful indicator of the Group's indebtedness, financial
flexibility and capital structure because it indicates the level of cash
borrowings after taking account of cash and cash equivalents within the
Group's business that could be utilised to pay down the outstanding cash
borrowings. Net debt is defined as current and non-current borrowings plus
non-cash adjustments, less payments to convertible bond trustees and cash and
cash equivalents. Non-cash adjustments include unamortised arrangement fees,
adjustment to convertible bonds, and other adjustments. The Group's definition
of net debt does not include the Group's leases as the Group's focus is the
management of cash borrowings and a lease is viewed as deferred capital
investment. The value of the Group's lease liabilities as at 30 June 2022 was
$214.9 million current and $837.2 million non-current; it should be noted that
these balances are recorded gross for operated assets and are therefore not
representative of the Group's net exposure under these contracts.
1H 2022 1H 2021
Current borrowings 100.0 297.8
Non- current borrowings 2,370.7 2,565.5
Non-cash adjustments(1) 29.4 38.3
Payment to Convertible Bond trustees(2) - (309.8)
Less cash and cash equivalents(3) (164.1) (301.8)
Net debt 2,336.0 2,290.0
(1) Non-cash adjustments include unamortised arrangement fees which are
incurred on creation or amendment of borrowing facilities. as well as the
Convertible Bonds which were measured at fair value. The difference between
the fair value and the principal of the bond was included as a component of
equity and a decrease to borrowings. Over the life of the Convertible Bond,
the fair value reduces until the carrying value of the borrowings is equal to
the principal outstanding for repayment on maturity.
(2) As part of the refinancing, it was agreed that Tullow would pay $300
million plus coupon of $10 million to the Convertible Bonds Paying Agent
(Deutsche Bank) on 17 May 2021. This amount was held in Trust until repayment
on maturity date of 12 July 2021.
(3) Cash and cash equivalents include an amount of $51.8 million (1H 2021:
$72.0 million) which the Group holds as operator in JV bank accounts. Included
within cash at bank is $3.8 million (1H 2021: $67.4 million) as the Group's
share of security for the Letters of Credit (LC) issued in relation to
decommissioning activities.
Gearing and Adjusted EBITDAX
Gearing is a useful indicator of the Group's indebtedness, financial
flexibility and capital structure and can assist securities analysts,
investors and other parties to evaluate the Group. Gearing is defined as net
debt divided by adjusted EBITDAX. This definition of gearing differs from the
one included in the RBL facility agreements. Adjusted EBITDAX is defined as
profit/(loss) from continuing activities adjusted for income tax
(expense)/credit, finance costs, finance revenue, gain on hedging instruments,
depreciation, depletion and amortisation, share-based payment charge,
restructuring costs, gain/(loss) on disposal, gain on bargain purchase,
exploration cost written off, impairment of property, plant and equipment net,
and provision for onerous service contracts.
1H 2022 1H 2021
Adjusted EBITDAX(1) 1,262.6 884.9
Net debt 2,336.0 2,290.0
Gearing (times) 1.9 2.6
(1) Last 12 months (LTM). Refer to the 2021 Annual Report and Accounts and
2021 Half year results for a full reconciliation of 2021 and 1H2021 Adjusted
EBITDAX.
Underlying cash operating costs
Underlying cash operating costs is a useful indicator of the Group's costs
incurred to produce oil and gas. Underlying cash operating costs eliminates
certain non-cash accounting adjustments to the Group's cost of sales to
produce oil and gas. Underlying cash operating costs is defined as cost of
sales, depletion and amortisation of oil and gas assets, underlift, overlift
and oil stock movements, share-based payment charge included in cost of sales,
and certain other cost of sales. Underlying cash operating costs are divided
by production to determine underlying cash operating costs per boe.
1H 2022 1H 2021
Cost of sales 225.4 405.7
Add
Lease payments related to operating activity 7.9 9.2
Less
Depletion and amortisation of oil and gas and leased assets(1) 176.9 169.5
Underlift, overlift and oil stock movements(2) (119.9) 89.5
Share-based payment charge included in cost of sales(3) 0.2 0.4
Other cost of sales(4) 33.4 12.2
Underlying cash operating costs 142.7 143.3
Non-recurring costs(5) (14.4) (4.9)
Total normalised operating costs 128.3 138.4
Production (MMboe) 11.0 11.1
Underlying cash operating costs per boe ($/boe) 13.0 12.9
Normalised cash operating costs per boe ($/boe) 11.6 12.5
(1) Depletion and amortisation of oil and gas assets is the depreciation and
amortisation of the Group's oil and gas assets over the life of an asset on a
unit of production basis.
(2) Under lifting or offtake arrangements for oil and gas produced in certain
operations in which the Group has interests with other commercial partners,
each participant may not receive and sell its precise share of the overall
production in each period. The resulting imbalance between cumulative
entitlement and cumulative production less stock constitutes "underlift" or
"overlift". Underlift and overlift are valued at market value and included
within other current assets and other current payables on the Group's balance
sheet, respectively. Movements during an accounting period are charged to cost
of sales rather than charged through revenue, and as a result gross profit is
recognised on an entitlements basis.
(3) Share-based payment charge included in cost of sales relates to the
portion of the non-cash share-based payment charge that relates to employees
who work on operational projects.
(4) Other cost of sales includes purchases of gas from third parties to fulfil
gas sales contracts and royalties paid in cash.
(5) Non-recurring costs include COVID-19 costs, OOSYS (Oil offloading system)
costs, CSV (Construction Support Vessel) campaign costs and shutdown costs.
Free cash flow
Free cash flow is a useful indicator of the Group's ability to generate cash
flow to fund the business and strategic acquisitions, reduce borrowings and
provide returns to shareholders through dividends. Free cash flow is defined
as net cash from operating activities, and net cash used in investing
activities, less debt arrangement fees, repayment of obligations under leases,
finance costs paid and foreign exchange gain/ (loss).
1H 2022 1H 2021
Net cash from operating activities 208.6 258.1
Net cash (used) in/from investing activities (191.9) 36.9
Debt arrangement fees - (57.8)
Repayment of obligations under leases (91.9) (68.3)
Finance costs paid (126.2) (86.9)
Foreign exchange (loss)/ gain (3.6) 4.2
Free cash flow (205.0) 86.2
Underlying operating cash flow
This is a useful indicator of the Group's assets ability to generate cash flow
to fund further investment in the business, reduce borrowings and provide
returns to shareholders. Underlying operating cash flow is defined as net cash
from operating activities less repayments of obligations under leases plus
decommissioning expenditure.
Pre-financing free cash flow
This is a useful indicator of the Group's assets ability to generate cash flow
to reduce borrowings and provide returns to shareholders through dividends.
Pre-financing free cash flow is defined as net cash from operating activities,
and net cash used in investing activities, less repayment of obligations under
leases and foreign exchange gain.
1H 2022 1H 2021
Net cash from operating activities 208.6 258.1
Less
Decommissioning expenditure 28.8 27.7
Lease payments related to capital activities 19.5 8.7
Plus
Repayment of obligations under leases (91.9) (68.3)
Underlying operating cash flow 165.0 217.5
Net cash (used) in/ from investing activities (191.9) 36.9
Decommissioning expenditure (28.8) (27.7)
Lease payments related to capital activities (19.5) (8.7)
Pre-financing free cash flow (75.2) 226.7
WEBCAST - 9:00 BST
To access the webcast please use the following link and follow the
instructions provided: https://web.lumiconnect.com/145-356-205
(https://web.lumiconnect.com/145-356-205)
A replay will be available on the website from midday on 14 September 2022:
https://www.tullowoil.com/investors/results-reports-and-presentations/
(https://www.tullowoil.com/investors/results-reports-and-presentations/)
Contacts
Tullow Oil plc Camarco
(London) (London)
(+44 20 3249 9000) (+44 20 3781 9244)
George Cazenove (Media) Billy Clegg
Robert Hellwig (Investors) Georgia Edmonds
Matthew Evans (Investors) Rebecca Waterworth
Notes to editors
Tullow is an independent oil & gas, exploration and production group which is quoted on the London, Irish and Ghanaian stock exchanges (symbol: TLW) and is a constituent of the FTSE250 index. The Group has interests in over 35 exploration and production licences across seven countries. In March 2021, Tullow committed to becoming Net Zero on its Scope 1 and 2 emissions by 2030.
For further information, please refer to our website at
www.tullowoil.com (http://www.tullowoil.com)
.
Follow Tullow on:
Twitter: www.twitter.com/TullowOilplc (http://www.twitter.com/TullowOilplc)
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(http://www.linkedin.com/company/Tullow-Oil)
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