17 March 2022 - Neptune Energy
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17 March 2022
Except as the context otherwise indicates, ’Neptune’ assumptions that we consider reasonable, are subject This presentation contains non-GAAP and non-IFRS
or ‘Neptune Energy’, ‘Group’, ‘we’, ‘us’, and ‘our’, to risks and uncertainties which could cause actual measures and ratios that are not required by, or
refers to the group of companies comprising Neptune events or conditions to materially differ from those presented in accordance with, any generally accepted
Energy Group Midco Limited (‘the Company’) expressed or implied by the forward-looking accounting principles (‘GAAP’) or IFRS. These non-IFRS
and its consolidated subsidiaries and equity-accounted statements. While these forward-looking statements and non-GAAP measures and ratios may not be
investments. are based on our internal expectations, estimates, comparable to other similarly titled measures of other
projections, assumptions and beliefs as at the date of companies and have limitations as analytical tools and
In this presentation, unless otherwise indicated, our such statements or information, including, among should not be considered in isolation or as a substitute
production, reserves and resources figures are other things, assumptions with respect to production, for analysis of our operating results as presentation
presented on a basis including our ownership share future capital expenditures and cash flow, we caution under IFRS or GAAP. Non-IFRS and non-GAAP
of volumes of companies that we account for under you that the assumptions used in the preparation of measures and ratios are not measurements of our
the equity accounting method, in particular, for the such information may prove to be incorrect and no performance or liquidity under IFRS or GAAP and
interest held in the Touat project in Algeria through assurance can be given that our expectations, or should not be considered as alternatives to operating
a joint venture company. Production for interests held the assumptions underlying these expectations, will profit or profit from continuing operations or any
under production sharing contracts is presentation on prove to be correct. other performance measures derived in accordance
an appropriate unit of production basis. with IFRS or GAAP or as alternatives to cash flow from
Any forward-looking statements that we make in this operating, investing or financing activities.
The discussion in this presentation includes forward- presentation speak only as of the date of such
looking statements which, although based on statement or the date of this presentation.
Sam Laidlaw, Executive Chairman
Introduction
Creating growth, accelerating the transition
– HSE remains our highest – Aim to store more carbon – 2021 earnings and OCF – Shorter-term focus
priority than we emit by 2030 higher on strong prices in strong price environment
– FY21 production in – Lower carbon energy – Strong level of liquidity to – Development capex lower as
line with guidance production: electrification support growth projects complete
– 2022 guidance higher at – Integrated energy hubs: – Low leverage supported – Short-cycle projects,
135-145 kboepd gas, CCS(1) and hydrogen by stronger EBITDAX low break-even prices
– Projects drive production – Utilise existing – Tax charge of $1 billion in – Exploration spend lower,
to c.170 kboepd in 2023 infrastructure, capabilities 2021, tax rate 72% focused around existing hubs
1. Carbon capture and storage.
Introduction
Diversified portfolio, strong balance sheet, lower carbon strategy
– Geographically diversified OECD-
focused portfolio, access to key markets
– Gas-weighted reserves and production,
strong growth potential
– Balanced commodity price Gas 41%
exposure, gas, oil and LNG
Geopolitical risk, Renewables 33%
energy nationalism,
investment gap – Near-term returns through
short cycle investments Oil 26%
– Hub strategy integrates gas, – Active hedging programme,
electrification, CCS, hydrogen future cash flow protection Nuclear 8%
– Leading ESG ratings, accelerating Macro – Low break-even costs, low
lower carbon projects factors leverage, strong liquidity Coal (12%)
– Produce lower carbon gas and
oil safely and efficiently High and volatile 4%
Net zero, ESG Other
prices, regulatory
financing, legislative
uncertainty, supply
priority
chain risk
Neptune has a production and 2P reserves gas
weighting of 74%
1. Neptune’s strategic positioning to macro trends.
2. Shell LNG Outlook 2021
Pete Jones, CEO
Operational update
Strong operational and financial results
(kboepd) 130-135 130.0
– Good HSE performance with improvement in PSER(1) KPI; plan in place (130-145)
to return TRIR(2) to lower levels by tackling minor incidents 145-155
(kboepd)
(140-155)
148.3
– Strong operational and financial performance in 2021, largely ahead
of guidance (kg CO2/boe) ~8 6.4
(~9)
– Significant free cash flow of $863 million driven by higher economic ~11.5
production, stronger commodity prices and lower capex ($/boe)
(11-12)
11.3
– Progressive increase in production achieved, with three projects ($m) ~650 636
(~700)
brought onstream. Production efficiency of 82%
– Remaining developments progressing well; to add 47 kboepd of ($m) ~180 154
(~150)
new production
($bn) ≥2.0 2.0
– Positive results from exploration and appraisal activity (~1.4)
– Increased 2P reserves to 604 mmboe, 107% reserve replacement ratio (net debt/EBITDAX)Operational update
Increasing production with full year contribution from new projects
kboepd
200
(~5 kboepd)
135-145 kboepd
180 (18.3 kboepd)
12 kboepd
160 14 kboepd 20 kboepd(3)
140
120
100
80
60
40
20
0
2021 Q1 Q2 Q3 Q4 2022
Touat (AL) Snøhvit
Gjøa (NO) Cygnus (UK) Touat
L5/L10/K12/G17 (NL)
Merakes (IN) NOGAT (NL)
Merakes (IN) Production equivalent
insurance income
1. The operator, Equinor, expects Snøhvit to restart in May 2022. | 2. Business interruption insurance income may vary depending on restart timing at Snøhvit and agreement for the level of claims with the insurers. | 3. Production from Njord is not included in our 2022
guidance. Output from Njord is expected to progressively increase reaching plateau in 2025.Operational update
kboepd
Further new projects provide growth potential
250
200 Risked mean
170 kboepd exploration
‒ 107% reserve replacement ratio; 123% achieved over past four years 150
‒ Increased proportion of developed 2P reserves 2C resources
100
‒ Potential new projects include Blasto, Echino South, Dugong, Römerberg, 50
Isabella. Maha already upgraded to 2P reserves 2P reserves
0
2022 2023 2024 2025 2026 2027 2028 2029 2030
2P reserve split 2C resource split(2) Gas
Oil Njord (20 kboepd(3)), Fenja (10 kboepd(3)), Existing projects to increase group
26% production to c.170 kboepd in 2023
Seagull (17 kboepd(3))
25%
36% 32% Europe
North Africa
604 mmboe 433 mmboe and APAC
68% 64%
75%
74%
‒ Refocused exploration strategy delivering positive drilling results
‒ New discoveries at Blasto and Turkoois
‒ Successful appraisal of Maha and Dugong
‒ Active exploration and appraisal programme planned in 2022
~1 billion barrels of 2P reserves and 2C resources
‒ Key wells at Ofelia, Hamlet, Isabella and Yakoot
‒ Step up in activity in the Netherlands
1. 2P reserves and contingent resources are management estimates, the majority of which are independently audited by ERCe.
2. Contingent resources included within categories 1-3.
3. Production rates calculated as 12 month peak rate.Operational update
Lower carbon barrels, integrated energy hubs
Long life, low cost, lower carbon portfolio
1 Gas
‒ Focus where we have experience and infrastructure Lower carbon
(electrification, CCS and hydrogen) energy
Hydrogen Oil
production
‒ Utilise higher returns from O&G to invest
incrementally in low carbon energies
2
Integrated
‒ Structure the organisation around focused activity Electrification CCS
set, optimise portfolio for near-term value energy hubsOperational update
Beyond net zero, aiming to store more carbon than we emit
kboepd
million tonnes CO2e
60 Snøhvit (NO) L10 CCS
25
5 Mton/yr
Njord Area (NO) Electrification of Njord 2026
50 Gudrun (NO) and Snøhvit has the
potential to reduce gross 20 DelpHYnus/other UK, Scope 3
Duva, emissions by 1 Mton/year Norway CCS emissions
40 Gjøa P1 (NO) 4.5 Mton/yr
Existing: ~2027
15
Gjøa (NO)
30 Q13 (NL)
10
20
5 Emissions
10
stored for
third party
emitters
- 0
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2022 2023 2024 2025 2026 2027 2028 2029 2030
1. Indicative timeline for future projects at Njord (including Hyme, Bauge, Fenja) and Snøhvit. 1.
-5 Indicative chart. Assumes 100% ownership of CCS projects, with L10 commencing in 2026 and ramping up to full capacity (5 million
2. Gudrun electrification project is due to start-up in late 2022. tonnes of CO2) in 2028, and DelpHYnus/other UK and Norway CCS opportunities commencing around 2027 and increasing to full
3. Production excludes Nova compensation. capacity (4.5 million tonnes of CO2) in 2029.
2. Emissions from use of sold product are Scope 3 category 11 emissions. This includes 2P reserves and 2C resources.Armand Lumens, CFO
Financial results
Strong balance sheet, targeted investment and healthy cash flow
‒ Strong liquidity, low leverage
‒ Strong capital structure provides liquidity ‒ Maintain or improve current credit ratings
to support growth, while maintaining low ‒ Cash flow protection through hedging and insurance
leverage
‒ Capex to focus on shorter-cycle projects
for nearer-term value creation ‒ Near-term returns, balanced with investments
‒ Invest in profitable lower carbon production growth and low carbon developments
‒ Lower exploration expenditure, adding ‒ Full cycle break-even pre-tax costs ofFinancial results
Strong financial performance, driven by higher economic production and commodity prices
OCF before w/c
1,982
EBITDAX(1) Post-tax 880
Net debt(4)
($m) 2,109 operating 1,697 ($m) 2,104
cash flow 1,821
35 Working
($m) OCF after w/c
capital change
940 915
(285)
2020 2021 2020 2021
2020 2021
OPEX(2) Capex(3) 741
Net debt to
($/boe) ($m) 12-month 2,104
11.3 636 1.9
rolling
9.5 EBITDAX(1,4)
(x)
1.0
2020 2021 2020 2021 2020 2021
1. EBITDAX (as defined by the RBL and Shareholder agreements). EBITDAX comprises net income for the period before income tax expense, financial expenses, financial income, other operating gains and losses, exploration expense and depreciation and amortisation. Includes our share of net income
from Touat. | 2.Opex including royalties, but excluding equity-accounted entities. | 3. Development capex, excluding acquisitions and exploration, but including equity-accounted entities. | 4. Book value net debt excluding Subordinated Neptune Energy Group Limited Vendor Loan as defined in RBL
and shareholders agreement.Financial results
Higher earnings driven by revenue growth
‒ $759.2 million of realised(7) hedging losses in 2021 compared with a
$287.0 million gain in 2020
($ million)(1)
‒ $128.6 million of other operating income in 2021 in relation to net LOPI
Revenue and other operating income 2,618.7 1,569.1
Operating costs (512.5) (467.0)
insurance income in Norway
Other cost of sales(2) 20.4 (73.2) ‒ $145.8 million net impairment reversal(6) in 2021 predominantly due to
G&A expenses (78.4) (69.1)
Share of net income/(loss) from equity-accounted entities(3) 61.1 (20.0)
Indonesia operations and a $32.2 million impairment reversal in Algeria
EBITDAX (RBL basis) 2,109.3 939.8 (Touat)
DD&A (575.1) (584.7)
Exploration expenses (67.7) (91.2)
‒ Effective tax rate of 72% and a tax charge of $1 billion in 2021
Operating profit 1,466.5 263.9
Net impairment reversals/(losses)(4) 113.6 (325.7) ($ million) (1)
Other operating losses(5) (65.4) (33.6)
Operating profit/(loss) before tax and financial items 1,514.7 (95.4)
Net finance costs (122.3) (237.7) 2,109
(575)
Profit/(loss) before tax 1,392.4 (333.1) (65) 114 (122)
Taxation charge (1,005.2) (65.9) (68) 1,467
Net profit/(loss) after tax 387.2 (399.0)
(1,005)
($ million)(1)
387
Operating profit/(loss) before tax and financial items 1,514.7 (95.4)
Net impairments (reversals)/losses(6) (145.8) 358.4
EBITDAX DD&A Exploration Operating Other(5) Net Net finance Tax Net
Net restructuring (release)/cost (0.5) 25.3 expense income impairment cost income
Other (0.1) (1.0) reversals
Underlying operating profit before tax 1,368.3 287.3
1. Numbers might not equal due to rounding differences. | 2. Other cost of sales include under/over lift, net-off income from tariffs and services and NOGAT operating costs. ). | 3. LOPI insurance income and impairment reversals for Algeria are included within equity-
accounted entities. | 4. Net impairments (reversals)/losses, excluding equity-accounted entities. | 5. In 2021, other operating losses ($65.4 million) include a loss on mark-to-market commodity contracts ($73.8 million), a release of contingent consideration ($2.5 million),
pension scheme curtailment credit ($4.1 million) and other net gains ($1.8 million). | 6. Net impairments (reversals)/losses, including equity-accounted entities. | 7. Realised hedging losses refer to fair value losses on commodity derivative contracts that matured during the
year.Financial results
S&P BB- Positive BB-
Moody’s Ba3 Positive B1
Fitch BB Stable BB
Strong cash flow generation, leverage materially lower Leverage ratio
Net debt
($ million)(1) 12mth rolling EBITDAX
$2.3bn $1.4bn $2.1bn $2.1bn
1,697 (119)
$1.8bn
(616)
(13) (1) (85)
$0.1bn $1.1bn $0.9bn
863 $1.0bn
Post-tax operating Exploration and Development Acquisitions(3) Equity- Other(4) Free cash flow Total available Drawn Undrawn Cash Liquidity(1) 31 Dec 2020 31 Dec 2021
cash flow evaluation capex(2) accounted facilities(5) facilities(5) facilities(5)
capex investments
1. Numbers might not equal due to rounding differences.
2. Development capex excludes equity-accounted entities.
3. Acquisitions include exploration assets ($9.0 million) and development assets ($3.7 million).
4. Includes repayment of lease obligations ($107.4 million) and proceeds from asset sales ($20.9 million).
5. RBL facility.Financial results
Actively managing hedge programme to increase upside exposure
2021
2020
$/MMbtu $/bbl 62%
49%
12 80
37%
30%
70 23% 26%
10
60
Oil Gas Total Oil Gas Total
8
50 2022 2023
6 40
Gas
30 Hedged downside volumes(1) mmboe 10.7 5.3
4
Upside cap $/MMbtu 6.6 13.1
20 Downside floor $/MMbtu 5.8 5.9
2 Oil
10
Hedged downside volumes(1) mmbbl 6.4 5.1
Upside cap(3) $/bbl 87.4(2) NA
0 0
Gas LNG Oil Other liquids Downside floor $/bbl 51.2 41.8
1. Hedged volumes includes swaps, puts and collars.
2. Post-tax hedge ratio reflects our equity production volumes, whereas our RBL hedging obligations exclude certain volumes.
3. We have bought calls to provide further upside exposure to oil prices above $95.38 for part of the hedged volume.Financial results
Strong financial outlook, supported Production growth expected in 2022, with outcome
contingent on operational efficiency at Touat and restart
by rising production and commodity prices timing at Snøhvit. Start-up of Njord to drive further
growth in production.
Carbon intensity to rise slightly, reflecting later start to
(kboepd) 135-145 gas compression in the UK. On track to achieve longer
(kg CO2/boe) ~8 term targets for carbon and methane intensity.
($/boe) 11.5-12.5 Development capex and exploration spend likely to be
lower reflecting a reduction in activity. Decommissioning
($m) ~600 spend to increase slightly.
($m) ~130 Cash taxes in 2022 include additional taxes for 2021 due
to the timing of our tax assessments in Norway. Cash
taxes will result in lower operating cash flows than in
($m) ~85
2021, when we received a net cash tax refund.
($bn) ~1.0
If investments do not meet strict return measures, cash
($bn) >1.2 to be distributed to shareholders. Leverage to be
maintained at less than 1.5 times.
(net debt/EBITDAX)Sam Laidlaw, Executive Chairman
Overview
Lower carbon, strong cash flows and returns
– Lowering emissions from our – Tight control on new investment, – Well-positioned to benefit from
operations through electrification with a lower spend on exploration higher commodity prices
– Focused strategy on integrated – Focus on higher value, short-cycle – Snøhvit and Touat restart to drive near-
energy hubs to deliver CCS, hydrogen projects around existing hubs term production growth
– Aim to store more carbon than – Targeting c.170 kboepd, with new – Maintaining control on operating costs
we emit by 2030 projects onstream in 2023 and managing hedging positionsYou can also read
