H1 2019 Results
29 AUGUST 2019
H1 2019 Results 29 AUGUST 2019 GENERAL & DISCLAIMER Except as - - PowerPoint PPT Presentation
H1 2019 Results 29 AUGUST 2019 GENERAL & DISCLAIMER Except as the context otherwise indicates, Neptune or Neptune Energy, Group, we, us, and our, refers to the group of companies comprising Neptune Energy
29 AUGUST 2019
GENERAL & DISCLAIMER
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Except as the context otherwise indicates, ‘Neptune’ or ‘Neptune Energy’, ‘Group’, ‘we’, ‘us’, and ‘our’, refers to the group of companies comprising Neptune Energy Group Midco Limited (‘the Company’) and its consolidated subsidiaries and equity accounted investments. ‘EPI’ refers to the business of ENGIE E&P International S.A. (now renamed Neptune Energy International S.A.) and its direct or indirect subsidiaries. This report includes the results of the acquired EPI business consolidated since 15 February 2018, which is the acquisition date as that is when Neptune acquired control over EPI. Comparative data for Neptune for the corresponding reporting period ended 30 June 2018 therefore includes only four and a half months results contribution from the EPI business. The unaudited results for the period ended 30 June 2018 as previously disclosed have been adjusted as they were based on provisional assigned fair values of the EPI business. On completion of the business combination accounting for the year ended 31 December 2018, the associated judgements and fair values were concluded. So, the June 2018 comparative financial results and associated metrics include this position. In this report, unless otherwise indicated, our production, reserves and resources figures are presented on a basis including our ownership share of volumes of companies that we account for under the equity accounting method, in particular, for the interest held in the Touat project in Algeria through a joint venture company. Production for interests held under production sharing contracts is reported on an appropriate unit of production basis. The discussion in this report includes forward-looking statements which, although based on assumptions that we consider reasonable, are subject to risks and uncertainties which could cause actual events or conditions to materially differ from those expressed or implied by the forward-looking statements. While these forward-looking statements are based on
production, future capital expenditures and cash flow, we caution you that the assumptions used in the preparation of such information may prove to be incorrect and no assurance can be given that our expectations, or the assumptions underlying these expectations, will prove to be correct. Any forward-looking statements that we make in this report speak only as of the date of such statement or the date of this report. This report contains non-GAAP and non-IFRS measures and ratios that are not required by, or presented in accordance with, any generally accepted accounting principles (‘GAAP’) or
should not be considered in isolation or as a substitute for analysis of our operating results as reported under IFRS or GAAP. Non-IFRS and non-GAAP measures and ratios are not measurements of our performance or liquidity under IFRS or GAAP and should not be considered as alternatives to operating profit or profit from continuing operations or any other performance measures derived in accordance with IFRS or GAAP or as alternatives to cash flow from operating, investing or financing activities.
SAM LAIDLAW, EXECUTIVE CHAIRMAN
SIGNIFICANT STRATEGIC PROGRESS
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DEMONSTRATING RESILIENCE AND BUILDING GROWTH Delivering current returns
Delivering medium-term production growth
Creating long-term growth opportunities
Building resilience into the business
Delivering value and growth
JIM HOUSE, CEO
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FINANCIAL AND OPERATING RESULTS SOLID H1 2019 PERFORMANCE, DESPITE LOWER COMMODITY PRICES
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149 kboepd
H1 20183
166 kboepd
$10.3/boe
H1 20183
$10.9/boe
$880m
H1 20183
$767m
TRIR5 2.08
H1 2018 3.59
$613m 613m
H1 20183
$585m
follows: TRIR = (fatalities + lost work day cases + restricted work day case + medical treatment cases)
𝑂𝑣𝑛𝑐𝑓𝑠 𝑝𝑔 ℎ𝑝𝑣𝑠𝑡 𝑥𝑝𝑠𝑙𝑓𝑒
x 1,000,000
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DIVERSE GEOGRAPHICAL PORTFOLIO ROBUST OPERATIONAL PERFORMANCE IN Q2 2019
at 72.5 kboepd vs Q1 2019
production efficiency
incremental production in H2
lower production efficiency
approximately 600 boepd
projects in Northwest Germany
kboepd due to unplanned shutdowns of L5a- D and Q13a platforms
Q13 to coincide with shutdown
reflecting strong Cygnus performance
mmcf/d in May
producing at around 50 mmscf/d
following workover and infill campaigns
campaign at Ashrafi and AESW infill well
exports to commence imminently
JK off initial plateau and minor curtailments
with workover at JKK-5
Kutei Basin and awarded West Ganal PSC
Production 9% of portfolio
GERMANY
Production 50% of portfolio
NORWAY
Production 11% of portfolio
UK
Production 14% of portfolio
NETHERLANDS
Production 3% of portfolio
NORTH AFRICA
Production 13% of portfolio
ASIA PACIFIC
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PRODUCTION UPDATE 2019 PRODUCTION WEIGHTED TOWARDS H2
increase expected in Q4 2019
around 5 kboepd on a full year net entitlement basis (8 kboepd
incremental production
platform recommenced in early August and start-up operations are currently underway at L5a-D
600 boepd
production to exceed 170 kboepd by the end of the year
135 140 145 150 155 160 165 170 175 130 135 140 145 150 155 160 165 170 175 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019* Q4 2019*
Delivering material production growth through investment in the portfolio1 Increasing production throughout H2, with Touat reaching plateau and infill well drilling at Fram
Source: Company information
1 Forecasts subject to change and external factors
kboepd kboepd
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FOCUS ON MAINTAINING LOW BREAKEVEN THROUGH COST CONTROL
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Competitive breakeven costs Lower operating costs
48% 11% 17% 8% 16% $7.1 $12.3 $25.7 $11.5
the business
Germany and the Netherlands
Opex Exploration expense Net finance costs All-in costs (post-tax) G&A Tax All-in costs (pre-tax)
Capex Decom.
Forecast 2019 all-in breakeven costs ($/boe)
0.0 5.0 10.0 15.0 20.0 25.0 0% 20% 40% 60% 80% 100% UK Norway Netherlands Asia Pacific Germany North Africa 61% of production ≤$7.1/boe
H1 2019 opex per country ($/boe)
Cumulative production $6.5/boe $7.1/boe $9.7/boe1 $13.7/boe $21.5 /boe2 $13.3/boe
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BUILDING OUR ACREAGE POSITION IN INDONESIA NEAR-TERM PRODUCTION GROWTH, WITH LONGER-TERM UPSIDE OPPORTUNITIES
prospective PSCs
further aligns our interests with Eni
East fields
with Jangkrik
least two wells planned for 2020
Addition of interests in the East Sepinggan, East Ganal and West Ganal PSCs
Building a strategic growth footprint
Jangkrik and Jangkrik NE Existing interests in the Mura Bakau and North Ganal PSCs West Ganal PSC award Merakes and Merakes East discoveries East Sepinggan and East Ganal PSCs interests acquired from ENI
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Latest progress
Onstream Onstream Onstream Onstream
22 kboepd net 2019 2020 2021
HIGH QUALITY GROWTH PIPELINE PROJECTS TO DELIVER SOME ~100 KBOEPD FROM 2019 ONWARDS
Neptune 35%
Seagull
Neptune 22.5%
Njord
Neptune 30%
Fenja
Neptune 30%
Duva/Gjøa P1
16 kboepd net 13 kboepd net 17 kboepd net Njord project remains on track for production to recommence in late 2020. Includes recommencement of production from Hyme and first oil from the Bauge field Subsea EPCI contract awarded to TechnipFMC in July, with the offshore campaign scheduled to commence in Q2 2020 Norwegian authorities approved the development plan for the projects in June. Scheduled for drilling in early 2020 Installation of pipelines, umbilical cables, subsea templates and manifolds commenced in June
Key projects
Neptune 12%
Snøhvit satellites
Snøhvit Nord (2019 start-up) and Askeladd (2020 start-up) Neptune 20%
Merakes
East Sepinggan PSC acquired in 2019. To be developed as a tie-back to the Jangkrik FPU Neptune 35%
Touat
16 kboepd net 8 kboepd net 13 kboepd net Commissioning complete and ready to commence gas exports
Onstream Onstream Onstream Onstream
FY 2019 capex of $700 million (excluding Merakes and M&A activities) unchanged
Neptune ENI Equinor Neptune Neptune Neptune Equinor
Operator
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INCREASING INVESTMENT IN GROWTH FIVE WELLS TO BE DRILLED IN H2 2019
Exploration
Country Project Neptune interest Timing Norway Sigrun East 25% Q3 Echino South 15% Q3 Skumnisse (Draugen step-out) 7.56% Q4 UK Isabella 50% Q4 Germany Schwegenheim 50%, operated Q3
Southern North Sea being analysed
with results expected in early 2020. Well is targeting 83 mmboe (P50 gross) in the UK Central North Sea
activity planned in 2020
material long-term growth opportunities; at least two wells planned in 2020
2019, weighted towards H2
ARMAND LUMENS, CFO
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FINANCIAL HIGHLIGHTS STRONG H1 2019 FINANCIAL PERFORMANCE
Revenues $1,238 million
price of $5.5/mcf before hedging
2019, compared with Q1
Post-tax operating cash flow $613million FCF(2) $179 million
financing requirements
Operating costs $277 million
Group
2018
Total capex $352 million
progress
H1 2019 EBITDAX(1) $880 million H1 2019 EBITDA $861 million
full half year result from the EPI acquisition
$338 million, representing $12.6/boe
Net debt to EBITDA: 0.75x EBITDAX: 0.72x
‒ Shareholder agreement: <1.5x net debt to EBITDA ‒ RBL requirement: <3.5x net debt to EBITDAX
Pre-tax profit $385 million Net income after tax $116 million
Hedged position 2019 Oil 53% Gas 64%
downside floor of $61/bbl and a capped upside of $75/bbl
price of $5.7/mmbtu and an upside cap of $7.1/mmbtu
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COMMODITY PRICES IN H1 2019 REALISED OIL AND GAS PRICES REFLECT SOFTER COMMODITY PRICES
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Realised LNG price1 ($/mcf) Realised oil price ($/bbl) Realised gas price ($/mcf)
Brent crude price average3 FY 20182 $72.3/bbl H1 2019 $66.2/bbl TTF price average3 FY 20182 $8.1/mcf H1 2019 $5.2/mcf Japan-Korea marker price average3 FY 20182 $9.3/mcf H1 2019 $5.7/mcf
Neptune’s realised prices
69.6 62.7 67.5 61.6 F Y 2018 H 1 2019
Pre-hedging Post hedging
7.9 5.5 6.9 5.8 F Y 2018 H 1 2019
Pre-hedging Post hedging
8.2 8.6 F Y 2018 H 1 2019
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COMMODITY PRICE SENSITIVITY HEDGING PROGRAMME PROTECTS DOWNSIDE, WHILE PRESERVING UPSIDE
Operating cash flow sensitivity Diverse production and commodity exposure
lower our exposure to gas prices to around 54% by volumes and 39% by Group revenues
volumes and 53% of oil volumes for the remainder of 20192
exposure to gas price weakness
than for gas
Source: Company information
52% 19% 20% 9% Product split Gas Oil NGL LNG 71% 29% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Production Oil Gas 54% 46% Commodity price exposure Gas Oil 39% 61% Revenue by commodity Gas Oil 38% 21% 22% 19% Post tax hedging
H2 2019 post-tax operating cash flow sensitivity to a $10/bbl change in oil and/or a 15% change in gas prices1
Unhedged volumes 41% Hedged volumes 59%
50 100 150 Gas Oil Oil & Gas $m
Production
KEY FINANCIALS
$10.3/boe
broadly unchanged at $12.6/boe
costs incurred on geological and geophysical activities
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H1 2019 EARNINGS
H1 2019 Total revenues 1,238 Operating costs (277) DD&A (338) Exploration expense (19) G&A (43) Other (38) Operating profit 523 Other (35) Net financial items (103) Profit before tax 385 Tax (269) Reported net income 116 EBITDA 861 EBITDAX 880
Consolidated income statement ($m) Commentary EBITDAX Net income
$m $m
KEY FINANCIALS
cash taxes of $190 million
million includes:
acquisitions.
strong at $179 million
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H1 2019 CASH FLOW
H1 2019 EBITDA 861 Cash taxes (190) Change in WC and other items (58) Cash flows from operations 613 Exploration capex (17) Development capex (335) Investments in equity accounted entities (32) Other 13 Cash flows from investment (371) Change in debt (230) Lease accounting (10) Interest paid (52) Cash flows from financing (292) Net change in cash (50) Cash at end of period 147 Free cash Flow after financing costs 179
Consolidated cash flow statement ($m) Commentary Operating cash flow Capex
$m $m 140 352 50 100 150 200 250 300 350 400 H1 2018 H1 2019
KEY FINANCIALS
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H1 2019 BALANCE SHEET
Source: Company information
H1 2019 Goodwill
657
PPE and intangibles
4,133
Investments in JVs
567
Other
674
Non-current assets
6,031
Trade and other receivables
632
Cash
147
Other
162
Current assets
941
Total assets
6,972
Equity
1,879
Long-term borrowings
1,581
Provisions
1,681
Other
918
Non-current liabilities
4,180
Trade payables
238
Taxes payable
250
Other
425
Current liabilities
913
Total liabilities
5,093
Net assets
1,879
Consolidated balance sheet ($m) Commentary Debt breakdown
$m
$1,435 million
30 June 2019
RBL, $750m Senior Secured Notes, $550m Touat, $233m Engie Vendor Loan, $111m 0.84 0.64 0.72 0.00 0.20 0.40 0.60 0.80 1.00 FY 2018 Q1 2019 H1 2019
Net debt to EBITDAX
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FINANCIAL POSITION SIGNIFICANT AVAILABLE LIQUIDITY
750 550 233 111 63 1,581 147 1,435 1,177 147 1,324 613 384 50 179
1,000 1,500 2,000 Drawn RBL Senior Notes Touat Project Finance Engie Vendor Loan B Debt Issuance Costs Total Debt Cash Net Debt Undrawn RBL Cash Headroom Operating CF Investing CF Finance & Other costs Free CF surplus $m
SAM LAIDLAW, EXECUTIVE CHAIRMAN
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NEAR-TERM PRODUCTION INCREASE, LONG-TERM GROWTH OPPORTUNITIES
and commodity prices
growth organically or through acquisition
Touat gas facility, Algeria
FY 2019 guidance
to exit the year at near record high production, exceeding 170 kboepd
long-term production growth
Strategy