hibiscus petroleum bhd -...

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Asia Pacific Equity Research12 January 2018

Hibiscus Petroleum BhdMalaysia's only listed E&P "pure play" evolving from the North Sea to Malaysia - Company Visit Note

Exploration & Production

Ajay Mirchandani AC

(65) 6882-2419

[email protected]

Bloomberg JPMA MIRCHANDANI <GO>

J.P. Morgan Securities Singapore Private Limited

Anshool Singhi

(91-22) 6157-5094

[email protected]

J.P. Morgan India Private Limited

Hoy Kit Mak

(60-3) 2718-0713

[email protected]

JPMorgan Securities (Malaysia) Sdn. Bhd. (18146-X)

See page 40 for analyst certification and important disclosures, including non-US analyst disclosures.J.P. Morgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

We recently met with Dr. Kenneth Pereira, Managing Director of Hibiscus Petroleum, and discussed the evolution of Hibiscus Petroleum’s business from the US$100/bbl oil era in 2014 (see our previous note on the company), to its survival during the tough years for the oil industry of 2015-16, to now being a ~3200 bpd producing company (U.K. North Sea assets with attributable 2P reserves of 22.7 mmboe) with what management sees as upside potential via its: (1) recently acquired (completion targeted by Mar-18) Malaysia EOR asset, North Sabah (attributable 2P reserves of 31 mmboe); and (2) exploration assets in Australia (recoverable resources of 50.9 mmboe in a “low case” scenario).

U.K. North Sea oil-producing asset has ~19-year reserve life and opex of $15-18/bbl with a $208mn valuation: HIBI MK completed the acquisition (from Shell) of its 50% stake in Anasuria Cluster (joint operator) in Mar-16 at an acquisition price of US$52.5mn. Per RPS’s valuation in Jun-16, this asset was valued at $208mn, with HIBI MK able to lower opex/bbl from $22/boe to $14/boe over the last two years. With £40mn of capex planned for Anasuria Cluster (over three years), the company hopes to add about 4 mmboe (of “attributable” 2P reserves) with a potential increase to its current 3200 bpd production.

North Sabah EOR to triple oil production as Hibiscus Petroleum looks to crystallize “attributable” 2C resources of 40 mmboe: The company believes the acquisition of North Sabah EOR (completion by Mar-18) will result in long-term value, as it will triple HIBI MK’s overall production. The asset was acquired for US$25mn (from Sabah Shell), with the remaining 50% held by Petronas Carigali.

Zero-debt balance sheet; proxy for “rising” oil prices: HIBI MK stock is up 42% over the last three months, outperforming oil (up 25%). The company has a “zero debt” balance sheet, although it has undertaken three tranches of equity-raising in the last six months.

NOTE: THIS DOCUMENT IS INTENDED AS INFORMATION ONLY AND NOT AS A RECOMMENDATION FOR ANY STOCK. IT CONTAINS FACTUAL INFORMATION, OBTAINED BY THE ANALYST DURING MEETINGS WITH MANAGEMENT. J.P. MORGAN DOES NOT COVER THIS COMPANY AND HAS NO RATING ON THE STOCK.

Hibiscus Petroleum (Reuters: HIBI.KL, Bloomberg: HIBI MK), Historical financial data

M$ in 000s, year-end June 2013 (12M) 2013 (9M) 2015 (18M) 2016 2017

Revenues 8,516 13,344 15,586 81,695 261,273

PATMI (4,197) 12,135 (74,216) (59,960) 106,097

EPS (M$) -0.010 0.026 -0.097 -0.057 0.075

ROE -1.7% 3.3% -14.5% -10.3% 14.3%

ROIC -5.3% 1.3% -11.2% -65.0% 13.6%P/E na 39.6 na na 13.9P/B 1.9 1.3 1.6 1.9 2.0Dividend yield 0.0% 0.0% 0.0% 0.0% 0.0%

Source: Company data, Bloomberg. 2013 (12M) = Mar-13, 2013 (9M) = Dec-13; 2015 (18M) = Jun-15.

.

HIBI MK, Not CoveredM$1.04 – 11 January 2018

Five-year share price chart

Source: Bloomberg, J.P. Morgan. Note: Past results

are not an indicator of future performance.

One-year price performance

1M 3M 12M

Absolute (%) 27.6 42.5 108

Relative (%) 22.6 39.1 99.5

Source: Bloomberg. As of 11-Jan-18. Note: Past

results are not an indicator of future performance.

Company data

52-wk range (M$) 0.385-1.06

Mkt cap. (M$ mn) 1605.7

Mkt cap. (US$ mn) 400.8

Shares O/S (MM) 1,543.9

Free float (%) 60.94

Avg. daily volume (6M) 41.75mn

Exchange rate 3.98

Index FBMKLCI Index

Year-end June

Source: Bloomberg. As of 11-Jan-18:

0

0.5

1

1.5

2

2.5

3

Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18

Completed 12 Jan 2018 02:09 AM HKTDisseminated 12 Jan 2018 02:09 AM HKT

https://www.jpmm.com/research/content/GPS-1401293-0.pdf

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Ajay Mirchandani(65) [email protected]

Table of contentsCompany overview...................................................................3

Financial summary .................................................................23

Appendix I: Insight into E&P valuations and fiscal systems.................................................................................................30

Appendix II: Overview of the Malaysian fiscal system........36

3



Company overview

Focus on high margin production from mature assets in U.K. and Malaysia, with exploration asset upside in Australia

Hibiscus Petroleum is Malaysia’s first listed independent oil and gas exploration and production (E&P) company having concessions in the United Kingdom, Malaysia and Australia. The company aims to grow by “sweating” mature assets and developing proven opportunities in its asset portfolio.

Hibiscus has rid itself of most exploration commitments and is focused on maximizing economic recovery in the mature assets it operates (Anasuria Cluster in the U.K., VIC/L31 production license in Australia) and is soon to operate (conditional SPA for North Sabah shallow-water assets in Malaysia).

Hibiscus Petroleum’s primary revenue stream is from its production at Anasuria Cluster, which it operates along with Ping Petroleum, with a 2P reserve of 22.7MMbbls (as of 1-Jan-18) and a production rate of ~3500boe/day.

Figure 1: Current portfolio of assets

Source: Company data.

Table 1: Asset summary

Anasuria Cluster*Australian VIC/P57 exploration license

Australian VIC/L31 production license

North Sabah EOR PSC**

Hibiscus (only Anasuria and Australia assets)

Stake 50% 78.30% 100% 50%Partner Ping Petroleum (50%) 3D Oil (21.70%) - Petronas Carigali (50%)Location United Kingdom Australia Australia MalaysiaProduction 3,500 boe/day Non-producing Non-producing 9Kstb/d** 3,500 boe/day2P reserve 22.7 MMbbls 6.5 MMbbls 31 MMstb** 29.2 MMbbls2C resource 5.2 MMbbls 1.5 MMbbls 39.5 MMstb** 6.7 MMbblsBest prospective reserve

Oil : 40.13 MMbblsGas: 367.24Bcf

Opex US$15.1/bbl - M$55.1/bbl(~US$14.1/bbl) US$15.1/bblLicense expiry 9-Jan-18 5-Dec-18

Source: Company data. * Anasuria 2P and 2C reserve data are as of 1-Jan-18. Production rate is as of 30-Jun-17. ** North Sabah Subject to completion of transaction. North Sabah 2P and

production based on 2015 actual data and on 50% interest in the PSC, as of 1-Jan-16. Stock tank barrels.

Hibiscus Petroleum aims to secure 2P reserves of 100MMbbls in existing core asset areas and net production of 20,000bbl/day by 2021

4



Description of assets

Hibiscus Petroleum’s core assets are: (1) Anasuria Cluster in the United Kingdom, in partnership with Ping Petroleum; (2) VIC/L31 production license and VIC/P57 exploration license in Australia; and (3) shallow-water asset in North Sabah for which Hibiscus has entered into an SPA with Sabah Shell Petroleum – the company expects the transaction to be completed soon.

Anasuria Cluster

Located 175km east of Aberdeen, U.K. North Sea, Anasuria Cluster was acquired by Hibiscus in partnership with Ping Petroleum on 10 March 2016 for a total purchase consideration of US$52.2mn. The Cluster is operated by a 50:50 JV, Anasuria Operating Company (AOC).

With first oil in 1996, Anasuria Cluster was acquired from U.K.-incorporated Shell and Esso companies in 2016. Hibiscus believes Anasuria can remain economic for another 15-20 years, subject to oil prices, capital investments and the management of operating expenditures.

Figure 2: Location of Anasuria Cluster


Anasuria Hibiscus has a long-term marketing and offtake agreement with BP Oil International Limited (BPOI), a subsidiary of BP. BPOI identifies potential customers, locks in competitive prices and arranges lifting. While Anasuria produces oil daily, it sells oil only in cargoes of ~250kbbls.

Table 3: Fields at Anasuria Cluster

Field Status Stake PartnerAttributable

2P reserve2C resource

(infill)Guillemot A Producing field 50% Ping Petroleum (50%) 12.39 MMbbls 3.5 MMbblsTeal Producing field 50% Ping Petroleum (50%) 2.06 MMbbls -Teal South Producing field 50% Ping Petroleum (50%) 3.82 MMbbls 0.75 MMbblsCook Producing field 19.30% Ping Petroleum (19.3%),

Ithaca Energy (61.4%)4.46 MMbbls 0.25 MMbbls

Kite Non-producing 50% Ping Petroleum (50%) 0.7 MMbblsTotal 22.7 MMbbls 5.2 MMbbls


Table 2: Anasuria Cluster

Working interest 50:50 ownership Ping Petroleum

Country United Kingdom2P reserve* 22.7 MMbbls2C resource * 5.2 MMbblsProduction rate** 3,500 boe/dayOpex** US$15.1/bbl

Source: Company data. * As of 1-Jan-18. ** For FY17.

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The four producing fields with eight wells are hooked up to the Anasuria FPSO,which is owned by AOC, the 50:50 JV between Hibiscus Petroleum and Ping Petroleum. In Mar-16, AOC awarded Petrofac a five-year Service Operator contract to assume responsibility of the field on behalf of AOC and to monitor and manage the pipelines and wells. The contract is believed to be worth US$250mn (Source: Offshore Energy Today).

Figure 3: Anasuria Cluster field layout


Figure 4: Anasuria ownership structure


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The Anasuria Cluster acquisition

The acquisition of Anasuria Cluster was announced on 6-Aug-15 in a joint press release by Hibiscus Petroleum and Ping Petroleum. The partners entered into a sale-and-purchase agreement to acquire 50% each of the entire interests of Shell UK, Shell EP Offshore and Esso Exploration and Production UK, effective 1-Jan-15.

The total purchase consideration for the asset was US$52.5mn. After applying certain working capital adjustments considering the economic benefits accruing from the Economic Date of 1 January 2015, the actual net cash outlay upon completion of initial consideration was US$5.2mn. For deferred consideration, a sum of US$15mn was paid in Mar-17, and US$7.5mn was settled in Sep-17.

Figure 5: Acquisition of Anasuria Cluster


Projects undertaken at Anasuria Cluster

Offshore turnaround of Anasuria FPSO: The operator shut down Anasuria FPSO facilities to undertake compliance and general maintenance-related activities from mid-Sep-17 to mid-Oct-17. The project was expected to improve the average unplanned facilities uptime/availability of the FPSO up to 90% post-shutdown. The next offshore turnaround of the FPSO will take place in late 2019.

Figure 6: Average oil production vs. facilities uptime


Souring: The souring project was undertaken to bring online wells that were shutin by the previous operator due to high hydrogen sulphide levels. The activity was carried out at GUA-P1 in Jan-17 and at TLS-P1 in Jul-17. The project was expected to add an average of 315bbls/day of production for 2017.

RPS Energy valued Anasuria Cluster at US$208mn (excluding upside from 2C) as of Jun-16. This assumes oil prices for 2017 of US$48/bbl; for 2018 of US$58/bbl; and for 2019 of US$65/bbl

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Figure 7: Average oil production rate


Installation of GUA-P4 gas lift facilities: This project was undertaken to re-enter an existing well using a Light Well Intervention Vessel for the installation of a gas lift system to enhance production. It was carried out from early Octoberto early November 2017. The project was expected to add 0.5 MMbbls of 2P reserves, and the production rate was anticipated to improve from an average of 60bbls/day to an average of approximately 350bbl/day net to AHUK.

Figure 8: Average oil production rate


Anasuria projects in 2018/2019

Hibiscus has highlighted three enhancement projects it plans to conduct in 2018-19.However, these opportunities will require significant investment.

Figure 9: Projects scheduled for execution on Anasuria Cluster in 2018/2019

Source: Company data. * Subject to sanction by all co-ventures of the Cook production license.

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Factors affecting Anasuria performance

Brent crude oil price: The price of Brent crude oil benchmark at approximately the time of a scheduled offtake from the Anasuria FPSO.

Figure 10: Brent crude oil price

Source: Bloomberg.

Gas prices from respective fields:

Cook Field – 40% of the Heren Index (Heren National Balancing Point Index),per Cook gas SPA.

Guillemot A, Teal and Teal South fields – 85% of Heren Index, per Anasuria SPA

Exchange rates

U.S. dollar : Revenues and valuation of Anasuria; British pound: Major operating costs of Anasuria

Figure 11: MYR vs. USD and MYR vs. GBP

Source: Bloomberg

Operating performance of Anasuria

Production performance of wells and facilities availability

Company outlook for Anasuria

The company believes it is gaining valuable experience in the U.K. Continental Shelf. Several production enhancement projects have ensured that the natural production decline generally seen on all mature oil and gas fields has been arrested at the Anasuria Cluster for the near future.

Following the recently concluded offshore turnaround, the group plans to exceed the 85% average facility uptime achieved in FY17 (end-June). This will enable increased daily oil production rates.

The company plans to achieve a production rate of 5,000bbls/day of oil net to Anasuria Hibiscus by year-ending 30 June 2019.

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30

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Brent (US$)

0.15

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0.23

0.25

0.27

MYRUSD MYRGBP

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Anasuria Cluster: Financial summary and operational parameters

Table 4: Anasuria Cluster quarterly financial summary

M$ in 000s 1Q17 2Q17 3Q17 4Q17 1Q18Revenue 53,694 61,788 68,052 73,284 57,048 EBITDA 27,117 38,090 40,016 55,296 33,250 Profit from operations 13,469 23,777 30,576 38,486 23,003 PBT 8,345 14,489 22,004 37,739 19,039 PAT 84,189 15,210 13,645 16,773 20,107 Anasuria EBITDA margin (%) 51% 62% 59% 75% 58%Anasuria PBT margin (%) 16% 23% 32% 51% 33%Anasuria PAT margin (%) 154% 24% 20% 23% 35%


Table 5: Anasuria Cluster quarterly operational parameters

4Q16 1Q17 2Q17 3Q17 4Q17 1Q18Average daily oil production rate (bbl/day) 2,971 3,032 3,934 2,617 3,204 2,576 Average daily gas export rate (boe/day) 236 374 474 257 317 156 Average oil equivalent production rate (boe/day) 3,206 3,406 4,408 2,873 3,522 2,731 Total oil sold (kbbl) 460 272 299 273 285 246 Total gas exported (sold) (mmscf) 172 206 262 138 173 87 Total gas exported (sold) (kboe) 30 36 46 24 30 15 Total kboe sold 490 308 345 298 315 261

Average realized oil price (US$/bbl) 40.1 45.2 41.7 53.0 50.5 51.5 Average gas price (US$/mmbtu)

For Cook field 1.2 1.3 1.7 2.1 1.6 1.6 For Guillemot A, Teal and Teal South fields 3.1 3.3 4.2 4.9 3.9 3.9

Average opex (US$ per bbl) 23.1 20.7 14.6 16.6 15.4Average opex (US$ per boe) 23.1 18.4 13.0 15.1 14.0 23.6 Average uptime/availability of Anasuria facilities (%) 88% 82 % 98 % 76 % 84 % 70 %


Anasuria Cluster: Quarterly performance

Table 6: Anasuria Cluster quarterly financial performance

M$ in 000s 1Q18 1Q17 y/y 4Q17 q/q FY17A FY16A y/yRevenue 57,048 53,694 6.2% 73,284 -22.2% 256,817 78,654 226.5%EBITDA 33,250 27,117 22.6% 55,296 -39.9% 160,519 363,777 -55.9%Profit from operations 23,003 13,469 70.8% 38,486 -40.2% 106,307 (17,434) -709.8%PBT 19,039 8,345 128.1% 37,739 -49.6% 82,577 339,979 -75.7%PAT 20,107 84,189 -76.1% 16,773 19.9% 129,818 336,373 -61.4%Anasuria EBITDA margin (%) 58.3% 50.5% 15.4% 75.5% -23% 62.5% - -Anasuria PBT margin (%) 33.4% 15.5% 114.7% 51.5% -35% 32.2% - -Anasuria PAT margin (%) 34.5% 153.8% -77.5% 22.5% 53% 50.5% - -


Table 7: Anasuria Cluster quarterly operational performance

1Q18 1Q17 y/y 4Q17 q/q FY17AAverage daily oil production rate (bbl/day) 2,576 3,032 -15.0% 3,204 -19.6% 3,197Average daily gas export rate (boe/day) 156 374 -58.3% 317 -50.8% 356Average oil equivalent production rate (boe/day) 2,731 3,406 -19.8% 3,522 -22.5% 3,552Total oil sold (kbbl) 246 272 -9.4% 285 -13.6% 1,129Total gas exported (sold) (mmscf) 87 206 -57.8% 173 -49.7% 779Average realized oil price (US$/bbl) 51.54 45.21 14.0% 50.46 2.1% 47.58Average gas price (US$/mmbtu)

For Cook field 1.58 1.33 18.8% 1.60 -1.3% 1.69For Guillemot A, Teal and Teal South fields 3.86 3.30 17.0% 3.86 0.0% 4.07

Average opex (US$ per boe) 23.61 18.39 28.4% 13.98 68.9% 15.10Average uptime/availability of Anasuria facilities 70% 82% -14.6% 84% -16.7% 85%


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Anasuria Cluster: Financial summary and operational parameters

Figure 12: Anasuria EBITDA margin


Figure 13: Anasuria PBT margin


Figure 14: Anasuria average production rate vs. opex (US$/bbl)


Figure 15: Anasuria average realized oil price (US$/bbl)


Figure 16: Anasuria average uptime/availability


Figure 17: Anasuria oil & gas sales volume mix


51%

62% 59%

75%

58%

0%

20%

40%

60%

80%

1Q17 2Q17 3Q17 4Q17 1Q18

Anasuria EBITDA Margin (%)

16%

23%

32%

51%

33%

0%

10%

20%

30%

40%

50%

60%

1Q17 2Q17 3Q17 4Q17 1Q18Anasuria PBT Margin (%)

3,032

3,934

2,617 3,204

2,576

18.4

13.0 15.1

14.0

23.6

0.0

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15.0

20.0

25.0

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1,000

2,000

3,000

4,000

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1Q17 2Q17 3Q17 4Q17 1Q18

Average Daily Oil Production Rate (bbl/day) Average OPEX (US$ per boe)

45.2 41.7

53.0 50.5 51.5

0.0

10.0

20.0

30.0

40.0

50.0

60.0

1Q17 2Q17 3Q17 4Q17 1Q18

Average realised oil price (US$/bbl)

82%

98%

76%84%

70%

0%

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40%

60%

80%

100%

120%

1Q17 2Q17 3Q17 4Q17 1Q18Average uptime/availability of Anasuria facilities (%)

88% 87% 92% 90% 94%

12% 13% 8% 10% 6%

0%

20%

40%

60%

80%

100%

1Q17 2Q17 3Q17 4Q17 1Q18

Oil Gas

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Australian VIC/P57 and VIC/L31 licenses

Hibiscus holds a 78.3% interest in the VIC/P57 exploration permit (with 21.7% held by 3D Oil) and a 100% interest in the VIC/L31 production permit. These licenses are located in the West Seahorse discovered oilfield, located in Bass Strait.

Development of the VIC/L31prodcution permit has not begun since the downturn in oil prices in 2014. With the potential acquisition of North Sabah assets, the company decided to prioritize the allocation of capital and rank projects in accordance with risks and potential returns.

As noted above, the VIC/P57 exploration permit is 78.3%-owned by Hibiscus petroleum and the rest by 3D Oil. As technical advisor, 3D Oil Ltd. undertook a comprehensive prospective review to identify potential drill targets to ultimately provide an inventory of prospects and leads. The studies led to the de-risking of previously identified prospects and uncovered new prospects. The exploration permit is set to expire in Jan-18, but the VIC/P57 JV has agreed to seek another five-year renewal and is in discussions with Australia’s National Offshore Petroleum Authority. The proposed work program in the primary term of the renewal period (the first three years) would be designed to de-risk and high-grade the prospect inventory to ultimately mature drill-ready prospects.

Figure 18: Location of VIC/P57 and VIC/P31 permits


Table 10: Gross prospective resource estimates for recoverable oil and gas within VIC/P57

LocationRecoverable resource Status Low Best High

Felix Oil (MMbbls) Prospect 6.84 15.94 26.94Salsa Oil (MMbbls) Lead 10.65 15.09 20.57Nicholson Oil (MMbbls) Lead 3.4 7.86 14.68Scooter Oil (MMbbls) Lead 0.54 1.24 2.27Pointer Gas (Bcf) Prospect 140.1 235.26 364.91Dexter Gas (Bcf) Lead 36.96 131.98 259.14Total Oil MMbbls 21.43 40.13 64.46Total Gas Bcf 177.06 367.24 624.05


Table 9: VIC/P57 exploration permit

Working interest 78.3% (21.7% 3D Oil)

Country AustraliaBest gross prospective oil resource

40.13 MMbbls

Best gross prospective gas resource

367.24Bcf

License expiry* 9-Jan-18

Source: Company data. * A five-year renewal

application has been submitted.

Table 8: VIC/P31 (West Seahorse) production permit

Working interest 100%Country Australia2P reserve 6.5 MMbbls2C resource 1.5 MMbblsProduction rate Non-producingOpex N/ALicense expiry 5-Dec-18


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North Sabah EOR PSC

In Oct-16, Hibiscus announced that it had entered into a conditional share purchase agreement with Sabah Shell Petroleum (SSPC) and Shell Sabah Selatan (SSS) to acquire their 50% participating interest in the 2011 North Sabah Enhanced Oil Recovery Production Sharing Contract, originally held between Petronas and SSPC,SSS and Petronas Carigali. Hibiscus will also acquire a 50% stake in the joint operating agreement between SSPC, SSS and Petronas Carigali. The total consideration for the transaction is US$25mn. The company is working with the current operator to complete the transfer of information. It expects the transaction to be completed after the fulfillment of all pre-conditions.

The acquisition of a 50% stake from SSPC and SSS will give Hibiscus responsibility for operations at the four existing oil fields and for the existing pipeline infrastructure, the Labuan Crude Oil Terminal and all other equipment and assets relating to North Sabah PSC.

Hibiscus Petroleum’s rationale for the deal was: (1) it is in line with its growth strategy to acquire a cash-flow-positive asset in a safe jurisdiction; (2) there is production enhancement scope to convert large 2C to 2P; and (3) it offers a partnership with a reputed global player, Petronas Carigali.

Figure 19: Location of North Sabah EOR PSC


Table 12: Fields at North Sabah EOR PSC

Field Status Stake* PartnerSt Joseph Producing 50% Petronas Carigali (50%)South Furious Producing 50% Petronas Carigali (50%)SF30 Producing 50% Petronas Carigali (50%)Barton Producing 50% Petronas Carigali (50%)St Joseph Producing 50% Petronas Carigali (50%)

Source: Company data. * Subject to completion of transaction.

Table 11: North Sabah EOR PSC*

Working interest 50% (50% Petronas Carigali)

Country Malaysia2P reserve** 31MMstb2

2C resource** 39.5MMstb2

Production1 9Kstb/d2

Opex1 M$55.1/bblSource: Company data. * Subject to completion of transaction. ** Based on 50% interest in the PSC. 1Actuals as of 2015. 2Stock tank barrels.

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Commercial details for purchase of North Sabah EOR

On 22-Dec-17, SEA Hibiscus, Petronas, the sellers and Petronas Carigali entered into a novation agreement for the assignment and transfer of the entire interest of SSPC and SSS in 2011 North Sabah EOR OSC to SEA Hibiscus, effective 31 March 2018.

The transaction for the purchase of North Sabah EOR PSC is split into an initial consideration of US$15mn, of which US$2.5mn was paid after the signing of the SPA, and US$12.5mn to be paid upon completion. A deferred consideration of US$10mn will be split into two US$5mn payments to be paid 12 months and 24 months after completion.

Figure 20: Commercial details for purchase of North Sabah EOR PSC

Source: Company data. The expected economic benefit to be derived from the effective date (1 January 2017).

The company believes the acquisition could increase the oil production output of the group by three times and could provide a second revenue stream independent of Anasuria Cluster.

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Table 13: Company history

25-Jul-11 Makes stock market debut as first SPAC in Malaysia25-Oct-11 Agrees to buy 35% stake in Lime Petroleum for US$55mn14-Aug-12 Enters into agreement to buy 13.04% of 3D Oil at A$2mn; enters into a conditional far-in agreement to buy 50.1% of VIC/P57, and any petroleum recovered

from permit area, for a total consideration of A$13.47M21-Mar-13 Rex Oil and Gas and its wholly owned subsidiary, Rex South East Asia, enter into HiRex Shareholders’ Agreement with Orient Hibiscus, Hibiscus Petroleum

and HiRex with respect of a joint venture between Hibiscus Petroleum and the group for joint venture entity HiRex12-Apr-13 Subsidiary Lime Petroleum secures fourth concession in Middle East region18-Jun-13 HiRex signed an agreement to receive a US$10mn investment from Panama-based Triax Ventures Corp in exchange for a 15% stake3-Sep-13 Oil & gas JV Lime Petroleum gets approval from Norway’s gov’t to buy four production licenses in Norwegian Continental Shelf18-Nov-13 Lime Petroleum to acquire 10% stake in two Norway assets, PL 707 and PL 708, from North Energy20-Sep-13 Bass Strait Oil Company signs agreement with HiRex to use Rex’s technology for exploration opportunities in Australia; HiRex has an option to acquire a

51% stake in the asset if exploration is successful26-Dec-13 Announces results of first exploration well in Oman – non-commercial hydrocarbons found4-Feb-14 Announces oil discovery in second Oman well21-Jan-14 Lime Petroleum announces that it has won five more blocks in Norway13-May-14 Signed Heads of Agreement with 3D Oil for increasing stake in VIC/P57; HiRex also granted option for additional 20% in the block5-Jun-14 Lime Norway acquires 5% stake in PL591 and PL591B, increasing its portfolio of licenses to 1623-Jun-14 Executes agreement to purchase 25% non-operated stake in Kitan producing field from Talisman for US$18mn24-Jul-14 Lime Norway drops 20% stake in each of PL509S, PL509BS and PL509CS; portfolio of licenses in Norway decreased to 1321-Jan-15 Lime Norway awarded a PL591C license, an extension of its current PL591 and PL591B license17-Feb-15 Interests in PL591, PL591B and PL591C to increase from 5% to 25% each4-Mar-15 Issued and allotted 15,024,900 new shares, the Placement Shares for the first tranche of the Placement 1-Apr-15 Lime Norway to acquire additional 10% interest in PL616 from Skagen4416-Apr-15 Lime Norway secures a 30% stake in PL544, increasing its portfolio to 16 licenses in Norway18-May-15 Lime Norway to participate in the drilling of an exploration well in Zumba Prospect in PL591 by Tullow Oil (operator)3-Aug-15 Lime Norway to acquire a 50% interest in PL760 and PL760B from Enquest Norge4-Aug-15 Gulf Hibiscus awarded the South East Ras El Ush concession in Egypt; Gulf Hibiscus’ financial exposure to undertake the minimum work commitment was

estimated to be approximately US$8mn over the first four years 6-Aug-15 Anasuria Hibiscus UK, an indirect wholly owned subsidiary, and Ping Petroleum UK, entered into two conditional SPAs in relation to proposed acquisition19-Aug-15 Lime Norway to acquire 30% interest in PL410 from Lundin11-Sep-15 Placement of 326.93mn new shares, representing up to 25% of the enlarged issued and paid-up share capital26-Oct-15 Commencement of drilling operations at Sea Lion-1 11-Nov-15 Acquisition of Hydra Energy and its 2P reserve in Western Australia; no commercial volume of hydrocarbon in the Sea Lion-1 exploration well2-Dec-15 Polo Resources acquires 8.40% of Hibiscus Petroleum shares via private placement4-Dec-15 Lime Norway to acquire an additional 10% interest in PL707 from North Energy8-Dec-15 Issues press release stating that the share issue by Masirah Oil Ltd. (MOL) diluting Lime Petroleum’s effective stake in MOL from 64% to 6.4% was

improperly carried out11-Dec-15 RIH announces that Lime Petroleum’s interest in Lime Petroleum Norway has changed from 73.82% to 3.51%14-Dec-15 Files application in Isle of Man courts against three directors of Lime Petroleum for breach of trust and/or breach of fiduciary duty related to the stake

dilution in Lime Petroleum Norway20-Jan-16 Proposes acquisition of Anasuria Cluster from Shell UK and Esso Exploration for US$52.5mn (M$228.3mn)11-Mar-16 Completion of Anasuria Cluster acquisition, five-year contract awarded to Petrofac facilities Management as duty holders4-Apr-16 Files complaint at Oslo Conciliation Board for compensation related to financial losses suffered in connection with restructuring undertaken by Lime Norway21-Apr-16 Gulf Hibiscus provides a detailed list of complaints filed against Rex International Holdings and Rex International Investments in various jurisdictions31-May-16 Anasuria Cluster provides significant positive cash flow in 3Q161-Jul-16 Isle of Man court grants order for winding up of Lime Petroleum on grounds that it was unable to pay debts; Hibiscus reiterates that it is ready to bear its

share of all necessary and reasonably incurred expenses of Lime Petroleum9-Aug-16 Placement of 82.305mn new shares, representing up to 6.05% of the enlarged issued and paid-up share capital24-Aug-16 Announces fair value gain of M$364.1mn from consolidation of Anasuria Cluster; no further investments in exploration through Lime Petroleum Group10-Oct-16 Announces acquisition of dormant shelf company Pacific Hibiscus, the sole shareholder of Sea Hibiscus, whose principal activity is oil & gas exploration12-Oct-16 Subsidiary enters into conditional SPA with Sabah Shell Petroleum for acquisition of stake in shallow-water assets in North Sabah15-Aug-17 62mn shares issued at M$0.385/share30-Oct-17 38mn shares issued at M$0.695/share15-Sep-17 31-day planned shutdown of Anasuria FPSO 5-Dec-17 Receives Petronas Carigali’s unconditional consent under the joint operating agreement to the assignment of Shell’s 50% interest in the 2011 North Sabah

EOR PSC8-Dec-17 Proposes issue of up to 317.6mn new warrants on the basis of 1 warrant for every 5 existing shares; warrants issue expected to be completed by 1H1822-Dec-17 SEA Hibiscus, Petronas, the sellers and Petronas Carigali enter into a novation agreement for the assignment and transfer of the entire interest of SSPC

and SSS in 2011 North Sabah EOR PSC to SEA Hibiscus, effective 31 March 20189-Jan-18 Fixes issue price of the third tranche of placement shares at M$0.92 per placement share


15



Figure 21: Share price performance

Source: Bloomberg. Note: Past results are not an indicator of future performance.

Table 14: Management team

KennethPereira

Managing Director

Science (Honours) degree in Engineering from University of Bath, United Kingdom; Master’s in Business Administration from Cranfield Institute of Technology, United Kingdom; Doctorate in Business Administration from University of South Australia, Australia. Dr. Pereira has 25 years’ experience in the oil and gas industry, in both services and exploration & production. He began his career with Schlumberger Overseas S.A in 1983 as a Field Service Engineer working in Brunei, Thailand, France, Libya, Italy, Norway and Tunisia. In 1990, he joined the Sapura Group, overseeing the service of telecommunication products, and later moved to the Group Corporate Planning Department. In 2003, the Sapura Group successfully acquired Crest Petroleum Berhad (Crest Petroleum) and he became the COO of SapuraCrest Petroleum Bhd, an oil and gas services public company listed on the Main Market of Bursa Malaysia Securities Berhad. In 2008, Dr. Pereira became Managing Director of Interlink Petroleum Ltd., an oil and gas exploration & production company listed on the Mumbai Stock Exchange (2009 to 2011). In 2009, he was appointed to the Board of STP Energy Pte Ltd., a privately held Singaporean company with offshore oil and gas exploration interests in New Zealand. Dr. Pereira holds directorships in all of Hibiscus Petroleum’s subsidiaries, 3D Oil Limited and other various private companies.

Pascal Hos CEO Bachelor’s in Science in Mechanical Engineering; Ph.D. in Mechanical Engineering from Rice University. Dr. Hos joined Hibiscus in 2011 as head of Petroleum Engineering and was redesignated COO of HiRex Petroleum in Oct-14. Has over 17 years’ experience in general management, field development, reservoir engineering, production technology and rock mechanics in major local and foreign companies. Includes experience in project management, field development planning, development project execution, well and reservoir management and reserves reporting. Previously worked at Sarawak Shell Berhad (SSB) as Senior Reservoir Engineer.

Mark John Paton

VP,Production & Operations

B.Sc. (Honours) in Chemical Engineering, University of Leeds, United Kingdom. Joined Hibiscus Petroleum in March 2013. Has over 37 years’ experience in the oil and gas industry in both services and exploration & production. Joined BHP in 1989 and held positionsincluding Well Services Supervisor, Production Manager and as General Manager for BHP Petroleum’s Northern Australia Operations.

David Jayakumar Richards

VP,Geoscience

B.Sc. (Honours) in Earth Science, Universiti Kebangsaan Malaysia (National University of Malaysia). Joined Hibiscus Petroleum in Oct-11. Has over 28 years’ experience as a petroleum geoscientist in the exploration, development, production and planning phases of the oil and gas industry. Position prior to joining Hibiscus Petroleum was Senior Geologist with Newfield Sarawak Malaysia Inc.

Devarajan Indran

VP, Petroleum Engineering

B. Petroleum Engineering, Universiti Teknologi Malaysia. Joined Hibiscus Petroleum in Nov-14. Has over 26 years’ experience in the upstream oil and gas industry, with specific expertise in production technology and production optimization. Worked for Petronas Carigali, Shell, PTTEP and Petrofac prior to joining Hibiscus Petroleum.

Yip Chee Yeong

VP, Finance,and Group Controller

Member of the Malaysian Institute of Accountants, Malaysia, and Fellow Member of the Association of Chartered Certified Accountants, United Kingdom. Association of Chartered Certified Accountants qualification, United Kingdom. Joined Hibiscus Petroleum in Nov-13. Has over 23 years’ accounting and finance experience in various industries, namely oil and gas, manufacturing, technology, services, risk consulting, audit and taxation. Was previously CFO at Microsoft Malaysia, where he was responsible for companywide financial management and was a key member of the top management team.


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Corporate structure

Figure 22: Corporate structure

Source: Bloomberg. As of 10-Oct-17. * Subject to claims and ongoing legal proceedings by Hibiscus Petroleum Berhad Group.

17



Capital-raising activities

In a press release on 31-Mar-17, Hibiscus announced its plan for a share placement of ~144.4mn shares, representing 10% of the existing issued ordinary share capital. On 15-Aug-17, it listed its first tranche of placement shares, numbering 62mn shares, raising ~M$23.9mn (or M$0.385/share). On 30-Oct-17, it completed the placement of its second tranche of 38.07mn shares, raising M$26.4mn (or M$0.693/share). On 9-Jan-18, Hibiscus announced the placement of ~44mn shares at M$0.92/share as part of is proposed 144.3mn-share placement.

Table 15: Placement of 144.3mn shares

Tranche Shares (mn) Price (M$) Total (M$ mn)

1st 62.0 0.385 23.92nd 38.1 0.693 26.43rd 44.2 0.920 40.7Total 144.3 91.0


Figure 23: Status of utilization of proceeds from private placement of M$50.3mn

Source: Company data. Proposed utilization from company report dated 28-Nov-17.

On 9-Aug-16, Hibiscus proposed a private placement of 82.3mn shares, representing 6.05% of the existing issued ordinary share capital. The proposed placement was completed on 20-Dec-16, raising a total of M$19.97mn.



1st 82.3 ~0.242 19.97Total 82.3 19.97


Table 17: Proposed utilization of proceeds from private placement of 82.3mn shares

Proposed utilization of proceeds* %

Expected utilization timeframe from date of completion of proposed private placement

Working capital and future developments and/or investments 97.60% Within 12 monthsEstimated expenses relating to proposed private placement 2.40% Within 3 months

Source: Company data. * Proposed utilization from press release dated 9-Aug-16.

On 13-Oct-15, Hibiscus proposed a placement of 326.9mn shares, representing 25% of its issued share capital. The placement of these shares was completed in seven tranches on 13-Jul-16, raising ~M$65.8mn. The rationale for the placement was to:

18



Strengthen the capital base.

Enable the company to raise funds without incurring interest expenses.

Improve liquidity and financial flexibility by strengthening the financial position.

Enable the company to raise funds for ongoing projects, future developments and/or investments and working capital that are expected to contribute positively to earnings.



1st 90.0 0.235 21.22nd 12.4 0.245 3.03rd 19.6 0.200 3.94th 30.0 0.200 6.05th 26.0 0.190 4.96th 100.0 0.180 18.07th 48.9 0.180 8.8Total 326.9 65.8



Proposed utilization of proceeds* % Expected utilization timeframeOngoing projects 51% Within 12 monthsFuture development and/or investments and working capital 46% Within 12 monthsExpenses for proposed placement 3% Within 3 months

Source: Company data. * Proposed utilization from press release dated 11-Sep-15. % of utilization derived from illustrative proceeds of

M$207.9mn. As of 11-Sep-15, ongoing projects included the development of the West Seahorse oilfield in the offshore Gippsland

Basin, Australia, and future development included potential projects in Europe and the Middle East.

On 14-Oct-14, Hibiscus proposed a private placement of 89.16mn shares,representing 10% of its issued share capital. The placement was issued in fivetranches, raising ~M$68mn, and was completed on 6-Aug-15.


Tranche Shares (mn) Price (M$) Total (M$ mn)1st 15.02 0.88 13.22nd 14.12 0.85 12.03rd 6.99 0.67 4.74th 18.20 0.67 12.25th 34.83 0.75 26.1Total 89.16 68.2



Proposed utilization of proceeds* % Expected utilization timeframe

Development of West Seahorse oilfield; drilling of production, appraisal and/or exploration wells in Australia, Asia Pacific and the Middle East 97% Within 15 monthsEstimated expenses for proposed placement 3% Within 1 month

Source: Company data. * Proposed utilization from press release dated 14-Oct-15. % of utilization is derived from illustrative proceeds

of M$130.2mn.

19



Proposed free warrants issue

In a company press release dated 8-Dec-17, Hibiscus Petroleum proposed the issue of up to 317.6mn new warrants on the basis of 1 warrant for every 5 existing shares. The company expects the warrants issue to be completed by 1H18. The proposed free warrants issue is subject to approvals by regulators, shareholders and any other relevant authorities.

The exercise price of the warrants will be determined and announced at a later date by the Hibiscus Board after obtaining the relevant approvals. The exercise price of each new warrant is subject to a fixed annual step-up of M$0.06 per year on each of the anniversary dates from the date of first issuance of the warrants.

The company expects to utilize the proceeds from the warrants exercised for potential expansion and capital expenditure primarily related to the maintenance and upgrading of assets to improve operational efficiency and potentially enhance production and asset life. The proceeds will also be used to repay any future borrowings and working capital requirements.

Rex International Holdings (RIH) litigation

On 24-Dec-15, Hibiscus Petroleum announced that it had filed an application in the Isle of Man courts through its subsidiary, Gulf Hibiscus Limited, to enable Lime Petroleum, Hibiscus Petroleum’s 35% subsidiary, to make claims against three directors of Lime Plc related to a breach of trust and breach of fiduciary duty by the directors (including directors nominated to the Board by REC Middle East and Schroder & Co. Banque (other partners in Lime Plc)), particularly with regard to their conduct in relation to the actions taken to effect a substantial dilution (from 73.82% to 3.51%) of Lime Plc’s shareholding interest in Lime Petroleum Norway AS (LPN) under a restructuring undertaken by LPN.

The Isle of Man court delivered judgment on 30 June 2016, ordering the winding up of Lime Petroleum Plc on the grounds that it was unable to pay its debts. Gulf Hibiscus reiterated its position of being prepared to pay its share of all proper and reasonably incurred necessary expenses of Lime Petroleum Plc. In the same judgement, the court also dismissed Gulf Hibiscus’s application to bring derivative claims on behalf of Lime against the Lime Directors.

Capital injection exercise by RIH in Masirah Oil Ltd. (MOL) that reduced Lime Petroleum’s stake in MOL from 64% to 6.4%

In a press release dated 16-Nov-15, RIH announced that it had completed a capital injection exercise to increase its stake in MOL. MOL had issued 9,000 new shares at US$1,426/share, of which 5,760 shares were subscribed by Rex Oman, RIH’s subsidiary, and the rest by Petroci (an existing partner in MOL). Post-completion of the capital injection exercise, RIH’s effective stake increased from 41.60% to 61.76%, and Lime’s stake declined from 64% to 6.4%.

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Figure 24: MOL shareholding, per RIH

Source: RIH press release dated 7-Dec-15.

In reply to the capital injection activity carried out by RIH, Hibiscus issued a press release on 8-Dec-15 stating that the share issue by MOL was improperly carried out.

Table 22: MOL shareholding

Before capital injectionAdditional

shares issued After capital injection

Shareholder Shares % Shares Shares %Lime 640 64% 0 640 6.4%Petroci 360 36% 3,240 3,600 36.0%Rex Oman 0 0% 5,760 5,760 57.6%Total 1,000 100% 9,000 10,000 100.0%

Source: RIH press release.

RIH announces restructuring exercise to be carried out by LPN reducing Lime Petroleum’s stake in LPN from 73.82% to 3.51%

In a press release dated 14-Dec-15, RIH announced that its subsidiary LPN hadcompleted a restructuring exercise of its share capital. RIH’s effective stake in LPN increased from 74.16% to 98.77%, and Lime Petroleum’s stake declined from 73.82% to 3.51%.

LPN undertook a capital reduction exercise and a subsequent increase in share capital through a new share issue. Following regulatory approval of the capital reduction, LPN’s share capital was restructured to NOK80.32mn (or ~US$9.27mn, based on an exchange rate of US$1:NOK8.6603 as of 11-Dec-15) from NOK382mn (~US$44.11mn) by catering for uncovered losses of NOK30.9mn (~US$3.57mn) and transferring NOK270.8mn (~US$31.27mn) to other equity. The exercise included the cancellation of 900,000 LPN shares held by Rex International Investments (RII), a wholly owned subsidiary of RIH, and NOK77.4mn (~US$8.94mn) was repaid to RII. RII then reinvested the NOK77.4mn into LPN’s subsequent share capital increase.

21



Figure 25: LPN restructuring

Source: RIH press release dated 14-Dec-15.

On 24-Dec-15, Hibiscus Petroleum announced that it had filed an application in the Isle of Man courts through its subsidiary Gulf Hibiscus Limited to enable Lime Petroleum to make claims against three directors of Lime Plc, including directors nominated to the Board by REC Middle East and Schroder & Co. Banque (other partners in Lime Plc).

The application relates to a breach of trust and breach of fiduciary duty by the directors, particularly with regard to their conduct in relation to the actions taken to effect a substantial dilution of Lime Plc’s shareholding interest in LPN under a restructuring undertaken by LPN.

Liquidation of Lime Petroleum

The Isle of Man court delivered judgment on 30 June 2016, ordering the winding up of Lime Petroleum Plc on the grounds that it was unable to pay its debts. Gulf Hibiscus reiterated its position of being prepared to pay its share of all proper and reasonably incurred necessary expenses of Lime Petroleum Plc. In the same judgement, the court also dismissed Gulf Hibiscus’s application to bring derivative claims on behalf of Lime against the Lime Directors.

22



Valuation comparables

Table 23: Valuation comparables

Mcap P/E (x) P/B (x) EV/EBITDA (x) Dividend yield ROE (%) Net debt to equity (%)($bn) 17Y 18Y 17Y 18Y 17Y 18Y 17Y 18Y 17Y 18Y 17Y 18Y

Hibiscus Petroleum* 0.4 8.8 5.8 1.5 1.2 3.6 0.9 0.0% 0.0% 18.7 24.0 net cash net cashPTTEP 13.4 15.0 13.8 1.0 1.0 3.5 3.2 3.7% 3.7% 7.6 8.1 net cash net cashCNOOC 69.6 14.3 12.4 1.1 1.0 5.9 5.1 2.9% 2.9% 8.0 9.0 14.7 8.3Inpex 19.7 32.6 20.9 0.8 0.8 5.7 5.0 1.2% 1.5% 2.2 3.4 14.9 19.3PetroChina-H 233.8 0.0 0.0 0.0 0.0 7.6 6.8 1.0% 1.7% 2.1 3.5 250.8 191.1ONGC 39.8 10.4 9.7 1.1 1.0 4.2 4.0 4.2% 4.7% 10.8 10.9 net cash net cashReliance Industries 95.8 18.5 16.4 2.1 1.9 13.7 11.1 0.6% 0.7% 11.9 12.1 81.7 66.7Oil Search 9.4 18.4 19.5 1.8 1.7 11.1 11.5 2.0% 1.9% 10.2 9.1 50.9 53.9Santos 9.1 16.9 19.1 1.2 1.2 8.1 8.1 0.0% 1.4% 7.0 6.0 31.9 23.6Woodside Petroleum 22.7 15.1 14.7 1.5 1.5 8.4 8.0 4.1% 4.2% 9.0 9.0 22.6 17.9

Anadarko Petroleum 30.3 - - 3.1 3.6 13.6 7.8 1.9% 1.9% -11.0 -2.9 114.7 163.9Antero Resources 6.0 95.6 29.9 0.8 0.8 7.6 6.2 0.0% 0.0% 0.9 2.6 63.8 72.2Apache 16.8 399.9 50.0 2.4 2.2 7.3 6.5 2.3% 2.3% 0.6 4.6 88.8 92.5Cimarex Energy 12.0 28.4 20.7 4.8 3.9 10.9 8.6 0.5% 0.5% 17.3 20.7 40.3 36.1Concho Resources 23.0 84.9 83.1 2.6 2.5 14.2 12.2 0.0% 0.0% 3.3 3.1 31.2 30.1Continental Resources 21.2 297.5 120.3 4.8 4.2 12.4 9.1 0.0% 0.0% 1.6 3.8 143.4 112.4Devon Energy 22.2 23.4 19.1 3.0 2.6 7.7 6.9 2.3% 2.3% 14.3 14.8 99.9 87.4EOG Resources 64.8 147.4 67.9 4.6 4.4 15.2 11.9 0.6% 0.6% 3.1 6.7 38.0 35.7EQT 14.9 78.4 131.8 0.9 1.3 11.7 6.4 0.2% 0.2% 1.5 1.0 29.0 58.1Hess 16.8 - - 1.3 1.5 10.2 11.7 1.9% 1.9% -10.8 -8.6 16.0 31.1Marathon Oil 15.2 - - 1.3 1.3 7.5 6.4 3.8% 3.8% -2.0 -1.8 39.4 32.7Murphy Oil 5.8 - 259.0 1.2 1.2 6.9 6.0 4.0% 4.1% -0.8 0.5 39.8 43.2Noble Energy 15.3 - 116.1 1.5 1.5 9.6 7.3 0.0% 0.0% 0.0 1.3 66.0 53.2Pioneer Natural 30.4 98.7 40.5 2.8 2.7 14.5 10.0 0.0% 0.0% 2.9 6.8 16.4 13.5Range Resources 4.2 42.0 26.6 0.7 0.7 67.7 53.0 1.0% 1.0% 1.8 2.8 71.6 69.6Southwestern Energy 2.8 12.3 5.9 1.5 1.2 5.9 4.1 0.0% 0.0% 16.4 23.1 190.1 147.8Cenovus Energy 12.8 17.7 131.1 0.7 0.8 7.7 6.5 1.5% 1.7% 5.7 0.6 41.2 34.8Chevron 244.4 29.2 20.3 1.7 1.6 10.1 8.2 3.4% 3.4% 5.7 8.1 23.0 19.1ConocoPhillips 68.9 96.1 24.0 2.4 2.3 8.6 6.8 1.8% 2.0% 2.3 9.5 47.4 39.2Delek US Holding 3.0 41.8 18.2 2.2 2.0 9.7 6.1 1.7% 2.2% 6.3 11.1 45.1 35.4Exxon Mobil 364.7 23.2 17.2 2.0 1.9 10.0 7.9 3.6% 3.6% 9.0 11.4 19.4 13.1Marathon Petroleum 33.9 18.0 17.0 2.8 2.8 7.7 7.6 2.2% 2.5% 14.9 16.1 98.9 120.6Occidental Pete 56.8 88.4 35.4 2.8 2.9 11.9 8.4 4.1% 4.2% 3.1 8.1 38.6 34.2Aker Solutions 1.6 38.3 51.5 1.9 1.9 10.4 10.1 0.0% 0.8% 5.3 3.8 33.8 24.0Cairn Energy 1.8 - - 0.9 0.9 -18.7 6.7 0.0% 0.0% -5.0 -0.9 net cash net cashEnquest 0.6 - 5.6 0.8 0.7 7.9 2.4 0.0% 0.0% -8.2 12.9 237.7 160.6Genel Energy 0.5 11.6 10.8 0.3 0.3 4.5 4.2 0.0% 0.0% 2.9 3.0 16.2 13.8Lundin Petroleum 8.3 48.4 54.8 - 98.7 54.9 57.7 0.0% 0.0% -113.7 1445.6 net cash 4607.7Soco Int’l 0.5 - 167.1 0.7 0.7 4.7 3.2 0.1% 0.0% -0.6 0.5 net cash net cashTullow Oil 4.1 13.6 13.5 1.7 1.5 5.3 4.9 0.0% 0.0% -24.2 11.8 147.1 112.7

Source: Bloomberg, J.P. Morgan. * Hibiscus is based on Bloomberg consensus. Priced as of 10-Jan-18. Hibiscus year-end is June. 17Y and 18Y represent Jun-18E and Jun-19E, respectively

23



Financial summary

Income statement

Table 24: Income statement

Period 12 months 12 months 9 months 18 months 12 months 12 monthsEnded 31-Mar-12 31-Mar-13 31-Dec-13 30-Jun-15 30-Jun-16 30-Jun-17M$ in 000s FY12 FY13 2013 2015 FY16 FY17Revenue 7,961 8,516 13,344 15,586 81,695 261,273 Cost of sales - - - - (40,803) (93,089)Gross profit 7,961 8,516 13,344 15,586 40,891 168,184 Other income - 1,255 18,190 10,697 9,286 37,883 Administrative expenses (6,270) (15,343) (22,311) (65,187) (363,994) (49,059)Other expenses (6,050) (748) (5,890) (8,761) (30,901) (72,454)EBIT (4,358) (6,320) 3,333 (47,665) (344,718) 84,554 Finance cost - (2,583) (2,693) (8) (8,196) (22,036)Share of results of associates & JV - 4,973 (3,364) (28,139) (67,539) (512)Negative goodwill from business combination - - - - 364,132* 0 Gain on dilution of interest in a JV - - 13,455 -PBT (4,358) (3,930) 10,730 (75,812) (56,321) 62,007 Tax (526) (267) 1,405 1,596 (3,639) 44,090 PAT (4,884) (4,197) 12,135 (74,216) (59,960) 106,097 Minority interest 0 0 0 0 0 0 PATMI (4,884) (4,197) 12,135 (74,216) (59,960) 106,097 D&A 115 230 511 8,761 (30,901) (72,454)EBITDA (4,474) (6,550) 2,821 (56,427) (17,224) 153,497 Interest expense (included in finance expense) 0.0 0.0 0.0 0.0 1,477.0 2,647.8 EPS (M$) (0.0) (0.0) 0.0 (0.1) (0.1) 0.1 Number of shares (000x) 304,986.7 436,890.4 461,926.1 766,407.8 1,058,755.1 1,413,201.8

Revenue 7,961 8,516 13,344 15,586 81,695 261,273 Anasuria - - - 0 78,654 256,817 3D Oil, VIC/L31 and VIC/P57 - 127 317 0 101 0 Investment holdings and group activities 7,961 8,389 13,027 15,586 2,940 4,455 Lime - - - 0 0 0 HiRex - - - 0 0 0

Profit from operations (4,358) (6,320) 3,333 (41,603) (65,728) 91,338 Anasuria - - - 0 (17,434) 106,307 3D Oil, VIC/L31 and VIC/P57 - (1,431) 50 (34,531) (25,240) (12,206)Investment holdings and group activities (4,358) (4,889) 3,283 (7,072) (23,053) (2,764)Lime - - - 0 0 0 HiRex - - - 0 0 0

PAT (4,884) (4,197) 12,135 (74,216) (59,960) 106,097 Anasuria - - - 0 336,373 129,818 3D Oil, VIC/L31 and VIC/P57 - 4,827 (1,544) (47,394) (53,310) (23,390)Investment holdings and group activities (4,884) (6,743) 3,245 (126) (50,580) (331)Lime - (2,337) (1,968) (19,504) (285,993) 0 HiRex - - 12,462 (7,192) (6,450) 0 Elimination - 56 (61) - - -

ImpairmentsAnasuria (4,342)3D Oil, VIC/L31 and VIC/P57 (17,549) 1,946Investment holdings and group activities (2,232) (4,389)Lime (224,354) 0HiRex (4,648) 0

Source: Company data. * Related to the acquisition of Anasuria Cluster.

24



Balance sheet

Table 25: Balance sheet

Period 12 months 12 months 9 months 18 months 12 months 12 monthsEnded 31-Mar-12 31-Mar-13 31-Dec-13 30-Jun-15 30-Jun-16 30-Jun-17M$ in 000s FY12 FY13 2013 2015 FY16 FY17Non-current assets 12,918 242,942 315,825 464,557 1,210,538 1,235,998Investments in subsidiaries - - - - - -Investment in an associate - 14,161 13,758 5,022 1,940 4,090Investments in JVs 12,258 180,770 209,156 259,309 - -Intangible assets - 44,179 61,787 144,774 997,146 1,029,293Equipment 660 3,831 31,124 55,451 211,452 202,616

Current assets 220,596 127,307 72,837 86,480 58,629 83,587Trade receivables 0 0 0 0 1,985 7,434Other receivables, deposits and prepayments 217 656 2,239 67,477 21,502 17,465Tax recoverable 0 90 1,241 0 0 0Inventories 0 0 0 0 5,543 3,997Amounts owing by subsidiaries 0 0 0 0 0 0Amount owing by a JV 1,855 572 4,984 12,102 121 191Amount by an associate 0 0 1,967 970 733 0Amount owing by a related party 0 0 0 0 0 0Fixed deposits with licensed banks 50,016 58,881 34,755 0 0 0Cash and bank balances 168,508 67,108 27,650 5,930 28,746 54,501

Total assets 233,514 370,249 388,662 551,037 1,269,167 1,319,586

Current liabilities 1,328 49,280 18,527 39,300 150,658 125,070Trade payables 0 0 0 0 60 242Other payables and accruals 627 5,116 16,242 26,970 88,775 54,765Deferred consideration 0 0 0 0 55,809 31,428Amount owing to subsidiaries 0 0 0 0 0 0Amount owing to a JV 0 0 0 241 315 337Amount owing to an associate 0 29,677 1,018 11,849 5,449 25Provision for taxation 481 6 40 21 30 38,054Dividend bonus payable 0 14,261 0 0 0 0Amount owing to a related party 0 0 0 0 0 0Redeemable convertible preference shares 219 219 219 219 219 219Convertible redeemable preference shares 0 0 1,008 0 0 0

Net current assets 221,924 176,587 91,364 125,780 209,287 208,658Deferred expenditure - - - - - -

Share capital 4,180 4,404 5,099 9,278 13,126 675,315Reserves 227,964 236,877 365,036 502,459 571,132 67,047

Other reserves 234,053 247,163 363,187 574,404 703,037 92,855Accumulated losses (6,089) (10,286) 1,849 (71,945) (131,904) (25,808)Shareholders’ fund 232,145 241,281 370,135 511,737 584,259 742,362Minority interest 0 0 0 0 0 0

Long-term liabilities 41 79,687 0 0 534,251 452,154Deferred consideration - - - - 26,549 -Contingent consideration - - - - 1,484 1,756Deferred tax liabilities 41 318 - - 390,866 325,562Convertible redeemable preference shares - 79,369 - - - -Provision for decommissioning costs - - - - 115,352 124,835Total liabilities 232,186 320,969 370,135 511,737 1,118,510 1,194,516

Total liabilities and shareholders’ equity 233,514 370,248 388,662 551,037 1,269,167 1,319,586


25



Cash flow statement

Table 26: Cash flow statement

Period 12 months 12 months 9 months 18 months 12 months 12 monthsEnded 31-Mar-12 31-Mar-13 31-Dec-13 30-Jun-15 30-Jun-16 30-Jun-17M$ in 000s FY12 FY13 2013 2015 FY16 FY17Cash flow from operations (5,787) 25,173 (36,765) (35,008) 62,496 96,505 Profit/(loss) before taxation (4,358) (3,930) 10,730 (75,812) (56,321) 62,007 Adjustments for:

D&A of equipment and intangible assets 115 230 511 8,761 30,901 72,454 Interest income (6,112) (2,332) (1,334) (1,081) (116) (16)Unrealized (gain)/loss on foreign exchange 12 (1,005) 4,519 (6,720) (877) (17,532)Listing expenses 216 - - - - -Qualifying acquisition expenses 5,706 46 - - - -Finance costs - 2,583 2,693 8 8,196 22,036 Impairment of investment in subsidiaries - - - - - -Reversal of impairment of investment in an associate - - - 6,062 (683) (1,946)Impairment of investment in JVs - - - - 229,002 -Impairment of intangible assets - - - - 17,549 -Impairment of other receivables and amounts owing by subsidiaries, JVs, an associate and a related party - - - 242 2,232 8,730 Share of results of an associate - (7,310) 404 1,443 4,099 512 Share of results of JVs - 2,337 2,961 26,696 63,440 -Negative goodwill from business combination - - - - (364,132) -Write-off of business development expenditure - - - - 30,890 -Gain on dilution of interest in a JV - - (13,455) - - -Reversal of discovery bonus payable - - (15,793) - - -

Operating profit/(loss) before working capital changes (4,421) (9,382) (8,764) (40,400) (35,820) 146,243 Trade receivables - - - - (1,436) (5,062)Other receivables, deposits and prepayments 195 (436) (1,279) (15,998) 18,218 7,695 Trade payables - - - - 89 177 Other payables and accruals 294 4,214 5,960 16,354 61,901 (48,910)Inventories - - - - 16,688 1,946 Amounts owing by joint ventures (1,855) 1,372 (4,412) (6,841) 10,167 (478)Amount owing to a joint venture - - - 240 (747) -Amount owing by an associate - - (1,996) 743 250 797 Amount owing to an associate - 29,406 (26,274) 10,894 (6,813) (5,906)Income tax paid (4) (557) 0 2,815 (1) (11,335)Net cash from operating activities (5,790) 24,616 (36,765) (32,192) 62,495 85,169 Cash flow from investing (12,371) (209,326) (56,966) (209,644) (131,837) (83,403)Purchase of equipment (769) (3,401) (28,236) (33,410) (27) (707)Interest received 6,112 2,332 1,334 1,081 116 16 Qualifying acquisition expenses paid (5,457) (295) - - - -Investment in an associate - (6,852) - - - -Investment in JVs (12,258) (157,335) (7,947) (49,059) - -Acquisition of intangible assets - (43,775) (22,117) (83,953) (104,358) (869)Deposit for an investment - - - (44,303) - (10,436)Net cash outflow arising from business combination - - - - (27,569) (71,408)Advances to subsidiaries - - - - - -Free cash flows (6,556) 21,772 (65,000) (68,417) 62,470 95,797 Cash flow from financing 235,496 90,013 32,915 180,645 95,222 42,035 Net proceeds from issuance of ordinary shares 241,161 11,173 6,543 186,099 92,572 27,792 Proceeds from issuance of CRPS and related exp. paid - 79,480 20,918 - - -Cash advances from directors - - - - 3,150 -Repayment of cash advances from directors - - - - (500) (2,650)Share issuance costs paid (5,449) (1,140) - - - -Deposit refunded to a conv. redeemable pref. shares place - 500 5,454 (5,454) - -Advances from subsidiaries - - - - - -Advances from a third party - - - - - 16,893 Listing expenses paid (216) - - - - -Net increase/(decrease) in cash and cash equivalents 217,334 (94,697) (60,816) (61,191) 25,880 43,801 Effects on foreign exchange rate changes (1,326) 2,162 (2,768) 4,716 (3,064) (18,046)Cash and cash equivalents at beginning of financial year 2,516 218,524 125,989 62,405 5,930 28,746 Less: Cash restricted in use - (500) (5,737) - - -Cash and cash equivalents at end of financial year 218,524 125,989 62,405 5,930 28,746 54,501


26



Ratios

Table 27: Ratio analysis

Period 12 months 12 months 9 months 18 months 12 months 12 monthsEnded 31-Mar-12 31-Mar-13 31-Dec-13 30-Jun-15 30-Jun-16 30-Jun-17

FY12 FY13 2013 2015 FY16 FY17MarginsGross margin (pre-depreciation) 99% 97% 96% 44% 88% 92%Gross margin 100% 100% 100% 100% 50% 64%EBITDA margin -21% 59%PBT margin -55% -46% 80% -486% -69% 24%PAT margin -61% -49% 91% -476% -73% 41%PATMI margin -61% -49% 91% -476% -73% 41%

Profitability ratiosRoA = PAT/(total assets - current liabilities (ex-bank debt)) -2.1% -1.3% 3.3% -14.5% -5.4% 8.9%RoCE = (EBIT)/avg. CE n/a -1.9% 0.8% -9.6% -34.3% 5.9%RoIC = (EBIT/(avg. net debt + equity) n/a -5.3% 1.3% -11.2% -65.0% 13.6%ROE – Total -2.1% -1.7% 3.3% -14.5% -10.3% 14.3%

M$ in 000sTotal assets 233,514 370,249 388,662 551,037 1,269,167 1,319,586Total assets - current liabilities (ex-bank debt) 232,186 320,969 370,135 511,737 1,118,510 1,194,516Net assets 221,924 176,587 91,364 125,780 209,287 208,658Total equity 232,145 241,281 370,135 511,737 584,259 742,362Capital employed 234,842 419,528 407,189 590,338 1,419,825 1,444,656Avg. capital employed 327,185 413,359 498,763 1,005,081 1,432,240Invested capital 63,637 174,174 342,484 505,807 555,513 687,861Average invested capital 118,905 258,329 424,145 530,660 621,687

Leverage ratios Net debt/equity -73% -28% -7% -1% -5% -7%EBITDA/interest expense (x) -11.7 58.0

Liquidity ratiosCurrent ratio (x) 166.1 2.6 3.9 2.2 0.4 0.7Quick ratio (x) 166.1 2.6 3.9 2.2 0.4 0.6

DuPont decompositionPATMI margin -61% -49% 91% -476% -73% 41%Revenue/assets 0.0 0.0 0.0 0.1 0.2Assets/equity 0.0 0.0 0.0 0.1 0.4ROE (DuPont) -0.1% 0.2% -0.6% -1.1% 3.6%


27



Quarterly summary

Table 28: Quarterly financials

M$ in 000s 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18

Revenue 48,717 54,745 62,821 69,242 74,465 58,236Cost of sales (17,005) (24,224) (17,581) (22,562) (28,722) (18,996)Gross profit 31,712 30,521 45,240 46,680 45,743 39,240Other income 1,504 11,114 10,792 6,976 9,162 685Administrative expenses (213,066) (10,033) (18,580) (14,895) (5,575) (7,707)Other expenses (21,323) (17,577) (21,060) (15,675) (18,278) (16,791)Finance cost (6,163) (6,567) (6,290) (5,990) (3,189) (5,343)Share of results of associates and JV 1,785 23 (70) (305) (160) (362)Negative goodwill from business combination 228,789 0 0 0 0 0PBT 23,238 7,481 10,032 16,791 27,703 9,722Tax (4,286) 72,802 643 (10,306) (19,049) 1,062PAT 18,952 80,283 10,675 6,485 8,654 10,784Minority interest 0 0 0 0 0 0PATMI 18,952 80,283 10,675 6,485 8,654 10,784D&A (18,061) (17,183) (21,454) (15,675) (18,142) (13,796)EBITDA 47,462 31,231 37,776 38,456 49,034 28,861


Table 29: Segment financials

M$ in 000s 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18Revenue 48,717 54,745 62,821 69,242 74,465 58,236 Anasuria 48,417 53,694 61,788 68,052 73,284 57,048 3D Oil, VIC/L31 and VIC/P57 2 1 (1) 0 0 3 Investment holding and group activities 298 1,050 1,034 1,190 1,181 1,185

EBITDA 47,462.0 31,231.0 37,776.0 38,456.0 49,034.0 28,861.0Anasuria 27,117.0 38,090.0 40,016.0 55,296.0 33,250.0Others 4,114.0 (314.0) (1,560.0) (6,262.0) (4,389.0)

Profit from operations (2,857) 13,431 19,338 23,861 34,709 14,448 Anasuria 15,346 13,469 23,777 30,576 38,486 23,003 3D Oil, VIC/L31 and VIC/P57 (12,789) 1,687 (14,547) 539 115 459 Investment holding and group activities (5,414) (1,725) 10,108 (7,254) (3,892) (9,014)

Impairment and other write-downs (198,316) 594 714 (4,435) (3,657) 979Anasuria 0 (4,488) 146 03D Oil, VIC/L31 and VIC/P57 63,808 754 770 153 269 1,885Investment holding and group activities (33,122) (160) (56) (100) (4,072) (906)Lime (224,354)HiRex (4,648)

Share of results of associates and JV 1,758 23 (70) (305) (160) (362)Anasuria 0 03D Oil, VIC/L31 and VIC/P57 (64) 23 (70) (305) (160) (362)Investment holding and group activities 0 0Lime 2,109 0

PBT 23,238.0 7,481.0 10,032.0 16,791.0 27,703.0 9,722.0Anasuria 8,345.0 14,489.0 22,004.0 37,739.0 19,039.0Others (864.0) (4,457.0) (5,213.0) (10,036.0) (9,317.0)

PAT 18,952 80,283 10,675 6,485 8,654 10,784 Anasuria 234,483 84,189 15,210 13,645 16,773 20,107 3D Oil, VIC/L31 and VIC/P57 48,690 (3,577) (16,269) (1,631) (1,914) (492)Investment holding and group activities (37,068) (329) 11,734 (5,529) (6,205) (8,831)Lime (222,245) 0 0 0 0 0 HiRex (4,908) 0 0 0 0 0


28



Quarterly performance

Table 30: Quarterly performance: 1Q18 vs. 1Q17 vs. 4Q17

M$ in 000s 1Q18 1Q17 y/y 4Q17 q/q FY17A FY16A y/y

Revenue 58,236 54,745 6.4% 74,465 -21.8% 261,273 81,695 219.8%Cost of sales (18,996) (24,224) -21.6% (28,722) -33.9% (93,089) (40,803) 128.1%Gross profit 39,240 30,521 28.6% 45,743 -14.2% 168,184 40,891 311.3%Other income 685 11,114 -93.8% 9,162 -92.5% 37,883 9,286 308.0%Administrative expenses (7,707) (10,033) -23.2% (5,575) 38.2% (49,059) (363,994) -86.5%Other expenses (16,791) (17,577) -4.5% (18,278) -8.1% (72,454) (30,901) 134.5%Finance cost (5,343) (6,567) -18.6% (3,189) 67.5% (22,036) (8,196) 168.9%Share of results of associates and JV (362) 23 -1673.9% (160) 126.3% (512) (67,539) -99.2%Negative goodwill from business combination 0 0 na 0 na 0 364,132 -100.0%PBT 9,722 7,481 30.0% 27,703 -64.9% 62,007 (56,321) -210.1%Tax 1,062 72,802 -98.5% (19,049) -105.6% 44,090 (3,639) -1311.6%PAT 10,784 80,283 -86.6% 8,654 24.6% 106,097 (59,960) -276.9%Minority interest 0 0 na 0 na 0 0 naPATMI 10,784 80,283 -86.6% 8,654 24.6% 106,097 (59,960) -276.9%D&A (13,796) (17,183) -19.7% (18,142) -24.0% (72,454) (30,901) 134.5%EBITDA 28,861 31,231 -7.6% 49,034 -41.1% 153,497 (17,224) -991.2%


Table 31: Quarterly performance: 1Q18 vs. 1Q17 vs. 4Q17

M$ in 000s 1Q18 1Q17 y/y 4Q17 q/q FY17A FY16A y/yRevenue 58,236 54,745 6.4% 74,465 -21.8% 261,273 81,695 219.8%Anasuria 57,048 53,694 6.2% 73,284 -22.2% 256,817 78,654 226.5%3D Oil, VIC/L31 and VIC/P57 3 1 200.0% 0 na 0 101 -100.0%Investment holding and group activities 1,185 1,050 12.9% 1,181 0.3% 4,455 2,940 51.5%

EBITDA 28,861 31,231 -7.6% 49,034 -41.1% 156,497 (17,224) -1008.6%Anasuria 33,250 27,117 22.6% 55,296 -39.9% 160,519 363,777 -55.9%Others (4,389) 4,114 -206.7% (6,262) -29.9% (4,022) (381,001) -98.9%

Profit from operations 14,448 13,431 7.6% 34,709 -58.4% 91,338 (65,728) -239.0%Anasuria 23,003 13,469 70.8% 38,486 -40.2% 106,307 (17,434) -709.8%3D Oil, VIC/L31 and VIC/P57 459 1,687 -72.8% 115 299.1% (12,206) (25,240) -51.6%Investment holding and group activities (9,014) (1,725) 422.6% (3,892) 131.6% (2,764) (23,053) -88.0%

Impairment and other write-downs 979 594 64.8% (3,657) -126.8% (6,784) (278,990) -97.6%Anasuria 0 0 na 146 -100.0% (4,342) 0 na3D Oil, VIC/L31 and VIC/P57 1,885 754 150.0% 269 600.7% 1,946 (16,866) -111.5%Investment holding and group activities (906) (160) 466.3% (4,072) -77.8% (4,388) (33,122) -86.8%Lime 0 0 na 0 na 0 (224,354) -100.0%HiRex 0 0 na 0 na 0 (4,648) -100.0%

Share of results of associates and JV (362) 23 -1673.9% (160) 126.3% (512) (67,539) -99.2%Anasuria 0 0 na 0 na 0 0 na3D Oil, VIC/L31 and VIC/P57 (362) 23 -1673.9% (160) 126.3% (512) (4,099) -87.5%Investment holding and group activities 0 0 na 0 na 0 0 naLime 0 0 na 0 na 0 (61,639) -100.0%

PBT 9,722 7,481 30.0% 27,703 -64.9% 62,007 (56,321) -210.1%Anasuria 19,039 8,345 128.1% 37,739 -49.6% 82,577 339,979 -75.7%Others (9,317) (864) 978.4% (10,036) -7.2% (20,570) (396,300) -94.8%

PAT 10,784 80,283 -86.6% 8,654 24.6% 106,097 (59,960) -276.9%Anasuria 20,107 84,189 -76.1% 16,773 19.9% 129,818 336,373 -61.4%3D Oil, VIC/L31 and VIC/P57 (492) (3,577) -86.2% (1,914) -74.3% (23,390) (53,310) -56.1%Investment holding and group activities (8,831) (329) 2584.2% (6,205) 42.3% (331) (50,580) -99.3%Lime 0 0 na 0 na 0 (285,993) -100.0%HiRex 0 0 na 0 na 0 (6,450) -100.0%


29



Anasuria Cluster: Quarterly performanceTable 32: Anasuria Cluster quarterly financial performance

M$ in 000s 1Q18 1Q17 y/y 4Q17 q/q FY17A FY16A y/y

Revenue 57,048 53,694 6.2% 73,284 -22.2% 256,817 78,654 226.5%EBITDA 33,250 27,117 22.6% 55,296 -39.9% 160,519 363,777 -55.9%Profit from operations 23,003 13,469 70.8% 38,486 -40.2% 106,307 (17,434) -709.8%PBT 19,039 8,345 128.1% 37,739 -49.6% 82,577 339,979 -75.7%PAT 20,107 84,189 -76.1% 16,773 19.9% 129,818 336,373 -61.4%Anasuria EBITDA margin (%) 58.3% 50.5% 15.4% 75.5% -23% 62.5% - -Anasuria PBT margin (%) 33.4% 15.5% 114.7% 51.5% -35% 32.2% - -Anasuria PAT margin (%) 34.5% 153.8% -77.5% 22.5% 53% 50.5% - -


Table 33: Anasuria Cluster quarterly operational performance

Anasuria operating indicators 1Q18 1Q17 y/y 4Q17 q/q FY17AAverage daily oil production rate (bbl/day) 2,576 3,032 -15.0% 3,204 -19.6% 3,197Average daily gas export rate (boe/day) 156 374 -58.3% 317 -50.8% 356Average oil equivalent production rate (boe/day) 2,731 3,406 -19.8% 3,522 -22.5% 3,552Total oil sold (kbbl) 246 272 -9.4% 285 -13.6% 1,129Total gas exported (sold) (mmscf) 87 206 -57.8% 173 -49.7% 779Average realized oil price (US$/bbl) 51.54 45.21 14.0% 50.46 2.1% 47.58Average gas price (US$/mmbtu)

For Cook field 1.58 1.33 18.8% 1.60 -1.3% 1.69For Guillemot A, Teal and Teal South fields. 3.86 3.30 17.0% 3.86 0.0% 4.07

Average opex (US$ per boe) 23.61 18.39 28.4% 13.98 68.9% 15.10Average uptime/availability of Anasuria facilities 70% 82% -14.6% 84% -16.7% 85%


1Q18 net profit up 25% q/q; lower oil production due to shutdown offset by higher realized oil price

Hibiscus Petroleum reported 1Q18 net profit of M$10.78mn, up 24.6% q/q. This was due mainly to higher average realized oil prices, up to US$51.5/bbl in 1Q18 from US$50.5/bbl in 4Q17. The company reported a 20% q/q fall in oil production due to the planned shutdown of Anasuria FPSO for 31 days (16 days in the current quarter) from mid-September onward. This also led to an increase in opex from US$13.98/bbl in 4Q17 to US$23.61 in 1Q18. EBITDA margin for 1Q18 was 58% vs. the 4Q17 EBITDA margin of 75%.

30



Appendix I: Insight into E&P valuations and fiscal systemsHow E&P valuations work

There are three main variables of focus when investing in oil and gas: production, reserves and cash flow. With the industry known for heavy investments and low earnings, ratios such as sales and earnings multiples are less relevant.

Net asset value (NAV): NAV remains the preferred technique for valuing E&P companies. NAV assumes that a company adds nothing to its existing reserves and that it produces or continues to produce until it runs out of reserves completely.

Reserves: E&P companies can be valued via reserves/resource multiples such as EV/2P (enterprise value divided by 2P reserves) and EV/(2P+2C) (enterprise value divided by 2P+2C resources). These are important metrics for evaluating acquiredproperties when little is known about their cash flows. These metrics yield values of a firm per barrel of oil equivalent.

However, EV/reserves and EV/resources have some limitations: (1) they provide no information on the oil/gas mix in a reserve portfolio; (2) they vary by capex intensity; and (3) they carry premiums/discounts, depending on the geography of an asset.

Cash flow

1. EV/DACF (enterprise value/debt-adjusted cash flow): Cash flow is one of the most important measures of performance in the oil and gas industry because the industry generally carries high levels of debt.

2. EV/EBITDAX: EBITDAX is used for oil E&P companies. It excludes exploration expenses. Proven, producing reserves generate EBITDAX, which is similar to EBITDA, but neutralizes exploration expenses.

Others (acreage multiples)

EV/acreage can be used to compare assets at similar stages in similar geographies across similar timelines when little is known about production or reserves. The multiple gives a value of land on a per-acre basis.

Stages of E&P assets and valuation techniques

Oil and gas assets are divided into reserves, contingent resources and prospective resources, per the definitions of the Society of Petroleum Engineers (SPE). These groups are further subdivided as seen below (definitions of each subdivision in Appendix).

Figure 26: SPE technique of risking reserves and resources

Source: SPE. GCoS = geological chance of success; ECoS = economic chance of success.

31



Valuation techniques for assets at different stages of E&P lifecycle

A DCF model is applied to assets that are producing or are certain to be developed by forecasting a production profile and discounting cash flow every year at an industry rate of 10%. According to the figure above, such assets include: (1) on production; (2) under development; (3) planned for development; and (4) development pending.

Further discounts are applied to values of these assets that range 50-100%, depending on the type of asset (1P, 2P, 3P, 1C, etc.) and taking into account other geographical, political and economic considerations.

Values for assets where no investment decision is taken or that are too early to assess (development on hold and below in the figure above) are arrived at by multiplying resource size by value of oil in ground. Value of oil in ground for such resources ranges 5-50% of value of oil/barrel of similar producing assets. For exploration assets, it may be as low as 5% of value oil/bbl value of producing assets, while for 2C resources, it may be as high as 50%. These values are further discounted by their ECoS (which depends on appraisal success, economic, geological and political factors).

Valuation using multiples: EV/2P and EV/(2P+2C)

Reserve multiples can provide a broad valuation in terms of value per barrel of reserve/resources. Such multiples are especially useful during acquisitions, but they may not provide an actual picture, and assets with identical 2P or 2P+2C can have different valuations.

Table 34: Factors affecting EV/2P and EV/2P+2C ratios

Factors ImpactOperating expense, capex Multiple will be higher for assets with lower opex and capexFiscal system Entitlement interest, tax will vary depending on fiscal systemOil gas ratio A higher oil ratio implies a higher multiple (except when gas prices are linked to oil)Asset stage Assets at development stage will command lower multiples than producing assets (at

declining production, multiple again goes down)Exploration upside Prospective resources that offer upside are not taken into account (e.g., Tullow

commands a higher multiple due to a better-than-average exploration success rate)Political situation Assets in politically unstable locations will command lower multiples

Source: Upstream.

32



Fiscal systems and their impact on share of oil

Fiscal systems play a very important role when assessing the economics of oil and gas companies. Assets with similar reserves and resources may not be valued at the same price. Oil companies’ final take varies according to the fiscal systems of countries, with contractors taking from as much as 70% of total oil produced to as little as 10%.

The two main types of fiscal systems are concessionary systems (where the government takes royalties) and contractual systems (which include PSCs and service contracts).

Figure 27: Fiscal systems

Source: J.P. Morgan.

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Concessionary systems (royalty/tax system)

Key characteristics

These systems are popular in North America and Europe and are characterized by IOCs having ownership of oil produced. Key characteristics of concessionary system include:

International oil company has the right to develop and produce the hydrocarbons.

When hydrocarbons are produced, the international oil company will take title to its share – gross production less the royalty – at the wellhead.

Entitlement: Gross production less Royalty. If the royalty is 10%, the international oil company can “lift” 90% of production. If the royalty is paid in cash, the IOC can “lift” 100% of production.

The IOCs pay taxes on profits from the sale of the oil.

Figure 28: Flow diagram for concessionary system


Entitlement interest in concessionary system

In such systems, royalties are paid either in cash or kind. If royalty is paid in kind, entitlement interest is production - royalty. If royalty is paid in cash, entitlement interest is simply the production share of the contractor.

Booking on income statement

Revenues are booked on (1) or (2) in the diagram above depending on how royalty ispaid (in cash or in kind). Costs are booked as spent.

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Production-sharing contracts

Key characteristics

Production-sharing contracts (PSCs) were made popular by Indonesia’s National Oil Company, Pertamina. Characteristic features of PSCs include:

Title to the hydrocarbons remains with the State.

Contractor bears the risk, limit to cost recovery.

Profit oil (production - cost) is split between contractor and government.

Entitlement oil = Cost oil + profit oil.

Figure 29: Flow diagram for PSC system

Source: J.P. Morgan. Note: The flowchart above is a generalized PSC diagram. Actual distribution may vary geographically.

Entitlement interest in PSC system

Entitlement in PSCs equals profit oil + cost oil.

Booking on income statement

Revenues are booked on entitlement (i.e., cost oil + profit oil). Hence, revenuebooked is lower than gross revenue generated (production * oil price). Costs are booked as incurred, although cost recovery may be lower than costs incurred.

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Service contracts

In service contracts, contractors are generally paid a fee for extracting resources. The fees may be fixed or variable. Characteristic features of PSCs include:

Production entitlement belongs to the government.

Contractors are responsible for all costs which they recover, along with an additional fee.

Fees are usually taxable.

Table 35: Characteristics of fiscal systems

Concessionary system PSC Service contractType of projects All types: Exploration,

developmentAll types: Exploration,

developmentAll types except exploration

Ownership of facilities International oil company Government/NOC Government/NOCWorking interest Production Production -Entitlement Gross production less

royaltyCost oil + profit oil -

Financial obligation forcosts

Contractor Contractor Contractor

Government participation Yes, but not common Yes, common Yes, very commonCost recovery limit No Usually SometimesGovernment control Low High HighContractor entitlement Typically around 80-90% ~50-60% -Contractor control High Low to moderate LowAccounting revenue Production (production-

royalty if paid in kind)Cost oil + profit oil Fee received for services


As seen in the table above, the contractor’s entitlement varies significantly,depending on the type of fiscal system. Accordingly, final take for oil companies also varies, depending on fiscal system, even if oil prices, capex and operating costs are similar.

Fiscal systems in ASEAN and contractor’s take

PSCs are the most popular type of fiscal system in ASEAN countries, with every country except Thailand having PSCs for oil and gas fields (EOR, marginal fields,etc., may have different fiscal systems in place).

Table 36: Fiscal systems in ASEAN

Country Fiscal systemIndonesia PSC, KSO (service contracts), TACMalaysia PSC, risk service contractsThailand Royalty/tax systemVietnam PSC Brunei PSC Malaysia-Thai JDA PSC (similar to Malaysia)


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Appendix II: Overview of the Malaysian fiscal system

Fiscal terms

Most licenses in Malaysia follow PSCs, of which there are four main types:

1976 PSC model

Post-1985 PSC model (conventional areas)

Post-1985 PSC model (deepwater areas)

Post-1996 PSC model (revenue/cost index)

Deepwater blocks are defined as those in water depths of greater than 200 meters.The PSCs differ in terms of royalty, domestic market obligation, cost recovery ceiling, depreciation, profit-sharing and tax rate. All new conventional contracts are issued under the Post-1996 (R/C) terms, while blocks in water depths in excess of 200 meters are issued under the terms of the Post-1985 (deepwater areas) model.

PSCs

Production taxes

Royalty: Royalty is levied at 10% of gross revenue and is payable in cash. Production is measured and valued at the sales point.

Export duty: Export duty is levied on the portion of the contractor’s share of profit oil exported out of Malaysia. Export duty is deductible for tax purposes. The duty was reduced to 10% in January 1998. Under the fiscal incentives introduced in November 2010, export duty will be waived for marginal oil fields.

Other production taxes

Research contribution: 0.5% of the contractor’s cost oil/gas production plus the contractor’s share of profit oil/gas.

Domestic market obligation (DMO): There is no DMO incorporated into current contracts.

Product pricing

Liquids pricing: The price of liquids is generally linked to the traded price of landed Malaysian crudes (mainly Tapis), which are in turn indexed to Brent. The two dominant Malaysian condensate blends are known as Terengganu Condensate and Bintulu Condensate.

Natural gas pricing: Petronas is a monopoly gas purchaser, resulting in low gas pricing arrangements. Gas sold to domestic users in Sabah and Sarawak is understood to be sold at a relatively low price that is not linked to any index.

PSC cost recovery

Cost recovery split in Malaysia’s PSC is one the most complex systems globally.

Cost recovery ceiling

Post-1996 R/C contracts: Under post-1996 R/C PSCs, the Total Cost Tranche (TCT) represents the ceiling of gross revenue available for cost recovery in any year. The TCT is determined by the R/C index. The R/C index at any point in

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time is calculated on a contractor’s cumulative share of revenues and costs to date. A separate R/C index is computed for oil and gas.

Revenues (R) are defined as a contractor’s cumulative share of cost oil plus profit oil, less any supplementary payment. Costs (C) are defined as a contractor’s cumulative share of all recoverable crude oil costs (exploration, appraisal, development and operating costs).

Table 37: TCT

R/C index TCT

0.0 > 1.0 701.0 > 1.4 60

1.4 > 2.0 502.0 > 2.5 30

2.5 > 3.0 303.0 and above 30

Source: Petronas.

Unused portions are shared between the contractor and Petronas on a sliding scale, dependent on the R/C index and Threshold Volume (THV). The total THV assigned to a contract area depends on the number of producing fields within it.For individual oil fields, the THV is 30mn barrels of oil, while for individual gas fields, the THV is 750 Bcf.

Table 38: Contractor’s share of unused TCT

R/C index Cumulative production < THV (%) Cumulative production > THV (%)

0.0 < 1.0 N/A N/A

1.0 < 1.4 80 401.4 < 2.0 70 402.0 < 2.5 60 40

2.5 < 3.0 50 403.0 and above 40 20

Source: Petronas.

Post-1985 contracts (conventional): Under post-1985 (conventional areas) PSCs, cost recovery ceilings are 50% of oil revenue and 60% of non-associated gas revenue.

Post-1985 contracts (deepwater): Under post-1985 (deepwater areas) PSCs, cost recovery ceilings were set as detailed in the following table:

Table 39: Cost recovery ceilings

Oil or gas and water depth Cost recovery ceiling

Oil: 200m - 1,000m 70%Oil: > 1,000m 75%Gas: > 200m 60%

Source: Petronas.

PSC profit-sharing

Post-1996 R/C contracts: Under post-1996 R/C PSCs, production remaining after royalty and the TCT is regarded as the Total Profit Tranche (TPT). THV is Threshold Volume (see cost recovery).

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Table 40: Contractor’s share of TPT

R/C index Cumulative Production < THV (%) Cumulative Production > THV (%)

0.0 < 1.0 80 401.0 < 1.4 70 301.4 < 2.0 60 30

2.0 < 2.5 50 302.5 < 3.0 40 303.0 and above 30 10

Source: Petronas.

Post-1985 contracts (conventional): After 50 MMbbls have been produced, the split is 70:30 in favor of Petronas, regardless of the level of production. For gas fields, the first 2.12 tcf is split 50:50 between Petronas and the contractor. The split reverts to 70:30 after this level has been reached.

Table 41: Contractor’s share of TPT

Oil production range (bbl/d) Contractor profit split (%)

0-10,000 5010,000-20,000 40

20,000+ 30

Source: Petronas.

Petroleum income tax (PITA)

Tax rate: PITA is levied on the contractor’s income from cost oil/gas and share of profit oil/gas. The PITA rate was reduced to 38% in January 1998. Under the fiscal incentives introduced in November 2010, PITA will be reduced to 25% for marginal oil developments.

Supplementary payment: A supplementary payment is payable, equaling 70% of the excess revenues over a base price from the sale of the contractor’s profit oil/gas, less any export paid on liquids. The base price used for calculating excess profits is defined in the contract and is usually the prevailing price per barrel at the time of signature.

Marginal field fiscal incentives: In November 2010, the Malaysian Government announced plans to introduce a series of fiscal incentives to the PITA, targeted at encouraging investment in marginal fields. The five incentives, whose further details are to be finalized, are as follows:

An investment tax allowance of 60-100% of capital expenditure to be deducted against income to encourage the development of capital-intensive projects, including enhanced oil recovery (EOR), high CO2 gas fields, high-pressure/high-temperature fields, deepwater developments and infrastructure projects.

A reduction of income tax from 38% to 25% for marginal oil fields.

An accelerated capital allowance of up to five years from 10 years where full utilization of capital costs could improve project viability.

A qualifying exploration expenditure transfer between PSC with the same ownership to encourage higher levels of exploration.

A waiver of export duty on oil produced and exported from marginal oil field development to improve project viability.

An amendment was made to the Petroleum Income Tax Act in June 2011 to allow for the transfer of exploration expenditure between PSCs, but ratification and clarification of the other incentives have not occurred to date.

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Hibiscus Petroleum: Summary historical financials

Profit and loss statement

M$ in 000s, year-end June FY15 FY16 FY17Revenue 15,586 81,695 261,273 COGS - (40,803) (93,089)Gross profit 15,586 40,891 168,184 Administrative expenses (65,187) (363,994) (49,059)Others 1,936 (21,615) (34,570)EBIT (47,665) (344,718) 84,554 D&A 8,761 (30,901) (72,454)EBITDA (17,224) 153,497 Finance cost (8) (8,196) (22,036)Others (28,139) 296,593 (512)PBT (75,812) (56,321) 62,007 Tax 1,596 (3,639) 44,090 PAT (74,216) (59,960) 106,097 MI 0 0 0 PATMI (74,216) (59,960) 106,097 EPS (M$) (0.1) (0.1) 0.1 DPS (M$) 0.0 0.0 0.0Payout ratio 0% 0% 0%Share outstanding (000s) 766,408 1,058,755 1,413,202

Source: Company data. FY15 represents a period of 18 months ending Jun-15.

Balance sheet

M$ in 000s, year-end June FY15 FY16 FY17Cash and bank balances 5,930 28,746 54,501 Trade receivable 0 1,985 7,434 Inventories 0 5,543 3,997 Others 80,550 22,356 17,656 Current assets 86,480 58,629 83,587 Intangible assets 144,774 997,146 1,029,293 Equipment 55,451 211,452 202,616 Other non-current assets 264,332 1,940 4,090 Total assets 551,037 1,269,167 1,319,586 Long-term liabilities 0 534,251 452,154 Trade payables 0 60 242 Others 26,970 88,775 124,828 Total current liabilities 39,300 150,658 125,070 Total liabilities 39,300 684,908 577,224 Shareholders’ equity 511,737 584,259 742,362 BVPS (M$) 0.7 0.6 0.5


Cash flow statement

M$ in 000s, year-end June FY15 FY16 FY17PBT (75,812) (56,321) 62,007 Depreciation & amort. on equipment & intangible assets

8,761 30,901 72,454

Change in working capital 5,392 98,316 (49,738)Income tax paid 2,815 (1) (11,335)Others 144013 12274 11783Net cash from operating activities 85,169 85,169 85,169 Capex (33,410) (27) (707)Others (176,234) (131,811) (82,696)Cash flow from investing (209,644) (131,837) (83,403)Net proceeds from issuance of ordinary shares

186,099 92,572 27,792

Other (5,454) 2,650 14,243 Dividends 0 0 0Cash flow from financing 180,645 95,222 42,035 Beginning cash 62,405 5,930 28,746 Change in cash flow 56,171 48,554 43,801 Ending cash 5,930 28,746 54,501 DPS (M$) 0 0 0


Ratio analysis

%, year-end June FY15 FY16 FY17Gross margin 100% 50% 64%EBITDA margin -21.08% 58.75%EBIT margin -305.83% -421.96% 32.36%PATMI margin -476.18% -73.39% 40.61%

ROE -14.50% -10.26% 14.29%ROA -14.50% -5.36% 8.88%ROCE -9.56% -34.30% 5.90%Net debt to equity -1.16% -4.92% -7.34%

Revenues/assets 3.53% 10.02% 22.59%Assets/equity (x) 0.04 0.15 0.39Interest coverage (x) n/a -233.38 31.93Tax rate -2.11% 6.46% 71.11%


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Taiwan: This material is issued and distributed in Taiwan by J.P. Morgan Securities (Taiwan) Limited. According to Paragraph 2, Article 7-1 of Operational Regulations Governing Securities Firms Recommending Trades in Securities to Customers (as amended or supplemented) and/or other applicable laws or regulations, please note that the recipient of this material is not permitted to engage in any activities in connection with the material which may give rise to conflicts of interests, unless otherwise disclosed in the “Important Disclosures” in this material. India: For private circulation only, not for sale. Pakistan: For private circulation only, not for sale. New Zealand: This material is issued and distributed by JPMSAL in New Zealand only to persons whose principal business is the investment of money or who, in the course of and for the purposes of their business, habitually invest money. JPMSAL does not issue or distribute this material to members of "the public" as determined in accordance with section 3 of the Securities Act 1978. The recipient of this material must not distribute it to any third party or outside New Zealand without the prior written consent of JPMSAL. Canada: The information contained herein is not, and under no circumstances is to be construed as, a prospectus, an advertisement, a public offering, an offer to sell securities described herein, or solicitation of an offer to buy securities described herein, in Canada or any province or territory thereof. Any offer or sale of the securities described herein in Canada will be made only under an exemption from the requirements to file a prospectus with the relevant Canadian securities regulators and only by a dealer properly registered under applicable securities laws or, alternatively, pursuant to an exemption from the dealer registration requirement in the relevant province or territory of Canada in which such offer or sale is made. The information contained herein is under no circumstances to be construed as investment advice in any province or territory of Canada and is not tailored to the needs of the recipient. To the extent that the information contained herein references securities of an issuer incorporated, formed or created under the laws of Canada or a province or territory of Canada, any trades in such securities must be conducted through a dealer registered in Canada. No securities commission or similar regulatory authority in Canada has reviewed or in any way passed judgment upon these materials, the information contained herein or the merits of the securities described herein, and any representation to the contrary is an offence. Dubai: This report has been issued to persons regarded as professional clients as defined under the DFSA rules. Brazil: Ombudsman J.P. Morgan: 0800-7700847 / [email protected].

General: Additional information is available upon request. Information has been obtained from sources believed to be reliable but JPMorgan Chase & Co. or its affiliates and/or subsidiaries (collectively J.P. Morgan) do not warrant its completeness or accuracy except with respect to any disclosures relative to JPMS and/or its affiliates and the analyst's involvement with the issuer that is the subject of the research. All pricing is indicative as of the close of market for the securities discussed, unless otherwise stated. Opinions and estimates constitute our judgment as of the date of this material and are subject to change without notice. Past performance is not indicative of future results. This material is not intended as an offer or solicitation for the purchase or sale of any financial instrument. The opinions and recommendations herein do not take into account individual client circumstances, objectives, or needs and are not intended as recommendations of particular securities, financial instruments or strategies to particular clients. The recipient of this report must make its own independent decisions regarding any securities or financial instruments mentioned herein. JPMS distributes in the U.S. research published by non-U.S. affiliates and accepts responsibility for its contents. Periodic updates may be provided on companies/industries based on company specific developments or announcements, market conditions or any other publicly available information. Clients should contact analysts and execute transactions through a J.P. Morgan subsidiary or affiliate in their home jurisdiction unless governing law permits otherwise.

"Other Disclosures" last revised January 01, 2018.

Copyright 2018 JPMorgan Chase & Co. All rights reserved. This report or any portion hereof may not be reprinted, sold or redistributed without the written consent of J.P. Morgan.

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