HORIZON OIL LIMITED ABN Investor Presentation June 2016

Transcription

1 HORIZON OIL LIMITED ABN Investor Presentation June 2016

2 Disclaimer Statements contained in this material, particularly those regarding the possible or assumed future performance, costs, dividends, returns, production levels or rates, prices, reserves, potential growth of Horizon Oil Limited, industry growth or other trend projections and any estimated company earnings are or may be forward looking statements. Such statements relate to future events and expectations and as such involve known and unknown risks and uncertainties. Actual results, actions and developments may differ materially from those expressed or implied by these forward looking statements depending on a variety of factors. All dollars in the presentation are United States dollars unless otherwise noted. 2

3 Company overview asset portfolio Clear geographic focus on Asia- Pacific region Technical focus on proven, conventional plays with scale, upside and * manageable risk Working with experienced partners such as CNOOC, OMV, Mitsubishi and Osaka Gas Currently producing oil but will have a diversified oil and gas production base in the future Potential exists for large gas export project into Asian market 3

4 Horizon Oil (HZN:AU) at a glance Sydney-based public company listed on Australian Securities Exchange Portfolio of exploration, development and producing assets in Asia-Pacific region Shareholding: IMC (Singapore) - 30%, institutions - 37%, high net worth - 20%, retail investors - 13% Current net production approximately 4,200 bopd, cash operating cost of US$15.90/bbl (volume-weighted average for Q42015) Operating income after opex: FY 2015 actual - US$81.1m HY 2016 actual - US$29.2m Audited 2P reserves and contingent resources of million barrels of oil equivalent (mmboe) Prospective resources of 78 mmboe best estimate Block 22/12 - cost recovery oil entitlement US$110.5m Receivable of US$130m from Osaka Gas, payable on FID of LNG project in PNG At 31 March Cash on hand US$17.0m Drawdown on US$120m debt facility US$89.1m Convertible bond (listed on SGX)* US$58.8m (matures 19 September 2016, unless converted prior) Net debt US$130.9m * As at 28 October

5 Shareholder distribution and trading statistics June 2016 (to date) Last $ High $0.560 Low $0.043 Volume 53,079, Months Last $0.050 High $0.120 Low $0.040 Volume m Fully paid shares 1,302m Partly paid shares 1.50m 1 Employee options 4.37m 2 General options 1.0m Share appreciation rights 63.77m 3 Convertible bonds No. of shareholders 5,800 Market capitalisation $65m Top 20 / Issued Capital 74.1% 1 Issued in accordance w ith employee incentive schemes 2 Options - issue price ranging from $ $ Share price equivalence of SARS - $ million SARS subject to shareholder approval 4 Convertible to ordinary shares per bond at the adjusted conversion price of $

6 Key performance measures last five financial years Completion of Maari Growth Project in July 2015 expected to increase production in 2016 The outlook for 2016 in the current oil price environment remains positive due to the benefit of oil price hedging Average cash cost of US$14.10/barrel for the year expected to be maintained during the low oil price environment Reserves for each year end are adjusted to account for the prior year s production 6

7 Net Reserves 1, Contingent Resources 1 and Prospective Resources 1 as at 30 June 2015 RESERVES Proven + Probable CONTINGENT RESOURCES Proven + Probable PROSPECTIVE RESOURCES Best Estimate Total: 13.9 mmboe Total: 87.6 mmboe including 400 bcf gas Total: 78 mmboe Including 286 bcf gas Long life of reserves and contingent resources mmboe (liquids 34% / gas 66%), estimated production for 30 years Reserves and Contingent Resources position 6.7 mmboe higher than comparable period last year, inclusive of production during the year, due to reserves addition in China and resource addition in PNG and China Prospective Resources 78 mmboe 1 Estimated in accordance with SPE-PRMS standard; 6 bcf gas equals 1 boe; 1 bbl condensate equals 1 boe 2 Net of production of 27 mmbo gross through 30 June Net of production of 9 mmbo gross through 30 June Reduced to allow for CNOOC participation at 51% 5 Subject to reduction to allow for PNG State Nominee participation at 22.5% 6 Includes 2.6 mmbbl LPG (1 tonne LPG equals 11 bbl) 7 Includes 9.0 mmbbl LPG 8 Subject to confirmation of acreage extension 7

8 Forecast net production from Reserves + Contingent Resources as at 1 July ,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 CY 15 CY 16 CY 17 CY 18 CY 19 CY 20 CY 21 CY 22 CY 23 CY 24 CY 25 Barrels of oil equivalent per day CY 26 CY 27 Assumptions Development of WZ 12-8E, and 12-3 fields in Beibu Gulf, with production commencing in 2017 Stanley condensate start-up with gas sales to OTML commencing 2018, with further large scale gas sales beginning in 2020 Condensate monetisation in conjunction with gas sales in PRL 21 commencing in 2020 Maari Wei W Wei 12-8E Stanley condensate Elevala/Ketu/Tingu condensate Stanley Gas Elevala/Ketu/Tingu gas 8

9 Strategic imperative focus on resource development Total audited reserves and contingent resources of 99.4 million barrels of equivalent 11% developed / 89% undeveloped 34% oil / 66% gas 10.0 mmboe Developed oil (NZ and China) 4.3 mmboe Undeveloped oil (NZ and China) 66.7 mmboe Undeveloped gas (PNG) 18.7 mmboe Undeveloped liquids (PNG) Portfolio composition 9

10 Beibu Gulf field production and future development areas China WZ 6-12N and WZ 12-8W fields producing above forecast Potential for higher oil recovery from WZ 12-8W Excellent HSE record since production start-up in 2013 Cost recovery oil entitlement of US$98m over Further development potential of 17.6 mmbo gross in WZ 12-8E, and 12-3 oil accumulations Block 22/12 Post-CNOOC Back-in: HZN 26.95% Gross reserves (mmbo) at 30/06/15 2P CNOOC 51.00% (Op) Produced 9.0 ROC 19.60% Majuko Corp 2.45% Remaining

11 Horizon Oil s share of Block 22/12 gross revenue calculated on 2P Reserves Forecast The above graph demonstrates Horizon Oil s increased share of cost recovery in the period Jan 2016 to Mar 2020, once CNOOC has recovered its share of development costs Horizon Oil s portion of investment recovery oil and remainder oil increases to 31-37%, until all development costs and attributable interest have been recovered - cost recovery oil entitlement US$98m 11

12 Beibu Gulf future development projects WZ 12-8 Development Area Integrated development of WZ 12-8E and WZ 12-3 fields (audited gross 2C resources 10.5 mmbo) plus WZ and WZ accumulations (audited gross 2P+2C reserves and resources 7.1 mmbo) envisaged; development plan to be submitted for Government approval in 2016 Appraisal/development well on WZ accumulation, WZ 12-8W-A6P1 currently drilling 12

13 Beibu Gulf fields phased development scheme Phased approach to development of new reserves utilising existing infrastructure 13

14 Maari /Manaia fields New Zealand FPSO Raroa purchased in April 2013 Maari field facilities and FPSO Raroa repaired and upgraded in H Maari Growth Projects Program successfully completed and Ensco 107 jack-up rig released in July 2015 Field production currently ~13,500 bopd Workover program underway to further enhance production Gross reserves (mmbo) at 30/6/15 2P PMP 38160: HZN 10% Produced 27.0 Remaining 45.5 OMV 69% (Op) Todd 21% CUE 5% 14

15 Manaia Maari schematic cross-section 15

16 Maari production forecast to 2030 showing Growth Projects contribution and upside potential (HZN) Actual Forecast 16

17 Exploration potential on Maari/Manaia oil migration path PEP

18 Papua New Guinea PNG is rich in oil, gas and minerals with track record of successful large-scale development projects Stable fiscal regime and succession of prodevelopment governments Jurisdiction well-supported by lenders Horizon Oil acreage position ~7,900 sq km in foreland terrain, primarily in wet gas sweet spot 18

19 Horizon Oil acreage and joint venture partners - Papua New Guinea Successful Tingu-1 exploration/appraisal well drilled in 2013 extended PRL 21 gas/condensate resources materially Development application for Elevala/Tingu/Ketu fields in PRL 21 filed in March 2014 Development licence for Stanley field (PDL 10) issued by PNG Government in May 2014 Encouraging options emerging for gas monetisation PRL 21: PDL 10: PPLs 372 and 373: PPL 259: HZN 27.0% (Op) HZN 30% HZN 90.0% HZN 35.0% Osaka Gas 18.0% Osaka Gas 20% PPL 430: Osaka Gas 10.0% Talisman 32.5% Talisman 40% HZN 50.0% Eaglewood 45.0% Kina 15.0% Mitsubishi 10% Eaglewood 50.0% P3GE 10.0% Mitsubishi 7.5% 19

20 Stanley and Elevala/Ketu field development schemes Stanley field Petroleum Development Licence awarded in May 2014 Development drilling subsequently completed, both wells Stanley-3 and -5 met or exceeded expectations Elevala and Tingu to be developed as one field Elevala/Ketu Petroleum Development Licence application submitted in March 2014 FEED underway 20

21 PNG gas commercialisation options Sales to regional buyers for power generation and other industrial use Ok Tedi Mining Limited (OTML) and Frieda River project (when sanctioned) Local towns and communities in Kiunga Ok Menga Frieda River corridor Export to West Papua: Merauke, Jayapura Mid-scale LNG project (~ 2-4 mtpa) Expandable mid scale LNG plant at coastal location, such as Daru, to supply:- City and mining project power demand, as substitute for diesel or fuel oil Singapore LNG and products hub North Asian markets Brownfield development Aggregation of Western Province NW Hub gas to supply dedicated expansion train at PNG LNG site in Port Moresby PNG LNG T3 21

22 Papua New Guinea hydrocarbon production 22

23 Horizon Oil forecast net production from Reserves + Contingent Resources as at 1 July ,000 Assumptions Barrels of oil equivalent per day 16,000 14,000 12,000 10,000 8,000 6,000 4,000 Development of WZ 12-8E, and 12-3 fields in Beibu Gulf, with production commencing in 2017 Stanley condensate start-up with gas sales to OTML commencing 2018, with further large scale gas sales beginning in ,000 0 CY 15 CY 16 CY 17 CY 18 CY 19 CY 20 CY 21 CY 22 CY 23 CY 24 CY 25 CY 26 CY 27 Condensate monetisation in conjunction with gas sales in PRL 21 commencing in 2020 Maari Wei W Wei 12-8E Stanley condensate Elevala/Ketu/Tingu condensate Stanley Gas Elevala/Ketu/Tingu gas 23

24 WoodMackenzie macro oil near-term outlook (Oct 2015) (1) US total rig count 767 (574 oil rigs) at 13 Nov 2015, down from 1,928 (1,574 oil rigs), year-on-year Global oil supply peaked in Q2 2015, as US unconventional oil went into decline ~ US$280 billion globally in new projects cancelled or deferred 24

25 WoodMackenzie macro oil supply/demand outlook (Oct 2015) (2) 25

26 Barclays global oil supply/demand outlook (Oct 2015) (3) The balances for 2016 are substantially tighter than 2014 and 2015, with stock draws forecast in Q

27 RBC oil price forecast Nov 2015 (4) 27

28 LNG demand vs contracted supply Medium to long-term LNG demand forecasts still robust Source: Oil Search Limited 28

29 Response to current low oil price environment Brent oil price Operating income substantively maintained by oil price hedging 2014 mid 2016 Opex reduced (down ~20% YTD in Block 22/12) Capex for materially reduced and discretionary expenditure minimised Estimated capex + net G&A for FY2016 < US$50m Spend on new field development planning maintained to take advantage of cost deflation PDL 10 (Stanley) and PRL 21 (Elevala/Ketu), PNG WZ 12-8E and WZ Beibu Gulf, China Administrative spend controlled currently net G&A US$7m pa Focus on managing business risk 29

30 Strong risk management with a well established hedging policy Oil price hedge profile 842,500 mmboe hedged from 1 Jan 2015 through mid 2016 at average of US$95/bbl Oil price hedging program means cash flows in 2015 and 2016 not as critically impacted by low oil prices Production costs significantly reduced in 2015 Oil production from multiple fields (currently 1 in New Zealand and 2 in China) reduces production risk Loss of Production Insurance policies in place for Maari and Beibu Gulf fields Longer term, gas sales will reduce reliance on oil price 30

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