Wilson HTM Equities Research – Horizon Oil Limited Issued by Wilson HTM Ltd ABN 68 010 529 665 - Australian Financial Services Licence No 238375, a participant of ASX Group and should be read in conjunction with the disclosures and disclaimer in this report. Important disclosures regarding companies that are subject of this report and an explanation of recommendations can be found at the end of this document. 05 September 2014 HORIZON OIL LIMITED (HZN) ACTION & RECOMMENDATION We initiate coverage of Horizon Oil on a BUY with a $0.45/sh target price implying a 39% potential TSR. HZN provides exposure to long life oil production from the Beibu Gulf (China) and the Maari/Manaia fields (New Zealand) in addition to significant potential upside from its wet gas assets in Papua New Guinea (81.6 mmboe 2P+2C). Our positive view on HZN is predicated on increasing production from Maari to ~20,000 bopd (gross) in 1H CY15e, further exploration success in PNG and de-risking of the Stanley wet gas project in PDL 10 (PNG) with first condensate sales in 2H CY16e. We value HZN at $0.44/sh risked ($0.58/sh unrisked) using a DCF methodology (12% discount rate). Catalysts on the Horizon, initiating coverage with a BUY Initiating Coverage Investment thesis HZN appears undervalued trading at 0.74x price/NPV although we expect the valuation gap to narrow as production from Maari doubles in FY15e, further wet gas resources are potentially discovered in PNG and the Stanley wet gas project is progressed. We believe HZN is fully funded to meet its share of capex based on existing cash of $99m, operating cash flow of $60m in FY15e while we assume the additional $130m payment from Osaka Gas is received in FY17e. Approx. 39% of our valuation relates to the PDL 10 and PRL 21 appraisal and development assets in PNG. We assume first condensate from Stanley (PDL 10) in 2HCY16 and the EKT Fields (PRL 21) in 1H CY19 with gas sales from CY20 to a mid-scale LNG project on Daru Island owned by third parties. Risks & Catalysts Risks: Lower-than-expected oil production and oil prices, development delays at the Stanley gas project in PNG. Catalysts: Stanley-3 well (PDL 10) due 4Q CY14; Nama-1 well (PPL 259) due 1Q CY15; progress in development of Stanley project, higher oil production from Maari Fields (New Zealand). Valuation We value HZN at $0.44/sh risked ($0.58/sh unrisked) based on a sum-of-the-parts DCF methodology (12% WACC) and WHTM commodity price forecasts. HZN’s oil-producing assets account for 61% of our project valuation while the PNG wet gas appraisal and development projects (PDL10 and PRL21) account for 39%. 12m Target Price (AUD) $0.45 Share Price @ 04-Sep-14 (AUD) $0.33 Fcst 12m Capital Return 38.5% Fcst 12m Dividend Yield 0.0% 12m Total S’holder Return 38.5% James Redfern [email protected]Tel. +61 2 8247 6609 12m Share Price Performance 1m 6m 12m Abs. Return (%) -5.8 1.6 -3.0 Rel. Return (%) -3.3 3.1 8.0 WHTM Return Re-Investment Matrix Return High Cash Generator Champion Low Challenged Potential Low High Re-Investment WHTM Risk Assessment Low Med High Spec Share Price Risk Business Risk Year-End June (USD) FY13A FY14A FY15E FY16E FY17E Revenue ($m) 48.1 138.5 193.1 184.6 197.7 EBITDA Margin (%) 57 64 72 71 70 NPAT Norm ($m) 3.5 12.8 48.6 44.2 51.2 Consensus NPAT ($m) 37.8 29.0 42.8 EPS Norm (cps) 0.3 1.0 3.8 3.4 4.0 EPS Growth (%) -55 234 268 -9 18 P/E Norm (x) 99.1 29.7 8.1 8.9 7.6 EV/EBITDA (x) 19.5 6.0 3.8 4.1 3.9 CFM (x) 10.6 5.9 6.8 7.5 10.2 DPS (cps) 0.0 0.0 0.0 0.0 0.0 Franking (%) 0 0 0 0 0 Source: Company data, WHTM estimates, S&P Capital IQ Key Changes Before After Var % Revenue : FY15 193 ($m) FY16 185 FY17 198 EBITDA: FY15 139.8 ($m) FY16 130.8 FY17 137.6 EPS: FY15 3.8 Norm FY16 3.4 (cps) FY17 4.0 Price Target: 0.45 Rec: BUY Mkt Cap: $423m Enterprise Value: $560m Shares: 1,302m Sold Short: 2.4% ASX 300 Wgt: 0.0% Median T’over/Day: $0.6m 0.20 0.25 0.30 0.35 0.40 0.45 0.50 Aug-13 Dec-13 Apr-14 Aug-14 $ HZN XSR Rebased
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Wilson HTM Equities Research – Horizon Oil Limited
Issued by Wilson HTM Ltd ABN 68 010 529 665 - Australian Financial Services Licence No 238375, a participant of ASX Group and should be read in conjunction with the disclosures and disclaimer in this report. Important disclosures regarding companies that are subject of this report and an explanation of recommendations can be found at the end of this document.
05 September 2014
HORIZON OIL LIMITED (HZN)
ACTION & RECOMMENDATION
We initiate coverage of Horizon Oil on a BUY with a $0.45/sh target price implying a 39% potential TSR. HZN provides exposure to long life oil production from the Beibu Gulf (China) and the Maari/Manaia fields (New Zealand) in addition to significant potential upside from its wet gas assets in Papua New Guinea (81.6 mmboe 2P+2C). Our positive view on HZN is predicated on increasing production from Maari to ~20,000 bopd (gross) in 1H CY15e, further exploration success in PNG and de-risking of the Stanley wet gas project in PDL 10 (PNG) with first condensate sales in 2H CY16e. We value HZN at $0.44/sh risked ($0.58/sh unrisked) using a DCF methodology (12% discount rate).
Catalysts on the Horizon, initiating coverage with a BUY
Init
iati
ng
Co
vera
ge
Investment thesis
HZN appears undervalued trading at 0.74x price/NPV although we
expect the valuation gap to narrow as production from Maari
doubles in FY15e, further wet gas resources are potentially
discovered in PNG and the Stanley wet gas project is progressed.
We believe HZN is fully funded to meet its share of capex based on
existing cash of $99m, operating cash flow of $60m in FY15e while
we assume the additional $130m payment from Osaka Gas is
received in FY17e. Approx. 39% of our valuation relates to the PDL
10 and PRL 21 appraisal and development assets in PNG. We
assume first condensate from Stanley (PDL 10) in 2HCY16 and the
EKT Fields (PRL 21) in 1H CY19 with gas sales from CY20 to a
mid-scale LNG project on Daru Island owned by third parties.
Risks & Catalysts
Risks: Lower-than-expected oil production and oil prices,
development delays at the Stanley gas project in PNG.
Catalysts: Stanley-3 well (PDL 10) due 4Q CY14; Nama-1 well
(PPL 259) due 1Q CY15; progress in development of Stanley project, higher oil production from Maari Fields (New Zealand).
Valuation
We value HZN at $0.44/sh risked ($0.58/sh unrisked) based on a
sum-of-the-parts DCF methodology (12% WACC) and WHTM commodity price forecasts. HZN’s oil-producing assets account for 61% of our project valuation while the PNG wet gas appraisal and development projects (PDL10 and PRL21) account for 39%.
Wilson HTM Equities Research – Horizon Oil Limited 7
Production
We forecast oil production of 1.8 mmboe in FY15e, up 28% from 1.4 mmboe in FY14
driven by higher production from Maari/Manaia (New Zealand) following the Maari Growth
Project which is expected to increase production to ~20,000 bopd by 1H CY15 (versus
8,319 bopd in 1H CY14). The Maari Growth Project comprises four new production wells,
one new injection well and a workover of the existing MR2 dual lateral production well. We
forecast Maari production to peak at ~19,000 in 1H CY15. We also assume first
condensate from Stanley at 4,000 boepd (gross) in 2H CY16 (FY17e).
FIGURE 8: PRODUCTION BY PROJECT (MBOE)
Source: Company data, Wilson HTM
FIGURE 9: PRODUCTION BY PRODUCT (MBOE)
Source: Company data, Wilson HTM
FIGURE 10: FY15E PRODUCTION BY PROJECT
Source: Company data, Wilson HTM
FIGURE 11: FY17E PRODUCTION BY PROJECT
Source: Company data, Wilson HTM
0
500
1,000
1,500
2,000
2,500
FY12 FY13 FY14 FY15F FY16F FY17F
Maari/Manaia Beibu Stanley (PDL 10)
0
500
1,000
1,500
2,000
2,500
FY12 FY13 FY14 FY15F FY16F FY17F
Oil Condensate
Beibu (China)67%
Maari/Manaia (NZ)33%
Maari/Manaia29%
Beibu48%
Stanley -Condensate
23%
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 8
Key assets
Beibu Gulf, offshore China
HZN holds a 26.95% interest in Block 22/12 (WZ 6-12, WZ 12-8 West) operated by
CNOOC (51%) and a 55% interest in WZ 12-8 East also in Block 22-12, located in the
Beibu Gulf, offshore China in ~50 metres water depth. At 30 June 2014, the Beibu Gulf
fields contained 22.1 mmbbl of 2P reserves (gross) providing a reserve life of ~10 years.
The Beibu Gulf development comprises two remote wellhead platforms and one joint
processing platform, connected by bridge to the CNOOC WZ 12-1A platform complex,
and utilises existing water injection and gas processing facilities. Ten development wells
were drilled from the WZ 6-12 platform and five development wells from the WZ 12-8
platform. At present, 5 of the 15 production wells continue to flow naturally, while 10 wells
are on production with artificial lift using electric submersible pumps.
Production from the WZ 6-12 and WZ 12-8 W fields commenced in March 2013 at 10,000
bopd (gross) and averaged 11,769 bopd (gross) in the June 2014 quarter. Oil is sold to
Chinese refineries at Brent less a US$4/bbl quality discount. Production from the WZ 6-12
and WZ 8-12 West wellhead platforms is tied back to an adjacent CNOOC-operated
processing facility, before being transported to CNOOC’s existing Weizhou Island storage
and export terminal via a 34 km pipeline, also owned and operated by CNOOC.
FIGURE 12: BEIBU GULF, OFFSHORE CHINA LOCATION MAP
Source: Company data
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 9
Future growth from WZ 12-8E development Phase II expansion
Four separate oil fields have been identified in Block 22/12 including the WZ 6-12 fields
(North and South) and WZ 12-8 fields (East and West). The WZ 6-12 South, WZ 6-12
North and WZ 12-8 West fields were developed in Phase 1 of the Beibu Gulf development
plan while the WZ 12-8 East field will be developed in Phase II as discussed below.
HZN is currently progressing the feasibility study for WZ 12-8E while the development
plan is due to be completed by the end of CY14. The WZ 12-8 East field is expected to be
a phased development, initially comprising three production wells utilising a leased mobile
production platform with production tied back to the existing processing facility on site.
FIGURE 13: BEIBU GULF FIELDS PHASED DEVELOPMENT SCHEME
Source: Company presentation
FIGURE 14: BEIBU GULF PRODUCTION AND REVENUE
Source: Company data, Wilson HTM
80
85
90
95
100
105
110
0
100
200
300
400
500
600
700
2H13 1H14 2H14 1H15F 2H15F 1H16F 2H16F
Oil production (mbbl) Revenue (US$/bbl) - RHS
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 10
Beibu Gulf modelling and valuation assumptions
We value HZN’s Beibu Gulf project at A$246m or $0.22/sh using a DCF methodology and
12% discount rate. Our key modelling assumptions are listed below:
Capex: We assume gross capex of US$20m p.a. in FY14-16. We expect the Phase II
Development program (WZ12-8E field) to be approved in 2015-16 and forecast capex of US$180m in FY17 for the construction, installation and tieback (via subsea pipeline to WZ-128W WHP) of a new well head platform in addition to drilling 14 horizontal development wells (US$12m per well).
Production: We forecast oil production of 12,500 bopd (gross) in FY14-16 declining
at ~10% p.a. before increasing to ~11,000 bopd (gross) in FY18 as production from the WZ12-8E field commences.
Pricing: Oil sold at Brent crude less a US$4/bbl discount for quality.
Opex: We assume operating costs of US$50m p.a. in CY14-16 with ~50% relating to
tariffs for processing and transportation through CNOOC-owned facilities. We assume fixed costs of US$20m p.a. and allow for US$10m p.a. for workovers to change out the electric submersible pumps (ESPs). We forecast opex to increase to US$70m p.a. from FY18 due to the start up of production from WZ12-8E with fixed operating costs of US$24m p.a. for an unmanned WHP and workovers every three years for the producing wells.
Amortisation: US$28/bbl.
Special oil gain levy: Charged at 20% starting at US$55/bbl increasing in US$5/bbl
increments to a maximum of 40% at US$75/bbl.
Tax: 30% company tax rate.
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 11
Maari/Manaia Fields, New Zealand
HZN has a 10% interest in the Maari/Manaia Fields (PMP 38160), located in the Taranaki
Basin, ~80 km offshore New Zealand, in ~100 metres water depth. The Maari/Manaia oil
development is operated by OMV New Zealand Ltd (69%) and currently produces oil from
three reservoirs: two in the Maari field and one in the Manaia field.
Production from Maari/Manaia commenced in February 2009 with the field producing
22.9 mmbbl to date. At 30 June 2014, Maari/Manaia contained gross 2P reserves of
58.0 mmbbl (5.8 mmbbl net) providing a solid ~30-year reserve life.
Oil production from the three producing reservoirs is tied to a single wellhead platform
located adjacent to the Maari field, connected to the 35,000 bopd “Raroa” FPSO moored
~1.5 km from the wellhead platform. Oil is sold at a US$5-6/bbl premium to Brent crude.
We highlight production has been affected by downhole pump reliability issues and scale
build-up in well completions resulting in production disruptions during CY13. In addition,
upgrade works and the refurbishment of the Raroa FPSO mooring and turret system led
to the shutdown of production facilities for five months in 2H CY13.
However, the joint venture partners are seeking to address these issues and improve
production optimisation through the Maari Growth Project which comprises:
two new producers and one new injector in the Maari Moki reservoir and the
conversion of one producer to a water injector;
one new producer in the Maari Mangahewa reservoir; and
one new extended reach producer in the Manaia Mangahewa reservoir.
OMV expects the Maari Growth project should increase production to 20,000 bopd (gross)
by 1H CY15. We conservatively forecast production of 14,320 bopd (gross) at end-CY14.
FIGURE 15: MAARI/MANAIA OIL FIELD (NEW ZEALAND) LOCATION MAP
Source: Company presentation
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 12
We value HZN’s Maari/Manaia project at A$152m ($0.13/sh) based on certified 2P
reserves of 58 mmbbl (gross) using a DCF methodology and 12% discount rate. Our key
modelling assumptions are reviewed below:
Capex: Gross capex of US$286m (~US$29m net) during FY14-16 for the Maari
Growth Project, remaining capitalised FPSO lease, recompletions and sustaining capex.
Production: We forecast oil production to peak at ~19,000 bopd in 1H CY15 driven
by the Maari Growth Project before declining at ~10% p.a.
0
20
40
60
80
100
120
140
0
50
100
150
200
250
300
350
400
2H13 1H14 2H14 1H15F 2H15F 1H16F 2H16F
Oil producton (mbbl) Revenue (US$/bbl) - RHS
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 13
Pricing: Oil sold at Brent crude plus US$5/bbl reflecting a quality premium.
Opex: We model operating costs of US$70m p.a. including fixed FPSO operating
costs and three workovers per year for electric submersible pump (ESP) changeouts.
Amortisation: US$12/bbl.
Royalty: 20% royalty consisting of an ad valorem royalty component (payable on
gross revenue) and an accounting profits royalty component (payable after cost recovery).
Tax: 28% company tax rate.
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 14
Papua New Guinea
HZN holds interests in 7,900 km2 of wet gas acreage in the Foreland Basin in the Western
Province of PNG. The company holds 30% in PDL 10 containing the Stanley
gas/condensate field (23.8 mmboe of 2P + 2C) and 27% in PRL 21, containing the
Elevala/Ketu/Tingu (EKT) gas/condensate fields (57.4 mmboe of 2P + 2C).
In May 2014, the PNG government granted the Stanley wet gas project with a production
development licence converting PRL 4 into PDL 10, allowing HZN to commence
development drilling with first condensate production expected in 2H CY16 with gas sales
to local customers expected shortly thereafter.
HZN is currently completing the FEED study for PRL 21 with a final investment decision
expected early CY15. The company is targeting first condensate production from PRL 21
in 2018 using a condensate stripping plant similar to the Stanley project in PDL 10.
However, with ~1.4 Tcf of gross 2C gas resource in PDL10 and PRL 21, the key prize is
monetising its gas resource by aggregating with other nearby fields (eg Talisman to the
south) to supply a mid-scale (2-4 Mtpa) LNG project requiring 2-4 Tcf of gas on Daru
Island on the Gulf of Papua. Another option is supplying gas to a potential third train (T3)
expansion of Exxon’s 6.9 Mtpa PNG LNG project near Port Moresby or the proposed
~5 Mtpa Total/InterOil Elk-Antelope LNG project, also near Port Moresby.
FIGURE 18: PNG ASSETS LOCATION MAP
Source: Company presentation
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 15
PDL 10, STANLEY GAS/CONDENSATE PROJECT
HZN holds a 30% interest in PDL 10 containing the Stanley wet gas field located ~40 km
north of Kiunga in the Western Province of PNG. Other joint venture partners include
Talisman Energy (operator, 40%), Osaka Gas (20%) and Mitsubishi Corp. (10%).
On 30 May 2014, the PNG government granted the Stanley Gas Project development
licence (PDL 10) and pipeline licence (PL 10), converting PRL 4 into PDL 10. Following
the development licence, HZN commenced development activities including the drilling of
the Stanley-3 and Stanley-5 development wells in August 2014, site preparation and
facilities construction. We note the PNG government may acquire up to a 22.5% interest
in the commercial development by reimbursing the participant partners for sunk costs
incurred.
The Stanley field contains a gross 2C resource of ~400 Bcf of gas and ~13 mmboe of
condensate. The project is expected to commence production in 2H CY16 at a rate of
~140 mmscf/d of gas plus recovery of ~4,000 bpd of condensate from two production
wells (Stanley-2 and Stanley-5) and two dry gas injection wells. Condensate will be
stripped from the wet gas using a two-train refrigeration plant with any unsold or unused
dry gas re-injected into the reservoir for enhanced recovery and sold at a later date.
Both the Stanley-2 and -5 production wells are complete and ready for production while
testing has indicated better-than-expected flow rates in excess of the 140 mmcf/d capacity
of the Stanley gas plant. In August 2014, Stanley-5 intersected ~96 metres of net pay with
a 24-hour flow rate of ~68 mmcf/d plus condensate at ~30 bbl per mmscf. We understand
the final Stanley-3 injection well was also recently spudded.
Condensate will be transported via a 6 inch, 40 km pipeline to a 60,000 bbl storage facility
at Kiunga on the Fly River before being shipped in 33,000 bbl capacity tankers (custom
designed and chartered by P&O) ~1 km downstream from the existing Kiunga wharf to
regional customers. We understand condensate will initially be sold to Trafigura’s Napa
Napa Refinery (Port Moresby) with additional cargos sold to the Singapore trading market.
FIGURE 19: PDL 10 (STANLEY FIELD) DEVELOPMENT CONCEPT
Source: Company presentation
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 16
Stanley project capex
RISC (HZN’s independent technical expert) has estimated gross capex of US$381m
(US$114m net at 30%) for the Stanley gas/condensate stripping project which we assume
for our Stanley project valuation. As shown below, the majority of the capex relates to the
gas plant with a 140 mmcf/d capacity using 2 x 50% gas processing trains.
TABLE 3: STANLEY GAS/CONDENSATE PROJECT CAPEX (GROSS)
Source: RISC, Wilson HTM
Stanley Project modelling and valuation assumptions
We value HZN’s 30% interest in the Stanley gas project at A$137m or $0.12/sh risked at
75%. Our valuation is derived using a DCF methodology (13% WACC) and assumes
~4,000 bpd of condensate sales from 2H CY16 and ~140 mmscf/d of gas sales from 1H
CY20. Our key modelling assumptions are discussed below:
Capex: Gross project capex of US$381m for two production wells, two injection wells,
the two train gas refrigeration plant, pipelines and storage tanks.
Production: Condensate sales of 4 kbpd (gross) commencing in 2H CY16 based on
13 mmbbl of condensate (gross 2P+2C). We assume gas production of ~140 mmscf/d is reinjected after condensate stripping before gas sales commence in 1H CY20 to supply a third party LNG project such as T3 of PNG LNG.
Pricing: Condensate sold at Brent crude oil pricing and gas sold at Australian east
coast LNG netback pricing (US$9/GJ in 1H CY20).
Opex: Operating costs of US$26m p.a. including condensate transport costs.
Royalty: 2% royalty to landowners, affected provincial governments and local level
governments calculated on a “wellhead value” basis plus a development levy of 2% of the wellhead value to the provincial governments and the local level governments.
Based on recent transactions for undeveloped PNG gas (Table 5), we calculate a median
resource multiple of US$4.35/boe (A$4.72/boe at US0.92). Applying this multiple to HZN’s
2P reserve plus 2C resource of 24.2 mmboe, we calculate a Stanley valuation of A$113m
or $0.10/sh, which supports our DCF valuation above.
Item US$m
Project Management and Supervision 15
Stanley Gas Plant 221
Pipeline 40
Kiunga Storage and Loadout facilities 27
Wells (including stack costs) 78
Total Capital Cost 381
Abandonment 38
Annual operating costs 26
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 17
PNG GAS COMMERCIALISATION OPTIONS
At present, no gas supply agreements from PDL 10 or PRL 21 have been contracted
although there are several gas commercialisation options available to HZN which we
review below.
Gas supply for power generation to nearby copper-gold mines
We understand HZN is in negotiations to supply ~3 PJa (~8 mmcf/d) of gas for power
generation to the Ok Tedi copper-gold mine located ~100 km to the north). Under this
scenario, HZN would supply dry gas to a small gas-fired power station to be constructed
adjacent to the Stanley Field with electricity transmitted to the Ok Tedi mine site to
displace diesel fuel. We understand that by switching from diesel fuel to electricity Ok Tedi
would reduce operating costs by approx. US$50m p.a.
Another option is supplying gas for power generation to be used at PanAust’s proposed
US$1.8bn Frieda River project, one of the world’s largest undeveloped copper gold
deposits. In August 2014 PanAust acquired an 80% interest in the project from Xstrata
and is expected to complete the feasibility study mid-CY15. We do not expect production
to start until ~2019.
However, we estimate that any gas sales for power generation are likely to be small at
around 20 mmcf/d, a fraction of the ~140 mmcf/d to be produced from Stanley.
Mid-scale (2-4 Mtpa) LNG project
Another potential option is for the ~1.4 Tcf (gross) 2C gas resource at Stanley (PDL 10)
and EKT (PRL 21) to underpin a mid-scale (2-4) Mtpa LNG project on Daru Island on the
Gulf of Papua. However, to secure the required 2-4 Tcf gas resource, HZN (and its joint
venture partners) would need to aggregate its resource with other fields in the Western
Province. We assume a final investment decision for an LNG project is reached in FY17
upon which HZN will receive a US$130m cash payment from Osaka Gas for the 40%
interest acquired in May 2013.
Assuming capex intensity of US$800/t for a barge-mounted LNG facility with river shuttle
tankers, a 4 Mtpa LNG project would cost ~US$2.4bn. Given the significant capex of
US$288m for HZN (assuming ~12% net interest), we currently do not assume HZN is an
equity participant despite the US$130m payment from Osaka Gas. However, HZN’s joint
venture partners Talisman, Osaka Gas and Mitsubishi should be able to fund an LNG
plant, in our view.
Gas sold to a third party LNG project
HZN could also supply gas to third party LNG projects such as the PNG LNG project
(Exxon, Oil Search, Santos) which is studying a potential third train (T3) expansion from
6.9 Mtpa to ~10.2 Mtpa underpinned by fields such as the 2.5 Tcf P’nyang field (PRL 3)
north of Stanley. We understand the PNG LNG partners are continuing development work
for P’nyang (PRL 3) with the aim of submitting a production development licence
application early CY15. In the event a pipeline is built from P’nyang (in the highlands)
down to the EKT Fields in the forelands, HZN would be well positioned to connect its
Stanley and EKT fields into the PNG LNG pipeline infrastructure.
Total SA and InterOil Corporation are also proposing a second LNG project in PNG near
Port Moresby to be supplied by the ~7 Tcf Elk-Antelope fields. In March 2014 Total
acquired a 40.1% interest in PRL 15 (the Elk-Antelope fields) from InterOil Corporation for
up to US$1.62bn. We believe a second LNG project in PNG will increase gas demand in
PNG and bodes well for undeveloped and uncontracted gas from fields such Stanley/EKT.
Wilson HTM view
We assume gas sales from Stanley (PDL 10) and the EKT fields (PRL 21) commence in
CY20 is sold to a mid-scale LNG project on Daru Island or possibly a T3 expansion of
PNG LNG near Port Moresby. As mentioned, at this stage we do not expect HZN to hold
an equity interest in a downstream LNG project given the substantial capex. We note HZN
may be able to secure earlier gas sales for power generation to Ok Tedi and Frieda River
(from CY19) although we expect any volumes to be small at ~20 mmscf/d.
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 18
PRL 21 (ELEVALA/KETU/TINGU)
HZN operates and holds a 27% interest in PRL 21 containing the Elevala, Ketu and Tingu
gas/condensate fields with gross 2C resource of 979 Bcf of gas (264 Bcf net to HZN) and
50 mmbbl of condensate (13.4 mmbbl net to HZN). Note that HZN’s interest will reduce to
20.93% assuming the PNG government exercises its back-in rights.
Other joint venture partners in PRL 21, located adjacent to PDL 10 are Osaka Gas (18%),
Talisman Energy (32.5%), Kina Petroleum (15%) and Mitsubishi Corporation (7.5%).
HZN is advancing the PRL 21 FEED study with a final investment decision targeted for
early CY15. In June 2014, HZN also submitted the environmental impact statement to the
Department of Environment and Conservation.
We understand the PRL 21 development concept is similar to Stanley although will be
larger with average annual gas production of ~210 mmcf/d (140 mmscf/d from Elevala
and 70 mmscf/d from Ketu) with a central processing facility for all production wells and
with condensate stripping on-site and transported to the Kiunga storage load-out facility
via a proposed pipeline from the project site.
According to HZN, the Elevala and Ketu fields have a higher condensate-gas ratio (CGR)
than the Stanley Field (30 bbl per mmscf) with Elevala gas yielding 52 bbl per mmscf and
Ketu yielding 57 bbl per mmscf which helps improve project economics.
FIGURE 20: PRL 21 DEVELOPMENT CONCEPT
Source: Company presentation
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 19
PRL 21 development plan
According to RISC, the PRL 21 development will include a liquids stripping project with
two producers and two injectors in Elevala and one producer in Ketu in addition to a gas
plant with three production trains and total production and injection capacity of 240
mmscf/d (~210 mmscf/d annualised capacity including downtime).
Similar to Stanley, condensate will be exported via a 60 km pipeline to a new storage and
ship loading facility located at Drimdemasuk on the Fly River (north of Kiunga) while gas
sales are forecast to commence in FY20.
PRL 21 project capex
RISC (HZN’s independent technical expert) has estimated gross capex of US$1,135m
(US$306m net to HZN at 27%) for the PRL 21 (Elevala/Ketu/Tingu) gas/condensate
stripping project which we assume for our project valuation. As shown below, the majority
of the capex relates to the three-train gas processing plant, 60 km pipeline, drilling and
completing five wells and a 20% contingency. We also assume operating costs of
~US$50m per year including condensate transport costs.
We assume the majority of the $1.1bn in capex is spent in FY17-18 with first condensate
production in FY19 and gas sales in FY20.
TABLE 4: PRL 21 (ELEVALA/KETU) PROJECT CAPEX (GROSS)
Source: RISC, Wilson HTM
PRL 21 (Elevala/Ketu/Tingu) modelling and valuation assumptions
We value HZN’s 27% interest in PRL 21 at A$115m or $0.10/sh, risked at 50% as PRL 21
remains in the FEED stage with a final investment decision not expected until 2015 in
addition to accounting for uncertainty relating to government approvals, development
delays, geological and funding risks. We highlight that the significant development capex
of $1.1bn to be spent during FY14-18 weighs heavily on our DCF valuation. Our key
modelling assumptions are discussed below:
Capex: Gross project capex of US$1,135m for three production wells, two injection
wells, the three train gas refrigeration plant, pipelines and storage tanks.
Production: Condensate sales of 11,270 bpd (gross) commencing in 1H CY19 based
on 50 mmbbl of 2C condensate resource (gross) and a CGR of ~54 bbl per mmcf. We assume gas production of ~210 mmscf/d is reinjected after condensate stripping with gas sales commencing in 1H CY20 to supply a third party LNG project such as T3 of PNG LNG.
Pricing: Condensate sold at Brent crude oil pricing and gas sold at Australian east
coast LNG netback pricing (US$9/GJ in FY17).
Opex: Operating costs of US$50m p.a. including condensate transport costs.
Royalty: 2% royalty to landowners, affected provincial governments and local level
governments calculated on a “wellhead value” basis plus a development levy of 2% of the wellhead value to the provincial governments and the local level governments.
Tax: 30% company tax rate.
Item US$m
Development planning 60
Gas Plant 390
Pipeline 210
Terminal, Storage and Loadout facilities 40
Roads 55
HSE, Regulatory, PM and Owners costs 55
Contingency (20%) 149
Wells (5) 175
Total Capital Cost 1135
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 20
Total Funds Employed 262.4 362.6 410.0 458.6 430.5 532.7
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 31
RETURN RE-INVESTMENT MATRIX RISK MEASURES
Retu
rn Hig
h
Cash Generator
Champion
Low
Challenged Potential
Low High
Re-Investment
HZN is not forecast to generate any free cash flows or pay any dividends until after 2020 when production from PRL 21 commences.
Low Med High Spec
Share Price Risk
Business Risk
HZN is considered High Risk due to the nature of oil & gas exploration and production, volatile commodity prices and potential project development delays.
BUSINESS DESCRIPTION
Horizon Oil Limited (HZN) is an ASX-listed oil and gas exploration, development and production company with assets located in China, New Zealand and Papua New Guinea. We forecast oil production of 1.8 mmbbl in FY15e (versus 1.4 mmbbl in FY14) from the company’s 26.95% interest in Block 22/12, located in the Beibu Gulf of China and 10% interest in the Maari/Manaia oil fields (PMP 38160) in the Taranaki Basin, offshore New Zealand. HZN also provides significant potential upside through the successful development of its 27-30% interest in 7,900 km
2 of acreage in the Western
forelands of Papua New Guinea containing a net 2C resource of 79.6 mmboe.
INVESTMENT THESIS
HZN appears undervalued trading at 0.77x price/NPV although we expect the valuation gap to narrow as production from Maari triples in FY15e, further wet gas resources are potentially discovered in PNG and the Stanley wet gas project is progressed. We believe HZN is fully funded to meet its share of capex based on existing cash of $99m, operating cash flow of $60m in FY15e while we assume the additional $130m payment from Osaka Gas is received in FY16e. Approx. 39% of our valuation relates to the company’s PDL 10 and PRL 21 appraisal and development assets in PNG. We assume first condensate from the Stanley development project (PDL 10) in 2H CY16 with gas sales from CY20 to a mid-scale LNG project on Daru Island owned by third parties.
REVENUE DRIVERS BALANCE SHEET
Higher-than-forecast oil production and oil prices
Development of the Stanley gas project faster than expected
Securing gas supply agreements for Stanley gas production
Finalisation of end markets for PDL and PRL 21 gas resource
Cash on hand of $98.9m at 30 June 2014
Convertible bond of US$80m due 17 June 2016
Reserves-based debt facility of $150m ($119 drawn at 30 June 2014)
Shareholders equity of $222m at 30 June 2014
KEY ASSETS
Block 22/12 in the Beibu Gulf, offshore China (26.95%)
Maari and Manaia Fields in PMP 38160, offshore New Zealand (10%)
Stanley Field in PDL 10, PNG (30%)
Elevala/Ketu/Tingu Fields in PRL 21, PNG (27%)
RESERVES & RESOURCES BOARD
2P reserves of 15.1 mmboe at 30 June 2014
2C resource of 79.6 mmboe at 30 June 2014
Fraser Ainsworth – Non-Executive Independent Director and Chairman
Brent Emmett – Executive Director and Chief Executive Officer
John Humphrey – Non-Executive Independent Director
Gerrit J de Nys – Non-Executive Director
Andrew Stock – Non-Executive Independent Director
KEY ISSUES/CATALYSTS MANAGEMENT
PNG government approval for EKT Fields (PRL 21)
Development of Stanley project on time and on budget
Resolution of PNG gas commercialisation strategy
Access to funding for development capex
Brent Emmett – Executive Director and Chief Executive Officer
Michael Sheridan – Chief Financial Officer/Company Secretary
Alan Fernie – Manager Exploration and Development
RISK TO VIEW CONTACT DETAILS
Lower-than-expected oil production and oil prices
Development delays for the Stanley wet gas project
Later-than-forecast production from Stanley
Address: Level 7, 134 William St, Woolloomooloo, NSW 2011 Australia
Phone: +612 9332 5000
Website: www.horizonoil.com.au
05 September 2014
Energy
Horizon Oil Limited
Wilson HTM Equities Research – Horizon Oil Limited 32
Head of Research Head of Institutional Sales
Shane Storey (07) 3212 1351 Richard Moulder (02) 8247 6603
Industrials Sydney
James Ferrier (03) 9640 3827 Jonathan Scales (02) 8247 6613
Stewart Oldfield (03) 9640 3818 Duncan Gamble (02) 8247 6629
George Gabriel (03) 9640 3864 Michael Pegum (02) 8247 6602
Daniel Wan (02) 8247 6694 Anthony Wilson (02) 8247 3113
Andrew Dalziel (07) 3212 1946 Peter Tebbutt (02) 8247 6682
Healthcare and Biotechnology Melbourne
Shane Storey (07) 3212 1351 David Permezel (03) 9640 3885
Joseph Michael (02) 8247 3101 Adam Dellaway (03) 9640 3824
Resources
Phillip Chippindale (02) 8247 3149 Wealth Management Research
James Redfern (02) 8247 6609 Peter McManus (02) 8247 3186
Liam Schofield (02) 8247 3173 John Lockton (02) 8247 3118
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Disclosure of Interest. Horizon Oil Limited
The Directors of Wilson HTM Ltd advise that at the date of this report they and their associates have relevant interests in Horizon Oil Ltd. They also advise that Wilson HTM Ltd and Wilson HTM Corporate Finance Ltd A.B.N. 65 057 547 323 and their associates have received and may receive commissions or fees from Horizon Oil Ltd in relation to advice or dealings in securities. Some or all of Wilson HTM Ltd authorised representatives may be remunerated wholly or partly by way of commission.
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