cost curve australian east coast gas - macquarie · 2015-04-15 · australian east coast gas a more...

Please refer to page 45 for important disclosures and analyst certification, or on our website

www.macquarie.com/research/disclosures.

AUSTRALIA

We now forecast little market tightness across East Coast gas markets...

...With a move to marginal cost still likely

Stock Rating TP NAV Share Price

STO O 10.00 12.27 7.69 ORG N 12.50 12.63 12.02 AGL N 15.15 14.92 15.28 BPT N 1.10 1.08 1.10 AWE O 2.00 2.39 1.23 DLS N (prev O) 1.20 1.37 1.10 SXY O 0.45 0.52 0.32

Source: AEMO, AGL, Macquarie Research, April 2015

Inside

Summary 2

Within the transition period 5

A more orderly transition through the peak 8

Buyers quickly adapting 14

Supply shortfall dictated by price 20

Infrastructure bottlenecks opening up 24

Government playing a more active role 29

Mixed news for the producers... 31

15 April 2015 Macquarie Securities (Australia) Limited

Australian East Coast Gas A more orderly transition Transitional period not looking that tight

Against the backdrop of a slower ramp up of LNG projects, greater elasticity of

domestic demand to the higher prices, improving CSG deliverability and existing

third party supply, the medium-term gas market appears less tight than we

previously anticipated over the 2014-19 window. Longer term, the East Coast

has ~155,000PJ of known recoverable gas reserves and contingent resources

with a further ~300,000PJs of estimated yet-to-be-discovered prospective

resources – the discovered gas in isolation underpins a resource life of over 60

years growing ~200 years including prospective shale and tight gas resources,

which together will continue to cap gas prices at marginal cost.

Gap between LNG net back & marginal cost largely eroded

With LNG ramp-up now upon us, the initial market reaction to QCLNG

commissioning has been, by all accounts, muted. Against the backdrop of

collapsing oil and spot LNG prices, the gap between marginal cost and operating

net-back has fallen considerably, offering LNG operators little incentive to pay

premium prices for short-term gas supply (potentially leaving those with surplus

gas exposed). This, in addition to a slower-than-anticipated ramp up, means

LNG exports are perhaps not having the desired effect of tightening

supply/demand or of importing premium international pricing. Indeed, exports are

merely driving a move up the cost curve (offering little reward for producers).

Buyers quickly adapting to the new environment

Faced with a once-in-a-generation change in gas prices, end-users are proving

reluctant to lock in high gas prices and are instead recontracting transitional

agreements to buy time to investigate alternative fuel sources or explore longer-

dated, riskier options. Furthermore, the range of gas price expectations among

buyers only highlights the uncertainty facing these businesses –in addition to

higher absolute prices, this is of equal concern, perhaps explaining buyers’

support for a transparent spot market.

Infrastructure bottlenecks opening up

With pipeline and processing infrastructure constraints likely to be lifted in due

course, long-term pricing could potentially move to merely reflect transportation

differentials (we envisage a ~A$2.50/GJ differential between Victoria and

Wallumbilla). Furthermore more ambitious pipeline connections/expansions

(such as the North East Interconnector) could potentially introduce new supply

competition into East Coast gas markets. Indeed the swing in gas at Wallumbilla

could be as large as 600-700TJ/d by the end of the decade.

Mixed news for the producers

With the short-lived peak in East Coast gas prices now likely to be even

shallower due to lower LNG net-back during the ramp-up of East Coast LNG

projects, any near-term margin expansion on offer for producers appears less

obvious compared to our original expectations. Furthermore, the prospect of

higher gas prices has stimulated an unwanted response from buyers, policy

setters and new suppliers – something the incumbents were keen to avoid.

Santos (Outperform, A$10.00/sh price target)

Origin (Neutral, A$12.50/sh price target)

Beach Energy (Neutral, A$1.10/sh price target)

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Peak capacity requirement ~6,000 TJ/d

TJ/d

http://www.macquarie.com/research/disclosures

Macquarie Wealth Management Australian East Coast Gas

15 April 2015 2

Summary A more orderly transition through peak pricing...

With East Coast demand tripling over coming years as LNG exports ramp-up, this was set to

the change the landscape of the local market, offering little time for adjustment. However with

LNG ramp up now upon us, compared with our original forecasts for East Coast gas supply &

demand, the East Coast gas market is looking better placed to manage this transition.

Consequently, while we anticipate that there could be some short-term volatility as initial LNG

trains are commissioned on Curtis Island over the course of this year, the possibility of near-

term price spikes appear to be quickly fading.

With both oil and spot LNG prices collapsing in conjunction with LNG ramp-up, the gap

between marginal costs and operating net-back has fallen considerably, offering LNG

operators little incentive to pay premium prices for short-term gas supply (even if

plants remain underutilised).

We believe a slower ramp up of East Coast LNG exports (with the 2nd

train at GLNG

not reaching capacity until 2019) is not being factored into consensus demand

projections. Furthermore, operators appear unlikely to deliver significant spot volumes

outside of commissioning cargoes, in our view.

Operators have a growing level of confidence surrounding the initial deliverability of

core upstream fields feeding LNG projects following an acceleration of drilling in recent

years. While tightening the market in the medium term, third party gas supplies have

already significantly reduced the risk of near-term shortfalls.

...with the medium-term market looking increasingly well supplied

Against the backdrop of much weaker domestic demand, abundant gas resources that could

be unlocked by proposed pipeline infrastructure expansion and a push by governments and

buyers alike for more pricing transparency, this could accelerate a permanent move to

marginal costs.

Local gas demand is looking more elastic than previously envisaged with demand

forecasts slashed over recent months – indeed AEMO now expects domestic demand

to decline by 1% p.a. over the next five years compared with original expectations of a

7% CAGR.

Apart from QCLNG (where Shell’s successful offer for BG could see Arrow Gas

underwrite a third train), expansion trains appear less likely. Furthermore, against the

backdrop of weak global LNG demand, little appetite for spot sales and finite resource

coverage, operators could potentially delay de-bottlenecking of foundation LNG

capacity.

The COAG Energy Council has taken heed of buyer concerns surrounding pricing

transparency, pushing for market based outcomes. While still a number of years away,

both a vibrant spot market at Wallumbilla and Moomba and flexible capacity trading on

strategic pipelines could erode the incumbents’ position and accelerate the move to

marginal cost.

Buyers quickly adapting

Faced with a once-in-a-generation change in gas prices, end-users are reluctant to lock in

high gas prices and are waiting until the last moment to recontract. Buyers are instead

agreeing to transitional agreements to buy time to investigate alternatives fuel sources or

explore longer-dated, riskier options. Furthermore, the range of gas price expectations among

the buyers only serves to highlight the uncertainty facing these businesses –this appears of

equal concern to buyers as the higher absolute prices faced, perhaps explaining support for a

transparent spot market. Meanwhile it is the energy retailers that are contracting early to take

advantage of an integrated portfolio to grow uncommitted gas volumes at Wallumbilla.

Short-term East

Coast gas price

spikes could be

avoided given weak

spot LNG and oil

prices

AEMO now

anticipates EA

domestic gas

demand to fall by

~1% p.a over

2015-20


15 April 2015 3

No shortage of gas longer term

The East Coast of Australia has ~155,000PJ of known recoverable gas reserves and

contingent resources, with a further ~300,000PJs of estimated yet-to-be-discovered

prospective resources – the discovered gas in isolation underpins a resource life of over 60

years growing to ~200 years including prospective shale and tight gas resources.

Even at spot LNG net-back, we believe this at least unlocks enough gas for 20 years

of domestic demand and supply for existing LNG projects and debottlenecking and as

much as 80,000-160,000PJ of resource based on various independent cost curves.

While unconventional activity in the Cooper has been curtailed in the current

environment, initial programs have already delivered 6tcf of discovered resource and

confirmed a vast resource in place, which will keep a cap on gas prices longer term.

Infrastructure bottlenecks opening up

We originally anticipated that increased contracting by retailers in Victoria (including ORG’s

432PJ, nine year GSA with Esso/BHPB) was to meet gas demand from southern states and

release either equity or contracted supply closer to Wallumbilla. Physical

pipeline/specification constraints could have potentially created a disconnect between

southern state gas prices and the premium price at Wallumbilla. However, with pipeline and

processing infrastructure constraints seemingly being resolved, long-term pricing could

potentially move to transportation differentials (we would envisage a ~A$2.50 transportation

differential between Victoria and Wallumbilla, reflecting flexible terms offered by APA to

access capacity across multiple pipelines).

With the SWQP, RBP, MSP and MAPS all likely to be capable of bi-directional flow by

2015, the pipeline network continues to become more integrated.

More ambitious pipeline connections/expansions (such as the North East

Interconnector) could potentially introduce new supply competition in East Coast gas

markets. Indeed, we believe the swing at Wallumbilla could be as large as 600-

700TJ/d by the end of the decade.

Governments playing a more active role

In its recently released Energy White Paper, the Federal Government continues to lean

towards market-based outcomes rather than regulation (including domestic reservation).

However it has taken note of buyers’ frustration regarding perceived near-term shortfalls and

the lack of transparency regarding both available gas supply and pricing signals. While the

possibility of regulation appears slim, greater transparency and oversight is likely to erode the

market power of incumbents (such as STO and ORG), providing greater market insight to

smaller producers and buyers, in our view. Furthermore, with separate parliamentary inquiries

recently undertaken by the NSW and Victoria state governments and the ACCC recently

commencing a 12-month public inquiry into the competitiveness of wholesale East Coast gas

markets, focus on the industry has never been so acute.

Mixed news for producers

With the peak in East Coast gas prices now likely to be even shallower due to lower LNG net-

back during the ramp-up of East Coast LNG projects, any near-term margin expansion on

offer for producers appears less obvious compared to our original expectations. Meanwhile

both upstream producers and industry experts alike have underestimated the elasticity of

domestic demand, in our view. Finally, the prospect of higher East Coast prices has

seemingly stimulated what for the incumbents is an undesirable response from buyers, policy

setters and new suppliers.

Santos (Outperform, A$10/sh target): The resource shortfall at GLNG; poor results

from the Cooper infill program; greater-than-anticipated elasticity of domestic demand;

a depressed LNG net-back just as CSG-to-LNG projects are ramping up; the threat of

new supply sources from NT & Victoria; and the possibility of a more transparent spot

market either have or will impact STO’s East Coast gas strategy. Indeed STO’s

stranglehold on East Coast markets appears to us threatened on multiple fronts.

Pipeline expansion

could see the gas

swing at Wallumbilla

grow to 600-700TJ/d


15 April 2015 4

Origin Energy (Neutral, A$12.50/sh target): Origin is in a strong position within the

east coast gas market as a both a producer and retailer of gas. Origin has ~20-30PJ

pa of equity gas along with ~40PJ pa of APLNG purchases which are all mispriced.

The other gas purchases, namely Esso/BHP from 2010 and 2014, Beach from 2015 all

reflect some level of oil price-look through, thus ORG in this case is more of an agent.

Thus leverage to every $1/GJ is ~$49m pa.

Beach Energy (Neutral, A$1.10/sh target): With the new managing director only

recently commencing, communication of the new strategy is likely to be a number of

months away. That said, we believe that East Coast gas markets more broadly will

remain core to the new strategy. With a solid balance sheet, a willingness to consider

divestment of infrastructure-like assets (that could crystallise healthy prices) and an

open mind to new opportunities, BPT could prove well placed to benefit from the

changing East Coast gas market dynamics.

AWE (Outperform, A$2.00/sh target): With the share price trading at a 14% discount

to our core NAV of A$1.48/sh, AWE offers considerable value. With the problematic

BassGas MLE project approaching completion (which will see a sizable uptick in

production), the focus is instead likely to be on further appraisal of the conventional

Waitsia fields in the Perth Basin, production & reserves growth in the Eagle Ford and

the ability to reach its target of 10mmboe of production in FY18.

Drillsearch (Downgrade to Neutral, A$1.20/sh target): DLS continue to take

proactive measures in order to adapt to the current oil price environment, expressing

capital discipline and encouraging cash flow conservation. Despite recent capex cuts,

we still believe that DLS has the ability to deliver material wet gas production over

coming years (50-70 mmcf/d). Furthermore, even a move to marginal cost will ensure

significant margin is preserved. Such production growth is set to benefit from potential

increased transparency in East Coast gas markets and available third-party

processing capacity at Moomba.

Senex Energy (Outperform, A$0.45/sh target): Despite traditionally being focussed

on high margin oil potential, targeted production of 3-5mmboe and 2P reserves of 100-

150mmboe by FY18 has seen a greater focus on gas assets. Indeed the recent West

Surat CSG asset swap provides SXY with a 488PJ 2P reserves position close to

existing CSG fields supporting LNG development. Furthermore we estimate a full-field,

90-well development could deliver 50TJ/d of production.


15 April 2015 5

Within the transition period With East Coast demand tripling over coming years as LNG exports ramp-up, this was set to

the change the landscape of the local market with little time for adjustment. This pointed to

rising prices in the medium term with a key market window opening up from 2014-19.

However, compared to our original forecasts for East Coast gas supply and demand, the

market has changed considerably. Consequently, while we anticipate that there could be

some short-term volatility as initial CSG-to-LNG trains are commissioned on Curtis Island, the

market is looking increasingly well supplied in the medium term, with the potential for near-

term pricing spikes seemingly fading.

Fig 1 In May 2012, it appeared that the East Coast market would be tight from 2014 to 2020…

Fig 2 …however with Arrow scrapped and given weaker domestic demand we see little tightness

Source: AEMO, Qld Govt, STO, Macquarie Research, April 2015 Source: AEMO, Qld Govt, STO, Macquarie Research, April 2015

After a number of years of relatively stable market share, the ramp up of Queensland CSG

fields over 2H14 (in particular QCLNG facilities) appears to have displaced offshore Victorian

production in the first instance, with Cooper Basin gas sales remaining well supported.

Fig 3 Growing production of Queensland CSG has largely displaced offshore Victorian volumes, with Cooper Basin gas also maintaining its market share

Source: NGBB, Macquarie Research, April 2015

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EA gas sales ex processing (TJ/d)

The potential for

near-term pricing

spikes appears to

be fading

Growing CSG

deliverability has

displaced Victorian

gas production, with

Cooper nominations

remaining strong


15 April 2015 6

Domestic demand deteriorating faster than anyone anticipated...: Following a

number of years of buyers heavily lobbying for domestic gas policy reform, many have

struck transition agreements heading into near-term contract expiries to consider

alternative fuel sources or to buy time to explore riskier, longer term supply sources.

However, with AEMO cutting its demand growth forecasts from a 7% CAGR from

2015-20 in 2010 to a 1% annual decline last year, the market continues to

underestimate the elasticity of demand. While the depreciation of the AUD and easing

labour markets could ease pressure, the damage appears to have already been done

with a number of announced plant closures.

...driving a move down the cost curve: With near-term shortfall quickly eroding, the

market should move back to marginal cost of the installed and developing capacity.

Post full ramp-up, we estimate the marginal cost of gas delivered to Wallumbilla at

>A$8/GJ, which is below LNG operating net-back (~A$9.70/GJ based on our long-term

assumptions but A$6.70/GJ assuming spot oil and fx). As seen in the US, any move to

market based pricing will likely erode incumbents’ power and only accelerate the move

to marginal cost.

A slower ramp-up of Curtis Island exports: With the slow ramp-up of contractual

obligations now obvious, the East Coast market could have more time, compared to

original expectations, to absorb this transformational change. While we anticipate

some volatility during commissioning of initial trains, this will be more effectively

managed as further trains are brought online (in light of interconnections between

projects and bilateral supply agreements). While BG continues to suggest 5-10% of

potential debottlenecking at QCLNG (equating to ~100-150PJ/yr of additional feed gas

requirement across all projects), this is only likely to be considered after ramp-up of

minimum contractual obligations at a time when gas supply is likely to grow and in a

strengthening global LNG market.

Fig 4 Marginal cost of existing/developing capacity delivered at Wallumbilla assuming peak demand of ~6,000TJ/d approaches ~A$8/GJ

Fig 5 AEMO forecasts for East Coast gas demand have fallen considerably over recent years

Source: AEMO, Qld Govt, STO, Macquarie Research, April 2015 Source: AEMO, Macquarie Research, April 2015

Greater confidence in CSG-to-LNG initial upstream deliverability: Against the

backdrop of a slower ramp-up, there appears a growing level of confidence

surrounding the initial deliverability of core upstream fields feeding projects. Logically,

operators appear to be focused on the sweet spots, including Fairview for GLNG

(where average deliverability has risen to ~2TJ/d), Talinga for APLNG and Ruby Jo for

QCLNG. While tightening the market in the medium term, third-party supply

agreements have removed uncertainty during ramp-up.

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Demand (PJ)


15 April 2015 7

Collapsing spot and contract LNG netbacks: Spot LNG prices have collapsed over

the last 12 months, falling from U$20/mmbtu in February 2014 to a low U$6.6/mmbtu

in February 2015. Consequently we estimate that the LNG operating net-back to

Wallumbilla has fallen from ~A$19/GJ to merely ~A$7.5/GJ, providing LNG operators

with significantly lower economic incentive to produce beyond minimum contractual

obligations, particularly against the backdrop of finite reserves coverage and a global

LNG portfolio.

Resolution to transportation bottlenecks: With APA calling for expressions of

interest on further expansions of the SWQ pipeline and also upgrading the Victoria-

NSW interconnect to 116TJ/d from 46TJ/d, physical infrastructure bottlenecks are

quickly being removed. Indeed this could ultimately see the MSP flow reversed and

more gas delivered to Wallumbilla, which could smooth any price spikes that otherwise

would have been isolated to the Queensland market.

Ramp-up of offshore Victoria production underappreciated: Queensland CSG

ramp-up gas has significantly displaced offshore Victorian production (particularly from

the Esso/BHPB Longford Plant where monthly production has fallen by between 10-

20% on pcp over recent months). However, with a number of gas sale agreements

struck over recent months (including a 198PJ agreement with AGL) supported by

completion of the ~U$1bn Longford gas conditioning plant due by 2016 (which will

deliver an additional 400mmscf/d of processing to support development of Kipper

Tuna Turrum), this could also provide medium-term production growth.


15 April 2015 8

A more orderly transition through the peak Producers continue to anticipate an increase in gas prices to the A$6-9/GJ range, with

medium-term contracts already exceeding the top end of this range (indeed STO now

believes prices are likely to remain >A$8/GJ). Nonetheless, with all three CSG-to-LNG

projects anticipated to ramp-up this year, it would appear that we could quickly move through

peak pricing. Indeed we believe LNG participants will navigate the ramp-up period via limiting

spot sales beyond commissioning cargoes, existing third-party gas supply deals, improving

well deliverability from core fields and the ability to turn-down these wells, which will limit the

reliance on other supply sources. This, in combination with a lower LNG net back pricing in

the current oil price environment, will cap incentive domestic gas pricing, with longer-term

prices likely to be supported by the rising production cost of production as LNG proponents

move to more marginal CSG fields and the broader industry moves up the cost curve (albeit

at a slower-than-expected pace).

Fig 6 While producers are still pointing to A$6-9/GJ gas prices, buyers remain uncertain where gas prices are going


Source: Company sources, Macquarie Research, April 2015 Source: AGL, Macquarie Research, April 2015

LNG net back now translating to a hump rather than a peak

With LNG development capex now sunk, the opportunity cost of keeping this infrastructure

underutilised appears high, which will likely keep East Coast prices temporarily well above

long-run marginal cost. However, with operators reluctant to aggressively utilise trains to

capacity (in accordance with the slower contractual ramp-up) and in light of collapsing spot

NE Asian LNG and JCC oil prices, both required volume and incentive pricing suggests to us

shallower peak pricing than our original expectations.

Buyers have been wary of a possible shift to oil-linked gas prices in Eastern Australia.

Furthermore, while initial oil-linked supply agreements were largely with LNG

participants, there have now been a number oil-linked supply agreements struck with

Esso/BHPB in the Bass Strait. However, with the majority of this volume going to ORG

and AGL in an attempt to supply preserve gas to the Queensland market, these

buyers are seemingly taking a portfolio approach. To date there have been few end-

users willing to sign up to long-term, oil-linked supply agreements.

With the pressure to ensure deliverability for minimum LNG contractual obligations

now largely met for all CSG-to-LNG projects, it would appear that we have reached the

end of this phase. Indeed, the Westside/GLNG gas sale agreement struck in March

2014 could well have represented the last long-term supply deal with oil-linkage struck

during the crucial ramp-up phase.

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15 April 2015 9

While confidential, we believe the actual pricing terms struck on these contracts are

perhaps less concerning. Indeed, the 750PJ STO-GLNG Horizon contract was

required to ensure resource coverage to assure the GLNG partners would sanction a

second train (which could have seen a discounted price offered, perhaps explaining

BPT’s reluctance to sign up). The Westside/GLNG supply agreement remains the only

contract where pricing terms have been publicly disclosed. However, with a constant

of U$1.5/GJ and a slope of 6.5%, this translates to a far from inspiring gas price of

A$6.6/GJ at spot assumptions today. Furthermore, despite being the last contract

struck with GLNG, we estimate that the price was at an implied 25% discount to LNG

operating net-back.

While operating LNG netback simplistically provides a SRMC ceiling to East Coast gas

prices, third-party gas supply during the ramp-up phase is merely deferring upstream

capex decisions rather than completely removing them from the supply equation

(particularly given the longer-term reserves shortfall facing many projects). Indeed it

would appear that GLNG is deferring investment in additional Roma compression via

third-party supply (we estimate that a further ~490TJ/d of compression will be needed).

Consequently, the incentive price demanded by LNG producers for upfront third-party

supply is likely to be significantly lower than LNG operating net-back (SRMC),

particularly across fields with limited existing gas processing.

Spot LNG prices have collapsed over the last 12 months, falling from U$20/mmbtu in

February 2014 to as low U$6.6/mmbtu in February 2015. Consequently, we estimate

that the LNG operating net-back to Wallumbilla has fallen from ~A$19/GJ to merely

~A$7.5/GJ, providing LNG operators with significantly lower economic incentive to

produce beyond minimum contractual obligations, particularly for those with finite

reserves coverage that are managing global LNG portfolios.

Fig 8 The gap between LNG net-back and marginal cost has shrunk, with the range falling due to weaker oil prices and a flattening cost curve

Source: AEMO, ACIL Allen, MMA, Qld Govt., ABS, JacobsSKM, Macquarie Research, April 2015

Short-term volatility likely to diminish...

While there has been significant pricing and volume volatility across short-term trading

markets (STTM) surrounding start-up of the first train at QCLNG (particularly in Sydney), we

anticipate that short-term gas markets will exhibit incrementally less volatility as successive

trains are commissioned over next two years. Indeed it would appear that LNG participants

have put in place a number of mechanisms to smooth LNG demand both during ramp-up and

planned maintenance.

In its latest Gas Statement of Opportunities released in April, AEMO now anticipates

only small 15-20PJ/a supply gaps could emerge from 2020 and that NSW now faces

little shortage of gas supply (even with modelling excluding Narrabri and Gloucester

production).

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A$/GJ Spread from marginal cost to LNG netback ACIl Tasman - Wallumbilla (nominal)

AEMO SKM-MMA (nominal)

QLD Gas Market review ABS

Macquarie Spot LNG netback

LNG operators are

preserving some of

the margin – we

estimate the

Westside/GLNG

supply agreement

was at a 25%

discount to

operating netback

Despite QCLNG

being the first train

to commission,

prices on Brisbane

STTM only spiked to

~A$5/GJ and have

quickly fallen back

to ~A$3/GJ


15 April 2015 10

STTM pricing in Brisbane had swung from a A$4/GJ discount to Sydney prices to a

small premium in late January as QCLNG fields (particularly Ruby Jo) ramped-up.

While volumes remained thin, the premium quickly spread to Sydney and to a lesser

extent Adelaide. While short-term prices peaked at ~A$5/GJ in Brisbane, this is

significantly lower than the >A$13/GJ spikes that we anticipated previously, with

Brisbane prices quickly normalising to ~A$3/GJ.

Bi-directional interconnections are in place between GLNG and APLNG at Fairview &

Scotia and between QCLNG and GLNG on both sides of the Narrows crossing (with

600TJ/d of capacity). This will help manage gas demand during subsequent

commissioning of LNG trains and the upstream turn-down during planned

maintenance periods.

The ability to turn down wells will provide significant flexibility during the ramp-up

period. Indeed, APLNG has suggested that by the time train 1 is commissioned in mid-

2015, as much as 400TJ/d of well-head capacity would be turned down. STO has also

suggested that there is significant flexibility surrounding the ability to shut-in wells at

Fairview (while deliverability here will reach 600TJ/d by year end, only a fraction of this

capacity is likely to be turned up during the first three months of ramp-up).

We believe GLNG could act as a swing producer, given the project remains 600ktpa

under-contracted (which equates to ~100TJ/d or 5% of domestic demand) and with

75TJ/d of injection/withdrawal capacity at the ~50PJ RUGS facility. As a large supplier

of gas, STO will not likely want to see a surplus of gas in the market.

Both storage and an upgrade to pipeline infrastructure to support bi-directional flow will

help manage peak loads, particularly in South Australia and Victoria. In addition to bi-

directional flow on the SWQP, bi-directional flow will be available on the RBP, MAPS

and MSP by 2015.

Fig 9 Volatility in daily gas nominations across predominately Victoria...

Fig 10 ...has been managed through Gippsland production, with storage likely to be increasingly important

Source: AEMO, Macquarie Research, April 2015 Source: AEMO, Macquarie Research, April 2015

Depressed gas pricing in late 2014 saw a significant ramp-up of gas-fired generation in

Queensland. With the forward electricity market pricing in A$35/MWh for the remainder

of FY15 & A$47/MWh in FY16 and assuming an average heating rate of

~8.00GJ/MWh, this equates to an incentive price of A$4.40-5.90/GJ (although hedging

within retailers is likely to distort this incentive price). Similarly, a gas price beyond

A$8/GJ could see ~189PJ of gas drawn from the immediate gas-fired power stations

across the NEM.

0

200

400

600

800

1,000

1,200

1,400

0% 20% 40% 60% 80% 100%

2014 Daily Demand

(TJ/d)

Percentage of time

SA

VIC

TAS

NSW

QLD

0

200

400

600

800

1,000

1,200

0% 20% 40% 60% 80% 100%

2014 Gas Production

(TJ/d)

Percentage of Time

Cooper-Eromanga

Bowen-Surat

Sydney

Otway

Gippsland

Bass

600TJ/d of bi-

directional

interconnection

between GLNG and

APLNG at Curtis

Island will provide

significant flexibility


15 April 2015 11

Fig 11 The short-term price reaction at the Brisbane STTM from commissioning of QCLNG has been more muted than we anticipated

Fig 12 This has come despite moving to a net short position at both the Sydney and Adelaide STTM

Source: AEMO, Macquarie Research, April 2015 Source: AEMO, Macquarie Research, April 2015

Arbitraging spot LNG prices to ensure flexibility

Unlike conventional LNG developments, the ability to turn down a significant portion of

upstream CSG well stock supported by the Optimised Cascade LNG Process (which provides

plant efficiency down to 50% utilisation) could provide LNG participants with the opportunity to

flex supply from equity to third party molecules or, under a more opportunistic scenario, seek

spot LNG cargoes to fulfil its contractual obligations if prices reach low enough levels.

Furthermore, against the backdrop of lumpy supply additions from Australian and the US in

coming years, coupled with weak demand from key markets, this could see liquidity in the

spot LNG market grow considerably from the ~70mtpa reported in 2014.

Both TOTAL and BG have active LNG trading businesses (both are in the top three

traders for LNG). Indeed TOTAL’s LNG trading arm anticipates that it will trade 220

cargoes by the end of the decade. QCLNG has signed 10mtpa of supply agreements

and therefore is already relying on supply from BG’s LNG portfolio. Indeed BG spot

LNG purchases increased from nine cargoes in 2013 to 28 cargoes in 2014 (largely to

manage challenges at the Egyptian LNG project). Completion of the Shell offer will see

the merged group control 46mtpa of equity LNG capacity by 2018 (~ 13% of our supply

forecast), offering significant scale and trading opportunities.

Arbitraging spot LNG markets could provide an opportunity to preserve reserves,

which has been of particularly concern for GLNG. We estimate a further 1,000PJ of

third-party gas is needed in due course here for this project however this is a long-term

problem.

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

Ja

n-1

2

Ma

r-1

2

May

-12

Jul-

12

Se

p-1

2

No

v-1

2

Ja

n-1

3

Ma

r-1

3

May

-13

Ju

l-13

Se

p-1

3

No

v-1

3

Jan

-14

Ma

r-1

4

Ma

y-1

4

Ju

l-14

Se

p-1

4

No

v-1

4

Jan

-15

Ma

r-1

5

Brisbane Sydney AdelaideA$/GJ

-500

-400

-300

-200

-100

0

100

200

300

Ja

n-1

2

Ma

r-1

2

Ma

y-1

2

Ju

l-1

2

Sep

-12

No

v-1

2

Ja

n-1

3

Ma

r-1

3

Ma

y-1

3

Ju

l-1

3

Sep

-13

No

v-1

3

Ja

n-1

4

Ma

r-1

4

Ma

y-1

4

Ju

l-1

4

Sep

-14

No

v-1

4

Ja

n-1

5

Ma

r-1

5

Brisbane Sydney AdelaidePJ

Majors could use

their growing LNG

portfolios to

manage contractual

obligations rather

than rely on a tight

East Coast gas

market


15 April 2015 12

Fig 13 There have been extended periods where spot NE Asian LNG prices have traded below proposed CSG-to-LNG contract prices...

Fig 14 ...this could see projects with significant turn-down capacity opportunistically take advantage – GLNG third-party gas costs already above spot LNG net-back

Source: WGI, Macquarie Research, April 2015 Source: WGI, STO, Macquarie Research, April 2015

...With the move to marginal cost still likely in the medium term

Against the backdrop of a vast undeveloped gas resource across Eastern Australia, we

continue to see little fundamental support for East Coast gas prices remaining oil linked (apart

from gas feeding LNG projects and a select number of “transition” contracts). Indeed, based

on installed and developing capacity, the marginal cost of gas delivered to Wallumbilla

appears to fall at >A$8/GJ, which is below LNG operating net-back (which is ~A$9.70/GJ

based on our long-term assumptions but above net-back at spot oil and fx of A$7.05/GJ).

With the existing East Coast 2P reserves life still at ~25 years (based on combined domestic

and LNG demand), this likely places a cap on longer-term pricing. However, while even spot

netback will incentivise at least~25,000PJ of undeveloped resource (equating to a further 11

years of reserves life assuming peak demand), the depressed oil price environment is already

seeing significant reductions in capex across emerging gas plays, which could have longer-

term ramifications.


Fig 16 ...with longer-term marginal cost driven by cost of undeveloped resources

Source: AGL, Macquarie Research, April 2015 Source: AEMO, EnergyQuest, IES, Core, JacobsSKM, April 2015

0

2

4

6

8

10

12

14

16

18

20

Oc

t-1

0

Ja

n-1

1

Ap

r-1

1

Ju

l-1

1

Oc

t-1

1

Ja

n-1

2

Ap

r-1

2

Ju

l-1

2

Oc

t-1

2

Ja

n-1

3

Ap

r-1

3

Ju

l-1

3

Oc

t-1

3

Ja

n-1

4

Ap

r-1

4

Ju

l-1

4

Oc

t-1

4

Ja

n-1

5

Ap

r-1

5

oil-linked LNG netback (opex + shipping)

spot LNG netback (opex + shipping)

U$/mmbtu

0

2

4

6

8

10

12

14

16

1Q

15

4Q

15

3Q

16

2Q

17

1Q

18

4Q

18

3Q

19

2Q

20

1Q

21

4Q

21

3Q

22

2Q

23

1Q

24

4Q

24

3Q

25

2Q

26

1Q

27

4Q

27

3Q

28

2Q

29

1Q

30

4Q

30

3Q

31

2Q

32

1Q

33

4Q

33

3Q

34

2Q

35

GLNG Netback (Fwd Curve)

Blended Break Even (Wallumbilla)

3rd Party Gas Costs (Fwd Curve)

3rd Party gas costs (Macq)

GLNG net-back (spot LNG)

A$/GJ

0

2

4

6

8

10

12

0

50

0

10

00

15

00

20

00

25

00

30

00

35

00

40

00

45

00

50

00

55

00

60

00

65

00

70

00

GLNG

APLNG

QCLNG

Arrow

Field Break Even


Real $15 cost curve

(A$/GJ)


TJ/d

0

2

4

6

8

10

12

14

16

18

20

0 50,000 100,000 150,000

Real $15 cost curve (A$/GJ)ACIL Tasman

IES

Energy Quest

Core Energy

20 y

ears

of

dom

estic E

A d

em

and

Gas s

upply

requir

ed fo

r 3 s

anction LN

G p

roje

cts

de-b

ottle

neckin

g

of

3 p

roje

ct

SKM

PJ

We estimate the

marginal cost of gas

delivered into

Wallumbilla for

existing and

sanctioned

processing capacity

is ~A$8/GJ


15 April 2015 13

Given finite uncontracted export capacity (96% of nameplate capacity is contracted,

leaving only ~190TJ/d of possible supply available for spot sales), adequately

deliverability and 3rd

party supply to manage ramp and with debottlenecking seemingly

not front of mind (with the exception of QCLNG), there appears little spare capacity to

create the pricing tension needed for LNG net-back pricing to be sustained.

The marginal cost of existing and near-developed capacity delivered into Wallumbilla

appears to be driven by physical Esso/BHPB supply. While recent contracts with ORG

have freed up portfolio gas closer to the Wallumbilla hub, the upgrade to the VTS and

interconnect suggests that significant volumes could be physically transported to

Wallumbilla (indeed STO recently suggested that Kipper gas could also be delivered

into Wallumbilla). That said the marginal cost of this gas is now above an LNG

operating netback to Wallumbilla based on both spot LNG prices (~A$7.5/GJ) and a

LNG contract price net back assuming spot oil prices (A$6.9/sh).

STO estimates that in the three years to 2013, Australian FD&C costs averaged

A$4.16/GJ, which is ~3 times the average in the three years to 2007. However this

cost inflation has seemingly been driven by capacity constraints/wage inflation, not

necessarily just the development of technically more challenging resources. With STO

suggesting that it has already delivered a 5-30% reduction in subsurface contracts and

a 10-20% saving for surface contracts and with capacity utilisation of onshore CSG

rigs likely to fall moving from the ramp-up to maintenance phase, the current

environment is likely to see some flattening of the cost curve compared to previous

expectations.

With only ~190TJ/d

of spare LNG

capacity this

appears

insufficient to create

the pricing tension

needed sustain LNG

net-back pricing


15 April 2015 14

Buyers quickly adapting East Coast demand has changed dramatically over recent years. Indeed, an appreciation of

the slower ramp-up of LNG contractual obligations, the formal cancellation of Arrow LNG

earlier this year and a shrinking domestic market have seen demand forecasts for 2018 fall

from as high as 2,900PJ (based on AEMO’s forecast in 2011) to merely 2,050PJ (based on

our current forecasts) – this represents a ~2,300TJ/d swing, which is equivalent to the

feedgas requirements for more than three LNG trains.

Fig 17 AEMO forecasts for East Coast gas demand have fallen considerably over recent years

Fig 18 Based on stated LNG ramp-up profiles, consensus demand still looks too high

Source: AEMO, Macquarie Research, April 2015 Source: Company Data, Macquarie Research, April 2015

Industrial buyers starting to react to higher pricing

With contract expiries fast approaching and uncontracted demand anticipated to grow from

2018, buyers have refrained from locking their business into long-term supply agreements

that would structurally change their input cost base. While the depreciating AUD and easing

labour markets have provided some relief to those that are trade-exposed, many are still

reluctant to commit to longer-term agreements that would see a structural shift in their

respective input cost base. Against the backdrop of more volatile, higher pricing many have

entered into transition agreements (2-3 years) while other substitutes are considered or in

order to buy time to explore riskier, longer-dated supply options.

High gas prices a significant burden on manufacturing

With AEMO cutting its demand growth forecasts from a 7% CAGR from 2015-20 in 2010 to a

1% annual decline last year, the market continues to underestimate the elasticity of demand.

While the depreciation of the AUD and easing labour markets could ease pressure, the

damage appears to have already been done with a number of announced plant closures. This

ranges from closure of East Coast oil refineries (Clyde, Kurnell and Bulwer Island), which

used significant amounts of gas to generate steam to trade-exposed industries where higher

energy costs have only added to the competitive disadvantage faced.

The perception of rising prices has already created dislocation among domestic users.

Australian Paper (which consumed ~7.5PJ/a at its Maryvale Mill in Victoria)

announced a turnaround plan in February 2015 citing, among other things, the need to

work closely with suppliers to reduce input costs. Indeed access to competitive long-

term pricing for key manufacturing inputs such as gas was earmarked as an external

factor impacting operational viability. For other companies, the additional gas costs

have been absorbed into the overall cost structure. For example CSR suggested that

higher gas costs would see gas costs grow from only 4% to 6% of its total cost base.

Other local buyers are investigating other sources of supply. Indeed one buyer

suggested a move to landfill gas has seen gas costs fall by a third.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

AEMO (2009)

AEMO (2010)

AEMO (2011)

AEMO (2012)

AEMO (2013)

AEMO (2014)

Demand (PJ)

500

700

900

1,100

1,300

1,500

1,700

1,900

2,100

2,300

2,500

2012 2014 2016 2018 2020 2022 2024

AEMO (2014)

Core Energy (2013)

EnergyQuest (2013)

Macq

PJ

2018 Demand

forecasts have

shrunk from

2,900PJ to 2,050PJ –

the difference could

support three trains

Rather lock in

higher prices long-

term many buyers

have entered

transitional 2-3 year

contracts


15 April 2015 15

In its submission to the Federal Government’s Energy Green Paper, the Australian

Aluminium Council suggests that energy represents 20-30% of the operating cost base

for alumina refineries, with a A$4-6/GJ increase translating to an additional A$600-

900m in costs.

In its submission to the NSW inquiry into gas and liquids fuels supply, CSR suggested

it is “expecting gas commodity prices will increase by 79% over three years in New

South Wales”. Furthermore “until the dramatic fall in oil prices very recently, there has

been little interest from suppliers in engaging in even preliminary discussions for

supply of gas beyond 2015”. CSR closed its Ingleburn float glass factory in 2013,

partly on a gas price arbitrage with Victoria. The shortfall from the lost production was

made up from increased production in Victoria and overseas.

In its submission to the Energy Green Paper, Orora recommended that the ACCC

revoke approval of joint gas marketing arrangements to encourage competition

between gas producers. It suggested that having a functioning gas market would allow

the smaller producers to sell their gas directly into the spot market without the burden

of a gas marketing team. This has more recently been supported by Manufacturing

Australia.

One smaller <10PJ/a buyer we spoke to suggested that, while it had historically had

been willing to pay a margin to a larger retailer for A$3-4/GJ gas, a doubling of prices

has prompted them to engage with smaller upstream producers and also participate

more actively on the STTM in Sydney. In this regard, they were supportive of Moomba

Trading Hub. Indeed buyers are willing to accept the volatility of a spot market when

the alternative is a high and opaque pricing structure.

A recent report by Deloitte Access Economics (supported by a number of energy user

associations) revealed the potential for severe side effects resulting from gas supply

tightness and cost increases. The report projects A$118bn in lost output by 2021 to

the Australian manufacturing sector alone, based on current gas price projections

among other factors.

In its business prospects for 2015 survey, Australian Industry Group (AIG) highlighted

that of the 235 CEOs from manufacturing companies that responded, 28% anticipate

energy prices will rise while 40% anticipate stable pricing. In a more detailed energy

survey in 2013, AIG found that price offered by suppliers to survey participants for new

longer-term contracts (>2 years) ranged between A$4.60 - 11.00/GJ with an average

of A$8.72/GJ. It also found that 30% of respondents were seeking supply contracts

with terms of less than four years.

A survey undertaken by Marsden Jacob Associates (on behalf of the Energy Users

Association) of large industrial users representing ~60PJ/a or 24% of total East Coast

industry demand highlighted that a move from A$5/GJ to A$10/GJ gas prices could

see, in aggregate, a~15-20PJ reduction in gas demand, a ~1,350 reduction in

employment and a ~A$1bn impact on domestic sales.


15 April 2015 16

Fig 19 Indentified annual gas consumption from domestic uses, PJ per annum

Fig 20 Cumulative impacts of current gas price projections on selected industries from 2014-21 – Deloitte estimates this could total U$58bn in present value terms

Source: Company sources, Macquarie Research, April 2015 Source: Deloitte Access Economics, Macquarie Research, April 2015

Industrial buyers still holding out on re-contracting, while retailers over contracted

While the cliff in contracted gas capacity post 2017 was fast approaching, the willingness of

select buyers to sign short-term transition agreements and retailers (namely AGL & Origin)

negotiating further supply agreements from Bass Strait has temporarily deferred the

pressures of near-term recontracting. However even accounting for the local demand

destruction anticipated, we forecast uncontracted demand will again grow to >300TJ/d by

2025. Apart from the gas supply options announced by Strike Energy, additional contract

announcements in 2014 were limited to the Westside/GLNG supply agreement, with little

recontracting undertaken by domestic end-users market.

Excluding LNG contracts, we estimate that ~940PJ of firm domestic volumes have

been recontracted, with a further ~300PJ of more speculative supply agreed upon. The

firm supply equates to ~420TJ/d of volume, which represents 27% of forecast

domestic demand in 2016. However, with 769PJ of this contracted to retailers (ORG &

AGL), some of these volumes could be diverted to LNG. Furthermore a number of

buyers have struck transitional agreements, which will see uncontracted volumes

again grow from 2020.

While buyers are waiting to recontract gas until the very last moment, the volume of

uncommitted 2P reserves in Eastern Australia appears sufficient to cover uncontracted

domestic demand for a further 16 years. While buyers have had to compete with LNG

projects (which appear willing to pay oil linkage), with sufficient volumes for initial

ramp-up and until debottlenecking is pursued, competition for this uncontracted

volume could prove less intensive.

CSR, 4.8Australia

Paper, 7.5

Orica, 18.0

Incitec Pivot, 27.3

Brickworks, 2.6Orora, 3.5

Rio Alcan, 28.0

Adelaide Brighton, 8.4

Goldman Fielder, 0.4

GB Galvanizin,

0.05

Xstrata (Mt Isa), 13.1

Boral, 4.0

Qenos, 8

-2,000

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

NSW VIC QLD SACumulative impacts (A$m)

While the gap

between demand on

contracted volumes

has closed, this has

been driven by

intermediaries

rather than end

users


15 April 2015 17

Fig 21 Domestic buyers are waiting until the last possible moment to renew gas sales agreements (update)...

Fig 22 With uncommitted 2P reserves >7,000PJ this is sufficient to cover uncontracted domestic demand for a further 16 years alone

Source: Core Energy, BPT, Macquarie Research, April 2015 Source: STO, Macquarie Research, April 2015

Against the backdrop of growing uncertainty, buyers have been waiting until the last

possible moment to sign contracts. Based on recent contract announcements, we

estimate that domestic buyers left only a ~11 month lead time to secure new supply

before old contracts expired (in the past, contracts have been negotiated at least 15-

24 months ahead of delivery). This compares to LNG buyers (which arguably require

greater visibility), which have typically contracted third-party supplies on average ~ 4

years in advance.

Over the last 3 years the contract terms domestic buyers are willing to commit to have

collapsed significantly. Indeed Orica, Lumo and Incitec Pivot have signed contracts

spanning merely 3 years. With its gas contract expiring in Dec-15, Boral (which

consumes ~4PJ in Eastern Australia) suggested that it would only sign a 2 year

contract for new supply. In its 2013 survey AIG reported that 56% of respondents were

seeking supply contracts with terms of less than 4 years. While we believe that the

price paid for such short-term supply remains high, buyers appear willing to wear this

cost on a temporary basis rather than locking into a longer-term deal at a higher price

and permanently increasing their cost structure. Short-term supply seemingly also

buys time as other substitutes or riskier, longer-dated supply options are explored.

Fig 23 Under any of the possible pricing approaches (LNG net-back, marginal cost or coal plus a carbon price) domestic East Coast gas prices look set to rise

Fig 24 ...However buyers are committing to shorter-term contracts over this transition period

Source: Company data, Macquarie Research, April 2015 Source: Company data, Macquarie Research, April 2015

0

100

200

300

400

500

600

700

800

20

12

20

13

20

14

20

15

20

16

20

17

20

18

20

19

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

20

31

20

32

Own UseCooperQLD CSGOtwayGippslandNew end user (post 2013)New portfolio (post 2013)

PJ Possible portfolio gas re-directed

to LNG

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

SA NSW QLD VIC

uncommitted 2P reserves uncommitted 2C reservesPJ

APLNG / QCLNG

STO / GLNG

ORG / GLNG

WCL / GLNG

AGL / QCLNG

AGL / Xstrata

STO / unidentified

ORG / MMG

BPT / ORG

Esso/BHPB / ORG

Esso/BHPB / Orica

AGK / IPL

Strike options4.0

5.0

6.0

7.0

8.0

9.0

10.0

Jul-09 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15

A$/GJExport contracts Domestic contracts Gas options

0

5

10

15

20

25

Jul-09 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15

yrs Domestic contracts Export contracts Gas options

Faced with tough

decisions, buyers

are leaving

recontracting to the

very last instance –

an average 11

months prior to

expiry


15 April 2015 18

Electricity prices following gas prices

The depressed gas pricing in late 2014 saw a significant ramp-up of gas-fired generation in

Queensland. With the forward electricity market pricing in A$35/MWh for the remainder of

FY15 and A$47/MWh in FY16 and assuming an average heating rate of ~8.00GJ/MWh, this

equates to an incentive price of A$4.40-5.90/GJ. Similarly, a gas price beyond A$8/GJ

(representing marginal cost of existing gas capacity delivered into Wallumbilla) could see

~189PJ of gas drawn from the intermediate gas-fired power stations across the NEM.

In its April 2015 report, AEMO is now forecasting total East Coast gas demand from

gas-powered generation will fall from ~200PJ in 2014 to merely ~80PJ by 2019, due to

rising gas prices and a new renewable generation, with only modest subsequent

growth out to 2034. This decline is predominately driven by uncompetitive Queensland

gas generators and the closure of Torrens Island, SA in 2017.

In a recent study into NSW gas supply (Solving for x – the NSW supply cliff), AGL

assumed gas-fired electricity generation would fall by 41% in 2015, followed by a 12%

fall in 2016, and a further 20% contraction in 2017 due to substitution effects (largely to

coal-fired power generation). “By 2018, [AGL] forecast that gas used in power stations

will contract to just 70.8 PJ/a, representing only 9.8% of domestic demand during the

winter peak, and less than 3% of total system demand” (down from 242PJ/a

representing 31% of demand in 2012).

Unless forward electricity pricing recovers from ~A$45-50/MWh currently to ~A$65-

75/MWh (which seems unlikely at this stage), intermediate gas-fired generation is

quickly going to get priced out of gas markets. Indeed if our East Coast gas price

scenario of ~A$8/GJ is proven true, we believe this will quickly see gas drawn away

from intermediate power with a marginal cost of A$64/MWh. We estimate this could

release up to 189PJ/a or ~500TJ/d of supply – enough to supply almost one LNG train

alone.

Fig 25 Queensland electricity futures are largely set by gas pricing – suggesting that prices will remain below A$5.0/GJ and A$5.4/GJ in FY16 and FY17, respectively

Fig 26 The SRMC vs incentive gas price – A$9/GJ gas prices mean many intermediate gas-fired plants do not make a margin

Source: Macquarie Research, April 2015 Source: Macquarie Research, April 2015

Near-term LNG shortfall seemingly overplayed

Much has been made of the perceived shortfall that Gladstone LNG projects have to meet

minimum contractual obligations. However a greater appreciation of the slower ramp-up to

plateau production, an acceleration of drilling activity over recent years to take it off the critical

path (after wet weather conditions early in the construction period) and a focus by operators

on core fields with the greatest deliverability and with over 2,200PJ of contracted third-party

supply seemingly leaves these projects well supplied in the short-term.

3.00

3.50

4.00

4.50

5.00

5.50

6.00

Dec

-12

Mar-

13

Ju

n-1

3

Sep

-13

Dec

-13

Ma

r-14

Ju

n-1

4

Sep

-14

De

c-1

4

Ma

r-15

A$/GJ assuming a

9.25GJ/MWh

heat rate

FY15 FY16 FY17 FY18

0

20

40

60

80

100

120

140

160

180

Co

nd

am

ine

Sw

anb

an

k E

Da

rlin

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irn

sd

ale

Oa

ke

y

Ba

rca

ldin

e

La

ve

rto

n N

ort

h

Ro

ma

Ura

nq

uin

ty

Co

long

ra

Va

lley P

ow

er

Je

era

lan

g A

Min

taro

SRMC (A$/MWh)

A$9/GJ gas

A$6/GJ gas

A$3/GJ gas

A gas price of

A$8/GJ could see

~189PJ of gas

drawn from

intermediate gas-

fired power stations

We believe

consensus

estimates for LNG

ramp-up appears to

aggressive


15 April 2015 19

Fig 27 There appears to be sufficient deliverability from CSG fields and existing third-party supply agreements in place for LNG operators to successful navigate the ramp-up

Registered Capacity

Planned com-

pression

Wells drilled

Wells connected

Targeted deliver-

ability

Current production

Initial third-party gas

Storage Late 2015 req.

Plateau req.

TJ/d TJ/d # # TJ/d TJ/d TJ/d TJ/d TJ/d TJ/d QCLNG 2,024 2,024 2,350 1,600 N/A 696 190 5 1,050 1,400 GLNG 165 725 735 358 600 ~35 470-590 75 108 1,200 APLNG 1,065 1,900 1,357 666 900 ~155 0 0 750 1,500

Source: Macquarie Research, April 2015

The ramp-up profile of LNG projects will likely prove slower than original expectations.

STO continues to anticipate first LNG at GLNG in 2H15 with a 3-6 months ramp-up for

train 1 and a slower 2-3 year ramp-up for train 2 from 2015 year-end. Meanwhile BG

anticipates a ramp-up of train 1 to full capacity by mid-2015 with the 2nd

train online in

3Q14 and a plateau production of 8mtpa delivered by mid-2016. APLNG anticipates

first LNG by mid 2015 with plateau production from both trains not expected until mid-

2016.

Given significant sunk capex, in downstream infrastructure and the already marginal

returns on offer, one would think that LNG operators would take advantage of spare

uncontracted capacity during the ramp-up phase to maximise returns. However, apart

from commissioning cargoes, no project is pointing to significant spot deliveries during

this ramp-up. This is partly driven by the narrowing spread between LNG spot price

netback and East Coast prices. However we suspect the local producers (namely STO

and ORG) are reluctant to further tighten the domestic market against a backdrop of

growing political and industry opposition and LNG participants with larger portfolios

(namely BG and TOTAL) are reluctant to flood an already weak spot LNG market with

further unnecessary supply.

Operators continue to point to growing confidence surrounding initial upstream

deliverability. STO has highlighted that it anticipates deliverability across Fairview to

improve from 500TJ/d at the end of 2014 to 600TJ/d by the end of 2015 (based on

2TJ/d average deliverability from Fairview wells this would suggest that merely 50

wells will need to be connected in 2015). At QCLNG, the Jordon and Woleebee Creek

central processing plants were both commissioned in March, in advance of train 2

start-up. With QGC processing facilities producing at an average gross rate of

~650TJ/d and the ORG supply agreement adding a further 190TJ/d in initial years,

QCLNG seemingly appears adequately supplied for train 1 ramp-up.

Fig 28 While both QCLNG and APLNG central processing facilities have commenced a ramp up of production it is notable that Fairview production is yet to grow

Fig 29 Based on stated LNG ramp-up profiles consensus demand still looks too high

Source: NGBB, Macquarie Research, April 2015 Source: Company Data, Macquarie Research, April 2015

0

100

200

300

400

500

600

700

800

De

c 1

1

Feb 1

2

Apr

12

Jun 1

2

Aug 1

2

Oc

t 12

Dec

12

Feb 1

3

Ap

r 1

3

Jun 1

3

Aug 1

3

Oc

t 13

De

c 1

3

Feb 1

4

Apr

14

Jun 1

4

Aug 1

4

Oc

t 14

Dec

14

Feb 1

5

GLNG QCLNG APLNGProduction(TJ/d)

500

700

900

1,100

1,300

1,500

1,700

1,900

2,100

2,300

2,500

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

AEMO (2014)

Core Energy (2013)

EnergyQuest (2013)

Macq

Demand (PJ)


15 April 2015 20

Supply shortfall dictated by price The East Coast of Australia has ~155,000PJ of known recoverable gas reserves and

contingent resources with a further ~300,000PJs of estimated yet-to-be-discovered

prospective resources. All up, this resource position would be sufficient to meet current east

coast gas demand for over 680 years. Indeed, even including the incremental demand

generated from 7 LNG trains (including an expansion train at QCLNG), this still equates to a

healthy reserve and resource life of over 60 years. Furthermore, if prospective shale and tight

gas resources are included, this reserve coverage could grow to ~200 years.

A longer-term move to marginal costs appears assured against the backdrop of abundant

East Coast gas resources. While this requires incentive pricing, even at depressed spot LNG

net-back we believe this at least unlocks enough gas for 20 years of domestic demand and

supply for existing LNG projects & debottlenecking and as much as 80,000-160,000PJ of

resource based on various cost curves.

Fig 30 If the price is right and unconventional resources are proved up, East Australian gas resources could cover combined local and export demand for up to 170 years

Volumes (PJs)

Domestic reserve life (yrs)

Export reserve life (yrs)

Combined reserve life (yrs)

2P 50,746 76 30 22

2C 103,329 155 62 44

Known reserves & resources 154,075 231 93 66

Prospective (Tight Gas) 22,052 33 13 9

Prospective (Shale Gas) 88,377 133 53 38

Prospective (conv. & CSG) 193,751 291 116 83

Total 458,255 688 275 197

Source: Queensland Govt., Geoscience Australia, Core Energy, Macquarie Research, April 2015

It is clear therefore that the East Coast is not short of gas but instead, according to

various independent cost curve estimates, merely short of gas that can be produced at

legacy gas prices. While the industry’s focus on longer-dated unconventional and

marginal CSG resources has cooled in recent months, initial programs have confirmed

resource is in place and can be recovered to surface. While limited activity in the near-

term could constrain the pace at which this resource is unlocked, cost deflation could

ultimately see the curve flatten in coming years. As a result, if East Coast prices do

remain persistently high, we would anticipate a significant medium-term supply

response, which is likely to limit the longevity of any price strength.

Even at the current spot LNG price net-back, we estimate this unlocks between 50,000

to 100,000PJ of resource – sufficient to meet the ~46,000PJ required to support

domestic demand and six LNG trains (including 10% debottlenecking). Moving to our

LT assumptions (U$78/bbl oil and 0.82 fx) sees the potential commercial volumes rise

to >80,000PJ. Alternatively, a gas price of merely A$4-7/GJ would be required to

unlock sufficient volume for forecast demand over the next 20 years. Consequently,

access to sufficient gas resources longer term does not appear a challenge.

Spot LNG operating

netback incentivises

at least enough gas

for 20 years and

potential as much

as 80,000-160,000PJ

based on various

cost curves


15 April 2015 21

Fig 31 Even at the current spot LNG price netback, we estimate this unlocks between 50,000 to 100,000PJ of resource – sufficient to meet the ~46,000PJ required to support domestic demand and six LNG trains

Source: AEMO, EnergyQuest, IES, Core, SKM Jacobs, Macquarie Research, April 2015

Following Shell’s formal decision to scrap a standalone Arrow LNG development

earlier this year, a potential third-party supply deal has made little progress. While at

the time we suspected the sticking point was price, in hindsight, ongoing due diligence

by Shell on BG’s portfolio could have acted as a handbrake. With ~9,500PJ of

reserves (with ~6,900PJ of this located in the Surat Basin in close proximity to the

QCLNG main pipeline), this is a considerable resource position located in close

proximity to existing infrastructure. Furthermore, with approval to drill 4,000 wells in the

Bowen Basin granted in September 2014 and FEED commenced for pipeline to

Gladstone in December 2014, this appears the most logical near-term supply option.

However recent news of Shell’s offer for BG potentially suggests this gas is destined

for QCLNG. With much of its Surat Basin production already contracted and FEED on

a pipeline connecting the Bowen Basin only commencing late last year, it remains

difficult to see how Arrow gas supply could aid QCLNG’s ramp-up this year and

support both debottlenecking efforts and underpin an expansion train (the site can

support 12mtpa).

Unconventional fading but not forgotten

With initial unconventional work programs in the Cooper Basin having proven that gas flow to

surface, in the current environment activity has been significantly curtailed. While this will

delay appraisal (which will see discovered resource remain largely unchanged) and extend

the timeline to a commercial development (if indeed commerciality can be proven), the vast

unconventional resource in the Cooper will likely keep a lid on prices in the longer-term,

particularly as processing and pipeline constraints are lifted.

Almost A$2bn was anticipated to be spent in the Cooper over a five year period to

FY16, however STO’s recent cuts to capex (trimming unconventional spend by

~A$150m), a revised work program across ATP 940P (with 4 commitment wells

removed from the program) and Chevron’s exit from the NTNG project (which will see

BPT curtail future drilling activity until a new partner can be found) has led to a

considerable reduction in unconventional activity across the Cooper.

We had previously assumed that production could ramp up to 500TJ/d over an 18-year

timeframe (which was seemingly conservative based on the ~9 years it took for

Barnett shale production to reach these levels). However we now conservatively

assume that 100TJ/d is delivered from sweet spots (which equates to merely ~1% total

East Cost supply).

0

2

4

6

8

10

12

14

16

18

20

0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000

Real $15 cost curve (A$/GJ)ACIL Tasman

IES

Energy Quest

Core Energy

SKM

PJ

contract LNG net back based on LT MRE

spot NE Asian LNG net back

contract LNG net back based on LT MRE

20 yrs of domestic EA demand + gas supply for 6 trains

+ 10% de-bottlnecking of 3 projects

While Arrow gas

now looks destined

for QCLNG we don’t

believe this will

tighten gas markets

significantly in the

short/medium-term

While

unconventional

programs have been

curtailed, a large

resource has been

delineated


15 April 2015 22

Fig 32 The cash LNG net-back to the Cooper seemingly prices out a significant portion of unconventional resources

Fig 33 ...This has seen a considerable curtailment of unconventional spending in the Cooper

Source: Company data, Macquarie Research, April 2015 Source: Company data, Macquarie Research, April 2015

While D&M has assessed STO’s net unconventional prospective resources in the

Cooper total ~50tcf on a mid-case basis, we estimate 2C unconventional resources

have fallen from 2,345PJ in 2011 to merely ~930PJ be break-even at gas prices

between A$6-9/GJ. Assuming STO’s U$90/bbl real long-term assumption and 0.80 fx,

we estimate an LNG cash net back to the Cooper Basin of >A$9/GJ, which perhaps

suggests that break-even costs have moved towards the top end of this range.

Fig 34 While unconventional resource potential in the Cooper is large, with limited further activity proposed, the current booked 2C resources would only add a further 3 years of resource life to EA gas markets

Operator Asset Play GIP (bcf)

Prospective (bcf)

Resource target (bcf)

2C Resource (bcf)

STO SACB Uncon. REM/Patchawarra 250,000 50,000 4,459 864 BPT NTNG Project REM/Patchawarra 300,000 45,000 5,343 1,781 BPT/ICN ATP 855P NTNG Project REM/Patchawarra 28,490 4,553 1,518 DLS Central Cooper REM/Patchawarra 48,000 12,000 3,500 na STX PEL 96 Deep Coal 34,000 6,738 400 na SXY Hornet Tight Gas 19,000 5,640 2,374 835 SXY PEL 516/115 REM & Deep Coal 100,000 20,000 1,119 1,119 DLS Western Cooper Deep Coal 63,000 12,500 na na DLS Southern Cooper REM 40,000 20,000 na na

Total 854,000 200,368 21,748 6,117

Cooper resource life 1,114.9 121.0 34.0 EA resource life 95.9 10.4 2.9

Source: Company data, Macquarie Research, April 2015

Retailers have uncontracted gas at Wallumbilla

As noted earlier, it would appear that both Origin and AGL have struck supply contracts with

Esso/BHP to meet loads in the Southern states to free up uncommitted gas supply closer to

Wallumbilla. Furthermore, given an integrated generation portfolio, we believe that ORG in

particular could have surplus gas as intermediate gas-fired generation is turned down.

After announcing a 198PJ, three year supply agreement with Esso/BHPB this month,

AGL highlighted that its gas portfolio now has sufficient Queensland-sourced supplies

to release 30-50 PJ/yr for sale into the Queensland market between FY18 and FY20,

which seemingly extends the ~40PJ/a of surplus at Wallumbilla that we estimate from

FY15 to FY17.

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

$10.0

0

1,0

00

2,0

00

3,0

00

4,0

00

5,0

00

6,0

00

7,0

00

8,0

00

9,0

00

Break-even gas price (A$/GJ)T

igh

t g

as

Infi

ll g

as

De

ep

co

al

Ex

istin

g

2P

Resource (est. existing 2C)- PJ

Cash LNG net-back to Cooper@spot oil and fx

SA

CB

U

nc

on

ve

nti

on

al

NappamerriTrough

We

t g

as

Cash LNG net-back to Cooper@ MRE's LT assumptions

-100

0

100

200

300

400

500

600

FY12a FY13a FY14e FY15e FY16e

BPT STO DLS SXY ORG Chevron BGA$m

Recent contracting

in Victoria and

weaker underlying

demand will deliver

surplus gas at

Wallumbilla


15 April 2015 23

ORG has already built a substantial gas supply base, which includes the 139-173PJ/a

BPT GSA, the 432PJ Esso/BHPB GSA, APLNG domestic gas contracts and equity

gas from the E&P segment. However with the total retail and C&I gas load falling to

108PJ in FY14 from 127PJ in FY13and a possible 35PJ released from intermediate

gas-fired power stations, it would appear ORG has a significant surplus gas position.

The challenge remains that a significant portion of this gas is located in Victoria/NSW

(70PJ/a) and Moomba (30PJ/a), with the residual 66PJ located at Wallumbilla. ORG

has indicated it has 27PJ/a of easternhaul capacity of the SWQP, however much of

this is utilised to supply the GLNG supply agreement. Consequently we estimate a net

position of 57PJ/a in 2018.

CSG-to-LNG reserves shortfall likely to be a longer-term problem

While initial deliverability into LNG projects appears adequate, reserves coverage will

continue to remain a focus for the LNG projects, particularly GLNG where we still estimate a

~1,000PJ shortfall. However this shortfall is likely to be exposed at the tail end of 20-year

contractual obligations, we believe, providing significant lead time for LNG proponents to

explore other supply options that are likely to emerge or utilise previously discussed flexibility.

As has been the case over recent years, APLNG has been endowed with the larger

CSG reserves positions. Despite 2,000PJ of domestic supply and the 640PJ QGC

contract, the project still has ~1,500PJ of surplus coverage.

If its BG offer is successful, completion in early 2016 will see Shell accumulate close to

24,000PJ of total equity resource and third-party gas, providing sufficient resource

coverage for three trains. While Arrow gas appears higher on the cost curve compared

to core QGC fields across the Undulla Nose (which typically have higher peak flow

rates and higher ultimate recovery compared to Arrow’s Surat CSG project area), this

gas could be used to backfill existing contracts.

Perhaps the only project facing resource challenges is GLNG, with a 1,000PJ shortfall

still estimated. However this appears a longer-term problem, which could potentially be

managed through STO extending the Horizon GLNG contract (this could require more

drilling success across the Cooper infill program to ensure reserves coverage),

diverting gas from Gunnedah once development progresses (this would require APA

to commit to a Narrabri to Tamworth pipeline) or possibly for TOTAL to deliver from the

early stage South Georgina play via a the North East Gas Interconnector.

Fig 35 Reserves coverage for the three CSG-to-LNG project – APLNG has sufficient coverage, Arrow gas likely to underpin an expansion at QCLNG while GLNG still appears to have a ~1,000PJ shortfall

Source: Company releases, Qld. Govt, Macquarie Research, April 2015

0

5,000

10,000

15,000

20,000

25,000

30,000

AP

LN

G

sup

ply

AP

LN

G

dem

and

QC

LN

G

sup

ply

QC

LN

G

dem

and

GLN

G

sup

ply

GLN

G

dem

and

1P 2P

2C Third Party

Arrow Existing contracts

Train 1 req. Train 2 req.

Train 3 req. Ramp/Tail

PJ

Longer-term LNG

reserves coverage

appears adequate,

with GLNG shortfall

remaining a long-

term issue


15 April 2015 24

Infrastructure bottlenecks opening up We originally anticipated that increasing contracting by retailers in Victoria (including ORG’s

432PJ, 9 year GSA with Esso/BHPB) was to meet gas demand from Southern states and

release either equity or contracted supply closer to Wallumbilla. Indeed physical

pipeline/specification constraints could have potentially created a disconnect between

southern state gas prices and the premium price at Wallumbilla. However, with pipeline and

processing infrastructure constraints seemingly being resolved, we believe in the long-term

pricing could potentially move to merely reflect transportation differentials.

Gas balances set to change dramatically

With the historic constraints moving gas to Wallumbilla and new supply sources potentially in

the mix we anticipate the gas balances at both Moomba and Wallumbilla are set to change

dramatically over the coming five years. Indeed we anticipate that a swing in supply outside of

CSG fields could be as high as 600-700TJ/d, allowing CSG field production to be dedicated to

LNG export. Meanwhile legacy Cooper Basin production could face significant competition in

coming years from new sources of supply. While the Cooper will always enjoy a

transportation advantage relative to new supply, the risk remains that the ex-field cost

structure of new supply potentially moves lower (whether it be due to lower CO2 handling,

higher liquids, lower drilling costs, etc) vs. an increasingly mature Cooper Basin. Indeed a

vibrant spot market will only make transportation/field costs even more transparent.

Fig 36 Gas movements at the Moomba and Wallumbilla Hubs are set to change dramatically with LNG ramp-up over the next two years and with new supply sources potentially being unlocked by new pipeline infrastructure by 2020

Source: NGBB, Macquarie Research, April 2015

With expressions of interest for a further expansion of the SWQP closing in February,

APA anticipates carrying out front-end engineering and decision work this year, with

the expansion anticipated to be complete by late 2017. We believe this could add a

further 100-150TJ/d to the existing 340TJ/d of capacity.

Much has been made of the GLNG-operated Wallumbilla Gas Treatment Facility.

Indeed we continue to believe that this remains the only facility approved to convert

pipeline spec gas into LNG specification gas. While the initial facility has a capacity of

250TJ/d, it is scalable to 500TJ/d. While this could prove a physical constraint on the

volume of conventional gas used as feedstock (unless an expansion to 500TJ/d is

confirmed, which will see the SWQP again become the bottleneck), retailers could

instead direct this gas to both gas-fired generation and/or C&I/retail load, freeing up

LNG spec gas for export without the need for further treatment (perhaps a luxury not

afforded to upstream producers, which do not have this portfolio flexibility).

Current LNG ramp-up LNG plateau Potential flow

Moomba/Ballera Hub

Avg: 200TJ/dayPeak: 340TJ/day

CGP: ~78TJ/day

Wallumbilla:~211TJ/day

MSP:~215TJ/day

MAPS:~115TJ/day

Upstream production:

~200TJ/day Moomba/Ballera Hub


CGP: ~90TJ/day


MSP:<40TJ/day

MAPS:<50TJ/day


~520TJ/day

Wallumbilla Hub

Industry:~370TJ/day

GPG:~260TJ/day

CSGproduction:

~750TJ/day

Wallumbilla Hub

LNG: ~4,100TJ/day

Industry:~320TJ/day

CSGproduction:

~4,150TJ/day

Moomba/Ballera Hub


CGP: ~0TJ/day

Wallumbilla:~430-470TJ/day

MSP:~60TJ/day

MAPS:<70TJ/day


~320TJ/day

Moomba:~340TJ/day

Moomba:~120TJ/day

Wallumbilla Hub

LNG: ~4,700TJ/day

Industry:~260TJ/day

CSGproduction:

~4,600TJ/day

Moomba:~430-470TJ/day

GPG:~70TJ/day

GPG:~90TJ/day

NT: ~100TJ/day

Moomba/Ballera Hub

Surplus: ~220TJ/d

CGP: ~100TJ/day


MSP:~60TJ/day

MAPS:133TJ/day


~400TJ/day

Wallumbilla Hub Surplus: 20TJ/d

LNG: ~4,700TJ/day

Industry:~260TJ/day

CSGproduction:

~4,600TJ/day

Moomba:~470TJ/day

GPG:~90TJ/day

NT: ~200TJ/day

We believe the

swing at Wallumbilla

could be as large as

600-700TJ/d


15 April 2015 25

MAPS is also investing to allow it backhaul gas from Adelaide to Moomba. The MAPS

pipeline has 241TJ/d of forward capacity, albeit there are some mothballed

compressors. With Adelaide having no natural source of gas the amount of back haul

the MAPS pipeline will be able to deliver is the SEAGas pipeline capacity namely

314TJ/day net of both Adelaide and Penola demand. AEMO estimates this at

~165TJ/day falling to 135TJ/day implying available back haulage of 149TJ/day

growing to 179TJ/day. One caution is whilst these numbers are the average, there is a

strong peak demand for winter gas in both Victoria and SA, which may constrain

backhaul.

Upgrade to Victorian system will likely see more gas move north...

Given infrastructure bottlenecks, the ability to free up gas around the strategic Wallumbilla

Hub has been reserved to those with portfolio positions (i.e. the retailers). We previously

believed that physical pipeline/specification constraints could potentially create a disconnect

between southern state gas prices and the premium price at Wallumbilla. However APA’s

upgrade of the Victoria Transmission System and the NSW-Victoria interconnect would see

more gas flow further north, presenting an opportunity for upstream producers in southern

states to receive LNG net-back pricing.

The A$160m upgraded will see APA increasing NSW-VIC interconnect capacity into

the Culcairn increase to 116TJ/d from 46TJ/d. The investment is underpinned by gas

transportation agreements with ORG, Energy Australia and Lumo Energy for terms of

between 4.5 – 6.0 years.

At the recent 2014 results, STO suggested that Kipper gas find its way to Moomba and

ultimately to Queensland. Production here is anticipated to ramp-up to 75TJ/d by early

2016. Indeed STO could utilise contracted capacity on the SWQP (beyond that

required for Horizon) to deliver this gas to Wallumbilla.

Based upon expectations of SA gas usage MAPS is also expected to export gas to

Moomba. Indeed the MAPS and SEA Gas pipeline are expected to be directly

connected later this year with bi-directional capability on MAPS also anticipated.

...With Narrabri gas more than displacing these lost volumes

Recent press has suggested that APA is in discussions with STO to build a 200km pipeline

connecting Narrabri to Tamworth and its broader NSW network (including the MSP). Recent

commitments by STO to a NSW parliamentary inquiry committee are that gas produced from

its Narrabri project will be made available to the state, which will likely make it politically

difficult to divert gas to Wallumbilla (without moving more gas through the Eastern Gas

Pipeline to displace this lost volume).

While there a number of challenges remaining, STO continues to target an initial 100-

140TJ/d phase -1 development with ramp-up from 2018. Based on the recently

downgraded net reserves of 777PJ, the full-field production rate of 200TJ/d implies a

13 year life.

Northern Territory supply a pipe dream or new competition?

The North East Gas Interconnector is gaining significant traction, with support from the

Federal, NT and NSW governments. After receiving nine initial proposals the Northern

Territory Government narrowed preferred proponents to four (including APA, DUE, Jemina

and Merlin Energy). With final requests for proposals due by September this year, the two

greatest challenges appear to be a competitively delivered gas price and bankable gas

reserves.

The challenges facing competitively delivered gas prices are two-fold: the cost of the

gas ex-field and the tariff charged on the pipeline. If the pipeline is banked on

developed or near-developed conventional resources, ex-fields costs are likely to be

low. However the committed volumes could also be low, which could translate to a

higher tariff. Based on a 200TJ/d, A$700m pipeline underpinned by 15 years of gas

supply with 50% gearing, we estimate a required tariff of ~A$1.6/GJ to return a 9%

equity IRR. Based on these parameters the LNG operating net-back could be as low

as ~A$5.8/GJ (based on Macquarie LT assumptions).

An upgrade to the

VTS will see

physical gas move

North to Sydney and

possibly

Wallumbilla

While still early

days, the North East

Interconnector

could introduce new

supply competition

at Moomba


15 April 2015 26

The NT government estimates that there could be 200tcf of gas resources across six

onshore basins. However exploration across these largely unconventional basins

remains at an early stage, with commercial development likely to be at least 5 years

away. Consequently, while a potential pipeline is likely to accelerate exploration

activity given a new route to market (with a potential pipeline easily expanded via

compression, looping or twinning), it is unlikely to bank the initial development. While

there are an estimated 30tcf of offshore resources in the Bonaparte Basin, Darwin

LNG backfill or expansion is likely to be the preferred route to market for a significant

portion of this gas. The NT government could divert ~175PJ previously earmarked to

supply the Gove refinery from 2016 for 10 years. It could also provide a guarantee on

tail-end supply, buying time to delineate and develop prospective unconventional

resources. Central Petroleum has suggested that 200PJ of gas could be delivered into

the pipeline once operational from the company’s Palm Valley and Dingo fields (Dingo

was recent commissioned at ~2TJ/d and CTP has entered into a HoA to supply up to

15PJ/a of conventional gas to Incitec Pivot).

APA is considering three routes, including a connection of the Amadeus pipeline to the

Carpentaria pipeline or a direct link to Moomba. The first option is likely to prove

cheaper (~A$700-900) but will be constrained by the CGP (119TJ/d capacity) and

Amadeus (104TJ/d capacity) pipelines. A more expensive A$1.3bn pipeline to

Moomba could prove the better long-term option, however APA suggested this could

require government support given the more challenged economics.

Recently modelling from AEMO suggests that any supply from the NT would likely be

constrained by SWQP eastern haul capacity.

Wallumbilla Hub may take some time to improve transparency

Against the backdrop of growing political pressure to improve market transparency, AEMO

established the Wallumbilla Gas Supply Hub in March 2014. While trading activity to the end

of February 2015 was limited, the ultimate aim here would be to replicate the successful

European hubs models where liquidity and therefore price discovery has grown considerably

over recent years. Nonetheless there appears little incentive for producers to participate and,

in light of physical constraints that still need to be ironed out, it could be some time before

liquidity could grow to more meaningful volumes. A second trading hub at Moomba is under

consideration (indeed STO has suggested that it is committed to establishing a gas supply

hub here in 2016).

A successful gas hub typically requires a large number of market participants, transparent

integration between trading and physical markets, little or no little or no commercially material

internal transportation/capacity constraints and the provision of hub services to add to the

convenience to commercial participants.

With only 9 trading participants (with an additional 11 viewing participants) and ~2.9PJ

traded at a price between A$0.18-8.50/GJ since opening, the Wallumbilla trading hub

still remains in its infancy and is providing little spot pricing transparency at this point in

time. We understand the current structure is being refined to consolidate three trading

productions into one common structure.

For those buyers that require gas price transparency on a forward basis to manage

investment decisions, the development of a forward market would also be imperative.

The ASX “think futures are complementary to the spot market” and already offer

Victoria gas futures (albeit with little volume traded). In early April the ASX launched

Wallumbilla monthly and quarterly futures. However, with the spot market yet to

develop, it could be some time before futures liquidity grows.

Physical constraints between RBP, SWQP and QGP have limited traded volumes. An

alleviation of this physical constraint would require further investment regarding

connections (potentially by an external participant such as APA). Given most of the

participants are integrated retailers, the volume has largely been on the Roma to

Brisbane pipeline (which supports gas supply to Darling Downs, Braemar 1&2 and

Swanbank power stations).

With the Wallumbilla

Supply Hub

established in early

2014 and a 2nd hub

proposed at

Moomba by 2016,

this could introduce

significant

transparency


15 April 2015 27

Capacity reservations on the crucial pipelines appear to be under increasing scrutiny.

Of particular focus has been the SWQP pipeline, where STO has disclosed 54PJ/a of

capacity, ORG has indicated it has rights to reverse its western haul volume of 27PJA

and AGL is estimated to have similar capacity. It remains unclear who holds the

residual capacity of 20-30PJ/a.

The European “Oversell/Buyback” or OSBB model has been presented by some in the

industry as an efficient mechanism of utilising spare pipeline capacity and to promote

liquidity at Wallumbilla, whereby excess capacity is auctioned and bought back from

capacity holders. APA has highlighted that it would facilitate capacity trading across its

pipelines through a secondary market for pipeline capacity. Indeed up to 15TJ/d and

5TJ/d has been traded on the RBP and SWQP already. However, on average, merely

1% and 4% of available capacity on the SWQP and RBP pipeline have been offered

respectively, leaving a significant percentage underutilised. The Energy Council will

also submit a rule change proposal to the AEMC in 2015 to enable the trading of

excess pipeline capacity.

Fig 37 The Oversell/Buyback (OSBB) mechanism utilised across European Hubs to manage spare capacity...

Fig 38 ...is yet to fully take effect at the Wallumbilla Hub given finite liquidity and abundant gas supply in close proximity

Source: QGC, Macquarie Research, April 2015 Source: APA, Macquarie Research, April 2015

Both the COAG Energy Council and market participants point to the Continental

European gas hubs as a successful case study. Inclusive of the UK NBP hub, physical

deliveries have grown to represent ~65% of total EU gas demand in 2015. Traded

volume has grown to 1,787bcm in 2013, representing a churn rate of 6x. Nonetheless,

while we anticipate traded liquidity to grow, the finite size of the Australian domestic

market and physical infrastructure constraints will limit the ultimate size of physical

deliveries at the Wallumbilla Hub.

Additionalcapacity

sold

Finalcapacity

sold

buyack

Final capacity

sold

Contracted capacity

Expected primary

utilisation

Actualprimary

utilisation

buyback

Finalprimary

utilisation

Additional capacity

sold

Based on mkt

outcomes, primarycapacityholders

reduced by 10%

Based on outcomes, additionaldemandreduced by 10%

-100%

-80%

-60%

-40%

-20%

0%

20%Pipeline capacity

59%69%

40%26%

1% 4%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

SWQP RBP

Utilised Capacity Spare Capacity Capacity on Offer

Capacity since 1/1/15

A robust capacity

trading mechanism

will be required to

ensure the integrity

of a trading hub


15 April 2015 28

Fig 39 Physical volumes through European gas hubs have grown considerably over recent years...

Fig 40 ...with trading volumes remaining largely consistent at a 6-7 times churn rate

Source: IEA, Macquarie Research, April 2015 Source: IEA, Macquarie Research, April 2015

0%

10%

20%

30%

40%

50%

60%

70%

0

50

100

150

200

250

300

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

NBP ZEE TTF

PSV PEGs BEB/GASPOOL

CEGH NCG % of demand

Physical Volume (bcm) % of EU demand

0.0 x

2.0 x

4.0 x

6.0 x

8.0 x

10.0 x

12.0 x

0

500

1000

1500

2000

2500

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Cont. European Hubs

NBP

Churn

Total Traded Volume (bcm)

Churn


15 April 2015 29

Government playing a more active role In the recently released Energy White Paper, the Federal Government continues to lean

towards market-based outcomes rather than regulation (including domestic reservation).

However it seemingly has taken note of buyers’ frustration regarding perceived near-term

shortfalls and the lack of transparency regarding both available gas supply and pricing

signals. While the possibility of regulation appears slim, greater transparency and oversight is

likely to erode the market power of incumbents (such as STO and ORG) providing greater

market insight to smaller producers and buyers, in our view. Furthermore, with separate

parliamentary inquiries undertaken by the NSW and Victoria governments, the focus on the

industry has never been so acute.

In September 2014, the Federal Government released its long-awaited Energy Green

Paper, which was subsequently followed by the Energy White Paper in April 2015. The

major issues related to gas markets identified included addressing near-term East

Coast gas supply, sustaining longer-term supply, greater pricing transparency and

improved gas market function. The government sees “no short-term fix” to potential

near-term supply shortages other to bring on new supply as quickly as possible

through appropriate, transparent pricing signals and policy. Furthermore the report

notes that reservation policies “will not address current challenges in the market, and

may result in negative long-term outcomes by deferring future investment”.

As mandated in the Energy White Paper, the ACCC has commissioned a 12-month

inquiry to address buyer concerns surrounding market transparency and pricing.

Among other things the inquiry will address the availability & competitiveness of offers

to supply gas, transparency of pricing, market structure, barriers to entry,

anticompetitive behaviour and transaction costs.

In December 2014 the COAG Energy Council released its vision for Australia’s future

gas market to “establishment of a liquid wholesale gas market that provides market

signals for investment and supply, where responses to those signals are facilitated by

a supportive investment and regulatory environment, where trade is focused at a point

that best serves the needs of participants, where an efficient reference price is

established, and producers, consumers and trading markets are connected to

infrastructure that enables participants the opportunity to readily trade between

locations and arbitrage trading opportunities”.

Individual states appear less supportive

With gas resource located in Commonwealth waters not subject to the same “social” scrutiny

as onshore acreage, it is perhaps understandable that state governments, which govern vast

onshore resources (in many instances in close proximity to population centres or strategic

cropping lands), have taken a more direct approach than purely market-based outcomes.

Despite looming contract expiries and warnings by independent experts (including AEMO)

that NSW could face supply shortfalls during peak winter loads, both STO’s Narrabri

development and AGL’s Gloucester project face significant opposition. Both STO’s

A$808m impairment of Gunnedah assets and AGK’s A$343m impairment of

Gloucester/Camden/Hunter in FY13 point to challenges facing NSW CSG assets.

Nonetheless commentary from the inquiry appears contradictory.

While the NSW inquiry rejected a state gas reservation policy, it also argued that the

Minister for Resources and Energy, through the COAG Energy Council, pursue the

implementation of an Australia-wide domestic gas reservation policy.

STO suggests that Narrabri “has the potential to supply up to 200TJ/d, or up to half of

NSW’s natural gas needs” and suggested that gas produced at Narrabri “will be made

available for the NSW market”. Indeed recent press reports have stated that APA is in

talks with STO to build a 200km pipeline from Narrabri to Tamworth, connecting

Narrabri to the Central West Pipeline, the Central Ranges Pipeline and ultimately the

MSP.

The Federal

government

continues to lean

towards market

based outcomes

rather than

domestic

reservations

Little progress in

NSW and VIC after

parliamentary

inquiries


15 April 2015 30

It has been 18 months since the Gas Market Taskforce released its final report and

recommendations. The taskforce recommended that the Victorian government “proactively

support the development of the onshore industry in Victoria to create a safe and efficient

onshore gas industry, underpinned by leading practice regulation and community

engagement” and “remove the holds on the issuing of new exploration licences for coal

seam gas (CSG) and hydraulic fracturing, subject to a package of reforms being adopted,

including leading practice regulation, community engagement, information and science to

underpin the management of the onshore gas industry in Victoria”.

However, after extending the original moratorium on CSG exploration licences and

hydraulic fraccing until July 2015, the ban was extended to all onshore gas

development in May 2014. With the new Labor government commencing a

parliamentary inquiry into Victoria’s unconventional gas industry, it would appear there

is no end in sight to the moratorium.

Growing market transparency

The gas market has traditional relied on confidential long-term bilateral contracts between

buyers and sellers and firm capacity reservations on point-to-point pipeline infrastructure. The

Energy Green Paper suggests that “two-way contracts are typically confidential, complex, and

contain an array of terms and conditions. They have served market participants well in the

past when prices were historically low. In the current rapidly changing market, however, two-

way contracting alone limits the ability of businesses to negotiate confidently on prices and

can mean higher transaction costs”. The Federal government has seemingly taken heed of

buyers concerns surrounding the lack of transparency in East Coast Gas markets, regarding

both price and volume.

The Eastern Australian Domestic Gas Market Study looked at whether there were issues

that could limit market competition and delay an efficient market response to potential

near-term supply shortages. The study found these competition issues were difficult to

assess using available public data. Consequently in the final Energy White Paper, the

Federal Government stated that an ACCC inquiry had been commissioned to address

buyer concerns surrounding market transparency and pricing.

In December 2012, the Standing Council on Energy and Resources (now the COAG

Energy Council) agreed to consider more broadly, in consultation with stakeholders,

whether further policy options could facilitate increased trade in gas transmission pipeline

capacity in the Eastern Australian gas market. Following consultation with stakeholders, in

December 2013, the COAG Energy Council approved a series of measures to improve

transparency:

These included the provision of enhanced capacity trading information for publishing

on the National Gas Bulletin Board (NGBB), improving the functionality and usability of

the NGBB, developing an eastern market capacity listing service and developing and

publishing voluntary standard contractual terms and conditions for eastern gas market

secondary capacity trade. In December 2014, AEMO launched a redevelopment of

NBGG including publishing eastern gas market capacity listing information made via

the Gas Supply Hub trading exchange.

In December 2014 the COAG Energy Council released its vision for Australia’s future

gas market for the “establishment of a liquid wholesale gas market that provides

market signals for investment and supply, where responses to those signals are

facilitated by a supportive investment and regulatory environment, where trade is

focused at a point that best serves the needs of participants, where an efficient

reference price is established, and producers, consumers and trading markets are

connected to infrastructure that enables participants the opportunity to readily trade

between locations and arbitrage trading opportunities”.

Government

initiatives to support

market

transparency


15 April 2015 31

Mixed news for the producers... With the short-lived peak in East Coast gas prices now likely to be suppressed by the lower

LNG net-back during the ramp-up of East Coast LNG projects, the potentially near-term

margin expansion on offer for producers appears less obvious compared with our original

expectations. Meanwhile both upstream producers and industry experts alike have

underestimated the elasticity of domestic demand. Furthermore an increasingly transparent

market bears the greatest risk to the incumbents and will quickly expose those with the more

marginal East Coast gas resource.

Fig 41 Valuations of the locally listed players are typically more exposed to rising domestic East Coast prices than to their East Coast LNG developments

% NAV East Coast LNG

% NAV East Coast Domestic

%FY15 Production East Coast Gas

% Reserves East Coast Gas

% East Coast Reserves Uncontracted

STO 46% 21% 34% 62%

ORG 39% 13% 72% 81% 66%*

BPT 0% 71% 50% 66% 54%

AWE* 0% 22% 46% 36% 76%

DLS 0% 37% 13% 66% 0%

SXY 0% 25% 2% 86% 100%

Source: Macquarie Research, April 2015 *Contracted retail volumes treated as uncontracted

While offering sub-economic returns and significantly burdening balance sheets, CSG-to-LNG

projects have accelerated the move up the cost curve. This was always going to have to be

managed carefully to avoid a backlash from buyers and unnecessary attention from policy-

setters – in hindsight it would seem both have come to fruition. For the incumbents, in STO

and ORG, it would appear there are mixed fortunes.

As the incumbent, at face value, STO remains most leveraged to the East Coast gas

market. However a combination of sunk GLNG capex and more marginal Cooper

production sees the portfolio of NAV exposed to East Coast gas prices falling to

merely 21%. Furthermore, faced with a resource shortfall at GLNG and given a

disappointing infill program to date, the Horizon/GLNG contract has soaked up the

majority of remaining conventional Cooper gas reserves. STO’s residual East Coast

gas exposure rests on the politically challenging Narrabri CSG development, early

stage unconventional plays across the Cooper, Amadeus and McArthur Basins’ (which

in some instances could be setting the marginal cost) and uncontracted volumes

offshore Victoria (with Kipper entirely uncontracted and Casino/Henry/Netherby

contracts rolling off from 2017). This has the potential to threaten STO’s incumbent

position in due course.

Recent development

across East Coast

markets poses

greater risks for the

incumbents


15 April 2015 32

Fig 42 While higher gas prices have allow STO to unlock addition volume, we forecast the EABU margin uplift only contributes a <1% of the uplift in group operating EBITDAX

Fig 43 Excluding GLNG, Narrabri and gas committed to the Horizon contract residual EA 2P reserves have now fallen from ~3,000PJ in 2009 to merely 660PJ in 2014

Source: STO, Macquarie Research, April 2015 Source: STO, Macquarie Research, April 2015

Conversely APLNG has more than sufficient resource coverage, ensuring that ORG’s

equity gas (i.e. Ironbark, equity production and portfolio gas) is not needed to

guarantee coverage. Instead ORG can effectively manage its integrated portfolio to

ensure that gas is deployed to the highest margin offering (whether it is LNG feedgas,

the domestic market or electricity generation). That said, given the premium price paid

for Bass Strait supply, ORG is taking a significant bet that LNG projects will be short

gas during the ramp-up (as it would appear other buyer are less willing to pay this

price). If not needed, this gas would have to be contracted into a weakening domestic

market (by which time there could be a well-developed spot market) or through its

intermediate gas generation portfolio (which would deliver little to no margin).

BPT’s willingness not to sign up to STO’s Horizon and instead secure a 139PJ

contract with ORG points to a superior deal (with downside protection and a higher

linkage to oil), which should help protect margins. Furthermore, unlike STO, BPT has

conservatively contracted developed 2P reserves, with a further ~180PJ of

uncontracted, undeveloped 2P reserves and ~400PJ of additional 2C conventional

resources in the Cooper. Finally, recent commentary suggests that BPT is not wedded

to holding on to capital inefficient processing and pipeline infrastructure – with

infrastructure-like assets attracting premium valuations, any monetisation could

crystallise significant value.

Rather it would appear that it is the mid-cap stocks (including SXY, DLS and AWE) that are

set to benefit the most in the current environment. Greater market transparency will move

them closer to an equal footing with the incumbents. Furthermore, a willingness by buyers to

integrate further up the risk spectrum is arguably cutting out the intermediaries and providing

much needed funding and critical mass for development (conversely capital markets look

more challenging in the current environment). Finally, with Moomba seemingly open to third

party gas at current pricing (~A$4-5/GJ), this could present on opportunities for those

companies with lower cost gas resources in the Cooper that are nimble enough.

1941

523

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Higher East Costgas prices have

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contribute more

meaningful ~80% of

the uplift

0

1,000

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4,000

5,000

6,000

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GLNG equity Horizon NSW EA gas2P reserves (PJ)


15 April 2015 33

AUSTRALIA

STO AU Outperform

Price (at 06:59, 14 Apr 2015 GMT) A$7.69

Valuation A$ 12.27 - DCF (WACC 9.0%, beta 1.3, ERP 5.0%, RFR 3.8%)

12-month target A$ 10.00

12-month TSR % +35.0

Volatility Index Medium

GICS sector Energy

Market cap A$m 7,721

30-day avg turnover A$m 41.6

Number shares on issue m 1,004

Investment fundamentals Year end 31 Dec 2014A 2015E 2016E 2017E

Revenue m 4,037.0 3,500.0 4,863.2 5,982.4 EBIT m 845.0 623.5 1,152.8 1,754.7

Reported profit m -935.0 206.6 433.8 927.9 Adjusted profit m 533.0 206.6 433.8 927.9 Gross cashflow m 1,777.0 1,462.6 2,148.8 2,959.1 CFPS ¢ 182.3 147.2 206.9 270.4 CFPS growth % 11.9 -19.2 40.6 30.7 PGCFPS x 4.2 5.2 3.7 2.8 PGCFPS rel x 0.45 0.54 0.45 0.36 EPS adj ¢ 54.7 20.8 41.7 84.8 EPS adj growth % 5.4 -61.9 100.3 103.6 PER adj x 14.1 37.0 18.5 9.1 PER rel x 0.82 2.13 1.19 0.63 Total DPS ¢ 35.0 35.0 42.0 46.2

Total div yield % 4.6 4.6 5.5 6.0

Franking % 100 100 100 100 ROA % 3.9 2.8 5.1 7.8 ROE % 5.4 2.2 4.4 8.9 EV/EBITDA x 7.2 8.2 5.5 4.2 Net debt/equity % 79.4 84.1 74.4 54.6 P/BV x 0.8 0.8 0.8 0.8

STO AU vs ASX 100, & rec history

Note: Recommendation timeline - if not a continuous line, then there was no Macquarie coverage at the time or there was an embargo period.

Source: FactSet, Macquarie Research, April 2015

(all figures in AUD unless noted)

Macquarie Securities (Australia) Limited

Santos

Incumbent position threatened on multiple fronts

Trying to protect market share…: While STO has enjoyed ~20% share of the

east coast gas market over recent years, after having to divert Cooper equity gas

to support GLNG train 2 coverage and with the infill program delivering only a

fraction of the 1,000PJ of reserves additions originally targeted, STO’s

incumbent position is likely to be tested in coming years. Furthermore, with net

back prices to the Cooper likely to remain below the threshold to support

development of equity gas it is perhaps unsurprising that Moomba is “open for

business” for third-party gas. Indeed it would appear STO is growing increasingly

desperate for third-party gas to preserve market share but also underpin the

significant investment in the Cooper Infrastructure Expansion Project.

…shrinking reserves base not being supplemented by resource

conversion: Excluding Narrabri reserves and gas relating to GLNG (including

the 750PJ Horizon contract), East Coast 2P gas reserves have fallen from

>3,000PJ in 2009 to merely 660PJ in 2010, equating to a remaining reserves life

of merely ~6 years. Furthermore unconventional Cooper Basin resources have

been downgraded from 2,345PJ in 2011 to merely 930PJ last year (despite an

original 2015 target of ~4,800PJ) with a move to develop this high cost resource

unlikely in the . While STO has reported ~4,800PJ of 2C gas resources

(excluding GLNG), it remains unclear where this sites of the EA cost curve or

whether STO can promote this to reserves in a timely manner.

Any move to spot pricing likely to erode pricing power: While STO has had

to wear low gas prices for a number of years, as the incumbent with significant

market share, the transition through LNG ramp-up potentially offered means to

become a price-setter. However, with buyers’ increasingly frustrated with the

lack of pricing transparency and the government increasingly taking note, the

introduction of a spot market at Wallumbilla in 2014 (and Moomba as early as

2016) could ultimately see the veil lifted on pricing, which will accelerate the

move to marginal cost (which could erode margins for all) and also potentially

provide the pricing visibility needed to smaller producers to bypass STO as an

intermediary when developing independent resources in the Coopers.

A significant infrastructural footprint: As well as having the largest, STO also

has one of the most accessible resource positions on the east coast close to

both infrastructure and customers. This advantaged position is largely a function

of STO’s operatorship of key infrastructure at Moomba, Ballera, GLNG and soon

to be Wallumbilla, all of which is supported by contracted pipeline capacity.

However, with independents claiming the standalone processing can be installed

at a fraction of the cost implied by STO estimate A$6bn replacement cost for

Moomba, growing traction behind the North East Gas Interconnector, a move to

pipeline capacity trading (which will remove the ability to ‘hoard’ firm capacity)

some of perceived barriers to new entrants are perhaps not as daunting.

GLNG likely to represent the swing demand source: We believe GLNG could

act as a swing producer, given the project remains 600ktpa under contracted

(which equates to ~260TJ/d demand) and with 75TJ/d of injection/withdrawal

capacity at the ~50PJ RUGS facility. STO will not likely want to see a surplus of

gas in the market (particularly if spot volumes grow at Wallumbilla). Furthermore,

in such a scenario, presumably there would be a healthy margin between a

depressed spot price for east coast gas and LNG net-back.

Maintain Outperform rating with a 10% lower A$10/sh target: We believe the

resource shortfall at GLNG, poor results from the Cooper infill program, greater

than anticipated elasticity of domestic demand, a depressed LNG net-back just

as CSG-to-LNG projects are ramping up, the threat of new supply sources from

NT and Victoria and the possibility of a more transparent spot market either have

or will impact on STO’s East Coast gas strategy. Indeed STO’s stranglehold on

East coast markets appears threatened on multiple fronts.


15 April 2015 34

Fig 44 Santos financials


Santos (STO-AU) Share Price: A$7.69

Outperform Shares: 983.8m

Profit & Loss 2H14A 1H15E 2014A 2015E 2016E 2017E Price Assumptions 2H14A 1H15E 2014A 2015E 2016E 2017E

Sales revenue A$m 2,150 1,684 4,037 3,500 4,863 5,982 US$/A$ ¢ 0.85 0.75 0.89 0.71 0.69 0.76

add other income A$m 42 40 81 80 78 79 Domestic gas A$/GJ 3.59 4.00 3.53 4.21 6.91 7.38

Total revenue A$m 2,192 1,724 4,118 3,580 4,941 6,061 Oil-Brent US$/bbl 90.43 53.50 100.08 56.00 67.75 80.75

less operating costs A$m (1,065) (841) (2,029) (1,700) (2,073) (2,275)

EBITDAX A$m 1,127 883 2,089 1,879 2,868 3,786 Production 2H14A 1H15E 2014A 2015E 2016E 2017E

less exploration expensed A$m (154) (98) (256) (175) (245) (245) Natural gas PJ 91.3 96.2 179.3 195.9 233.8 256.6

EBITDA A$m 973 785 1,833 1,704 2,623 3,541 Crude mmbbl 5.0 4.6 9.6 8.6 7.4 6.9

less dep. & amort. A$m (559) (518) (988) (1,081) (1,470) (1,786) Condensate mmbbl 1.8 2.0 3.2 4.1 4.6 4.8

less other non-cash costs A$m - - - - - - LPG k tonnes 79.5 84.6 167.4 176.2 224.2 255.6

EBIT A$m 414 266 845 624 1,153 1,755 LNG k tonnes 572.1 603.8 826.7 1277.6 1784.4 2367.3

less net interest A$m (51) (62) (97) (229) (443) (339) Total production mmboe 29.1 30.2 54.1 61.3 72.3 82.6

Pre-tax operating profit A$m 363 205 748 395 710 1,415 Third party sales mmboe 6.5 7.9 12.5 14.5 12.6 13.5

less tax expense (incl PRRT) A$m (88) (97) (215) (188) (276) (488) Total sales mmboe 34.8 38.0 63.7 75.4 83.5 94.3

Net operating profit A$m 275 108 533 207 434 928

add non-recurring items A$m (1,416) - (1,468) - - -

Reported profit A$m (1,141) 108 (935) 207 434 928

add (goodwill amm - pref div) A$m - - - - - -

Adjusted profit A$m 275 108 533 207 434 928

EPS (Adjusted) Acps 28.1 11.0 54.7 20.8 41.7 84.9

EPS Growth % 6% -61% 5% -62% 100% 104%

DPS (Ordinary & Special) Acps 15 15 35 35 42 46

Franking % 100% 100% 100% 100% 100% 100%

EFPOWA shares on issue m 977 984 975 994 1,037 1,094

Cashflow Analysis 2H14A 1H15E 2014A 2015E 2016E 2017E Reserves 2014A 2015E 2016E 2017E

Cash receipts from operations A$m 4,577 4,476 4,577 3,866 4,606 5,931 Natural gas PJ 6,786 6,590 6,356 6,099

less operating costs A$m (2,371) (2,319) (2,371) (2,135) (1,978) (2,258) Oil mmbbl 62 53 46 39

less gross interest paid A$m (35) (48) (49) (196) (390) (289) Condensate mmbbl 63 59 54 50

less tax paid A$m (28) (39) (164) (82) (113) (179) LPG k tonnes 3,022 2,846 2,622 2,366

Cashflow from operations A$m 1,187 820 1,993 1,454 2,126 3,205 Total 2P reserves mmboe 1,245 1,183 1,111 1,029

less development & exploration A$m (1,862) (1,078) (3,714) (2,065) (1,518) (1,342) Contingent resources mmbbl 1,721 1,721 1,721 1,721

less acq./inv. A$m (26) - (48) - - - Total reserves & resources mmboe 2,966 2,904 2,832 2,750

add divestment A$m 1 - 1 - - -

less dividends paid A$m (115) (148) (196) (298) (415) (481) 2P reserve life years 23.1 19.3 15.4 12.5

add debt movements A$m 1,420 (40) 2,081 - (450) (1,490) EV/ 1P reserves A$/boe 24.16 26.80 30.76 37.01

add equity movements/other A$m 9 148 10 298 415 237 EV / 2P reserves A$/boe 12.08 12.71 13.54 14.62

Net cashflow A$m 316 (289) 127 (612) 158 129 EV / Total resources A$/boe 5.07 5.18 5.31 5.47

add exchange rate adj. A$m 11 - 4 - - - EV/ 1P reserves US$/boe 18.84 20.90 23.99 28.86

Increase in cash A$m 327 (289) 131 (612) 158 129 EV / 2P reserves US$/boe 9.43 9.91 10.56 11.41

Net debt at year end A$m 7,477 7,735 7,477 8,089 7,481 5,862 EV / Total resources US$/boe 3.96 4.04 4.14 4.27

Balance Sheet 2H14A 1H15E 2014A 2015E 2016E 2017E Per Barrel Statistics 2H14A 1H15E 2014A 2015E 2016E 2017E

Cash & cash eq. A$m 775 486 775 163 321 450 Sales revenue / boe US$/boe 73.91 55.68 66.44 40.51 46.27 55.04

Current assets A$m 2,065 1,427 2,065 1,092 1,589 1,856 EBIT / boe US$/boe 14.23 8.81 13.91 7.22 10.97 16.14

Fixed assets A$m 20,280 20,792 20,280 21,190 20,993 20,304 Profit / boe US$/boe 9.45 3.57 8.77 2.39 4.13 8.54

Total assets A$m 22,345 22,218 22,345 22,281 22,582 22,160 Opex/boe US$/boe 16.20 12.23 16.44 11.68 10.45 10.94

Current liabilities A$m 1,946 1,578 1,946 1,458 1,539 2,211 Capex/boe US$/boe 54.26 26.55 61.13 23.91 14.45 12.35

Total liabilities A$m 12,932 12,697 12,932 12,662 12,529 11,423 DDA/boe US$/boe 19.22 16.66 16.26 12.18 13.71 16.17

Shareholder equity A$m 9,413 9,521 9,413 9,620 10,053 10,737 Cash flow/boe US$/boe 40.80 27.12 32.80 16.82 20.23 29.49

Ratio Analysis 2H14A 1H15E 2014A 2015E 2016E 2017E NPV @ WACC of 9.0%

ND/ND+E % 44% 45% 44% 46% 43% 35% Producing assets A$m A$ps %

Interest cover x 5.2 x 2.9 x 2.9 x 1.9 x 3.0 x 6.1 x Cooper Basin Area 1,798 1.82

Dividend payout ratio % 53% 137% -37% 168% 101% 54% Onshore Queensland CSG Assets 80 0.08

ROA % 2% 1% 4% 3% 5% 8% Otway Gas 298 0.30

ROE % 3% 1% 5% 2% 4% 9% WA Gas 1,480 1.50

ROIC % 1% 0% 4% 2% 4% 7% WA Oil 482 0.49

Effective tax rate % 37% 34% 34% 34% 35% 32% South East Asia 1,104 1.12

EBITDA margin % 45% 47% 45% 49% 54% 59% Bayu-Undan 388 0.39

EBIT margin % 19% 16% 21% 18% 24% 29% PNG LNG trains 1 & 2 risked valuation @ 100% 3,036 3.07

Free cash flow A$m (674) (258) (1,720) (612) 608 1,863 Developing assets

Kipper risked valuation @ 100% 646 0.65

Valuation 2H14A 1H15E 2014A 2015E 2016E 2017E Glastone LNG train 1&2 risked valuation @ 100% 4,433 4.48

EV/EBITDAX ratio x 17.7 x 17.0 x 7.2 x 8.0 x 5.2 x 4.0 x Cooper Basin - 2C risked valuation @ 75% 857 0.87

EV/DACF ratio x 19.7 x 20.2 x 8.3 x 9.9 x 6.7 x 4.9 x PNG LNG debottleneck risked valuation @ 75% 314 0.32

P/E ratio x 45.2 x 70.0 x 14.1 x 37.0 x 18.4 x 9.1 x Static assets & exploration

P/CEPS ratio x 25.2 x 20.9 x 4.2 x 5.2 x 3.7 x 2.8 x PNG LNG train 3 risked valuation @ 75% 435 0.44

FCF yield % nmf nmf nmf nmf 7.6% 22.1% Discoveries 801 0.81

Dividend yield % 1.2% 2.0% 4.6% 4.6% 5.5% 6.0% Exploration 973 0.98

Financial assets

Sensitivities (Adjusted Earnings) Valuation 2014A 2015E 2016E 2017E Corporate/tariffs/other 209 0.21

Oil price (+US$1/bbl) A$m 12.45 533 294 499 976 Cash & Investments 775 0.78

delta 0.18 0 87 65 49 Debt (5,970) (6.03)

1.5% 0.0% 42.1% 15.1% 5.2% Risked NPV 12,138 12.27

Currency (+1c) A$m 12.06 533 227 438 915 Shareprice prem/(disc) to NPV -37%

delta (0.21) 0 20 4 (12) - core NPV per share (A$) 10.17

-1.7% 0.0% 9.9% 0.4% -1.2% - risked NPV per share (A$) 12.27

- unrisked NPV per share (A$) 16.34

0

20

40

60

80

100

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Gas Crude Condensate LPG LNGmmboe


15 April 2015 35

AUSTRALIA

ORG AU Neutral

Price (at 07:06, 14 Apr 2015 GMT) A$12.12

Valuation A$ 12.63 - DCF (WACC 10.3%, beta 1.3, ERP 5.0%, RFR 3.8%, TGR 2.0%)


12-month TSR % +7.3

Volatility Index Low

GICS sector Energy




Investment fundamentals Year end 30 Jun 2014A 2015E 2016E 2017E

Revenue m 14,518 14,108 14,344 14,653 EBIT m 1,362 1,317 1,730 2,253

Reported profit m 539 222 672 1,206 Adjusted profit m 722 686 730 1,206 Gross cashflow m 1,560 1,563 1,625 2,093 CFPS ¢ 141.7 141.3 145.8 187.2 CFPS growth % 1.8 -0.3 3.2 28.4 PGCFPS x 8.6 8.6 8.3 6.5 PGCFPS rel x 0.91 0.89 1.02 0.83 EPS adj ¢ 65.6 62.0 65.5 107.9 EPS adj growth % -5.6 -5.5 5.7 64.8 PER adj x 18.5 19.6 18.5 11.2 PER rel x 1.08 1.13 1.20 0.78 Total DPS ¢ 50.0 50.0 50.0 64.8

Total div yield % 4.1 4.1 4.1 5.3

Franking % 0 32 85 100 ROA % 4.5 4.0 4.8 6.3 ROE % 5.4 5.1 5.3 8.6 EV/EBITDA x 12.1 12.1 10.0 9.7 Net debt/equity % 60.4 87.6 91.0 83.7 P/BV x 1.0 1.0 1.0 0.9

ORG AU vs ASX 100, & rec history





Origin Energy

Benefiting from contracting position

Origin is in a strong position within the east coast gas market as a both a

producer and retailer of gas. Origin has ~20-30PJ pa of equity gas along with

~40PJ pa of APLNG purchases which are all mispriced. The other gas

purchases, namely Esso/BHP from 2010 and 2014, Beach from 2015 all reflect

some level of oil price-look through, thus ORG in this case is more of an agent.

Thus leverage to every $1/GJ is ~$49m pa

What makes ORG and AGL unique versus peers like STO and BPT is the

historical contracting position has enabled both parties to have naturally long

positions at Wallumbilla where LNG demand will be centred. The positions

reflect their historical exporting of Qld gas to NSW. AGL’s position is through

historical QGC contacts, ORG via APLNG and ~73TJ/day ie 20% of the SWQP

back haul capacity. As a result ORG has ~70PJ pa of gas at Wallumbilla, of

which 56PJ has been specifically contracted (GLNG). As a result ORG captures

more of the transport savings The residual can be contracted either through

sales to domestic users or the LNG producers. This provides ORG some

flexibility to manage changing demand. Price expectation of $8/GJ is consistent

with our past expectation of central case.

One difference for ORG is it vertical integration into gas fired electricity

generation with large plants in Qld, Victoria and NSW. These plants will

generally become idle and whilst they act as insurance policies, in an electricity

market over supplied, their underperformance has offset a portion of the profit

from the gas sales. The exception is Queensland where market structure is

causing volatility. In 1Q15, the spark spread averaged $11.50/GJ, materially

higher than anticipated East Cost gas price.

ORG has a reasonable pipeline of opportunities with the most significant

Ironbark, which is located near the Condabri. Timing of its development is likely

to be co-ordinated with available capacity at existing gas plants in the region, but

ultimately provides ORG a further 20-40PJ located at Wallumbilla sometime post

2019 with a forward option to deliver this into GLNG. As a partner with SACB JV

ORG can also benefit from expanding Moomba production driven.

As a supplier, user and retailer of gas, ORG equity gas position is less than 50%

of its sales position, thus it can trade its position to take advantage of the

changing markets, but flexing down longer term contracts for short term

volumes. Recent trading in at Wallumbilla demonstrates this advantage.

Neutral recommendation, $12.50 price target. ORG differs to peers as only

55% of its Enterprise Value is tied to the oil price, with the residual 45% around

energy markets and the price of electricity, RECS and retail demand. Whilst this

diversification should be a benefit Energy Markets challenging outlook, combined

with the need to use proceeds from APLNG start up to retire debt will limit the

cashflow/dividend benefit of the APLNG project to FY17 or FY18.

Surprise catalysts for ORG will be around Energy markets outlook improving.

Whilst retail demand will be soft, higher REC price which is starting to emerge

(leverage ~$24m per $10/REC increase) and higher NSW electricity pricing

(leverage ~$12-13m per $1/MWh) implied in forwards does provides some

upside to expectations.


15 April 2015 36

Fig 45 Origin Energy financials


Origin Energy (ORG-AU)Sensivity switch is OFF Share Price 11.39

Neutral Shares: 1103.6m

Profit & Loss 2013A 2014A 2015E 2016E 2017E 2018E Assumptions 2013A 2014A 2015E 2016E 2017E 2018E

Total Revenue $m 14,619 14,518 14,108 14,344 14,653 15,004 AUD/USD c 1.01 0.92 0.79 0.68 0.72 0.81

less operating costs $m (12,512) (12,453) (12,036) (11,824) (12,064) (12,453) AUD/NZD c 1.24 1.09 1.05 1.03 1.04 1.13

EBITDA $m 2,107 2,082 2,091 2,540 2,608 2,570 Brent oil prices US$/bbl 109.47 109.73 71.67 60.75 76.50 84.76

less dep. & amort. $m (679) (732) (791) (801) (781) (757) East Coast gas price $/GJ 4.51 4.54 5.60 8.00 8.37 7.85

EBIT $m 1,428 1,350 1,300 1,739 1,827 1,813

less net interest expense $m (255) (192) (216) (557) (571) (585) E&P Production 2013A 2014A 2015E 2016E 2017E 2018E

add share in associates (inc. APLNG)$m 10 12 16 (9) 426 477 Natural gas (inc Ethane) PJ 65.0 75.7 62.2 68.7 67.5 66.3

Profit before tax $m 1,183 1,170 1,100 1,173 1,683 1,705 Crude kbbls 551.4 384.0 355.1 354.3 350.3 346.3

less tax expense $m (339) (342) (328) (349) (370) (362) Condensate kbbls 1,496.3 1,828.6 1,593.5 1,379.6 1,377.8 1,352.3

Net profit $m 844 828 772 824 1,312 1,343 LPG kt 114.6 159.4 141.4 138.0 142.2 140.5

less minorities $m (84) (106) (86) (95) (106) (106) APLNG PJe 41.7 46.2 61.1 202.1 295.8 262.8

Adjusted profit $m 760 722 686 730 1,206 1,237 Total production (inc APLNG)PJe 123.7 141.9 141.0 287.1 379.8 345.3

add net abnormals $m (381) (183) (464) (58) - -

add amortisation of goodw ill $m - - - - - - E&P Reserves 2013A 2014A 2015E 2016E 2017E 2018E

Reported profit $m 379 539 222 672 1,206 1,237 2P Reserves PJe 1,183 1,331 1,251 1,166 1,082 999

2P reserves life yrs 14.4 13.9 15.7 13.7 12.9 12.1

EPS (Adjusted) Acps 69.5 65.6 62.0 65.5 107.9 110.6

EPS Growth % -15.7% -5.6% -5.5% 5.7% 64.8% 2.5%

Generation #######

EPS (Reported) c 34.8 49.0 20.0 60.3 107.9 110.6 Retail #######

DPS (Ordinary & Special) Acps 50.0 50.0 50.0 50.0 64.8 66.4 Contact (555.02)

Franking % 50% 0% 32% 85% 100% 100% E&P 884.34

EFPOWA shares on issue m 1,093.8 1,101.0 1,106.6 1,114.0 1,117.9 1,117.9 APLNG #######

Other #REF!

Cash Flow Statement 2013A 2014A 2015E 2016E 2017E 2018E

EBITDA $m 2,107 2,082 2,091 2,540 2,608 2,570

chg working capital $m (199) 162 (232) (237) (126) (130)

Net interest expense $m (436) (442) (551) (742) (703) (717)

Tax payable $m (275) (17) (50) (244) (370) (362)

APLNG $m - - - 76 426 477

Other $m 9 - - - - -

Op cash flow $m 1,206 1,785 1,258 1,393 1,835 1,838

add proceeds from sales $m 141 400 - 165 387 356

add capital raisings/debt draw dow ns$m 7,583 11,096 10,284 1,461 512 678

less debt repaid $m (6,678) (8,997) (6,566) (123) (1,627) (681)

less capital expenditure $m (1,669) (3,710) (4,304) (1,634) (787) (1,044)

less dividends paid $m (535) (634) (665) (683) (751) (902)

add other $m 11 5 11 0 (0) 0

Net cash flow $m 59 (55) 19 580 (432) 245

Cash at Beginning of Period $m 357 307 228 247 827 395

Cash at end of period $m 416 252 247 827 395 640

Balance Sheet 2013A 2014A 2015E 2016E 2017E 2018E

Cash $m 307 228 247 827 395 640

Fixed Assets $m 11,800 11,742 11,952 12,000 12,109 12,498

Exploration Assets $m 864 1,120 1,951 1,951 1,951 1,951

Intangibles $m 741 882 882 882 882 882

Other $m 15,874 17,167 20,070 20,686 20,353 20,048

Total Assets $m 29,586 31,139 35,102 36,346 35,690 36,019 Valuation 2013A 2014A 2015E 2016E 2017E 2018E

Senior Debt $m 5,533 7,779 10,649 11,898 11,682 11,679 EV/EBITDA ratio x 8.9 x 10.1 x 12.0 x 7.7 x 5.9 x 5.9 x

Total Liabilities $m 14,792 16,010 19,840 20,911 19,724 19,642 EV/EBIT ratio x 13.4 x 15.9 x 19.6 x 14.1 x 10.0 x 9.8 x

Total S/Holders Funds $m 14,794 15,129 15,262 15,434 15,965 16,376 P/E ratio x 16.5 x 17.4 x 18.4 x 17.4 x 10.6 x 10.3 x

P/CEPS ratio x 10.4 x 7.0 x 10.0 x 9.1 x 6.9 x 6.9 x

Key Ratios 2013A 2014A 2015E 2016E 2017E 2018E FCF yield x 9.47% 0.97% -20.05% 13.69% 28.67% 25.93%

Net Debt/Equity % 46% 60% 88% 91% 84% 80% Dividend yield x 4.35% 4.39% 4.39% 4.39% 5.68% 5.83%

Net Debt/(Net Debt+Equity) % 32% 38% 47% 48% 46% 44%

Debt Coverage Ratio % 5.3 x 6.3 x 5.0 x 3.1 x 3.1 x 3.0 x

Enterprise Value $m 19,392 21,691 25,997 26,755 26,093 25,844 NPV @ WACC of 8.2% 2013 2014 2015 2016 2017 2017

Effective tax rate % 29% 29% 30% 30% 22% 21% Energy Markets 12,049 12,120 12,536 12,134 11,675 11,172

EBITDA margin % 14.4% 14.3% 14.8% 17.7% 17.8% 17.1% Contract Energy 2,855 2,855 3,043 3,270 3,340 3,471

EBIT margin % 9.8% 9.3% 9.2% 12.1% 12.5% 12.1% Energy Production Development 2,122 2,251 2,787 2,839 3,018 3,503

ROA % 5.1% 4.4% 3.9% 5.2% 7.3% 7.3% Exploration 122 129 884 1,024 1,086 1,136

ROE % 6.4% 6.2% 5.7% 6.0% 9.2% 9.1% Corporate (515) (538) (555) (551) (547) (542)

ROIC % 6.2% 5.8% 4.7% 3.0% 3.3% 3.4% Debt (6,809) (9,134) (13,374) (14,044) (13,359) (13,111)

Free cash f low $m 1,190 120 (2,525) 1,740 3,650 3,302 Sub total 9,824 7,683 5,320 4,671 5,214 5,629

APLNG (37.5%) Gross 5,709 8,852 12,197 14,090 13,265 12,598

Segmental EBITDA 2013A 2014A 2015E 2016E 2017E 2018E Debt (2,162) (3,016) (4,267) (4,629) (3,834) (3,229)

E&P 395 487 387 440 455 425 Sub total 3,548 5,836 7,930 9,460 9,431 9,369

Energy Markets 1,333 1,062 1,203 1,550 1,591 1,612 Origin Total 13,371 13,519 13,251 14,132 14,645 14,998

Contact Energy 435 533 541 582 595 566 per share 12.18 12.25 11.94 12.64 13.10 13.42

APLNG 60 83 99 940 1,825 1,811

Corporate (42) (17) (58) (51) (51) (52) Implied EV/EBITDA

Total EBITDA (inc. associates) 2,181 2,148 2,171 3,461 4,414 4,362 Energy Markets 9.0 11.4 10.4 7.8 7.3 6.9

Underlying EBITDA growth -3.3% -1.5% 1.1% 59.4% 27.5% -1.2% Contact 6.6 5.4 5.6 5.6 5.6 6.1

0%

10%

20%

30%

40%

50%

60%

Jun-11 Jun-12 Jun-13 Jun-14 Jun-15 Jun-16 Jun-17

S&P Ratio

FFO/TD

S&P likely to show short-term leniency; BBB credit rating

(500)

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2014 Dec-14

Jun-15

2015 Dec-15

Jun-16

2016 Dec-16

Jun-17

2017 Dec-17

Jun-18

2018APLNG Maintenance Capex

Energy Markets Contact Energy

A$m Capex profile


15 April 2015 37

AUSTRALIA

BPT AU Neutral

Price (at 07:00, 14 Apr 2015 GMT) A$1.10



12-month TSR % +1.8


GICS sector Energy





Revenue m 1,052.1 719.6 709.0 793.2 EBIT m 376.1 141.1 172.9 231.8

Reported profit m 101.8 -42.8 119.6 158.6 Adjusted profit m 259.2 98.1 119.6 158.6 Gross cashflow m 445.9 317.5 320.1 377.9 CFPS ¢ 35.0 24.5 24.7 29.1 CFPS growth % 63.7 -30.0 0.7 18.1 PGCFPS x 3.1 4.5 4.5 3.8 PGCFPS rel x 0.34 0.46 0.55 0.48 EPS adj ¢ 20.3 7.6 9.2 12.2 EPS adj growth % 81.6 -62.6 21.8 32.6 PER adj x 5.4 14.5 11.9 9.0 PER rel x 0.32 0.84 0.77 0.62 Total DPS ¢ 4.0 3.0 2.0 2.1

Total div yield % 3.6 2.7 1.8 1.9

Franking % 100 100 100 100 ROA % 14.9 5.6 7.1 9.1 ROE % 14.2 5.3 6.4 8.1 EV/EBITDA x 2.3 3.7 3.6 2.9 Net debt/equity % -15.2 -4.7 -3.4 -9.0 P/BV x 0.8 0.8 0.8 0.7

BPT AU vs ASX 100, & rec history





Beach Energy

East coast gas likely to remain pivotal to the new strategy

New strategy unlikely to deviate from East Coast markets: BPT already

enjoys a large exposure to East Coast gas markets (~60% of NAV). Indeed

BPT’s decision not to sign up to STO’s Horizon and instead secure a 139PJ

contract with ORG points a superior deal (with downside protection and a higher

linkage to oil) helping preserve margins if weaker oil prices persist. Furthermore

BPT has conservatively contracted developed 2P reserves, with a further

~180PJ of uncontracted, undeveloped 2P reserves and ~400PJ of additional 2C

resources in the Cooper. With such a large exposure to East Coast gas markets,

this will likely remain core to the new strategy.

With ~A$400m of available liquidity BPT has suggested it would

consider inorganic opportunities that offer value accretive growth. While

BPT would appear the logical consolidator of smaller independents in

the Cooper, with a significant existing position here, the company could

look further afield to other East Coast gas basins.

Could look to crystallise value: In stark contrast to the highly capital efficient

activity in the Western Flank, the Cooper Infrastructure Expansion Project and

SACB/SWQ JV infill drilling program has been a significant burden on BPT over

recent years. Indeed we question what purpose it serves BPT to hold a non-

operated ~20% interest Moomba infrastructure. However under the portfolio

rationalisation program announced last year it would appear no stone is being

left unturned, with BPT recently suggesting that it would consider the

infrastructure tolling and asset monetisation potential for everything through

processing, pipelines to storage facilities.

Re-assessing unconventional: Following Chevron decision not to commit to

Phase 2 of the Nappamerri Trough Gas Project, activity has been significantly

curtailed until prevailing market conditions improve, high graded play types are

confirmed (including Daralingie sands, areas with strong gas shows such as

Keppel-1, areas such as Boston where this is natural fractures and enhance

porosity). Indeed BPT it will be in a position to confirm the scope of work for

Stage 2 by 1HCY16 as which time it will seek a new partner. However, while this

would appear prudent, the lack of activity in the near-term could see the critical

mass built surrounding provision of services partly evaporate, which make it

difficult to quickly pick up activity from the 18 wells drilling during Phase 1.

While D&M has estimated P50 prospectively resources across ATP

855P of 28.5tcf (gross) alone. However with little further drilling

proposed until a new partner can be found, the focus will remain on the

3.3tcf of booked 2C resources (gross) across PRLs 33-49 and ATP

855P.

Maintain a Neutral rating with a 8% lower A$1.10/sh target price: With the

new MD only recently commencing, communication of the new strategy is likely

to be a number of months away. That said it remains clear that East Coast gas

markets more broadly remain core to the new strategy. With a solid balance

sheet, a willingness to consider divestment of infrastructure-like assets (that

could crystallise healthy prices) and an open mind to new opportunities, BPT

could well placed to benefit from the changing East Coast gas market dynamics.


15 April 2015 38

Fig 46 Beach Energy financials


Beach Energy (BPT-AU) Share Price: A$1.10


Profit & Loss 2H14A 1H15E FY14A FY15E FY16E FY17E Price assumptions 2H14A 1H15E FY14A FY15E FY16E FY17E

Sales Revenue A$m 495 427 1,052 720 709 793 US$/A$ ¢ 0.93 0.85 0.95 0.89 0.68 0.72

add other income A$m 9 9 11 25 11 6 Ave. domestic Gas A$/Gj 5.32 5.55 5.41 5.43 3.06 3.25

Total revenue A$m 504 435 1,063 745 720 799 Oil-Brent US$/bbl 109.73 90.43 109.05 100.08 60.75 76.50

less operating costs A$m (246) (217) (496) (384) (347) (348)

EBITDAX A$m 259 219 567 361 373 451 Production 2H14A 1H15E FY14A FY15E FY16E FY17E

less exploration expensed A$m (0) (2) (2) (5) (6) (12) Natural gas PJ 10 12 21 23 28 36

EBITDA A$m 258 217 565 356 367 439 Condensate kkbbls 168 199 392 433 615 765

less dep. & amort. A$m (102) (113) (185) (215) (195) (207) Oil kkbbls 2,571 2,420 5,201 4,605 3,992 3,239

less other non-cash costs A$m (3) - (4) - - - LPG k tonnes 23 24 49 49 64 83

EBIT A$m 154 103 376 141 173 232 Total production kboe 4,649 4,800 9,592 9,420 9,892 10,831

less net interest A$m (6) (10) (13) (10) (0) (2)

Pre-tax operating profit A$m 148 93 363 131 173 230

less tax expense (inc PRRT) A$m (46) (21) (104) (33) (53) (72)


add significant items A$m (160) (152) (157) (141) - -

Reported profit A$m (59) (79) 102 (43) 120 159


EPS (Adjusted) Ac 8.3 5.6 20.3 7.6 9.2 12.2

EPS Growth % -31% -32% 82% -63% 22% 33%

DPS Ac 2.0 1.0 4.0 3.0 3.0 3.2

Franking % 100% 100% 0% 0% 0% 0%

EFPOWA shares on issue m 1,278 1,292 1,285 1,297 1,297 1,297

Cashflow Analysis 2H14A 1H15E FY14A FY15E FY16E FY17E Reserves 2H14A 1H15E FY14A FY15E FY16E FY17E

Cash from operations A$m 597 453 1,102 800 706 790 Natural gas PJ 323.8 300.7 273.1 237.4

less operating costs A$m (275) (250) (495) (433) (346) (347) Liquids mmbbl 29.9 24.5 19.4 14.8

less interest paid A$m (4) (4) (9) (6) (4) (5) Total reserves mmboe 85.6 76.2 66.3 55.5

less tax paid A$m (10) (65) (15) (76) (53) (71)

Gross cashflow from operationsA$m 308 136 583 285 303 366 Reserves / production years 8.9 8.1 6.7 5.1

less expl. & eval. A$m (28) (90) (188) (112) (50) (85) EV / 2P reserves A$/boe 13.4 15.0 17.2 20.6

less acq./inv. A$m (261) (191) (307) (324) (240) (125) EV / 2P reserves US$/boe 11.1 12.4 14.3 17.1

add divestment/other A$m - - - - - -

less dividends A$m (16) (19) (31) (32) (39) (40)

add equity movements/other A$m 5 1 6 11 5 - Per bbl statistics 2H14A 1H15E FY14A FY15E FY16E FY17E

add debt movements A$m - - - - - - Sales Revenue / boe A$/boe 99.22 75.37 104.09 67.98 48.38 52.91

Net cashflow A$m 8 (164) 66 (177) (20) 117 EBIT / boe A$/boe 30.84 18.27 37.21 13.33 11.80 15.46

add exchange rate adj. A$m (1) 1 (2) 1 - - Profit / boe A$/boe 20.27 12.79 25.64 9.26 8.16 10.58

Increase in cash A$m 7 (163) 64 (176) (20) 117 Opex/boe A$/boe 15.26 15.99 16.51 15.53 9.92 9.66

Net debt/(cash) A$m (284) (101) (284) (85) (65) (182) DDA/boe A$/boe 20.10 19.87 18.16 20.10 13.12 13.68

Ratio analysis 2H14A 1H15E FY14A FY15E FY16E FY17E Valuation 2H14A 1H15E FY14A FY15E FY16E FY17E

(ND/ND+E) % -18% -6% -18% -5% -4% -10% EV/EBITDAX x 6.5 x 7.7 x 2.8 x 3.2 x 3.1 x 2.5 x

EBIT Interest cover x 29.2 x 18.3 x 35.3 x 16.9 x 41.0 x 49.5 x P/E Ratio x 19.4 x 24.6 x 7.3 x 16.4 x 11.9 x 9.0 x

Dividend payout ratio % 26% 18% 20% 40% 33% 26% P/CEPS x 10.0 x 9.5 x 4.2 x 5.1 x 4.5 x 3.8 x

ROA % 6% 4% 14% 6% 7% 9% FCF yield % 1.0% nmf 5.2% nmf 1.0% 11.0%

ROE % 5% 4% 14% 5% 6% 8% Dividend Yield % 1.2% 0.7% 2.7% 2.4% 2.7% 2.9%

ROIC % 7% 5% 18% 7% 7% 9% Price to Book x 1.1 x 1.0 x 1.0 x 0.9 x 0.8 x 0.7 x

Effective tax rate % 31% 22% 29% 25% 31% 31%

EBITDA Margin % 52% 51% 54% 49% 52% 55% NPV @ WACC of 9.7%

EBIT Margin % 31% 24% 36% 20% 24% 29% Producing assets A$m A$ps %

Free cash flow A$m 19 (139) 97 (145) 14 156 Cooper, SACB JV - 2P 317 0.24

Cooper, Western Flank Oil 467 0.36

Balance sheet 2H14A 1H15E FY14A FY15E FY16E FY17E Cooper, Wet Gas 194 0.15

Cash A$m 411 249 411 235 215 332 Eqypt, North Shadwan 15 0.01

Current Assets A$m 227 221 227 160 181 195 Developing assets

Fixed Assets A$m 2,017 1,929 2,017 1,996 2,085 2,075 Basker-Manta-Gummy - gas risked valuation @ 10% 3 0.00

Total Assets A$m 2,655 2,398 2,655 2,391 2,481 2,602 Cooper, SACB JV - 2C risked valuation @ 70% 117 0.09

Current Liabilities A$m 401 316 401 125 129 131 Western Flank Oil - 2C risked valuation @ 33% 7 0.01

Total Liabilities A$m 784 615 784 574 579 580 Wet Gas - 2C risked valuation @ 50% 14 0.01

Shareholder equity A$m 1,871 1,783 1,871 1,817 1,903 2,022 Static assets & exploration

Cooper (Unconventional) 86 0.07

Sensitivities (Adjusted earnings) NPV FY14A FY15E FY16E FY17E Exploration 116 0.09

Oil price (+US$1/bbl) A$m 1.12 259 100 128 164 Financial assets

delta 3% - 2 8 5 Cash 249 0.19

2.9% 0.0% 1.9% 6.6% 3.4% Debt (150) (0.12)

Currency (+1c) A$m 1.08 259 98 119 155 Carbon - -

delta 0% - (0) (1) (4) Equity investments 38 0.03

-0.4% 0.0% -0.1% -1.0% -3.2% Corp. overhead (120) (0.09)

Third Party Volumes 60 0.05

Risked NPV 1,413 1.08

Shareprice prem/(disc) to NPV 1%

- core NPV per share (A$) 0.91

- risked NPV per share (A$) 1.08


-

2.0

4.0

6.0

8.0

10.0

12.0

FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19 FY20

Gas Crude Condensate LPG

kboe


15 April 2015 39

AUSTRALIA

AWE AU Outperform

Price (at 07:01, 14 Apr 2015 GMT) A$1.10





GICS sector Energy

Market cap A$m 578


Number shares on issue m 525.9


Revenue m 328.3 286.4 367.5 419.3 EBIT m 34.7 -21.0 22.3 78.4

Reported profit m 62.5 -80.6 -0.7 35.6 Adjusted profit m 7.0 -32.9 -0.7 35.6 Gross cashflow m 171.2 120.5 164.0 192.2 CFPS ¢ 32.8 23.0 31.2 36.6 CFPS growth % 32.2 -30.0 35.8 17.2 PGCFPS x 3.4 4.8 3.5 3.0 PGCFPS rel x 0.35 0.51 0.44 0.41 EPS adj ¢ 1.3 -6.3 -0.1 6.8 EPS adj growth % -58.5 nmf 97.9 nmf PER adj x 81.9 nmf nmf 16.2 PER rel x 4.75 nmf nmf 1.41 Total DPS ¢ 0.0 0.0 0.0 0.0

Total div yield % 0.0 0.0 0.0 0.0

ROA % 2.9 -1.7 1.7 5.9 ROE % 0.8 -3.5 -0.1 3.7 EV/EBITDA x 2.8 4.3 3.0 2.4 Net debt/equity % -4.5 10.3 10.9 3.5 P/BV x 0.6 0.6 0.6 0.6

AWE AU vs Small Ordinaries, & rec history





AWE

Perth Basin likely to overshadow east coast exposure

Large East Coast portfolio, but long-dated exposure: AWE has considerable

uncontracted gas reserves and resources located close to existing infrastructure,

offshore Victoria. With the two-development drilling program underway at

BassGas, AWE anticipates the installation of the compression module by mid-

year will see capacity increase by ~30% to 67TJ/d (constrained by the onshore

Lang Lang plant).

AWE has contingent gas resources relating to these assets of ~125PJ,

which is almost equivalent to its current East Coast gas 2P reserves base

of ~134PJ. While these relate to near existing discoveries at Trefoil,

Rockhopper and White Ibis, the commerciality of these resources remain

unknown. While higher gas prices could unlock these resources in the

fullness of time, they are likely to be lower margin reserves additions.

Nonetheless the JV could look to tie-back these fields to the Yolla Hub as

backfill.

Separately with two-thirds of existing Australian gas reserves

uncontracted (the majority in Victoria), this implies a further ~80PJ of

uncontracted gas that is already commercial at current prices. Indeed

AWE’s uncontracted position is only expected to grow from 5TJ/day in

2016 to ~40TJ/day in 2019. AWE anticipates that recontracting of both

BassGas and Otway could commence within the next two years.

Furthermore, given a seller’s market and ORG’s Esso/BHPB contract

(which extends to 2023), AWE could potentially separately market this

gas. At the Otway project, STO continues to examine the next phase of

development beyond 2017 (although the reserves potential here looks

relatively smaller vs. BassGass).

Exposure to WA gas prices likely to be more meaningful: With the Irwin-1

exploration well drilling ahead and further two appraisal wells planned at the

Waitsia field, results here are likely to prove more material to the AWE

investment case. Three wells (Senecio-3 and Waitsia 1&2) will be initially tied

into the existing Dongara Plant via low-cost flow lines to deliver early production.

However, a wider development would likely require 15-20 development wells and

an expansion of gas processing (although the low impurities could keep required

processing to a minimum). Tighter intervals across the shallower

Dongara/Wagina sands and HCSS will likely be developed at a later stage.

While we do not foresee any challenges on the marketing front (given the

proximity of the resource to SWIS demand centres), with STO announcing a

45TJ/d contract with Alcoa from its John Brookes Field, the second 150TJ/d

domgas tranche from Gorgon still uncontracted and a further 200TJ/d of

Wheatstone capacity from 2018, there is significant supply-side competition in

the medium term.

Maintain an Outperform rating and a 13% lower A$2.00/sh target: With the

share price trading at a 14% discount to core NAV of A$1.48/sh, AWE offers

considerable value. With the problematic BassGas MLE project approaching

completion (which will see a sizable uptick in production), the focus is instead

likely to be on further appraisal of the conventional Waitsia fields in the Perth

Basin, production & reserves growth in the Eagle Ford and the ability to reach its

target of 10mmboe of production in FY18.


15 April 2015 40

Fig 47 AWE financials


Australian Worldwide Exploration (AWE-AU) Share Price: A$1.23



Sales Revenue A$m 161 125 328 286 367 419 US$/A$ ¢ 0.85 0.75 0.92 0.80 0.68 0.72

add other income A$m 0 - 1 0 - - Oil-Brent US$/bbl 48.50 55.50 100.08 56.00 67.75 80.75

Total revenue A$m 162 125 330 287 367 419

less operating costs A$m (81) (72) (129) (153) (179) (183) Production 1H15A 2H15E FY14A FY15E FY16E FY17E

EBITDAX A$m 81 53 201 134 188 237 Natural gas PJ 8 8 19 17 20 21

less exploration expensed A$m (28) (7) (38) (35) (11) (9) LPG k tonnes 16 23 42 39 58 64

EBITDA A$m 53 46 163 99 178 228 Condensate kbbl 438 558 760 996 1,334 1,441

less dep. & amort. A$m (60) (58) (126) (118) (154) (148) Oil kbbl 530 463 1,139 993 1,232 1,005

EBIT A$m (8) (13) 35 (21) 22 78 Total production kboe 2,533 2,671 5,605 5,203 6,602 6,647

less net interest A$m (6) (3) (9) (10) (14) (13)

Pre-tax operating profit A$m (14) (17) 26 (31) 8 65

less tax expense A$m 3 - (6) 3 (2) (20)

less PRRT A$m (3) (2) (13) (5) (6) (10)

Net operating profit A$m (14) (19) 7 (33) (1) 36

Reported profit A$m (62) (19) 63 (81) (1) 36

add significant items A$m (48) - 56 (48) - -

Adjusted profit A$m (13.9) (19.0) 7.0 (32.9) (0.7) 35.6

EPS (Adjusted) Ac -2.7 -3.6 1.3 -6.3 -0.1 6.8

EPS growth % -59% -566% -98% -5231%

DPS Ac - - - - - -

Franking % 100% 100% 0% 0% 0% 0%

EFPOWA shares on issue m 524 526 522 525 526 526

Cashflow Analysis 1H15A 2H15E FY14A FY15E FY16E FY17E Reserves FY14A FY15E FY16E FY17E

Cash from operations A$m 159 126 376 285 368 420 Sales gas PJ 248.0 222.8 190.5 156.7

less operating costs A$m 94 72 176 166 179 183 Oil & condensate mmbbl 8.9 7.9 6.6 5.6

less interest paid A$m 2 3 8 5 12 11 Total reserves mmboe 105.1 99.9 93.3 86.6

less tax paid A$m 0 - (6) 0 (2) (20)

Gross cashflow from operations A$m 59 51 154 110 171 197 Reserves/production years 18.7 19.2 14.1 13.0

less development & exploration A$m (147) (162) (172) (309) (178) (128) EV / 2P reserves A$/boe 6.0 6.3 6.7 7.2

less acq./inv. A$m - - (7) - - - EV / 2P reserves US$/boe 5.0 5.2 5.6 6.0

add divestment/other A$m 64 - 103 64 - -

less dividends A$m - - - - - -

add equity movements/other A$m - - - - - -

add debt movements A$m 123 60 (78) 183 10 -

Net cashflow A$m 32 (51) 0 (19) 4 13

add exchange rate adj. A$m 1 - 1 1 - -

Increase in cash A$m 33 (51) 1 (18) 4 13

Net debt at year end A$m (15) 96 (42) 96 102 34

Balance sheet 1H15A 2H15E ` FY15E FY16E FY17E Per bbl statistics 1H15A 2H15E FY14A FY15E FY16E FY17E

Cash & cash eq. A$m 75 24 42 24 28 41 Sales Revenue / boe US$/boe 53.98 34.90 54.02 43.83 37.57 45.58

Current assets A$m 156 105 178 105 109 122 EBIT / boe US$/boe (2.58) (3.71) 5.70 (3.21) 2.28 8.52

Fixed assets A$m 1,121 1,215 1,024 1,215 1,225 1,196 Profit / boe US$/boe (4.65) (5.29) 1.15 (5.03) (0.07) 3.87

Total assets A$m 1,277 1,320 1,203 1,320 1,333 1,318 Opex/boe US$/boe 18.77 14.10 17.33 16.32 12.64 12.42

Current liabilities A$m 117 117 122 117 172 157 Capex/boe US$/boe 49.29 45.25 28.26 47.37 18.16 13.95

Total liabilities A$m 327 388 261 388 401 349 DDA/boe US$/boe 20.19 16.26 20.63 18.15 15.76 16.04

Shareholder equity A$m 950 932 941 932 933 970 Cash flow/boe US$/boe 19.69 14.33 25.39 16.86 17.51 21.37

Ratio analysis 1H15A 2H15E FY14A FY15E FY16E FY17E NPV @ WACC of 10.5%

ND/ND+E % (2%) 9% (5%) 9% 10% 3% Producing assets A$m A$ps %

EBIT interest cover x 29.6 x 18.0 x 32.1 x 23.5 x 15.2 x 20.8 x BassGas 206 0.39

Dividend payout ratio % 0% 0% 0% 0% 0% 0% Cliff Head Oil 39 0.07

ROA % -1% -1% 3% -2% 2% 6% Casino 102 0.19

ROE % -1% -2% 1% -4% 0% 4% NZ - Tui oil (+Pateke-4H) 93 0.18

ROIC % -1% -2% 1% -3% 1% 4% Onshore Perth Basin 19 0.04

Effective tax rate % 21% 0% -25% -10% -30% -30% Sugarloaf AMI 330 0.63

EBITDA margin % nmf nmf nmf nmf nmf nmf Developing assets

EBIT margin % (5%) (11%) 11% (7%) 6% 19% Senecio tight gas risked valuation @ 70% 47 0.09

Free cash flow A$m (24) (111) 78 (135) (6) 68 Lengo risked valuation @ 75% 71 0.14

North West Natuna PSC risked valuation @ 75% 157 0.30

Valuation 1H15A 2H15E FY14A FY15E FY16E FY17E Sugarloaf AMI - Austin Chalk risked valuation @ 50% 87 0.17

EV/EBITDAX x 10.5 x 11.8 x 3.8 x 4.7 x 3.3 x 2.7 x Trefoil risked valuation @ 20% 30 0.06

P/E Ratio x nmf nmf 104.4 x nmf nmf 18.2 x Static assets & exploration

P/CEPS x 14.7 x 12.6 x 4.7 x 5.9 x 3.8 x 3.3 x Exploration 102 0.19

FCF yield % nmf nmf 10.7% nmf nmf 10.6% Financial assets

Dividend Yield % 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Cash 75 0.14

Debt (60) (0.11)

Sensitivities (Adjusted earnings) NPV FY14A FY15E FY16E FY17E Corp. overhead (47) (0.09)

Oil price (+US$1/bbl) A$m 2.42 7 -30 6 39 Risked NPV 1,251 2.39

delta 0.03 0 2 7 4 Shareprice prem/(disc) to NPV -49%

% 1.9% 0% 8% 997% 10% - core NPV per share (A$) 1.45

Currency (+1c) A$m 2.42 7 -31 6 39 - risked NPV per share (A$) 2.39

delta 0.03 0 2 6 4 - unrisked NPV per share (A$) 9.02

% 1.1% 0% 5% 915% 11%

.

-

2,000

4,000

6,000

8,000

10,000

12,000

FY02 FY04 FY06 FY08 FY10 FY12 FY14 FY16 FY18 FY20

Gas Crude Condensate LPG

kboe


15 April 2015 41

AUSTRALIA

SXY AU Outperform

Price (at 05:33, 14 Apr 2015 GMT) A$0.32




Volatility Index High

GICS sector Energy

Market cap A$m 368




Revenue m 170.9 124.0 148.8 188.9 EBIT m 50.2 11.2 58.3 89.0

Reported profit m 37.9 -59.8 42.7 63.5 Adjusted profit m 44.7 7.7 42.7 63.5 Gross cashflow m 88.9 53.9 70.9 94.8 CFPS ¢ 7.7 4.7 6.2 8.2 CFPS growth % 15.9 -38.9 31.5 33.6 PGCFPS x 4.2 6.8 5.2 3.9 PGCFPS rel x 0.44 0.72 0.65 0.52 EPS adj ¢ 3.9 0.7 3.7 5.5 EPS adj growth % 2.4 -82.6 452.2 48.9 PER adj x 8.3 47.6 8.6 5.8 PER rel x 0.48 2.79 0.67 0.50 Total DPS ¢ 0.0 0.0 0.0 0.0

Total div yield % 0.0 0.0 0.0 0.0

ROA % 9.5 2.1 10.5 14.4 ROE % 9.7 1.7 9.6 12.7 EV/EBITDA x 3.1 5.1 3.4 2.4 Net debt/equity % -15.9 -16.3 -14.6 -8.7 P/BV x 0.8 0.9 0.8 0.7

SXY AU vs Small Ordinaries, & rec history





Senex Energy

CSG development back on the agenda

Solid CSG resource position the key to meeting long term aspirations:

Following the Surat gas asset swap with QCG SXY’s net 2P CSG position has

grown to 488 PJ from 157PJ. However, with an expected 3 year appraisal

program, a meaningful production uplift resulting from a full field development

would not be realised until the latter end of the decade. That said we estimate a

90-well, full-field development could deliver 50TJ/d of gross production.

Following Shell’s offer for BG Group in early April it appears that Arrow

gas (which has seen both greenfield development plans scrapped and 3rd

party negotiations stall) now seems destined for QCLNG, with the

additional ~10tcf underpinning either debottlenecking activities and/or

further expansion. With GLNG requiring a further ~1,000PJ to satisfy the

back end of its 20 year contractual commitments the Shell/BG tie up likely

sees SXY’s competitive position in the Western Surat basin strengthen.

Indeed, a majority of this acreage lies between GLNG’s Fairview and

Roma and west of APLNG’s Spring Gully with both GLNG’s main pipeline

and the Queensland gas pipeline running directly through the licences.

Thus, optionality remains with the gas either potentially utilised by LNG

proponents or domestic industrial users.

While the program sees SXY’s Surat position transition into the appraisal

phase (potentially leap frogging Hornet gas in the development pecking

order), the initial 3 year work program will focus on pilot production, with

FID expected in 2016 and a wider full field development potentially

delivering ~60TJ/d gross production by 2020. Nevertheless, with GLNG

targeting 600TJ/d of deliverability from Fairview upon start up and with

400TJ/d of 3rd

party contracts already secured (and with only a 2-3 year

ramp up requirement for Train 2), we don’t envisage that additional 3rd

party volumes will be required in the near term, perhaps easing pressure

on SXY’s proposed development timeframe. Indeed, while only

contributing 9% to SXY’s NAV we see Surat CSG contributing a

meaningful ~25% by 2020, offsetting the natural declines of SXY’s

Cooper oil position.

Available Moomba capacity comes at a price: Initial pilot testing of Hornet and

Kingston Rule will be commercialised through a 10mmcf/d, 2-year GSA with the

SACB JV. However, with STO suggested that third party capacity would only be

available if gas prices remain as low as A$5-6/GJ, this leaves little margin for

error surrounding a Hornet development (given an estimated break-even of

~A$5/GJ). Rather the close proximity of the MSP pipeline and modular

processing estimated to cost ~ U$2-3/mmscf/d (which is a fraction of the

replacement cost for the Moomba processing facility) would see SXY access

higher market-based pricing if full-field development progresses.

Maintain an Outperform rating with a 10% lower 45Acps target: Despite

traditionally being focussed on high margin oil potential, targeted production of 3-

5mmboe and 2P reserves of 100-150mmboe by FY18 has seen a greater focus

on gas assets. Indeed the recent West Surat CSG asset swap provides SXY

with a 488PJ 2P reserves position close to existing CSG fields supporting LNG

development.


15 April 2015 42

Fig 48 Senex Energy financials


Senex Energy (SXY-AU) Share Price: A$0.32




add other income A$m 7 9 12 16 21 19 Avg. Domestic Gas A$/GJ 6.31 4.47 5.95 6.31 4.91 6.06

Total revenue A$m 77 63 183 140 170 208 Oil-Brent US$/bbl 100.48 65.30 109.73 71.97 67.75 80.75



less exploration expensed A$m (18) (3) (17) (21) (2) (3) Natural gas PJ 0 0 - 0 1 -

EBITDA A$m 16 21 78 36 85 117 Condensate kkbbls 0 2 - 2 9 -

less dep. & amort. A$m (13) (12) (27) (25) (26) (28) Oil kkbbls 740 762 1,380 1,502 1,733 1,866

less other non-cash costs A$m (0) - (0) (0) - - LPG k tonnes - - - - - -

EBIT A$m 2 9 50 11 58 89 Total production kboe 745 795 1,380 1,540 1,905 1,866

less net interest A$m (0) (2) 1 (2) (0) (1)




add significant items A$m (68) - (7) (68) - -

Reported profit A$m (66) 6 38 (60) 43 64


EPS (Adjusted) Ac 0.1 0.5 3.9 0.7 3.7 5.5

EPS Growth % -87% 280% 2% -83% 452% 49%

DPS Ac - - - - - -

Franking % 100% 100% 0% 0% 0% 0%

EFPOWA shares on issue m 1,146 1,150 1,146 1,150 1,150 1,150


Cash from operations A$m 88 63 179 151 161 201 Natural gas PJ 156.4 156.2 155.2 155.2


less interest paid A$m - - - - - - Total reserves mmboe 39.9 97.5 95.5 93.7

less tax paid A$m - - 1 - - (24)




add divestment/other A$m 20 - - 20 - -

less dividends A$m - - - - - -

add equity movements/other A$m 0 - 1 0 - - Per bbl statistics 1H15A 2H15E FY14A FY15E FY16E FY17E

add debt movements A$m - - - - - - Sales Revenue / boe A$/boe 79.53 50.65 125.51 74.24 62.21 69.59

Net cashflow A$m (5) (6) (50) (11) (1) (22) EBIT / boe A$/boe 2.66 8.35 36.86 6.74 24.37 32.77

add exchange rate adj. A$m 4 - (0) 4 - - Profit / boe A$/boe 1.83 5.73 32.85 4.63 17.84 23.40

Increase in cash A$m (2) (6) (50) (7) (1) (22) Opex/boe A$/boe 26.29 22.92 28.79 28.49 21.78 19.41

Net debt/(cash) A$m (75) (69) (77) (69) (68) (46) DDA/boe A$/boe 13.06 9.59 18.15 13.00 9.62 9.17


(ND/ND+E) % -22% -19% -19% -19% -17% -10% EV/EBITDAX x 15.6 x 12.5 x 8.1 x 5.1 x 3.4 x 2.4 x

EBIT Interest cover x nmf nmf nmf nmf nmf nmf P/E Ratio x 376.5 x 60.2 x 19.0 x 63.0 x 8.6 x 5.8 x


ROA % 0% 2% 9% 2% 10% 14% FCF yield % nmf nmf nmf nmf nmf nmf

ROE % 0% 1% 9% 2% 9% 12% Dividend Yield % nmf nmf nmf nmf nmf nmf





Free cash flow A$m (26) (6) (53) (29) (1) (22) Growler/Snatcher/Martlet 172 0.15

Worrior/Padulla/Harpoono/Dunlop 16 0.01

Balance sheet 1H15A 2H15E FY14A FY15E FY16E FY17E Developing assets

Cash A$m 75 69 77 69 68 46 Mustang risked valuation @ 100% 34 0.03

Current Assets A$m 43 45 50 45 57 66 Spitfire risked valuation @ 100% 35 0.03

Fixed Assets A$m 385 408 436 408 460 537 Mirage/Ventura/Burruna risked valuation @ 100% 14 0.01

Total Assets A$m 503 522 563 522 585 650 Acrasia risked valuation @ 100% 27 0.02

Current Liabilities A$m 28 38 37 38 42 45 Vintage Crop risked valuation @ 100% 24 0.02

Total Liabilities A$m 85 97 80 97 117 119 Qld CSG assets risked valuation @ 60% 49 0.04

Shareholder equity A$m 419 425 483 425 468 531 Hornet tight gas - 2C risked valuation @ 50% 28 0.02

Vanessa tight gas risked valuation @ 50% 13 0.01

Sensitivities (Adjusted earnings) NPV FY14A FY15E FY16E FY17E Static assets & exploration

Oil price (+US$1/bbl) A$m 0.54 45 8 45 65 Western Flank 3P upside. risked valuation @ 20% 16 0.01

delta 1% - 0 2 1 Cooper, Murta Formation risked valuation @ 10% 1 0.00

2.5% 0.0% 4.3% 5.0% 2.0% Cooper, Growler waterflood risked valuation @ 25% 1 0.00

Currency (+1c) A$m 0.51 45 8 42 62 PEL 182 expl 12 0.01

delta -1% - 0 (0) (1) Hornet tight gas - upside risked valuation @ 20% 23 0.02

-1.9% 0.0% 0.5% -3.9% -3.5% Cooper (Unconventional) 87 0.08

Financial assets

Cash 78 0.07

Debt - -

Corporate overheads (25) (0.02)

Risked NPV 606 0.52

Shareprice prem/(disc) to NPV -39%




-

0.5

1.0

1.5

2.0

2.5

FY

03

FY

04

FY

05

FY

06

FY

07

FY

08

FY

09

FY

10

FY

11

FY

12

FY

13

FY

14

FY

15

FY

16

FY

17

FY

18

FY

19

FY

20

Crude Gas Condensate LPG

kboe


15 April 2015 43

AUSTRALIA

DLS AU Neutral

Price (at 07:04, 14 Apr 2015 GMT) A$1.10



12-month TSR % +9.1

Volatility Index High

GICS sector Energy

Market cap A$m 507


Number shares on issue m 461.1


Revenue m 387.0 258.7 258.9 270.3 EBIT m 212.3 121.8 105.2 124.7

Reported profit m 71.5 51.4 68.9 82.7 Adjusted profit m 94.6 69.4 68.9 82.7 Gross cashflow m 139.2 129.4 124.1 129.8 CFPS ¢ 32.3 28.5 26.9 28.2 CFPS growth % 248.3 -11.8 -5.5 4.6 PGCFPS x 3.4 3.9 4.1 3.9 PGCFPS rel x 0.36 0.41 0.51 0.53 EPS adj ¢ 21.9 15.3 14.9 17.9 EPS adj growth % 270.6 -30.4 -2.1 20.1 PER adj x 5.0 7.2 7.4 6.1 PER rel x 0.29 0.42 0.57 0.53 Total DPS ¢ 0.0 0.0 0.0 0.0

Total div yield % 0.0 0.0 0.0 0.0

ROA % 40.6 18.5 13.1 14.7 ROE % 30.9 17.8 14.1 14.3 EV/EBITDA x 1.9 2.8 3.2 3.0 Net debt/equity % 23.7 -7.9 -19.6 -36.0 P/BV x 1.5 1.1 1.0 0.8

DLS AU vs Small Ordinaries, & rec history





Drillsearch Energy

Available Moomba capacity growing

Wet gas discoveries reliant on third party infrastructure: Much like other

Western Flank wet gas resource owners, DLS finds itself dependent on STO’s

legacy infrastructure footprint, which sees pricing power and potential

development timeframes dictated by the infrastructure owner. However, with a

70mmcf/d contracted with STO with some oil-linkage and a Moomba trading hub

potential earmarked for 2016, DLS remains a clear beneficiary of greater pricing

transparency and greater third party capacity at Moomba:

In July 2013 DLS formed a JV with STO to commercialise six wet gas

resources across PEL 106A, with STO securing a 60% operated interest

at ~A$1.2/mmscf based on a 2C resource size of 62bcf

DLS also struck a GSA with STO for up to 70 mmcf/day of gas out to

2025 with prices transitioning from CPI-escalation to oil linkage, ultimate

access to Moomba is yet to be finalised. However, given STO’s 60%

interest across both ventures it is likely that the operator will remain

largely indifferent to 3rd

party tolling charges.

Indeed, wet gas prospects has been enhanced by solid exploration

success to date with four discoveries across the Wet Gas JV with STO in

FY15 (Nulla North-1, Yarowinnie South-1, Varanus South-1, and Kyanite-

1 with an additional 3 wells set to be carried through the remainder of

FY15).

Potential for unconventional to see further curtailment: Following

Queensland governments’ legislative changes that now sees the exploration

work program extended by two years in 2017, the QGC/DLS JV opted for a

prudential approach to additional near term capex commitments reducing the

program to 4 wells (and an additional A$25-30m to test and analyse results from

initial frac stimulation). With the Shell/BG tie up potentially seeing plans for 10tcf

of Arrow gas resource rejuvenated the new owners’ commitment to ATP 940P

remains unclear.

Following the theme of most global majors, Shell announced that the

proposed Shell/BG entity would launch a U$30bn non-core asset sales,

and continue with Shell’s U$15bn curtailment of capex across 2015-2017

as well as the “high-grading” of pre-FID projects. Against this backdrop, it

remains to be seen whether Shell would express the same level of

commitment to an ATP 940P unconventional program as shown by BG.

BG recently highlighted that a Cooper unconventional development is at

least 5-6 years away from formal sanction (compared to ~4 years for

Bowen CSG and ~5 years for Bowen deep sand gas).

With FEED on a pipeline connecting the Bowen Basin commencing late

last year, we envisage that Arrow gas could contribute to debottlenecking

efforts or a 3rd

train by early next decade. Thus, with QCLNG potentially

not short of equity feedstock for expansion it is unlikely that Shell would

look to prioritise Cooper unconventional.

Downgrade to Neutral rating with a A$1.20/sh target: DLS continues to take

proactive measures in order to adapt to the current oil price environment,

expressing capital discipline and encouraging cash flow conservation. Despite

recent capex cuts we still believe that DLS have the ability to deliver material

western flank wet gas production over coming years (50-70 mmcf/d), although

the Northern Acreage appears more challenging (given limited activity). Such

production growth is set to benefit from potentially increased transparency in

East Coast gas markets and available third-party processing capacity at

Moomba.


15 April 2015 44

Fig 49 Drillsearch Energy financials


Drillsearch Energy (DLS-AU) Share Price: A$1.10




add other income A$m 3 25 1 29 2 - Ave. domestic Gas A$/GJ 2.98 3.00 3.13 2.88 3.01 3.07

Total revenue A$m 150 137 388 287 261 270 Oil-Brent US$/bbl 90.43 53.50 109.05 100.08 60.75 76.50



less exploration expensed A$m - (2) (2) (2) (8) (8) Natural gas bcf 0.8 0.8 1.8 1.5 3.6 6.9

EBITDA A$m 95 83 259 178 152 164 Condensate kbbls 25 70 77 94 308 477

less dep. & amort. A$m (31) (25) (40) (56) (45) (37) Oil kbbls 1,359 1,420 2,923 2,779 2,368 1,695

less other non-cash costs A$m 1 (1) (6) (0) (2) (2) LPG k tonnes 3.3 4.6 8.3 7.9 22.0 39.7

EBIT A$m 65 57 212 122 105 125 Total production kboe 1,541 1,655 3,375 3,196 3,454 3,652

less net interest A$m (3) (4) (10) (7) (6) (4) Total production rate kpd 8,375 9,142 9,246 8,755 9,437 10,006




add significant items A$m (18) - (23) (18) - -

Reported profit A$m 14 37 72 51 69 83


EPS (Adjusted) Ac 7.2 8.0 21.9 15.3 14.9 17.9

EPS Growth % -27% 11% 271% -30% -2% 20%

DPS Ac - - - - - -

Franking % 100% 100% 0% 0% 0% 0%

EFPOWA shares on issue m 433 461 433 461 461 461


Cash from operations A$m 191 151 393 342 263 271 Natural gas PJ 270.5 269.0 265.4 258.6


less interest paid A$m (4) (5) (11) (9) (7) (4) Total reserves mmboe 28.3 25.1 21.7 18.0

less tax paid A$m - - 0 - - (10)




add divestment/other A$m (6) - - (6) - - 451 3 600

less dividends A$m - - - - - - 3.4 680

add equity movements/other A$m 1 - 3 1 - - Per bbl statistics 1H15A 2H15E FY14A FY15E FY16E FY17E

add debt movements A$m - - (10) - - (122) Sales Revenue / boe A$/boe 80.71 50.41 108.83 72.03 50.60 53.47

Net cashflow A$m (6) 40 116 34 67 (25) EBIT / boe A$/boe 35.70 25.63 59.71 33.92 20.57 24.67

add exchange rate adj. A$m - - 0 - - - Profit / boe A$/boe 17.81 16.68 26.59 19.33 13.46 16.36

Increase in cash A$m (6) 40 116 34 67 (25) Opex/boe A$/boe 19.62 16.26 21.97 19.99 13.15 12.46

Net debt/(cash) A$m 4 (36) 1 (36) (103) (229) DDA/boe A$/boe 17.00 11.31 11.35 15.60 8.81 7.31


(ND/ND+E) % 1% -9% 0% -9% -24% -56% EV/EBITDAX x 5.9 x 6.0 x 2.0 x 2.8 x 3.2 x 3.0 x

EBIT Interest cover x -762.2 x nmf 90.1 x ####### 28.8 x 34.1 x P/E Ratio x 17.2 x 13.7 x 6.4 x 7.7 x 7.4 x 6.1 x


ROA % 9% 8% 38% 16% 12% 15% FCF yield % nmf 7.9% 26.1% 7.2% 13.1% 19.1%

ROE % 8% 8% 29% 15% 13% 13% Dividend Yield % nmf nmf nmf nmf nmf nmf





Free cash flow A$m (2) 40 162 39 67 97 Cooper, Tintaburra 33 0.07

Flax/Juniper/Tintaburra Tight Oil - 2P (3) (0.01)

Balance sheet 1H15A 2H15E FY14A FY15E FY16E FY17E Cooper, Western Flank (PEL 91/92) 244 0.52

Cash A$m 146 187 76 187 253 229 Cooper, Wet Gas (PRL 130) 157 0.33

Current Assets A$m 83 70 84 70 70 70 Cooper, Wet Gas (PEL 632) 55 0.12

Fixed Assets A$m 469 496 402 496 532 548 Developing assets

Total Assets A$m 699 753 562 753 855 847 Western Flank - Contingent 35 0.07

Current Liabilities A$m 54 54 51 54 177 57 Wet Gas - GMI Ridge (PEL 103) 25 0.05

Total Liabilities A$m 281 299 235 299 332 212 Wet Gas - Ginko, Crocus (PEL 101) 5 0.01

Shareholder equity A$m 417 454 326 454 523 635 Wet Gas - Ginko, Crocus (PEL 101) 10 0.02

Flax/Juniper/Tintaburra Tight Oil - 2C 1 0.01

Sensitivities (Adjusted earnings) NPV FY14A FY15E FY16E FY17E Bass Basin (T/18P) - 2C 2 0.00

Oil price (+US$1/bbl) A$m 1.39 95 70 72 84 Static assets & exploration

delta 2% - 0 3 1 Cooper REM Shale (ATP 940P) (15) (0.03)

1.3% 0.0% 0.7% 4.0% 1.7% Exploration 96 0.20

Currency (+1c) A$m 1.35 95 69 68 81 Financial assets

delta -2% - (1) (1) (2) Cash 144 0.31

-1.7% 0.0% -0.8% -1.0% -2.6% Debt (122) (0.26)

Corp. Overhead + other (23) (0.05)

Risked NPV 644 1.37

Shareprice prem/(disc) to NPV -20%




-

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19 FY20

Crude Gas Condensate LPGkboe


15 April 2015 45

Important disclosures:

Recommendation definitions

Macquarie - Australia/New Zealand Outperform – return >3% in excess of benchmark return Neutral – return within 3% of benchmark return Underperform – return >3% below benchmark return Benchmark return is determined by long term nominal GDP growth plus 12 month forward market dividend yield

Macquarie – Asia/Europe Outperform – expected return >+10% Neutral – expected return from -10% to +10% Underperform – expected return <-10%

Macquarie First South - South Africa Outperform – expected return >+10% Neutral – expected return from -10% to +10% Underperform – expected return <-10%

Macquarie - Canada

Outperform – return >5% in excess of benchmark return Neutral – return within 5% of benchmark return Underperform – return >5% below benchmark return

Macquarie - USA Outperform (Buy) – return >5% in excess of Russell 3000 index return Neutral (Hold) – return within 5% of Russell 3000 index return Underperform (Sell)– return >5% below Russell 3000 index return

Volatility index definition*

This is calculated from the volatility of historical price movements. Very high–highest risk – Stock should be

expected to move up or down 60–100% in a year – investors should be aware this stock is highly speculative. High – stock should be expected to move up or down at least 40–60% in a year – investors should be aware this stock could be speculative. Medium – stock should be expected to move up or down at least 30–40% in a year. Low–medium – stock should be expected to move up or down at least 25–30% in a year. Low – stock should be expected to move up or down at least 15–25% in a year. * Applicable to Asia/Australian/NZ/Canada stocks only

Recommendations – 12 months Note: Quant recommendations may differ from Fundamental Analyst recommendations

Financial definitions

All "Adjusted" data items have had the following adjustments made: Added back: goodwill amortisation, provision for catastrophe reserves, IFRS derivatives & hedging, IFRS impairments & IFRS interest expense Excluded: non recurring items, asset revals, property revals, appraisal value uplift, preference dividends & minority interests EPS = adjusted net profit / efpowa* ROA = adjusted ebit / average total assets ROA Banks/Insurance = adjusted net profit /average total assets ROE = adjusted net profit / average shareholders funds Gross cashflow = adjusted net profit + depreciation *equivalent fully paid ordinary weighted average number of shares All Reported numbers for Australian/NZ listed stocks are modelled under IFRS (International Financial Reporting Standards).

Recommendation proportions – For quarter ending 31 March 2015

AU/NZ Asia RSA USA CA EUR Outperform 48.99% 59.51% 49.30% 43.79% 59.59% 52.20% (for US coverage by MCUSA, 7.42% of stocks followed are investment banking clients)

Neutral 34.12% 26.62% 35.21% 50.29% 34.93% 31.32% (for US coverage by MCUSA, 5.68% of stocks followed are investment banking clients)

Underperform 16.89% 13.87% 15.49% 5.93% 5.48% 16.48% (for US coverage by MCUSA, 0.87% of stocks followed are investment banking clients)

Company-specific disclosures: Important disclosure information regarding the subject companies covered in this report is available at www.macquarie.com/disclosures.

Analyst certification: The views expressed in this research reflect the personal views of the analyst(s) about the subject securities or issuers and no part of the compensation of the analyst(s) was, is, or will be directly or indirectly related to the inclusion of specific recommendations or views in this research. The analyst principally responsible for the preparation of this research receives compensation based on overall revenues of Macquarie Group Ltd (ABN 94 122 169 279, AFSL No. 318062) (“MGL”) and its related entities (the “Macquarie Group”) and has taken reasonable care to achieve and maintain independence and objectivity in making any recommendations. General disclosure: This research has been issued by Macquarie Securities (Australia) Limited (ABN 58 002 832 126, AFSL No. 238947) a Participant of the Australian Securities Exchange (ASX) and Chi-X Australia Pty Limited. This research is distributed in Australia by Macquarie Equities Limited (ABN 41 002 574 923, AFSL No. 237504) ("MEL"), a Participant of the ASX, and in New Zealand by Macquarie Equities New Zealand Limited (“MENZ”) an NZX Firm. Macquarie Private Wealth’s services in New Zealand are provided by MENZ. Macquarie Bank Limited (ABN 46 008 583 542, AFSL No. 237502) (“MBL”) is a company incorporated in Australia and authorised under the Banking Act 1959 (Australia) to conduct banking business in Australia. None of MBL, MGL or MENZ is registered as a bank in New Zealand by the Reserve Bank of New Zealand under the Reserve Bank of New Zealand Act 1989. Any MGL subsidiary noted in this research, apart from MBL, is not an authorised deposit-taking institution for the purposes of the Banking Act 1959 (Australia) and that subsidiary’s obligations do not represent deposits or other liabilities of MBL. MBL does not guarantee or otherwise provide assurance in respect of the obligations of that subsidiary, unless noted otherwise. This research is general advice and does not take account of your objectives, financial situation or needs. Before acting on this general advice, you should consider the appropriateness of the advice having regard to your situation. We recommend you obtain financial, legal and taxation advice before making any financial investment decision. This research has been prepared for the use of the clients of the Macquarie Group and must not be copied, either in whole or in part, or distributed to any other person. If you are not the intended recipient, you must not use or disclose this research in any way. If you received it in error, please tell us immediately by return e-mail and delete the document. We do not guarantee the integrity of any e-mails or attached files and are not responsible for any changes made to them by any other person. Nothing in this research shall be construed as a solicitation to buy or sell any security or product, or to engage in or refrain from engaging in any transaction. This research is based on information obtained from sources believed to be reliable, but the Macquarie Group does not make any representation or warranty that it is accurate, complete or up to date. We accept no obligation to correct or update the information or opinions in it. Opinions expressed are subject to change without notice. The Macquarie Group accepts no liability whatsoever for any direct, indirect, consequential or other loss arising from any use of this research and/or further communication in relation to this research. The Macquarie Group produces a variety of research products, recommendations contained in one type of research product may differ from recommendations contained in other types of research. The Macquarie Group has established and implemented a conflicts policy at group level, which may be revised and updated from time to time, pursuant to regulatory requirements; which sets out how we must seek to identify and manage all material conflicts of interest. The Macquarie Group, its officers and employees may have conflicting roles in the financial products referred to in this research and, as such, may effect transactions which are not consistent with the recommendations (if any) in this research. The Macquarie Group may receive fees, brokerage or commissions for acting in those capacities and the reader should assume that this is the case. The Macquarie Group‘s employees or officers may provide oral or written opinions to its clients which are contrary to the opinions expressed in this research. Important disclosure information regarding the subject companies covered in this report is available at www.macquarie.com/disclosures.

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