East Coast Gas SECTOR REVIEW. Everything changes (but supply) Figure 1: Net-back prices at US$80/bbl vs. cost of new supply

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1 Asia Pacific/Australia Equity Research Oil & Gas (Oil & Gas (AU)) Research Analysts Martin Kronborg, CFA martin.kronborg@credit-suisse.com Mark Samter mark.samter@credit-suisse.com Peter Wilson peter.wilson.2@credit-suisse.com David Hewitt david.hewitt@credit-suisse.com East Coast Gas SECTOR REVIEW Everything changes (but supply) Take That Australia: It becomes clearer by the day that the CSM-LNG projects were built for a $100/bbl oil world. BG was the first to report a writedown with $6.7bn for QCLNG and downgrade of ~1.8TCF (11%) of 2P reserves. The challenge is, with reserve shortages seemingly widening, net back pricing doesn t stack up in the domestic market at $60-70/bbl oil. New prices, new structures: With the fall in the oil price, oil-linkages in domestic gas contracts have fallen from A$8-10/GJ to A$4-5/GJ. This hurts net sellers such as Beach and Origin that do have not high floors or kinks. We believe that new contracts will have to be structured differently, with higher oil linkages or floors as per Figure 1, marginal cost of the cheapest undeveloped gas is ~A5-6/GJ in Victoria before any transport charges. QLD and Cooper are more expensive, NT doesn't yet have meaningful reserves. No supply response yet: Nothing material has been sanctioned in years as uncertainty makes it difficult to commit to major projects. The issues are three-fold: 1) The scope of the shortage is unknown with CSG supply capacity an untested quantity. 2) Balance sheets of resource owners (ORG, STO) are stretched. 3) Netback prices are currently too low to develop new supplies on our numbers, we need at least $80/bbl oil for LNG sales to be profitable from new gas supplies (no sunk cost yet). What will balance the market? Clearly one of supply or demand will ultimately act to balance the market. With PJa of gas set to go to the LNG projects from the domestic market, and no new capacity being sanctioned, if supply isn t added soon demand will have to adjust sizeably. Figure 1: Net-back prices at US$80/bbl vs. cost of new supply $12 $10 Wellhead Cost $8 $6 QLD (Wallumbilla) $4 $2 $0 Vic (repl.) Vic (new) Cooper QLD CSG NT (max WH cost) Cooper Basin Victoria Source: Company data, Credit Suisse estimates DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, AND THE STATUS OF NON-US ANALYSTS. US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS BEYOND INFORMATION Client-Driven Solutions, Insights, and Access

2 Globalisation bites The most obvious change in the oil and gas world is the more than halving of oil prices in only six months. With recent LNG contracts all oil-linked this directly feeds through to received prices which are probably around A$9/mmbtu currently. This compares to last year's prices above A$15/GJ and our LT forecasts of A$12-13/GJ (Global LNG Sector). Needless to say this is extremely painful for many East-Coast LNG projects that are about to start up, with QCLNG the first to book a $6.7bn impairment. At $50-60/bbl oil, much of the production is borderline economic and very little new CSG development would be incentivised (where development cost is not yet sunk). We write more about the LNG side of things in the accompanying note (Islands in the dream?). Figure 2: Landed price in Japan, netbacked to Aus US$/mmBtu A$/mmBtu Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan Japan landed price (US$, LHS) Theoretical domestic QLD netback ($A$, RHS) Source: Company data, Credit Suisse estimates Brave new domestic world For now, this has had limited impact on the current domestic gas market prices that are largely fully contracted and fixed price. However, many new contracts starting in 2015/16 are oil-linked and therefore directly exposed to international markets. Costs may exceed prices and it is likely we will see a change in pricing structure for the next round. Price and supply uncertainty also means that no new projects have been sanctioned. Domestic sellers with oil-price linkage and no floor will be hurt obvious losers from lower prices are Beach and Origin. Santos 50PJa Cooper Basin sales are offset by 190PJ third party purchases by GLNG. See Figure 13 for contract details. Contract structures will change and prices will go higher: No new gas will be developed at the $5-6/GJ prices implied by the 6-8% oil-linkage. Either new contracts must have higher oil linkages, contain higher floors/kinks or perhaps fixed-price CPI- Index returns. We estimate prices need to be $7-8/GJ in NSW and $9-10/GJ in QLD for new developments to be economically attractive, see Figure 10. Supply demand balance stays tight: Demand destruction has helped in the short term but new sanctioning is still needed. But there may be too many uncertainties to sanction: performance of CSG wells at the large projects is still an unknown and Arrow is a wild card for others. At current low prices and stretched balance sheets it is not easy to sanction new gas on the expectation of potential demand higher prices. Ownership may have to change: Arrow is needed for its reserves (potentially near term production too) so Shell/PetroChina must be incentivised, maybe with LNG capacity. NSW needs its own gas to prevent being fully exposed to QLD prices by buying from the Cooper but neither AGK nor STO are likely to charge ahead alone. East Coast Gas 2

3 Pricing - I know what you did last summer What seemed like phenomenal oil-linked deals last year are now coming back to haunt the sellers. A 6-7% slope at US$60/bbl translates into A$4-5/GJ, not far ahead of historical averages and possibly below cash cost for more marginal fields. GLNG, and probably QCLNG, has sought to share the downside burden meaning there are no contract floors, only modest kinks. Perversely, this probably means GLNG and QCLNG are better off on operating costs (not reserves) as they are heavily dependent on third-party gas to supply the trains. Within our coverage: Santos is a wash domestic (but of course lower prices are negative for LNG sales). 50PJa largely matches its 30% share of the 190PJa GLNG has contracted so far, meaning the net impact is marginal. Beach is negative; it is directly and fully exposed to lower prices with no real offset for its 17PJa sales to Origin. To be clear, lower than previously expected not lower than historical levels estimated around $4/GJ. Shale interest is also likely to decline in the near term, reducing the value to resource holders. Other juniors DLS and SXY have uncontracted gas resources and could benefit from a tight market. Origin's domestic business has some vertical hedge but net long: through its sales to QCLNG and GLNG, Origin has direct oil exposure on up to 75PJ per annum of sales until when one of the sales contract ends. This is ~20-25PJ more than its total oil linked supply contracts (Beach, Esso-BHP) which leaves it net long oil. Origin does retain the option to reduce the volumes sold to GLNG by 19PJ per annum which provides some protection against low prices, but in a relative sense it still leaves Origin better off in a high oil price environment. Note, Origin of-course has a huge material exposure to oil prices through its 37.5% share ownership of APLNG and the JV's sales to other projects. AGK has hedged all direct oil exposure: AGL has entered into gas sales agreements for up to 59PJ per annum over FY15-17 with QGC and others that incorporate oil indexation. However, AGL has confirmed that shortly after entering into those contracts it hedged all oil and fx exposure, thereby locking in an average margin of $3.40/GJ on its FY15 gas sales. The rest of AGL's portfolio of supply and demand is understood to be fixed price CPI indexation. Figure 3: Average annual oil-linked contracts for our coverage next two years - Seller PJa Buyer PJa Comment Santos 50 GLNG 50 Little downside protection in LNG sales (known) Origin 75 GLNG 75 Little downside protection in LNG sales (assumed) Other 49 GLNG 49 Little downside protection in LNG sales (assumed) BPT 17 Origin 17 "Better than historical" Esso-BHP 35 Origin 35 Unknown Source: Energy Quest, Credit Suisse estimates Going forward, pricing structure changes but prices remain high: Although current oil-linked contract prices received are a far cry from the $8-10/GJ+ we forecast, we still think that is a reasonable level for Wallumbilla prices (QLD). The reason is two-fold: 1) an expectation of a partial recovery in oil-price which drives prices to netback pricing in a short market and 2) incentive pricing for new gas projects. New sales terms could be achieved through higher oil-linkages, floors or by simply going back to CPI indexed fixed price contracts. East Coast Gas 3

4 Greenfield liquefaction cost is probably above $4/GJ as capex that must still be spend forms part of the budget. That is relevant if there is too much gas in the market and additional LNG trains would need to be constructed to balance the market. However, if the market is short gas (and it certainly looks that way), the operating cost around $1.5/GJ would be used by exporters. As long as the net-back price is more than $1.5/GJ lower than the spot LNG price, it will be economical for LNG exporters to buy up gas in the East Coast market. We expect netback to set the price in QLD ($9-10/GJ), Moomba (-$1/GJ for transport) and through them indirectly in NSW and Victoria (-$2-3/gj). We do not expect any Victorian gas to flow to Queensland and therefore assume prices will be substantially lower in Victoria at around $6-7/GJ. However, if NSW does not develop new fields, it is likely that peak gas will be needed from the Cooper Basin. That means netback Moomba +$/1GJ for transport, closer to $9.5/GJ (or a negotiated average price level in between $ /GJ) with Victoria $1/GJ below that. Marginal cost, if higher, would provide the floor. Northern Territory gas must be able to deliver to QLD for ~$9/GJ to compete. That means domestic NT gas should not cost more than $5-6/GJ to develop and produce, a very low number in the current Australia context. Things could get worse. If the LNG projects are only short for spot cargoes, gas prices will likely be priced at netback as described above. However, if they are short contracted gas, prices can go well above netback due to penalty payments. These are typically large but we can't quantify without knowing contracts. We discuss this in more detail later, but in short we won't know this before all projects are ramped up (as true well performance can then better be estimated). Figure 4: Netback price ranges A$5-6/GJ? A$10.5/GJ A$8.5/GJ A$9.5/GJ A$ GJ A$ /GJ Source: Company data, Credit Suisse estimates East Coast Gas 4

5 S-D balance how to match... With great uncertainty come few decisions. Resource owners are unsure about the future netback price as well as how great demand for gas will be in the near term. You could not sanction a project based on prevailing oil prices. In addition, there are great technical uncertainties on how exactly the CSG projects perform once they have fully ramped up. If wells exceed expectations, there may not be huge excess demand for gas in the near term (reserve coverage is a longer term problem). Demand... destruction for now Back in 2013, we forecast a supply shortage of PJ by 2016/17 unless major new gas developments were begun (see Eastern Australia Gas Prices - Only way is up). Nothing has been sanctioned yet and the market has responded clearly less demand. The government regulator AEMO forecasts that by 2017, 100PJ will be taken out of Gas Powered Generation (GPG) and 50PJ from industrial uses (aluminium smelters, car manufacturers, etc). Figure 5: AEMO demand forecasts Historical ( ) Short Term ( ) Medium Term ( ) 2000 Total consumption Annual gas conusmption (PJ) Source: AEMO GPG Decline due to reduced electricity demand Industrial LNG ramp up as QCLNG, APLNG & GLNG begin to export gas from Curtis Island. Consumption plateaus as they reach full production Reduced dispatch of GPG in the electricity market due to rising gas prices and increased renewable generation Reduced consumption due to rising gas prices, fuel substitution and plant closures (particularly in Qld and NSW) Total consumption excl. LNG Residential & Commercial Growth due to new connections exceeding reduction in average usage Losses Mixed with supply uncertainty That, however, is not enough to match the 2-300PJa of gas that will be diverted from domestic consumption to LNG, so production must increase elsewhere. The supply uncertainties are substantial: When looking at a short 1-5-year horizon, QLD is a huge unknown. There is uncertainty on CSG well performance, all-in cost and on what projects will be sanctioned. We can't at this stage predict the level of shortage. For supply, Arrow is large enough to be a game changer for a smaller projects such as Ironbark or Senex' Surat that had not secured off-take. We discuss the longer-term view in more detail here (Islands in the dream?). East Coast Gas 5

6 There could be a perpetual shortage in QLD but we would not expect the South to supply any gas. More likely the gas will stay in the South, which is also facing demand destruction from shortages, and get a netback price for the ~$3-4/GJ transport cost. With no QLD gas flowing South anymore, we think this is most likely supply increase is out of Esso-BHP's facilities in Gippsland. Volumes could go up 50-60PJa if another source can be used to peak gas supply. Additional gas and peak supply could be found in NSW (probably cheaper if progress is made) or the Cooper Basin which has 70PJa storage capacity (expensive as competing with QLD). However, with Otway facing declines later this decade additional projects must be sanctioned. In the South, that could be NSW CSG or Otway life extension. The Cooper Basin may also have a bigger role to play in the long run. To be clear, none of this is likely to be cheap gas. Queensland: The first LNG is the hardest Gas markets in the next few years will likely be in a state of flux, with QCLNG and, in particular, GLNG scrambling to secure enough gas to reach full capacity. According to AEMO, domestic Queensland will need 140PJa for industrial customers (primarily mines) after 100PJa demand destruction. The currently supplied 240PJ is primarily from CSG that will not remain available e.g. LNG operators and ~40PJa from Arrow. Gas powered generation will cease. While we can find the ~140PJa that AEMO is forecasting ex. LNG, most of the contracts have not yet been signed with end-producers that would have to compete on commercial terms with LNG facilities. The intermediaries, ORG and AGK, have enough gas but they will of course choose the best commercial option, whether that is LNG or domestic. Origin gets is supply from 1) APLNG 40PJ (until 2030), GLNG 15PJ (until 2020), Beach 17PJ (until 2030) and Cooper equity gas 15-17PJ. o Origin is selling about 55-73PJ to GLNG (its discretion), 15pj to QGC for 2 years and 3PJa to MMG. That leaves very little for the domestic market until AGK: QGC supplies 45PJ to AGK to 2027 and APLNG supplies 25PJ until o Onsold to MMG, Incitec, Xstrata (28PJa total) APLNG will service some of the QLD market: o 12Pj to QAL o 23PJ to Arrow supplies about 40PJa to power stations. That gas is probably much more valuable elsewhere (whether Arrow sells it or the power station is a moot point), meaning it will like find its way to elsewhere in the market. GLNG has already purchased "100tj/d from other", which could well be from Arrow. Capacity vs. demand In theory, there is enough gas compression capacity being constructed to meet all needs at around 4500TJ/d (1,650PJ) from the LNG projects. Add to that gas supplies from existing Arrow contracts that is better sold to exporters and ~100PJa Cooper supply available to GLNG and Origin. East Coast Gas 6

7 It is unclear if APLNG, with much higher 2P reserves, would be willing to commit to further supply and also unclear if new projects will get sanctioned. A few issues: (1) Capacity does not equal production. Compressors don't run at full capacity and the real bottleneck will be CSG well performance. We simply do not yet know what the performance of each the fields will be when full production is required and how this changes over time (probably neither do the operators). Compression capacity does not greatly exceed required demand, so there is not much scope for any fields to fall short of expectations. (2) The distribution is extremely uneven, with GLNG having the least capacity. Adding third party signed, GLNG only has committed gas of around 1,050Tj/d, below the ~1,250Tj/d will need for full capacity. Whether this shortfall is an issue with price or because APLNG and QCLNG want to remain certain that they have sufficient equity capacity (refer point 1 above) is not clear. Probably both. (3) With many modern LNG facilities operating well above capacity there is every chance that the downstream facilities at Gladstone will be able to as well (they are all built for 9mtpa), potentially adding 10% export capacity or 130PJ. APLNG may want to keep the option to exceed nameplate equity gas in the future, requiring additional reserves. Figure 6: Capacity, maybe enough for now. But well performance uncertain 6,000 TJ/d 5,000 4,000 3,000 2,000 10% De-Bottleneck Uncontracted Capacity GLNG QCLNG APLNG Domestic Demand Cooper + Arrow Dom 1,000 0 Compression (100%) LNG Contracts LNG Capacity De-bottlenecked Source: Company data, Credit Suisse estimates Options for new supply, not your CSG wells of old... There are three potential projects that may proceed in some form, though only one is large enough to supply the missing resources Arrow with is ~9.5Tcf of 2P reserves. On the smaller end, Origin has delayed a decision on Ironbark (259PJ 2P) probably due to a strained balance sheet and uncertain prices and economics. Senex also has interests in the Western Surat (488PJ), near Santos Roma acreage. All three projects are very secretive about economics, so we only have estimates. What we can say for all projects, is that they were not included in the original LNG projects. For Ironbark and Western Surat (prev. owned by QGC), that probably says a lot about the quality of the resource. For Arrow, it could be that were simply keeping the reserve to use for its own LNG project (now shelved). However, if economics are anything like the existing CSG projects, Arrow gas will not come cheaply. After all, all of the capex that is sunk at the existing projects must still be included in a cash cost calculation for Arrow. East Coast Gas 7

8 Figure 7: Arrow marginal cost scenarios (real A$/GJ) A$/GJ Upstream capex to first gas $1.30 BG guided sustaining capex (ex some associated infrastructure) $ Upstream opex $1.50 Royalty $0.50 Margin required for 10% return $ well head cost $ Transportation costs to Gladstone $1.00 Marginal cost delivered to Gladstone $ Source: Company data, Credit Suisse estimates What happens in the North does not stay there... In the short term, the re-direction of supply from the Cooper (and QLD) away from the South is what has caused concern in NSW and Vic. In a familiar story, no material production has been sanctioned to compensate. The obvious result is demand destruction of that amount. After that, the Southern states (NSW, Vic, SA, and TAS) are forecast to consume app. 330PJ for industrial and consumer needs, and another 50PJa for gas generation at peak times. Keep it in my backyard It is important for the South to stay self-sufficient. If gas must be imported from Queensland (or NT or LNG), it will be very expensive. Queensland will likely be permanently short as the LNG trains ramp, meaning prices in QLD will converge to operating netback. Buyers outside of QLD would have to pay additional transport costs to compete on the same term as LNG sellers, meaning netback is QLD price +$3-4/GJ. Where will new supply come from? While demand destruction will partially solve the problem, it may be hard to fully replace the 100PJa+ coming into the markets from QLD and Cooper. Nothing new can be developed in the short term, so the market must look to existing projects with capacity. The more QLD demands from Cooper, the more the South's demand on Gippsland. After that, new projects must be developed to meet potential decline in the Otway later in the decade. By far the largest supplier is off-shore Victoria, with the Esso-BHP operated Gippsland fields going through Longford at about 240PJa and currently the main peak suppliers. Nearby Longtom supplies another 10PJa but it will slowly start to decline. Sole (STO/COE) or BGM (BPT/COE) could provide a nice replacement for Longtom, adding another 20PJa if the Orbost Gas Plant gets an upgrade. However, it is still early stage and neither backer is cash rich. The Otway supplies 110PJ through three separate fields, all of which are nearing the end of their lives (Origin's Halladale and the exploration well Speculant may offset some). BassGas has received an upgrade and should remain stable at 15-20Pja for the foreseeable future. Halladale Blackwatch (ORG) could add another 15PJ or so. If the Speculant exploration well is successful, that could further support production. East Coast Gas 8

9 Figure 8: Share of total reserves and production Otway the issue, NSW the solution? 60% 50% 40% 30% 20% 10% 0% Gippsland NSW Cooper Otway Yolla Reserves (8.2 Tcf) Production (457PJa) Source: EnergyQuest, Credit Suisse estimates Gippsland can probably move to PJa Figure 9 shows the historical production of the Longford gas plant owned by the Gippsland basin JV of Esso and BHP Billiton. Due to a lack of demand, the JV has been producing at less than it true capacity in recent years but it will be increasingly important in coming years as the Cooper basin production is redirected to LNG export. Figure 9: Longford Production vs. Capacity TJ/d 1,600 1,400 1,200 1, Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Actual Longford Production Total Northern Supply (pipeline flow ADL + SYD) Longford 7-day Capacity Outlook Source: Company data, Credit Suisse estimates The Longford plant is rated at a capacity of 1,145TJ/d which means that theoretically it could produce over 400PJ/annum if running at 100% 365 days a year. However, in reality the maximum annual production is far less. The annual production potential is constrained by two factors: (1) Annual maintenance requirements: As shown above, the 45-year-old plant has in the past reduced its production capacity in shoulder demand periods for regular maintenance. It is unclear to what extent this is chicken-egg and to what extent it could have increased availability were e the demand there to support it. Nevertheless, it is likely that maintenance reduces the maximum annual production significantly. East Coast Gas 9

10 (2) Winter peaking demand profile does not support flat output: to increase annual production, the JV will have to sell much more gas in the non-winter months. We do expect that they can displace most of the non-winter Cooper basin production, but this still will not be sufficient. The absence of significant storage in the market also limits sales. By our estimates, the effect of these two factors will limit the maximum output of the Gippsland JV to PJ per annum. NSW CSG one step forward politically, one step backwards financially: A domestic source of gas is important to avoid being beholdend to Esso-BHP and/or Cooper Basin. If the South is short gas during peak times (it will be if Longford must switch to baseload), then peak gas probably has to come from the Cooper that means NSW is competing with QLD and might have to play the ~$8/GJ Cooper Basin price +$1/GJ for transport. Is there is sufficient gas from NSW and Victoria combined, then the price floor would be closer to netback price of $7/GJ ($8/GJ Cooper minus $1/GJ transport. This of course assumes that gas can be developed at that price. There has been little progress in NSW, with AGK's Gloucester project (25PJa) and STO's Narrabri (35-70PJa) still in planning stages with a 2018 first production target. AGK has also temporarily halted all development after high concentrations of BTEX were found in samples Gloucester. The state government has seemingly taken a positive stance on major CSG developments by established companies (exclusively, all exploration licenses were pulled). However, many rules are still left to be clarified in and there is a State election to get through in March. A labour victory could see fresh delays. Should rules be clarified and approval given, the key determinant will then be economics. With new rules and regulations still to be determined, substantial additional costs could be put on the project sponsors. We understand that some of the Coal Seam Gas is relatively high quality and would probably work in 6/GJ+ market (the lower end of Santos past price expectations). However, the "core" may be limited to a smaller subset of reserves which itself may not be large enough to underpin the required pipeline infrastructure. Balance sheets are stretched, with Santos having already targeted Narrabri spending for cuts in Narrabri would likely end up a multi $bn project, something which Santos cannot consider at present time (especially for an uncertain economic return). A sell-down to a partner is on the cards. Cooper middle man The Cooper has seen its fortunes severely reversed in the past six months. A lower oil price has already impacted capex budgets and seen the economics of liquids rich gas deteriorate. Geology has not helped either, with Santos in-field drilling program having disappointed so far. With announced capex cuts, the expected 130PJa from the SACB JV may not be reached, meaning less gas to go around. Cooper gas will likely go to Queensland where price are expected to be higher. It may provide peak supply to the south via the storage facilities at Moomba. A few topics to look for: Santos has reduced its budgets, affecting Cooper Basin. By how much is still unknown but a guided 10% reduction in sustaining capex could mean a 10% reduction from the planned 130PJa. Additional details may be given at the half year result. East Coast Gas 10

11 Santos farm-in to Drillsearch wet gas acreage has produced some positive early results but this is relatively small scale (and also at risk). Other projects that could are Senex' Hornet or Strike's deep CSG but both are early stage (economics unknown) and neither company can afford development on their own. Economics have blown out... while the small DLS/BPT JV is still profitable, the same can probably not be said for the SACB JV. The math is simple: o o o o o Santos has guided to $400mn net capex for its previous targeted ~85Pja, meaning $4-5/GJ is spent on sustaining capex. Some may be for the associated infrastructure that has additional value. Operating costs (including oil) is $18/bbl, meaning another $2-3/GJ additional cost as gas costs are probably lower than oil. Royalties adds another ~$0.5/GJ. At current oil prices, all-in received prices (including liquids) and probably $5-6/GJ, meaning a net loss of $1-3/GJ. That is before allowing for the $800mn growth project that is still on-going (and which has quite likely blown out at least we don't understand what else all the Cooper Basin capex has been spent on in past years). Unconventional is struggling too. Santos has cut its spending, Origin and SXY have not gotten past starting seismic and DLS/BG are looking to cut the 10 well programme to 4 wells (already drilled) for now. That leaves Chevron and Beach and it is unclear how much additional spend Chevron is willing to commit given its own capex constraints shale gas is a numbers game and no-one else is adding any digits at the moment. Meaningful production is a story for the next decade, at best. Long live the pipeline in the North? Probably not, it seems like a panic button. While the pipeline has support from politicians in NSW and a $2mn scoping study is currently being undertaken by APA, there are obvious difficulties. To be used in QLD gas must be cheap enough to compete with Arrow (or similar). Transport costs from NT to East-QLD would probably be in the range of $4/GJ after a new pipeline has to be constructed, meaning the netback to the Northern Territory is closer to $5-6/GJ ex. subsidies (once/if oil prices recover). That the pipeline is even being considered should have investors worried about the true cost of developing gas in QLD or NSW. Sufficient gas must be found and developed to warrant construction of infrastructure. There was not even enough gas to keep Rio's Alumina smelter operation within NT, much less to fill any East-Coast shortage. o o One option is domestic NT gas but apart from a few small Santos fields, the large estimated gas resources are little more advanced than say Cooper Basin shale. You could not sanction a pipeline without a lot more information on the geology and economics of that gas. Another option is to rely on additional off-shore field developments or voluntary supply from the LNG operators (Darwin and Ichthys have no dom-gas obligations). Possible if either of them expands but Darwin is already now scrambling for additional gas for or a second train. The fact that no development has been agreed on yet (there are plenty of uncommitted gas resources), is probably an indication of difficult economics. Those economics of development must also be able to support pipeline infrastructure to Moomba or to QLD. That additional cost would likely be in the range of $1-2/GJ, with the lower range probably only applicable if volumes are sufficiently large (similar to the LNG pipelines). East Coast Gas 11

12 Once it reaches Moomba or Carpentaria, it has another $2/GJ of transport cost to get to any demand centre. If gas ever arrives, it will be very expensive. It will also be competing against LNG export capacity in NT that would not have the addition $3-4/GJ transport cost. Cost curve With the astronomical cost rises seen in Australian development costs in the past few years, we think cheap gas is definitively a thing of the past. Even if the market did not have to move towards international netback prices, we struggle to find any gas that can be developed below $5/GJ wellhead. The cheapest gas has always come from off-shore Victoria, easily supplying the market at <$4/GJ. However, recent development and life-extension projects have virtually all exceeded budget. Kipper and Turrum (Esso-BHP/STO) would have cost more than $3/GJ of lifetime reserves upfront. Sustaining projects as Bass Gas and Otway are probably closer to $2/GJ. Add to that $2-3/GJ operating costs from gas treatment (fields themselves are low cost), royalties and margin requirements and prices are $6-7/GJ. Liquids rich fields may offset this by $1-1.5/GJ. Transport to NSW adds another $1/GJ for a landed cost of $6-7/GJ. In the Cooper, the only major project is the SACB JV which guides to $450mn sustaining capex for gas ($4-5/GJ), including F&D costs. Operating, pipeline and treatment costs to Moomba are another $2-3/GJ, offset by liquids production. That's a wellhead. Add a required margin and wellhead costs foe new supply could exceed $7/GJ. Transport to QLD adds another $2/GJ while delivery to NSW is $1/GJ. In Queensland, we simply use the historical and guided costs from the major dry-gas CSG projects. Upfront capex is $1-2/GJ (per GJ lifetime reserve), sustaining capex $4-5/GJ, operating and royalty cost above $2/GJ. Adding a margin puts the cost around $9/GJ or $10/GJ delivered to Gladstone. We have no real knowledge of potential NT gas cost because we there is no obvious supply. The highest it can cost after paying for pipeline cost (new and existing) to QLD is in the $5-6/GJ range, which would make it close to the cheapest gas to develop. We think that is a lot to hope for. NSW - Narrabri ~$7-8/gj is probably goal given Santos price estimates of $6-9/GJ. We understand there is huge uncertainty around the cost number though as 1) there are unknown regulatory costs and 2) the acreage is of mixed quality. The "core" may not be large enough to pay for the required infrastructure, meaning non-core acreage must also be developed at higher cost. East Coast Gas 12

13 Figure 10: Cost curve for new developments (NSW and Gladstone are "end-markets") $12.00 CS estimates Back-solved $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 Vic (repl.) Vic (new) Cooper QLD CSG NT (max WH cost) NSW CSG Wellhead Transport to end-consumer Source: Company data, Credit Suisse estimates M&A opportunities Two of the major issues are balance sheets (ORG/STO/Cooper Basin) and non-alignment of resource ownership (Arrow vs. LNG exporters). Both can be solved by putting assets into new hands. Although uncertainty on everything CSG means the shortage is not easy to predict for us, the companies themselves probably know better how their gas reserves truly look. Plenty deals are possible in the next 12 months. In QLD, the grand bargain to solve the shortage is probably to merge Arrow into the downstream LNG facilities, providing sufficient reserve coverage for all projects at the price of capacity (though this will not be an easy deal). Other gas resources are Ironbark (ORG) and Senex (Western Surat), both companies that could use some with financing. Recent activity in the Cooper Basin (Cooper Basin Producers - We belong together?) could be an indication that players with larger balance are already thinking along those lines. Consolidation there and development activities underpinned by a larger balance sheet could see new fields developed, even if Santos' recent experience with costs has been disappointing. Is NSW, Santos has already suggested it is looking for farmdowns. While it is not obvious that major companies want to deal with the reputational risk in NSW, perhaps a smaller player could be brought in to take on some of the capex (in Victoria, Santos already farmed down the Sole field to the much smaller company). Implications for pipeline flows and APA For some time, we have been writing about the redirection of Cooper and Surat basin production from southern domestic demand towards the LNG export projects. The oil price shock does nothing to disrupt this thematic; the LNG projects in any oil price scenario are still the marginal buyer willing to pay the highest price. Hence, the opportunity cost of using Cooper basin gas to supply Sydney or Adelaide demand will remain higher than that of using gas from Victorian sources. East Coast Gas 13

14 Redirection to result in lower volumes on APA owned Moomba-Sydney pipeline This redirection will result in much lower flows on the APA owned Moomba to Sydney pipeline, and easterly flow on the APA owned South West Queensland Pipeline. Figure 11 shows that this is indeed what happened immediately when QCLNG began loading its first cargo in late December. Figure 11: Gas pipeline flows- a sign of things to come TJ/d Dec: QCLNG cargo begins loading Sep 31-Oct 30-Nov 31-Dec -50 Easterly flow Moomba to Sydney Pipeline System South West Queensland Pipeline Source: AEMO, Credit Suisse estimates Ultimate reduction in MSP contracted capacity not to be seen until 2016/17 The immediate reduction in flows along the MSP will have very little earnings impact on APA due to the duration of existing contracts and the capacity-based charges. APA's largest customer on this pipeline (AGL) has a contract which runs to the end of calendar 2016 which is aligned with their contracted gas supply from the cooper basin. AGL will need expanded pipeline capacity to replace this Cooper basin supply into Sydney. This will require augmentation of either the APA owned VIC-NSW Interconnect or the Jemena owned Eastern Gas Pipeline (EGP). We see augmentation of the EGP as more likely as this provides more secure supply into AGL's large residential retail base because it avoids passage through the Victorian market. We would expect an announcement to this effect in the next 12 months to give enough lead time to install new compression. AGL is also constructing the Newcastle Gas Storage Facility which is targeting operation by winter By shaving AGL's peak demand, this should reduce AGL's MSP capacity requirements. What is the upside for APA from upstream LNG shortfall? The three Gladstone LNG projects are in aggregate short reserves and will thus need third party supply to varying degrees. The location of this incremental supply will determine whether there is any incremental upside on APA's South West Queensland pipeline Asset. If the incremental supply is from Arrow, Ironbark or other fringe Surat acreage then this will bypass the SWQP. East Coast Gas 14

15 The SWQP is currently fully contracted for eastern haul capacity of 340TJ/d. Figure 12 plots the historical production of the Moomba gas plant versus this capacity. Note, historically this production has been delivered to the MSP and MAPs pipeline but as discussed we expect this to be redirected. The Moomba gas plant is being upgraded to a maximum production capacity of 600TJ/d. The extent to which well head production can be increased to feed this expanded plant capacity will determine whether there is any upside to SWQP contracted capacity. Figure 12: Spare capacity on SWQP TJ/d Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Moomba Gas Plant Average Production Eastern-haul rated capacity Source: AEMO, Credit Suisse estimates Northern Territory Pipeline? As we discussed earlier, the large transmission cost pushes the Northern Territory gas down the merit order of likely sources for the LNG upstream shortfall. However, if it was sanctioned then this would result in additional eastern haul capacity contracts on the SWQP. This represents an upside scenario to APA regardless of whether it (or for example DUE) is ultimately selected to construct and own the NT link. East Coast Gas 15

16 Appendix Figure 13: Announced Contracts since 2010 Source: Energy Quest East Coast Gas 16

17 Companies Mentioned (Price as of 08-Feb-2015) BG Group plc (BG.L, 934.9p) BHP Billiton (BHP.AX, A$31.05) Beach Energy (BPT.AX, A$1.16, OUTPERFORM, TP A$1.1) Chevron Corp. (CVX.N, $109.61) Cooper Energy (COE.AX, A$0.26) Drillsearch Energy Limited (DLS.AX, A$0.94) Origin Energy (ORG.AX, A$11.98, UNDERPERFORM, TP A$11.2) Santos Ltd (STO.AX, A$8.17, NEUTRAL, TP A$8.2) Senex Energy Limited (SXY.AX, A$0.4) Strike Energy (STX.AX, A$0.115) Important Global Disclosures Disclosure Appendix Martin Kronborg, CFA, Mark Samter, Peter Wilson, David Hewitt and Shew Heng Tan each certify, with respect to the companies or securities that the individual analyzes, that (1) the views expressed in this report accurately reflect his or her personal views about all of the subject companies and securities and (2) no part of his or her compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this report. 3-Year Price and Rating History for Beach Energy (BPT.AX) BPT.AX Closing Price Target Price Date (A$) (A$) Rating 30-May O * 30-Jul N 27-Aug Oct * 03-Mar O 25-Aug N 30-Sep Nov O 26-Nov Dec Jan * Asterisk signifies initiation or assumption of coverage. O U T PERFO RM N EU T RA L 3-Year Price and Rating History for Drillsearch Energy Limited (DLS.AX) DLS.AX Closing Price Target Price Date (A$) (A$) Rating 05-Nov O * 02-Dec Jan * Asterisk signifies initiation or assumption of coverage. O U T PERFO RM East Coast Gas 17

18 3-Year Price and Rating History for Origin Energy (ORG.AX) ORG.AX Closing Price Target Price Date (A$) (A$) Rating 09-Feb O 23-Feb May Jul * 03-Jul * 04-Jul O 11-Jul Aug Oct Nov Jan N 21-Feb Jun Jun * 09-Jul Jan Feb Mar Aug Aug * 21-Aug N 22-Oct Nov U 02-Dec Feb * Asterisk signifies initiation or assumption of coverage. O U T PERFO RM N EU T RA L U N D ERPERFO RM East Coast Gas 18

19 3-Year Price and Rating History for Santos Ltd (STO.AX) STO.AX Closing Price Target Price Date (A$) (A$) Rating 17-Feb N 01-Mar * 12-Apr N 19-Apr Jun O 11-Jul N 13-Aug * 17-Aug N 15-Oct O 22-Nov Jan Feb N 05-Jun Jul U 09-Sep * 07-Oct U * 07-Oct * 18-Oct U 04-Dec Jan Jan Feb Mar Apr Jun Jun Jul Aug Sep Sep Oct Nov Nov Dec Dec Jan N 27-Jan * Asterisk signifies initiation or assumption of coverage. N EU T RA L O U T PERFO RM U N D ERPERFO RM 3-Year Price and Rating History for Senex Energy Limited (SXY.AX) SXY.AX Closing Price Target Price Date (A$) (A$) Rating 25-Jun O * 27-Jun Jul Jan * 29-May Jun Aug Sep Nov N 02-Dec * Asterisk signifies initiation or assumption of coverage. O U T PERFO RM N EU T RA L The analyst(s) responsible for preparing this research report received Compensation that is based upon various factors including Credit Suisse's total revenues, a portion of which are generated by Credit Suisse's investment banking activities East Coast Gas 19

20 As of December 10, 2012 Analysts stock rating are defined as follows: Outperform (O) : The stock s total return is expected to outperform the relevant benchmark*over the next 12 months. Neutral (N) : The stock s total return is expected to be in line with the relevant benchmark* over the next 12 months. Underperform (U) : The stock s total return is expected to underperform the relevant benchmark* over the next 12 months. *Relevant benchmark by region: As of 10th December 2012, Japanese ratings are based on a stock s total return relative t o the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractiv e, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. As of 2nd October 2012, U.S. and Canadian as well as European ratings are based on a stock s total return relative to the analyst's coverage universe which consists of all companies covered by the analyst within the relevant sector, with Outperforms representing the most attractive, Neutrals the less attractive, and Underperforms the least attractive investment opportunities. For Latin Ame rican and non-japan Asia stocks, ratings are based on a stock s total return relative to the average total return of the relevant country or regional benchmark; prior to 2nd October 2012 U.S. and Canadian ratings were based on (1) a stock s absolute total return potential to its current share price and (2) the relative attractiv eness of a stock s total return potential within an analyst s coverage universe. For Australian and New Zealand stocks, 12 -month rolling yield is incorporated in the absolute total return calculation and a 15% and a 7.5% threshold replace the 10-15% level in the Outperform and Underperform stock rating definitions, respectively. The 15% and 7.5% thresholds replace the % and % levels in the Neutral stock rating definition, respectively. Prior to 10th December 2012, Japanese ratings were based on a stock s total return relative to the average total return of the relevant country or regional benchmark. Restricted (R) : In certain circumstances, Credit Suisse policy and/or applicable law and regulations preclude certain types of communications, including an investment recommendation, during the course of Credit Suisse's engagement in an investment banking transaction and in certain other circumstances. Volatility Indicator [V] : A stock is defined as volatile if the stock price has moved up or down by 20% or more in a month in at least 8 of the past 24 months or the analyst expects significant volatility going forward. Analysts sector weightings are distinct from analysts stock ratings and are based on the analyst s expectations for the fundamentals and/or valuation of the sector* relative to the group s historic fundamentals and/or valuation: Overweight : The analyst s expectation for the sector s fundamentals and/or valuation is favorable over the next 12 months. Market Weight : The analyst s expectation for the sector s fundamentals and/or valuation is neutral over the next 12 months. Underweight : The analyst s expectation for the sector s fundamentals and/or valuation is cautious over the next 12 months. *An analyst s coverage sector consists of all companies covered by the analyst within the relevant sector. An analyst may cover multiple sectors. Credit Suisse's distribution of stock ratings (and banking clients) is: Global Ratings Distribution Rating Versus universe (%) Of which banking clients (%) Outperform/Buy* 46% (53% banking clients) Neutral/Hold* 38% (49% banking clients) Underperform/Sell* 14% (45% banking clients) Restricted 2% *For purposes of the NYSE and NASD ratings distribution disclosure requirements, our stock ratings of Outperform, Neutral, an d Underperform most closely correspond to Buy, Hold, and Sell, respectively; however, the meanings are not the same, as our stock ratings are determined on a relative basis. (Please refer to definitions above.) An investor's decision to buy or sell a security should be based on investment objectives, current holdings, and other individual factors. Credit Suisse s policy is to update research reports as it deems appropriate, based on developments with the subject company, the sector or the market that may have a material impact on the research views or opinions stated herein. Credit Suisse's policy is only to publish investment research that is impartial, independent, clear, fair and not misleading. For more detail please refer to Credit Suisse's Policies for Managing Conflicts of Interest in connection with Investment Research: Credit Suisse does not provide any tax advice. Any statement herein regarding any US federal tax is not intended or written to be used, and cannot be used, by any taxpayer for the purposes of avoiding any penalties. Price Target: (12 months) for Santos Ltd (STO.AX) Method: We set our $8.2/sh Santos target price broadly in line with our roll forward DCF valuation of $8.50/sh minus an ESG discount of 3% for environmental and regulatory risks related to CSG drilling. Oil prices, the critical sector earnings driver, are determined by the Credit Suisse research team on a quarterly basis taking into consideration global demand-supply pressures. The oil price forecast is for a longterm real oil price of US$85 from Risk: The critical risks associated with our $8.2/sh STO target price, forecasts and valuation relate to commodity price assumptions and delivery issues associated with growth projects, predominantly timing, third party gas requirements and capex estimates for GLNG. On a lesser level, the sector is experiencing significant upside pressure to operating costs, however, somewhat counter balanced by the upside risk to production numbers and potential new project sanctions. East Coast Gas 20

21 Price Target: (12 months) for Origin Energy (ORG.AX) Method: Our ORG discounted cash flow based sum of the parts yields a $11.20/sh target price, which includes a $0.36/sh reduction to reflect ongoing investor concerns around the potential for reversionary interests to claw back current reserves from ORG. Our DCF employs a weighted average cost of capital (WACC) of 9.31%, with an equity beta of 0.95, target gearing 32.5%, 6.0% equity risk premium and 5.3% risk-free rate. Risk: The key risk to ORG achieving our 12 month $11.20 target price is balance sheet / funding issues and capex concerns in delivering the APLNG project. Other risks include increased wholesale electricity costs, increasing expenses associated with providing retail electricity and gas to customers. Increased customer churn in competitive retail markets could also raise costs through a negative impact on operating and marketing expenses. Risks associated with Origin's exploration and production activities include pricing risk on resources, volume risk relating to the amount of fuel produced, increasing costs, unsuccessful exploration expenses and capex risk. Revenue from retail operations could face risk fom weather conditions, where unseasonably mild weather can reduce usage of energy via airconditioning and heating units. Price Target: (12 months) for Beach Energy (BPT.AX) Method: Our $1.1/sh target price for Beach Energy is set broadly in line with our risked valuation. Our valuation is derived using a risked sum-ofthe-parts DCF valuation for BPT's producing assets (10% WACC), adjusted for net cash, plus risked exploration upside relating to unconventional shale gas in the Copper Basin and other conventional exploration. In valuing BPT's exploration upside, we use a resource multiple risked for the probability of success. Our long-term commodity price assumptions include $8/GJ gas and $85/bbl oil (real). Risk: Risks to our $1.1/sh target price for Beach Energy includes lower-than-forecast oil and gas prices, geological risks e.g. uncommercial discoveries, the failure of unconventional shale gas to be economic/commercial, and changes to royalties and the Petroleum Resource Rent Tax regime. Please refer to the firm's disclosure website at for the definitions of abbreviations typically used in the target price method and risk sections. See the Companies Mentioned section for full company names The subject company (ORG.AX, SXY.AX) currently is, or was during the 12-month period preceding the date of distribution of this report, a client of Credit Suisse. Credit Suisse provided non-investment banking services to the subject company (ORG.AX) within the past 12 months Credit Suisse expects to receive or intends to seek investment banking related compensation from the subject company (STO.AX, ORG.AX, DLS.AX, SXY.AX) within the next 3 months. Credit Suisse has received compensation for products and services other than investment banking services from the subject company (ORG.AX) within the past 12 months As of the end of the preceding month, Credit Suisse beneficially own 1% or more of a class of common equity securities of (DLS.AX). Important Regional Disclosures Singapore recipients should contact Credit Suisse AG, Singapore Branch for any matters arising from this research report. The analyst(s) involved in the preparation of this report have not visited the material operations of the subject company (STO.AX, ORG.AX, BPT.AX, DLS.AX, SXY.AX) within the past 12 months Restrictions on certain Canadian securities are indicated by the following abbreviations: NVS--Non-Voting shares; RVS--Restricted Voting Shares; SVS--Subordinate Voting Shares. Individuals receiving this report from a Canadian investment dealer that is not affiliated with Credit Suisse should be advised that this report may not contain regulatory disclosures the non-affiliated Canadian investment dealer would be required to make if this were its own report. For Credit Suisse Securities (Canada), Inc.'s policies and procedures regarding the dissemination of equity research, please visit As of the date of this report, Credit Suisse acts as a market maker or liquidity provider in the equities securities that are the subject of this report. Principal is not guaranteed in the case of equities because equity prices are variable. Commission is the commission rate or the amount agreed with a customer when setting up an account or at any time after that. To the extent this is a report authored in whole or in part by a non-u.s. analyst and is made available in the U.S., the following are important disclosures regarding any non-u.s. analyst contributors: The non-u.s. research analysts listed below (if any) are not registered/qualified as research analysts with FINRA. The non-u.s. research analysts listed below may not be associated persons of CSSU and therefore may not be subject to the NASD Rule 2711 and NYSE Rule 472 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst account. Credit Suisse AG, Singapore Branch... David Hewitt ; Shew Heng Tan East Coast Gas 21