David Knox - MD & CEO Andrew Seaton - CFO

Dale Koenders - Citigroup Mark Wiseman - Goldman Sachs Ben Wilson - JPMorgan Stuart Baker - Morgan Stanley Nik Burns - UBS Kirit Hira - Macquarie Group Limited Mark Samter - Credit Suisse Group AG Hugh Morgan - Deutsche Bank Scott Ashton - BBY

Thank you very much and good morning to everyone to Santos's 2014 Full year results conference call. Joining me on the line today is CFO, Andrew Seaton. In addressing the results we will refer to the presentation released this morning. This is available on our website. On the cover of the deck you can see GLNG as it is today. The project will ship its first cargoes during the second half of this year. The upstream is ready to deliver gas to the plant as and when required. The gas reserves grew during the year, the pipeline work is complete and it's filled with gas right the way through onto Curtis Island. The plant is now well into the commissioning stage and we're very proud of progress in all aspects of this project. I'm going to talk about that more later in my presentation. I'm now going to jump straight to slide 3. In presenting the results here today we will focus on the important highlights to 2014 and the company's position moving into 2015. First, our safety and operational performance continues to improve, demonstrating a strong safety performance at a time of very high activity is especially important. It's important for our people and for the successful delivery of our project. Andrew will talk about the sound operational performance that delivered growth in production, growth in revenue, EBITDAX, underlying profits and operating cash flow. The second feature of our results today is strong project delivery. PNG LNG and GLNG are transformational to Santos's earnings profile and both are in excellent shape. We also delivered first productions from Peluang in Indonesia and Dua in Vietnam. Finally, the rapid decline on oil prices since late-November is a challenge for the whole energy industry. Our response has been comprehensive. We cut our CapEx for 2015 by 25%. This means our CapEx for 2015 will be nearly 45% lower than it was last year. We're tightening our belt significantly and our suppliers are working with us in achieving this. We're forecasting at least a 10% reduction in operating costs. 2015 poses a great challenge to E&P companies worldwide but I'm supremely confident that Santos is in a strong position both operationally and financially. We've risen to the challenge and we will come out the other side a strong, leaner and fitter company. I'm now going to turn to slide 4. At the end of the day our operational and financial performance are dependent upon safe execution of our operations in every sense of the word. That's in the field; it's on our onshore operations and also here in the office. We have a broad safety scorecard. Our performance and all-indicator was better than planned in 2014. In terms of lost time injury performance, it was another good year where the rate was equivalent to that achieved in 2013. This is particularly pleasing during a period where two major EPC contractors, Saipem and Fluor, completed work and demobilized from the GLNG project. You can see that that's coming through in the reduction of GLNG work hours. Our focus on process safety, particularly safety critical maintenance also remains strong. Moving to slide 5, I want to talk more on the steps we've taken to meet the challenge of the lower oil price environment. As I said earlier, we've cut planned CapEx in 2015 by about 45% compared to last year. Our guidance of AUD2 billion for this year is maintained. The reductions are being implemented across all assets and operations company-wide. We've completed a full review of our company-wide gross spending. Essentially, 80% of our cost attributes to 20% of our suppliers and of these companies almost all are upstream, subsurface-related, drilling and workover rigs and frac spreads. We're achieving valuable efficiencies in many areas. Just now I'll give some key examples. Our well service costs are down 30%. Our onshore drilling day rates have been reduced by 20%. Approximately 15% reduction has come out of the cost of fuels and lubricants. Cooper drill, frac and completion costs per well have been cut from AUD7.1 million per well to AUD6.1 million per well. So every business unit is scrutinizing costs and reducing spending wherever possible. There is of course a material reduction in contractor numbers to take place this year, as GLNG expenditure comes down and the project is completed. In addition, we're reducing head count wherever it is possible as we focus on growing shareholder value in the new oil price environment. Since November last year, 520 positions have been removed. I have made it clear that there will be further reductions throughout the year as part of our continuing cost reduction program to drive both efficiency and also productivity throughout Santos. In summary, we're reducing our spending, controlling what we can and doing it well. With that overview, I'm going to ask Andrew to take you through the financials in some more detail.

Thanks David and good morning. I'm going to start on slide 7. 2014 delivered growth in production, in revenue, in EBITDAX, underlying profit and, importantly, operating cash flow. These are sound results which were achieved despite the lower oil price in the second half of the year. We're well past peak CapEx and we expect to be free cash flow positive by the fourth quarter of this year. With over AUD2.9 billion in cash and undrawn debt facilities, our funding position remains sound. As David outlined, we're implementing material cost reductions right across the business. From here in the new oil price environment, our focus is on delivering shareholder value from the investments that we've made. Turning to the summary financials on slide 8, without seeking to diminish the non-cash impairment charges that reflect the current outlook for oil prices, I believe these numbers underscore a sound operating and financial performance. Record sales revenues of AUD4 billion were up 12% from the previous year. Production was at the highest levels in five years. Underlying profit of AUD533 million is up 6%. The impairments as announced last week do not impact our investment grade credit rating or any of our debt facilities. The final dividend has been maintained at AUD0.15 per share, fully franked. This brings the full year payout to AUD0.35, up 17% on the previous year. When we announced the adoption of a progressive dividend policy last year, we made it clear that the Board is conscious of the need to strike a correct balance between shareholder returns, debt repayment and continued investment. Given the movements in oil price since that time, the Board took the view that maintaining a steady final dividend is the responsible course of action. The DRP will be fully underwritten, consistent with prudent capital management in the current environment. The bottom line is that, as a result of these decisions and outcomes, we remain well funded to executive our strategy. Our growth story is evident when you look at production on slide 9. We saw quarter-on-quarter increases in production, ending the year 24% higher than where we started. In fact, we delivered our highest annual production level since 2009. This reflects the successful ramp up of production from PNG LNG as well as higher Cooper production. PNG LNG is now producing ahead of expectation and obviously we're targeting a similar success with the imminent start-up of GLNG in the second half of this year. The Cooper Basin turnaround was also evident in 2014, with increases in both oil and in gas production. We have said before that higher gas prices would lead to higher investment and ultimately higher production and that's what we're now seeing in the Cooper after a long period of decline. 2015 production guidance remains unchanged, notwithstanding the cuts in capital expenditure. On the next slide, you can see the record sales revenue. Our third party business performed well again, as we leveraged our infrastructure position. We make a margin from all third party oil produced in the Cooper. We also sell third party gas and liquids in eastern Australia. LNG revenue more than doubled. This reflects the start-up of PNG LNG and also a strong performance from Darwin. EBITDAX was up 8%, reflecting the higher revenue and also the sound operating performance right across the business. Moving to production costs on slide 11 and while both production costs and DD&A increased for the year, it's important to remember that one of the main drivers has been new assets online. These include PNG LNG, Dua and Peluang. Of the AUD173 million increase in production costs, 60% can be attributed to these new assets coming online and also a full year of production from Fletcher-Finucane. There is also AUD29 million in relation to various planned shutdowns right across our operation, including the Cooper Basin and the 35 day shutdown at Bayu-Undan. It's a similar story with DD&A which for 2014 was up by 5% on a per barrel basis. This was primarily due to first production from these new assets. As David noted earlier, we're targeting a 10% cut in production costs per barrel in 2015 and DD&A costs are also expected to be lower, as shown on this slide. On slide 12, you can see the 6% increase year-on-year for underlying net profit, higher sales volumes and a lower effective tax rate were the key drivers. This was a solid result given the lower oil price environment in the second half of the year. The headline result, of course, includes the AUD1.6 billion in after tax impairments that we've already reported to the market. Turning to operating cash flow on slide 13 and this chart really highlights the growing strength of the company. With the start-up of new assets we recorded our highest ever full year operating cash flow of over AUD1.8 billion, 13% higher than the previous year. In 2015, at a AUD60 a barrel oil price, we expect to be free cash flow positive from the fourth quarter, that is operating cash flow less CapEx positive. In 2016 we'll be free cash flow positive for the whole year. If you turn now to slide 14, while I've already spoken to the dividend, you should note that we will underwrite the DRP which we believe is prudent in the current oil price environment. The DRP discount will be set at 1.5%. On the next slide, slide 15, you can see an additional level of granularity around our reported capital expenditure of AUD3.6 billion. As you'd expect, GLNG was the largest item at AUD1.3 billion. This represents all of the Santos spending in relation to GLNG and includes AUD135 million for domestic stay-in business CapEx, exploration, appraisal and Santos corporate costs. We spent AUD937 million in the Cooper and AUD426 million in other eastern Australian assets and this includes our share of the Combabula and Spring Gully development, also Narrabri and Mereenie. Capitalised interest was AUD230 million. The AUD2 billion in CapEx now planned for 2015 will be on a business unit split roughly proportionate to the 2014 spend which is shown on this slide. Now let me take you to our reserves position on slide 16. The chart talks to the most significant changes throughout the year. GLNG proved reserves increased by 22%, whilst 2P reserves are up 4%. This reflects positive subsurface performance and upward revision across the GLNG fields. Including our share of non-operated fields, the project now has 6000 petajoules of 2P reserves. When you add committed Santos portfolio and third party gas, the total is 7800 petajoules. Including 2C contingent resource, brings the total to 9000 petajoules. GLNG is in a strong position on gas supply today compared to its contracted volumes and we've got 20 years in which to supply those volumes. The Gunnedah Basin reassessment which saw proved and probable reserves down 32%, was detailed previously at the Investor Seminar in November last year. Cooper gas reserves decreased by 7% before production and there were two main drivers of this. First the greater Tindilpie area where reserves were reduced by 9 million barrels of oil equivalent, this was due to a combination of lower production from existing well and a reduced number of planned future development projects. The second area is PEL 106A, where reserves were reduced by 5 million barrels oil equivalent. Here field results and desktop studies didn't support the previous operator's position which was what we reported last year. Overall, after 2014 production, 2P reserves were down by 9% at 1.245 billion barrels of oil equivalent, giving a 2P reserves life of 23 years. More detail can be found in our reserves report that was released to the ASX today. Now, my final slide speaks to our balance sheet. Santos has a robust funding position. With the additional billion dollar facility, a debt facility that we secured in December last year, we now have AUD2.9 billion of liquidity. Net debt at year end was AUD7.5 billion and our average borrowing cost was significantly lower than the prior year. We have minimal drawn debt maturities until 2017. It is our intention to maintain the investment grade credit rating and we believe that we're well positioned in that regard. In closing, I believe our results today show that the business remains in good shape. We're well placed to manage through the current conditions while sticking to our overall strategic course. Peak CapEx is well behind us. Our funding position is strong and we've taken the steps needed to meet the challenges of the lower oil price environment and with that I'll hand back to David.

Thank you very much, Andrew. I'm now going to turn to slide 19. The transformation of Santos remains on course. In Vietnam and in Indonesia, two key Asian growth projects were delivered in 2014, on or before schedule and both on budget. We achieved good exploration and appraisal success. In particular, Lasseter in the Browse and Barossa in the Bonaparte Basin. I'll say more about these later. We've made our first entry to Malaysia through an agreement to acquire a participating interest in two exploration blocks located in the Sabah Basin. Exploration drilling began on Block S towards the end of 2014 and will continue in Block R this year. Finally to the LNG projects on slide 20, as I said at the start of our call, we're really pleased with progress. The reservoirs are producing better than expected and, in conjunction with secured third party gas, we're confident in delivering the volume to fill both our trains for 20 years. The capacity is there. The surface kit and the plant commissioning are making progress right on schedule. The upstream is ready and so is the pipeline. I recently visited Curtis Island with Bechtel senior management and the progress on site since my last visit is just as good as I expected it would be. Pipework has progressed, the majority of the cable has been pulled and there's a good atmosphere of progress right across the site. First gas is one of the many commissioning milestones. After this, the next big one will be the spinning of the first of the six massive gas compressors which are at the heart of the plant. Train 2 is also coming along well and will, as promised, be ready for start-up by the end of this year. So clearly, we're on track and furthermore, GLNG is a robust project which provides free cash flow at $40 per barrel. Let's go into a bit more detail on the upstream work on slide 21. Our focus in 2014 was to ensure that we had the capacity to supply the gas when the plant needs it, to ramp up Train 1 and commence the ramp up of Train 2 by the end of this year. The quality of our CSG fields, particularly Fairview, continues to surprise us on the upside. Fairview now is more than 250 wells online. As you know, we expected these wells would have the capacity to produce over 500 terajoules per day. In fact, by the end of this year, we expect the field to produce an extra 100 TJs per day, bringing the total capacity to 600 terajoules per day. This is a step change from what was contained in our plan last year and demonstrates how well Fairview is performing. At Roma, more than 100 wells are online and gas production is ramping up as expected. In short, I'm confirming that our fields as they stand, combined with third party gas, will comfortably meet the gas required to fill Train 1 and to ramp up Train 2 on target. The surface kit is ready, Fairview Hub 5 is operational and Fairview 4 and Roma 2 are well into commissioning. As I said, the upstream is clearly ready to start supplying as to Curtis Island as and when it is needed. Turning to the pipeline and the LNG plant on Curtis Island, so I'm now on slide 22, the 420 kilometer gas transmission pipeline is complete and gassed up all the way to the island. All rehabilitation works on the pipeline route are also complete, as are our pipeline interconnects with BG. All 111 modules are now set on Train 1 and Train 2 which is excellent. Both LNG tanks have now been hydrotested and the loading jetty has long been complete. Bechtel is responsible for plant commissioning and we now have 107 Santos operational staff embedded in that commissioning team at the plant. With gas into the plant imminently, we're well on our way to delivering first LNG in the second half of this year. I'm now going to take a closer look at PNG LNG on slide 23. The first LNG was delivered ahead of schedule in April 2014 and the project was ramped up to full capacity by late-July. Since then, the project has delivered a total of 68 cargoes to our customers in Asia. This is an outstanding achievement. All eight Hides development wells and the produced water disposal well have been drilled and completed. The development and produced water well results are being used to refine the Hides reservoir model. Last quarter, EXXON also commenced the drilling of the exploration Hides F1 well. This is targeting a deeper exploration play which lies directly below the existing Hides fields. The well was previously known as Hides Deep and it intersected the existing Toro reservoir and this section has been logged in case of a future production and drilling is now continuing to the exploration target below. As I said before, we're confident expansion will happen, but it remains just a little early to predict exactly how and when. As an existing infrastructure owner and the holder of perspective acreage, Santos is well placed to benefit from any expansion of the project. Whatever the source of that expansion gas, Santos has a seat at the table to benefit from the multiple growth options. I'm now going to take a look at our promising exploration program. I'm going to start in the Browse Basin on slide 24. On the back of the Crown and Lasseter discoveries, the appraisal planning and development concepts are being progressed. We're excited to see the extent of the very high quality sandstone reservoirs we found in both of these wells. We have committed to a 3D seismic program this year across the blocks. Further to the north east, we look closer to the Bonaparte Basin on slide 25. Early this year we announced further success with the Barossa appraisal program. The result of the Barossa-3 well confirmed a much larger and better quality resource than originally anticipated. Barossa-3 was an aggressive step out and we got a great result with over 100 meters of net pay over the target aligned formation. Our operator, ConocoPhillips is currently drilling a third well in the program and that's Barossa-4. Importantly, Santos has carried on this appraisal program which obviously makes Andrew happy, given the very tight rein he is applying on spending in 2015. Overall, the Barossa's success to date strengthens Santos's position as a key player for either backfill or expansion at Darwin LNG. So to close our commentary before we take your questions, our strategic portfolio has made us a key player in the Asian gas market. Backed by long term offtake agreements to high quality Asian buyers, Darwin LNG, PNG LNG and GLNG will provide strong cash flow for decades to come. Over the last 12 months we've delivered on our key strategic milestones. Andrew has pointed to the positive contribution from strong oil and gas production. We lifted our revenue to a record for Santos in 2014. We have shown you that that balance sheet remains in good shape. We have moved swiftly to reduce OpEx and CapEx materially to address the oil price environment. Above all, we're focusing on delivering shareholder value as our major investment program is completed. What we're most excited about now is the startup of GLNG in the second half of this year. Looking ahead, we remain bullish about the medium to long term fundamentals for the energy sector, particularly in this region and in that regard we're well positioned as and when commodity conditions stabilize and improve. Thank you. We'll now take your questions and I'll hand over to Leah, our operator, to coordinate. Can I have the first question please?

[Operator Instructions]. Your first question comes from the line of Dale Koenders of Citigroup. Please go ahead.

In terms of your 10% OpEx reduction target for 2015 which is a good step, where do you see the cost basis for Santos after this has been delivered. Do you see room for more cost reductions going forward, given others in the industry have sort of set targets higher than that, sort of 15% to 20%?

Yes Dale, I think that there is more scope to cost out than the 10%. 2015 is a bit of a messy year for us, if you like in terms of operating cash -- in terms of operating costs and that's because with the startup of GLNG where hubs have been handed over, so for example, Fairview Hub 5 was handed over late last year to operations. That's now being expensed, the costs associated with that. So progressively, as equipment is handed over, we'll see our operating expense go up and that's ahead of production from GLNG starting up. But of course during the ramp up period, you have disproportionately higher operating costs. So that's certainly a consideration for us. At the same time, David pointed to the steps that we've already taken across the business and we're continuing to push more cost out and our suppliers are responding well to that as well.

Yes, I think Dale especially we're working with our suppliers and particularly things like drilling rigs, we're already seen a 20% reduction on the day rate on drilling rigs in the Cooper Basin. That will flow through and, as Andrew said, through 2015 and also obviously into 2016 and beyond. So yes, I think 10% is sort of the minimum and we'll be driving for far more as we flow all of this through.

Okay. In terms of the comments for asset sales, David you've been quoted in the media recently about pursuing a GLNG pipeline sale could you provide some more comment about if that is and a realistic target and JV partners sort of views and opinions on that sale and possible timing?

Yes, that's right, yes we have. We've been quite straightforward in that. We've now appointed Goldman Sachs, or the JV has appointed Goldman Sachs to support us in this. So the JV is right behind this, so we will progress this during 2015. As I say, the JV is fully engaged.

Okay and then finally, just in terms of the Cooper reserves downgrades which were a bit disappointing, what is your view on this asset going forward? Does this break the infield drilling story? Should we be thinking about the life of this asset in line with the reserve life of 10 years? Or what is your outlook for this asset longer term?

So let me just make a few comments and then I'll ask Andrew to add some more color. The fourth quarter, as you've seen in our fourth quarter report in the Cooper Basin, it's had a very good production performance. Our production performance has continued in 2015. At the investor day, James Baulderstone promised we'd achieve a capacity of 450 million standard cubic feet by the end of 2014. We've achieved that 415 million standard cubic feet capacity. So what's pleasing about the Cooper Basin is that the fourth quarter really showed that it's building its production. As I say, I can confirm that has continued into 2015. What's really delivered that has been the performance of the recent Big Lake pad, the performance of [inaudible] and the drilling rigs on those pads.

Dale, maybe if I can just add on the reserves piece, as I said, the reserves downgrade was Greater Tindilpie and that's really a story from 12 months ago, it's a continuation of the hit that we took a year ago. The Greater Tindilpie wells just haven't performed as well as we'd hoped. The other area that I referenced was the drill search acreage where we farmed in. Now we've taken a bit of a write-down because our studies didn't support the reserves that we put on the books directly from drill search. But I've got to say the last couple of wells that we've drilled in this area have been positive upside results. As David said, the Big Lake pads are performing well. So no, the Cooper has got a lot of life in it yet. Obviously with our reductions in CapEx, we're very focused on the delivery and getting the reliability up and the surface kit right. So we're not going to be doing a lot of appraisal drilling for the next year at least. But there is a lot of scope still in the Cooper. Obviously the higher oil prices are -- higher gas price I should say, on the east coast is a key enabler of continued investment in that basin.

Sure. I guess back in 2010 the target was set for 1000 petajoules of net reserve add over the next five years. We're approaching that five years on and we're almost back to square in terms of the reserve through that period. Are you still sort of targeting that sort of aspirational reserves add going forward?

Dale it's interesting, we only came out of the box on that one five years ago and booked a lot of reserves up front. Some of those have now come off. As I said, the focus right now and David pointed to the increase in production, focus right now is on taking cost out, right sizing it in the current environment, delivering on our contractual commitments. The reserve adds would necessitate quite a significant appraisal spend and we're just not allocating the budget to appraisal work this year.

[Operator Instructions]. Your next question comes from the line of Mark Wiseman, Goldman Sachs. Please go ahead.

Just a first question on the dividend, obviously given the macro conditions, 2015 earnings look like they'll be substantially lower than 2014. Should we still read that the progressive policy over the full year should apply going forward?

Yes, Mark we've not changed our progressive dividend policy. When we announced it, we always said that we had to respond to market conditions and they had to be taken into account and I think everyone understands there's been a very significant chance since the middle of last year. So the Board has not moved away from a progressive policy. The Board is not removing -- or moving away from its commitment to deliver returns to shareholders. That's going to become increasingly important to us as we reduce our capital spend from our major projects. So no, our progressive dividend policy is absolutely unchanged. We're however, going to be prudent, depending on market conditions and that's what we decided to do this year, to a very prudent and reasonable position on the dividend.

Probably one more point to make, Mark, is that our operating cash flow last year was strong and we've clearly said we will be free cash flow positive by the fourth quarter of this year and free cash flow positive moving forward through 2016. So the financial flexibility of the company is improving as we put our major CapEx programs behind us. So we're going to be generating good cash even in low oil price environments.

And just another question if I could just on GLNG, I know we've spoken before about a three-or-so year ramp ups in production to the full contracting capacity, if oil prices remain lower for longer, can you just remind us of how those contracts kick in and if you were to go slow in that ramp up by pulling some CapEx out and perhaps drilling less wells, what's your sort of minimum requirement to deliver to those customers?

The ramp up is not going to be affected, in fact quite the reverse. What we're seeing is an over performance from our current wells. We'll get the whole system connected and up and running by obviously the second half of this year. We're not going -- you know, we're planning on continuing to achieve the guidance that we've already set on the ramp up. If anything, I'm becoming increasingly confident around that, not the reverse. So that's completely unaffected.

Just finally if I could, I was intrigued by your comment that GLNG breaks even at about AUD40 a barrel, certainly better than our forecast and I guess it just begs the question, is the billion dollar sustaining CapEx for the first five years and the OpEx of AUD150 million downstream and AUD1.25 per gig in the upstream, does that still all apply and is that AUD40 calculated in the first five years when you're still in that heavy sustained CapEx period?

Yes, it is. It's in all years, but I think what's happening Mark, here, is we've moved away from sort of big, heavy capital investment phase and obviously we use in the upstream Fluor as the key contractor working with us on that. We've demobilized Fluor now completely and we're now in what's more described self-managed situations where we go to individual contractors who are best for that particular job. We've simplified the designs we're using, we've got better at the execution, we've got some great execution teams. We're seeing the cost of the next bit of compression, the next well pad, the additional drilling, is reducing very, very significantly. I'm not going to change the guidance today, but we're seeing considerable costs coming out of GLNG, as we go forward, as we learn as we do things better, as we change our contracting strategy and as we basically manage small incremental projects and we manage them extremely well. All of our small incremental projects we're running, some of them are not that small, but say the Comet Ridge to Wallumbilla pipeline, we've just completed that project. That project which is a sort of reasonably sized, large project, that project has been completed on schedule and well under budget.

Yes Mark, so the answer is the guidance is unchanged and the pre cash flow positive at AUD40 oil takes into account all of that guidance and that's from 2016 onwards. Another point I would make is that third party gas is linked to the oil price, so it does provide a bit of a hedge to our input costs in a lower oil price environment.

Your next question comes from the line of Ben Wilson of JPMorgan. Please go ahead.

Just two questions, one just wondering if you could provide a comment on this cyclone that seems to be bearing down on mid-Queensland, we've heard maybe there's been some shutdowns at Gladstone there. And also, sorry I missed part of the comment you made earlier with respect to the question on asset sales processes. If I could ask, on the GLNG pipeline, do you see any benefit on the assumption of a similar sale price to that which was achieved by BG? Any net benefit to your credit metrics which S&P look at it? Thanks very much.

I'll address one of those things. Yes, I've had a couple of conversations with the site this morning on the cyclone. It is clearly a very serious cyclone, potentially a category 5 that by any standards is very serious. What we've done on the island is earlier this week we started basically tying everything down, obviously Bechtel are running the site, but everything was -- has been tied down basically. And that's everything from movable containers, scaffold boards, the whole nine yards. And then we did mobilize all the staff who live in Gladstone, back to Gladstone and those who don't live in Gladstone obviously have gone further. Those staff that are residents on the island, because they do effectively a couple of weeks on, or a month on and a month off, those staff are in the accommodation on the island. We have about 1500 rooms on the island. Those rooms are cyclone proof; they're designed for this sort of condition. In addition we've got a very small Santos operational team who are in the control room, a very small number of staff in the control room. So everything this morning is absolutely battened down and of course we're just keeping a very close eye on the situation. Nobody is going backwards and forwards across the harbor that has been closed for at least 24 hours now. So there's been a lot of preparation and planning and engineering designed for an event such as this which is very infrequent in Gladstone, very infrequent indeed. On the asset sales I'll allow Andrew to talk to the metrics, but yes, just to confirm we're working with the whole GLNG partnership, with the support of that partnership, to monetize the pipeline and we have appointed Goldman Sachs to support us and help us in that process.

Yes Ben, in relation to the credit rating, the monetization of the pipeline will be credit enhancing in that you're really arbitraging your lower cost of capital that's available from the prospective purchases versus our costs of capital. So for the effective operating costs that you've capitalized back, we'll be receiving disproportionately more proceeds upfront, if you like because of the lower cost of capital.

Yes, I think S&P confirmed for us the other week that they use the 7% discount rate on those operating costs, so you would suggest that maybe you can do better than an implied higher IRR of 7% on a sale process?

That's right. I think we had already with other like sales.

Yes okay. And just lastly, I just want to ask about Kipper gas, any chance or any plans to get that up to GLNG somehow?

Hope Kipper gas will come on in 2016 as has been planned for a long time and as probably everyone knows, Moomba is a critical piece of infrastructure and does allow us to move gas around, so it is a key part of the strategy, to be able to move gas between states and obviously we do that anyway. We supply New South Wales from Moomba, right now we see South Australia and [inaudible] supply Queensland. So it does give us some real optionality and flexibility and as I say, Kipper is coming on in 2016 and we'll really welcome it and the timing will be very good for us.

Ben, we do swap portfolios around but we also physically transport the gas.

So we've got some real flexibility in the gas market.

Okay, so no rush to contract that gas I guess by implication is that the message?

No we're not, we're just looking forward to it coming on and then it will come on to what we believe will be a good strong domestic gas market in 2016.

Your next question comes from the line of Stuart Baker of Morgan Stanley. Please go ahead.

Another question on the Cooper Basin, just to clarify something with respect to your current reserve there of about 970 PJs, 750 PJs going to GLNG and by my sort of rough understanding, about another sort of 150-odd PJs, 200-oddish PJs still to be contracted and rolled off into the domestic market 2015-2016, into 2017, is that approximately correct?

Yes I think your numbers are all factual, just remember Stuart that the GLNG 750 PJs volumes are not necessarily linked to the Cooper, they're Santos portfolio gas, so I think Ben's point on Kipper before was pertinent as well, that we can swap gas around as we see fit.

Just a second question on the Cooper and maintaining deliverability, as distinct from reserves and with the number of rigs allocated for drilling down from seven to three and, obviously, capital tightening generally. I'm just wondering what lump of capital's required over an extended period to extract the undeveloped proportion of that reserve which is about 45%. I obviously understand that you've got a period of years to do that, but just wondering what is an average level to spend over a number of years to develop the remaining 2P.

Stuart, we've previously guided, loosely, to around AUD400 million of sustaining CapEx in the Cooper and that would develop that 2P. The good thing at the moment is the way that our suppliers are responding and the costs we're taking out of our business. So the real challenge for us is to ensure that the cost-out remains even as we move forward if the oil price recovers.

And just moving over, finally to something completely different, up at PNG. Hides wells have been drilled, development online, PWD well done, any insights yet into when we'll see a Hides field reserve determination and, I guess, going back some years, there was an expectation that that reserve could be quite a lot larger and help underpin the expansion. That story seems to have gone very quiet over a period of time and don't seem to hear much about it at all now. Just wondering whether the development seen to date, based on results, seem no material change to the Hides reserves.

Yes, I think Stuart everyone is now incorporating the results into the reservoir model. Like many of these things, the more results you get, the more time it takes to really get the model to absolutely history match, particularly the water contact is the most important thing that is being worked on right now. So I think what you'll see over a period of time is increased confidence around that Hides model. Also, as you produced more of the gas in the Hides reservoir you get another pressure center that's an indication of the size of the total contactable volume by the current well stock, so we're starting to see a bit of that. So I think what we'll see over a period of time is, again, more confidence around exactly how big the Hides reservoir is. I don't think the fact that it's been quite quiet should give anybody anything other than -- our confidence is unchanged that the Hides reservoir is likely to get bigger over time. But we just have to give it time so we can prove that and that process is ongoing.

But Stuart, there are triggers for formal redeterminations amongst the joint venture in the different fields, but they have not been triggered, so there is no formal redetermination scheduled in or being required by the partners at the moment?

Your next question comes from the line of Nik Burns of UBS. Please go ahead.

Look, just the first question from me -- look, you've been very proactive in the face of lower oil prices. You've outlined plans to cut CapEx. You've got extra liquidity in place and today you've announced lower operating costs and plans to underwrite your DRP. You're also looking at asset sales. With S&P maintaining your BBB credit rating, I know, David, you've been in the press saying that you see an equity raise as the last resort. With everything that's in place now, are you in a position where you can categorically rule out having to raise equity this year?

Yes Nik, no, our position hasn't changed. As you've rightly said, we've taken proactive steps. We're doing it very seriously. We're doing it in a manner which is extremely rigorous. As you say, we've cut 25% of our CapEx, we're reducing our OpEx, we've raised AUD1 billion of additional liquidity. So today we've talked a little bit more about staff reductions as well. So we're continuing to turn over every stone to make sure that the firm is fit, strong, lean and healthy in what I call a AUD60 world, but, basically, a low price world and that's what we're driving towards. So our position on equity is absolutely unchanged.

So can you rule it out for this year?

Well, I'm not expanding on that, I'm just saying our position is completely unchanged. And what we've been doing is taking real proactive steps to make sure that that's underpinned by real actions. And I think you've probably seen some real leadership from us on that front.

And Nik, we've said that investment grade credit rating's important to us and note that we're two notches above sub-investment grade. So we're pretty comfortable with where we're at.

Look, my other question was just relating to the gas contract with GLNG which initially, as you've said, would be supplied from the Cooper Basin. Can you just give us some understanding around the shape of that, in terms of when you're expecting first gas to be sold from Cooper into GLNG? And that 50 PJ ramp up, how does that ramp up over time? And also, just in terms of the pricing, I understand that's probably an oil linked contract as well and with -- if oil price stays around current levels, should we expect the realized gas price from the Cooper from your portfolio going up or down post GLNG -- sorry, post the commencement of this contract?

It is oil linked. It will start up as GLNG starts up. It obviously is a total of 750 petajoules or about 143, I think after fuel, gas and terajoules, per day. So it'll start when GLNG starts. It is oil linked, so it's obviously -- and the price of that contract does drop as oil price -- and, equally, it goes up as oil price goes up. That gives you a bit of a hedging effect for the GLNG owners. We don't announce the exact price, no [inaudible].

And Nik, in terms of the ramp up, there is a commissioning period allowed for under the contract, but then it becomes a flat, effectively, block of 50 petajoules per annum for the next 15 years.

That's right.

When does it reach that level?

Within several months of plant commissioning.

Yes, quite quickly, I think. That's what the Cooper Basin is set up to deliver that contract, you know. All this hard work that's been going in and the performance of our wells will underpin that in the Cooper Basin.

And interestingly, the Cooper Basin's already delivering gas into LNG.

It is yes, through the BG plant.

Right. What sort of volume are you selling to BG at the moment?

It's small.

A small volume, but -- and probably shouldn't talk about the actual volume, but it is actually -- the gas is flowing.

Yes.

Your next question comes from the line of Kirit Hira of Macquarie. Please go ahead.

Just a couple of questions around the cost reduction, you talked about 500 odd positions being removed to-date. Just wondering if we can get a sense of how many of those positions are permanent staff versus, I guess, temporary staff that has been built up over recent years, just given the developments that you've been undertaking over recent years.

They're not temporary staff. These are real positions that are being removed from the organization. The 520 number is the number to date. There are going to be more over the coming weeks and months. So these are real -- this is not fun. These are real people who are leaving the organization and it's a difficult time for everybody and we're working through it very diligently. But it is necessary for us to come out the other side as a stronger firm than we went in.

Okay. And in terms of -- just skipping to GLNG, in the upstream at Fairview you're targeting 600 terajoules a day at the end of 2015, just based on average deliverability. That implies only another 50 wells connected this year at Fairview. Does that mean that more wells will be connected at Roma? Or does it mean there's a greater reliance on third party gas? It just seems like a fairly slow pace of additional wells being connected there.

Yes basically what's happened in Fairview is the performance of the Fairview wells has been excellent. And that means that while we connected a huge number of wells last year -- and we've got some more to connect this year -- we don't need to go at it like a bull in a china shop any longer. We can go in a much more measured pace. And that's why we're bringing the rig numbers down progressively this year is the plan, because we don't need to drill a huge number of new wells. We need to just connect all of our well stock up -- and we've got it largely all connected -- and we need to just bring all those wells on. The other thing that's important -- we've discussed it many times in the past. There were all sorts of concerns and worries about can you turn down wells. Again, the Fairview field, being an exception field, does allow us to turn down connected wells which gives us a high degree of flexibility which is frankly, very helpful, going forward. But we currently have 358 wells online today, the majority in the Fairview field, the rest -- the balance in the Roma field. We do have more wells than that which are connected, but they're not online because we [inaudible] we're able to shut in some wells. So we're going to have plenty of well capacity. And I think the other key thing, of course, is our objective here is to make sure that our existing Hubs and the new Hubs -- basically, that they run full from the get go and then we'll continue to add further compression in order to make sure that both trains are absolutely full. What's happened here is there's been a real uplift in the performance of Fairview. And what's happening is that Roma field is delivering in accordance with what we hoped with potential to go beyond, that's what's happening. That's what's driven our ability to say that we're increasing our capacity at the end of 2015 and has allowed us the flexibility to basically reduce the number of wells we have to drill.

What's the CapEx implications of that in terms of -- I mean the compression, if you add up all the Hubs, in terms of existing Hub 4, Hub 5, it's around 550 terajoules a day which closely matches that 500 to 600 terajoules a day that you're targeting at Fairview. Is there any CapEx implications from that additional performance you're seeing at Fairview?

Well, there may ultimately be but we're not, at this stage going to change our CapEx guidance which is, effectively, AUD5 billion over the next five years or AUD1 billion a year. We're not going to change that. But potentially, as I've said, the increase in field performance allow us to, obviously reduce the number of wells, that's good. The other thing that really is being -- starting to be really factored in is, following our move away from our contractor philosophy -- when we were doing the big contract Fluor -- to a much more bespoke set of contracts with the really good Aussie contractors doing specific smaller jobs, we're getting very good performance out of that and that's allowing us to drive real efficiency. So I'm more optimistic than I was, probably, 12 months ago, that CapEx will come down in the future. We really are seeing some good performance and this goes to the very heart of this coal seam gas business, that by driving down our costs, that's what really drives our profitability.

Okay. And just a last question around the Cooper, I know there is been plenty of questions there, but you talked about, I guess, the reserves downgrades there. We know there's an infrastructure footprint being expanded. Just wondering, just given the lower prices that we're seeing, given the oil linkage, how much of that capacity will be reserved for third party gas? I know you're suggesting that maybe Kipper could be bought in, but is there scope for Santos to take more third party gas there? But also would Santos look to aggregate more acreage outside of the SACB JV? You've done that in the western flank and also in some northern acreage.

Yes, Kirit, we're, I guess, with the reduced CapEx, slowing down the infrastructure build out in the Cooper. Obviously, we're taking the CapEx out. Third party gas is good business for us. We're certainly open for business and we'll make sure that we've got the capacity, provided the economics stack up for us. We're putting increasing volumes of third party gas through the plant at the moment, but it's a matter for others to bring that gas into the plant.

I think the key thing with Moomba is it is increasingly going to be obvious that this is a really key piece of infrastructure for the East Coast of Australia. This is where all the pipes come together.

I guess we're not building to spec, build it and they will come. We're spending on CapEx for the direct line of sight that we have to our production and modest third party gas that's coming in at the moment.

Your next question comes from the line of Mark Samter of Credit Suisse. Please go ahead.

I might start with a slightly mundane question if I can, for Andrew. Andrew, CapEx at AUD3.6 billion, this may just be because I'm not an accountant and missing something, but in the investing cash flow there's about a AUD200 million difference. Is that just a timing issue?

Yes, it is Mark. And you'll see that again in 2015. Reality is that we prepaid and we pre-funded Bechtel, Saipem and Fluor. So, yes, there's a benefit in 2014, there'll be another benefit this year. That CapEx was spent in 2012 and 2013.

A similar size this year?

The cash out, it comes down a bit as the projects taper off, so it's probably not the same magnitude as last year. But it is still positive for us.

And David, a question for you, just on the longer term strategy. And it slightly ties into the next question about the equity raising. I mean we can quibble on the exact numbers but, I guess, on the oil price deck you guys used -- probably, FFO-to-debt doesn't get back above 30% until 2017, 2018 whichever number it may be. In the absence of asset sales are you fundamentally happy to sanction no new projects in the next three or four years and, therefore, produce materially less at the end of the decade, turn of the next decade? Or would you think there comes a time when the business has to invest in growth opportunities and you just take your balance out in that company strategy? How long do you hunker down for?

Well, we're clearly -- right now we're very focused on making sure we did deliver our largest project that we've ever done in Santos and that's clearly going to be the focus of this year. As I've talked about, we're continuing exploring this year. We've got the wells at -- just talked about Malaysia and obviously, we've had some very, very good success in the Browse Basin and also in the Bonaparte Basin. So that combined -- I mean we have, really, a very strong portfolio and that gives us the opportunity to make choices as we go forward. And as I say, we're going to be making choices between returning, effectively, money to shareholders and investing for growth and that's where we'll play the balance, going forward. We're in a strong position though that we do have a good portfolio and our recent exploration success is further built on that. So we really are in a very good place to make some really rational choices, going forward. I also, Mark, fundamentally believe and still fundamentally believe, that Asia's the growing economy, energy is going to be increasingly important and particularly gas, because gas ultimately does have a lower footprint than some other sources of energy. And I think that'll also become increasingly important as we go through the rest of this decade. And we're fortunate in Santos in that we're now involved in three really, really high quality LNG projects. We've got great offtakers. So that's going to underpin the long term future of our shareholders for the next 20 or 30 years. And that's where the real value comes in this company.

And just really finding a balance, and I talked about the balance that we need to find between ongoing CapEx for growth and maintaining our dividend and shareholder value and returns.

But just one last question, if I can? David, you talked about how you said have cover for when train 2 is fully ramped up. And obviously, six months ago, on the call, you talked about still being in the market for third party gas deals if they make sense. Should we take your statement today as any third party gas deal is categorically off the table now?

No, absolutely not. I absolutely stand by the same comment, if it makes sense we'll go for it and where we're on the GLNG reserves, just to be absolutely clear, we've got 5600 petajoules of 2P. We've got 1800 petajoules of third party that we've purchased and the beauty with that is there is no ramp and tail. And as Andrew said, to a certain extent there's a hedge to the down side. And we've got 400 petajoules of our own Santos fields. And you add that little lot together, you get 7800. If you then add on the 2C which is not an unreasonable thing to do, then we're up about 9000 petajoules level which is plenty to fill two trains for 20 years which is our objective. So any suggestion that that's not available to us, I think is just -- the facts just don't support it at this stage. However, if a third party gas deal makes sense to the GLNG partnership, obviously, it's got to make sense to all the partners, then absolutely we'll entertain it.

Can you just explain that, sorry; how if you got the -- how does any third party gas deal make sense or what, because--

Well simply because it's a choice do you invest in additional compression or do you, in fact, buy deliverability and it's a simple trade off you can make and we'll continue to make it. We've been making it for the last five years and I think we've made it very successfully. I know not everybody's agreed with me, but at the -- once we get this up and running, I think everyone will see the massive benefits of having a mixed portfolio.

And I mean is there an oil price where -- in the short term -- deliverability issue -- obviously, the contract with Origin -- 94 PJs of that is puttable by them. The WestSide contract is obviously up to certain volumes. Is there a realistic threat of a AUD50 or AUD60 or more that you probably don't get those volumes? Maybe it doesn't make sense for them.

Hard to judge what their development costs are. What we've said, obviously, is that GLNG is profitable at $40, after CapEx. So that gives you an indication of where the price would need to be for them to choose not to develop reserves. But it goes to my earlier comments -- and I don't think Origin will be any different from us -- is that we're seeing a substantial reduction in our costs as we develop the next phases of these projects and we're -- we've learned a lot, we're working with the best contractors now with a really fit for purpose design and that's knocking -- you know, we're talking 30%, 40% coming out of our cost base here. Very substantial, I would imagine that applies to Origin just as much as it applies to us.

Your next question comes from the line of Hugh Morgan, Deutsche Bank. Please go ahead.

Just another question around the investment grade credit rating, Andrew, as you mentioned, you've obviously still got BBB- up your sleeve. I'm just wondering if you can give us any sense around if hypothetically there was to be a move to that rating, what it could mean for interest costs or covenants or anything like that?

That's an easy one. Thanks for the question, Hugh. The answer is absolutely nothing.

So following on from that, I guess it would kind of imply that that's, you know, on the economic stratum of opportunities of ways to deal with the balance sheet, that's a pretty attractive thing to allow to happen.

Listen, you know, credit rating is an important mix for us, But yes, BBB- is still investment grade. Obviously we're happy with where we're at.

Okay. Just another question a slightly different direction around exploration, just comparing the plans for 2015 versus I guess where you were at the investor seminar late last year, does look like there's more activity in Malaysia than previous. Dave, just wondering if maybe you can just give us a bit of sense around the prospectivity of some of those targets, potential size, probability of success, some factors like that.

Yes Hugh, at the investor day we weren't able to say anything about the Block R investment because it hadn't been approved by PETRONAS. That has now been approved and we've just started drilling the first well on that. So yes, the Sabah basin is an oil prone basin. A very highly oil prone basin is obviously a very -- is a very prolific basin. It supplies into Brunei, it also supplies the big gas plants into Bintulu. So its oil prone has quite a number of very, very large gas condensate fields in it. We're drilling basically a series of five wells in total. These are relatively straightforward excavation style wells into high quality oil prospects. Our partner at INPEX leads one and JX Nippon leads the other.

Yes, reasonably sizeable oil prospects. The beauty of the basin as well is the infrastructure that's existing and with PETRONAS as a partner in all of these permits, the access regime to infrastructure is favorable to a new discovery.

We clearly have a good relationship with PETRONAS. When I say sizeable, I mean 100 million barrels and above. These are good quality prospects 25% in one and 20% in the other.

Your next question comes from the line of Stuart Baker of Morgan Stanley. Please go ahead.

Sorry gentlemen, just another follow up question. Just going back to comments that Andrew made about GLNG being cash flow break-in about AUD40 a barrel, just triggers a thought process which is, you know we had a view that the LNG contracts had S-curves or floors or something in them and I know there's been kind of chatter around it over a period of time, haven't seen anything much more recently. I'm just wondering whether your contracts do give you downside oil price protection, particularly given there's been a few people around the world suggests maybe oil prices touch AUD20 or AUD30 or whatever. Do you have a floor in there that gives you a guaranteed minimum revenue and are we sort of anywhere near it?

Yes Stuart, as we have consistently said, we don't have S-curves as such in any of our offtake contracts from GLNG. There are kink points but they're not an absolute floor as such.

Yes, we have absolutely no floor, Stuart, in our contracts.

So there is slightly different slopes, but you don't get full downside protection.

Yes.

But at the same time, we don't get capped on the upside.

Your next question comes from the line of Scott Ashton of BBY. Please go ahead.

Look just a very quick question on the organic growth in PNG. The Hides Deep well was outside the stratigraphic limits of the PNG LNG, so I suppose some questions--

No. It's in the structure, but not as part of the current PNG unitized project. It's underneath. It's in the same structure. That's the beauty of it, it's right underneath the Hides.

Correct. So on the basis that there's still some determination going on with the science of the Hides tank, could you sort of form the view that it may be post the Hides Deep well is when we'll get a clearer picture on how big the tank is and therefore that triggers then some redeterminations and unit expansions? So is that one way to think of it in terms of the timing?

Yes, that's right. What the Hides Deep well does is it obviously gives us another data point in the Toro reservoir which is the main Hides field, so it gives us another data point there. But obviously the fundamental thing about it is this is a very high quality exploration prospect which lies right underneath the existing infrastructure. So if it is successful, then clearly it's a very high value asset to come into the existing infrastructure. While on its own we don't--

You've got a higher equity, sorry David--

We a higher equity -- absolutely, we're highly leveraged for this. So on its own, perhaps we don't expect it to be big enough to drive a second train but that -- sorry, a third train, but that combined with the existing Hides and potentially other resources around, I've always said, it's probable that that will give us a third train but let's see. You know, it's still in front of us and that's what's so exciting. That's what's exciting about this oil and gas game, is you drill these wells and sometimes they come in and this one, let's fingers crossed, it will.

So David just on that though, could we maybe get a bit of timing on what you sort of see as the timeline for maybe getting a better idea on how big Hides is? Is it sort of this year, this quarter?

The Hides reservoir, I think we -- you know, we're starting to learn a lot about it now but as we go through 2015, now that the field is on production and on really strong production, then that will start to give us the [inaudible] parts that we require to really say with a higher degree of confidence how big the Hides tank is and I think it'll get bigger. Then of course the Hides Deep, if it was a discovery, one small effectively 8.5 inch hole does not determine the size of the field. We'll then have to drill a follow up and that will start to give us the real feeling on Hides Deep. With that, I think we'll wrap. Thank you very much for all of your questions. For us as I said, we had a good 2014, we delivered production growth, Cooper grew, that's continuing into 2015. The really big thing for us of course is bringing on our GLNG project and that's going to happen in the second half of this year. We'll look forward to meeting everyone over the next week or two, but thank you very much for your questions this morning.

Ladies and gentlemen, that does conclude the conference for today. Thank you all for participating, you may all disconnect.